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, 2021

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)

Isabela Klemes, phone: (56-2) 2353-4400, ir.enelchile@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

Auditor Firm ID: 1273Auditor Name: KPMG Auditores Consultores SpAAuditor Location: Santiago, Chile

Enel Chile’s Simplified Organizational Structure⁽¹⁾

As of the date of this Report

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

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TABLE OF CONTENTS

		Page
GLOSSARY		3
INTRODUCTION		5
PRESENTATION OF INFORMATION		6
FORWARD-LOOKING STATEMENTS		8
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	9
Item 2.	Offer Statistics and Expected Timetable	9
Item 3.	Key Information	9
Item 4.	Information on the Company	20
Item 4A.	Unresolved Staff Comments	47
Item 5.	Operating and Financial Review and Prospects	47
Item 6.	Directors, Senior Management and Employees	81
Item 7.	Major Shareholders and Related Party Transactions	87
Item 8.	Financial Information	89
Item 9.	The Offer and Listing	91
Item 10.	Additional Information	92
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	109
Item 12.	Description of Securities Other Than Equity Securities	113
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	114
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	114
Item 15.	Controls and Procedures	114
Item 16.	Reserved	115
Item 16A.	Audit Committee Financial Expert	115
Item 16B.	Code of Ethics	115
Item 16C.	Principal Accountant Fees and Services	118
Item 16D.	Exemptions from the Listing Standards for Audit Committees	118
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	119
Item 16F.	Change in Registrant’s Certifying Accountant	119
Item 16G.	Corporate Governance	119
Item 16H.	Mine Safety Disclosure	120
Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	120
PART III
Item 17.	Financial Statements	120
Item 18.	Financial Statements	120
Item 19.	Exhibits	121

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GLOSSARY

ADR	American Depositary Receipt(s)	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.
AFP	Administradora de Fondos de Pensiones	A legal entity that manages a Chilean pension fund.
CEN	Coordinador Eléctrico Nacional	The Chilean system operator. 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.
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.
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 Chilean corporation engaged in non-conventional renewable electricity generation and a subsidiary of Enel Chile.
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, 2021, 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.

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Enel Distribution	Enel Distribución Chile S.A.	A Chilean publicly held limited liability stock corporation engaged in electricity distribution and a subsidiary of Enel Chile operating in the Santiago Metropolitan Region.
Enel Generation	Enel Generación Chile S.A.	A Chilean publicly held limited liability stock corporation engaged in electricity generation and a subsidiary of Enel Chile.
Enel Transmission	Enel Transmisión Chile S.A.	A Chilean publicly held limited liability stock corporation engaged in electricity transformation and transmission and a subsidiary of Enel Chile.
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.
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.
PMGD	Pequeños Medios de Generación Distribuida	A Chilean regime for distributed generation facilities.
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.
SEN	Sistema Eléctrico Nacional	The National Electricity System is the Chilean national interconnected electricity system.
UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit, equivalent to Ch$ 30,991.74 as of December 31, 2021.
VAD	Valor Agregado de Distribución	Value-added from distribution of electricity.

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INTRODUCTION

As used in this Report on Form 20-F (“Report”), first-person personal pronouns such as “we,” “us,” or “our,” as well as “Enel 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, 2021.

We are a Chilean 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.

We are engaged in electricity generation, transmission, and distribution businesses in Chile through our subsidiaries and affiliates. We own 93.5% of Enel Generación Chile S.A. (“Enel Generation”), a Chilean electricity generation company with operations in Chile, 99.9% of Enel Green Power Chile S.A. (“EGP Chile”), a Chilean renewable electricity generation company, 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 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.

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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, 2021, one UF was equivalent to Ch$ 30,991.74. The U.S. dollar equivalent of one UF was US$ 36.69 as of December 31, 2021, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2021, of Ch$ 844.69 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, 2021. 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.

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 Note 2.4, Note 2.5, and Note 2.6 of the Notes to our consolidated financial statements.

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.

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.

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

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.

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FORWARD-LOOKING STATEMENTS

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

● our capital investment program;

● trends affecting our financial condition or results 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.

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PART I

Item  1.      Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.      Offer Statistics and Expected Timetable

Not applicable.

Item 3.      Key Information

A. [Reserved]

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

Material Risks Related to Our Business

Our businesses depend heavily on hydrology and are affected by droughts, flooding, storms, ocean currents, and other chronic changes in weather conditions as a result of climate change.

The fight against climate change is a major global challenge that exposes our businesses to a variety of medium- and long-term risks. Our generation business could be negatively affected by arid hydrological conditions, which could negatively affect our ability to dispatch energy from our hydroelectric generation facilities. 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 distribution business is also affected by inclement weather. With extreme temperatures, demand can increase significantly within a short period, affecting service and resulting in service outages that may result in fines. Depending on weather conditions, results obtained by our distribution business can vary 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. These events significantly increased our costs due to emergency responses, including payments related to damage compensation, fines, line maintenance, and tree trimming programs.

Our operating expenses increase during 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

9

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. Our thermal power plants require water for cooling, and droughts may reduce water availability and increase transportation costs. As a result, we may have to purchase water from agricultural areas that are also experiencing water shortages. These water purchases may increase our operating costs and require us to negotiate further with the local communities. If such negotiations were unsuccessful, we may be unable to operate our power plants.

A full recovery from the droughts affecting the regions in Chile where most of our hydroelectric power plants are located may require an extended period, and new drought periods may recur in the future. Climate change may increase the likelihood of prolonged droughts exacerbating the risks described above, which would have a further negative effect on our business, results of operations, and financial condition.

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 these facilities. Although we base our business decisions on solar and wind studies for each renewable energy facility, actual conditions may not conform to the findings of these studies. 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 electricity from our backup thermal power plants to make up the electricity generation shortfall. Our thermal power plants have higher operating costs and generate greenhouse gas (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. In 2021, spot prices reached historic highs. 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, fiduciary obligations, contractual limitations, and foreign exchange controls imposed by local authorities.

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. Insufficient cash flows from our subsidiaries may result in their inability to meet debt obligations and the need to seek waivers to comply with some debt covenants. To a limited extent, these subsidiaries may require guarantees or other emergency measures from us as shareholders. For further details regarding financial support provided to our subsidiaries, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

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

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Construction and operation of power plants may encounter significant delays, stoppages, cost overruns, and stakeholder opposition that may damage our reputation and impair our goodwill with stakeholders.

Our power plant projects may be delayed in obtaining regulatory approvals or may face shortages and increases in the price of equipment, materials, or labor. They may be subject to construction delays, strikes, accidents, and human error. Any such event could negatively affect our business, results of operations, and financial condition.

Market conditions may change significantly between the approval and completion of a project, which, in some cases, may decrease its profitability or render it impracticable. 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 with challenging geographical topography, such as mountain slopes, high altitudes, or other areas with limited access. Additionally, given some projects’ locations, there may be additional inherent risks to archaeological heritage sites. These factors may also lead to significant delays and cost overruns.

The operation of our power plants, especially those that are coal-fired, may also affect our goodwill with stakeholders due to GHG emissions that could adversely affect the environment and local residents. In addition, communities might have their own interests and different perceptions of the company, being influenced by other stakeholders or motivations unrelated to the project. Therefore, if the company fails to engage with its relevant stakeholders, we may face opposition, which could negatively affect our reputation, impact operations, or lead to litigation threats or actions.

Our reputation is the foundation of our relationship with key stakeholders and other constituencies Any damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, possibly leading to the abandonment of projects and operations, which 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. If we do not effectively manage these sensitive issues, they could adversely affect our business, results of operations, and financial condition.

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

We have exposure to fluctuations in certain commodity market prices that affect our long-term electricity sales contracts. These contracts commit our generation subsidiaries 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 can charge under these contracts, which could adversely affect our business, results of operations, and financial condition.

We are subject to incremental risks in distribution markets that are becoming more liberalized.

In our distribution business, some customers who meet certain requirements are free to choose between regulated and unregulated tariffs. 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, which could adversely affect our business, results of operations, and financial condition.

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

We depend on transmission facilities owned and operated by other companies to deliver the electricity we sell. This dependence exposes us to several risks. If the transmission is disrupted, or its capacity is inadequate, we may be unable to sell and deliver our electricity, particularly electricity generated by our solar and wind plants, which requires more flexibility. 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 that 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. As a result, renewable energy generation projects are being completed faster than new transmission projects, creating a backlog of electricity that is difficult to transmit through current transmission systems. 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 be unable to reach satisfactory collective bargaining agreements with our unionized employees or retain key employees in labor conflict cases.

Our business relies on attracting and retaining many highly specialized employees, and 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. Specific actions such as strikes, walkouts, or work stoppages by these employees could negatively impact 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.

On an ongoing basis, we carry out mergers and review acquisition prospects to expand our operations, which may increase our market coverage or provide synergies with our existing businesses. 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 may be a complicated, costly, and time-consuming process that may strain our resources and relationships with our employees and customers.

These mergers and acquisitions may not ultimately be successful or achieve the expected benefits and may encounter delays or difficulties in connection with the integration of their operations due to a number of factors, including but not limited to:

● inconsistencies in standards, controls, procedures and policies, business cultures, and compensation structures;

● difficulties in integrating various business-specific operating procedures and systems, as well as our financial, accounting, information, and other systems;

● complications in retaining key employees, customers, and suppliers;

● unexpected transaction costs or failures in the assessed value or a proper projection of the potential benefits and synergies; and

● diversion of our management’s attention from their other responsibilities.

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Any of these risks encountered in the integration process could have a material adverse effect on our revenues, expenses, results of operations, and 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 network 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 other individuals. IT Systems are critical to controlling and monitoring our power plants’ operations, maintaining generation and network performance, monitoring smart grids, managing billing processes and customer service platforms, achieving operating efficiencies, and meeting our service targets and standards in our generation and distribution businesses. The operation of our generation system is dependent not only on the physical interconnection of our facilities with the electricity network infrastructure but also on communications among the various parties connected to the network. The reliance on IT Systems to manage information and communication among those parties has increased significantly since the implementation of smart meters and intelligent grids in Chile.

Our generation and 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. Cybersecurity incidents have evolved dramatically in recent years, and the number of incidents and their degree of impact have grown exponentially, making it increasingly difficult to identify their source in a timely manner. Our industry has begun to see an increase in 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 business 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 various events that could increase our liability exposure. Our generation and distribution business systems are part of an interconnected system. Given the role of electricity as a vital resource in modern society, a widespread or prolonged 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 have broad socio-economic ramifications across households, businesses, and vital institutions, which could unfavorably affect our business.

Our businesses require the collection and storage 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 information, or other unauthorized disclosure of personal or sensitive data, may lead to 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. 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, such as penalties, third-party claims, repairs, increased insurance expense, litigation, notification and remediation, security, and compliance costs.

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Material Risks 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 electricity businesses are subject to extensive regulation, inspections, and audits. The tariffs we charge to our customers are a result of a tariff-setting process defined by regulators, which may negatively affect our profitability. Our business is also exposed to the decision of governmental authorities regarding material rationing policies during droughts or prolonged failures of power facilities, or regulatory changes that may unfavorably affect our future operations and profitability.

For example, in the context of the social crisis that began in October 2019, the government enacted Law No. 21,185, which 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 8 and Note 27 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.

In August 2020, the Ministry of Energy’s Law No. 21,249 (“Ley de Servicios Básicos” or the Basic Services Law) was enacted to prohibit electricity distribution companies from cutting services due to late payment for 90 days following the publication of the law for residential customers, small businesses, hospitals, and firefighters, among others. 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. In December 2021, the Chilean association of power distribution companies (“Empresas Eléctricas”) announced that its members (CGE, Chilquinta, Enel Distribución, and Grupo Saesa) would extend until January 31, 2022, the prohibition on cutting service to customers for non-payment of electricity bills, despite the law expiring on December 31, 2021.

On December 29, 2020, Law No. 21,301 was ratified and extended the Basic Services Law, increasing the prohibition on cutting off services from 90 days to 270 days, as well as the maximum number of monthly installments from 12 to 36. On May 13, 2021, Law No. 21,340 was enacted, which extended the effects of the Basic Services Law until December 31, 2021. Additionally, the number of installments was increased to a maximum of 48 monthly installments from 36 monthly installments.

On February 11, 2022, Law No. 21,243 established a payment schedule for all debts arising from the application of Law No. 21,249, through which each customer may pay their debt in 48 equal monthly installments, with a maximum limit equivalent to 15% of their average billing. Of the balance of the debt that may not be covered in the 48 installments, 50% will be absorbed by distribution companies and the remaining 50% will be applied to the distribution tariffs in the tariff process that will be carried out after the expiration of the 48 installments. As a result of the application

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of this law, we estimate that during the year 2022 we will have to recognize a greater loss due to impairment of our accounts receivable of up to approximately ThCh$ 980,000. Please see Note 40 of the Notes to our consolidated financial statements for further information.

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, sometimes unexpectedly. 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 the original implementation and ongoing emission standard requirements of monitoring systems 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.

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

Our business faces risks from the Chilean government’s decarbonization efforts.

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 subsidiary Enel Generation 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. In November 2021, the Chilean National Electricity Coordinator (“CEN” in its Spanish acronym) proposed that we postpone the closure of the Bocamina II plant due to potential electricity supply restrictions that the Chilean electricity system could face in the near future. We did not accept the proposal and continue to maintain the original expected closure date.

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, if water concessions are granted with a limited duration, or if the cost of water rights is increased.

The Chilean Water Authority (“Dirección General de Aguas”) grants us water rights for water supply from rivers and lakes near our generation facilities. Currently, these water rights:

● are for an unlimited duration;

● are absolute and unconditional property rights; and

● are 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.

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

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

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, such as net zero emissions, may require higher levels of investment in new, more efficient technologies. Failure to monitor or delay the adoption of new technologies may jeopardize our ability to adapt to climate change and may involve additional costs to operate and maintain our equipment and facilities, 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.

Material Risks 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.

All our operations are in Chile. Accordingly, our consolidated revenues may be affected by the performance of the Chilean economy. Chile is also vulnerable to external shocks in other countries, 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, 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, which could adversely affect our results of operations and financial condition.

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. Changes in social, political, regulatory, and economic conditions or in laws and policies governing foreign trade, manufacturing, development, and investment in Chile, as well as crises and political uncertainties in Chile, could adversely affect economic growth in Chile. In October and November 2019, Chile experienced riots and widespread mass demonstrations in Santiago and other major cities in Chile, triggered by an increase in public transportation fares in the city of Santiago, which involved violence and significant property damage and caused commercial disruptions throughout the country. The demonstrations expanded to include several social and economic concerns, including the cost of healthcare and education, exploitation of natural resources, pensions, and income equality. As a result, the Chilean government has introduced several social reforms, and in a November 2020 referendum, Chilean citizens strongly supported convening a constitutional convention to draft a new Chilean constitution. Any new constitution could alter the Chilean political situation, affect the Chilean economy, its business outlook, 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.

We cannot give any assurance that these reforms and proposals or the constitutional reform process will resolve the social and economic concerns or that mass protests or civil unrest will not resume. The long-term effects of this social unrest are hard to predict but could include slower economic growth, which could adversely affect our business, results of operations, and financial condition.

In addition, in December 2021, Chile elected Gabriel Boric as the new president. President Boric took office on March 11, 2022, and his agenda is mainly focused on the elimination of private pension funds, social security programs, increases in the minimum wage and pensions, and increases in corporate taxes. President Boric is also a strong supporter

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of the constitutional reforms being considered by the constitutional convention drafting a new Chilean constitution. While it is still very early in President Boric’s term, and there is uncertainty regarding how his reforms may affect the political and business climate in Chile in the future, these reforms could lead to higher-than-expected inflation levels, unemployment, higher corporate taxes, and financial constraints on small- and medium-sized companies, any of which could negatively 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 growth, 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 in Chilean financial and capital markets may be affected by international events, which could unfavorably affect the value of our securities.

Changes to the Chilean constitution could impact a wide range of rights, including water rights and property rights generally, and could affect our business, results of operations, and financial condition.

A new Chilean constitution is in the process of being drafted by a constitutional convention, which was convened on July 4, 2021. The constitutional convention will have approximately one year to draft an entirely new constitution. A wide range of rights could potentially be under consideration for reform under the new constitution, including water rights and property rights generally. If approved by the constitutional convention, the final draft of the new constitution will be submitted for approval to a public referendum with mandatory participation and would require a simple majority vote for approval. If a new constitution is not approved, the existing constitution, which has been in place since 1980, would remain in effect. There can be no assurance that the constitutional convention will agree on a draft of a new constitution or that the Chilean citizens will approve any draft constitution approved by the constitutional convention. Any changes to rights under a new constitution could change the political situation of Chile and affect the Chilean economy and the business outlook for the country generally and our business, results of operations, and financial condition.

We may be subject to the effects of the armed conflict between Russia and Ukraine.

The effects of the armed conflict between Russia and Ukraine, which began in February 2022, on our company are unknown. Although we do not have direct business transactions with suppliers, clients, or lenders from Russia or Ukraine, our business, results of operations, and financial condition may be impacted by (i) limited access to financial markets; (ii) possible interruptions in the global supply chain; (iii) volatility in commodity prices; and (iv) an increase in inflationary pressures in Chile, which could increase the rates charged to our customers.

We are subject to the adverse effects of worldwide pandemics.

In response to the Covid-19 pandemic that began in December 2019 and was declared by the World Health Organization as a public health emergency of international concern, the Chilean government declared a state of emergency (“estado de excepción constitucional de catástrofe”), instituted nighttime curfews, 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.

All of these measures, as well as other government restrictions, temporarily disrupted our business and operations, decreased the demand for electricity, destabilized financial markets, negatively affected the global supply chain, and compromised our ability to generate income. As a result, Chile experienced negative growth in GDP in 2020, and these disruptions significantly impacted our 2020 performance. For example, during 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 estimate that the impact on our net income caused by the Covid-19 pandemic stemmed from lower energy demand and increased uncollectible debts. However, the Chilean government loosened restrictions in 2021, and Chile experienced a rebound in economic activity that resulted in positive growth in GDP in 2021. As restrictions loosened, the demand for electricity increased, which positively impacted our net income in 2021. For further information with

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respect to the pandemic effect on our business and financial results, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results.”

The recent emergence of new Covid-19 variants and increases in infection rates may result in a reimposition of governmental and private sector measures in response. If there is a resurgence of the Covid-19 pandemic or similar outbreaks in the future, our business, results of operations, and financial condition may be materially adversely affected.

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

Our functional currency is the Chilean peso, which has been subject to devaluations and appreciations against the U.S. dollar and may be subject to significant fluctuations in the future. In 2021, the Chilean peso depreciated by approximately 16% against the U.S. dollar, and the U.S. dollar Observed Exchange Rate peaked at Ch$ 868.76 per US$ 1.00 on December 21, 2021. 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.

Material Risks Related to Ownership of Our Shares and ADSs

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 a beneficial interest of 64.9% of our share capital as of the date of this Report. Under Law No. 18,046 (the “Chilean Corporations Law”), Enel has the power to determine the outcome of all material matters that require a simple majority of shareholders’ votes, such as the election of most 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. 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 ADSs.

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 ADSs to sell shares of our common stock withdrawn from the ADS program, on the 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 for fiscal year 2020, which has been remediated; however, if we experience additional material weaknesses or otherwise fail to maintain an

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effective system of internal control over financial reporting, it could result in material misstatements of our consolidated financial statements, or cause us to fail to meet our periodic reporting obligations.

In connection with the preparation of our financial statements as of and for the year ended December 31, 2020, we identified a material weakness in our internal control over financial reporting related to our general information technology controls, including the design and implementation of changes to management controls. As a result, as reported in our annual report on Form 20-F for the year ended December 31, 2020, our management concluded that as of December 31, 2020, our internal control over financial reporting was not effective, although our consolidated financial statements as of and for the year ended December 31, 2020, 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.

A 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. We believe we have taken the necessary steps to remediate the identified material weakness and enhance our internal controls. Accordingly, our management has concluded that, as of December 31, 2021, our internal control over financial reporting was effective. See “Item 15. Controls and Procedures—Disclosure Control and Procedures.”

If we experience additional material weaknesses or otherwise fail to maintain an effective system of internal control over financial reporting, it 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.

General Risk Factors

Our electricity business is subject to risks arising from extreme weather events related to climate change, 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 transmission and distribution assets that are exposed to damage from the increased severity and frequency of extreme weather events, such as cyclones, hurricanes, or floods, due to climate change, catastrophic natural disasters, such as earthquakes and fires, and human causes, such as 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 and could require us to incur unplanned capital expenditures. 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.

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, 2021, our consolidated debt totaled Ch$ 4.3 trillion mainly consisting of accounts payable to related parties and financial liabilities. Please see Note 9 and Note 19 of the Notes to our consolidated financial statements for further information.

A significant portion of our financial indebtedness is subject to (i) financial covenants, (ii) affirmative and negative covenants, (iii) events of default, (iv) mandatory prepayments for contractual breaches, (v) change of control clauses for material mergers and divestments, (vi) bankruptcy and insolvency proceeding covenants, and (vii) cross-default provisions, which have varying definitions, criteria, materiality thresholds, and applicability concerning

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subsidiaries that could result in a cross-default event. Our debt may also become immediately due and payable in cases involving bankruptcy or insolvency proceedings of a significant or material subsidiary.

The market conditions prevailing at any time may prevent us from accessing capital markets or satisfying our financial needs to fund new projects. We may also be unable to raise the necessary funds required to finish our projects under development or construction. Likewise, we may be unable to refinance our debt or obtain such refinancing in 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. 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.

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.

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

Our electricity businesses may be subject to regulatory sanctions for any breach of current regulations, including failures to supply energy. Local regulatory entities supervise our generation subsidiaries. We may be subject to sanctions 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. Please see Note 37 of the Notes to our consolidated financial statements for further information on sanctions.

We are involved in litigation proceedings.

We are involved in various litigation proceedings, including lawsuits and arbitrations, that could result in unfavorable decisions or financial penalties against us. Given the difficulty of predicting the outcome of legal matters, we have no certainty about the most likely outcome of these proceedings or what the eventual fines or penalties related to each litigation may be. Although we intend to defend our positions vigorously, our defense of these litigation proceedings may not be successful and responding to such lawsuits and arbitrations diverts resources and our management’s attention from day-to-day operations.

Our financial condition or results of operations could be unfavorably affected if we are unsuccessful in defending these litigations or other lawsuits and legal proceedings against us. Please see Note 35.3 of the Notes to our consolidated financial statements for further information on litigation proceedings.

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 legal name is Enel Chile S.A., and we are also known commercially as “Enel Chile.” As of December 31, 2021, 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 ADSs are listed and traded on the NYSE under the trading symbol “ENIC.”

Our contact information for the Investor Relations Department in Chile is:

Contact Person:	Isabela Klemes
Street Address:	Av. Santa Rosa 76, Piso 15 Comuna de Santiago Santiago, Chile

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Email:	ir.enelchile@enel.com
Telephone:	(56-2) 2353-4400
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.

The Chilean electric utility sector was reorganized in the 1980s under the Chilean Electricity Law, known as Decree with Force of Law No. 1 of 1982 (“DFL1”). In August 1988, Compañía Chilena Metropolitana de Distribución Eléctrica S.A., our predecessor company, changed its name to Enersis S.A. (“Enersis” and currently known as Enel Américas S.A.) and 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.). In 2016 Enersis separated its Chilean business from the rest of the South American countries’ businesses. As a result of the demerger, Enersis Chile was created and changed its name to Enel Chile. As of December 31, 2021, Enel Chile owns 99.1% of both Enel Distribution and Enel Transmission, and 93.5% of Enel Generation.

Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires a Chilean distribution company 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 a result, Enel Distribution carried out a corporate reorganization on January 1, 2021, pursuant to which its distribution and transmission business lines were separated into two separate companies and Enel Transmission was spun-off as a separate publicly traded company. The energy commercialization segment, formerly operated by Enel Distribution, was transferred to Enel Generation Chile to improve synergies and cost-efficiency among affiliates.

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 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 2022-2024 period, we expect to make capital expenditures of Ch$ 2.2 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 2022-2024 period and the capital expenditures incurred in 2021, 2020, and 2019:

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	Estimated 2022-2024	2021	2020	2019
	(in millions of Ch$)
Capital Expenditure(1)(2)	2,196,194	786,073	554,314	321,079

(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.

(2) Estimated capital expenditure for 2022-2024 period corresponds to US$ 2.6 billion, calculated based on the Observed Exchange Rate as of December 31, 2021.

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 November 2021. Please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further information.

Capital Expenditures in 2021, 2020, and 2019

In the last three years, our capital expenditures were principally related to the Campos del Sol I, Domeyko, and Sol de Lila solar projects, Los Cóndores hydroelectric power plant, Renaico II wind farms, and maintenance of our existing power plants.

During 2021, our investments in the distribution business focused on facilitating new customer connections, reinforcing feeders, increasing the capacity of our substations, implementing anti-theft, corrective, technological and regulatory measures, and automating our systems through the installation of control remote devices and smart meters for residential customers.

During 2021, our generation business investments focused primarily on (i) solar projects (Azabache, Campos del Sol I and II, Domeyko, and Sol de Lila); (ii) PMGD I and PMGD II solar projects, which comprise a portfolio of distributed generation projects; (iii) hydroelectric projects (Los Cóndores and Rapel); (iv) wind projects (Renaico II, La Cabaña, and Rihue wind farms); and (v) our first green hydrogen project. Please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Completed and Under Construction” for further detail on our projects.

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 engaged in the generation, transmission, and distribution of electricity in Chile through our subsidiaries and affiliates. As of December 31, 2021, we had 8,054 MW of gross installed capacity and 2.0 million distribution customers. Of our total gross installed capacity, 70% corresponds to renewable energies, including 3,561 MW of hydroelectric power plants, 642 MW of wind farms, 1,321 MW of solar plants, and 76 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 and for the year ended December 31, 2021, we had consolidated assets amounting to Ch$ 9.5 trillion and operating revenues of Ch$ 2.9 trillion.

We also participate in other activities that are not core businesses and represent less than 1% of our 2021 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	2021	2020	2019	Change 2021 vs. 2020
	(in millions of Ch$)			(in %)
Generation	1,953,288	1,577,422	1,726,612	23.8
Distribution	1,201,833	1,382,068	1,412,872	(13.0)
Other businesses and intercompany transaction adjustments	(299,891)	(374,088)	(368,649)	19.8
Total revenues	2,855,230	2,585,402	2,770,834	10.4

For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 27 of the Notes to our consolidated financial statements. Please see 35.5 of the Notes to our consolidated financial statements for further information related to the effects of Covid-19 on our business.

Electricity Generation Business Segment

In 2021, our consolidated electricity sales were 28,214 GWh, and our electricity production was 19,034 GWh, representing a 22.9% increase and 1.5% decrease, respectively, compared to 2020. Our total installed capacity in 2021 was 8,054 MW, representing an 11.9% increase compared to 2020, mainly due to solar projects that reached commercial operation during 2021.

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

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

ELECTRICITY DATA

	Year ended December 31,
	2021	2020	2019
Number of generating units(1)	2,317	1,028	1,029
Installed capacity (MW)(2)(3)	8,054	7,200	7,303
Electricity generation (GWh)	19,034	19,331	21,041
Electricity sales (GWh)	28,214	22,960	23,513

(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 2021, 40.7% was from hydroelectric sources, 42.2% was from thermal sources, and 6.5%, 9.1%, and 1.5% were from solar, wind, and geothermal energy sources, respectively.

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

GENERATION BY TYPE OF ENERGY (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric	7,743	40.7	9,712	50.2	10,578	50.3
Solar	1,235	6.5	1,177	6.1	1,190	5.7
Wind	1,731	9.1	1,768	9.1	1,845	8.8
Geothermal	284	1.5	221	1.1	194	0.9
Thermal	8,041	42.2	6,452	33.4	7,233	34.4
Total generation	19,034	100.0	19,331	100.0	21,041	100.0

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,
	2021		2020		2019
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales  Volume
Regulated customers	10,056	35.6	10,838	47.2	12,712	54.1
Unregulated customers	17,528	62.1	11,043	48.1	9,902	42.1
Total contracted sales(1)	27,584	97.8	21,881	95.3	22,614	96.2
Electricity pool market sales	630	2.2	1,079	4.7	899	3.8
Total electricity sales	28,214	100.0	22,960	100.0	23,513	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 through generation companies. 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 unregulated customers are 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.

In 2022, distribution company contracts awarded in the August 2016 auction came into effect. Therefore, the tariffs of our regulated contracts decreased 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 electricity sale contracts that incorporate the expected variable costs considering changes to the most relevant variables. These contracts secure the sale of our current and expected new capacity and allow us to stabilize our income.

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In November 2017, the outcome of a bidding process was announced. This process tendered 2,200 GWh per year to be delivered between 2024 and 2043. 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.

In September 2021, 2,310 GWh per year were tendered to supply electricity to regulated customers for 15 years starting in 2026. As a result, the average awarded price was US$ 23.8 per MWh. We did not have electricity awarded in this process.

Finally, in February 2022, the CNE issued a final prospectus regarding the tender offer 2022/01 related to the auction of 5,250 GWh per year to be delivered to regulated customers for 15 years, starting in 2027. The bidding process will conclude by August 2022.

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 critical reservoirs’ capacity. In addition to 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. For further details about hydrological conditions and their effects on our business, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation and Transmission Business.”

Seasonality

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

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Operations

We participate in electricity generation through our subsidiaries, Enel Generation, EGP Chile, and Pehuenche. As of December 31, 2021, we had 55 generation power plants in Chile with a total net installed capacity of 8,054 MW, representing 29% of the National Electricity System’s (“SEN” in its Spanish acronym) installed capacity in 2021.

Enel Generation owns 13 hydroelectric, 10 thermal, and 2 wind generation power plants, with a total net installed capacity of 5,301 MW. Pehuenche owns 3 hydroelectric power plants, with a net installed capacity of 699 MW. EGP Chile owns 2 hydroelectric power plants, 7 wind farms, 16 solar parks, and 2 geothermal power plants, with a total net installed capacity of approximately 2,053 MW. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

During 2021, the electricity demand throughout the SEN increased by 4.5%. The total electricity demand was 75,065 GWh in 2021, and 71,808 GWh in 2020. Our total generation amounted to 19,034 GWh in 2021, which represents 25.4% of the total demand.

Our total hydroelectric generation accounted for over 40.7% of our total generation in 2021, reaching 7,743 GWh, a decrease of 20% compared to 2020, while our thermal generation accounted for 42.2% of our total generation in 2021, reaching 8,041 GWh, an increase of 25% compared to 2020, in each case mainly due to severe prolonged drought conditions.

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

ELECTRICITY GENERATION BY COMPANY (GWh)

	Year ended December 31,
	2021	2020	2019
Enel Generation	13,648	13,613	15,428
EGP Chile(1)	3,451	3,418	3,493
Pehuenche	1,935	2,300	2,120
Total	19,034	19,331	21,041

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

The following table sets forth the electricity generation by type:

ELECTRICITY GENERATION BY TYPE (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation	7,698	40.4	9,680	50.1	10,523	50.0
Thermal generation	8,041	42.2	6,452	33.4	7,233	34.4
Wind generation – NCRE(1)	1,731	9.1	1,768	9.1	1,845	8.8
Mini-hydro generation – NCRE(2)	45	0.2	32	0.2	55	0.3
Solar generation – NCRE	1,235	6.5	1,177	6.1	1,190	5.7
Geothermal generation – NCRE	284	1.5	221	1.1	194	0.9
Total generation	19,034	100.0	19,331	100.0	21,041	100.0

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

(2) Electricity generated in 2019 refers to the Ojos de Agua mini-hydroelectric plant.

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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 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 some irrigation associations in the Maule basin and Colbún S.A., the electric utility company that owns Colbún Reservoir, 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, February 2021, and August 2021, our subsidiary Pehuenche, Colbún S.A., and the Maule Lagoon Vigilance Board-First Section, signed an agreement to optimize the use of water during drought periods. The agreement, which expires on August 31, 2025, and includes an automatic renewal clause for 58 months, facilitates water accumulation in the Colbún Reservoir in the spring for use in the summer, the peak irrigation period, of 2020/2021 and 2021/2022 irrigation season.

In September 2021, Enel Generation signed an agreement with the Biobío River Basin Vigilance Board to limit the use of the Ralco reservoir during the 2021/2022 irrigation season, along with making more flexible the generation of the Pangue power plant and its reservoir.

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 2021, Enel Generation used 1,409 million cubic meters of LNG for its generation and commercialization requirements, which represents 90% more compared to 2020, mainly explained by the greater needs for electricity generation and lower availability of Argentine gas compared to the previous year.

In 2021, Enel Generation imported 573 million cubic meters of natural gas under supply agreements with YPF, Total Austral, and Pan American Energy, among other producers.

In 2021, 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).

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Concerning the commercialization of LNG by truck, 89 million cubic meters were delivered in 2021, a 27% increase compared to 2020. In 2021, Enel Generation approved the expansion of capacity in the LNG loading yard for trucks at the Quintero LNG Terminal. The project involves the construction of a fifth loading bay with a capacity equivalent to 375,000 cubic meters per day, which is expected to be in operation by the end of 2022.

Generation from NCRE sources

Under Chilean law, electricity generation companies must derive a minimum amount of their electricity 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 4.5% in 2021 compared to 2020.

The following table sets forth SEN’s electricity sales:

ELECTRICITY SALES IN SEN (GWh)

	Year ended December 31,
	2021	2020	2019
Total electricity sales (SEN)	75,065	71,808	71,670

Our electricity sales reached 28,214 GWh in 2021, 22,960 GWh in 2020, and 23,513 GWh in 2019, which represented a 37.6%, 32.0%, and 32.8%, market share, respectively. Energy purchases increased by 153% in 2021, compared to 2020, mainly to comply with our contractual obligations with third parties, which were affected by higher energy demand as a result of new energy supply contracts for a total of approximately 3,200 GWh per year, and restrictions to our hydroelectric generation as a result of droughts and insufficient rainfall.

The following table sets forth our electricity generation and purchases:

ELECTRICITY GENERATION AND PURCHASES (GWh)

	Year ended December 31,
	2021		2020		2019
	(GWh)	% of Volume	(GWh)	% of Volume	(GWh)	% of Volume
Electricity generation	19,034	67.5	19,331	84.2	21,041	89.5
Electricity purchases	9,181	32.5	3,629	15.8	2,472	10.5
Total	28,214	100.0	22,960	100.0	23,513	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 2021, 2020, and 2019, we had 961, 384, and 315 customers, respectively.  In 2021 our customers included 21 regulated customers and 940 unregulated customers. This significant increase in 2021 is mainly due to CNE Resolution 176 issued in 2020, pursuant to which distribution companies may only provide public electricity distribution service and

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are prohibited from selling electricity and power to unregulated customers. As a result, Enel Distribution transferred all its unregulated customers to Enel Generation.

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 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, 2021, our principal distribution customers were (in alphabetical order): Empresa Eléctrica de Puente Alto, Enel Distribution, Grupo CGE, Grupo Chilquinta, and Grupo SAESA.

Our principal unregulated customers were (in alphabetical order): Anglo American Sur, BHP Billiton, Compañia Minera Doña Inés de Collahuasi SCM, Grupo CMPC.

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 44.1% 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 and Transmission Businesses Segment

Our electricity transmission operations are conducted through Enel Transmission, a company that was spun-off from Enel Distribution as of January 1, 2021, and our distribution operations are conducted through Enel Distribution. We have a 99.1% economic interest in both subsidiaries.

We distribute electricity in a concession area of 2,105 square kilometers, under an indefinite concession granted by the Chilean government. We distribute electricity in 33 municipalities in the Santiago metropolitan region. As of December 31, 2021, we distributed electricity to over 2 million customers and residential, commercial, industrial, and other customers, who are primarily municipalities, represented 30.8%, 12.2%, 4.4%, and 52.6%, respectively, of our total electricity sales of 16,668 GWh, which is an increase of 1.1% compared to 2020.

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

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	16,668	16,481	17,135
Residential	5,140	5,006	4,897
Commercial	2,029	4,606	4,924
Industrial	726	1,687	1,954
Other customers(1)	8,773	5,183	5,360
Number of customers (thousands)	2,038	2,008	1,972
Residential	1,826	1,801	1,768
Commercial	156	154	152
Industrial	12	12	13
Other customers(1)	44	41	40
Energy purchased (GWh)(2)	17,472	17,356	18,115
Total energy losses (%)(3)	5.2	5.2	5.0
SAIDI (minutes)	152	171	184
SAIFI (times)	1.5	1.5	1.6
Collection rate(4)	97.5	96.9	99.4

(1) The data for other customers includes tolls.

(2) In 2021, 2020, and 2019, Enel Distribution acquired 41%, 42%, and 42%, 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.

(4) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

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.

For the supply to regulated distribution customers, Enel Distribution has entered into contracts with the following generation companies (in alphabetical order): Acciona Energía Chile Holdings S.A., AES Gener S.A., Colbún S.A., Enel Generation, Engie Energía Chile S.A., and other companies.

For the supply to unregulated distribution customers, Enel Distribution has contracts with 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.

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ELECTRICITY INDUSTRY STRUCTURE AND REGULATORY FRAMEWORK

1. Overview and Industry Structure

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

The Chilean electricity sector is physically divided into three main networks: SEN which extends from Arica in northern Chile to Chiloé in southern Chile, and two smaller isolated networks (Aysén and Magallanes).

The following chart shows the relationships among the different agents in the Chilean electricity market:

Generation

Generators supply electricity to end customers using lines and substations that belong to transmission and distribution companies. The generation segment operates competitively, and 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.

Transmission

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.

Distribution

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 legislation. The electricity network is open access, and distribution tariffs are regulated. Distribution companies must provide electricity to regulated customers within their concession area at regulated prices. According to Law No. 21,914 (“Ley Corta”), distribution companies may not enter into new electricity supply contracts with unregulated customers.

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Concessions

Hydroelectric generation companies require a concession granted by the authorities to operate for an indefinite time, while other types of technologies for generating electricity do not require concessions. The Chilean Ministry of Energy grants distribution concessions for undefined periods and the right to use public areas for building distribution lines. Distribution companies must 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 established by the regulator.

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 more than 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, but must remain in the selected category for at least four years.

Limits on Integration and Concentration

The antitrust legislation established in Decreto con Fuerza de Ley (“DFL”) 211 (modified in 2016 by Law No. 20,945) and the regulations applicable to the electricity industry stated in DFL 4 (“Electricity Law”) and Law No. 20,018 (“Ley General de Servicios Eléctricos”) 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. Companies must also comply with the conditions set forth in Resolution No. 667/2002 and Ley Corta, discussed below.

The transmission sector is subject to the most significant restrictions, mainly because of its open access requirements. The Electricity Law 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. Furthermore, 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 Chilean government antitrust agency, the Tribunal de la Libre Competencia.

Resolution No. 667/2002 states that Enel Chile must keep our generation and distribution segments separate and manage them as independent business units; Enel Chile, Enel Generation, Enel Transmission, and Enel Distribution are registered with the CMF and must remain subject to the regulatory authority of the CMF and comply with the regulations applicable to publicly held limited liability stock corporations, even if any of these companies should lose such designation. The members of our 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 Ley Corta adopted in 2020, the Ministry of Energy requires any Chilean distribution company 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 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.

Electricity Markets

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

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contracts. They balance their contractual obligations with their dispatch by trading deficit and surplus electricity at the spot market price set hourly by the CEN, based on the lowest production cost of the last kWh dispatched.

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 transmission and distribution network. Regulated customers with residential generation units can sell their surpluses to a distribution company under certain conditions (net billing regulation). Since November 2018, Law No. 21,118 has permitted customers with a connected capacity of up to 300 kW to sell their surpluses.

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.

2. Electricity Sector Laws

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 Electricity Law, allowing for the private sector’s renewed participation. Law No. 20,018 and its modifications currently govern the industry under the Electricity Law, the reformed DFL 4, published in 2006 by the Ministry of Economy and its respective regulations included in Decreto Supremo D.S. No. 327/1998.

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 electricity sales by 2025 but grandfathered contracts signed between 2007 and 2013, which have a 10% target by 2024.

3. Principal Regulatory Authorities

Responsible for Setting Policy

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

Responsible for Regulation and Supervisory Body

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

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System Operator

CEN is a centralized dispatch center that coordinates SEN’s operations with an approach that minimizes costs while monitoring the quality of the generation and transmission companies’ service. 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.

CEN schedules energy production of each generating company considering their marginal costs, the maximum capacity a generator may supply to the system at certain peak hours, statistical information, accounting for maintenance time, and arid conditions for hydroelectric power plants. However, it does not take into account the power plants’ contribution to the security of the entire system.

4. Remuneration and Tariffs

Remuneration for Generators

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, also known as the marginal 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.

Transmission Tariffs

The remuneration of existing national and zonal transmission installations is determined by a tariff-setting process conducted every four years regulated by Law No. 20,936. 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 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. 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 and as of the date of this Report the tariff-setting process is ongoing.

Distribution Tariffs

Ley Corta 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 prohibits distribution companies from operating 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”). 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, Ley Corta 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.

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

The tariff-setting process for 2016-2020 concluded in August 2017 and had been effective, retroactively, since November 4, 2016. 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.

5. Environmental Regulations

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

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.

For more information about regulatory framework and matters, see Note 4 of the Notes to our consolidated financial statements.

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, 2021. Enel is a multinational power company and a leading integrated player in the global power and renewables markets. It is one of the largest European utility companies with operations in over 30 countries worldwide and a consolidated installed capacity of approximately 90 GW. Enel distributes electricity through a network of over 2.2 million kilometers to 75 million end users. It is one of the world’s largest network operators and has one of the most extensive customer bases. Enel’s shares are listed on Euronext Milan 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

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

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We consolidated the companies listed in the following table as of December 31, 2021. 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%	3,302	1,900
EGP Chile	99.9%	3,311	326
Electricity Distribution
Enel Distribution	99.1%	1,632	1,165
Electricity Transmission
Enel Transmission	99.1%	363	68

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 55 generation power plants, all located in Chile, of which 18 are hydroelectric (3,561MW of installed capacity), 10 are thermal (2,454 MW of installed capacity), 16 are solar (1,321 MW of installed capacity), and nine are wind-powered (642 MW of installed capacity), and two are geothermal (76 MW of 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)	2021	2020	2019
			(in MW)
Enel Generation	Ralco	Reservoir	690	690	689
	Pangue	Reservoir	467	467	466
	El Toro	Reservoir	450	450	449
	Rapel	Reservoir	377	377	376
	Antuco	Run-of-the-river	321	321	319
	Abanico	Run-of-the-river	136	136	136
	Cipreses	Reservoir	106	106	106
	Sauzal	Run-of-the-river	80	80	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	Run-of-the-river	9	9	9
	Total hydroelectric		2,770	2,770	2,759
	Atacama	Combined Cycle /Natural Gas+Diesel Oil	732	732	732
	San Isidro 2(3)	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	350	476
	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	—	—	—
	Total thermal		2,454	2,454	2,580
	Canela II	Wind Farm	60	60	60
	Canela I	Wind Farm	18	18	18
	Total wind farm		78	78	78
	Total		5,301	5,302	5,417
Pehuenche	Pehuenche	Reservoir	570	570	568
	Curillinque	Run-of-the-river	89	89	89
	Loma Alta	Run-of-the-river	40	40	40
	Total Pehuenche		699	699	697
EGP Chile	Campos del Sol	Solar	375	—	—
	Domeyko	Solar	204	—	—
	Sol de Lila	Solar	161	—	—
	Parque Solar Finis Terrae	Solar	160	160	160
	Parque Eólico Sierra Gorda Este	Wind	112	112	112
	Eólica Talinay Oriente	Wind	99	99	99
	Eólica Taltal	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	48	41
	Pilmaiquén	Reservoir	41	41	41
	Chañares	Solar	40	40	40
	Solar Diego de Almagro	Solar	36	36	36
	Cerro Pabellón 3	Geothermal	28	—	—
	Parque Solar Finis Terrae Ext	Solar	22	—	—
	Eólica Los Buenos Aires	Wind	24	24	24
	Carrera Pinto I Etapa	Solar	20	20	20
	Lalackama 2	Solar	18	18	18
	Azabache	Solar	61	4	—
	PMGD San Camilo	Solar	3	—	—
	PMD Dadinco	Solar	3	—	—
	Solar La Silla	Solar	2	2	2
	Total EGP Chile (NCRE)		2,053	1,200	1,189
	Total Aggregate Capacity for Enel Chile		8,054	7,200	7,303

(1) The installed capacity corresponds to the gross installed capacity, without taking into account 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

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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) The environmental permit limits the capacity to 740 MW.

(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.

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 concession, networks, and transformers. They include the consolidated property, plant, and equipment figures of our subsidiary Enel Distribution.

Distribution Network – Concession area and Medium and Low Voltage Lines⁽¹⁾

	As of December 31, 2021			As of December 31, 2020			As of December 31, 2019
	Concession Area (km2)	Medium Voltage (Km)	Low Voltage (Km)	Concession Area (km2)	Medium Voltage (Km)	Low Voltage (Km)	Concession Area (km2)	Medium Voltage (Km)	Low Voltage (Km)
Enel Distribution	2,105	5,568	12,011	2,105	5,406	11,960	2,103	5,349	11,819

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

Transformers from Medium to Low Voltage for Distribution⁽¹⁾

	As of December 31, 2021		As of December 31, 2020		As of December 31, 2019
	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)
Enel Distribution	22,137	5,215	21,997	5,108	21,839	4,963

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

Property, Plant, and Equipment of Transmission Companies

As of January 1, 2021, Enel Transmission was spun-off from Enel Distribution. As a result, the assets and liabilities associated to the transmission segment that belonged to Enel Distribution were assigned to Enel Transmission to engage in the transmission business.

The following table identifies the transmission equipment that we own, at the end of each year presented.

Power and Interconnection Substations and Transformers from High to Medium Voltage and Transmission Lines^(1)(2)(3)(4)

	As of December 31, 2021				As of December 31, 2020				As of December 31, 2019
	Number of Substations	Number of Transformers	Capacity (MVA)	Transmission Lines (Km)	Number of Substations	Number of Transformers	Capacity (MVA)	Transmission Lines (Km)	Number of Substations	Number of Transformers	Capacity (MVA)	Transmission Lines (Km)
Enel Transmission (5)	57	169	8,531	683	56	165	8,331	683	56	165	8,331	683

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

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

(3) The installed transformation capacity includes back-up transformers.

(4) Only includes assets that have been authorized for use by the regulatory authority.

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(5) As of January 1, 2021, the transmission business assets were spun-off from Enel Distribution. Figures for 2020 and 2019 correspond to Enel Distribution.

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 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 and Transmission Business Projects

In 2021, our subsidiaries Enel Transmission and Enel Distribution and its subsidiary Enel Colina invested a total of Ch$ 145 billion in projects related to our customers’ natural growth rate, service quality requirements, and safety and information system needs.

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The most relevant investments in 2021 include the following:

● Ch$ 55 billion in the medium and low voltage network to facilitate new customer connections, including residential customers, large volume clients, and real estate projects.

● Ch$ 26.6 billion to reinforce feeders. Automatization of the medium voltage network increased rapidly as a result of the installation of 189 new remote-control devices, reaching a total of 2,572 devices controlled by our centralized network operations center.

● Ch$ 11 billion oriented to our digitalization processes.

● Ch$ 23.9 billion to increase our distribution capacity to high and medium voltage facilities; Bicentenario, Pudahuel, Quilicura, Pajaritos, Altamirano, San Joaquin, San Jose’s Substations, and to reinforce Cerro Navia, Chena, San Bernardo, Vizcaya, Terminal, and El damasco’s feeders

● Ch$11.4 billion to corrective and technological maintenances.

● Ch$ 8 billion to comply with regulations and standards regarding network and substation normalization.

● Ch$ 3 billion in anti-theft measures, such as the shielding and reinforcements of the network.

● Ch$ 4 billion in network relocations due to new highways and requests from municipalities.

● Ch$ 2 billion in public lightning and other programs oriented to reduce losses.

Generation Business Projects

Projects Completed in 2021

EGP Chile

Azabache Solar Project

Azabache is a photovoltaic (“PV”) project in Calama in the Antofagasta Region in northern Chile and was 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 required 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 was US$ 56.0 million. Construction began in April 2020 and the project was completed in 2021. The commercial operation is expected in June 2022.

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 375 MW of installed capacity and consists of 974,400 crystalline bifacial PV

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modules with a solar tracking system. It is the largest PV solar power plant in Chile, covering approximately 1,700 hectares. The connection point includes two main transformers through the Carrera Pinto substation, owned by Transelec, through a 7.5 km, 220 kV transmission line.

The project was awarded to EGP Chile during the 2016 Distribution Companies Tender. The project has potential synergies with EGP Chile’s operational Carrera Pinto solar project.

The total approved investment was US$ 327.9 million. Construction began in August 2019, and was completed in December 2021. The project reached commercial operation by March 2022.

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

The total approved investment was US$ 164.2 million, of which US$ 160.6 million had been incurred as of December 31, 2021. Construction began in May 2020 and the project was completed in 2021. The commercial operation is expected in June 2022.

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 was required.

It is a greenfield solar project with an installed capacity of 161 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 S.A., and includes one main transformer and a 1.2 km, 220 kV transmission line.

The total approved investment was US$ 134.6 million. Construction began in February 2020 and the project was completed in 2021. The commercial operation is expected in June 2022..

San Camilo and Dadinco PMGD I Solar Project

San Camilo and Dadinco are part of the PMGD I Solar Project, which consists of a portfolio of 10 solar PV plants to develop 75 MW of installed capacity by 2022 in the Metropolitan, O’Higgins, and Maule Regions of Chile. The San Camilo and Dadinco projects added 3 MW of installed capacity each and are connected to the distribution lines.

The total approved investments for San Camilo and Dadinco were US$ 2.0 million and US$ 2.01 million, respectively. Construction began in December 2020 and was completed by April 2021.

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Projects under Construction in 2021

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 is composed of two stages:

● Stage 1: This stage includes the closure of 67,000 m² of the landfill, comprises waterproofing materials that include a conductive geomembrane, and increasing the thicknesses of fillers and substrates.

● Stage 2: This stage includes reforestation with a high density of native specimens per hectare and includes maintenance and monitoring procedures for the species planted with the advice of Universidad de Concepción.

The total approved investment is €15.9 million, of which €14.1 million had been incurred as of December 31, 2021. We expect the project to be completed by 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 that 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.

As of December 31, 2021, 87% of the project had been completed, and 96% of the transmission lines had been completed and assembled.

The total approved investment is US$ 1.2 billion, of which US$ 935.7 million had been incurred as of December 31, 2021. Construction began in April 2014, and we expect the project to be completed by 2023.

Rapel Hydroelectric Repowering Project

The Rapel Hydroelectric Repowering project is being executed within our existing 377 MW Rapel power plant, located in the 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, 2021, 19% of the project had been completed. In 2021, the engineering design was completed while model tests and the principal manufacturing activities were 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 US$ 2.7 million had been incurred as of December 31, 2021. We expect both units to be installed and the project to be completed by 2023.

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EGP Chile

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$ 117.6 million, of which US$ 110.9 million had been incurred as of December 31, 2021. Construction began in August 2019, and we expect the project to be completed in 2022.

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. A new bay unit and new power transformer will be installed in the current substation for interconnection purposes.

The total approved investment is US$ 103.5 million, of which US$ 82.1 million had been incurred as of December 31, 2021. Construction began in May 2020, and we expect the project to be completed in 2022.

Finis Terrae 3 Solar Project

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 approved investment is US$ 11.1 million, of which US $ 5.1 million had been incurred as of December 31, 2021. Construction began in August 2021, and we expect the project to be completed in 2022.

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 project will connect to 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 through a 220 kV transmission line.

The total approved investment is US$ 313.5 million, of which US$ 141 million had been incurred as of December 31, 2021. The construction began in July 2021, and we expect the project to be completed in 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

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voltage substation. It consists of 830,000 monocrystalline bifacial PV modules with a solar tracking system. The project will connect to the Centinela substation located 19 km from the solar plant, in the Centinela substation owned by Red Eléctrica Chile.

The total approved investment is US$ 252.5 million, of which US$ 98.3 million had been incurred as of December 31, 2021. The construction began in July 2021, and we expect the project to be completed in 2022.

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 of 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 and a solar tracking system. The project site occupies 320 hectares. Valle del Sol will connect to the Miraje substation, owned by Transelec, through 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 approved investment is US$ 126.5 million, of which US$ 112.1 million had been incurred as of December 31, 2021. Construction began in 2021, and we expect the project to be completed in 2022.

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 wind farms: (i) the Las Viñas project, including a 58.5 MW wind power plant built by EGP Chile; and (ii) the 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 and will be 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$ 198.6 million, of which US$ 168.7million had been incurred as of December 31, 2021. Construction began in April 2020, and we expect the project to be completed in 2022.

PMGD I Solar Project

The PMGD I Solar Project consists of a portfolio of 10 solar PV plants to develop 75 MW of installed capacity by 2022 in the Metropolitan, O’Higgins, and Maule Regions of Chile. Each project is connected to the distribution lines.

There were two projects (San Camilo and Dadinco) completed in 2021, and currently there are eight projects (Agrovision, Caracoles, Curamachi, Doña Rodriga, La Colonia, Piduco, Rinconada, and Villa Alegre) under construction for a total of 69 MW with an approved investment of US$ 47.5 million of which $ 21.1 million had been incurred as of December 31, 2021.

PMGD II Solar Project

The PMGD II Solar Project consists of a portfolio of projects with an installed capacity of up to 10 MW. Each project is connected to the distribution lines.

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Currently, the projects under construction are El Sharon, Don Rodrigo, and Valera. El Sharon is located in the O’Higgins Region and Don Rodrigo and Valera are in the Maule Region of Chile. These projects have an installed capacity of 3, 5, and 3 MW, respectively, with an approved investment of US$ 9.9 million, of which US$ 6.8 million had been incurred as of December 31, 2021. Construction began in July 2021, and we expect the projects to be completed in 2022.

Pilot Green Hydrogen Project

The Pilot Green Hydrogen Project is in the Magallanes Region in southern Chile. The region has one of the best wind conditions due to its proximity to Antarctica.

The project expects to produce 20.5 kg of hydrogen per hour through a wind farm with 3.4 MW of total capacity and the installation of an electrolyzer for a capacity of approximately 1.2 MW.

The total estimated investment is US$ 4.1 million, of which US$ 0.8 million had been incurred as of December 31, 2021. Construction began in August 2021, and we expect the project to be completed in 2023.

Projects under Development in 2021

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 takes advantage of the heat of the gases emitted by the existing turbines to produce steam by installing a steam turbine and a generator, converting the existing open-cycle plant into a combined-cycle gas plant. Currently, the Quintero plant has two gas turbines with a total capacity of 257 MW. With a steam turbine unit of 130 MW capacity, the Quintero plant would reach a full capacity of 387 MW. We would 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$ 2,855 million, equivalent to US$ 3.4 million, calculated based on the foreign exchange rate as of December 31, 2021, had been incurred as of December 31, 2021.

San Isidro Power Plant Upgrade

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 (Unit 1 and Unit 2), with a total installed capacity of 767 MW which is limited to 740 MW due to environmental authorizations. The project consists of upgrading the existing gas turbine to improve the Unit 2 efficiency and recover 15 MW within the approved environmental permit.

The total estimated investment is € 17 million, of which US$ 9.8 million had been incurred as of December 31, 2021. We expect construction to begin in 2022 and the project to be completed and in operation during 2022.

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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 through 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 Antofagasta 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$ 2,873 million, equivalent to US$ 3.4 million, calculated based on the foreign exchange rate as of December 31, 2021, had been incurred as of December 31, 2021. We expect construction to begin in 2022 and the project to be completed by 2023.

EGP Chile

La Cabaña and Rihue Wind Farm and Battery Energy Storage System (BESS)

The La Cabaña and Rihue wind farms are located in the Araucanía and Biobío Regions in southern Chile, respectively. The projects have a total installed capacity of 226 MW (120 MW for Rihue and 106 MW for La Cabaña) and the BESS system has a total capacity of 60 MW. The project would connect to the Renaico substation.

The total approved investment is US$ 389.1 million, of which US$ 23.7 million had been incurred as of December 31, 2021. We expect construction to begin in 2022 and the project to be completed in 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 approved investment is US$ 78.1 million, of which US$ 8.4 million had been incurred as of December 31, 2021. We expect construction to begin in 2022 and the project to be completed in 2023.

Major Encumbrances

As of December 31, 2021, we did not have any major encumbrances.

Item  4A.      Unresolved Staff Comments

None.

Item  5.      Operating and Financial Review and Prospects

Introduction

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, 2021, and 2020, and for the three years ended December 31, 2021, are derived from our audited consolidated financial statements included in this Report. Our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB.

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The tables are expressed in millions, except for ratios, operating data, and data for shares and 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, 2021, has been converted at the U.S. dollar Observed Exchange Rate for that date of Ch$ 844.69 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.

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

	For the year ended December 31,
	2021(1)	2021	2020	2019
	(US$ millions)	(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income	3,380	2,855,230	2,585,402	2,770,834
Raw materials and consumables used	(2,381)	(2,011,305)	(1,374,445)	(1,421,205)
Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense, by nature	(692)	(584,330)	(1,245,212)	(823,574)
Operating income (loss)	307	259,594	(34,255)	526,055
Financial results(2)	(186)	(157,059)	(112,435)	(150,893)
Other gains	12	10,137	9,489	1,793
Share of profit (loss) of associates and joint ventures accounted for using the equity method	4	3,177	3,509	366
Income (loss) before income taxes	137	115,849	(133,692)	377,321
Income taxes	(18)	(15,139)	81,305	(61,228)
Net income	119	100,710	(52,387)	316,093
Net income attributable to the parent Company	101	85,154	(50,860)	296,154
Net income attributable to non-controlling interests	18	15,556	(1,527)	19,939
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)	0.001	1.23	(0.74)	4.28
Total basic and diluted earnings per average number of ADS (Ch$/US$ per ADS)	0.073	61.56	(36.77)	214.09
Cash dividends per share (Ch$/US$ per share)	0.004	3.08	4.23	3.14
Cash dividends per ADS (Ch$/US$ per ADS)	0.182	154.00	211.50	157.00
Weighted average number of shares of common stock (millions)	69,167	69,167	69,167	69,167
Other Consolidated Financial Data
Capital expenditures (CAPEX)(3)	931	786,073	554,314	321,079
Depreciation, amortization and impairment losses(4)	311	262,592	942,931	527,437
	As of December 31,
	2021(1)	2021	2020
	(US$ millions)	(Ch$ millions)
Consolidated Statement of Financial Position Data
Total assets	11,247	9,500,324	7,904,472
Non-current liabilities	4,761	4,021,504	3,264,717
Equity attributable to the parent company	3,667	3,097,868	3,351,916
Equity attributable to non-controlling interests	294	248,625	242,359
Total equity	3,962	3,346,493	3,594,275
Capital stock (5)	4,596	3,882,103	3,882,103

(1) Solely for the reader’s convenience, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 844.69 per U.S. dollar, as of December 31, 2021.

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

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

(4) Please refer to Note 30 of the Notes to our consolidated financial statements for further detail.

(5) Capital stock represents issued capital.

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Exchange Rates

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the price in Chilean pesos of our shares of common stock on the Chilean Stock Exchanges. 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 foreign currency 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 purchased either in the Formal or the Informal Exchange Market, but such payments and distributions must be remitted through the Formal Exchange Market.

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 2021, one determines the percentage change between the reciprocal of Ch$ 710.95, the value of one U.S. dollar as of December 31, 2020, or 0.0014066, and the reciprocal of Ch$ 844.69, the value of one U.S. dollar as of December 31, 2021, or 0.0011839. In this example, the percentage change between the two periods is 15.8%, representing the 2021 year-end depreciation of the Chilean peso against the 2020 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2017, through December 31, 2021, 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,
2021	844.69	(15.8)
2020	710.95	5.3
2019	748.74	(7.2)
2018	694.77	(11.5)
2017	614.75	8.9

Source: Central Bank of Chile.

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

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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 the selected financial data included above. Our audited consolidated financial statements as of December 31, 2021, and 2020 and for each year in the three-year period ended December 31, 2021, 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.

On November 2, 2019, the Chilean Ministry of Energy published Law No. 21,185, which established a transitional mechanism for stabilizing customers’ electricity prices under the regulated price system (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 CNE 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, 2021, and 2020 are described in Note 8a.1 of the Notes 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 15.c.iv and 30.b. of the Notes 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 27.3 of the Notes to our consolidated financial statements.

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, 2021, 2020, and 2019 was 8,054 MW, 7,200 MW and 7,303 MW, respectively, of which 44.2%, 49.5%, and 48.6% were hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”

Hydroelectric generation was 7,743 GWh, 9,712 GWh, and 10,578 GWh in 2021, 2020, and 2019, respectively. Our hydroelectric generation decreased in 2021 compared to 2020, 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

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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 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.

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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 and Transmission Business

During the year ended December 31, 2021, 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, 2021, electricity sales were 16,668 GWh, representing a 1.1% increase compared to 2020. For the year ended December 31, 2020, electricity sales amounted to 16,481 GWh, representing a 3.8% decrease compared to 2019.

Distribution and transmission 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 and transmission 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 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

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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% for the 2018-2021 period, 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 a 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.

On December 21, 2019, the Chilean Ministry of Energy issued Law No. 21,194 (the “Distribution Short Law”) that reduces distribution companies’ rate of return and improves the electricity distribution tariff setting process. The Distribution Short Law eliminates the prior methodology that involved weighing the results of the VAD study performed by the CNE (two-thirds) and the VAD study performed by distribution companies (one-third), and replaces it by using only the CNE’s VAD study. The discount rate in the calculation of the annual investment cost was also modified. The previous 10% real annual pre-tax discount rate was replaced by a 6% real annual after-tax discount rate to be applied in the following tariff setting process that began on November 4, 2020. The after-tax economic rate of return of distribution companies may not be more than 2 percentage points higher or 3 percentage points lower than the rate determined by the CNE. The new tariff for the following four-year tariff period will be defined during the first half of 2022 and will be effective retroactively as of November 2020.

In response to the Covid-19 pandemic, Law No. 21,249 (the “Basic Services Law”) was published on August 8, 2020, providing exceptional measures for end-users of health services, electricity, and natural gas. The law prohibits electricity distribution companies from cutting services for residential customers, small businesses, hospitals, and firefighters, among others, 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 Basic Services Law, increasing the prohibition on cutting off services from 90 days to 270 days, as well as the maximum number of monthly installments from 12 to 36. On May 13, 2021, Law No. 21,340 was enacted, which extended the effects of the Basic Services Law until December 31, 2021. Additionally, the number of installments was increased to a maximum of 48 monthly installments from 36 monthly installments.

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On February 11, 2022, Law No. 21,423 established a payment schedule for all debts arising from the application of Law No. 21,249, through which each customer may pay their debt in 48 equal monthly installments, with a maximum limit equivalent to 15% of their average billing. The balance of the debt that may not be covered in the 48 installments will be absorbed by the distribution company. As a result of the application of this law, the Company estimates that during the year 2022 it will have to recognize a greater loss due to impairment of its accounts receivable of up to approximately ThCh$ 980,000. Please see Note 40 of the Notes to our consolidated financial statements for further information.

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 — C. 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 — C. Risk Factors — Fluctuations in the 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
	2021		2020		2019
	Average	Year End	Average	Year End	Average	Year End
Chilean pesos per U.S. dollar	759.06	844.69	790.92	710.95	702.63	748.74

Source: Central Bank of Chile

2. Analysis of Results of Operations for the Years Ended December 31, 2021, and 2020

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, 2021, and 2020:

	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,953,288	1,577,422	375,866	23.8
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	1,201,833	1,382,068	(180,235)	(13.0)
Non-electricity business and consolidation adjustments	(299,891)	(374,088)	74,197	19.8
Total Revenues and Other Operating Income (Loss)	2,855,230	2,585,402	269,828	10.4

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business increased Ch$ 375.9 billion, or 23.8%, in 2021 compared to 2020, due to:

(i)a Ch$ 309.1 billion increase in energy sales, mainly due to:

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a) a Ch$ 287.0 billion increase from 5,255GWh of higher physical energy sales due to 6,485 GWh from greater sales to unregulated customers primarily related to new contracts, including those transferred from Enel Distribution Chile in order to comply with new regulations regarding the single business of distribution companies, which was partially offset by decreases of782 GWh of lower physical sales to regulated customers and 448 GWh of lower spot market sales;

b) Ch$ 17.4 billion of higher ancillary services revenue related to safety and service quality and other revenues; and

c) an Ch$ 11.0 billion positive price effect resulting from exchange rate hedges that compensated the negative price effect due to the appreciation of the Chilean peso against the U.S. dollar.

These effects were partially offset by lower revenue from commodity hedges for Ch$ 6.3 billion.

(ii)an increase of Ch$ 90.8 billion in other sales mainly due to a Ch$90.6 billion increase in gas sales revenue.

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

(iii)a decrease of Ch$ 14.6 billion in other operating revenues mainly due to:

a) Ch$ 9.9 billion of lower revenue from temporary facility leasing; and

b) Ch$ 8.9 billion of lower compensation from insurance claims.

These effects were partially offset by a Ch$ 2.3 billion increase in revenue from commodity hedges.

(iv)a decrease of Ch$ 9.4 billion in other service revenue from tolls due to the settlements calculated during 2020.

Distribution and Transmission Business: Revenues and other operating income

Revenues and other operating income from our distribution and transmission business decreased Ch$ 180.2 billion, or 13.0%, in 2021 compared to 2020 primarily due to:

(i)a decrease of Ch$ 166.4 billion in energy sales mainly due to:

a) Ch$ 127.1 of lower energy sales from 2,805 GWh primarily as the result of lower physical energy sales mainly from commercial and industrial customers segments, mostly due to the transfer of 3,022 GWh of Enel Distribution’s unregulated customer contracts to Enel Generation and the migration of regulated customers to the unregulated customer segment; and

b) a lower average sales price as a consequence of a Ch$ 39.3 billion negative exchange rate effect during the period and the tariff review process.

(ii)Ch$ 15.2 billion decrease in revenue from other services mainly due to:

a) Ch$ 9.4 billion in lower revenue from the construction of new customer connections, public lighting, and other services; and

b) a Ch$ 5.8 billion in lower tolls mainly in the zonal transmission segment.

Total raw materials and consumables used

The following table set forth our total raw materials and consumables used for the years ended December 31, 2021, and 2020 by business segment.

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	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,346,982	616,852	730,130	118.4
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	974,858	1,116,324	(141,466)	(12.7)
Non-electricity business and consolidation adjustments	(310,535)	(358,731)	48,196	13.4
Total Raw materials and consumables used	2,011,305	1,374,445	636,860	46.3

Generation Business: Raw materials and consumables used

Raw materials and consumables used in our generation business increased Ch$ 730.1 billion, or 118.4%, in 2021 compared to 2020, mainly due to:

(i) a Ch$ 483.3 billion increase in energy purchases mainly due to 3,296 GWh higher physical purchases on the spot market and 2,256 GWh of physical purchases from other generation companies mainly needed to satisfy unregulated customers’ higher demand, in addition to a higher spot price due to electricity market conditions;

(ii) a Ch$ 143.7 billion increase in fuel consumption costs mainly due to:

a)a Ch$ 146.8 billion increase in gas consumption costs, primarily as a consequence of the higher purchase price of gas and greater gas-fired electricity generation;

b)a Ch$ 24.7 billion and a Ch$ 0.3 billion increase in impairment losses on coal and diesel inventories, respectively, accounted in the second quarter of 2021 related to the impairment of Bocamina II;

c)Ch$ 21.0 billion in higher fuel oil consumption costs; and

d)Ch$ 12.4 billion in higher coal consumption costs mainly due to a higher average purchase price.

These effects were partially offset by a Ch$ 61.7 billion reduction in the cost of commodity hedges.

(iii) a Ch$ 57.3 billion increase in other variable procurement and services costs mainly due to:

a)Ch$ 76.5 billion of higher gas commercialization costs of sales for ;

b)Ch$ 5.6 billion of higher thermal emission taxes.

These effects were partially offset by: (i) a Ch$ 15.9 billion decrease in the cost of commodity hedging transactions; and (ii) Ch$ 7.9 billion of lower expenses on temporary facility rentals.

(iv) Ch$ 45.8 billion in higher transmission tolls mainly due to:

a) Ch$ 36.2 billion higher costs of tariff revenue as a consequence of higher marginal costs;

b) Ch$ 7.4 billion higher costs related to the tariff adjustment concept (Ajuste de Armonización Tarifaria) of the zonal transmission system; and

c) Ch$ 2.6 billion higher costs resulting from the settlements related to the contract with Transmisora Eléctrica de Quillota Ltda.

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Distribution and Transmission Business: Raw materials and consumables used

Raw materials and consumables used in our distribution and transmission business decreased slightly by Ch$ 141.5 billion, or 12.7% in 2021 compared to 2020 mainly due to:

(i) Ch$ 126.8 billion in lower energy purchases mainly due to Ch$ 126.5 from 3,000 GWh lower energy purchases, primarily due to the transfer of 3,801 GWh for unregulated customer contracts to Enel Generation Chile;

(ii) Ch$ 10.7 billion in lower zonal transmission system tolls; and

(iii) Ch$ 4.0 billion in lower other variable procurement and services mainly due to (a) Ch$ 2.1 billion in lower customer compensation and (b) Ch$ 2.4 billion in lower cost of sales for other services. These effects were partly compensated by Ch$ 0.5 billion in higher expenses for new customer connections.

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Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense

Our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense are comprised of salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following table set forth our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense for the years ended December 31, 2021, and 2020, by business segment:

	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	383,470	1,056,586	(673,116)	(63.7)
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	168,792	165,855	2,937	1.8
Non-electricity business and consolidation adjustments	32,069	22,771	9,298	40.8
Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expenses	584,331	1,245,212	(660,881)	(53.1)

Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased Ch$ 660.9 billion, or 53.1%, in 2021 compared to 2020, mainly due to:

(i) a decrease of Ch$ 673.1 billion, or 63.7%, in the generation business due to:

a) a decrease of Ch$ 680.3 billion in depreciation, amortization, and impairment costs in 2021 compared to 2020, mainly due to:

● Ch$ 664.9 billion in lower impairment loss primarily in our generation business due to the Ch$ 697.9 billion impairment charge for the Bocamina II coal-fired power plant recorded in 2020 within the framework of the Group’s decarbonization plan, compared to the Ch$ 28.8 billion impairment charge related to the same plan recorded in 2021;

● Ch$ 19.0 billion in lower depreciation and amortization mainly related to Ch$ 15.4 billion in lower depreciation of the Bocamina II coal-fired power plant as a consequence of the impairment of the power plant during the first half of 2020, in addition to Ch$ 6.9 billion of lower depreciation and amortization of the EGP Chile Group, primarily due to exchange rate effects. This was partly offset by Ch$ 2.3 billion in higher expenses in the distribution and transmission business segment related to the commissioning of new investments; and

● Ch$ 3.6 billion in higher account receivable impairments, primarily in the distribution and transmission business segments for Ch$ 4.4 billion, mainly due to the expected weaker financial condition of regulated customers.

(ii) an increase of Ch$ 8.6 billion in the distribution and transmission business due to higher restructuring expenses linked to the Group's digitization strategy for 2021-2024; partially offset by an increase of Ch$ 7.6 billion of higher capitalization of personnel expenses allocated to investment projects.

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Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2021, and 2020:

	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	222,836	(96,017)	318,853	n.a.
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	58,183	99,889	(41,706)	(41.8)
Non-electricity business and consolidation adjustments	(21,425)	(38,128)	16,703	(43.8)
Total Consolidated Operating (Loss) / Income	259,594	(34,255)	293,849	n.a.
Operating margin(1)	9.1%	(1.3)%	—	—

(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 2021 and 2020 with the expense related to impairment arising from the closure of two coal-fired power plants.

Our operating income in 2021 increased compared to 2020 due to the following:

Generation Business 

Revenues totaled Ch$ 1,953.3 billion as of December 31, 2021, an increase of Ch$ 375.9 billion, or 23.8%, mainly due to higher physical energy sales in 2021 related to new contracts, including those transferred from Enel Distribution to comply with the new regulation regarding the single business of distribution companies and also higher gas sales.

The raw materials and consumables used totaled Ch$ 1,346.9 billion as of December 31, 2021, an increase of Ch$ 730.1 billion, or 118.4%, compared to 2020 mainly due to higher electricity purchase costs due to higher average price of energy purchases and a greater quantity of purchases, and higher fuel consumption costs related to a less efficient generation mix as a consequence of the poor hydrology and higher commodity prices, in addition to the higher cost of gas sales.

Operating income was affected by the impairment of the Bocamina II coal-fired power plant recognized in 2020, compared to the impairment recognized in 2021, related to the announcement of the closures of the Tarapacá and Bocamina I coal-fired power plants, and a lower depreciation and amortization expense, primarily associated with the lower depreciation of the impaired coal-fired plants in 2020.

Distribution and Transmission Business

Revenues were Ch$ 1,201.8 billion as of December 31, 2021, a decrease of Ch$ 180.2 billion, or 13.0%, compared to 2020, mainly due to lower average sales price. Physical sales were 16,668 GWh as of December 31, 2021, reflecting an increase of 1.1% compared to 2020 mainly due to higher tolls, higher sales to residential customers and other clients, which offset the lower sales in the industrial and commercial customer segments primarily as a consequence of the unregulated customer contracts transferred to Enel Generation.

The raw materials and consumables used totaled Ch$ 974.9 billion as of December 31, 2021, a decrease of Ch$ 141.5 billion, or 12.7%, compared to 2020, mainly due to lower energy purchases.

Operating income was mainly affected by (i) a higher impairment loss on trade receivables due to higher trade receivables, primarily as a result of the Covid-19 pandemic, mainly in the segment of regulated clients; (ii) higher amortization of intangibles due to IT developments; and (iii) a higher depreciation of fixed assets due to an increase in

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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, 2021, and 2020:

	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Financial results
Financial income	26,420	36,160	(9,740)	(26.9)
Financial costs	(174,043)	(127,409)	(46,634)	36.6
Gain (loss) from indexed assets and liabilities	5,898	2,086	3,812	182.7
Foreign currency exchange differences	(15,334)	(23,272)	7,938	(34.1)
Total financial results	(157,059)	(112,435)	(44,624)	39.7
Other Results
Share of the profit (loss) of associates and joint ventures accounted for using the equity method	3,177	3,509	(332)	(9.5)
Other gains (losses)	10,137	9,489	648	6.8
Total Other results	13,314	12,998	316	2.4
Total Consolidated Financial and Other Results	(143,745)	(99,437)	(44,308)	44.6

Financial Results

We recorded a higher net financial expense in 2021 compared to 2020, primarily attributable to:

(i) an increase of Ch$ 46.6 billion in financial costs, mainly due to:

a) Ch$ 47.9 billion from trade accounts receivable factoring, of which Ch$ 42.6 billion are related to the sale of accounts receivables that arise from the Tariff Stabilization Law;

b) Ch$ 19.2 billion related to the financial discounts on accounts receivables related to the Basic Services Law; and

c) Ch$ 6.9 billion with related parties related to Enel Finance International N.V. loans.

These effects were partially offset by greater capitalization of interest for Ch$ 28.4 billion primarily due to the development of NCRE projects and by a greater continuity in the development of the Los Cóndores project.

(ii) a decrease of Ch$ 9.7 billion in financial income, mainly due to: (i) a Ch$ 10.5 billion decrease related to lower financial income due to the Tariff Stabilization Law, (ii)a decrease of Ch$ 4.0 billion on short term fixed-income investments. These effects were partially offset by a Ch$ 4.7 billion increase in financial income related to the financial restatement of the dismantling provisions of the impaired power plants related to the decarbonization process, as a result of the increase in discount rates by the end of 2021.

(iii) an increase of Ch$ 3.8 billion in income related to indexation, primarily due to:

a) Ch$ 3.1 billion in higher income from the indexation of recoverable taxes; and

b) Ch$ 1.7 billion greater profit from the indexation of financial instruments, mainly related to financial debt and derivative instruments.

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These effects were partially offset by: (i) less profit from the indexation of trade accounts receivable for Ch$ 0.4 billion; and (ii) a Ch$ 0.9 billion greater loss related to the indexation of trade accounts payable and other liabilities.

(iv) a decrease of Ch$ 7.9 billion in loss from exchange rate differences, mainly due to:

a) Ch$ 84.3 billion in higher positive exchange rate differences on trade accounts receivables, which includes the Ch$ 88.1 billion greater positive 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; and

b) Ch$ 4.4 billion in higher positive exchange rate differences on current tax assets and liabilities;

The abovementioned was partially offset by the following negative exchange rate difference effect:

c) a Ch$ 30.7 billion higher negative exchange rate difference effect in accounts payables to related parties related to Enel Finance International N.V. loans;

d) a Ch$ 21.6 billion higher negative exchange rate difference effect in trade accounts payable that includes the Ch$ 34.3 billion greater negative effect related to the Tariff Stabilization Law;

e) a Ch$ 12.0 billion higher negative exchange rate difference effect in financial debt and derivative instruments; and

f) a Ch$ 8.2 billion higher negative exchange rate effect on other assets and liabilities.

Other Results

Our gain from the disposition of assets increased Ch$ 0.7 billion in 2021 compared to 2020 mainly due to the Ch$ 10.0 billion profit from the sale of the stake that our subsidiary Enel Generation had in the joint control of Transmisora Eléctrica de Quillota Ltda., were partially offset by lower results of Ch$ 9.4 billion compared to the previous period mainly due to the gain from the sale of our Quintero-San Luis transmission line recorded in December 2020.

Consolidated Income Tax Expenses

The effective tax rate was an income tax expense of 13.1% in 2021 compared to an income tax benefit of 60.8% in 2020.

Consolidated income tax benefit decreased Ch$ 96.4 billion in 2021 compared to the income tax profit in 2020, mainly due to:

(i) Ch$ 179.5 billion in income reduction in 2021 due to the greater impairment loss recorded in 2020 associated with the Group’s decarbonization plan;

(ii) a Ch$ 33.7 billion reduction in 2021 in tax income from the goodwill recorded in Enel Generation in 2020 due to the merger with GasAtacama Chile in 2019; and

(iii) a Ch$ 3.5 billion increase in income tax as a consequence of the tax income resulting from the merger of Enel Green Power Chile S.A. and Almeyda Solar SpA during 2021.

These effects were partially offset by:

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(iv) Ch$ 104.4 billion in lower tax expenses due to lower operating income when compared to 2020, excluding the impairment of Bocamina; and

(v) Ch$ 17.5 billion in lower expense as a consequence of the price-level restatement of the period.

For further details, please refer to Note 18 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, 2021, and 2020:

	Years ended December 31,
	2021	2020	Change	Change
	(in millions of Ch$)			(in %)
Operating income (loss)	259,594	(34,255)	293,849	n.a.
Other results	(143,745)	(99,437)	(44,308)	44.6
Net (Loss) / Income before Taxes	115,849	(133,692)	249,541	n.a.
Income tax (expenses) / benefit	(15,139)	81,305	(96,444)	n.a.
Consolidated Net (Loss) / Income	100,710	(52,387)	153,097	n.a.
Net income attributable to the Parent Company	85,154	(50,860)	136,014	n.a.
Net income attributable to non-controlling interests	15,556	(1,527)	17,083	n.a.

Net income attributable to the Parent Company increased Ch$ 136 billion in 2021 compared to 2020, mainly explained by higher physical energy sales in 2021 related to new contracts realized, higher raw materials by electricity purchase costs due to higher average price of energy purchases and a greater quantity of purchases, and a decrease of the impairment expense associated with the accelerated schedule for the Bocamina II coal-fired power plant closure as part of the decarbonization process.

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3. 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	(149,190)	(8.6)
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	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	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.

Distribution and Transmission Business: Revenues and other operating income

Revenues and other operating income from our distribution and transmission 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

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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.

Total raw materials and consumables used

The following table set forth our total raw materials and consumables used for the years ended December 31, 2020 and 2019, by business segment.

	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	(61,336)	(9.0)
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	1,116,324	1,114,936	1,388	0.1
Non-electricity business and consolidation adjustments	(358,731)	(371,919)	13,188	3.5
Total Raw materials and consumables used	1,374,445	1,421,205	(46,760)	(3.3)

Generation Business: Raw materials and consumables used

Raw materials and consumables used of our generation business decreased Ch$ 61.3 billion, or 9.0%, in 2020 compared to 2019, mainly due to:

(i) 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.

(ii) 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

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

The decrease in our generation business raw materials and consumables used was partially offset by higher costs of:

(iii) 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

(iv) 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 and Transmission Business: Raw materials and consumables used

Raw materials and consumables used of our distribution and transmission business increased slightly by Ch$ 1.4 billion, or 0.1%, in 2020 compared to 2019, mainly due to:

(i) 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

(ii) 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 and transmission business raw materials and consumables used was partially offset by:

(iii) 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.

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Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense

Our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense are comprised of salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following table set forth our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense for the years ended December 31, 2020 and 2019, by business segment:

	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	404,097	61.9
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	165,855	145,642	20,213	13.9
Non-electricity business and consolidation adjustments	22,771	25,443	(2,672)	(10.5)
Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense	1,245,212	823,574	421,638	51.2

Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense increased Ch$ 421.6 billion, or 51.2%, 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 and transmission 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.

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Consolidated Operating Income

The following table sets forth our 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	(96,017)	395,935	(491,952)	n.a.
Distribution and Transmission Business
Enel Distribution, Enel Transmission, and subsidiary	99,889	152,294	(52,405)	(34.4)
Non-electricity business and consolidation adjustments	(38,128)	(22,174)	(15,954)	(71.9)
Total Consolidated Operating (Loss) / Income	(34,255)	526,055	(560,310)	n.a.
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 raw materials and consumables used 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 and Transmission 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 raw materials and consumables used 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.

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Consolidated Financial and Other Results

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

	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	n.a.
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	858.7
Gain (loss) from sales of assets	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.

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(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;

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 on 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:

(i) 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;

(ii) 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

(iii) 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:

(iv) 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 18 of the Notes to our consolidated financial statements.

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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:

	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Consolidated Operating income	(34,255)	526,055	(560,310)	n.a.
Consolidated Other results	(99,437)	(148,734)	49,297	33.1
Consolidated Net income before taxes	(133,692)	377,321	(511,013)	n.a.
Income tax expenses	81,305	(61,228)	142,533	n.a.
Consolidated Net income	(52,387)	316,093	(368,480)	n.a.
Net income attributable to the Parent Company	(50,860)	296,154	(347,014)	n.a.
Net income attributable to non-controlling interests	(1,527)	19,939	(21,466)	n.a.

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.

B.Liquidity and capital resources.

Our main assets are our consolidated Chilean subsidiaries, Enel Generation, EGP Chile, Enel Transmission, 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 present requirements for cash to fund our working capital, expected debt service, dividends, and planned capital expenditures in the foreseeable future, as discussed in further detail below.

Set forth below is a summary of our consolidated cash flow information for the years ended December 31, 2021, 2020, and 2019:

	Year ended December 31,
	2021	2020	2019
	(in billions of Ch$)
Net cash flows provided by operating activities	413	756	744
Net cash flows used in investing activities	(736)	(555)	(312)
Net cash flows provided by (used in) financing activities	293	(128)	(440)
Net increase (decrease) in cash and cash equivalents before the effect of exchange rates changes	(30)	73	(8)
Effect of exchange rate changes on cash and cash equivalents	8	23	(1)
Cash and cash equivalents at the beginning of the period	332	236	245
Cash and cash equivalents at the end of the period	310	332	236

For the year ended December 31, 2021, net cash flow provided by operating activities decreased Ch$ 343 billion, or 45.4%, compared to the same period in 2020. The decrease was in part the result of:

(i) Ch$ 982.0 billion in higher payments to suppliers mainly from (i) our generation segment due to a higher cost for energy purchases due to a greater quantity and average price, a higher cost for fuel consumption due to the

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less efficient generation mix due to dry hydrology conditions and higher commodity prices, together with higher gas costs of Ch$ 743.1 billion ; and (ii) our distribution segment totaled Ch$ 168.6 billion.

(ii) Ch$ 110.8 billion in higher income tax payments in 2021, mainly due to (i) a Ch$ 53.8 billion increase in Enel Chile due to higher payments on income tax due to lower recovery tax related to tax losses in 2020; (ii) a Ch$ 57.9 billion increase in Enel Generation due to higher payments on income tax due to lower tax losses; (iii) a Ch$ 20.2 billion increase in Pehuenche related with an increase in monthly provisional payments on account of income tax. These were partially offset by Ch$ 24.6 billion of recovery of tax from the merger of GasAtacama Chile in 2019 (a former subsidiary of Enel Generation engaged in gas transportation and electricity generation in northern Chile).

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

(i) Ch$ 481.0 billion from increased collections in the generation and distribution and transmission businesses of Ch$ 156.9 billion and Ch$ 391 billion, respectively, including cash flows from sales and disposals of receivables (see Note 8.a.1 of the Notes to our consolidated financial statements);

(ii) Ch$ 520.8 billion due to higher sales in generation and transmission to unregulated customers largely associated with new contracts, including those transferred from Enel Distribution (application of the distribution exclusive business law); and

(iii) Ch$ 328.3 billion in lower energy sales from Enel Distribution for 2,805 GWh mainly to commercial and industrial customers mostly due to the transfer of 3,022 GWh of Enel Distribution’s unregulated customer contracts to Enel Generation and the migration of regulated customers to the unregulated customer segment.

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, due to (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:

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

a) 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

b) 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 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.

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(ii) 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;

(iii) 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;

(iv) 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

(v) 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 further information regarding our operating results in 2021, 2020, and 2019, please see “— A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2021 and 2020” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2020 and 2019.”

For the year ended December 31, 2021, net cash flows used in investing activities were outflows amounting to Ch$ 736 billion, representing an increase of 32.6% or Ch$ 181 billion, compared to the same period in 2020. The aggregate investment in 2021 was mainly due to:

(i) Ch$ 748 billion in fixed assets investments carried out by our subsidiaries, mainly due to Ch$ 504.2 billion by EGP Chile in developing renewable projects, Ch$ 156.7 billion by Enel Generation, mainly due to the construction of the Los Cóndores power plant, and Ch$ 84.9 billion by Enel Distribution to improve its networks.

These investing activities net cash flow increases were partially offset by:

(i) the sale of transmission lines of Quintero San Luis for Ch$ 18.2 billion completed in December 2020 by Enel Generation;

(ii) the sale of Transmisora Eléctrica de Quillota Limitada for Ch$ 11.8 billion by Enel Generation; and

(iii) dividends received of Ch$ 7 billion.

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, 2021, net cash flows from financing activities were Ch$ 293 billion compared to the cash flows used in financing activities of Ch$ 128 billion in 2020.

The aggregate cash payments associated with financing activities in 2021 were primarily due to:

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(i) Ch$ 231.1 billion in dividend payments, of which Ch$ 136.4 billion was paid to Enel, our controlling shareholder, and Ch $94.7 billion to third parties;

(ii) Ch$ 142.9 billion of interest payments (Ch$ 56.6 billion paid by Enel Generation, Ch$ 28.1 billion paid by EGP Chile, and Ch$ 57.5 billion paid by Enel Chile); and

(iii) Ch$ 33.7 billion in loan and bond payments by Enel Generation, partially offset by

(iv) aggregate cash inflows from financing activities in 2021, primarily from a Ch$ 633.8 billion loan provided to Enel Chile by Enel Finance International N.V., a related company.

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 a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — C. Risk Factors — We depend on distributions from our subsidiaries to meet our payment obligations.” Please see Notes 20 and 23 of the Notes to our consolidated financial statements for further details regarding the features and conditions of financial obligations and financial derivatives. These notes also refer to the material cash requirements of known contractual and other obligations.

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The table below sets forth our cash payment of contractual obligations as of December 31, 2021:

	Payments Due by Period
Contractual Obligation	Total	2022	2023-2024	2025-2026	After 2026
	(in billions of Ch$)
Purchase obligations(1)	8,263	2,587	3,384	1,539	753
Bank debt(2)	1,836	363	347	399	727
Yankee bonds	1,451	—	338	—	1,113
Interest expense	1,112	163	271	212	466
Local bonds(2)	285	36	80	70	99
Lease obligations	254	14	27	20	193
Pension and post-retirement obligations(3)	55	7	11	11	26
Total contractual obligations(4)	13,257	3,170	4,458	2,251	3,377

(1) Includes generation, distribution and transmission business purchase obligations, comprised mainly of electricity purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 8,263 billion, 70% corresponds to electricity purchased for distribution, 22% primarily to fuel supply, maintenance of medium- and low-voltage lines, cable and utility poles, and electricity purchased for generation. The remaining 8% 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.

(4) Represents obligations only with third parties.

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 “—B. Liquidity and capital resources.”

As of December 31, 2021, our consolidated interest-bearing debt totaled Ch$ 4.2 trillion, including Ch$ 2.1 trillion in debt that Enel Chile incurred with Enel Finance International N.V. (“EFI”), and had the following maturity profile:

Maturity Profile of Our Consolidated Interest-Bearing Debt
2022(1)	2023-2024	2025-2026	After 2026
(in billions of Ch$)
885	767	519	2,032

(1) The figures included in 2022 account for the revolving committed credit lines that Enel Chile signed with EFI, which have maturities between 2023 and 2024. Based on its revolving nature, we can decide whether to renew or pay each draw by its maturity date, but in any case, we have to repay all the draws before the credit line’s expiration date.

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Our ADSs 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 our subsidiaries and the aggregate principal amount that are outstanding as of December 31, 2021:

					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
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			5.267%	(3)​	2,050	1,717

(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. In March 2018, we registered a 30-year local bond program with the CMF for UF 15 million (Ch$ 465 billion as of December 31, 2021). As of December 31, 2021, and as of the date of this Report, there have been no issuances of bonds under this program.

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, 2021:

			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	1.50	47
Enel Generation Series M	21 years	December 2029	4.75%		10.00	7.27	225
Total			5.00%	(1)​	14.00	8.78	272

(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 19.2 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.

Our U.S. dollar syndicated and bilateral revolving loans are governed by the laws of the State of New York and the amounts that are outstanding as of December 31, 2021, are summarized in the table below.

Borrower	Type	Lender	Maturity	Facility Amount	Amount Drawn
				(in millions of US$)	(in millions of US$)
Enel Chile	Syndicated Revolving Loan	BBVA S.A. and Mizuho Bank Ltd	June 2024	100	—
Enel Chile	Bilateral Revolving Loan	EFI	June 2024	50	50
Enel Chile	Bilateral Revolving Loan	EFI	April 2026	290	290
Enel Chile	Bilateral Revolving Loan	EFI	September 2025	200	200
Enel Chile	Bilateral Revolving Loan	SMBC	October 2025	50	50
Total				690	590

In January 2022 we entered into a revolving loan facility for up to US$ 300 million, with a maturity in August 2023. As of March 31, 2022, the outstanding amount drawn was US$ 300 million. As a result, the total amount drawn from our credit lines as of March 31, 2022, was US$ 890 million.

Our Chilean pesos revolving loan and the amounts outstanding as of December 31, 2021, are summarized in the table below.

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

Some of the aforementioned revolving credit loans are not subject to the compliance of conditions precedent regarding the non-occurrence of a “Material Adverse Effect” (or MAE, as defined contractually). This kind of contracts with committed credit lines, which allow us complete flexibility for a drawdown under any circumstances including situations involving an MAE, are up to US$ 540 million as of December 31, 2021, and up to US$840 million as of March 31, 2022, of which US$ 840 million were drawn as of March 31, 2022.

Additionally, we and our subsidiaries have also entered into uncommitted Chilean bank facilities for approximately Ch$ 88 billion in the aggregate, none of which are drawn as of March 31, 2022. 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.

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As for our term loans, the detail of each transaction and the outstanding principal amount as of December 31, 2021, is described in the following table:

Borrower	Type	Lender	Issuance Date	Maturity	Outstanding principal
					(in millions of  US$)
Enel Chile	Term Loan	EFI	December 2015	December 2027	644
EGP Chile	Term Loan	Inter-American Investment Corporation	May 2017	November 2022	30
Enel Chile	Term Loan	EFI	December 2018	December 2022	400
Enel Chile	Term Loan	EFI	January 2020	July 2023	200
Enel Chile	Term Loan	EFI	March 2020	March 2030	400
Enel Chile	Term Loan SDG linked	EFI	April 2021	April 2031	300
Enel Chile	Term Loan SDG linked	Santander Chile	July 2021	June 2024	50
Enel Chile	Term Loan SDG linked	Scotiabank Chile	December 2021	December 2026	150
Total					2,174

For a complete description of our credit lines and term loans, see Note 9.1.d) and Note 19.1 of the Notes to our consolidated financial statements.

As is customary for certain credit and capital market debt facilities, some of our financial indebtedness is subject to covenants. The main covenants governing the loans granted to us are bankruptcy, insolvency, cross default clauses, limitations on liens, change of control, restrictions on the sale of assets and corporate reorganizations, adverse court judgments, and governmental actions, among others. As of December 31, 2021, Enel Chile, on a stand-alone basis, had debt obligations that included covenants or events of default but were not subject to financial ratios. In addition, two of Enel Generation’s loan agreements, include the obligation to comply with certain financial ratios. Finally, EGP Chile has a debt agreement that is not subject to financial ratios but to other clauses. These agreements include affirmative and negative covenants and restrictions in the event of default, which all require monitoring to ensure their compliance. For more information about financial restrictions please see Note 35.4 of the Notes to our consolidated financial statements.

The payment of dividends and distributions by our subsidiaries and affiliates represents an essential source of funds and 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’s status, see “Item 3. Key Information — D. Risk Factors— We depend on distributions from our subsidiaries to meet our payment obligations.”

Our estimated capital expenditures for 2022 through 2024 are expected to amount to Ch$ 2,196 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.

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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 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.

This reform may affect us in the following ways:

(i) 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.

(ii) 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.

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

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

As of March 31, 2022, our total debt exposure to LIBOR was US$ 1,190 million and 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. For more information, see “Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4, and IFRS 16: Interest Rate Benchmark Reform (Phase 2)” in Note 2.2.a) of the Notes to our consolidated financial statements.

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 2021, we executed three Revolving Credit Facility Agreements (“RFA”) linked to sustainable development goals, for up to US$ 290 million and US$ 200 million, both with Enel Finance International N.V. which mature in 2026 and 2025, respectively, and for up to US$ 50 million with SMBC due in 2025. All these contracts include provisions for a replacement rate for LIBOR. We also entered into two loan agreements, one with Scotiabank for US$ 150 million, due in 2026, which is linked to sustainable development goals, and the other with Santander for US$ 50 million, due in 2024. Both loans contracts are subject to LIBOR and include specific fallback rate provisions. As of March 31, 2022, the RFA had an outstanding principal amount of US$ 540 million.

In 2020, we executed an 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. This RFA expired in June 2021 and loan draws are no longer available.

In 2019, we executed a Senior Unsecured Revolving Credit Agreement (“SURCA”) for up to US$ 100 million, which matures in 2024, 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.,

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which matures in 2024, 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, 2022, the SURCA was undrawn and the 2019 RFA had an outstanding principal amount of US$ 50 million.

Additionally, in 2018 we entered into a term loan for US$ 400 million, due in 2022, 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.

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

None.

D.Trend Information.

Generation

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.

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 including our NCRE projects that will be completed by 2022. 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.

Distribution

We expect that distribution customers who can choose between regulated and unregulated tariffs will continue to switch to unregulated tariffs, thereby becoming direct generation company customers. 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, investments in new technologies that will automate our systems to achieve better operational and economic efficiency, such as smart meters, which allow bi-directional communication, digitized and interconnected networks, enable our consumers to improve their energy efficiency, reduce costs in meter reading processes, remotely manage the disconnection and reconnection processes, and improve response times to better address extreme weather emergencies by significantly reducing failure recognition time.

Hydrogen in energy transition

The ability to generate hydrogen by electrolysis with renewable energy sources allows not only to decarbonize the hydrogen production process but also generates value in economic sectors in which hydrogen is used as an energy source to replace coal-based sources. We believe that hydrogen, within the energy transition, has potential for development due to its impact on the environment and the benefits it may generate in our earnings and financial results as a result of diversifying our sources of income. In this line, we are currently building our first hydrogen project, which we expect to be completed by 2023. For further information on the hydrogen project, see “Item 4. Information on the Company — D. Property, Plant, and Equipment. — Project Investments — Projects under Construction in 2021 — Pilot Green Hydrogen Project.”

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Adverse Effects of the Covid-19 Pandemic

Increases in infection rates and extraordinary governmental measures such as quarantines and lockdown periods, may adversely affect our business and results. For more information see “Item 3. Key Information — D. Risk Factors— We are subject to the adverse effects of worldwide pandemics.”

Adverse Effects of Governmental Regulations

The Tariff Stabilization Mechanism, Law 21,194 (“Ley Larga”) which reduces the profitability of distribution companies, and Law 21,249 (“Ley de Servicios Básicos”) which prohibits electricity distribution companies from cutting services due to nonpayment for residential customers, small businesses, hospitals, and firefighters, among others, may adversely affect our business and results. For more information see “Item 3. Key Information — D. Risk Factors— Governmental regulations may unfavorably affect our businesses, cause delays, impede the development of new projects, or increase the costs of operations and capital expenditures.”

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 demanding 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 accounted for an expense of approximately Ch$ 17.5 billion in 2021.

Armed conflict between Russia and Ukraine

The effects of the armed conflict between Russia and Ukraine, which began in February 2022, on our company are unknown. Although we do not have direct business transactions with suppliers, clients, or lenders from Russia or Ukraine, our business, results of operations, and financial condition may be impacted by (i) limited access to financial markets; (ii) possible interruptions in the global supply chain; (iii) volatility in commodity prices; and (iv) an increase in inflationary pressures in Chile, which could increase the rates charged to our customers.

E.Critical Accounting Estimates

Our significant accounting policies are more fully described in Notes 2 and 3 of the Notes to our consolidated financial statements included elsewhere in this Report. Certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates, as described in Note 2.3 of the Notes to our consolidated financial statements.

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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 elected and hold office at the discretion of the board of directors.

Our current board of directors was elected at the OSM held on April 28, 2021, for a three-year term that ends in April 2024. The members as of December 31, 2021, were as follows:

Directors	Position	Age(1)	Current Position Held Since
Herman Chadwick P.	Chairman	77	2016
Gonzalo Palacios Vásquez	Director	71	2021
Pablo Cabrera G.	Director	74	2016
Fernán Gazmuri P.	Director	77	2016
Salvatore Bernabei	Director	48	2016
Mónica Girardi	Director	42	2021
Isabella Alessio	Director	47	2021

(1) As of the date of this Report.

Set forth below are brief biographical descriptions of the members of our board of directors, as of December 31, 2021.

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.

Gonzalo Palacios Vásquez: Mr. Palacios currently works as a consultant mainly in the energy sector and as independent director on the board at Naturgy Ban, a gas distribution company in Argentina. He has served as either director or CEO of the following companies in the electricity industry: CGE, CGED, CONAFE, EDELMAG, EJESA (Argentina), EJSEDSA (Argentina), EDET (Argentina); Energía San Juan (Argentina), Tusan, Hornor, Energy Sur, and Tecnet. His experience also includes studies for the World Bank and governments related to deregulation, liberalization, privatization, and regulatory framework throughout Latin America, as well as participation in Comisión Nacional de Energía (Chile), the Chilean electricity law of 1982, and the legal modifications to the Chilean gas law in the late 1980s. He holds a degree in industrial engineering from Pontificia Universidad Católica de Chile.

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.

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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.

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 Milan.

Mónica Girardi: Mónica joined Enel in 2018 as head of group investor relations. She worked at Barclays as a senior research analyst responsible for Italian and Iberian public services (2009-2018). Previously, she worked at Lehman Brothers equity research team as an analyst covering European public services and infrastructure (2003-2009). She holds a degree in business administration from Luigi Bocconi University in Milan and graduated summa cum laude.

Isabella Alessio: Isabella is head of legal and corporate affairs for global procurement of the Enel Group. From 2014 to 2017 she was head of legal affairs for North, Central, and South America for the global infrastructure and networks line of Enel. From 2011 to 2014 she joined Enel as head of corporate affairs for Iberia and Latin America at Enel Green Power. Previously, she worked at Grimaldi e Associati and at Clifford Chance law firm. She is a Lawyer from the University of Rome “La Sapienza” and has a master's degree in European Law.

Executive Officers 

Set forth below are our executive officers as of December 31, 2021:

Executive Officers	Position	Age(1)	Joined Enel or Affiliate in	Current Position Held Since
Paolo Pallotti (3)	Chief Executive Officer	59	1990	2018
Giuseppe Turchiarelli	Chief Financial Officer	51	1998	2019
Eugenio Belinchon(2)	Internal Audit Officer	45	1998	2020
Liliana Schnaidt H.	Human Resources Officer	42	2009	2018
Domingo Valdés P.	General Counsel	58	1993	2016

(1) As of the date of this Report.

(2) Juan Díaz Valenzuela assumed this position as of February 1, 2022.

(3) Fabrizio Barderi assumed this role as of March 1, 2022.

Set forth below are brief biographical descriptions of our executive officers.

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.

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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.

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, and 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 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.

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In 2021, 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.	154,778	61,426	—	—	—	216,204
Gonzalo Palacios Vásquez	52,698	23,762	17,566	7,915	—	101,941
Pablo Cabrera G.	77,389	30,713	25,796	10,232	—	144,130
Fernán Gazmuri P.	77,389	28,407	25,797	8,669	—	140,262
Juan Gerardo Jofré M.(1)	18,959	6,951	6,320	2,317	—	34,547
Salvatore Bernabei(2)	—	—	—	—	—	—
Mónica Girardi(2)	—	—	—	—	—	—
Isabella Alessio(2)	—	—	—	—	—	—
Total	381,213	151,259	75,479	29,133	—	637,084

(1) Mr. Jofré held his position as director until April 28, 2021.

(2) Directors Alessio, Bernabei, and Girardi waived their compensation as directors of Enel Chile due to their positions as employees of other companies in Enel.

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, 2021, the aggregate gross compensation, paid and accrued, for all of our executive officers, attributable to the fiscal year 2021, was Ch$ 2.0 billion of fixed compensation, and Ch$ 299 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 2021. There are no other amounts set aside or accrued to provide for pension, retirement, or similar benefits for our executive officers.

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C. Board Practices.

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. Our current board of directors was elected at the OSM held on April 28, 2021, for three-year term. For information about the directors in office as of December 31, 2021, 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.

Directors Committee (Audit Committee)

Set forth below are our members of the Directors Committee as of December 31, 2021:

Committee Member	Position in Committee
Fernán Gazmuri P.	President
Pablo Cabrera G.	Member
Gonzalo Palacios Vásquez	Member

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;

● 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; and

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

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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, 2021, 2020, and 2019:

Company	2021	2020	2019
Enel Generation	656	668	700
Enel Distribution(1)	556	755	733
Enel Chile	500	494	480
EGP Chile	304	285	212
Enel X	99	15	6
Enel Transmission(2)	98	—	—
Pehuenche	2	2	2
Total Personnel(3)	2,215	2,219	2,133

(1) Includes Enel Colina S.A.

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

(3) 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 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

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

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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 only one class of capital stock, and Enel, our controlling shareholder, has the same voting rights as our other shareholders. As of December 31, 2021, 6,557 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 four 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 four 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, 2021, Chilean private pension funds (“AFPs”) owned 10.4% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 19.2% of our shares. ADR holders owned 4.3% of our shares, and 6,415 minority shareholders held the remaining 1.2% of our shares.

The following table sets forth information concerning ownership of the common stock as of April 1, 2022, 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, an Italian company and our controlling shareholder that beneficially owned 64.9% of our shares as of December 31, 2021, is a multinational power company and a leading integrated player in the global power and renewables markets. It is one of the largest European utility companies with operations in over 30 countries worldwide and a consolidated installed capacity of approximately 90 GW. Enel distributes electricity through a network of over 2.2 million kilometers to 75 million end users. It is one of the world’s largest network operators and has one of the most extensive customer bases. Enel’s shares are listed on Euronext Milan 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 Corporations 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

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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.

The following are related-party transactions conducted between January 1, 2021, and March 31, 2022.

Related-party transactions

Lender	Borrower	Issuance Date	Maturity Date	Amount (million)	Interest rate (%)	Outstanding principal (million)(1)	Contract type
EFI	Enel Chile	Apr-21	Apr-26	US$ 290	Libor + 1.00%	US$ 290	Sustainable Development Goals (SDGs)-linked revolving facility agreement
EFI	Enel Chile	Apr-21	Apr-31	US$ 300	2.50%	US$ 300	SDG-linked loan agreement
EFI	Enel Chile	Sep-21	Sep-25	US$ 200	Libor + 1.15%	US$ 200	SDG-linked revolving facility agreement
EFI	Enel Chile	Jan-22	Aug-23	US$ 300	SOFR + 0.75%	US$ 300	Revolving facility
Enel Chile	Enel Distribution	Oct-21	Oct-22	Ch$ 95,000	6.47%	Ch$ 95,000	Term loan
Enel Chile	Enel Distribution	Mar-22	Mar-27	Ch$ 134,000	8.58%	Ch$ 134,000	Term loan
Enel Chile	Enel Transmission	Jan-21	Nov-22	Ch$ 42,145	3.20%	Ch$ 42,145	Term loan
Enel Chile	Enel Transmission	Jan-22	Dec-22	Ch$ 87,000	8.18%	Ch$ 87,000	Term loan
Enel Chile	EGP Chile	Feb-21	Feb-26	US$ 200	2.88%	US$ 200	Term loan
Enel Chile	EGP Chile	Apr-21	Apr-31	US$ 300	2.95%	US$ 300	Term loan
Enel Chile	EGP Chile	Jun-21	Dec-27	US$ 644	3.16%	US$ 644	Term loan
Enel Chile	EGP Chile	Dec-21	Dec-26	US$ 150	3.02%	US$ 150	Term loan
Enel Chile	EGP Chile	Jan-22	Jan-27	US$ 242	3.95%	US$ 242	Term loan
Enel Chile	Enel Generation	Dec-21	Dec-26	US$ 180	3.01%	US$ 180	Term loan

(1) As of March 31, 2022.

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 March 31, 2022, the peso-denominated transactions were priced at TAB 1m (a Chilean interbank interest rate published daily) plus 1.44% when lending to affiliates and TAB 1m minus 0.18% when accepting deposits of cash surpluses from affiliates. The US$-denominated transactions were priced at SOFR 1m plus 1.61% when lending to affiliates and SOFR 1m plus 0.28% when accepting deposits of cash surpluses from affiliates.

The following are related party transactions under the centralized cash management mechanism conducted between January 1, 2021, and March 31, 2022.

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● We granted short-term intercompany loans to our subsidiaries, EGP Chile, Enel Colina, Enel X, Geotérmica del Norte S.A., and Sociedad Agrícola De Cameros Ltda. As of March 31, 2022, the total outstanding balance of the loans was Ch$ 188 billion, including interest.

● Under our cash management contracts, Enel Generation, Enel Distribution, Enel Transmission, Parque Talinay Oriente S.A., and Pehuenche all transferred cash surpluses to Enel Chile. As of March 31, 2022, the total outstanding balance of these transfers was Ch$ 175 billion, including interest.

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.

As of the date of this Report, the transactions above have not experienced material changes. As of December 31, 2021, there were some commercial transactions with related parties. Please see Note 9 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 35.3 of the Notes to our consolidated financial statements for detailed information as of December 31, 2021, 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

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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 2021, on November 26, 2021, the board of directors agreed to distribute an interim dividend of Ch$ 0.10497 per share of common stock on January 28, 2022, equal to 15% of consolidated net income as of September 30, 2021. At the OSM held on April 27, 2022, our shareholders approved a final dividend of US$ 0.36934 per share for the year 2021, equivalent to a payout of 30% of annual net income for the fiscal year 2021. The final dividend for the fiscal year 2021 will be distributed in May 2022, after deducting the interim dividend paid in January 2022.

For dividends relating to the fiscal year 2022, our board of directors presented at the OSM held on April 27, 2022, the following proposed dividend policy:

● An interim dividend, accrued in the fiscal year 2022 and amounting to 15% of consolidated net income as of September 30, 2022, to be paid in January 2023.

● A final dividend payout of 30% of annual net income for the fiscal year 2022, to be paid in May 2023, from which the interim dividend to be paid in January 2023 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. However, these potential legal 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 ADSs 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)
2021	3.08	0.18
2020	4.23	0.30
2019	3.14	0.21

(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.

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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.

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 Comercio de Santiago (Santiago Stock Exchange or “SSE”) and the Bolsa Electrónica de Chile (Chilean Electronic Stock Exchange or “ESE”). These stock exchanges operate 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. As of December 31, 2021, the SSE and ESE accounted for 96.8% and 3.2%, respectively, of our total equity traded in Chile.

In the United States, our common stock trades on the NYSE, our primary market, in the form of ADSs. 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 in the books of the Depositary as owners of ADRs. The NYSE operates on business days from 9:30 a.m. to 4:00 p.m.

Our equity shares are part of the SPCLXIGPA, and SPCLXIPSA, leading Chilean stock market indices, as well as the MSCI Universal and ESG focus indexes, FTSE4Good Emerging and Latin America indexes, and S&P Dow Jones Sustainability Index, in which we hold the lead in three categories: Emerging Markets, Pacific Alliance Integrated Markets (“MILA” in its Spanish acronym), and Chile S&P IPSA ESG Titled index.

The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during 2021:

Market	Number of Common Shares Traded	Percentage of Shares Traded
Chile(1)	19,529,317,755	66%
United States (One ADS = 50 shares of common stock)(2)	10,268,033,000	34%
Total	29,797,350,755	100%

(1) Includes SSE and ESE.

(2) Includes the NYSE and over-the-counter trading.

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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

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 the Chilean Corporations Law (Law No. 18,046). Under the Chilean Corporations Law, shareholders’ legal actions to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the plaintiff’s option, before Chilean courts. Members of the board of directors, managers, officers, and principal executives of the company, or shareholders that individually own shares with a book value or stock value higher than UF 5,000 (approximately Ch$ 156 million as of December 31, 2021) 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 limited liability 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.

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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 limited liability 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 ADSs are deemed to represent the shares of common stock underlying the ADRs, transactions in ADRs will be subject to these reporting requirements and those established in Circular No. 1375 of the CMF. Shareholders of publicly held limited liability 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 limited liability 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 limited liability 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 limited liability stock corporation’s subscribed 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 limited liability 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 limited liability stock corporation.

The majority shareholders of a publicly held limited liability 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 limited liability 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 limited liability 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.

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Board of Directors

Our board of directors consists of seven members elected by shareholders at an OSM 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. Shareholders may vote their shares in favor of one nominee or may apportion their 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 can elect a board member. However, 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, 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, as set forth by 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.

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.”

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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 the subscriber’s 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 the subscriber 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 shareholder rights, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing the Chief Executive Officer, will reduce in the shareholders’ register the number of shares in the name of the debtor shareholder to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after 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, 2021, the Company’s subscribed and fully paid capital totaled Ch$ 3.9 trillion consisting of 69,166,557,220 shares.

Preemptive Rights and Increases of Share Capital

Except for capital increases needed to carry out a merger, Chilean regulation requires Chilean publicly held limited liability 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.

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 to the 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 that should be 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-day period, publicly held limited liability 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-day period, a Chilean publicly held limited liability stock corporation is authorized to sell unsubscribed shares to third parties on any terms, provided they are sold on one of the Chilean Stock Exchanges.

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Shareholders’ Meetings and Voting Rights

An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April 27, 2022. An ESM may be called by the board of directors when deemed appropriate. An ESM and OSM, as the case may be, must be called when requested by shareholders representing at least 10% of the issued shares with voting rights, or by the CMF. To convene an OSM or 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 the CMF and the Chilean Stock Exchanges.

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 a two-thirds majority of the outstanding shares with voting rights is required to adopt any of the following actions:

● a transformation of the company into a form other than a publicly held limited liability 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;

● the 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;

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● 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 limited liability 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 limited liability stock corporation and its subsidiaries within 15 days before its scheduled shareholders’ meeting. Under Chilean law, publicly held limited liability 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, the fact that an ESM or OSM has been summoned, indicating the date, a reference to 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 the 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 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 limited liability 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.

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Only shareholders registered as such with us as of midnight on the fifth business day before a 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 ADSs, and evidenced by outstanding ADSs, is the custodian for the Depositary (Citibank, N.A.), currently Banco Santander-Chile, or any successor custodian. Accordingly, holders of ADSs are not entitled to receive notice of shareholders’ meetings or vote the underlying shares of common stock represented by ADSs directly. The Deposit Agreement contains provisions under which the Depositary has agreed to request instructions from registered holders of ADSs regarding the exercise of the voting rights of the shares of common stock represented by the ADSs. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the 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 to vote) the shares of common stock represented by the ADSs under any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If the Depositary receives no voting instructions from a holder of ADSs concerning the shares of common stock represented by the ADSs, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADSs 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 the 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 limited liability 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 limited liability stock corporations may grant their shareholders an option to receive those dividends, in cash, or shares issued by such publicly held limited liability 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.

Dividends declared but not paid within the appropriate period outlined 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 by a vote of a majority of shares present (in person or by proxy) at the shareholders’ meeting reject the financial statements, the board of directors must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire board of directors is deemed removed from office, and a new board is elected at the same meeting. Directors who individually approved such

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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 who are 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.

The price paid to a dissenting shareholder of a publicly held limited liability 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 price paid to the dissenting shareholder shall be the book value. Book value for this purpose must be 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 latest 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 (Reglamento de Sociedades Anónimas) establishes that in cases where the right to withdraw arises, the company is obliged to inform the shareholders of this situation, the value per share that will be paid to shareholders exercising their right to withdraw, and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted, giving rise to the right of withdrawal, 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

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the company. The notice of the shareholders’ meeting 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 that is not a publicly held limited liability stock corporation governed by the 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 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 company, as well as any disposition of its shares that results in the parent company losing its position of controlling shareholder;

● issue of guarantees for third parties’ liabilities 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 shall 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 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.

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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 outlined 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 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 repatriate at any time an investment made in us upon selling our shares, and the profits derived from there, with no monetary ceiling, subject to the regulations in effect at the time, 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 Chilean material income and withholding tax consequences to foreign holders arising from the ownership and disposition of shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of shares or ADSs, if any, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs.

The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions 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.

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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 ADSs are assigned to a branch, agent, representative, or permanent establishment of such entity in Chile.

Taxation of Shares and ADSs

Taxation of Cash Dividends and Property Distributions

Cash dividends paid concerning the shares or ADSs 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 ADSs does not have a tax treaty with Chile. If there is a tax treaty between both countries (in force or signed before January 1, 2021), the Foreign Holder can apply 100% of the CIT as a credit. For 2021, 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 limited liability stock corporations, such as our company, 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 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

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rate for 2021 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 depositary’s address.

Taxation on Sale or Exchange of ADSs Outside of Chile

Gains obtained by a foreign holder from the sale or exchange of ADSs outside Chile 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 limited liability 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 ADSs 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 (i) when 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 the date of this Report, our shares are considered to 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 ADSs representing such shares of common stock) could be subject to the general tax regime,

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with a 27% Chilean CIT, the rate applicable during 2021, and a 35% Chilean withholding tax, the former being creditable against the latter.

The date of acquisition of the ADSs is the date of purchase of the shares for which the ADSs 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 ADSs 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 ADSs. However, 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 ADSs.

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 ADSs will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADSs. However, 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 ADSs as capital assets for U.S. federal income tax purposes. It does not describe all of the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

● certain financial institutions;

● insurance companies;

● dealers and traders in securities who use a mark-to-market method of tax accounting;

● persons holding shares or ADSs as part of a “straddle” integrated transaction or similar transaction;

● persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

● partnerships or other entities classified as partnerships for U.S. federal income tax purposes or partners in such partnerships;

● persons liable for the alternative minimum tax;

● tax-exempt organizations;

● persons holding shares or ADSs that own or are deemed to own ten percent or more of our stock; or

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● persons holding shares or ADSs connected with a trade or business conducted outside of the United States.

Persons or entities described above, including partnerships holding shares or ADSs 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 ADSs.

You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or ADSs and if you are, for U.S. federal income tax purposes:

● a citizen or 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 ADSs will be treated as the beneficial owner of the underlying shares represented by the ADSs. The remainder of this discussion assumes that a U.S. Holder of our ADSs will be treated in this manner for U.S. federal income tax purposes. Accordingly, deposits or withdrawals of shares for ADSs will generally not be subject to U.S. federal income tax.

The U.S. Treasury has expressed concerns that parties to whom ADSs are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADSs may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with 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 ADSs or of any future administrative guidance interpreting provisions thereof. U.S. Holders should consult their own tax advisors concerning their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S., and other tax laws and the possibility of changes in tax laws, including the effects of any future administrative guidance interpreting provisions thereof.

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 ADSs, 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

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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 ADSs, 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 ADSs generally will be subject to taxation at preferential rates if the dividends are “qualified dividends.” Dividends paid on the ADSs generally will be treated as qualified dividends if (i) the ADSs 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 ADSs 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 2021 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 2022 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 ADSs 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 ADSs 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 ADSs. 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 ADSs.

Sale or Other Disposition of Shares or ADSs

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss, and will be a long-term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not ADSs). See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs.” If a Chilean tax is imposed on the sale or disposition of shares, a beneficial owner that is a U.S. Holder may be eligible to claim a

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credit against its U.S. federal income tax liability for the eligible Chilean taxes withheld under a sale or disposition of shares or ADSs 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 ADSs. 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 ADSs, 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 2021 taxable year. We do not anticipate being a PFIC for our 2022 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 ADSs, 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.

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 ADSs, subject to certain exceptions (including an exception for our shares or ADSs 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 ADSs. 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 ADSs.

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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 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 ADSs, less certain deductions. A U.S. Holder should consult the holder’s own tax advisor regarding the applicability of the “net investment income” tax regarding 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 ADSs.

F. Dividends and Paying Agents.

Not applicable.

G. Statement by Experts.

Not applicable.

H. Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign private issuer, we are not subject to the SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. 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 ADSs 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.

We have 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, 2021, we held the following swaps: 1.93 kBbl of Brent oil to be settled in 2022 and 9.1 TBtu of Henry Hub gas to be settled in 2022. As of December 31, 2020, we held the following swaps: 1,782 kBbl of Brent oil settled in 2021 and 16.8 TBtu of Henry Hub gas settled in 2021.

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.

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Interest Rate and Foreign Currency Risk

As of December 31, 2021, 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.

	Expected Maturity Date
For the year ended December 31,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Fixed Rate
Ch$/UF	223	20	19	—	—	—	262	262
Weighted average interest rate	2.5%	5.9%	6.2%	—	—	—	3.0%	n.a.
US$	28,796	175,101	474,120	136,244	136,244	1,841,242	2,791,748	3,044,846
Weighted average interest rate	2.1%	2.8%	4.0%	2.9%	2.9%	4.7%	4.3%	n.a.
Other currencies	778	743	743	743	743	4,256	8,008	8,008
Weighted average interest rate	4.9%	4.8%	4.8%	4.8%	4.8%	4.8%	4.8%	n.a.
Total fixed rate	29,797	175,864	474,882	136,987	136,987	1,845,498	2,800,018	3,053,116
Weighted average interest rate	2.2%	2.9%	4.0%	3.0%	3.0%	4.7%	4.3%	n.a.
Variable Rate
Ch$/UF	38,216	39,393	39,324	39,154	39,048	213,716	408,851	447,535
Weighted average interest rate	4.9%	4.9%	4.9%	5.0%	5.0%	4.1%	4.5%	n.a.
US$	794,009	—	42,235	42,235	126,704	—	1,005,181	1,005,181
Weighted average interest rate	1.3%	—	0.2%	1.3%	1.4%	—	1.2%	n.a.
Total variable rate	832,225	39,393	81,559	81,389	165,752	213,716	1,414,032	1,452,716
Weighted average interest rate	1.4%	4.9%	2.5%	3.1%	2.2%	4.1%	2.2%	n.a.
Total	862,022	215,257	556,441	218,376	302,739	2,059,214	4,214,050	4,505,832

(1) Calculated based on the Observed Exchange Rate as of December 31, 2021.

(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.

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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.

	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.

(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, 2021, and 2020, 82% and 99% of our total outstanding debt had fixed interest rates, and 18% and 1%, respectively, was subject to variable interest rates. Because of the exposure to variable interest rate risks, we engage in derivative hedging instruments.

As of December 31, 2021, 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,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Variable to fixed rates	473,547	—	59,193	—	—	—	532,740	(8,550)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	473,547	—	59,193	—	—	—	532,740	(8,550)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2021.

(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.

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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.

(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, 2021, 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,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
UF to US$	—	—	618,606	127,688	—	—	746,294	(52,422)
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	—	618,606	127,688	—	—	746,294	(52,422)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2021.

(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, 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.

(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.

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Please refer to Note 21 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 ADSs directly from investors depositing shares or surrendering ADSs 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. The Depositary may generally refuse to provide the requested services until its fees for those services are paid. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:

Service Fees	Fees
(1) Issuance of ADSs upon deposit of shares (excluding issuances as a result of distributions described in paragraph (4) below)	Up to US$ 5 per 100 ADSs (or fraction thereof) issued
(2) Delivery of deposited securities against surrender of ADSs	Up to US$ 5 per 100 ADSs (or fraction thereof) surrendered
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(4) Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADSs	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(5) Distribution of securities other than ADSs or rights to purchase additional ADSs (i.e., a spin-off of shares)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(6) Depositary services	Up to US$ 5 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary

Depositary Payments for Fiscal Year 2021

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2021, the Depositary reimbursed us for expenses related primarily to investor relations activities for approximately US$ 0.7 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, 2021.

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 the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

As required by Section 404 of the Sarbanes-Oxley Act of 2002, our management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule13a-15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2021. The assessment was based on criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 framework”). Based on the assessment, our management has concluded that as of December 31, 2021, our internal control over financial reporting was effective.

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(c) Attestation Report of the Public Accounting Firm

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2021. Their attestation report appears on page F-3.

(d) Changes in Internal Control Over Financial Reporting

Remediation of Previously Disclosed Material Weakness

During 2021, we implemented measures to improve our internal controls over financial reporting and remediate the material weakness previously identified as of December 31, 2020, with respect to 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 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.

In an effort to remediate the material weakness and enhance our internal controls, management implemented the following actions to revise and enhance our GITCs to ensure, for the affected IT application, full enforcement of tracking 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.

After completing our testing of the design and operating effectiveness of these new procedures, our management concluded that, as of December 31, 2021, we have remediated the previously identified material weakness as of December 31, 2020.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer and other members of our executive management have implemented the aforementioned remedial measures during the year ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16.      Reserved

Item 16A.      Audit Committee Financial Expert

As of December 31, 2021, 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 corporate rulings or policies: (i) the Manual for the Management of Information of Interest to the Market (the “Manual”); (ii) the Human Rights and Politically Exposed Person Policy (Política de Derechos Humanos); (iii) the Code of Ethics; (iv) the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”); (v) the Penal Risk Prevention Model; (vi) the Enel Global Compliance Program on Corporate Criminal Liability (the “Enel Global Compliance Program”); (vii) the Risk Management and Control System; (viii) 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; and (ix) 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.

Our board of directors approved a procedure for regulating the commercial and contractual relationships between Politically Exposed People (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company. The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into corporate reality. 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 No. 20,393, which imposes criminal responsibility for legal entities for certain crimes, including money laundering, financing of terrorism, and bribery of public officials. 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 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 Control and Management 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.  Enel classifies risk monitored in its Risk Catalogue into 6 macro-categories: Financial, Strategic, Governance & Culture, Operational, Compliance and Digital Technology.

We have a specific Risk Control and Management policy, as well as specific policies that are established in relation to certain risks, corporate functions or businesses of the Company and that include limits and indicators that are subsequently monitored. Our main risk control and management policies are described as follow:

● The Guarantee Management Policy establishes the guidelines and methodologies to apply to managing guarantees from suppliers and to ensure an effective mitigation of counterparty risk, related to the profile of the supplier and the guarantor.

● The Commodities Risk Control Policy aims to allow the Company to make informed decisions and to minimize the probability of not achieving strategic results. In addition, it allows the Company to control the risk of non-compliance with the regulation of prices, volume, exchange rate, credit and counterparty of commodities, as well as financial regulation.

● The Credit and Counterparty Risk Control Policy is designed to minimize the probability that expected results will be affected by a default or reduction in the credit quality of a counterparty.

● The Financial Risk Control Policy strives to minimize the probability of not achieving commercial and financial strategic results by controlling financial market, financial counterparty, liquidity, and operational risks.

● The Hedge Policy aims to mitigate the risk of variations in exchange rates by maintaining a balance between flows indexed to US$ or local currencies, if any, and the levels of assets and liabilities in such currency.

● The Climate Change Policy establishes a common framework for the Company to guarantee the effectiveness in strategically managing the risks and opportunities associated with climate change while integrating with the Company’s main processes and decision-making.

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

116

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 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. The CMF requires us to provide them with information related to the board’s functions and composition; relationships between the company, shareholders, and the general public; third-party assessments; and internal control and risk management. The information must be provided annually by March 31 and be based on the previous calendar year. If none of them is adopted, the company must explain its reasons to the CMF. This information is available at the public’s disposal on the company’s website (www.enelchile.cl) and is sent to the stock exchanges.

In November 2021, the CMF issued General Norm Regulation No. 461 (“NCG 461”), establishing a new structure and contents for the Company’s annual report, including information previously reported through NCG 385. Therefore, NCG 385 will be phased out according to each company’s level of assets. In the case of Enel Chile, NCG 461 will be effective as of December 31, 2022, at which time NCG 385 will no longer apply to us.

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 all risks associated with ESG and climate change issues, including compliance with board policies.

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 2021, 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 2021.

117

Item 16C.      Principal Accountant Fees and Services

The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm KPMG Auditores Consultores SpA (“KPMG”) and its respective affiliates by type of service for the periods indicated.

Services Rendered	2021	2020
	(in millions of Ch$)
Audit fees(1)	1,175	905
Audit-related fees	68	127
Tax fees	—	—
All other fees	—	—
Total	1,243	1,032

(1) The Ch$ 270 million increase in audit fees in 2021 was mainly due to overrun audit 2020 for Ch$ 179 million and to the incorporation of Enel Transmission, which increased Enel Chile’s audit fees by Ch$ 88 million.

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 any related footnotes have been classified in accordance with SEC guidance.

Directors Committee Pre-Approval Policies and Procedures

The Directors Committee, which performs the functions of the Audit 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.

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Item  16E.      Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In the fiscal year 2021, there were no purchases of Enel Chile’s equity securities by us or any of our affiliates.

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

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 the Chilean Corportaions Law, a member would not be considered independent if, at any time, within the last 18 months such member (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 who 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 who 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 who 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$ 46 billion as of December 31, 2021) 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 the Chilean Corporations Law and the criteria and requirements of independence prescribed by the Sarbanes-Oxley Act (“SOX”), the SEC, and the NYSE. As of the date of this Report, 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.

119

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, including among its functions the duties performed by an Audit Committee. Please see “Item 6. Directors, Senior Management and Employees — C. Board Practices” for more information about the Director Committee’s functions and duties.

Item  16H.      Mine Safety Disclosure

Not applicable.

Item  16I.      Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item  17.      Financial Statements

Not Applicable.

Item   18.      Financial Statements

See Financial Statements included at the end of this Report.

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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 filed as Exhibit 2.1 to Enel Chile’s Annual Report on Form 20-F for the year ended December 31, 2020, is incorporated herein by reference.
8.1	List of Subsidiaries as of December 31, 2021.
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	Inline XBRL Instance Document – The Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Inline Cover Page Interactive File – The Cover Page Interactive Data File does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.

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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/ Fabrizio Barderi
	Name:	Fabrizio Barderi
	Title:	Chief Executive Officer
Date: April 27, 2022

122

Enel Chile and subsidiaries

Index to the Audited Consolidated Financial Statements

Report of KPMG Auditores Consultores SpA (PCAOB ID No. 1273) at December 31, 2021, and 2020	F-1 - F-4
Report of EY Audit S.p.A. – Enel Chile S.A. (PCAOB ID No. 1431) at December 31, 2019	F-F-5
Consolidated Financial Statements:
Consolidated Statements of Financial Position	F-6
Consolidated Statements of Comprehensive Income	F-8
Consolidated Statements of Changes in Equity	F-10
Consolidated Statements of Cash Flows	F-11
Notes to the Consolidated Financial Statements	F-12

Ch$Chilean pesos

US$U.S. dollars

UF“Unidades de Fomento” – A Chilean inflation-indexed, Chilean peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.

UTM“Unidad Tributaria Mensual” –Chilean inflation-indexed monthly tax unit used to define fines, among other purposes.

UTA“Unidad Tributaria Annual” – Chilean inflation-indexed annual tax unit. One UTA equals 12 UTM.

ThCh$Thousands of Chilean pesos

ThUS$Thousands of U.S. dollars

EUREuro

Consolidated Financial Statements

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 statements of financial position of Enel Chile S.A. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years ended December 31, 2021 and 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, 2021 and 2020, and the results of its operations and its cash flow for the years ended December 31, 2021 and 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, 2021, 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 27, 2022, expressed an unqualified 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 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 audits to obtain reasonable assurance about whether the consolidated 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 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 audits 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 audits provide 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 3-q and 27 to the consolidated financial statements, revenue from sales to customers includes estimates of energy provided and not billed as of December 31, 2021, amounting to ThCh$466,620,691 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 clients, such as energy purchased from the Company and the historical customers consumption information, including the energy consumption by clients 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 27 to the consolidated financial statements.

/s/ KPMG

KPMG Auditores Consultores SpA

We have served as the Company’s auditor since 2020.

Santiago, Chile

April 27, 2022

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, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, 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 statements of financial position of the Company as of December 31, 2021 and 2020, the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years ended December 31, 2021 and 2020, and the related notes (collectively, the consolidated financial statements), and our report dated April 27 2022 expressed an unqualified opinion 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 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.

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.

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

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 27, 2022

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 statements of comprehensive income, shareholders' equity and cash flows of Enel Chile S.A. and subsidiaries (the Company) for the year 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 results of its operations and its cash flows for the year 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 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 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 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 audit 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 audit provides a reasonable basis for our opinion.

/s/ EY Audit SpA.                

EY Audit SpA.

We served as the Company’s auditor from 2011 to 2020.

Santiago, Chile

April 29, 2020

F-5

ENEL CHILE S.A.

Consolidated Statements of Financial Position

As of December 31, 2021 and 2020

(In thousands of Chilean pesos – ThCh$)

		12-31-2021	12-31-2020
ASSETS	Note	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	5	309,975,140	332,036,013
Other current financial assets	6	4,041,415	3,352,404
Other current non-financial assets	7.a	66,825,997	19,801,573
Trade and other receivables, current	8	688,185,127	554,886,639
Current accounts receivable from related parties	9	56,440,088	57,976,125
Inventories	10	31,247,710	23,310,029
Current tax assets	11	111,537,016	35,038,413
TOTAL CURRENT ASSETS		1,268,252,493	1,026,401,196
NON-CURRENT ASSETS
Other non-current financial assets	6	39,379,065	20,660,450
Other non-current non-financial assets	7.a	89,616,648	65,787,215
Trade and other non-current receivables	8	515,786,340	445,016,566
Non-current accounts receivable from related parties	9	6,348,001	48,358,915
Investments accounted for using the equity method	12	9,923,933	12,992,803
Intangible assets other than goodwill	13	191,221,555	165,114,521
Goodwill	14	921,078,198	915,705,369
Property, plant and equipment	15	6,110,688,761	5,033,496,472
Investment property	16	7,539,005	7,421,940
Right-of-use assets	17	160,788,861	55,502,192
Deferred tax assets	18.b	179,700,736	108,013,945
TOTAL NON-CURRENT ASSETS		8,232,071,103	6,878,070,388
TOTAL ASSETS		9,500,323,596	7,904,471,584

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ENEL CHILE S.A.

Consolidated Statements of Financial Position (continued)

As of December 31, 2021 and 2020

(In thousands of Chilean pesos – ThCh$)

		12-31-2021	12-31-2020
LIABILITIES AND EQUITY	Note	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	19	88,339,890	157,499,141
Current lease liabilities	20	11,105,018	7,007,711
Trade and other payables, current	23	978,324,487	627,958,022
Current accounts payable to related parties	9	1,004,597,958	130,053,962
Other current provisions	24	19,756,317	3,434,804
Current tax liabilities	11	13,148,707	72,359,944
Other current non-financial liabilities	7.b	17,053,840	47,166,581
TOTAL CURRENT LIABILITIES		2,132,326,217	1,045,480,165
NON-CURRENT LIABILITIES
Other non-current financial liabilities	19	1,941,874,378	1,483,589,126
Non-current lease liabilities	20	148,557,059	44,857,807
Trade and other payables non-current	23	179,397,412	117,210,059
Non-Current accounts payable to related parties	9	1,300,059,097	1,164,044,462
Other long-term provisions	24	194,112,714	210,241,671
Deferred tax liabilities	18.b	197,416,950	168,057,562
Non-current provisions for employee benefits	25	58,951,586	75,538,265
Other non-current non-financial liabilities	7.b	1,135,285	1,177,968
TOTAL NON-CURRENT LIABILITIES		4,021,504,481	3,264,716,920
TOTAL LIABILITIES		6,153,830,698	4,310,197,085
EQUITY
Share and paid-in capital	26.1	3,882,103,470	3,882,103,470
Retained earnings		1,603,186,295	1,747,437,805
Other reserves	26.5	(2,387,421,412)	(2,277,625,485)
Equity attributable to Enel Chile		3,097,868,353	3,351,915,790
Non-controlling interests	26.6	248,624,545	242,358,709
TOTAL EQUITY		3,346,492,898	3,594,274,499
TOTAL LIABILITIES AND EQUITY		9,500,323,596	7,904,471,584

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2021, 2020 and 2019

(In thousands of Chilean pesos – ThCh$)

		2021	2020	2019
STATEMENTS OF PROFIT (LOSS)	Note	ThCh$	ThCh$	ThCh$
Revenues	27	2,829,682,404	2,548,384,317	2,624,576,323
Other operating income	27	25,547,131	37,017,880	146,258,037
Revenues and other operating income		2,855,229,535	2,585,402,197	2,770,834,360
Raw materials and consumables used	28	(2,011,305,404)	(1,374,445,639)	(1,421,205,251)
Contribution Margin		843,924,131	1,210,956,558	1,349,629,109
Other work performed by the entity and capitalized	15.b.2	31,157,196	25,539,316	17,610,861
Employee benefits expense	29	(163,345,154)	(137,226,748)	(129,604,956)
Depreciation and amortization expense	30.a	(210,927,656)	(229,957,019)	(236,627,387)
Impairment (loss) reversal recognized in profit or loss	30.b	(32,898,854)	(697,806,441)	(280,762,652)
Impairment (loss) impairment gain and reversal of impairment loss determined in accordance with IFRS 9	30.b	(18,765,175)	(15,167,707)	(10,047,000)
Other expenses, by nature	31	(189,550,825)	(190,593,334)	(184,143,140)
Operating Income		259,593,663	(34,255,375)	526,054,835
Other gains	32	10,137,284	9,488,815	1,793,201
Financial income	33	26,420,400	36,160,460	27,399,275
Financial costs	33	(174,043,116)	(127,408,771)	(164,897,900)
Share of profit of associates and joint ventures accounted for using the equity method	12	3,177,409	3,509,392	366,089
Foreign currency exchange differences	33	(15,334,368)	(23,272,231)	(10,412,110)
Gains or loss from indexed assets and liabilities	33	5,897,520	2,085,768	(2,982,268)
Profit (loss) before taxes		115,848,792	(133,691,942)	377,321,122
Income tax expense	18.a	(15,138,658)	81,305,107	(61,227,904)
PROFIT (LOSS)		100,710,134	(52,386,835)	316,093,218
Profit (loss) attributable to
Profit (loss) attributable to owners of the parent		85,153,969	(50,860,313)	296,153,605
Profit (loss) attributable to non-controlling interests	26.6	15,556,165	(1,526,522)	19,939,613
Profit (Loss)		100,710,134	(52,386,835)	316,093,218
Basic earnings per share
Basic earnings (losses) per share	Ch$/Share	1.23	(0.74)	4.28
Weighted average number of outstanding shares	Th	69,166,557	69,166,557	69,166,557
Diluted earnings per share
Diluted earnings (losses) per share	Ch$/Share	1.23	(0.74)	4.28
Weighted average number of outstanding shares	Th	69,166,557	69,166,557	69,166,557

The accompanying notes are an integral part of these consolidated financial statements.

F-8

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$)

		2021	2020	2019
STATEMENTS OF COMPREHENSIVE INCOME	Note	ThCh$	ThCh$	ThCh$
Gains (losses)		100,710,134	(52,386,835)	316,093,218
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
Profit (loss) from defined benefit plans	25.2.b	12,547,898	(8,545,834)	(7,777,204)
Other comprehensive loss that will not be reclassified subsequently to profit or loss		12,547,898	(8,545,834)	(7,777,204)
Components of other comprehensive income that will be reclassified subsequently to profit or loss, before taxes
Gains (losses) from foreign currency translation difference		197,099,813	(69,218,245)	73,114,966
Gains (losses) on measuring Financial Asset at Fair Value of Other Comprehensive Income		31	(9,125)	(3,673)
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	12.1.a	359,797	18,982	—
Gains (losses) on cash flow hedges		(455,116,679)	208,749,917	(160,828,497)
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		48,145,467	58,790,411	21,654,376
Other comprehensive income that will be reclassified subsequently to profit or loss		(209,511,571)	198,331,940	(66,062,828)
Total components of other comprehensive income (loss) before taxes		(196,963,673)	189,786,106	(73,840,032)
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		(3,387,932)	2,308,510	2,099,845
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		(3,387,932)	2,308,510	2,099,845
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		109,882,227	(72,741,119)	36,883,401
Income tax related to financial assets at fair value of other comprehensive income		(8)	2,464	992
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		109,882,219	(72,738,655)	36,884,393
Total other comprehensive income (loss)		(90,469,386)	119,355,961	(34,855,794)
TOTAL COMPREHENSIVE INCOME		10,240,748	66,969,126	281,237,424
Comprehensive income (loss) attributable to:
Owners of Enel Chile		(17,917,889)	68,669,685	255,988,200
Non-controlling interests		28,158,637	(1,700,559)	25,249,224
TOTAL COMPREHENSIVE INCOME		10,240,748	66,969,126	281,237,424

The accompanying notes are an integral part of these consolidated financial statements.

F-9

ENEL CHILE S.A.

Consolidated Statements of Changes in Equity

For the years ended December 31, 2021, 2020 and 2019

(In thousands of Chilean pesos – ThCh$)

			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 1-1-2021	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 equity						—	—	—	—	—	—	—
Comprehensive income	—	—	—	—	—	—	—	—	—	—	—	—
Profit (loss)	—	—	—	—	—	—	—	—	85,153,969	85,153,969	15,556,165	100,710,134
Other comprehensive income (loss)	—	—	176,151,370	(288,577,039)	8,993,993	21	359,797	(103,071,858)	—	(103,071,858)	12,602,472	(90,469,386)
Comprehensive income	—	—	—	—	—	—	—	—	—	(17,917,889)	28,158,637	10,240,748
Dividends	—	—	—	—	—	—	—	—	(238,399,472)	(238,399,472)	(21,782,812)	(260,182,284)
Increase (decrease) from other movements	—	—	—	—	(8,993,993)	—	2,269,924	(6,724,069)	8,993,993	2,269,924	(109,989)	2,159,935
Total changes in equity	—	—	176,151,370	(288,577,039)	—	21	2,629,721	(109,795,927)	(144,251,510)	(254,047,437)	6,265,836	(247,781,601)
Equity at end of period 12-31-2021	3,882,103,470	—	279,801,463	(391,523,134)	—	1,804	(2,275,701,545)	(2,387,421,412)	1,603,186,295	3,097,868,353	248,624,545	3,346,492,898

			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 Statements 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 movements	-	—	—	—	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 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 1-1-2019	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 movements	(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

(1) See Note 27.1

(2) See Note 27.3

(3) See Note 27.5

(4) See Note 27.6

F-10

ENEL CHILE S.A.

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2021, 2020 and 2019

			2021	2020	2019
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			3,686,363,387	2,961,814,449	3,053,366,631
Collections from premiums and services, annual payments, and other obligations from policies held			14,095,650	6,846,414	30,131,403
Receipts from rents and subsequent sales of such assets			13,674,456	102,436,230	7,938,954
Other collections from operating activities			142,770	16,403,356	929,839
Types of payment in cash from operating activities
Payments to suppliers for goods and services			(2,917,132,449)	(1,935,080,572)	(1,923,705,670)
Payments to and on behalf of employees			(134,092,365)	(140,378,194)	(130,102,939)
Payments of premiums and services, annual payments, and other obligations from policies held			(23,852,317)	(25,114,326)	(16,828,690)
Payments to manufacture or acquire assets held for rental to others and subsequently held for sale			(1,026,749)	(56,489,776)	(39,625,028)
Other payments for operating activities			(108,405,395)	(170,290,593)	(154,500,049)
Cash flows from (used in) operating activities
Income taxes paid			(112,104,283)	(1,342,494)	(82,778,533)
Other cash outflows, net			(4,769,890)	(2,938,296)	(1,114,199)
Net cash flows from operating activities			412,892,815	755,866,198	743,711,719
Cash flows from (used in) investing activities
Cash flows from the loss or gains of control of subsidiaries or other businesses, net			(62,769)	—	—
Other cash payments to acquire equity or debt instruments of other entities			(6,806)	(2,769,624)	(130,639)
Other receipts from the sale of shares in joint ventures		12.3.a)	11,786,767	—	—
Loans to related companies			(1,402,847)	—	—
Amounts from the sale of property, plant and equipment			18,197,075	—	872,988
Purchases of property, plant and equipment			(748,013,237)	(514,807,265)	(300,346,362)
Proceeds from the sale of intangible assets			2,489,340	—	—
Purchases of intangible assets			(38,059,298)	(39,506,950)	(20,732,156)
Payments for future, forward, option and swap contracts			(4,791,872)	(3,260,921)	(7,551,080)
Collections from future, forward, option and swap contracts			11,607,175	22,229	2,737,887
Collections from related entities			1,381,763	—	—
Dividends received			7,023,030	—	6,455,840
Interest received			3,296,869	5,671,141	6,034,028
Other inflows (outflows) of cash			—	—	1,127,683
Net cash flows used in investing activities			(736,554,810)	(554,651,390)	(311,531,811)
Cash flows from (used in) financing activities
Payments for other equity interests			—	(519,943)	—
Collection from long-term loans	5.d		77,273,500	—	—
Loans from related companies	5.d		633,799,000	484,520,001	283,831,505
Payments of loans	5.d		(33,736,628)	(150,878,247)	(315,323,464)
Payments of borrowings and lease liabilities	5.d		(6,060,566)	(4,940,582)	(4,498,202)
Dividends paid			(231,068,611)	(312,714,789)	(236,478,649)
Interest paid	5.d		(142,891,300)	(139,251,404)	(134,429,754)
Other outflows of cash, net	5.d		(4,083,886)	(3,884,370)	(33,537,124)
Net cash flows from (used in) financing activities			293,231,509	(127,669,334)	(440,435,688)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate movements			(30,430,486)	73,545,474	(8,255,780)
Effect of exchange rate movements on cash and cash equivalents
Effect of exchange rate movements on cash and cash equivalents			8,369,613	22,806,039	(1,231,644)
Net increase (decrease) in cash and cash equivalents			(22,060,873)	96,351,513	(9,487,424)
Cash and cash equivalents at beginning of year	5		332,036,013	235,684,500	245,171,924
Cash and cash equivalents at end of year	5		309,975,140	332,036,013	235,684,500

The accompanying notes are an integral part of these consolidated financial statements.

F-11

ENEL CHILE S.A

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contents	Page
1. GENERAL INFORMATION	F-15
2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS	F-16
2.1 Accounting principles	F-16
2.2 New accounting pronouncements	F-16
2.3 Responsibility for the information, judgments and estimates provided	F-22
2.4 Subsidiaries	F-23
2.5 Investment in associates	F-25
2.6 Joint arrangements	F-26
2.7 Basis of consolidation and business combinations	F-26
2.8 Functional currency	F-28
2.9 Conversion of financial statements denominated in foreign currency	F-28
3. ACCOUNTING POLICIES	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
f.1) Lessee	F-34
f.2) Lessor	F-35
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 of financial assets and financial liabilities	F-40
g.8) Financial guarantee contracts	F-40
h) Fair value measurent	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) Classification of balances as current and non-current	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-49
a) Regulatory framework	F-49
b) Regulatory matters	F-52
c) Tariff Revisions and Supply Processes	F-55
5. CASH AND CASH EQUIVALENTS	F-58
6. OTHER FINANCIAL ASSETS	F-59
7. OTHER NON-FINANCIAL ASSETS AND LIABILITIES	F-60

F-12

8. TRADE AND OTHER RECEIVABLES	F-61
9. BALANCES AND TRANSACTIONS WITH RELATED PARTIES	F-66
9.1 Balances and transactions with related parties	F-67
a) Receivables from related parties	F-67
b) Accounts payable to related parties	F-67
c) Significant transactions and effects on profit or loss	F-69
dd91Significatnstransactions) Significant transactions	F-69
9.2 Board of Directors and key management personnel	F-71
9.3 Compensation of key management personnel	F-74
9.4 Incentive plans for key management personnel	F-74
9.5 Compensation plans linked to share price	F-74
10. INVENTORY	F-75
11. CURRENT TAX ASSETS AND LIABILITIES	F-75
12. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD	F-76
12.1. Investments accounted for using the equity method	F-76
12.2. Additional financial information on investments in associates	F-76
12.3. Joint ventures	F-77
13. INTANGIBLE ASSETS OTHER THAN GOODWILL	F-77
14. GOODWILL	F-80
15. PROPERTY, PLANT AND EQUIPMENT	F-82
16. INVESTMENT PROPERTY	F-87
17. RIGHT-OF-USE-ASSETS	F-88
18. INCOME TAX AND DEFERRED TAXES	F-89
a) Income taxes	F-89
b) Deferred taxes	F-90
19. OTHER FINANCIAL LIABILITIES	F-93
19.1 Interest-bearing borrowings	F-93
19.2 Unsecured liabilities	F-95
19.3 Secured liabilities	F-96
19.4 Hedged debt	F-96
19.5 Other information	F-96
19.6 Future Undiscounted debt flows	F-97
20. LEASE LIABILITIES	F-97
21. RISK MANAGEMENT POLICY	F-99
21.1 Interest rate risk	F-99
21.2 Exchange rate risk	F-99
21.3 Commodities risk	F-100
21.4 Liquidity risk	F-100
21.5 Credit risk	F-101
21.6 Risk measurement	F-101
22. FINANCIAL INSTRUMENTS	F-103
22.1 Financial instruments, classified by type and category	F-103
22.2 Derivative instruments	F-104
22.3 Fair value hierarchy	F-107
23. CURRENT AND NON-CURRENT PAYABLES	F-108
24. PROVISIONS	F-109
25. POST-EMPLOYMENT BENEFIT OBLIGATIONS	F-111
25.1 General information	F-111
25.2 Details, movements and presentation in financial statements	F-111
25.3 Other disclosures	F-112
26. EQUITY	F-113
26.1 Equity attributable to the owners of Enel Chile	F-113
26.1.1 Subscribed and paid capital and number of shares	F-113
26.2 Dividends	F-113
26.3 Foreign currency translation reserves	F-113
26.4 Restrictions on subsidiaries transferring funds to the parent	F-113
26.5 Other reserves	F-114
26.6 Non-controlling Interests	F-115
27. REVENUE AND OTHER OPERATING INCOME	F-116
28. RAW MATERIALS AND CONSUMABLES USED	F-118

F-13

29. EMPLOYEE BENEFITS EXPENSE	F-118
30. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSS OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9	F-119
31. OTHER EXPENSES, BY NATURE	F-119
32. OTHER GAINS (LOSSES)	F-120
33. FINANCIAL RESULTS	F-120
34. INFORMATION BY SEGMENT	F-122
34.1 Basis of segmentation	F-122
34.2 Generation and distribution	F-123
35. GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS	F-125
35.1 Direct guarantees	F-125
35.2 Indirect guarantees	F-125
35.3 Litigation and arbitration proceedings	F-125
35.4 Financial restrictions	F-128
35.5 COVID-19 contingency	F-130
35.6 Other Commitments	F-131
36. HEADCOUNT	F-131
37. SANCTIONS	F-132
38. ENVIRONMENT	F-134
39. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED	F-139
40. SUBSEQUENT EVENTS	F-140
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY	F-142
APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012	F-144
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES	F-146
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY, POWER AND TOLL	F-149
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS	F-150

F-14

ENEL CHILE S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2021 AND 2020 AND FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019.

(In thousands of Chilean pesos – ThCh$)

1. GENERAL INFORMATION

Enel Chile S.A. (hereinafter the “Parent Company”, the “Company” or “Enel Chile”) 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, 2021, the Group had 2,215 employees. During the fiscal year ended December 31, 2021, the Group averaged a total of 2,221 employees (see Note 36).

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.

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2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1. Accounting principles

The consolidated financial statements of Enel Chile as of December 31, 2021, approved by its Board of Directors at its meeting held on April 27, 2022, 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 as of December 31, 2021 and 2020, and the results of operations changes in equity and cash flows for each of the years ended December 31, 2021, 2020 and 2019, 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 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, 2021:

Amendments	Mandatory application for annual periods beginning on or after:
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	January 1, 2021

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 or after 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.

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The application of these improvements did not generate 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 finalized a reform that phased out benchmark interest rates, such as Interbank Offering Interest Rates (“IBORs”), by issuing a package of amendments to the following IFRS:

- IFRS 9 Financial Instruments

- IAS 39 Financial Instruments: Recognition and Measurement

- IFRS 7 Financial Instruments: Disclosures

- IFRS 4 Insurance Contracts

- IFRS 16 Leases

The aim of these amendments is to help companies provide investors with useful information about the effects of the reform on their financial statements.

Background information

IBORs are interest rates published daily as a reference to the average interest at which a certain number of financial institutions would grant unsecured interbank loans at different terms and currencies.

Because of concerns regarding attempts to manipulate benchmark interest rates in recent years, regulators around the world started a radical reform on these rates to increase the reliability of benchmark interest rates within the international financial system. The objective of the reform is to replace interbank offering interest rates with alternative risk-free benchmark interest rates, which are based on liquid transactions in underlying markets and do not depend on expert judgments, such as the Secured Overnight Funding Rate (SOFR).

Phase 1 Amendments

Phase 1 of the IASB’s work was focused on providing temporary exceptions that allow entities to continue to apply hedge accounting during the uncertain period prior to IBOR replacement. This phase finished in 2019 with the issuance of amendments to IFRS 9, IAS 39 and IFRS 7, which became effective on January 1, 2020.

Phase 2 Amendments

Phase 2 complements the previous amendments and addresses the effects on financial statements when a company replaces a previous benchmark interest rate with an alternative benchmark interest rate. These amendments mainly relate to the following:

- 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.

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Phase 2 amendments issued became effective beginning on January 1, 2021, with retrospective application, subject to certain exceptions. It is not necessary to restate previous periods.

Hedging relationships

The Group has assessed the impact of uncertainty generated by the IBOR reform on its current hedging relationships, on both hedging instruments and hedged items. The Group’s most relevant exposure is to USD LIBOR rate.

The hedging relationships affected by the IBOR reform could be rendered ineffective due to the expectations of market participants regarding the time when interbank market-based benchmark rates will transition to risk-free alternative rates. This transition could occur at different times for hedged items and hedging instruments and could lead to ineffectiveness. Therefore, the Group is applying the amendments to IFRS 9 issued in September 2019 (Phase 1 Amendments) to the hedging relationships directly affected by the reform.

Group Exposure

In March 2021, the LIBOR succession dates were announced: December 31, 2021, for LIBOR in Euros, Swiss francs, yen and British pounds, regardless of terms. The same succession date applies to LIBOR in USD at one week and two months and June 30, 2023, will be the succession date for all the remaining terms of LIBOR in USD. Accordingly, the Group has completed an impact evaluation of the LIBOR reform on loan agreements and derivative instrument contracts after having defined the scope regarding number and nominal value, including the determination of fallback rates for new transactions. The alternative benchmark rates will begin to be implemented as of July 1, 2023, with the elimination of the remaining USD LIBOR rates.

As of December 31, 2021, the Group’s exposure, (in terms of the notional amounts of the contracts that must transition to an alternative reference rate, by type of instrument and interest rate), is detailed as follows:

	Notional as of 12-31-2021
Type of interest rate	Non-derivative financial liabilities MCh$	Derivative instruments MCh$	Total MCh$
USD LIBOR	751,774	42,235	794,009

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b) Accounting pronouncements applicable beginning on January 1, 2022 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 or after:
Amendments to IFRS 16: COVID-19 - Related Rent Concessions Beyond June 30, 2021	April 1, 2021
Amendments to IFRS 3: Reference to the Conceptual Framework	January 1, 2022
Amendments to IAS 16: Proceeds before Intended Use	January 1, 2022
Amendments to IAS 37: Onerous contracts - Cost of Fulfilling a Contract	January 1, 2022
Annual Improvements to IFRS: 2018-2020 Cycle - IFRS 1: First-time Adoption of International Financial Reporting Standards - IFRS 9: Financial Instruments - Amendment to Illustrative Examples accompanying IFRS 16 - IAS 41: Agriculture	January 1, 2022
Amendments to IAS 1: Classification of Liabilities as Current or Non-Current	January 1, 2023
Amendments to IAS 1 and IFRS Practice Statement 2: Disclosure of Accounting Policies	January 1, 2023
Amendments to IAS 8: Definition of Accounting Estimates	January 1, 2023
Amendment to IAS 12: Deferred Tax related to Assets and Liabilities arising from a Single Transaction	January 1, 2023

Amendments to IFRS 16: “COVID-19-Related Rent Concessions after June 30, 2021”

Because of the continued impact of the COVID-19 pandemic, the IASB issued an amendment to IFRS 16 “Leases” on March 31, 2021, that extended by one year the period of application of the practical expedient that helps lessees to account for rental concessions linked to COVID-19. With these amendments, the IASB extended the practical expedient to rent concessions that reduce lease payments originally due on or before June 30, 2022.

The amendment is effective for annual periods beginning on or after April 1, 2021, retrospectively, recognizing the cumulative effect of initially applying the amendment as an adjustment to the opening balance of retained earnings (or another component of equity, as appropriate) at the beginning of the annual reporting period in which the lessee first applies the amendment. Earlier application is permitted, even for financial statements that have not been authorized for publication as of March 31, 2021. Enel Chile has decided not to early apply these amendments.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact 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 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.

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The amendments are applicable prospectively to business combinations with acquisition dates beginning on the first annual period beginning on or after January 1, 2022. Early application is permitted.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact 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 or after 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 has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact 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 or after January 1, 2022. Early application is permitted. 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 has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

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 9 “Financial 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.

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These improvements are applicable to reported annual periods beginning on or after 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 accompanying IFRS 16 Leases: 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 has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

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 assessing the potential impact of the application of these amendments on the Group’s consolidated financial statements.

Amendments to IAS 1 and IFRS Practice Statement 2: “Disclosure of Accounting Policies”

On February 12, 2021, the IASB issued limited-scope amendments to IAS 1: Presentation of Financial Statements and IFRS: Practice Statement No. 2 Making Materiality Judgements. This related to the final stage of its materiality improvement work, in order to help entities with their accounting policy disclosures. The aim was to provide more useful information to investors and other primary users of the financial statements.

Amendments to IAS 1 require entities to disclose their material information on the accounting policies rather than their significant accounting policies. The amendments to IFRS Statement of Practice No. 2 provide guidance on how to apply the concept of materiality to accounting policy disclosures.

The amendments are effective for annual periods beginning on or after January 1, 2023. Early application is permitted.

Management is assessing the potential impact of the application of these amendments on the Group’s consolidated financial statements disclosures.

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Amendments to IAS 8: “Definition of Accounting Estimates”

On February 12, 2021, the IASB issued limited-scope amendments to IAS 8: “Accounting Policies, Changes to Accounting Estimates and Errors.” The aim was to clarify how companies should distinguish between changes to accounting policies and changes to accounting estimates, in order to reduce diversity in practice.

This distinction is important because accounting estimate changes only apply prospectively to future transactions and other future events. In addition, accounting policy changes generally apply retrospectively to past transactions and other past events.

The amendments are effective for annual periods beginning on or after January 1, 2023 and will be applied prospectively to changes to estimates and accounting policies that occur from the beginning of the first year in which the entity applies the amendments. Early application is permitted.

Management is assessing the potential impact of the application of these amendments on the Group’s consolidated financial statements.

Amendments to IAS 12: “Deferred Tax related to Assets and Liabilities arising from a Single Transaction”

On May 7, 2021, the IASB issued specific amendments to IAS 12: Income Taxes, with the aim of clarifying how companies should account for deferred taxes on transactions, such as leases and decommissioning obligations.

In certain circumstances, companies are exempt from recognizing deferred taxes when they recognize assets or liabilities for the first time. Previously, there was some uncertainty about whether the exemption applied to transactions, such as leases and decommissioning obligations, transactions for which companies recognize both an asset and a liability. The amendments clarify that the exemption is not applicable to these transactions and companies are required to recognize deferred taxes on such transactions.

The amendments are effective for annual periods beginning on or after January 1, 2023. Early application is permitted.

Management is assessing 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.

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).

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- 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 25).

- 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 22).

- 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 8).

- 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, 2021, according to the information available and considering a scenario in constant evolution, the main areas that required Management to use their judgment and make estimates were the following: i) measurement of expected credit losses on 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.

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Enel Chile has power over its subsidiaries when it holds the majority of substantive voting rights, or if this is not the case, when it holds the rights that grant it present capacity to direct their relevant activities, i.e., the activities that significantly affect the subsidiary’s performance.

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 12-31-2021			Ownership % at 12-31-2020
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
77.282.311-8	Enel Transmisión Chile S.A. (i) (iv)	Chile	Chilean peso	99.09%	—	99.09%	—	—	—
96.800.460-3	Luz Andes Ltda. (v)	Chile	Chilean peso	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A. (i) (v)	Chile	Chilean peso	99.09%	—	99.09%	99.09%	—	99.09%
96.783.910-8	Enel Colina S.A. (vii)	Chile	Chilean peso	—	100.00%	100.00%	—	100.00%	100.00%
91.081.000-6	Enel Generación Chile S.A.	Chile	Chilean peso	93.55%	—	93.55%	93.55%	-	93.55%
96.504.980-0	Empresa Eléctrica Pehuenche S.A.	Chile	Chilean peso	—	92.65%	92.65%	—	92.65%	92.65%
77.047.280-6	Sociedad Agrícola de Cameros Ltda.	Chile	Chilean peso	57.50%	—	57.50%	57.50%	—	57.50%
76.924.079-9	Enel X Chile Spa	Chile	Chilean peso	100.00%	—	100.00%	100.00%	—	100.00%
96.920.110-0	Enel Green Power Chile Ltda. (vi)	Chile	U.S. dollar	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A. (ii) (vi)	Chile	U.S. dollar	99.99%	—	99.99%	99.99%	—	99.99%
76.052.206-6	Parque Eólico Valle de los Vientos SpA (vi)	Chile	U.S. dollar	—	—	—	—	—	—
76.306.985-0	Diego de Almagro Matriz SpA (vi)	Chile	U.S. dollar	—	—	—	—	—	—
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (vi) (viii)	Chile	U.S. dollar	—	—	—	—	—	—
76.321.458-3	Almeyda Solar SpA (ii)	Chile	U.S. dollar	—	—	—	—	100.00%	100.00%
76.179.024-2	Parque Eólico Tal Tal SpA (viii)	Chile	U.S. dollar	—	—	—	—	—	—
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. (iii)	Chile	U.S. dollar	—	—	—	—	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%
76.722.488-5	Empresa de Transmisión Chena S.A. (iv)	Chile	Chilean peso	—	—	—	—	100.00%	100.00%

2.4.1Changes in the scope of consolidation at December 31, 2021

2021

i. 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 shareholders’ interest in the spin-off company.

This process was performed to comply with the requirements related to the exclusive line of business of distribution, in accordance with the latest amendments to Decree Law No. 4/2016 issued by the Ministry of Economy, Development and Reconstruction, which established the consolidated, coordinated and systematized text of Decree Law No. 1-1982 issued by the Ministry of Mining, General Law of Electric Services.

ii. On January 1, 2021, the merger by the incorporation of Almeyda Solar SpA into Enel Green Power Chile S.A. took place. As a consequence, the latter became the legal successor company.

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iii. During the second quarter of 2021, the liquidation of the company “Empresa Nacional de Geotermia S.A.” (a subsidiary of Enel Green Power Chile S.A.) was finalized. The advance termination and liquidation of this company was approved by the shareholders at the Extraordinary Shareholders’ Meeting, held on November 24, 2020.

iv. On November 1, 2021, Empresa de Transmisión Chena S.A. merged with Enel Transmisión Chile S.A. where the latter became the legal successor company. This transaction was approved by the Board of Directors of Enel Transmisión Chile S.A. at the extraordinary meeting held on October 20, 2021, in which the Directors in attendance unanimously ruled to buy from Enel Colina S.A., the minority interest held by the latter in the subsidiary Empresa de Transmisión Chena S.A., so as to hold 100% of that subsidiary’s shares. Consequently, an irregular merger was performed, by which Empresa de Transmisión Chena S.A. was absorbed by Enel Transmisión Chile S.A. without any liquidation thereof.

2020

v. On January 1, 2020, Luz Andes Ltda. merged into Enel Distribución Chile S.A. where the latter company became the legal successor company.

vi. 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.

vii. On April 14, 2020, Empresa Eléctrica de Colina Ltda. changed its name to Enel Colina S.A.

viii. 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.

2.5. Investments in associates

Associates are 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 12-31-2021			Ownership % at 12-31-2020
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 X AMPCI Ebus Chile SpA (*)	Chile	U.S. dollar	—	20.00%	20.00%	—	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 12-31-2021			Ownership % at 12-31-2020
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (i)	Chile	Chilean peso	—	—	—	—	50.00%	50.00%
77.110.358-8	HIF H2 SpA. (ii)	Chile	U.S. dollar	—	50.00%	50.00%	—	—	—

i. On December 30, 2021, the sale of the entire interest that Enel Generación Chile S.A. held in Transmisora Eléctrica de Quillota Ltda., to APG Energy & Infra Investments Chile Expansion SpA and CELEO Redes Chile Expansion SpA was completed.

ii. On April 1, 2021, Enel Green Power Chile S.A. acquired an interest of 50% in the new company HIF H2 SpA., for the development of green hydrogen projects in the Magallanes region.

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.

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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 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 Company 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.

For each business combination, 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 Parent 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 Company.

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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 Company, 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.

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 statement of comprehensive income in 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. Changes in the Company’s net investment in the subsidiary, which operates in a hyperinflationary economy, based on the application of the price-level restatement/translation method, are recorded as follows: (i) the effect of restatement due to inflation is recognized directly in Equity, under the "Other reserves" account; and (ii) the effect of foreign currency translation is recognized in Gain (losses) from foreign currency translation, in the consolidated statements of comprehensive income: Other comprehensive income.

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.

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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 2019	53.64%
From January to December 2020	36.13 %
From January to December 2021	50.95%

The effects of the application of this standard on these consolidated financial statements are detailed in Note 33.

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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 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 e.g., 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 15.b.1).

- Employee expenses directly related to construction in progress (see Note 15.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 24).

Assets under 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 longer useful life are capitalized as an increase in the cost 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	10 – 50
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 16.

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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 Company 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, 2021 and 2020, intangible assets with indefinite useful lives amounted to ThCh$14,766,953 and ThCh$14,605,574, 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 2021, the rates used to extrapolate the projections were between 2.0% and 3.0%.  

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 2021 were between 6.0% and 7.7%.

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,

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the investments necessary to maintain the installed capacity in adequate operating conditions are taken into account; in the distribution activity, 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 2021, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2020, were not significant and cash flows generated in 2021 remained in a reasonable variance range compared to those expected for that period.

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.

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.

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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 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.

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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 12) and non-current assets and disposal groups held for sale or distribution to owners (see Note 3.k), into 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 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.

(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.

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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); ii) Loss Given Default (LGD), and iii) Exposure at Default (EAD).  

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:

- 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

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- EAD: accounting exposure at the reporting date, including invoices issued but not due and invoices pending issuance for services rendered, net of potential cash deposits obtained as guarantees.

- Analytical or individual evaluation: if accounts receivables 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 22, 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 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.”

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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 CVA and 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 22.3.

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 (see Notes 2.5 and 2.6 respectively).

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

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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.

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.”

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.

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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 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.

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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.

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 receivable 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

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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 be 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.

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 exists 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, 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

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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, 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 27 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 obligations not met (or not met partially) at the end of the reporting period.

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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, 2021 and 2020 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 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 (expense) 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 (Chilean Corporations Law) 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 Chile 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, 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.

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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.

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.

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4.    SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

a) Regulatory Framework

The Chilean electricity sector is regulated by the General Law of Electricity Services (Ley General de Servicios Eléctricos) No. 20,018, contained in Decree with Force of Law (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 Decreto Supremo D.S. No. 327 of 1998.

The main authority on Chilean 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.

Within the Ministry of Energy, the Chilean National Energy Commission (or “CNE” in its Spanish acronym), is the regulatory body for the Chilean electricity sector and the Superintendency of Electricity and Fuel (“SEF”), is the oversight entity. The Ministry of Energy also includes the Chilean Commission of Nuclear Energy (CChEN) and the Energy Sustainability Agency.

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

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 Electricity Law establishes a National Electric Coordinator, an independent body governed by public law, in charge of the operation and coordination of the Chilean electricity system whose main objectives are to: i) Preserve the security of the service, ii) Guarantee an economic operation of the interconnected installations of the system and iii) Guarantee open 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 networks: the National Electricity System (“SEN” in its Spanish acronym), which extends from Arica in northern Chile to Chiloé in southern Chile, and two smaller isolated networks: Aysén and Magallanes.

The Chilean electricity industry can be divided into three business segments: generation, transmission and distribution. The electricity facilities associated with these three segments 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. The CNE determines the prices of Capacity.

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Consumers are classified according to their demand as regulated or unregulated customers. Regulated customers are those with a connected capacity of up to 5,000 kW. Customers with a connected capacity between 500 kW and 5,000 kW may choose between the free or regulated rate system.

Limits to Integration and Concentration

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, transmission, 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 establishes limits to the participation of generation or distribution companies in the National Transmission segment and prohibits National Transmission companies to participate in the generation and distribution segment.

Moreover, as of January 1, 2021, Exempt Resolution No. 173 of the CNE determined the scope of the exclusive line of business and separate regulatory accounting obligations, for the provision of public electric distribution services in accordance with Law No. 21,194.  

a.1 Generation Segment

Electricity generation companies must operate under the operation plan designed by the National Electric Coordinator. However, each company can freely decide whether to sell its energy and capacity to regulated or unregulated customers. Any surplus or deficit between sales to customers and production is sold to other generators at the spot market price. A generation company may have the following types of customers:

• Unregulated 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 an unregulated customer but must remain in the selected category for at least four years. These consumers can freely negotiate their electricity supply prices with suppliers.

• Distribution Companies: those that 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 come about 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, and energy is valued at marginal cost and capacity at the corresponding regulated price established twice a year by the authority.

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.

Law No. 20,257, dated April 2008, encourages the use of Non-Conventional, Renewable Energies (NCRE). The current version of this law states that by the year 2025, 20% of the electricity matrix will be covered by NCREs, adhering to the withdrawal schedule established in the previous law for contracts in force as of July 2013.

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a.2 Transmission Segment

Transmission segment is divided into five segments: National Transmission, Transmission for Development Poles, Zonal Transmission, Dedicated Transmission and International Interconnection Systems. The transmission facilities are subject to an open access regime, and may be used by any interested user under non-discriminatory conditions. The remuneration of the existing facilities of the National, Zonal, Development Poles Transmission segments and the dedicated transmission facilities used by users subject to price regulation is determined through a tariff-setting process conducted every four years and regulated by Law No. 20,936.

The planning of the National, Zonal and Development Pole Transmission systems corresponds to a regulated and centralized process, for which both the National Electrical Coordinator and the interested parties annually propose expansion works. The CNE is in charge of annually preparing an expansion plan through Technical Reports, which can be observed and disagreed with before the Panel of Experts.

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-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, 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, will be a yearly after-tax rate of between 6% and 8%.

Subsequently, 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.

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.

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b) Regulatory matters

2019 – 2021 Laws and Regulations

(i) Law No. 21,185 – Creates a Transitional Mechanism for Stabilizing Customers’ Electricity Prices under the Regulated Price System

On November 2, 2019, the Ministry of Energy published Law No. 21.185, which established a transitional mechanism for stabilizing customers’ electricity prices under the regulated price system. 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” in its Spanish acronym). 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). 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. 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 CNE, and its modifications.

(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 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%). 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. 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, distribution companies may only provide public electricity distribution service and are prohibited from selling energy and power to unregulated customers. The requirements contained in said Resolution are applicable since January 1, 2021.

(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 (Ley de Servicios Básicos) was passed. This law considers extraordinary measures to support the most vulnerable customers and prohibits electricity distribution companies from cutting services due to nonpayment for residential customers, small businesses, hospitals, and firefighters, among others. 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.

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On December 29, 2020, Law No. 21,301 was ratified and extended the terms defined in Law No. 21,249, establishing a benefit duration of 270 days following ratification of this new Law, as opposed to the initial 90 days. Likewise, the number of installments was modified to a maximum of 36, instead of the previously defined maximum of 12 installments.

On May 13, 2021, Law No. 21,340 was passed to extend the effects of Law No. 21,249 to December 31, 2021. If, at that date, the State of Constitutional Exception and Emergency due to the Covid-19 Pandemic is still in effect, the terms will extend up to 60 days after the end date of said state of constitutional exception. Additionally, the number of installments was modified to a maximum of 48, instead of the previously defined maximum of 36 installments.

In December 2021, the Chilean association of power distribution companies (“Empresas Eléctricas”) announced that its members (CGE, Chilquinta, Enel Distribución Chile S.A., and Grupo Saesa) would extend until January 31, 2022, the prohibition on cutting service to customers for non-payment of electricity bills, despite the law expiring on December 31, 2021.

(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.

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 submitted to the Chilean Chamber of Representatives that would modify the Electricity Law in order to establish the right to electricity portability and to 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.

(vii) Law No. 21,305- Energy Efficiency

On February 13, 2021, the Energy Efficiency Law was passed for the purpose of preparing the First National Energy Efficiency Plan, which shall be renewed every five years, with the goal of reducing the energy efficiency by at least 10% between 2019 and 2030. Additionally, this plan must consider a goal for consumers with energy management capacity to reduce their energy intensity by an average of at least 4% during the effective term.

The Energy Efficiency Law includes other matters such as the construction of housing, buildings of public use, corporate buildings, and office buildings that must have an energy classification in order for final reception by the

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respective Department of Municipal Works. The Energy Efficiency Law also establishes that the Ministry of Energy will regulate the interoperability of the electric vehicle charging system.

(viii)Storage and Electromobility Systems Bill

On November 23, 2021, a bill was submitted to the Chilean Chamber of Representatives, that would promote the storage of electricity through the remuneration of surplus energy for stand-alone energy storage systems, and electromobility through a temporary discount to the annual vehicle registration fee for electric vehicles. The bill enables new business models for electromobility and allows the use of electric vehicle batteries for the provision of services to the network like frequency control. Additionally, it incorporates the concept of generation and consumption infrastructure project to allow renewable projects plus storage to extract energy from the electric system and inject surplus energy.

(ix) Non-Conventional Renewable Energies Bill

On November 23, 2021, a bill was submitted to the Chilean Chamber of Representatives, to establish the participation of renewable energies in the national energy matrix through the promotion of small-scale distributed generation, especially in net billing projects, the creation of a renewable energy traceability system and increased share of NCREs in the National Electric System, establishing a production goal of 40% by 2030.

(x) Green Hydrogen Bill

On November 23, 2021, a bill was submitted to the Chilean Chamber of Representatives to establish the production and use of green hydrogen in the country, establishing hydrogen blends in natural gas networks and allowing the National Petroleum Company (ENAP) to participate in its development. It proposes that gas line distribution concessions companies be required to use green hydrogen in their gas lines, which would generate local demand for green hydrogen, while also using the existing gas infrastructure and industry experience. Moreover, the project will allow for the use of other gases, such as biomethane or synthetic methane, to meet this share within natural gas blends.

Regulations Published in 2019 - 2021

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 SEN: On December 20, 2019, the Ministry of Energy published Decree No. 125/2017 with the Regulations on the Coordination and Operation of the SEN.

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 Net billing: On September 24, 2020, the Ministry of Energy published Decree No. 57/2019 with the Regulations on Distributed Generation for Self-Consumption.

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.

Draft of New Regulations on Surplus Energy: In September 2021, the Ministry of Energy issued a draft for new energy regulations. The main amendments are the inclusion of an efficiency factor that affects high variable cost generation units; the recognition of surplus power for renewable power plant storage systems with storage capacity; and the modification of the surplus power recognition methodology to eliminate technological discretion.

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Modification to the GNL Technical Standards: On October 13, 2021, the CNE issued Exempt Resolution No. 411, which approves the modification to the technical standards for operations programming in units that use regasified liquefied natural gas (GNL). These technical standards place responsibility upon the National Electric Coordinator to perform a Projected GNL Unit Generation Study (“GNL Study”), to determine the maximum volume of GNL to be declared “inflexible” for each regasified GNL by companies that operate these types of generation units.

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 2021 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) 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 SEN, as well as the adjustments and surcharges upon application of the Residential Rate Equality Mechanism, effective retroactively from 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 SEN, 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

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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.

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 SEN, 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.

On March 20, 2021, the Ministry of Energy published Decree No. 16T/2020 in the Official Gazette, which establishes the average regulated prices in the SEN, as well as the adjustment factor for application of the price stabilization transitory mechanism considered in Law No. 21,185, effective from July 1, 2020.

On May 20, 2021, the Ministry of Energy published Decree No. 19T/2020 in the Official Gazette, which establishes the average regulated prices in the SEN, as well as the adjustment factor for application of the price stabilization transitory mechanism considered in Law No. 21,185, effective from January 1, 2021.

Given the price stabilization mechanism, the publication of Decrees No. 6T/2020, No. 16T/2020, and No.19T/2020 had no effect on the final regulated customer rate.

- Short Term Regulated Prices

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.

On March 22, 2021, the Ministry of Energy published Decree No. 3T/2021, which establishes the regulated prices for electricity supply, effective from April 1, 2021.

vi) Exempt Resolution, which establishes charges for the use of transmission systems applied to free and regulated final consumers:

- On December 29, 2020, the National Energy Commission issued Exempt Resolution No. 495, which establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services, effective from January 1, 2021.

- On June 17, 2021, the National Energy Commission issued Exempt Resolution No. 192, which establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services, effective from July 1, 2021.

- Exempt Resolution that communicates the value of the indexes contained in the rate formulas applicable to supplies subject to price-setting and establishes the cut-off and restitution factor by concessions company. On June 21, 2019, the National Energy Commission issued Exempt Resolution No. 379, which communicates the value of the indexes contained in the rate formulas applicable to supplies subject to price-setting, effective as of July 1, 2019, and establishes the cut-off and restitution factor applicable for the period between July 1, 2019, and December 31, 2019.

- Exempt Resolution No. 434 from the National Energy Commission (dated November 18, 2020, effective as of December 1, 2020): establishes and communicates the Public Service Charge.

Given that the price stabilization mechanism is currently in effect, the Exempt Resolutions mentioned above have remained in force to date.

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c.2 Distribution Price Setting 2020-2024

This process is currently under development and therefore the rates are being applied according to the 2016-2020 rate setting.

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, which to date has not been issued.

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5.    CASH AND CASH EQUIVALENTS

a) The details of cash and cash equivalents as of December 31, 2021 and 2020 are as follows:

	As of December 31,
	2021	2020
Cash and Cash Equivalents	ThCh$	ThCh$
Cash balances	37,852	42,660
Bank balances	282,625,181	330,471,774
Time deposits	28,923	591,570
Other fixed-income instruments	27,283,184	930,009
Total	309,975,140	332,036,013

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,
	2021	2020
Currency	ThCh$	ThCh$
Chilean peso	245,516,611	300,357,149
Argentine peso	195,683	3,977,675
Euro	196,498	83,819
U.S. dollar	64,066,348	27,617,370
Total	309,975,140	332,036,013

More details of the Statement of Cash Flows see below:

c) The following table records the components of “Other payments for operating activities” line item in the Statement of Cash Flows for the years ended December 31, 2021, 2020 and 2019:

	2021	2020	2019
Other payments from operating activities	ThCh$	ThCh$	ThCh$
VAT tax debit	(80,921,378)	(135,096,018)	(123,065,058)
Tax on emissions	(16,465,950)	(23,800,541)	(15,563,495)
Other	(11,018,067)	(11,394,034)	(15,871,496)
Total	(108,405,395)	(170,290,593)	(154,500,049)

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d) Reconciliation of liabilities arising from financing activities for the years ended December 31, 2021, 2020 and 2019:

		Financing Cash Flows
Liabilities arising from financing activities	Balance as of 12-31-2021	From	Used	Interest paid	Total	Movements in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other movements	Balance as of 12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Short-term loans	157,573,676	417,253,000	(33,736,628)	(142,046,785)	241,469,587	(1,923,185)	114,041,146	138,755,531	—	231,743,010	881,659,765
Long-term loans	2,648,032,219	293,819,500	(6,238,340)	—	287,581,160	16,329,103	513,617,504	7,763,806	—	(232,072,987)	3,241,250,805
Lease liabilities (Note 20)	51,865,519	—	(6,060,565)	(844,515)	(6,905,080)	—	15,193,796	1,960,901	97,937,192	(390,251)	159,662,077
Assets held to cover liabilities arising from financing activities	(16,490,690)	2,154,453	—	—	2,154,453	(3,632,092)	(18,126,146)	—	—	—	(36,094,475)
Total	2,840,980,724	713,226,953	(46,035,533)	(142,891,300)	524,300,120	10,773,826	624,726,300	148,480,238	97,937,192	(720,228)	4,246,478,172
		Financing Cash Flows
Liabilities arising from financing activities	Balance as of 12-31-2020	From	Used	Interest paid	Total	Movements in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other movements	Balance as of 12-31-2020
	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 (Note 20)	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
Liabilities arising from financing activities	Balance as of 12-31-2019	From	Used	Interest paid	Total	Movements in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other movements	Balance as of 12-31-2019
	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 (Note 20)	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

(1) It relates to accrual of interest

6.    OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2021 and 2020 is as follows:

	Current		Non-current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Other Financial Assets	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value with changes in other comprehensive income	127,854	127,854	2,358,143	2,326,480
Financial assets measured at amortized cost	118,547	808,692	—	—
Hedging derivatives	3,584,937	1,000,964	37,020,922	16,422,737
Non-Hedging derivatives	210,077	1,414,894	—	1,911,233
Total	4,041,415	3,352,404	39,379,065	20,660,450

(*) See Note 35.6.

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7.    OTHER NON-FINANCIAL ASSETS AND LIABILITIES

a) Other non-financial assets

The detail of other non-financial assets as of December 31, 2021 and 2020 is as follows:

	Currrent		Non-Current
Other non-financial assets	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Tax Credit and Other Taxes	30,879,791	8,575,080	67,966,488	46,638,860
Prepaid expenses	34,623,121	9,991,447	—	—
Guarantee deposit	—	—	128,724	128,724
Water rights credits	—	—	9,298,704	7,910,531
Spare parts with a consumption schedule of more than 12 months	—	—	7,392,047	7,543,841
Other	1,323,085	1,235,046	4,830,685	3,565,259
Total	66,825,997	19,801,573	89,616,648	65,787,215

b) Other non-financial liabilities

The detail of other non-financial liabilities as of December 31, 2021 and 2020 is as follows:

	Currrent		Non-Current
Other non-financial liabilities	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Credit and Other Taxes	12,741,963	40,117,141	—	—
Reimbursable financial contributions	—	—	1,135,285	1,177,968
Deferred revenue from splices	1,149,415	3,860,816	—	—
Deferred revenue from transfer of networks	696,675	1,473,486	—	—
Deferred revenue from lighting services	564,465	145,247	—	—
Deferred revenue from other services	1,260,078	1,184,427	—	—
Other	641,244	385,464	—	—
Total	17,053,840	47,166,581	1,135,285	1,177,968

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8.    TRADE AND OTHER RECEIVABLES

a) The detail of trade and other receivables as of December 31, 2021 and 2020 is as follows:

	As of December 31,
	2021		2020
Trade and Other Receivables, Gross	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, gross	767,900,561	515,856,801	619,626,310	445,129,898
Trade receivables, gross	694,597,739	442,941,968	531,179,316	377,160,616
Accounts receivable from finance leases, gross	10,735,484	69,873,385	8,556,146	62,602,528
Other receivables, gross	62,567,338	3,041,448	79,890,848	5,366,754
	As of December 31,
	2021		2020
Trade and Other Receivables, Net	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, net	688,185,127	515,786,340	554,886,639	445,016,566
Trade receivables, net	628,681,800	442,871,507	481,442,020	377,047,284
Accounts receivable from finance leases, net	8,365,583	69,873,385	4,072,738	62,602,528
Other receivables, net (1)	51,137,744	3,041,448	69,371,881	5,366,754

(1) The detail of other accounts receivable is as follows:

	As of December 31,
	2021		2020
Other receivables, net (1)	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Accounts receivable from employees	11,808,014	2,522,560	13,256,252	4,442,878
Advances to suppliers and creditors	33,079,980	514,119	43,102,611	909,661
Compensation for central claims Tarapacá and Bocamina 1	—	—	5,360,345	—
Others	6,249,750	4,769	7,652,673	14,215
Total	51,137,744	3,041,448	69,371,881	5,366,754

a.1) Increase in trade and other receivables:

As of December 31, 2021. long-term trade receivables increased significantly by ThCh$65,781,352 compared to the end of 2020. This variance is mainly explained by the following:

● An increase in new balances receivable by ThCh$202,451,642, related to “Stabilized Price to Regulated Customers” offset by

● assignments and sales of accounts receivable from the generation segment totaling ThCh$ 156,928,875 (see section a.2 of this Note) during the first half of 2021.

These assignments of accounts receivable arose from the application of Law No. 21,185,

Published on November 2, 2019, by the Ministry of Energy, 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” in its Spanish acronym).

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).

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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.

The application of this Law generates a greater delay in the billing and collection of sales generated by 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$415,664,120 as of December 31, 2021 (ThCh$370,276,397 as of December 31, 2020) and trade payables for the purchase of energy from suppliers in the amount of ThCh$174,373,938 (ThCh$112,895,627 as of December 31, 2020), see Note 23.

- Lower energy sales revenue of ThCh$12,245,142 as of December 31, 2021 (ThCh$10,864,866 and ThCh$3,782,091 as of December 31, 2020 and 2019 respectively).

- Lower energy purchase costs of ThCh$3,388,944 as of December 31, 2021 (ThCh$3,515,292 and ThCh$1,181,163 as of December 31, 2020 and 2019 respectively).

- Higher finance income of ThCh$4,802,376 as of December 31, 2021 (ThCh$15,328,829 and ThCh$5,225,739 as of December 31, 2020 and 2019 respectively). See note 33.

- Higher finance costs of ThCh$2,409,504 as of December 31, 2021 (ThCh$ 4,518,268 and ThCh$19,062,333 as of December 31, 2020 and 2019 respectively). See note 33.

- Net gain from foreign currency translation of ThCh$28,572,116 as of December 31, 2021 (net loss of ThCh$25,260,383 and ThCh$3,835,024 as of December 31, 2020 and 2019 respectively), due to the dollarization of unbilled accounts receivable, see Note 33.

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 31, 2021 and 2020, 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) Assignment of rights and sale of accounts receivable to customers

I. Distribution Segment

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• On December 28, 2020, Enel Distribución Chile and Inter-American Investment Corporation entered into a framework agreement by virtue of which Enel Distribución Chile will have the right to assign collection rights from time to time, including a portion of accounts receivable from energy sales to certain customers. As of December 31, 2021, collection rights were assigned for ThCh$324,134,944 under this framework agreement (ThCh$44,797,737 as of December 31, 2020). According to the accounting criteria described in Note 3.g. 6, cash inflows have led to the derecognition of accounts receivable and the recognition of finance cost of ThCh$5,872,765 (ThCh$533,615 as of December 31, 2020).  

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.

II. Generation Segment

• On January 20, 2021, our subsidiaries Enel Generación Chile and Enel Green Power Chile signed a document called “Joinder”, whereby they became parties to “Commitment and Engagement Letter” dated December 31, 2020, which is subject to foreign governing law. The “Commitment and Engagement Letter” was subscribed by Goldman Sachs & Co. LLC and Goldman Sachs Lending Partners LLC, among others. Subsequently, on January 29, 2021, Enel Generación Chile and Enel Green Power Chile entered into a “Commitment Agreement” (also subject to foreign governing law), with the Inter-American Investment Corporation. The purpose of these agreements is to regulate the terms and conditions for the sale and assignment, by Enel Generación Chile and Enel Green Power Chile of balances generated in their favor (the “Balances”) by applying the transitional electricity price stabilization mechanism to customers who are subject to tariff rate regulation, as established by Law No. 21,185.

• Pursuant to the terms and conditions established in the “Sale and Purchase Agreement” (also subject to foreign governing law), entered into and between Enel Generación Chile S.A., Enel Green Power Chile and Chile Electricity PEC SpA., assignments of Balances may be carried out by Enel Generación Chile and Enel Green Power Chile from time to time, in favor of Chile Electricity PEC SpA, an unrelated entity which was specifically incorporated for this purpose.

• In addition, on January 29, 2021, Enel Generación Chile and Enel Green Power Chile entered into an agreement (subject to foreign governing law) with Chile Electricity PEC SpA referred to as the “Sale and Purchase Agreement” (the “Agreement”) for the sale and assignment of Balances. By virtue of this Agreement, Enel Generación Chile and Enel Green Power Chile have agreed to sell and assign to Chile Electricity PEC two groups of Balances for a nominal value of approximately US$158.9 million (ThCh$115,867,879) and US$12.2 million (ThCh$8,666,252) for Enel Generación and Enel Green Power Chile, respectively, totaling ThCh$121,652,067. The sale and assignment of these groups of Balances was effected on February 8, 2021, and March 31, 2021, respectively.

• In addition, on June 18, 2021, Enel Generación Chile and Enel Green Power Chile entered into amendments to the aforementioned “Commitment Agreements” entered into with the Inter-American Investment Corporation. The main purpose of these amendments is to recognize new groups of Balances that the companies may sell and assign to Chile Electricity PEC SpA, as well as to make adjustments to reflect the incorporation of a third financing provider to Chile Electricity PEC SpA. Likewise, on June 21, 2021, Enel Generación Chile, Enel Green Power Chile, Goldman Sachs & Co. LLC and Goldman Sachs Lending Partners LLC, among others, agreed to modify the aforementioned “Commitment and Engagement Letter”, to reflect the incorporation of certain entities of the Allianz Group as holders of promissory notes issued by Chile Electricity PEC SpA.

• On June 21, 2021, Enel Generación Chile, Enel Green Power Chile, and some entities of the Allianz Group signed a “Fee Letter”, detailing the commitments assumed by the Allianz Group entities to provide financing to Chile Electricity PEC SpA, among other matters, including its amendments. On the same date, Enel

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Generación Chile, Enel Green Power Chile, and Chile Electricity PEC SpA amended the aforementioned “Sale and Purchase Agreements” in order to regulate the terms and conditions of future sales of Balances that Enel Gneración Chile and Enel Green Power Chile may decide to effect.  

• On June 30, 2021, Enel Generación Chile and Enel Green Power Chile sold and assigned Balances to Chile Electricity PEC SpA for a nominal value of approximately US$41.7 million (ThCh$30,382,074) and US$2.8 million (ThCh$2,012,670), respectively.

As a result of the sale and assignment of Balances made during 2021, Enel Generación Chile and Enel Green Power Chile recognized finance costs of ThCh$39,110,910 and ThCh$3,458,695, respectively.

As mentioned above, Enel Generación Chile and Enel Green Power Chile may continue to make new sales of Balances from time to time. Whether or not these sales materialize will depend on the analysis that Management performs of the cash needs and prevailing market conditions from time to time.

For the year ended December 31, 2021 the effects of the aforementioned finance costs on the Distribution and Generation segments totaled ThCh$48,442,370 (ThCh$533,615 as of December 31, 2020) (see Note 33)

a.3) Others

There are no restrictions on the disposal of these types of accounts receivable in a significant amount.

The Group has one customer in the generation segment whose sales represent 10% or more of its revenue for the years ended December 31, 2021 and 2020:

- CGE Distribución S.A.

For amounts, terms and conditions related to accounts receivable due from related parties, refer to Note 9.1

b) Financial lease receivables

As of December 31, 2021 and 2020, future collections on financial lease receivables are the following:

	12-31-2021			12-31-2020
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	12,574,641	1,839,157	10,735,484	13,043,482	4,487,336	8,556,146
From one to two years	11,492,554	1,833,885	9,658,669	10,294,652	1,735,758	8,558,894
From two to three years	11,377,461	1,628,175	9,749,286	10,266,956	1,692,482	8,574,474
From three to four years	11,308,946	1,056,999	10,251,947	10,226,534	1,309,548	8,916,986
From four to five years	9,494,846	602,282	8,892,564	10,118,045	472,761	9,645,284
More than five years	31,618,242	297,323	31,320,919	27,488,134	581,244	26,906,890
Total	87,866,690	7,257,821	80,608,869	81,437,803	10,279,129	71,158,674

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.

As of December 31, 2021, financial income from lease debtors reached ThCh$1,829,631 (ThCh$1,562,017 as of December 31, 2020).

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c) As of December 31, 2021, and 2020, 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,
	2021	2020
Trade accounts receivables due and unpaid, but for which no impairment losses have been recorded	ThCh$	ThCh$
Less than three months	103,142,026	52,948,476
Between three and six months	22,902,308	13,513,388
Between six and twelve months	17,421,962	8,311,729
More than twelve months	51,177,749	34,485,893
Total	194,644,045	109,259,486

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, 2020	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 as of December 31, 2020	64,853,003
Increases (decreases) for the year (*)	18,765,175
Amounts written off	(3,884,603)
Increases (decreases) in foreign currency translation differences	52,320
Balance at December 31, 2021	79,785,895

(*) During 2021, impairment losses on trade receivables amounted to ThCh$18,765,175, which represents an increase of 23.7% over the prior year. This increase is mainly due to the effects on the economy arising from the COVID-19 pandemic, the deterioration of the payment capacity of a certain customer segment, as well as the prolonged lockdowns and the impossibility of cutting electricity supply to residential customers as a result of Law No. 21,249 (also referred to as the “Basic Services Law”, whose term was extended by Law 21,301), among other factors. For further information, see Note 4.b “Regulation - Regulatory Issues 2020 - 2021 - Laws and Regulations”, Note 30 “Impairment of financial assets” and Note 35.5 “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. Overall, the risk of uncollectability and, therefore, the write-off of the Company’s customers, is limited. (See Notes 3.g.3 and 21.5).

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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9.    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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9.1 Balances and transactions with related parties

The balances of accounts receivable and payable as of December 31, 2021 and 2020 are as follows:

a) Receivables from related parties

						Current		Non-current
						12-31-2021	12-31-2020	12-31-2021	12-31-2020
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa España	Spain	Common Inmediate Parent	EUR	Other Services	29,197	31,032	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Inmediate Parent	EUR	Other Services	519,340	266,732	—	—
Foreign	Enel Green Power Morocco	Morocco	Common Inmediate Parent	EUR	Other Services	377,899	252,803	—	—
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Gas Purchase Advance	15,677,431	20,067,363	6,348,001	48,358,915
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Dividends	—	616,697	—	—
Foreign	Endesa Generación	Spain	Common Inmediate Parent	EUR	Engineering Services	50,844	42,794	—	—
Foreign	Enel Italia SrL.	Italy	Common Inmediate Parent	EUR	Other Services	—	534,991	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	Other Services	477,950	216,185	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	Commodity derivatives	21,198,832	22,048,245	—	—
Foreign	Eletropaulo Metropolitana Eletricidade	Brazil	Common Inmediate Parent	US$	Other Services	31,841	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	Other Services	882,361	533,309	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Inmediate Parent	US$	Engineering Services	14,980	—	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Inmediate Parent	US$	Other Services	1,435,123	866,928	—	—
77.374.847-0	HIF H2 S.p.A	Chile	Joint Business	CLP	Capital advance	1,987,978	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Inmediate Parent	US$	Engineering Services	223,213	198,066	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Inmediate Parent	US$	Other Services	140,226	164,018	—	—
Foreign	Codensa S.A.	Colombia	Common Inmediate Parent	EUR	IT Services	96,464	322,872	—	—
Foreign	Codensa S.A.	Colombia	Common Inmediate Parent	US$	Other Services	51,915	74,930	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Inmediate Parent	CLP	Engineering Services	—	1,064,232	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Inmediate Parent	CLP	Other Services	71,862	—	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Inmediate Parent	US$	Engineering Services	1,036,601	162,252	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Inmediate Parent	US$	Other Services	558,576	404,354	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	CLP	IT Services	737,980	410,946	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	CLP	Other Services	1,533,188	1,007,511	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	CLP	Technical Services	486,802	—	—	—
Foreign	Enel Green Power Colombia SAS	Colombia	Common Inmediate Parent	US$	Engineering Services	511,502	1,342,341	—	—
Foreign	Enel Generación Piura S.A.	Peru	Common Inmediate Parent	US$	Engineering Services	77,487	55,897	—	—
Foreign	Enel Innovation Hubs Srl	Italy	Common Inmediate Parent	EUR	IT Services	102,449	25,362	—	—
Foreign	Chinango S.A.C.	Peru	Common Inmediate Parent	US$	Engineering Services	18,269	70,925	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	Engineering Services	126,210	170,756	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	US$	Engineering Services	470,414	395,683	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	Other Services	2,294	2,088	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	US$	Other Services	721,622	653,975	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Common Inmediate Parent	US$	IT Services	384,250	657,232	—	—
Foreign	Enel Green Power Perú	Peru	Common Inmediate Parent	US$	Engineering Services	489,630	405,030	—	—
Foreign	Enel Green Power Perú	Peru	Common Inmediate Parent	US$	Other Services	4,411	186,734	—	—
Foreign	Energía Nueva Energía Limpia México S.R.L	Mexico	Common Inmediate Parent	US$	Other Services	—	34,843	—	—
Foreign	Enel Italia SrL.	Italy	Common Inmediate Parent	EUR	Other Services	761,119	—	—	—
Foreign	Proyectos y Soluciones Renovables S.A.C.	Peru	Common Inmediate Parent	US$	Other Services	149,270	96,267	—	—
Foreign	Enel Generacion Costanera S.A.	Argentina	Common Inmediate Parent	US$	Engineering Services	184,990	155,722	—	—
Foreign	Enel Generacion El Chocón S.A.	Argentina	Common Inmediate Parent	US$	Engineering Services	14,203	11,954	—	—
Foreign	Enel Green Power Brasil Participacoes LTDA.	Brazil	Common Inmediate Parent	US$	Engineering Services	—	6,714	—	—
Foreign	Enel Green Power Brasil Participacoes LTDA.	Brazil	Common Inmediate Parent	US$	Other Services	—	200,977	—	—
Foreign	Enel Green Power Argentina	Argentina	Common Inmediate Parent	US$	Other Services	320,138	269,280	—	—
Foreign	Energetica Monzon S.A.C.	Peru	Common Inmediate Parent	US$	Engineering Services	776,841	653,567	—	—
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Inmediate Parent	US$	Other Services	90,777	234,834	—	—
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Inmediate Parent	US$	IT Services	1,543,540	1,080,101	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	CLP	Other Services	189,150	623,843	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	CLP	Technical Services	33,905	—	—	—
Foreign	Enel X S.R.L.	Italy	Common Inmediate Parent	EUR	Other Services	51,303	29,990	—	—
Foreign	Enel Produzione	Italy	Common Inmediate Parent	EUR	Other Services	230,049	60,644	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	EUR	Technical Services	1,223,525	753,544	—	—
Foreign	Enel North America Inc	United States	Common Inmediate Parent	US$	Other Services	222,740	192,582	—	—
Foreign	Enel X North America Inc	United States	Common Inmediate Parent	US$	Other Services	96,448	86,685	—	—
Foreign	Renovables de Guatemala S.A.	Guatemala	Common Inmediate Parent	US$	Engineering Services	—	1,089	—	—
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Inmediate Parent	EUR	IT Services	—	173,263	—	—
77.157.781-4	Enel X AMPCI L1 Holdings SpA	Chile	Associated	US$	Management services	3,239	8,176	—	—
77.157.783-0	Enel X AMPCI L1 SpA	Chile	Associated	US$	Management services	16,471	41,591	—	—
77.157.779-2	Enel X AMPCI Ebus Chile SpA	Chile	Associated	US$	Management services	3,239	8,176	—	—
					Total	56,440,088	57,976,125	6,348,001	48,358,915

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b) Accounts payable to related parties

						Current		Non-current
						12-31-2021	12-31-2020	12-31-2021	12-31-2020
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa España	Spain	Common Inmediate Parent	EUR	Other Services	—	159,940	—	—
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Inmediate Parent	CLP	IT Services	81,921	—	—	—
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Inmediate Parent	US$	Other Services	17,846	94,838	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Inmediate Parent	COP	Other Services	5,077	4,576	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	CLP	Other Services	2,528,922	2,285,642	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	US$	Other Services	144,953	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Common Inmediate Parent	US$	Other Services	—	2,185	—	—
Foreign	Eletropaulo Metropolitana Eletricidade	Brazil	Common Inmediate Parent	US$	Other Services	307,897	—	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Inmediate Parent	EUR	Other Services	330,865	651,662	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Inmediate Parent	EUR	IT Services	2,532,663	—	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Inmediate Parent	EUR	Technical Services	5,170,559	5,397,360	—	—
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Gas Purchase	6,484,164	14,650,079	—	—
Foreign	Endesa Generación	Spain	Common Inmediate Parent	EUR	Coal purchase	501,677	—	—	—
Foreign	Endesa Generación	Spain	Common Inmediate Parent	EUR	Engineering Services	—	190,879	—	—
Foreign	Endesa Generación	Spain	Common Inmediate Parent	EUR	Other Services	—	25,643	—	—
Foreign	Enel Iberia SRL	Spain	Common Inmediate Parent	EUR	IT Services	225,322	—	—	—
Foreign	Enel Iberia SRL	Spain	Common Inmediate Parent	EUR	Other Services	536,809	891,821	—	—
Foreign	Enel Produzione	Italy	Common Inmediate Parent	EUR	Other Services	1,033,214	1,395,436	—	—
Foreign	Enel Produzione	Italy	Common Inmediate Parent	EUR	Engineering Services	1,880,143	1,999,721	—	—
Foreign	Enel Energía	Italy	Common Inmediate Parent	EUR	Other Services	556,018	478,207	—	—
Foreign	Gridspertise s.r.l.	Italy	Common Inmediate Parent	EUR	IT Services	403,567	—	—	—
Foreign	Enel Generacion Costanera S.A.	Argentina	Common Inmediate Parent	US$	Purchase of materials	1,331,438	—	—	—
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Joint Business	CLP	Tolls	—	13,887	—	—
Foreign	Enel Green Power España SL	Spain	Common Inmediate Parent	EUR	Other Services	561,326	403,225	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	Other Services	787,719	558,964	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	Engineering Services	26,185	—	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	US$	Commodity derivatives	36,208,560	2,405,919	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	Technical Services	7,562,517	5,042,033	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Inmediate Parent	EUR	IT Services	303,992	—	—	—
Foreign	Enel Global Services S.r.l.	Italy	Common Inmediate Parent	EUR	Technical Services	1,324,716	1,154,817	—	—
Foreign	Enel Global Services S.r.l.	Italy	Common Inmediate Parent	EUR	IT Services	5,916,002	11,719,059	—	—
Foreign	Enel Global Services S.r.l.	Italy	Common Inmediate Parent	EUR	Engineering Services	—	551,776	—	—
Foreign	Enel Global Services S.r.l.	Italy	Common Inmediate Parent	EUR	Other Services	95,565	640,692	—	—
Foreign	Enel S.p.A.	Italy	Parent	CLP	Dividends	16,527,560	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	US$	Dividends	1,923	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	Technical Services	9,935,189	7,310,421	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	IT Services	2,142,992	263,443	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	Engineering Services	—	1,381,313	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	Other Services	5,410,491	2,516,113	—	—
Foreign	Enel Italia SrL	Italy	Common Inmediate Parent	EUR	IT Services	—	253,605	—	—
Foreign	Enel Italia SrL	Italy	Common Inmediate Parent	EUR	Other Services	1,617,382	676,267	—	—
Foreign	Enel Italia SrL	Italy	Common Inmediate Parent	EUR	Engineering Services	1,145,568	243,460	—	—
Foreign	Codensa S.A.	Colombia	Common Inmediate Parent	US$	Other Services	5,167	35,616	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	EUR	Technical Services	5,977,965	4,782,053	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	EUR	IT Services	3,050,405	2,125,349	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	EUR	Engineering Services	203,833	17,720	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	EUR	Other Services	1,304,026	947,100	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	Technical Services	31,580,956	21,206,647	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	Engineering Services	17,274,445	17,975,839	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	Other Services	16,248,379	9,249,143	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	EUR	IT Services	4,485,802	—	—	—
Foreign	Enel Green Power Spa	Italy	Common Inmediate Parent	CLP	Other Services	274,891	—	—	—
Foreign	Enel Green Power North America Inc	United States	Common Inmediate Parent	US$	Other Services	436,649	315,697	—	—
Foreign	Enel Finance International NV (*)	Netherlands	Common Inmediate Parent	US$	Loan payable	799,265,075	3,444,366	1,300,059,097	1,164,044,462
Foreign	Enel Green Power Italia	Italy	Common Inmediate Parent	CLP	Other Services	—	459,992	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	CLP	Other Services	407,152	345,708	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	EUR	Engineering Services	—	871,748	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	US$	Other Services	246,923	42,549	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Inmediate Parent	US$	Engineering Services	—	60,957	—	—
Foreign	Enel X S.R.L.	Italy	Common Inmediate Parent	EUR	Other Services	127,063	130,664	—	—
Foreign	Enel X S.R.L.	Italy	Common Inmediate Parent	EUR	IT Services	890,918	—	—	—
Foreign	Enel X S.R.L.	Italy	Common Inmediate Parent	EUR	Technical Services	8,826,081	4,225,269	—	—
Foreign	Cesi S.p.A.	Italy	Common Inmediate Parent	EUR	Engineering Services	316,622	247,773	—	—
Foreign	Tecnatom SA	Italy	Common Inmediate Parent	EUR	Engineering Services	33,386	73,842	—	—
Foreign	Enel X Brasil Gerenciamento de Energia Ltda	Brazil	Common Inmediate Parent	US$	Other Services	1,478	360	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Common Inmediate Parent	US$	Other Services	—	132,587	—	—
					Total	1,004,597,958	130,053,962	1,300,059,097	1,164,044,462

(*) See letter d below.

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c) Significant transactions and effects on profit or loss

As of December 31, 2021, 2020 and 2019, the significant transactions with related companies that are not consolidated, are as follows:

					For the years ended December 31,
					2021	2020	2019
Taxpayer ID N°	Company	Country	Relationship	Description of transaction	ThCh$	ThCh$	ThCh$
94.271.000-3	Enel Américas S.A.	Chile	Common Inmediate Parent	Provision of administration services and others	5,632,424	5,021,265	4,748,244
76.418.940-K	GNL Chile S.A.	Chile	Associated	Gas consumption	(314,415,258)	(164,410,577)	(99,801,403)
Foreign	Enel X S.R.L.	Italy	Common Inmediate Parent	Technical Services	(5,284,971)	(3,435,918)	—
Foreign	Enel Global Services S.r.l.	Italy	Common Inmediate Parent	Engineering Services	—	(5,097,105)	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Inmediate Parent	IT Services	(2,230,293)	—	—
Foreign	Enel S.p.A.	Italy	Parent	Technical Services	(5,305,537)	(3,800,471)	(4,110,257)
Foreign	Enel Global Trading SpA.	Italy	Common Inmediate Parent	Commodity derivatives	35,815,215	(37,771,702)	(12,118,800)
Foreign	Enel Global Trading SpA.	Italy	Common Inmediate Parent	Gas Purchase	(2,618,484)	—	—
Foreign	Enel Global Trading SpA.	Italy	Common Inmediate Parent	Technical Services	(2,227,749)	(2,183,183)	(1,634,832)
Foreign	Enel Global Trading SpA.	Italy	Common Inmediate Parent	Gas Sales	—	—	58,352,346
Foreign	Enel Finance International NV	Netherlands	Common Inmediate Parent	Financial expenses	(42,040,047)	(35,079,947)	(31,328,749)
Foreign	Enel Italia S.r.l.	Italy	Common Inmediate Parent	IT Services	—	—	(2,699,915)
Foreign	Enel Italia S.r.l.	Italy	Common Inmediate Parent	Technical Services	—	—	(3,139,990)
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Inmediate Parent	Technical Services	—	(3,172,872)	—
Foreign	Enel Green Power SpA	Italy	Common Inmediate Parent	Engineering Services	—	(7,263,535)	—
Foreign	Enel Green Power SpA	Italy	Common Inmediate Parent	Technical Services	(7,861,111)	(4,674,437)	(3,898,762)
76.802.924-3	Energía y Servicios South America SpA	Chile	Common Inmediate Parent	IT Services	—	(2,128,624)	—

The transactions detailed in the preceding table correspond to all those that exceed Ch$2,000 million, by counterparty and nature of the transactions

d) Significant transactions

I. Enel Chile

• On December 21, 2018, Enel Finance International NV granted a revolving credit facility in USD to Enel Chile 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. During the availability period, Enel Chile will pay an annual availability commission equivalent to 35% of the margin over the non-withdrawn amount. On June 3 and 18, 2019, Enel Chile withdrew the total amount of the line of credit. This revolving credit is unsecured, corresponds to a bullet maturity loan, and the principal and interest may 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 ten days prior to the prepayment date. Enel Chile will not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2021 amounted to US$400 million, equivalent to ThCh$337,876,000 (ThCh$284,380,000 as of December 31, 2020), and does not include accrued interest because the payment of these was made at the end of the fiscal year.

Note that, in line with our financing strategy and based on that established in our industrial plan, the Company is assessing the best alternative to refinance the maturity with several market players, including Enel Finance International NV, which have shown interest in participating in this transaction.

• In June 2019, Enel Chile 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 June 24, 2024. During the availability period, Enel Chile 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 may require renewal of a withdrawal, by sending a letter at least five business days prior to the due date of the obligation. On September 15, 2021, this facility was drawn upon in its entirety for a period of 3M, maturing in December 2021 and renewed again for another 3M period, accordingly, as of December 31, 2021, it has been drawn upon for US$50 million, equivalent to ThCh$42,234,500. Based on its

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revolving nature, at maturity, the decision will be made to renew or pay, but this decision may not be extended beyond the maturity date of the facility. As of December 31, 2021, accrued interest amounts to ThCh$20,700.

• On January 3, 2020, Enel Finance International NV granted a loan in USD to Enel Chile 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 is unsecured, corresponds to a bullet loan, and the principal and interest may 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, at least ten days prior to the prepayment date. Enel Chile will not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2021 was US$200 million, equivalent to ThCh$168,938,000 (ThCh$142,190,000 as of December 31, 2020). As of December 31, 2021, accrued interest amounts to ThCh$12,101 (ThCh$0 as of December 31, 2020).

• On March 11, 2020, Enel Finance International NV granted a loan in USD to Enel Chile 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 is unsecured, corresponds to a bullet loan, and the principal and interest may 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 at least ten days prior to the prepayment date. Enel Chile will not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2021 was US$400 million, equivalent to ThCh$337,876,000 (ThCh$284,380,000 as of December 31, 2020). As of December 31, 2021, accrued interest amounts to ThCh$3,468,860 (ThCh$2,893,567 as of December 31, 2020).

• On June 15, 2020, Enel Chile 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 will pay an annual availability commission equivalent to 0.35% 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 may require renewal of a withdrawal, by sending a letter at least five business days prior to the due date of the obligation. On April 1, 2021 this credit facility was closed in advance, paying the corresponding commitment fee. As of December 31, 2021, this credit facility was not available.

• On April 1, 2021, Enel Chile secured an SDG-Linked loan of US$300 million from Enel Finance International N.V. This loan has a fixed interest rate of 2.50% (which is subject to compliance with a reduction of greenhouse gas emissions (CO2) until December 2023), semi-annual payments and matures on April 1, 2031. It is a bullet loan that has no guarantees, and may be partially or totally prepaid in advance (principal and interest) without any penalty other than the “costs of failure”; by submitting a prepayment request to Enel Finance International NV thirty days prior to the prepayment date. As of December 31, 2021, the outstanding balance of this loan was US$300 million, equivalent to ThCh$253,407,000. As of December 31, 2021, accrued interest amounts to ThCh$1,601,391.

• On April 1, 2021, Enel Chile S.A. secured a SDG-Linked revolving committed credit facility from Enel Finance International N.V. for US$ 290 million. This credit facility has a variable interest rate of LIBOR 1M, 3M or 6M + 1.00% spread, which is indexed to compliance with a reduction of greenhouse gas emissions to December 2023, with monthly, quarterly, or semi-annual interest payments and maturing on April 1, 2026. During the effective period of the credit facility, Enel Chile S.A. will pay an annual availability commission equal to 0.35% of the margin on the undrawn amount. This revolving credit facility has no guarantees and can be partially or totally prepaid in advance (principal and interest) along with any other costs under the agreement. Enel Chile S.A. has the right to renew a draw by sending a letter five (5) business days before expiration of the obligation. On May 4, 2021, a first draw was made for US$ 100 million. On July 6, 2021, a second draw was made for US$ 100 million. On September 15, 2021, a third withdrawal was made for US$ 90 million. At the time of each draw, the interest period is defined at 1M, 3M or 6M renewable through the maturity of the facility. As of December 31,

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2021, the credit facility remains at US$ 290 million, equivalent to ThCh$ 244,960,100 (of which $100 million mature on March 3, 2022, US$90 million on March 15, 2022 and US$ 100 million on July 6, 2022). Because this is a revolving credit facility, at the maturity of each draw its renewal or payment will be decided upon, which cannot be extended beyond the maturity date of the facility. As of December 31, 2021, accrued interest amounts to ThCh$ 345,148.

• On June 30, 2021, the debt previously held by Enel Green Power S.A. was transferred to Enel Chile (see the next paragraph) under the following conditions: the debt has been refinanced by Enel Finance International NV for US$ 644 million, at a fixed interest rate of 2.82% per annum, with semi-annual interest payment (beginning on June 30, 2024) maturing on December 31, 2027, by virtue of an addendum to a debt agreement belonging to Enel Green Power S.A. This debt can be voluntarily prepaid, including “breakage costs.” As of December 31, 2021, the outstanding balance of this debt was US$ 644 million, equivalent to ThCh$ 544,294,079 (US$ 644 million as of December 31, 2020, equivalent to ThCh$ 458,115,848). As of December 31, 2021, this debt does not record accrued interest because its payment was made at year-end.

• On September 30, 2021, Enel Chile S.A. formalized an SDG-Linked revolving committed credit facility from Enel Finance International N.V. for US$ 200 million. This credit line has a variable interest rate of LIBOR 1M, 3M or 6M + 1.15% margin (structured so that the interest rate relates to compliance with a reduction in the ratio of greenhouse effect gas emissions as at December 2023), with monthly, quarterly, or semi-annual interest payments, and matures on September 30, 2025. During the effective period of the credit facility, Enel Chile S.A. will pay an annual availability commission equal to 0.30% of the margin on the undrawn amount. This revolving credit facility has no guarantees and can be partially or fully prepaid (principal and interest) along with any other costs under the agreement. Enel Chile S.A. has the right to renew withdrawals by sending a letter five (5) business days before the obligation expires. On October 8, 2021, the first draw was made for US$ 100 million, and the second on October 14, 2021, for US$ 100 million. As of December 31, 2021, this facility has been drawn upon for US$200 million, equivalent to ThCh$168,938,000, of which US$ 100 million matures on July 7, 2022 and the other US$100 million matures on July 14, 2022. Based on its revolving nature, at the maturity of each draw, the decision will be made to renew or pay, but this decision may not be extended beyond the maturity date of the credit facility. As of December 31, 2021, accrued interest amounts to ThCh$484,764.

9.2 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 Board of Directors in office as of December 31, 2021, was elected at the Ordinary Shareholders’ Meeting held on April 28, 2021, and comprises the following people:

• Mr. Herman Chadwick Piñera

• Mrs. Mónica Girardi

• Mrs. Isabella Alessio

• Mr. Salvatore Bernabei

• Mr. Fernán Gazmuri Plaza

• Mr. Pablo Cabrera Gaete

• Mr. Luis Gonzalo Palacios Vásquez

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At the Ordinary Board Meeting held on April 28, 2021, Mr. Hermán Chadwick Piñera was elected as Chairman of the Board and Mr. Domingo Valdés Prieto as Secretary of the Board.

The Directors’ Committee was also appointed during the same Board Meeting, which is governed by Law No. 18,046 (the Chilean Corporations Law), and the Sarbanes-Oxley Act. This Committee comprises the Directors Mr. Fernán Gazmuri Plaza, Mr. Pablo Cabrera Gaete and Mr. Luis Gonzalo Palacios Vásquez. All the members of the Committee are independent Directors, in accordance with the provisions of Circular No. 1,956 issued by the CMF.

The Board of Directors has appointed Mr. Fernán Gazmuri Plaza as financial expert of Enel Chile’s Directors’ Committee. The Company’s Directors’ Committee has appointed Mr. Fernán Gazmuri Plaza as Chairman of the aforementioned corporate body and Mr. Domingo Valdés Prieto as its Secretary.

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) Guarantees given by the Company in favor of the directors

No guarantees have been given to the Directors.

c) Compensation for directors

In accordance with Article 33 of Law No. 18,046 (Chilean Corporations Law), governing stock corporations, the compensation of Directors is established each year at the General Shareholders Meeting of Enel Chile.

A monthly compensation, 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 compensation 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 compensation 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 affiliates, 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 of 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.

F-72

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.

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, 2021, 2020 and 2019:

				December 31, 2021
				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 2021	216,204	—	—
Foreign	Giulio Fazio	Director	January - March 2021	—	—	—
4.461.192-9	Fernán Gazmuri Plaza	Director	January - December 2021	105,796	—	34,466
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2021	108,102	—	36,028
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - March 2021	25,910	—	8,637
5.545.086-2	Luis Gonzalo Palacios Vasquez	Director	April - December 2021	76,460	—	25,481
Foreign	Monica Girardi	Director	April - December 2021	—	—	—
Foreign	Isabella Alessio	Director	April - December 2021	—	—	—
Foreign	Daniele Caprini	Director	January - March 2021	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2021	—	—	—
			Total	532,472	—	104,612

				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	—	34,663
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2020	103,959	—	34,663
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2020	103,959	—	34,663
Foreign	Daniele Caprini	Director	January - December 2020	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2020	—	—	—
			Total	519,795	—	103,989

				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

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9.3 Compensation of key management personnel

Enel Chile’s key management personnel as of December 31, 2021 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 Administration, Finance and Control Officer, replacing Mr. Marcelo Antonio de Jesús.

(2) On March 1, 2020, Mr. Eugenio Belinchon Gueto was appointed Internal Audit Manager, replacing Mr. Raffaele Cutrignelli.

9.4 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 as of December 31, 2021, 2020 and 2019 was as follows:

	December 31, 2021	December 31, 2020	December 31, 2019
	ThCh$	ThCh$	ThCh$
Remuneration	2,060,928	2,133,063	2,357,252
Short-term benefits for employees	260,400	272,714	207,391
Other long-term benefits - IAS	38,713	146,404	2,088
Total	2,360,041	2,552,181	2,566,731

a) Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

9.5 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 common stock.

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10.  INVENTORY

The detail of inventories as of December 31, 2021 and 2020, is as follows:

	As of December 31,
	2021	2020
Classes of Inventories	ThCh$	ThCh$
Supplies for Production	6,130,065	5,207,472
Gas	2,764,539	2,280,335
Oil	3,365,526	2,927,137
Supplies for projects and spare parts	22,131,301	13,468,592
Electrical materials	2,986,344	4,633,965
Total	31,247,710	23,310,029

There are no inventories acting as security for liabilities.

For the years ended December 31, 2021, 2020 and 2019, raw materials and inputs recognized as fuel cost was ThCh$ 374,868,794, ThCh$ 231,176,489 and ThCh$ 230,944,415, respectively. See Note 28.

At the end of 2021, ThCh$46,572,145 impairment adjustments were recorded to coal and diesel oil inventories related to the discontinuity of the Bocamina II plant. For this same reason, at the end of 2020, an impairment of coal and diesel oil inventories was recorded for ThCh$21,574,783. For further information on Bocamina II impairment effects see Note 15.c.iv; and for information on the effects of impairment of raw materials and consumables, see Note 28.

11.   CURRENT TAX ASSETS AND LIABILITIES

a) The detail of current tax receivables as of December 31, 2021 and 2020, is as follows:

	As of December 31,
	2021	2020
Tax Receivables	ThCh$	ThCh$
Advance income tax payments	51,691,573	34,534,731
Credit for adsorbed tax profits	59,372,737	—
Tax credit for training expenses	472,706	503,682
Total	111,537,016	35,038,413

b) The detail of current tax payables as of December 31, 2021 and 2020, is as follows:

	As of December 31,
	2021	2020
Current tax liabilities	ThCh$	ThCh$
Income tax	13,148,707	72,359,944
Total	13,148,707	72,359,944

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12.   INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

12.1. Investments accounted for using the equity method

The detail of the Group’s investees accounted for using the equity method and the movements for the years ended December 31, 2021 and 2020, 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	1-1-2021	Additions	(Loss)	Declared	Translation	Income	(Decrease)	12-31-2021	Equity	12-31-2021
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%	1,729,383	—	3,620,701	(381,860)	738,412	—	—	5,706,636	—	5,706,636
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (*)	Joint Business	Chile	Chilean Peso	0.00%	7,451,193	—	(292,529)	(5,360,886)	—	—	(1,797,778)	—	—	—
76.014.570-K	Enel Argentina S.A.	Associate	Argentina	Argentine Peso	0.0793%	370,563	—	(108,016)	(66,360)	(5,706)	—	196,654	387,135	—	387,135
76.364.085-K	Energías Marina SpA	Associate	Chile	Chilean Peso	25.00%	—	57,357	(62,484)	—	—	—	—	(5,127)	5,127	—
77.157.779-2	Enel X AMPCI Ebus Chile SpA	Associate	Chile	U.S. dollar	20.00%	3,441,664	—	19,737	(670,700)	678,387	359,797	—	3,828,885	—	3,828,885
77.374.847-0	HIF H2 SpA	Joint Business	Chile	U.S. dollar	50.00%	—	1,277	—	—	—	—	—	1,277	—	1,277
					TOTAL	12,992,803	58,634	3,177,409	(6,479,806)	1,411,093	359,797	(1,601,124)	9,918,806	5,127	9,923,933

								Share of		Foreign	Other	Other	Balance as	Negative	Balance as
						Balance as of		Profit	Dividends	Currency	Comprehensive	Increase	of	Equity	of
Taxpayer ID					Ownership	1-1-2020	Additions	(Loss)	Declared	Translation	Income	(Decrease)	12-31-2020	Provision	12-31-2020
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%	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 Business	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	Argentine Peso	0.08%	401,908	—	15,333	—	(130,962)	—	84,284	370,563	—	370,563
76.364.085-K	Energías Marina SpA	Associate	Chile	Chilean Peso	25.00%	17,246	—	(70,360)	—	—	—	—	(53,114)	53,114	—
77.157.779-2	Enel X 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

(*) See Note 12.3.a).

12.2. Additional financial information on investments in associates

Financial information as of December 31, 2021 and 2020 of the main companies in which the Group exercises significant influence is detailed below:

	As of December 31, 2021
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A.	33.33%	135,535,995	1,551,052,079	204,485,491	1,464,982,676	1,025,300,274	10,862,103	2,215,243	13,077,346
Enel X AMPCI Ebus Chile SpA	20.00%	15,011,284	105,903,882	13,781,434	87,989,309	—	98,684	5,190,928	5,289,612

	As of December 31, 2020
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	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	3,381,935	(366,207)	3,015,728
Enel X AMPCI Ebus Chile SpA	20.00%	20,007,409	93,871,600	15,101,345	81,569,344	7,503,692	5,425,709	—	5,425,709

None of the Company’s associates have issued price quotations.

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12.3. Joint ventures

The detail of the Group’s statements of financial position and statements of income of joint ventures for the years ended December 31, 2021 and 2020, are as follows:

a) Transmisora Eléctrica de Quillota Ltda.:

	Transmisora Eléctrica
	de Quillota Ltda.
	50.0% (1)	50.0%
	12-31-2021	12-31-2020
	ThCh$	ThCh$
Total current assets	—	7,157,805
Total non-current assets	—	10,068,936
Total current liabilities	—	806,841
Total non-current liabilities	—	1,517,515
Cash and cash equivalents	—	4,261,166
Revenues	896,616	4,643,283
Other fixed operating expenses	(239,154)	(268,806)
Depreciation and amortization expense	(824,314)	(782,799)
Other Income	25,735	4,187
Interest income	61,769	29,103
Income tax expense	(505,710)	(921,039)
Profit (loss)	(585,058)	2,703,929
Comprehensive income	(585,058)	2,703,929

(1) On December 30, 2021, the Company sold its 50% equity interest in Transmisora Eléctrica de Quillota Ltda. (see Note 2, section 1.6) for US$13,862,707, equivalent to ThCh$11,786,767, resulting in a profit of ThCh$9,968,845, which is included in Other profits (losses) of the consolidated statement of income (See Note 32).

b) HIF H2 SpA.:

	HIF H2 SpA
%	50%
	12-31-2021
	ThCh$
Total Current Assets	4,008,576
Total non-current liabilities	4,006,021
Cash and cash equivalents	2,555

There are no significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.

13.  INTANGIBLE ASSETS OTHER THAN GOODWILL

The balances of this caption as of December 31, 2021 and 2020 are presented below:

	As of December 31,
	2021	2020
Intangible Assets, Gross	ThCh$	ThCh$
Intangible Assets, Gross	317,349,834	275,527,801
Easements and water rights	22,169,638	20,551,471
Concessions	68,707,575	53,053,457
Patents, Registered Trademarks and Other Rights	1,560,467	679,227
Computer software	215,606,140	186,855,438
Other identifiable intangible assets	9,306,014	14,388,208

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	As of December 31,
	2021	2020
Intangible Assets, Amortization and Impairment	ThCh$	ThCh$
Accumulated Amortization and Impairment, Total	(126,128,279)	(110,413,280)
Easements and water rights	(6,203,360)	(5,519,394)
Concessions	(13,306,986)	(9,469,344)
Patents, Registered Trademarks and Other Rights	(502,432)	(478,232)
Computer software	(103,254,572)	(92,187,254)
Other identifiable intangible assets	(2,860,929)	(2,759,056)

	As of December 31,
	2021	2020
Intangible Assets, Net	ThCh$	ThCh$
Intangible Assets, Net	191,221,555	165,114,521
Easements and water rights	15,966,278	15,032,077
Concessions	55,400,589	43,584,113
Patents, Registered Trademarks and Other Rights	1,058,035	200,995
Computer software	112,351,568	94,668,184
Other identifiable intangible assets	6,445,085	11,629,152

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The following table presents intangible assets other than Goodwill as of December 31, 2021 and 2020:

	Easements and water rights	Concessions	​ Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangibles Assets, Net
Movements in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2021	15,032,077	43,584,113	200,995	94,668,184	11,629,152	165,114,521
Movements in identifiable intangible assets
Increases other than from business combinations	—	—	—	26,651,901	—	26,651,901
Increase (decrease) from foreign currency translation differences	872,636	8,594,987	—	781,819	1,435,762	11,685,204
Amortization (1)	-	(1,841,472)	(24,200)	(10,361,635)	—	(12,227,307)
Increases (decreases) from transfers and other Movements	61,565	5,062,961	881,240	614,323	(6,620,089)	—
Increases (decreases) from transfers	61,565	5,062,961	881,240	614,323	(6,620,089)	—
Argentina Hyperinflation Effect	—	—	—	—	260	260
Other increases (decreases)	—	—	—	(3,024)	—	(3,024)
Total Movements in identifiable intangible assets	934,201	11,816,476	857,040	17,683,384	(5,184,067)	26,107,034
Closing balance as of December 31, 2021	15,966,278	55,400,589	1,058,035	112,351,568	6,445,085	191,221,555

	Easements and water rights	Concessions	​ Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangibles Assets, Net
Movements 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
Movements 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	—	(217,658)	—	—	—	(217,658)
Increases (decreases) from transfers and other Movements	91,775	—	(91,775)	(1,067)	1,067	—
Increases (decreases) from transfers	91,775	—	(91,775)	(1,067)	1,067	—
Dispositions and removal from service	(1,616,582)	—	—	—	—	(1,616,582)
Dispositions	(1,616,582)	—	—	—	—	(1,616,582)
Argentina Hyperinflation Effect	—	—	—	—	142	142
Increase (decrease)	—	—	—	(1,557,129)	—	(1,557,129)
Total Movements 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

(1) See Note 30 a).

No impairment losses have been recognized as of December 31, 2021 and 2020. 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, 2021 (see Note 3. e).

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14.  GOODWILL

The following table sets forth goodwill by cash-generating unit or group of cash-generating units and changes for the years ended December 31, 2021 and 2020:

		Opening Balance 01-01-2020	Foreign Currency Translation	Closing Balance 12-31-2020	Transfer	Foreign Currency Translation	Closing Balance 12-31-2021
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	(37,912,005)	—	90,462,357
Enel Transmisión Chile S.A.	Enel Transmisión Chile	—	—	—	37,912,005	—	37,912,005
Enel Generación Chile S.A.	Generación Chile	756,642,815	—	756,642,815	—	—	756,642,815
Almeyda Solar SpA	Enel Green Power Chile	21,820,403	(1,194,585)	20,625,818	(20,625,818)	—	—
Enel Green Power Chile S.A.	Enel Green Power Chile	—	—	—	20,625,818	3,895,532	24,521,350
Geotérmica del Norte	Enel Green Power Chile	81,930	(4,485)	77,445	—	14,627	92,072
Parque Eólico Talinay Oriente	Enel Green Power Chile	8,192,986	(448,535)	7,744,451	—	1,462,670	9,207,121
	Total	917,352,974	(1,647,605)	915,705,369	—	5,372,829	921,078,198

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, 2021 and 2020 (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.

2. Enel Distribución Chile S.A.

On November 2000, Enersis S.A. (currently Enel Américas S.A.) acquired through a public tender offer, an additional ownership interest of 25.4% in Enel Distribución Chile S.A., reaching 99.99% ownership.

3. Enel Transmisión Chile S.A.

Enel Transmisión Chile S.A. was spun-off from Enel Distribución Chile S.A. on January 1, 2021. As a result, the assets and liabilities associated with the transmission business that belonged to Enel Distribución Chile S.A. were assigned to Enel Transmisión Chile S.A. to engage in the transmission business. The division process was carried out to comply with requirements related to the exclusive distribution business, in accordance with the latest amendments to Executive Order No. 4/2016 of the Ministry of Economy, Development and Reconstruction. Enel Chile maintained a goodwill arising from the Cash-Generation Unit (CGU) of Enel Distribución Chile S.A. until December 31, 2020. However, as a result of these new regulations and the emergence of a new CGU in the transmission business in 2020, a redistribution of this goodwill was carried out using the value in use method as of December 21, 2020 as reference.

4. 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.) achieving 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. The resulting goodwill was recognized in Enel Generación Chile S.A.

4.1 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.

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4.2.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.

4.3. 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.

5. 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.

In addition, on August 6, 2001, Enel Green Power Chile S.A. acquired interests in the companies Empresa Eléctrica Panguipulli S.A. and Empresa Eléctrica Puyehue S.A., which subsequently merged by absorption of Puyehue into Panguipulli and the latter became the legal successor company. On July 1, 2020, Empresa Eléctrica Panguipulli S.A. was absorbed by Parque Eólico Taltal SpA and the latter became the legal successor company. On August 1, 2020, Parque Eólico Taltal SpA merged with Almeyda Solar SpA and the latter became the legal successor. Finally, on January 1, 2021, Almeyda Solar SpA merged with Enel Green Power Chile S.A. and the latter became the legal successor company.

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15.  PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2021 and 2020:

	As of December 31,
	2021	2020
Classes of Property, Plant and Equipment, Gross	ThCh$	ThCh$
Property, Plant and Equipment, Gross	11,142,172,107	9,768,708,590
Construction in progress	2,404,299,833	1,567,685,720
Land	78,715,479	78,366,909
Buildings	655,780,937	562,807,945
Generation Plant and Equipment	6,300,566,056	5,992,384,131
Network infraestructure	1,488,114,938	1,378,810,834
Fixtures and fittings	194,179,535	171,396,847
Other property, plant and equipment	20,515,329	17,256,204

	As of December 31,
	2021	2020
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment	ThCh$	ThCh$
Total Accumulated Depreciation and Impairment in Property, Plant and Equipment	(5,031,483,346)	(4,735,212,118)
Buildings	(185,002,401)	(144,646,529)
Plant and equipment	(4,086,507,212)	(3,871,912,436)
Network infraestructure	(614,017,141)	(584,630,846)
Fixtures and fittings	(126,246,469)	(117,944,385)
Other property, plant and equipment	(19,710,123)	(16,077,922)

	As of December 31,
	2021	2020
Classes of Property, Plant and Equipment, Net	ThCh$	ThCh$
Property, Plant and Equipment, Net	6,110,688,761	5,033,496,472
Construction in progress	2,404,299,833	1,567,685,720
Land	78,715,479	78,366,909
Buildings	470,778,536	418,161,416
Generation Plant and Equipment	2,214,058,844	2,120,471,695
Network infraestructure	874,097,797	794,179,988
Fixtures and fittings	67,933,066	53,452,462
Other property, plant and equipment	805,206	1,178,282

The composition and movements of the property, plant and equipment accounts during the fiscal year ended December 31, 2021 and 2020 are as follows:

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	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
Movements in 2021	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2021	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
Increases other than from business combinations	894,031,403	—	366,432	1,429,573	2,016,740	615,804	—	898,459,952
Increases (decreases) from foreign currency translation differences	167,710,277	118,312	62,905,635	174,366,572	9,145,223	268,274	162,162	414,676,455
Depreciation (1)	—	—	(20,084,630)	(128,647,891)	(38,770,418)	(6,725,834)	(535,238)	(194,764,011)
Impairment losses recognized in profit or loss for the period (2)	(28,773,082)	—	(4,262,649)	—	—	—	—	(33,035,731)
Increases (decreases) from transfers and other movements	(180,007,066)	167,714	17,268,849	32,926,796	109,860,379	19,783,328	—	—
Increases (decreases) from transfers from construction in progress	(180,007,066)	167,714	17,268,849	32,926,796	109,860,379	19,783,328	—	—
Disposals and removals from service	(230,675)	—	(577)	(1,464,759)	(895,689)	—	—	(2,591,700)
Disposals	(230,675)	—	(577)	(1,464,759)	(895,689)	—	—	(2,591,700)
Other increases (decreases) (3)	(16,306,942)	(2,182)	(3,675,456)	14,194,951	(1,438,426)	223,672	—	(7,004,383)
Argentine hyperinflationary economy	190,198	64,726	99,516	781,907	—	315,360	—	1,451,707
Total movements	836,614,113	348,570	52,617,120	93,587,149	79,917,809	14,480,604	(373,076)	1,077,192,289
Closing balance as of December 31, 2021	2,404,299,833	78,715,479	470,778,536	2,214,058,844	874,097,797	67,933,066	805,206	6,110,688,761

	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
Movements 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 movements	(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 movements	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

(1) See Note 30.

(2) See clause iv) in section c) other information, contained in this same Note.

(3) See Note 24.

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 and operating plants and new projects under construction. These investments totaled ThCh$ 2,404,299,833 and ThCh$ 1,567,685,720 as of December 31, 2021 and 2020, respectively.    

In the distribution segment, the main investments are improvements in networks to optimize their operation, in order to enhance efficiency and quality of service level. These investments totaled ThCh$131,899,846 and ThCh$148,835,155 as of December 31, 2021 and 2020, respectively.

In the generation segment, investments include works towards the new capacity program. This includes:

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(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$790,358,312 and ThCh$637,303,224, as of December 31, 2021 and 2020, 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$1,092,094,271 and ThCh$436,164,981, as of December 31, 2021 and 2020, 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$1,675,012,361 and ThCh$780,827,755, as of December 31, 2021 and 2020.

b) Capitalized cost

b.1) Capitalized financial expenses in works in progress

The capitalized cost for financial expenses amounted to ThCh$61,513,684 as of December 31, 2021, (ThCh $33,109,819 and ThCh $9,321,354 as of December 31, 2020 and 2019, respectively) (see Note 32). The average financing rate ranged between 6.86% and 7.39% as of December 31, 2021 (4.60% and 6.84% as of December 31, 2020 and 2019, respectively).

The increase in interest capitalization evidenced during 2021 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. 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 project during the previous years, an update of the project schedule provided by Enel Generación Chile on July 27, 2020, estimates 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 to constructions in progress was ThCh$31,157,196, ThCh$25,539,316 and ThCh$17,610,861 as of December 31, 2021, 2020 and 2019, respectively.

The increase in the capitalization of interest and personnel expenses compared to 2020 and 2019 is mainly due to a greater development of non-conventional renewable energy projects.

c) Other information

(i) As of December 31, 2021 and 2020, the Group maintained commitments to acquire tangible fixed assets in the amount of ThCh$119,301,305 and ThCh$303,709,257, respectively.

(ii) As of December 31, 2021 and 2020, Enel Chile had no property, plant or 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$964,590,000), 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 €400 million (ThCh$385,836,000) in case these claims are due to the rupture of any dams owned by the Company or its subsidiaries, as well as environmental civil liability to cover environmental damage claims up to €20 million (ThCh$19,291,800). The premiums associated with these policies are recorded proportionally to each company in the caption prepaid expenses.

(iv) Decarbonization plan

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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 I and Tarapacá, respectively, from the National Electricity System, establishing their deadlines on 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 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 on 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.

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.

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On July 3, 2020, the CNE issued Exempt Resolution No. 237 authorizing the final withdrawal, disconnection, and termination of operations of Bocamina I on 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. Additionally, for this same reason, during fiscal year 2021 the Group recorded an additional impairment loss of ThCh$28,773,083. 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 18.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, and which finalized during the first half of 2021.

(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 dispositions amounting to ThCh$1,880,608 occurred. Both concepts total ThCh$3,510,591, see Note 31.

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16.  INVESTMENT PROPERTY

The investment property breakdown and activity during 2021 and 2020 are detailed as follows:

	Investment Properties, Gross	Accumulated Depreciation, Amortization and Impairment	Investment Properties, Net
Investment Property, Net, Cost Model	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2020	9,189,377	(2,394,222)	6,795,155
Depreciation expense	-	(19,812)	(19,812)
Reversals of value impairment loss recognized in the income statement	-	646,597	646,597
Balance as of December 31, 2020	9,189,377	(1,767,437)	7,421,940
Depreciation expense	-	(19,812)	(19,812)
Reversals of value impairment recognized in the income statement	-	136,877	136,877
Balance as of December 31, 2021	9,189,377	(1,650,372)	7,539,005

During 2021 and 2020, no real estate property has been sold.

- Fair value measurement and hierarchy

As of December 31, 2021 and 2020, the fair value of the investment was ThCh$8,856,391 and ThCh$8,484,901 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, 2021
	Level 1	Level 2	Level 3
	ThCh$	ThCh$	ThCh$
Investment properties	—	—	8,856,391

See Note 3.h.

The revenue and expenses derived from investment properties for the years ended December 31, 2021, 2020 and 2019, are detailed as follows:

	2021	2020	2019
Income and expense from investment properties	ThCh$	ThCh$	ThCh$
Income derived from rental income from investment properties	204,483	196,955	202,896
Direct operating expenses from investment properties that generate rental income	(39,727)	(36,761)	(44,136)
Total	164,756	160,194	158,760

There are no contracts for repairs, maintenance, acquisition, construction, or development which represent future obligations for the Group as of December 31, 2021 and 2020.

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.

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17.  RIGHT-OF-USE-ASSETS

Right-of-use assets for the years ended December 31, 2021 and 2020, are detailed as follows:

	Land	Other Plants and equipment	Right-of-use assets, Net
Movements in 2021	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2021	33,587,391	21,914,801	55,502,192
New assets contracts, by right-of use	97,937,192	—	97,937,192
Increases (decreases) from foreign currency translation differences, net	11,766,090	407,407	12,173,497
Depreciation	(1,794,208)	(2,122,318)	(3,916,526)
Other increases (decreases)	(907,494)	—	(907,494)
Total movements	107,001,580	(1,714,911)	105,286,669
Closing balance as of December 31, 2021	140,588,971	20,199,890	160,788,861
	Land	Other Plants and equipment	Right-of-use assets, Net
Movements 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)
Other increases (decreases)	356,444	(356,444)	-
Total movements	(494,408)	153,090	(341,318)
Closing balance as of December 31, 2020	33,587,391	21,914,801	55,502,192

As of December 31, 2021 and 2020, 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 to land lease contracts for the development of non-conventional renewable energy projects in the EGP Chile Group.

The present value of future payments derived from those contracts is detailed as follows:

	As of December 31,
	2021			2020
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	14,282,203	3,177,185	11,105,018	8,783,640	1,775,929	7,007,711
From one to two years	13,303,170	2,903,458	10,399,712	6,583,269	1,546,496	5,036,773
From two to three years	7,228,546	2,794,604	4,433,942	8,399,111	1,332,024	7,067,087
From three to four years	7,018,180	2,690,733	4,327,447	3,271,835	1,245,169	2,026,666
From four to five years	6,916,077	2,590,412	4,325,665	3,077,572	1,174,438	1,903,134
More than five years	160,449,882	35,379,589	125,070,293	37,595,016	8,770,869	28,824,147
Total	209,198,058	49,535,981	159,662,077	67,710,443	15,844,925	51,865,518

a) Short-term and low-value leases

The consolidated income statement for the years ended December 31, 2021, 2020 and 2019 includes expenses in the amounts of ThCh$3,790,971 and ThCh$4,958,760 and ThCh$3,824,195 respectively, of which ThCh$3,129,893 correspond to short-term lease payments in 2021 (ThCh$3,334,241 in 2020 and ThCh$1,995,392 in 2019); while ThCh$661,078 relate to leases with variable payment clauses in 2021 (ThCh$1,624,519 in 2020 and ThCh$1,828,803 in 2019), which are exempt from the application of IFRS 16 (see Note 3.f).

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As of December 31, 2021 and 2020, future payments derived from those contracts are detailed as follows:

	As of December 31,	As of December 31,
	2021	2020
	ThCh$	ThCh$
Less than one year	2,797,608	4,813,265
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	2,797,608	4,813,265

18.  INCOME TAX AND DEFERRED TAXES

a) Income taxes

The following are the components of income tax recorded in the consolidated statements of comprehensive income for the years 2021, 2020 and 2019:

	2021	2020	2019
Current Income Tax and Adjustments to Current Income Tax for Previous Periods	ThCh$	ThCh$	ThCh$
Current income tax	28,269,648	(155,196,656)	(54,904,679)
Adjustments to current tax from the previous period	(773,163)	3,694,656	(2,251,167)
Current tax (expenses) / benefit (related to cash flow hedges)	(109,882,227)	72,354,119	(36,172,878)
Other current tax benefit / (expense)	—	(98,646)	(1,197,052)
Current tax expense, net	(82,385,742)	(79,246,527)	(94,525,776)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	67,247,084	160,551,634	33,297,872
Total deferred tax benefit / (expense)	67,247,084	160,551,634	33,297,872
Income tax expense	(15,138,658)	81,305,107	(61,227,904)

The following table shows the reconciliation of the tax rate as of December 31, 2021, 2020 and 2019:

		2021		2020		2019
Reconciliation of Tax Expense	Tax Rate	ThCh$	Tax Rate	ThCh$	Tax Rate	ThCh$
ACCOUNTING INCOME BEFORE TAX		115,848,792		(133,691,942)		377,321,122
Total tax income (expense) using statutory rate	(27.00)%	(31,279,174)	27.00%	36,096,825	(27.00)%	(101,876,703)
Tax effect of rates applied in other countries	0.08%	96,520	0.04%	55,915	0.06%	232,897
Tax effect of tax-exempt revenue and other positive effects impacting the effective rate	2.53%	2,931,159	31.79%	42,501,879	11.30%	42,638,986
Tax effect of non-deductible expenses for determining taxable profit (loss)	(10.49)%	(12,156,154)	(7.32)%	(9,790,603)	(2.76)%	(10,399,776)
Tax effect of adjustments to income taxes in previous periods	(0.67)%	(773,163)	2.76%	3,694,656	(0.60)%	(2,251,167)
Price level restatement for tax purposes (investments and equity)	22.48%	26,042,154	6.54%	8,746,435	2.76%	10,427,859
Total adjustments to tax expense using statutory rate	13.93%	16,140,516	33.82%	45,208,282	10.77%	40,648,799
Income tax benefit (expense)	(13.07)%	(15,138,658)	60.82%	81,305,107	(16.23)%	(61,227,904)

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, 2021 and 2020 are as follows:

	12-31-2021		12-31-2020
	Assets	Liabilities	Assets	Liabilities
Deferred Taxes Assets/(Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$
Depreciation	79,595,812	(297,814,005)	55,197,762	(249,821,145)
Obligations for post-employment benefits	6,221,900	(65,201)	9,581,174	(5,997)
Tax loss	116,355,816	—	46,518,690	—
Provisions	104,211,997	—	91,579,562	—
Decommissioning Provision	50,001,807	—	51,513,634	—
Provision for Civil Contingencies	1,946,340	—	3,991,087	—
Provision for doubtful trade accounts	9,362,865	—	12,544,171	—
Provision of Human Resources accounts	11,902,160	—	8,605,410	—
Other Provisions	30,998,825	—	14,925,260	—
Other Deferred Taxes	19,147,266	(45,369,799)	24,942,402	(38,036,065)
Activation of expenses for issuance of financial debt	—	(11,282,929)	—	(10,691,535)
Gain from Bargain Purchase for Tax Purposes	—	(10,177,907)	—	—
Price-level Adjustment - Argentina	—	(2,160,549)	—	(1,015,095)
Other Deferred Taxes	19,147,266	(21,748,414)	24,942,402	(26,329,435)
Deferred taxes Assets/(Liabilities) before compensation	325,532,791	(343,249,005)	227,819,590	(287,863,207)
Compensation deferred taxes Assets/Liabilities	(145,832,055)	145,832,055	(119,805,645)	119,805,645
Deferred taxes Assets/(Liabilities) after compensation	179,700,736	(197,416,950)	108,013,945	(168,057,562)

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		Movements
Recognized in others in comprehensive income	Net balance as of January 1, 2021	Recognized in profit or loss	Recognized in others in comprehensive income	Foreign currency translation difference	Other increases (decreases)	Net balance as of December 31, 2021
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Depreciation (1)	(194,623,383)	13,724,680	—	(37,319,490)	—	(218,218,193)
Obligations for post-employment benefits	9,575,177	(48,778)	(3,387,932)	18,232	—	6,156,699
Tax loss	46,518,690	52,345,977	—	17,491,149	—	116,355,816
Provisions	91,579,562	12,215,102	—	417,333	—	104,211,997
Decommissioning Provision	51,513,634	(2,132,573)	—	620,746	—	50,001,807
Provision for Civil Contingencies	3,991,087	(2,044,747)	—	—	—	1,946,340
Provision for doubtful trade accounts	12,544,171	(3,189,704)	—	8,398	—	9,362,865
Provision of Human Resources accounts	8,605,410	3,067,041	—	229,709	—	11,902,160
Other Provisions	14,925,260	16,515,085	—	(441,520)	—	30,998,825
Other Deferred Taxes	(13,093,663)	(10,989,897)	(8)	(709,383)	(1,429,582)	(26,222,533)
Capitalization of expenses for issuance of financial debt	(10,691,535)	(591,394)	—	—	—	(11,282,929)
Gain from Bargain Purchase for Tax Purposes	—	(3,145,494)	—	(404,762)	(6,627,651)	(10,177,907)
Price-level Adjustment - Argentina	(1,015,095)	284,128	—	—	(1,429,582)	(2,160,549)
Other Deferred Taxes	(1,387,033)	(7,537,137)	(8)	(304,621)	6,627,651	(2,601,148)
Deferred taxes Assets/(Liabilities)	(60,043,617)	67,247,084	(3,387,940)	(20,102,159)	(1,429,582)	(17,716,214)

		Movements
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$
Depreciation (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
Decommissioning 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)
Price-level Adjustment - 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)

(1) See Note 15, 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.

F-91

As of December 31, 2021, the Group has accounted for all deferred tax assets associated with its tax losses. The Group has not recognized deferred tax assets related to tax loss carry forwards of ThCh$4,551,790 as of December 31, 2020, (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, 2021, amounts to ThCh$1,232,849,769 (ThCh$1,317,729,055 as of December 31, 2020). 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, 2021, such deductible temporary differences amount to ThCh$1,433,966,236 (ThCh$999,207,087 as of December 31,2020).

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 2018 to 2020.

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by tax authorities for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, the Company’s Management estimates that the liabilities, if any, that may arise from such audits, would not significantly impact the Group companies’ future results.

The effects of deferred taxes on the components of other comprehensive income attributable to both controlling and non-controlling interests for the years ended December 31 2021, 2020 and 2019 are as follows:

	2021			2020			2019
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 movements in other comprehensive income	31	(8)	23	(9,125)	2,464	(6,661)	(3,673)	992	(2,681)
Cash flow hedge	(406,971,212)	109,882,227	(297,088,985)	267,540,328	(72,741,119)	194,799,209	(139,174,121)	36,883,401	(102,290,720)
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	359,797	—	359,797	18982	—	18,982	—	—	—
Foreign currency translation	197,099,813	—	197,099,813	(69,218,245)	—	(69,218,245)	73,114,966	—	73,114,966
Actuarial gains(losses) on defined-benefit pension plans	12,547,898	(3,387,932)	9,159,966	(8,545,834)	2,308,510	(6,237,324)	(7,777,204)	2,099,845	(5,677,359)
Income tax related to components of other income and expenses with a charge or credit in equity	(196,963,673)	106,494,287	(90,469,386)	189,786,106	(70,430,145)	119,355,961	(73,840,032)	38,984,238	(34,855,794)

The following table shows the reconciliation of deferred tax movements between balance sheet and income taxes in other comprehensive income as of December 31, 2021, 2020 and 2019:

	For the years ended December 31,
	2021	2020	2019
Deferred taxes of components of other comprehensive income	ThCh$	ThCh$	ThCh$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	(3,387,940)	1,923,974	2,811,360
Income tax of movements in cash flow hedge transactions	109,882,227	(72,354,119)	36,172,878
Total income tax relating to components of other comprehensive income	106,494,287	(70,430,145)	38,984,238

F-92

19.  OTHER FINANCIAL LIABILITIES.

The balance of other financial liabilities as of December 31, 2021 and 2020 is as follows:

	12-31-2021		12-31-2020
	Current	Non-current	Current	Non-current
Other financial liabilities	ThCh$	ThCh$	ThCh$	ThCh$
Interest –bearing borrowings	75,182,769	1,868,805,671	152,076,992	1,467,421,655
Hedging derivatives (*)	11,647,944	72,386,037	5,398,864	16,167,471
Non-hedging derivatives (**)	1,509,177	682,670	23,285	—
Total	88,339,890	1,941,874,378	157,499,141	1,483,589,126

(*) See Note 22.2.a

(**) See Note 22.2.b

19.1 Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2021 and 2020 is as follows:

	12-31-2021		12-31-2020
	Current	Non-current	Current	Non-current
Classes of Interest-bearing borrowings	ThCh$	ThCh$	ThCh$	ThCh$
Secured bank loans	25,389,270	—	106,783,562	21,315,003
Unsecured bank loans	210,122	210,558,388	4	—
Unsecured obligations with the public	49,583,377	1,658,247,283	45,293,426	1,446,106,652
Total	75,182,769	1,868,805,671	152,076,992	1,467,421,655

Bank borrowings by currency and contractual maturity as of December 31, 2021 and 2020 are as follows

- 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 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	Total Non-Current 12-31-2021
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	1.50%	1.50%	Yes	—	25,389,270	25,389,270	—	—	—	—	—
Chile	CLP	6.00%	6.00%	No	3	—	3	—	—	—	—	—
Chile	US$	1.11%	1.02%	No	—	210,119	210,119	—	41,944,576	41,910,312	126,703,500	210,558,388
				Total	3	25,599,389	25,599,392	—	41,944,576	41,910,312	126,703,500	210,558,388
					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	Three to four years	Four to five years	Total Non-Current 12-31-2020
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	1.77%	1.77%	Yes	—	106,783,562	106,783,562	21,315,003	—	—	—	21,315,003
Chile	CLP	6.00%	6.00%	No	4	—	4	—	—	—	—	—
				Total	4	106,783,562	106,783,566	21,315,003	—	—	—	21,315,003

F-93

Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2021 is ThCh$236,395,400 (ThCh$127,771,152 as of December 31,2020). The borrowings have been categorized as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 3.h).

- Identification of bank borrowings by company

											12-31-2021							12-31-2020
											Current			Non-current				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$	Three to four years ThCh$	Two to three years ThCh$	Four to Five years ThCh$	Total Non- Current ThCh$	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two 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	—	—	—	—	3	—	3	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Foreign	Inter-American Development Bank ( BID )	USA	US$	1.50%	1.50%	Upon expiration	Yes	—	25,389,270	25,389,270	—	—	—	—	—	39,966	39,966	21,315,003	21,315,003
76.412.562-2	Enel Green Power Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	1.95%	1.95%	Upon expiration	Yes	—	—	—	—	—	—	—	—	106,743,596	106,743,596	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.036.000-k	Banco Santander	Chile	US$	0.49%	0.42%	Upon expiration	No	—	1,991	1,991	41,944,576	—	—	41,944,576	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Foreign	Sumitomo Mitsui Banking Corp.NY	USA	US$	1.48%	1.27%	Upon expiration	No	—	73,007	73,007	—	41,910,312	—	41,910,312	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	1.37%	1.37%	Upon expiration	No	—	135,121	135,121	—	—	126,703,500	126,703,500	—	—	—	—	—
							Total				3	25,599,389	25,599,392	41,944,576	41,910,312	126,703,500	210,558,388	4	106,783,562	106,783,566	21,315,003	21,315,003

F-94

19.2 Unsecured liabilities

The detail of unsecured liabilities by currency and maturity as of December 31, 2021 and 2020, 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 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12-31-2021
Country	Currency	Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	7.08%	6.49%	No	8,686,780	5,204,817	13,891,597	—	335,926,442	—	—	1,089,748,792	1,425,675,234
Chile	UF	6.01%	5.48%	No	—	35,691,780	35,691,780	34,620,562	34,620,562	34,620,562	34,620,562	94,089,801	232,572,049
				Total	8,686,780	40,896,597	49,583,377	34,620,562	370,547,004	34,620,562	34,620,562	1,183,838,593	1,658,247,283
								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

F-95

- Individual identification of Unsecured liabilities by debtor.

											12-31-2021									12-31-2020
											Current			Non-Current						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$	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 – First inssuance S-1	USA	US$	8.00%	7.87%	Upon expiration	No	5,706,279	—	5,706,279	—	—	—	—	173,387,986	173,387,986	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 - First inssuance S-2	USA	US$	8.80%	7.33%	Upon expiration	No	1,824,754	—	1,824,754	—	—	—	—	58,776,668	58,776,668	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 - First inssuance S-3	USA	US$	8.68%	8.13%	Upon expiration	No	1,155,747	—	1,155,747	—	—	—	—	28,755,477	28,755,477	972,757	—	972,757	—	—	—	—	23,349,497	23,349,497
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Single 24296	USA	US$	4.67%	4.25%	Upon expiration	No	—	3,031,498	3,031,498	—	335,926,442	—	—	—	335,926,442	—	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 Series-H	Chile	UF	7.17%	6.20%	Biannual	No	—	7,047,198	7,047,198	6,446,281	6,446,281	6,446,281	6,446,281	10,683,388	36,468,512	—	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 Series-M	Chile	UF	4.85%	4.75%	Biannual	No	—	28,644,582	28,644,582	28,174,281	28,174,281	28,174,281	28,174,281	83,406,413	196,103,537	—	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 - Single	USA	US$	5.24%	4.88%	Upon expiration	No	—	2,173,319	2,173,319	—	—	—	—	828,828,661	828,828,661	1,829,215	—	1,829,215	—	—	—	—	695,907,008	695,907,008
										Total Unsecured Bonds	8,686,780	40,896,597	49,583,377	34,620,562	370,547,004	34,620,562	34,620,562	1,183,838,593	1,658,247,283	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

19.3 Secured liabilities

As of December 31, 2021 and 2020, 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, 2021 was ThCh$2,008,803,043 (ThCh$1,866,198,159 as of December 31, 2020). These liabilities have 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).

19.4 Hedged debt

The debt denominated in U.S. dollars equivalent to ThCh$2,379,556,771 held by the Group as of December 31, 2021, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThCh$1,931,705,893 as of December 31, 2020) (see Note 3.g.5).

The following table details changes in “Reserve for cash flow hedges” as of December 31, 2021, 2020 and 2019, due to exchange differences:

	For the years ended December 31,
	2021	2020	2019
	ThCh$	ThCh$	ThCh$
Balance in hedge reserves (income hedge) at the beginning of the year net	(60,345,663)	(189,813,409)	(127,508,852)
Exchange differences recorded in equity net	(248,168,691)	98,288,849	(77,347,380)
Allocation of exchange differences to income net	26,960,555	31,178,897	15,042,823
Balance in hedge reserves (income hedge) at the end of the year net	(281,553,799)	(60,345,663)	(189,813,409)

19.5 Other information

As of December 31, 2021, the Group has unconditional long-term lines of credit of ThCh$118,469,000 (ThCh$140,643,000 as of December 31, 2020) at its disposal.

F-96

19.6 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 12-31-2021	One to two years	Two to Three Years	Three to four years	Four to five years	More than five years	as of 12-31-2021	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
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$				ThCh$
Chile	US$	1.14%	698,527	27,612,245	28,310,772	2,410,877	44,943,858	44,801,951	129,494,530	—	221,651,216	845,182	109,110,564	109,955,746	21,608,084	—	—	—	—	21,608,084
Chile	CLP	6.00%	3	—	3	—	—	—	—	—	—	4	—	4	—	—	—	—	—	—
Totals			698,530	27,612,245	28,310,775	2,410,877	44,943,858	44,801,951	129,494,530	—	221,651,216	845,186	109,110,564	109,955,750	21,608,084	—	—	—	—	21,608,084

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 12-31-2021	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2021	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
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.49%	20,108,083	60,324,249	80,432,332	80,432,332	411,026,050	65,350,879	65,350,879	1,441,550,517	2,063,710,657	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
Chile	UF	5.48%	3,524,020	44,954,298	48,478,318	46,675,021	44,871,725	43,068,428	41,265,131	108,039,559	283,919,864	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
Totals			23,632,103	105,278,547	128,910,650	127,107,353	455,897,775	108,419,307	106,616,010	1,549,590,076	2,347,630,521	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

20.  LEASE LIABILITIES

As of December 31, 2021, and 2020, the balance of lease liabilities is as follows:

	12-31-2021		12-31-2020
Lease liability	Current ThCh$	Non-Current ThCh$	Current ThCh$	Non-Current ThCh$
Lease liability	11,105,018	148,557,059	7,007,711	44,857,807
Total	11,105,018	148,557,059	7,007,711	44,857,807

F-97

20.1. Individualization of Lease Liabilities

Individualized lease liabilities are detailed as follows:

									12-31-2021									12-31-2020
									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	776,668	2,404,736	3,181,404	5,992,962	—	—	—	—	5,992,962	613,801	1,900,462	2,514,263	2,677,690	5,044,096	—	—	—	7,721,786
91.081.000-6	Enel Generación Chile S.A.	Chile	10.579.624-2	Marcelo Alberto Amar Basulto	Chile	UF	2.06%	Monthly	4,933	15,092	20,025	20,485	20,906	21,337	21,775	184,656	269,159	4,631	13,872	18,503	18,828	19,215	19,610	20,014	193,632	271,299
91.081.000-6	Enel Generación Chile S.A.	Chile	91.004.000-6	Productos Fernandez S.A.	Chile	UF	2.09%	Monthly	16,794	28,366	45,160	38,515	39,320	40,142	40,982	368,423	527,382	13,012	26,063	39,075	35,386	36,127	36,882	37,654	384,022	530,071
91.081.000-6	Enel Generación Chile S.A.	Chile	61.216.000-7	Empresa de Ferrocarriles del Estado	Chile	UF	1.07%	Biannual	1,847	—	1,847	—	—	—	—	—	—	1,163	578	1,741	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	78.392.580-K	Agricola el Bagual LTDA.	Chile	UF	1.91%	Annual	1,285	—	1,285	636	—	—	—	—	636	1,205	—	1,205	588	597	—	—	—	1,185
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	—	—	—	—	—	—	144,460	—	144,460	—	—	—	—	—	—
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	10,176	—	10,176	—	—	—	—	—	—	9,546	—	9,546	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	8.992.234-8	Roberto Guzman Borquez	Chile	CLP	1.37%	Monthly	371	1,114	1,485	1,377	—	—	—	—	1,377	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	409	1,232	1,641	1,525	—	—	—	—	1,525	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	5,097	—	5,097	—	—	—	—	—	—	19,023	38,171	57,194	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	70.015.730-K	MUTUAL DE SEGUROS DE CHILE	Chile	UF	1.91%	Monthly	23,270	51,474	74,744	69,779	71,113	72,470	61,449	—	274,811	21,619	47,378	68,997	64,225	65,453	66,704	67,977	57,639	321,998
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.596.523-3	CAPITAL INVESTI	Chile	UF	1.91%	Monthly	19,090	42,080	61,170	57,044	58,134	59,244	50,235	—	224,657	17,765	38,732	56,497	52,505	53,508	54,530	55,571	47,121	263,235
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.253.641-2	BCYCLE LATAM S.P.A	Chile	CLP	6.24%	Annual	79,717	—	79,717	17,719	18,825	—	—	—	36,544	60,000	—	60,000	16,679	17,719	18,825	—	—	53,223
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.203.089-6	RENTAS INMOBILIARIAS AMANECER S.A.	Chile	UF	1.56%	Monthly	5,013	4,754	9,767	—	—	—	—	—	—	4,563	39,724	44,287	17,803	—	—	—	—	17,803
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	—	234,086	234,086	70,479	74,698	79,169	83,908	735,553	1,043,807	—	327,074	327,074	111,940	118,640	125,742	133,269	1,249,650	1,739,241
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	1.08%	Monthly	457,380	285,436	742,816	31,728	—	—	—	—	31,728	191,038	272,511	463,549	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	1.77%	Monthly	98,029	115,211	213,240	109,492	77,991	32,930	—	—	220,413	41,407	106,769	148,176	143,774	102,703	73,155	30,888	—	350,520
96.800.570-7	Enel Distribución Chile S.A.	Chile	99.530.420-1	INMOBILIARIA NIALEM SA	Chile	UF	0.40%	Monthly	45,910	137,991	183,901	184,630	185,366	46,457	—	—	416,453	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	9,607	—	9,607	—	—	—	—	—	—	27,018	81,066	108,084	9,011	—	—	—	—	9,011
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	3.16%	Annual	1,642,921	1,941,762	3,584,683	2,866,968	2,914,858	2,964,390	3,015,619	107,161,591	118,923,426	546,737	430,871	977,608	711,487	735,784	761,006	787,190	15,513,561	18,509,028
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	250,639	—	250,639	77,502	79,471	81,490	83,561	1,419,297	1,741,321	109,911	—	109,911	70,851	72,651	74,497	76,389	1,408,792	1,703,180
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4.94%	Annual	16,532	—	16,532	7,259	7,618	7,994	8,389	198,038	229,298	266,597	—	266,597	6,483	6,804	7,140	7,493	193,507	221,427
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4.94%	Annual	21,470	—	21,470	9,572	10,045	10,542	11,063	242,741	283,963	51,923	—	51,923	8,550	8,973	9,416	9,882	237,592	274,413
76.412.562-2	Enel Green Power Chile S.A.	Chile	4.595.479-K	Adriana Castro Parra	Chile	UF	4.94%	Annual	74,019	—	74,019	15,602	16,374	17,183	18,033	369,450	436,642	33,522	—	33,522	13,937	14,626	15,349	16,108	363,230	423,250
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	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.378.630-5	Agricola Santa Amalia	Chile	UF	4.94%	Annual	33,913	—	33,913	15,602	16,374	17,183	18,033	369,450	436,642	22,346	—	22,346	13,937	14,626	15,349	16,108	363,230	423,250
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.894.990-3	Orafti Chile S.A.	Chile	UF	4.94%	Annual	16,954	—	16,954	7,434	7,801	8,187	8,592	186,308	218,322	8,966	—	8,966	6,640	6,968	7,313	7,674	183,027	211,622
76.412.562-2	Enel Green Power Chile S.A.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4.94%	Annual	107,386	—	107,386	47,172	49,504	51,952	54,521	1,231,819	1,434,968	66,597	—	66,597	42,137	44,221	46,407	48,701	1,205,826	1,387,292
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	EUR	5.02%	Annual	—	1,050,760	1,050,760	209,159	219,656	230,680	242,258	2,431,078	3,332,831	—	596,278	596,278	181,888	191,016	200,603	210,671	2,441,450	3,225,628
76.412.562-2	Enel Green Power Chile S.A.	Chile	76.259.106-5	Inmobiliaria Terra Australis Tres S.A.	Chile	UF	6.39%	Biannual	85,721	21,033	106,754	43,211	44,784	46,414	48,103	1,207,776	1,390,288	32,757	19,025	51,782	39,084	40,507	41,981	43,509	1,177,273	1,342,354
76.412.562-2	Enel Green Power Chile S.A.	Chile	79.938.160-5	Soc. Serv. Com. Multiservice F.L.	Chile	UF	2.94%	Annual	—	76,729	76,729	40,483	41,673	42,898	44,159	1,023,505	1,192,718	—	101,743	101,743	36,866	37,949	39,065	40,213	963,970	1,118,063
76.412.562-2	Enel Green Power Chile S.A.	Chile	76.064.627-K	Fortestal Danco	Chile	UF	2.42%	Annual	—	68,355	68,355	32,670	33,460	34,268	35,097	1,862,245	1,997,740	—	—	—	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	99.576.780-5	Inversiones e Inmobiliaria Itraque S.A.	Chile	UF	5.35%	Annual	—	—	—	4,363	4,363	4,363	4,363	104,715	122,167	—	—	—	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	76.152.312-0	Sociedad Agricola El Futuro Huerto Limitada	Chile	UF	4.35%	Annual	—	—	—	104,970	104,970	104,970	104,970	2,414,316	2,834,196	—	—	—	—	—	—	—	—	—
76.126.507-5	Parque Eólico Talinay Oriente S.A.	Chile	76.248.317-3	Agricola Alto Talinay	Chile	EUR	4.61%	Annual	427,121	—	427,121	250,397	261,940	274,015	286,647	2,823,778	3,896,777	374,657	—	374,657	218,600	228,677	239,219	250,247	2,840,625	3,777,368
76.536.353-5	Enel Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	0.10%	Monthly	4,339	4,338	8,677	498	—	—	—	—	498	2,710	4,065	6,775	5,426	476	—	—	—	5,902
77.282.311-8	Enel Transmisión Chile S.A.	Chile	61.219.000-3	EMPRESA DE TRANSPORTE DE PASAJEROS METRO S.A	Chile	US$	5.99%	Annual	—	239,398	239,398	70,479	74,698	79,169	83,908	735,554	1,043,808	—	—	—	—	—	—	—	—	—
							Total Leasing		4,381,071	6,723,947	11,105,018	10,399,712	4,433,942	4,327,447	4,325,665	125,070,293	148,557,059	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

20.2. Undiscounted debt cash flows.

Undiscounted debt cash flows are detailed as follows:

			Current			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 12-31-2021	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2021	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
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.16%	930,191	3,228,385	4,158,576	6,452,784	281,183	270,895	260,606	1,714,465	8,979,933	805,609	2,544,526	3,350,135	3,343,654	5,400,991	227,622	219,295	1,598,935	10,790,497
Chile	EUR	4.82%	418,674	—	418,674	660,889	638,249	615,610	592,971	2,145,489	4,653,208	427,451	—	427,451	582,405	563,152	543,900	524,648	2,334,458	4,548,563
Chile	UF	2.68%	3,269,537	5,810,978	9,080,515	9,570,650	9,401,180	9,063,780	8,792,850	189,317,356	226,145,816	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
Chile	CLP	2.89%	74,988	1,142	76,130	22,841	20,252	—	—	—	43,093	24,156	—	24,156	20,234	19,173	18,112	—	—	57,519
Totals			4,693,390	9,040,505	13,733,895	16,707,164	10,340,864	9,950,285	9,646,427	193,177,310	239,822,050	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

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21.  RISK MANAGEMENT POLICY

The Group companies follow the guidelines of the Risk Management Control System (SCGR) defined at the holding level (Enel S.p.A.), which establishes rules for managing risks through the respective standards, procedures, systems, etc., applicable to the different levels of the Group companies and business risk identification, analysis, evaluation, treatment, and communication processes. These guidelines are approved by the Enel S.p.A. 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 the guidelines, 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. There is a risk taxonomy 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 senior management and the Directors up-to-date on risk management. In this sense, the first and second lines of defense report to the senior management, and the second and third lines report to the 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 mitigating measures.

21.1 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 Group’s financial debt structure per fixed and/or hedged interest rate on gross, net of hedging derivative instruments engaged, as of December 31, 2021 and 2020 is as follows:

	For the years ended December 31,
	2021	2020
	%	%
Fixed interest rate	82%	99%

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 was offset by effective risk mitigation actions using derivative financial instruments.

21.2 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’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between U.S. dollar flows and the levels of assets and liabilities denominated in such currency. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. In addition, the policy works to refinance debt in the functional currency of each of the Group’s companies.

During the fourth quarter of 2021, exchange rate risk management continued in the context of complying with the aforementioned risk management policy, without difficulty to access the derivatives market. During the pandemic, financial markets have been characterized by exchange rate volatility, which has been offset by risk mitigation actions through derivative financial instruments.

21.3 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, 2021, there were Brent hedges for 1.93 kbbl to be settled in 2022 and 9.1 Tbtu of HH to be settled in 2022. As of December 31, 2020, there were operations in force for 1.782 kbbl from Brent to be settled in 2021 and 16.8 Tbtu from Henry Hub to be settled in 2021.

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 2021.

21.4 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.

Despite having negative working capital at the end of 2021, the Company has the capacity to overcome this situation and mitigate the risk through its liquidity risk policy and actions described herein.

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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 19 and 22.

As of December 31, 2021, the Group recorded liquidity in the amount of ThCh$ 309,975,140 in cash and cash equivalents and ThCh$118,469,000 in unconditionally available long-term lines of credit. As of December 31, 2020, the Group recorded liquidity of ThCh$332,036,013 in cash and cash equivalents and ThCh$140,643,000 in unconditionally available long-term lines of credit.

21.5 Credit risk

The Group closely monitors its credit risk.

Trade receivables:

Regarding the credit risk of our electricity generation line of business, related to trade receivables, this risk is historically very limited because the customer collection period is short, accordingly, no significant individual amounts are accumulated before the service is shut-off due to late payment, according to contract conditions. For this reason, credit risk is continuously monitored, measuring the maximum amounts exposed to payment risk which is very limited.

For our electricity distribution company, it has the power to shut-off supply in the event of customer default, which is applied in accordance with current regulations and facilitates the process to evaluate and control credit risk, which is also limited. However, on August 8, 2020, Law 21,249 on Basic Services was published - with two extensions published during 2021. The Law establishes, on an exceptional basis, measures to benefit the end users of water, electricity, and gas services. The regulation established, up to December 31, 2021, the prohibition to shut off services for residential customers (as well as hospitals, healthcare centers, orphanages and retirement homes, non-profit organizations, microcompanies, among others), and the option to prorate debt assumed over this period in 48 installments (according to the latest update), with no associated fines, interest, or expenses, upon accreditation of the conditions stated by the regulation itself. In addition, it imposes the obligation to establish online customer service platforms and by telephone so that they may request access to these benefits. From the enactment of the law, the number of customers that have used the benefit is 68,839. (See Note 4.b).

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 from the beginning of the pandemic, as a result of an increase in expected credit losses from counterparties (see Notes 3.g.3 and 8.d).

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial 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.

21.6 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.

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- Hedging 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.

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$654,949,943.

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.

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22.  FINANCIAL INSTRUMENTS

22.1 Financial instruments classified by type and category

a) The detail of financial assets, classified by type and category, as of December 31, 2021 and 2020 is as follows:

		12-31-2021
	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	—	730,524,889	—	—
Derivative instruments	3,613,470	—	14,620,453	3,584,937
Other financial assets	—	118,547	—	—
Total Current	3,613,470	730,643,436	14,748,307	3,584,937
Equity instruments	—	—	2,358,143	—
Trade and other accounts receivable	—	522,134,341	—	—
Derivative instruments	—	—	—	37,020,922
Total Non-current	—	522,134,341	2,358,143	37,020,922
Total	3,613,470	1,252,777,777	17,106,450	40,605,859
		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
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

The carrying amount of trade accounts receivable and payable approximates their fair value.

F-103

b) The detail of financial liabilities, classified by type and category, as of December 31, 2021 and 2020 is as follows:

	12-31-2021
	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	—	75,182,770	—	—
Trade and other accounts payable	—	1,978,051,397	—	—
Derivative instruments	3,843,088	—	3,396,389	11,647,943
Other financial liabilities	—	11,105,018	—	—
Total Current	3,843,088	2,064,339,185	3,396,389	11,647,943
Interest-bearing loans	—	1,868,805,671	—	—
Trade and other accounts payable	—	1,479,456,509	—	—
Derivative instruments	682,670	—	—	72,386,037
Other financial liabilities	—	148,557,059	—	—
Total Non-current	682,670	3,496,819,239	—	72,386,037
Total	4,525,758	5,561,158,424	3,396,389	84,033,980
	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

22.2 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).

F-104

a) Assets and liabilities for hedge derivative instruments

As of December 31, 2021 and 2020, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:

	12-31-2021				12-31-2020
	Assets		Liabilities		Assets		Liabilities
	Current	Non-current	Current	Non-current	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	—	432,151	6,532,657	—	—	—	1,947,377	12,944,130
Cash flow hedge	—	432,151	6,532,657	—	—	—	1,947,377	12,944,130
Exchange rate hedge:	3,584,937	36,588,771	5,115,286	72,386,037	1,000,964	16,422,737	3,451,487	3,223,341
Cash flow hedge	3,584,937	36,588,771	5,115,286	72,386,037	1,000,964	16,422,737	3,451,487	3,223,341
Total	3,584,937	37,020,922	11,647,943	72,386,037	1,000,964	16,422,737	5,398,864	16,167,471

- 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	12-31-2021	12-31-2020	of
instrument	risk	item	ThCh$	ThCh$	risk hedged
SWAP	Exchange rate	Unsecured Obligations (Bonds)	(37,402,976)		Cash flow
SWAP	Interest rate	Loans with Related Companies	(6,100,507)	(12,944,129)	Cash flow
SWAP	Interest rate	Bank loans	—	(1,947,377)	Cash flow
FORWARD	Exchange rate	Operational Income	(4,285,349)	(1,967,328)	Cash flow
FORWARD	Interest rate	Other	—	(77,558)	Cash flow
FORWARD	Exchange rate	Property, plant & equipment investment	3,278,444	—	Cash flow
FORWARD	Exchange rate	Other	1,082,267	29,981	Cash flow

As of December 31, 2021 and 2020, 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, 2021 and 2020, 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:

	12-31-2021				12-31-2020
	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	210,077	1,509,177	—	682,670	1,414,895	23,285	1,911,233	—
Total	210,077	1,509,177	—	682,670	1,414,895	23,285	1,911,233	—

These derivative instruments correspond to forward contracts entered into by the Group, the purpose of which is to hedge the exchange rate risk related to future obligations arising from civil works contracts linked to the 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.

F-105

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, 2021 and 2020.

	12-31-2021
		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:	(6,100,506)	337,876,000	—	42,234,500	—	—	380,110,500
Cash flow hedge	(6,100,506)	337,876,000	—	42,234,500	—	—	380,110,500
Exchange rate hedge:	(37,327,615)	264,384,743	110,432,048	344,081,268	53,306,308	—	772,204,367
Cash flow hedge	(37,327,615)	264,384,743	110,432,048	344,081,268	53,306,308	—	772,204,367
Derivatives not designated for hedge accounting	(1,981,770)	26,610,132	10,387,480	339,050	—	—	37,336,662
Total	(45,409,891)	628,870,875	120,819,528	386,654,818	53,306,308	—	1,189,651,529
	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

The notional amount of the contracts entered into does not represent the risk assumed by the Group, as this amount only relates to the basis on which the derivative settlement calculations are made.

F-106

22.3 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, 2021 and 2020:

		Fair Value Measured at End of Reporting Period Using:
	12-31-2021	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	40,605,859	—	40,605,859	—
Financial derivatives not designated for hedge accounting	210,077	—	210,077	—
Derivatives of commodities designated as non-hedging of cash flow at fair value through profit or loss	3,403,393	—	3,403,393	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	14,620,453	—	14,620,453	—
Equity instruments at fair value with changes in other comprehensive income	2,485,997	2,358,143	127,854	—
Total	61,325,779	2,358,143	58,967,636	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	84,033,980	—	84,033,980	—
Financial derivatives not designated for hedge accounting	2,191,847	—	2,191,847	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in profit or loss	2,333,911	—	2,333,911	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	3,396,389	—	3,396,389	—
Total	91,956,127	—	91,956,127	—

		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	—

F-107

23.  CURRENT AND NON-CURRENT PAYABLES

The detail of trade and other current payables as of December 31, 2021 and 2020 is as follows:

	Current		Non-current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Trade and Other Payables	ThCh$	ThCh$	ThCh$	ThCh$
Energy suppliers (1)	237,889,432	135,817,661	175,580,989	112,895,627
Fuel and gas suppliers	86,288,004	36,735,748	—	—
Payables for goods and services	193,170,873	153,883,621	487	487
Payables for assets acquisition	396,820,422	251,679,169	3,730,996	4,233,657
Subtotal Trade Payables	914,168,731	578,116,199	179,312,472	117,129,771
Other Payables
Dividends payable to third parties	18,090,436	5,755,000	—	—
Accounts payables to employees	39,207,096	35,256,939	—	—
Other payables	6,858,224	8,829,884	84,940	80,288
Subtotal other current payables	64,155,756	49,841,823	84,940	80,288
Total	978,324,487	627,958,022	179,397,412	117,210,059

(1)The non-current portion shows delays in payments for energy purchases of ThCh$ 174,373,938 as of December 31, 2021 and ThCh$ 112,895,627 as of December 31, 2020, generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 8).

The description of the liquidity risk management policy is detailed in Note 21.4.

The details of trade payables, both current and past due as of December 31, 2021 and 2020 are presented in Appendix 3.

F-108

24.  PROVISIONS

a) The detail of provisions as of December 31, 2021 and 2020, is detailed as follows:

	Current		Non-current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Provision for legal proceedings (1)	1,264,710	1,492,140	13,149,618	14,843,034
Decommissioning or restoration (2)	13,375,095	—	173,341,364	191,867,939
Other provisions (3)	5,116,512	1,942,664	7,621,732	3,530,698
Total	19,756,317	3,434,804	194,112,714	210,241,671

(1) See Note 35.3.

(2) See Note 3.a.

(3) In 2021, this item includes an amount of ThCh$ 3,434,242 at short-term and ThCh$ 4,042,759 at long-term, which relates to restructuring provisions associated with the Group’s 2021-2024 digitization strategy. This enables the adoption of new work and operation models and demands new skills and knowledge to make processes even more efficient.

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.

b) Movements in provisions as of December 31, 2021 and 2020, are as follows:

	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
Movements in Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2021	16,335,174	191,867,939	5,473,362	213,676,475
Increase (decrease) in existing provisions (1)	6,006,400	(3,197,115)	7,856,556	10,665,841
Provisions used	(1,999,269)	(2,782,780)	(623,019)	(5,405,068)
Reversal of unused provision	(6,378,072)	—	—	(6,378,072)
Increase from adjustment to time value of money (2)	—	(1,672,021)	—	(1,672,021)
Conversion Difference Foreign Currency Exchange	483,048	2,605,855	33,882	3,122,785
Other Increase (Decrease)	(32,953)	(105,419)	(2,537)	(140,909)
Total movements in provisions	(1,920,846)	(5,151,480)	7,264,882	192,556
Balance as of December 31, 2021	14,414,328	186,716,459	12,738,244	213,869,031
	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
Movements 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 (3)	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
Conversion Difference Foreign Currency Exchange	(156,143)	(1,118,607)	—	(1,274,750)
Total movements 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

F-109

(1) Changes to provisions for decommissioning and restoration for the year ended December 31, 2021, are mainly due to an increase in the discount rate used to calculate these provisions.

(2) Corresponds to a financial update, see Note 33.

(3) The increase in the provisions for decommissioning or restoration during 2020 is explained primarily by the process to close the Bocamina II plant’s operations. This resulted in an increase in the present value of the obligation, as a result of the adjustment to the previously-established terms for making the disbursements, along with performing an update to the estimated values thereof (see Note 15.c.iv).

F-110

25.  POST-EMPLOYMENT BENEFIT OBLIGATIONS.

25.1 General information:

Enel Chile 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.

• 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.

25.2 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, 2021 and 2020 are as follows:

	12-31-2021	12-31-2020
	ThCh$	ThCh$
Employee severance indemnities	39,469,461	50,011,279
Complementary Pension	14,349,089	18,896,906
Health Plans	2,459,163	3,145,989
Energy Supply Plans	2,673,873	3,484,091
Total post-employment obligations, net	58,951,586	75,538,265

The decrease in post-employment obligations is mainly due to an adjustment of the discount rate that the Group applied at the end of the year ended December 31, 2021. The increase in this actuarial assumption of more than 100 basis points compared to the end of 2020 arose from changes to the macroeconomic and financial environment due to the COVID-19 pandemic (see Notes 2.3 and 34.5).

b) The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2021 and 2020.

	For the years ended December 31,
Expense Recognized in	2021	2020	2019
Comprehensive Income	ThCh$	ThCh$	ThCh$
Cost of current defined benefit plan service	(1,099,554)	(2,132,231)	(1,928,868)
Defined benefit plan interest cost (1)	(1,818,983)	(2,146,386)	(2,639,738)
Past service cost	—	—	(1,224,527)
Expenses recognized in Profit or Loss	(2,918,537)	(4,278,617)	(5,793,133)
Gains (losses) from remeasurement of defined benefit plans	12,547,898	(8,545,834)	(7,777,204)
Total expense recognized in the Statement of Comprehensive Income	9,629,361	(12,824,451)	(13,570,337)

(1) See Note 33

F-111

c) The balance and movements in post-employment defined benefit obligations as of December 31, 2021 and 2020 are as follows:

Actuarial Value of Post-employment Obligations	ThCh$
Balance as of January 1, 2020	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)
Balance as of December 31, 2020	75,538,265
Current service cost	1,099,554
Interest cost	1,818,983
Actuarial (gains) losses from changes in financial assumptions	(14,628,751)
Actuarial (gains) losses from changes in experience adjustments	2,080,853
Foreign currency translation	141,342
Contributions paid	(7,265,904)
Transfer of employees	167,244
Closing balance December 31, 2021	58,951,586

25.3 Other disclosures:

• Actuarial assumptions:

As of December 31, 2021 and 2020, the following assumptions were used in the actuarial calculation of defined benefit plans:

	12-31-2021	12-31-2020
Discount rates used	5.60%	2.60%
Expected rate of salary increases	3.80%	3.80%
Turnover rate	6.90%	7.10%
Mortality tables	CB-H-2014 and RV-M-2014	CB-H-2014 and RV-M-2014

• Sensitivity:

As of December 31, 2021, 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$4,470,682 (ThCh$5,602,670 as of December 31, 2020) if the rate rises and an increase of ThCh$4,741,049 (ThCh$6,136,668 as of December 31, 2020) 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$7,448,154.

• Length of commitments

Enel Chile´s obligations have a weighted average length of 7.03 years and the outflows of benefits for the next 10 years is expected to be as follows:

Years	ThCh$
1	7,448,154
2	5,436,208
3	5,779,343
4	5,630,099
5	5,339,404
6 to 10	26,450,572

F-112

26.  EQUITY

26.1.Equity attributable to the owners of Enel Chile

26.1.1. Subscribed and paid capital and number of shares

The issued capital of Enel Chile for the years ended December 31, 2021 and 2020 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. Enel Chile’s common stock is traded on the Santiago Stock Exchange (Bolsa de Comercio de Santiago de Chile), the Chilean Electronic Stock Exchange (Bolsa Electrónica de Chile), and the New York Stock Exchange (NYSE).

26.2 Dividends

Dividend No.	Type of Dividend	Agreement date	Payment Date	Total Amount ThCh$	Pesos per Share	Charged to Fiscal
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)
10	Eventual	04-28-2021	05-28-2021	212,853,281	3.07740	(2)
11	Interim	11-26-2021	01-28-2022	7,260,512	0.10497	2021

(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 15.c.iv, Development during 2019), the distribution of a provisional dividend was approved with charge to the retained earnings for previous years.

(2) At the Ordinary Shareholders’ Meeting held on April 28, 2021, the shareholders agreed to distribute a dividend with a debit against retained earnings from prior years to offset the impairment losses recognized by the subsidiary Enel Generación in 2020 (see Note 15.c.iv, Development during 2020)

26.3 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, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	12-31-2021	12-31-2020	12-31-2019
Reserves for Accumulated Currency Translation Differences	ThCh$	ThCh$	ThCh$
Enel Generación Chile S.A.	(7,729,810)	(7,746,933)	(3,292,629)
GNL Chile S.A.	1,598,641	907,869	1,022,047
Grupo Enel Green Power Chile	285,686,490	110,921,404	168,387,151
Enel X AMPCI Ebus Chile SpA	246,142	(432,247)	—
TOTAL	279,801,463	103,650,093	166,116,569

26.4 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 Company. As of December 31, 2021 and 2020, the Company’s interest in the net restricted assets of Enel Generación Chile was ThCh$ 712,519,037.

F-113

26.5 Other reserves

Other reserves for the years ended December 31, 2021, 2020 and 2019 are as follows:

	01-01-2021	2021 Changes	12-31-2021
Detail of other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	103,650,093	176,151,370	279,801,463
Cash flow hedges	(102,946,095)	(288,577,039)	(391,523,134)
Financial assets at fair value with changes in other comprehensive income	1,783	21	1,804
Other miscellaneous reserves	(2,278,331,266)	2,629,721	(2,275,701,545)
TOTAL	(2,277,625,485)	(109,795,927)	(2,387,421,412)
	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)

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).

c) Other miscellaneous reserves:

The main items and their effects are the following:

	For the years ended
	2021	2020	2019
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)	13,222,164	11,216,652	8,939,332
Other miscellaneous reserves (vii)	7,645,052	7,020,843	7,001,861
TOTAL	(2,275,701,545)	(2,278,331,266)	(2,280,627,568)

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 CMF, 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 31, 2008.

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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 completed in March 2018.

v) “Reorganization of Renewable Assets” Reserve: This corresponds to the reserve constituted by the merger between Enel Green Power Latin América S.A. 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.A. 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.

26.6 Non-controlling Interests

The detail of non-controlling interests as of December 31, 2021, 2020 and 2019, is as follows:

		Non-controlling Interests
		Equity		Profit (Loss)
	12-31-2021	12-31-2021	12-31-2020	2021	2020	2019
Companies	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile S.A.	0.91%	6,178,079	8,188,827	151,538	749,261	1,079,941
Enel Transmisión Chile S.A.	0.91%	1,585,517	—	291,934	—	—
Enel Generación Chile S.A.	6.45%	96,773,030	111,567,532	7,480,423	(10,006,037)	12,667,880
Empresa Eléctrica Pehuenche S.A.	7.35%	10,695,281	10,113,358	7,717,216	6,403,829	6,241,062
Sociedad AgrÍcola de Cameros Ltda.	42.50%	2,120,237	2,068,169	52,068	230,557	(504,550)
Geotermica del Norte S.A.	15.41%	64,539,697	55,283,359	(760,576)	645,440	(264,158)
Empresa Nacional de Geotermia S.A.	0.00%	—	11,134	(5,089)	(515,293)	(74,963)
Parque Eólico Talinay Oriente S.A.	39.09%	66,070,754	55,283,519	609,150	945,454	868,127
Other		661,950	(157,189)	19,501	20,267	(73,726)
TOTAL		248,624,545	242,358,709	15,556,165	(1,526,522)	19,939,613

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27.  REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
Revenues	ThCh$	ThCh$	ThCh$
Energy sales (1)	2,585,248,169	2,380,736,600	2,405,903,242
Generation	1,489,763,351	1,111,508,158	1,090,021,527
Regulated customers	532,353,167	480,168,004	540,017,333
Unregulated customers	893,147,380	571,587,710	524,559,735
Spot market sales	64,262,804	59,752,444	25,444,459
Distribution	1,095,484,818	1,269,228,442	1,315,881,715
Residential	597,631,419	608,703,250	552,124,205
Business	293,442,712	366,874,872	450,108,855
Industrial	99,516,111	168,931,181	181,595,960
Other consumers (2)	104,894,576	124,719,139	132,052,695
Other sales	156,907,706	58,870,872	124,113,792
Gas sales	129,442,332	38,808,266	97,564,262
Sales of goods and services	27,465,374	20,062,606	26,549,530
Revenue from other services	87,526,529	108,776,845	94,559,289
Tolls and transmission	29,341,568	41,859,311	31,232,252
Metering equipment leases	2,967,964	3,387,302	2,131,427
Services and Business Advisories provided (Public lighting, connections and electrical advisories)	44,126,106	53,121,851	47,455,465
Other services	11,090,891	10,408,381	13,740,145
Total Revenues	2,829,682,404	2,548,384,317	2,624,576,323
Other Income	ThCh$	ThCh$	ThCh$
Temporary leasing of generating facilities	686,126	10,662,952	2,777,404
SEF fine revocation	1,161,837	—	—
Commodity derivative income	6,814,747	4,473,463	5,967,739
Income from insurance claims (3)	—	—	121,117,605
Income from claim collection (insurance)	6,352,546	10,799,437	5,952,589
Income from sanctions to users	3,419,398	1,314,193	87,275
Other income	7,112,477	9,767,835	10,355,425
Total other income	25,547,131	37,017,880	146,258,037

(1) As of December 31, 2021, this item includes ThCh$466,620,691 which corresponds to estimated, unbilled sales related to estimates of energy sold in December 2021, including PEC and base prices. As of December 31, 2020 and 2019, these amounted to ThCh$434,442,879 and ThCh$310,301,370, respectively.

(2) For the year ended December 31, 2021, it includes revenue from the sale of energy to municipalities of ThCh$37,097,819 (ThCh$35,598,366 and ThCh$45,768,456 as of December 31, 2020 and 2019, respectively); government entities of ThCh$15,986,996 (ThCh$17,334,983 and ThCh$20,432,048 as of December 31, 2020 and 2019, respectively); agricultural companies of ThCh$7,798,059 (ThCh$10,324,464 and ThCh$9,100,691 as of December 31, 2020 and 2019, respectively); public and telecommunications service companies of ThCh$10,624,277 (ThCh$27,014,443 and ThCh$24,818,503 as of December 31, 2020 and 2019, respectively), educational institutions of ThCh$4,121,823 (ThCh$5,749,102 and ThCh$9,367,933 as of December 31, 2020 and 2019, respectively), healthcare services of ThCh$12,142,923

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(ThCh$21,407,325 and ThCh$18,975,909 as of December 31, 2020 and 2019, respectively) and other of ThCh$ 17,122,729 (ThCh$ 7,290,456 and ThCh$3,589,156 as of December 31, 2020 and 2019, respectively).

(3) In February 2019, Anglo American Sur S.A. notified Enel Generación Chile of its decision to terminate three electricity supply contracts ahead of schedule. These contracts were entered into by the parties in 2016. In accordance with the exit and settlement clauses of the respective contracts, notification of early termination gave Enel Generación Chile the right to receive compensation, consisting of a cash amount made by Anglo American Sur S.A., and determined according to the predetermined calculation mechanism.

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28.  RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
Raw materials and consumables used	ThCh$	ThCh$	ThCh$
Energy purchases	(1,296,992,284)	(864,863,454)	(835,284,742)
Fuel consumption	(374,868,794)	(231,176,489)	(230,944,415)
Gas	(251,009,877)	(149,734,219)	(134,127,365)
Coal (*)	(96,282,224)	(75,342,193)	(3,326,061)
Oil (*)	(27,576,693)	(6,100,077)	(93,490,989)
Energy transmission cost	(151,738,224)	(141,539,687)	(196,848,788)
Gas sales costs	(110,831,219)	(34,332,998)	(74,998,608)
Other raw materials and consumables	(76,874,883)	(102,533,011)	(83,128,698)
Total	(2,011,305,404)	(1,374,445,639)	(1,421,205,251)

(*) During 2021, this item includes an impairment loss on coal inventory impairment of ThCh$45,904,847 as a consequence of the closure of the Bocamina II plant (ThCh$21,246,157 in 2020). For the same reason, adjustments due to impairment of diesel were also recorded for ThCh$667,298 (ThCh$328,626 in 2020). For further information see Note 15.c.iv. and Note 10.

29.  EMPLOYEE BENEFITS EXPENSE

The detail of employee expenses for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
Employee Benefits Expense	ThCh$	ThCh$	ThCh$
Wages and salaries	(129,759,535)	(117,220,406)	(109,101,737)
Post-employment benefit obligations expense	(1,099,554)	(2,132,231)	(3,153,395)
Social security and other contributions	(13,059,172)	(12,346,828)	(14,334,587)
Other employee expenses	(19,426,893)	(5,527,283)	(3,015,237)
Total Employee Benefits Expenses	(163,345,154)	(137,226,748)	(129,604,956)

(*) During 2021, this item included ThCh$ 17,602,579 from restructuring provisions and expenses associated with the Group’s 2021-2024 digitization strategy. This enables the adoption of new work and operation models and demands new skills and knowledge to make processes even more efficient.

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30.  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, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
	ThCh$	ThCh$	ThCh$
Depreciation	(198,700,349)	(215,581,938)	(224,724,380)
Amortization	(12,227,307)	(14,375,081)	(11,903,007)
Total	(210,927,656)	(229,957,019)	(236,627,387)

b) The detail of the items related to impairment for the years ended December 31, 2021, 2020 and 2019, is as follows

	For the years ended December 31,
	Generation			Distribution and Transmission			Other			Total
	2021	2020	2019	2021	2020	2019	2021	2020	2019	2021	2020	2019
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 15)	(33,035,731)	(698,235,380)	(280,020,263)	—	—	—	—	—	—	(33,035,731)	(698,235,380)	(280,020,263)
Intangibles (see Note 14)	—	(217,658)	—	—	—	—	—	—	—	—	(217,658)	—
Investment Property (see Note 17)	—	—	—	—	—	—	136,877	646,597	(742,389)	136,877	646,597	(742,389)
Total Reversal of impairment losses (impairment losses) recognized in profit or loss	(33,035,731)	(698,453,038)	(280,020,263)	—	—	—	136,877	646,597	(742,389)	(32,898,854)	(697,806,441)	(280,762,652)
Impairment gain and reversals from impairment losses in accordance with IFRS 9 (see note 8.d)	(691,132)	(1,305,341)	(1,338,599)	(17,419,025)	(12,998,719)	(8,153,419)	(655,018)	(863,647)	(554,982)	(18,765,175)	(15,167,707)	(10,047,000)

31.  OTHER EXPENSE, BY NATURE

Other miscellaneous operating expense for the years ended December 31, 2021, 2020 and 2019, are detailed as follows:

	For the years ended December 31,
	2021	2020	2019
Other Expenses by nature	ThCh$	ThCh$	ThCh$
Professional, outsourced and other services	(74,650,311)	(74,630,728)	(60,819,733)
Administrative expenses	(9,072,602)	(7,214,238)	(8,893,785)
Repairs and maintenance	(43,670,583)	(49,051,950)	(50,846,851)
Indemnities and fines	(76,693)	(1,029,517)	(1,243,376)
Taxes and charges	(6,316,351)	(5,675,978)	(6,802,176)
Insurance premiums	(23,487,377)	(19,992,385)	(19,200,681)
Leases and rental costs	(3,790,971)	(4,958,760)	(3,824,195)
Marketing, public relations and advertising	(1,971,879)	(2,491,884)	(3,274,693)
Write-off of Property, Plant and Equipment (*)	—	—	(3,510,591)
Travel expenses	(1,220,870)	(2,223,358)	(3,991,349)
Environmental expenses	(7,998,327)	(8,313,182)	(9,886,690)
Other supplies and services	(17,294,861)	(15,011,354)	(11,849,020)
Total	(189,550,825)	(190,593,334)	(184,143,140)

(*) See explanation in Note 15 c) paragraph vi).

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32.  OTHER GAINS (LOSSES)

The detail of other gains (losses) for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
Other Gains (Losses)	ThCh$	ThCh$	ThCh$
Gain on sale of Property, Plant and Equipment	—	9,384,038	1,530,689
Gain on sale of Transmisora Eléctrica de Quillota Ltda. (*)	9,968,845	—	—
Result of other investments	168,439	104,777	262,512
Total	10,137,284	9,488,815	1,793,201

(*) See Note 12.3 a).

33.  FINANCIAL RESULTS

Finance income and costs for the years ended December 31, 2021, 2020 and 2019, are as follows:

	For the years ended December 31,
	2021	2020	2019
Finance Income	ThCh$	ThCh$	ThCh$
Income from deposits and other financial instruments	3,259,801	7,324,057	8,973,606
Interests charged to customers in energy accounts and billing	13,130,196	12,477,393	8,057,203
Financial income by Law N°21,185 (1)	4,802,376	15,328,829	5,225,739
Other financial income	5,228,027	1,030,181	5,142,727
Total Finance Income	26,420,400	36,160,460	27,399,275

	For the years ended December 31,
	2021	2020	2019
Finance Costs	ThCh$	ThCh$	ThCh$
Bank loans	(2,727,697)	(7,151,030)	(14,487,700)
Bonds payable to the public not guaranteed	(85,990,347)	(84,268,247)	(81,818,564)
Lease obligations	(1,960,901)	(2,128,360)	(1,815,170)
Valuation of financial derivatives for cash flow hedging	(9,327,966)	(5,887,498)	1,775,749
Financial cost by Law N°21,185 (1)	(2,409,504)	(4,518,268)	(19,062,333)
Financial update of provisions (2)	(3,048,796)	(4,115,292)	(4,356,650)
Post-employment benefit obligations (3)	(1,818,983)	(2,146,386)	(2,639,738)
Debt formalization expenses and other associated expenses	(5,003,674)	(2,646,906)	(4,710,012)
Capitalized borrowing costs	61,513,684	33,109,819	9,321,354
Financial cost related companies	(42,066,043)	(35,079,947)	(31,304,382)
Assignment of rights and sale of accounts receivable to customers (4)	(48,442,370)	(533,615)	—
Financial costs by law N°21,340 and N°21,249 (5)	(19,186,490)	—	—
Other financial costs	(13,574,029)	(12,043,041)	(15,800,454)
Total	(174,043,116)	(127,408,771)	(164,897,900)
Gains or loss from indexed assets and liabilities, net (*)	5,897,520	2,085,768	(2,982,268)
Foreign currency exchange differences (**)	(15,334,368)	(23,272,231)	(10,412,110)
Total Finance Costs	(183,479,964)	(148,595,234)	(178,292,278)
Total Financial Results	(157,059,564)	(112,434,774)	(150,893,003)

(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 8).

(2) See Note 24.

(3) See Note 25.2 b).

(4) See Note 8, section a.2.

(5) Costs of applying a financial discount to accounts receivable related to the Basic Service Law (see Note 4.b).

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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,
	2021	2020	2019
Gains (losses) from Indexed Assets and Liabilities (*)	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	64,806	—	36,797
Trade and other receivables	1,837,037	2,212,324	1,410,408
Current tax assets and liabilities	4,168,869	1,026,963	2,557,465
Other financial liabilities (Financial Debt and Derivative Instruments)	2,743,973	980,933	(1,637,291)
Trade and other payables	(103,883)	241,532	16,939
Other provisions	(610,605)	(196,777)	—
Other non-financial liabilities	(101,358)	(643)	(1,688)
Subtotal	7,998,839	4,264,332	2,382,630
Inventories	20,926	—	—
Intangible assets other than goodwill	(77,239)	142	203
Property plant and equipment	1,451,708	764,982	1,132,453
Deferred tax liability	(1,429,582)	(548,505)	—
Equity	(2,143,830)	(2,434,384)	(5,805,120)
Other Provisions of Services	(1,849)	(1,246)	—
Energy Sales	—	—	(1,352,295)
Energy Purchases	—	—	432
Work for Fixed Assets	—	—	103,512
Personal expenses	161,385	130,213	166,715
Other fixed operating expenses	139,968	108,226	23,714
Financial income	(231,931)	(204,137)	(367,059)
Financial expenses	9,125	6,145	732,547
Subtotal Hyperinflation result (1)	(2,101,319)	(2,178,564)	(5,364,898)
Gains from indexed assets and liabilities net	5,897,520	2,085,768	(2,982,268)
	For the years ended December 31,
	2021	2020	2019
Foreign Currency Exchange Differences (**)	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	1,863,916	10,110,166	(937,177)
Other financial assets	8,922,639	6,316,333	2,052,540
Other non-financial assets	(5,754,262)	6,086,388	(1,712,690)
Trade and other receivables (2)	59,815,718	(24,262,013)	1,811,670
Current tax assets and liabilities	47,239	(4,361,506)	(1,633,471)
Other financial liabilities (Financial Debt and Derivative Instruments)	(22,271,858)	(10,265,859)	(8,147,939)
Trade and other payables (2)	(27,326,682)	(1,023,613)	642,558
Accounts payable to related entities	(30,778,711)	(4,974,416)	(2,987,980)
Other non-financial liabilities	147,633	(897,711)	500,379
Total Foreign Currency Exchange Differences	(15,334,368)	(23,272,231)	(10,412,110)

(1) 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).

(2) Contains the exchange effect of the dollarization of trade receivables and payables of ThCh$51,620,491 and ThCh$23,048,375, respectively (Trade receivables and Payables ThCh$36,494,889 and ThCh$11,234,506, respectively as of December 31, 2020), generated by the temporary mechanism for stabilizing electricity prices for customers subject to rate regulation, as established in Law No. 21,185 (see Note 8).

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34.  INFORMATION BY SEGMENT

34.1. 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 were defined based on IFRS 8.9 and on the criteria described in IFRS 8.12.

Generation Segment: The electricity generation segment is composed 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 non-conventional renewable energies through our subsidiary Enel Green Power Chile S.A.

Distribution and Transmission Segments: The electricity distribution business is operated by Enel Distribución Chile S.A. and its subsidiary Enel Colina S.A. They operate under a distribution concession regime, with service obligations and regulated tariffs. The electricity transmission business is operated by Enel Transmission Chile S.A. and its subsidiary Empresa de Transmission Chena S.A., which operate under an open access regime, making their network infrastructures available to any interested user under non-discriminatory conditions.

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 and Transmission Business at the reportable segment level. In addition, in order to assist the decision-making process, the Planning & Control Department at Parent Company level prepares internal reports containing combined information at the reportable segment level about the main key performance indicators (KPIs), such as: EBITDA, Gross Margin, Total Capex, Total Opex, Profit for the Year, Total Energy Generation, Distribution 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 and transmission 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 methods used to distribute its products or provide the services: generators normally sell energy through energy bids, whereas distributors and transmitters deliver energy in their concession area or area where their facilities operate; and

d) The nature of the regulatory framework for public electricity services: the regulatory framework distinguishes between Generation companies, which can freely decide whether to sell their energy and capacity to regulated or unregulated customers; and Distribution and Transmission companies, which, as natural monopolies, are subject to regulated tariffs and are required free access to their networks.

The Company’s highest decision-making authority 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.

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34.2 Generation and Distribution

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
ASSETS
CURRENT ASSETS	704,953,231	581,661,790	381,074,530	282,024,842	182,224,732	162,714,564	1,268,252,493	1,026,401,196
Cash and cash equivalents	4,059,117	4,971,820	1,964,579	3,657,471	303,951,444	323,406,722	309,975,140	332,036,013
Other current financial assets	2,747,199	2,562,093	1,238,240	29,977	55,976	760,334	4,041,415	3,352,404
Other current non-financial assets	53,654,303	11,665,802	4,215,329	2,830,106	8,956,365	5,305,665	66,825,997	19,801,573
Trade and other current receivables	319,374,477	285,241,891	344,375,668	259,172,712	24,434,982	10,472,036	688,185,127	554,886,639
Current accounts receivable from related companies	262,328,437	232,991,789	11,763,448	4,269,460	(217,651,797)	(179,285,124)	56,440,088	57,976,125
Inventories	25,601,423	18,163,284	2,997,869	3,397,415	2,648,418	1,749,330	31,247,710	23,310,029
Current tax assets	37,188,275	26,065,111	14,519,397	8,667,701	59,829,344	305,601	111,537,016	35,038,413
NON-CURRENT ASSETS	5,869,269,137	4,722,779,027	1,590,778,338	1,369,182,558	772,023,628	786,108,803	8,232,071,103	6,878,070,388
Other non-current financial assets	38,915,283	20,660,446	—	4	463,782	—	39,379,065	20,660,450
Other non-current non-financial assets	85,177,306	62,608,451	3,076,764	2,791,875	1,362,578	386,889	89,616,648	65,787,215
Trade and other non-current receivables	100,176,330	166,469,458	401,098,758	277,378,406	14,511,252	1,168,702	515,786,340	445,016,566
Non-Current accounts payable from related companies	148,999,820	141,649,129	—	—	(142,651,819)	(93,290,214)	6,348,001	48,358,915
Investments accounted for using the equity method	6,095,038	9,551,139	—	—	3,828,895	3,441,664	9,923,933	12,992,803
Intangible assets other than goodwill	101,567,646	94,464,506	82,839,363	65,335,352	6,814,546	5,314,663	191,221,555	165,114,521
Goodwill	34,159,548	32,682,252	2,240,478	2,240,478	884,678,172	880,782,639	921,078,198	915,705,369
Property, plant and equipment	5,031,641,934	4,037,877,000	1,093,444,389	1,015,249,248	(14,397,562)	(19,629,776)	6,110,688,761	5,033,496,472
Investment property	—	—	—	—	7,539,005	7,421,940	7,539,005	7,421,940
Assets for right of use	156,537,247	50,373,648	4,244,878	5,117,436	6,736	11,108	160,788,861	55,502,192
Deferred tax assets	165,998,985	106,442,998	3,833,708	1,069,759	9,868,043	501,188	179,700,736	108,013,945
TOTAL ASSETS	6,574,222,368	5,304,440,817	1,971,852,868	1,651,207,400	954,248,360	948,823,367	9,500,323,596	7,904,471,584

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES	1,160,666,050	903,590,885	746,688,757	335,412,469	224,971,410	(193,523,189)	2,132,326,217	1,045,480,165
Other current financial liabilities	79,273,121	155,592,371	150,674	77,554	8,916,095	1,829,216	88,339,890	157,499,141
Current lease liabilities	9,242,799	5,495,257	1,853,542	1,505,677	8,677	6,777	11,105,018	7,007,711
Trade and other current payables	668,905,400	416,425,675	262,862,315	190,709,618	46,556,772	20,822,729	978,324,487	627,958,022
Current accounts payable to related companies	373,766,861	237,326,397	465,826,390	118,883,364	165,004,707	(226,155,799)	1,004,597,958	130,053,962
Other current provisions	17,906,766	2,933,069	1,266,514	—	583,037	501,735	19,756,317	3,434,804
Current tax liabilities	2,461,869	65,963,158	9,202,761	95,556	1,484,077	6,301,230	13,148,707	72,359,944
Other current non-financial liabilities	9,109,234	19,854,958	5,526,561	24,140,700	2,418,045	3,170,923	17,053,840	47,166,581
NON-CURRENT LIABILITIES	2,688,289,480	1,647,789,150	371,287,907	415,149,858	961,927,094	1,201,777,912	4,021,504,481	3,264,716,920
Other non-current financial liabilities	902,487,329	774,737,983	—	4	1,039,387,049	708,851,139	1,941,874,378	1,483,589,126
Non-current lease liabilities	145,264,339	41,147,046	3,292,221	3,704,860	499	5,901	148,557,059	44,857,807
Trade and other non-current payables	3,788,764	4,286,773	175,608,162	112,922,799	486	487	179,397,412	117,210,059
Non-current accounts payable to related companies	1,245,386,779	457,825,939	142,651,760	228,805,329	(87,979,442)	477,413,194	1,300,059,097	1,164,044,462
Other long-term provisions	181,398,929	194,653,912	12,319,020	15,587,759	394,765	—	194,112,714	210,241,671
Deferred tax liabilities	192,175,894	152,083,137	11,639,461	20,212,892	(6,398,405)	(4,238,467)	197,416,950	168,057,562
Non-current provisions for employee benefits	17,787,446	23,054,360	24,641,998	32,738,247	16,522,142	19,745,658	58,951,586	75,538,265
Other non-current non-financial liabilities	—	—	1,135,285	1,177,968	—	—	1,135,285	1,177,968
EQUITY	2,725,266,838	2,753,060,782	853,876,204	900,645,073	(232,650,144)	(59,431,356)	3,346,492,898	3,594,274,499
Equity attributable to owners of the parent	2,725,266,838	2,753,060,782	853,876,204	900,645,073	(232,650,144)	(59,431,356)	3,097,868,353	3,351,915,790
Issued capital	1,264,108,957	1,403,737,121	230,137,980	230,137,980	2,387,856,533	2,248,228,369	3,882,103,470	3,882,103,470
Retained earnings	1,455,385,686	1,473,514,878	946,912,262	988,991,623	(799,111,653)	(715,068,696)	1,603,186,295	1,747,437,805
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	(79,739,297)	42,929,658	(323,528,258)	(318,838,750)	(1,735,529,312)	(1,759,357,684)	(2,387,421,412)	(2,277,625,485)
Non-controlling interests	—	—	—	—	—	—	248,624,545	242,358,709
Total Liabilities and Equity	6,574,222,368	5,304,440,817	1,971,852,868	1,651,207,400	954,248,360	948,823,367	9,500,323,596	7,904,471,584

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
	2021	2020	2019	2021	2020	2019	2021	2020	2019	2021	2020	2019
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
REVENUES	1,953,287,738	1,577,422,263	1,726,611,508	1,201,833,293	1,382,068,220	1,412,871,738	(299,891,496)	(374,088,286)	(368,648,886)	2,855,229,535	2,585,402,197	2,770,834,360
Revenues	1,934,131,175	1,543,647,794	1,581,230,963	1,193,549,267	1,376,425,433	1,408,588,042	(297,998,038)	(371,688,910)	(365,242,682)	2,829,682,404	2,548,384,317	2,624,576,323
Energy sales	1,803,343,706	1,494,203,779	1,472,565,933	1,103,758,191	1,270,159,653	1,318,386,716	(321,853,728)	(383,626,832)	(385,049,407)	2,585,248,169	2,380,736,600	2,405,903,242
Other sales	129,626,809	38,825,239	97,870,470	5,347,333	6,601,069	9,365,186	21,936,360	13,444,564	16,878,136	156,910,502	58,870,872	124,113,792
Other services rendered	1,160,660	10,618,776	10,794,560	84,443,743	99,664,711	80,836,140	1,919,330	(1,506,642)	2,928,589	87,523,733	108,776,845	94,559,289
Other operating income	19,156,563	33,774,469	145,380,545	8,284,026	5,642,787	4,283,696	(1,893,458)	(2,399,376)	(3,406,204)	25,547,131	37,017,880	146,258,037
RAW MATERIALS AND CONSUMABLES USED	(1,346,981,551)	(616,852,308)	(678,187,609)	(974,857,661)	(1,116,324,483)	(1,114,936,281)	310,533,808	358,731,152	371,918,639	(2,011,305,404)	(1,374,445,639)	(1,421,205,251)
Energy purchases	(660,360,745)	(177,049,909)	(160,044,206)	(933,785,293)	(1,060,494,642)	(1,056,562,636)	297,153,754	372,681,097	381,322,099	(1,296,992,284)	(864,863,454)	(835,284,743)
Fuel consumption	(374,868,794)	(231,176,490)	(230,944,414)	—	—	—	—	—	—	(374,868,794)	(231,176,490)	(230,944,414)
Transportation expenses	(159,477,763)	(113,704,101)	(169,062,680)	(12,947,272)	(23,694,571)	(22,725,942)	20,686,811	(4,141,015)	(5,060,166)	(151,738,224)	(141,539,687)	(196,848,788)
Other miscellaneous supplies and services	(152,274,249)	(94,921,808)	(118,136,309)	(28,125,096)	(32,135,270)	(35,647,703)	(7,306,757)	(9,808,930)	(4,343,294)	(187,706,102)	(136,866,008)	(158,127,306)
CONTRIBUTION MARGIN	606,306,187	960,569,955	1,048,423,899	226,975,632	265,743,737	297,935,457	10,642,312	(15,357,134)	3,269,753	843,924,131	1,210,956,558	1,349,629,109
Other work performed by the entity and capitalized	13,352,715	15,581,738	8,887,421	17,403,271	9,805,315	8,723,440	401,210	152,263	0	31,157,196	25,539,316	17,610,861
Employee benefits expense	(71,617,409)	(65,564,485)	(62,871,525)	(49,357,037)	(37,496,730)	(34,828,194)	(42,370,708)	(34,165,533)	(31,905,237)	(163,345,154)	(137,226,748)	(129,604,956)
Other expenses	(126,899,337)	(121,366,276)	(120,522,841)	(71,488,295)	(79,580,559)	(70,678,241)	8,836,807	10,353,501	7,057,942	(189,550,825)	(190,593,334)	(184,143,140)
GROSS OPERATING INCOME	421,142,156	789,220,932	873,916,954	123,533,571	158,471,763	201,152,462	(22,490,379)	(39,016,903)	(21,577,542)	522,185,348	908,675,792	1,053,491,874
Depreciation and amortization expense	(164,579,061)	(185,479,080)	(196,623,025)	(47,931,057)	(45,583,947)	(40,705,580)	1,582,462	1,106,008	701,218	(210,927,656)	(229,957,019)	(236,627,387)
Impairment losses (reversal of impairment losses) recognized in profit or loss	(33,035,731)	(698,453,039)	(280,020,263)	—	—	—	136,877	646,598	(742,389)	(32,898,854)	(697,806,441)	(280,762,652)
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9.	(691,132)	(1,305,341)	(1,338,599)	(17,419,025)	(12,998,719)	(8,153,419)	(655,018)	(863,647)	(554,982)	(18,765,175)	(15,167,707)	(10,047,000)
OPERATING INCOME	222,836,232	(96,016,528)	395,935,067	58,183,489	99,889,097	152,293,463	(21,426,058)	(38,127,944)	(22,173,695)	259,593,663	(34,255,375)	526,054,835
FINANCIAL RESULT	(62,697,134)	(80,090,891)	(101,324,905)	(11,685,010)	5,929,058	5,232,127	(82,677,420)	(38,272,941)	(54,800,225)	(157,059,564)	(112,434,774)	(150,893,003)
Financial income	8,178,108	15,080,015	15,241,046	19,109,146	22,717,208	22,742,687	(866,854)	(1,636,763)	(10,584,458)	26,420,400	36,160,460	27,399,275
Cash and cash equivalents	29,479	597,718	3,556,554	1,093,452	1,562,194	1,456,253	2,136,870	5,164,145	3,960,799	3,259,801	7,324,057	8,973,606
Other financial income	8,148,629	14,482,297	11,684,492	18,015,694	21,155,014	21,286,434	(3,003,724)	(6,800,908)	(14,545,257)	23,160,599	28,836,403	18,425,669
Financial costs	(94,212,401)	(59,088,322)	(111,219,566)	(30,325,667)	(17,696,544)	(19,061,123)	(49,505,048)	(50,623,905)	(34,617,211)	(174,043,116)	(127,408,771)	(164,897,900)
Bank loans	(2,465,972)	(7,112,931)	(11,813,855)	—	(33,244)	(40,508)	(261,725)	(4,855)	(2,633,337)	(2,727,697)	(7,151,030)	(14,487,700)
Secured and unsecured obligations	(47,518,870)	(47,654,290)	(45,714,879)	—	—	—	(38,471,477)	(36,613,957)	(36,103,685)	(85,990,347)	(84,268,247)	(81,818,564)
Others	(44,227,559)	(4,321,101)	(53,690,832)	(30,325,667)	(17,663,300)	(19,020,615)	(10,771,846)	(14,005,093)	4,119,811	(85,325,072)	(35,989,494)	(68,591,636)
Income from indexation units	3,385,938	(703,130)	(5,157,076)	1,851,124	1,124,304	1,843,435	660,458	1,664,594	331,373	5,897,520	2,085,768	(2,982,268)
Foreign exchange profits (losses)	19,951,221	(35,379,454)	(189,309)	(2,319,613)	(215,910)	(292,872)	(32,965,976)	12,323,133	(9,929,929)	(15,334,368)	(23,272,231)	(10,412,110)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	3,157,673	2,424,250	366,089	361	—	—	19,375	1,085,142	—	3,177,409	3,509,392	366,089
Other gains (losses)	10,137,284	9,478,528	1,683,246	2,171,056	10,287	12	(2,171,056)	—	109,943	10,137,284	9,488,815	1,793,201
Gain (loss) from other investments	10,137,284	94,490	152,557	2,171,056	10,287	12	(2,171,056)	—	109,943	10,137,284	104,777	262,512
Gain (loss) from the sale of assets	—	9,384,038	1,530,689	—	—	—	—	—	—	—	9,384,038	1,530,689
Profit (loss) before taxes	173,434,055	(164,204,641)	296,659,497	48,669,896	105,828,442	157,525,602	(106,255,159)	(75,315,743)	(76,863,977)	115,848,792	(133,691,942)	377,321,122
Income tax	(24,666,990)	97,419,625	(40,347,869)	2,275,431	(23,421,217)	(38,748,555)	7,252,901	7,306,699	17,868,520	(15,138,658)	81,305,107	(61,227,904)
PROFIT (LOSS)	148,767,065	(66,785,016)	256,311,628	50,945,327	82,407,225	118,777,047	(99,002,258)	(68,009,044)	(58,995,457)	100,710,134	(52,386,835)	316,093,218
	—		—	—		—	—		—	—	—	—
Profit (loss) attributable to	148,767,065	(66,785,016)	256,311,628	50,945,327	82,407,225	118,777,047	(99,002,258)	(68,009,044)	(58,995,457)	100,710,134	(52,386,835)	316,093,218
Profit (loss) attributable to owners of the parent	—	—	—	—	—	—	—	—	—	85,153,969	(50,860,313)	296,153,605
Profit (loss) attributable to non-controlling interests	—	—	—	—	—	—	—	—	—	15,556,165	(1,526,522)	19,939,613
	Generation			Distribution			Holdings eliminations			Total
	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF CASH FLOWS
Net cash flows from (used in) operating activities	445,854,355	551,979,917	754,113,794	17,684,402	111,689,249	50,246,845	(50,645,942)	92,197,032	(60,648,920)	412,892,815	755,866,198	743,711,719
Net cash flows from (used in) investing activities	(604,078,037)	(100,557,328)	(426,038,012)	(85,111,489)	(111,939,127)	(28,896,947)	(47,365,284)	(342,154,935)	143,403,148	(736,554,810)	(554,651,390)	(311,531,811)
Net cash flows from (used in) financing activities	157,788,515	(469,832,875)	(453,927,358)	67,203,137	1,578,034	(23,901,991)	68,239,857	340,585,507	37,393,661	293,231,509	(127,669,334)	(440,435,688)

The Holding, Eliminations and Others column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-124

35.  GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS

35.1 Direct guarantees

As of December 31, 2021, Enel Chile had future energy purchase commitments amounting to ThCh$7,347,166,465 (ThCh$6,458,055,505 as of December 31, 2020).

35.2 Indirect guarantees

			Debtor			Outstanding balance as of
Contract	Maturity	Creditor of Guarantee	Company	Relationship	Type of Guarantee	Currency	12-31-2021 ThCh$	12-31-2020 ThCh$
B Bond (*)	October 2028	Bondholders Enel Américas´ Bond Program	Enel Américas	Companies divided from the original debtor Enersis (solidarity debtor Enel Chile)	Joint and several co-signer	UF	2,803,327	7,672,851
Credit opening contract	November 2022	Pto. GDN BID	Enel Green Power Chile S.A.	Subsidiary	Guarantor	US$	25,389,270	21,368,491
Credit opening contract	December 2021	Scotiabank Chile	Enel Green Power Chile S.A.	Subsidiary	Guarantor	US$	-	106,811,188
Warranty contract	December 2027	Enel Finance International N.V.	Enel Green Power Chile S.A.	Subsidiary	Guarantor	US$	-	458,115,841

(*)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.

35.3 Litigation and arbitration proceedings

As of the date of these consolidated financial statements, the most relevant litigation and arbitration proceedings of Enel Chile and its subsidiaries are the following:

1.Enel Chile

1.1. In October 2020, Inversiones Tricahue S.A. filed a tort liability lawsuit against Enel Chile, 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. On December 6, 2021, the court opened an evidentiary period; however, such resolution has not yet been notified to the parties.

1.2. On August 25, 2021, three investors, Inversiones Inmobiliarias y Asesorías Anaelen Ltda., Inversiones León Obrecht Ltda. and Inversiones Antares Ltda., filed a criminal complaint with the 7th Criminal Court of Santiago. The claim for the crime of mismanagement was filed against the Directors of Empresa Eléctrica Pehuenche S.A. and the crime of infringement of the duties of supervision and oversight was filed against Enel Chile. The second claim was based on the fact that Enel Chile allegedly allowed the crime of mismanagement to be committed by Pehuenche. On August 25, 2021 the 7th Criminal Court of Santiago admitted the processing of the complaint and, afterwards, sent the case file to the Public Prosecutor’s Office of the Central-North Metropolitan Regional Prosecutor’s Office. The case is in the informal investigation stage.

2.Enel Generación Chile S.A.

2.1. On August 20, 2021, Inversiones Tricahue S.A. filed a request for a precautionary injunction against Enel Generación Chile S.A. with the 19th Civil Court of Santiago to enjoin Enel Generación Chile S.A. from entering into acts and contracts. In this context, on August 18, 2021, a precautionary injunction was decreed prohibiting Enel Generación Chile S.A. from executing acts or entering into agreements with respect to the shares owned by it in Empresa Eléctrica Pehuenche S.A. that would entail the merger of both companies. Consequently, Enel Generación Chile S.A. abstained from participating in the Extraordinary Shareholders’ Meeting of Empresa Eléctrica Pehuenche S.A. held on September 28, 2021, which was convened to decide on the merger of the latter with Enel Generación Chile S.A., so this transaction could not be approved. It should be noted that the shareholders of Enel Generación Chile S.A. had approved the aforementioned merger at an Extraordinary

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Shareholders’ Meeting of Enel Generación Chile S.A. held on August 27, 2021. In addition to the above, Inversiones Tricahue S.A. announced an arbitration claim against Enel Generación Chile S.A. and requested the appointment of an arbitrator in compulsory arbitration. At the appointment hearing there was no agreement between the parties, and the court, in view of the disagreement, appointed an arbitrator on December 16, 2021.

3.Enel Distribución Chile S.A.

3.1. The National Consumer and User Protection Agency, CONADECUS, filed a class action lawsuit against Enel Distribución Chile S.A. for violation of the collective and diffuse interest of consumers due to non-compliance with Law No. 19,496, the amount of which is undetermined. On November 5, 2021 Enel Distribución Chile S.A. filed a motion for reconsideration against the resolution that allows the lawsuit to proceed. As of December 31, 2021, the resolution on the motion is pending.

3.2. The National Consumer Service, SERNAC, filed a lawsuit against Enel Distribución Chile S.A. and Empresa Eléctrica Colina on the basis of the power outages that occurred between January 29 and February 2, 2021, the amount of which is undetermined. On December 13, 2021 Enel Distribución Chile S.A. filed a motion for reconsideration against the decision that allows the lawsuit to proceed. As of December 31, 2021, the resolution on the motion is pending.

3.3. The Municipality of Recoleta filed an enforcement lawsuit against Enel Distribución Chile S.A. by virtue of the provisions of Ordinance No. 75 of 2021, on “Municipal Fees for the Municipality of Recoleta”, for the amount of ThCh$ 2,344,896.

3.4. By means of Exempt Resolution No. 24,805 dated July 20, 2018, the Superintendence of Electricity and Fuels confirmed the fine imposed on Enel Distribución Chile S.A. equivalent to 80,000 UTM (ThCh$4,333,680), by unfavorably resolving the motion for reconsideration against Exempt Resolution No. 21,788 dated December 29, 2017. On July 27, 2021, the court issued a judgment dismissing Enel Distribución Chile S.A.’s request and on August 6, 2021, Enel Distribución Chile S.A. filed an appeal, which was granted on August 30, 2021. On September 8, 2021, the case entered the Supreme Court and on September 24, 2021, the hearing was held. The case is awaiting the court’s judgment.

3.5. By means of Exempt Resolution No. 24,821 dated July 23, 2018, the Superintendence of Electricity and Fuels confirmed the fine imposed on Enel Distribución Chile S.A. equivalent to 10,000 UTM (ThCh$ 541,710), by unfavorably resolving the motion for reconsideration against Exempt Resolution No. 21.790 dated December 29, 2017. On July 27, 2021, the court issued a judgment dismissing Enel Distribución Chile S.A.’s request and on August 6, 2021, Enel Distribución Chile S.A. filed an appeal. On September 24, 2021, the hearing was held and the case is awaiting the court’s judgment.

3.6. By means of Exempt Resolution No. 27,005 dated December 28, 2018 (received on January 28, 2019), the Superintendence of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. equivalent to 16,911 UTM (ThCh$916,086), on the basis 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 on September 9, 2020. On April 8, 2021, the court issued a judgment, which partially accepted the arguments raised by Enel Distribución Chile S.A., and reduced the fine to 5,925 UTM (ThCh$320,963). The Superintendence of Electricity and Fuels appealed the decision and the case was sent to the Supreme Court on April 23, 2021. On May 5, 2021, the respective arguments were made before the Supreme Court. To date there has been no ruling, and the case is still pending judgment by the Supreme Court.

3.7. By means of Exempt Resolution No. 33,196 dated August 25, 2020, the Superintendence of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. equivalent to 22,000 UTM (ThCh$1,191,762), on the basis that Enel Distribución Chile S.A. did not comply with article 4-2 of the regulations of technical quality of the distribution service. The resolution derived from the information provided by Enel Distribución Chile S.A. in

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the proceedings captioned “outages year 2018”, which indicated that Enel Distribución Chile S.A. exceeded the maximum limit of System Average Interruption Duration Index (SAIDI), established in the current regulations in at least four districts. An appeal was filed against this resolution with the Court of Appeals of Santiago on May 6, 2021. On November 19, 2021, a ruling was issued, dismissing the appeal. On December 1, 2021, Enel Distribución Chile S.A. appealed the ruling, and the case was sent to the Supreme Court on December 7, 2021. The hearing for the arguments was held on December 27, 2021, where the case is being considered.

4.Enel Transmisión Chile S.A.

4.1. By means of Exempt Resolution No. 32,918 dated July 14, 2020, the Superintendence of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. equivalent to 10,000 UTM (ThCh$ 541,710), on the basis that on March 7, 2019 Enel Distribución Chile S.A. failed to comply with its duty to maintain the electric supply at the Brasil Substation. Enel Distribución Chile S.A. filed a request for reconsideration, which was rejected and the fine was confirmed. Consequently, on September 3, 2021, Enel Distribución Chile S.A. filed an appeal against such resolution with the Court of Appeals of Santiago. On November 15, 2021, the Court of Appeals of Santiago requested a report from the Superintendence of Electricity and Fuels, which was issued on November 30, 2021. On December 3, 2021, the case was passed to the reporting judge.

In relation to the litigation proceedings described above, the Enel Chile Group has established provisions for ThCh$6,863,141 as of December 31, 2021 (see Note 24). There are other litigations that also have associated provisions but are not described in this note since individually they represent immaterial amounts. Management considers 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.

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35.4. 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.

Financial restrictions	Enel Chile	Enel Chile	Enel Chile	Enel Generación Chile	Enel Generación Chile
Instrument type with restriction	Cred. with Fin. Inst.	Cred. with Fin. Inst.	Yankee bonds	Yankee bonds	Yankee bonds
Restriction to be fulfilled by Informant or Subsidiary	Any financial debt that Enel Chile maintains, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$150 million in an individual debt.	Any financial debt that Enel Chile maintains, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$150 million in an individual debt.	Any financial debt that Enel Chile maintains, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$150 million in an individual debt.	Any financial debt held by Enel Generación Chile or its Chilean subsidiaries, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$30 million in an individual debt.	Any financial debt held by Enel Generación Chile or its Chilean subsidiaries, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$50 million in an individual debt.
Creditor	BBVA, S.A. (Administrative Agent)	Santander Chile, SMBC and Scotiabank	Bank of New York Mellon (Representative of Bondholders)	Bank of New York Mellon (Representative of Bondholders)	Bank of New York Mellon (Representative of Bondholders)
Registration Number	-	-	ISIN: US29278DAA37	ISIN: US29244TAC53; US29244TAB7; US29244TAA9	ISIN: US29246RAA14
Indicator name or financial ratio	cross default	cross default	cross default	cross default	cross default
Measurement frequency	Quarterly	Quarterly	Quarterly	Quarterly	Quarterly
Calculation mechanism or definition of the indicator or ratio	Debt in arrears greater than US$150 million of principal individually.	Debt in arrears greater than US$150 million of principal individually.	Debt in arrears greater than US$150 million of principal individually.	Debt in arrears greater than US$30 million of principal individually.	Debt in arrears greater than US$50 million of principal individually.
Restriction that must be fulfilled (Range, Value and Unit of measure)	Not have individual debts in arrears greater than US$150 million.	Not have individual debts in arrears greater than US$150 million.	Not have individual debts in arrears greater than US$150 million.	Not have individual debts in arrears greater than US$30 million.	Not have individual debts in arrears greater than US$50 million.
Indicator or ratio determined by the company	There are no outstanding debts for an amount greater than US$150 million individually.	There are no outstanding debts for an amount greater than US$150 million individually.	There are no outstanding debts for an amount greater than US$150 million individually.	There are no outstanding debts for an amount greater than US$30 million individually.	There are no outstanding debts for an amount greater than US$50 million individually.
Compliance YES/NO	Yes	Yes	Yes	Yes	Yes
Accounts used in the calculation of the indicator or ratio	-	-	-	-	-

Financial restrictions	Enel Generación Chile	Enel Generación Chile	Enel Green Power Chile	Enel Distribución Chile
Instrument type with restriction	Series H and M Bonds	Cred. with Fin. Inst.	Cred. with Fin. Inst.	Cred. with Fin. Inst.
Restriction to be fulfilled by Informant or Subsidiary	Any financial debt that Enel Generación Chile maintains, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$50 million in an individual debt.	Any financial debt held by Enel Generación Chile, for any amount in arrears.	Any financial debt held by Enel Green Power Chile or material subsidiary, for any amount in arrears, and that the principal of the debt that gives rise to the cross default exceeds US$50 million individually.	Any financial debt held by Enel Distribución Chile, for any amount in arrears.
Creditor	Banco Santander (Representative of Bondholders)	Banco Santander Chile	Inter-American Development Bank	Banco Santander Chile, Security and Scotiabank
Registration Number	Registration in the CMF Securities Registry No. 317 for Series H and No. 522 for Series M	-	-	-
Indicator name or financial ratio	cross default	cross default	cross default	cross default
Measurement frequency	Quarterly	Quarterly	Quarterly	Quarterly
Calculation mechanism or definition of the indicator or ratio	Debt in arrears greater than US$50 million of principal individually.	Delinquent debt.	Debt in arrears greater than US$50 million of principal individually.	Delinquent debt.
Restriction that must be fulfilled (Range, Value and Unit of measure)	Not have individual debts in arrears greater than US$50 million.	Not have individual debts in arrears.	Not have individual debts in arrears greater than US$50 million.	Not have individual debts in arrears.
Indicator or ratio determined by the company	There are no outstanding debts for an amount greater than US$50 million individually.	There are no delinquent debts.	There are no outstanding debts for an amount greater than US$50 million individually.	There are no delinquent debts.
Compliance YES/NO	Yes	Yes	Yes	Yes
Accounts used in the calculation of the indicator or ratio	-	-	-	-

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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.

Financial restrictions	Enel Generación Chile	Enel Generación Chile	Enel Generación Chile	Enel Generación Chile
Instrument type with restriction	Series H and M Bonds	Series H and M Bonds	Series H and M Bonds	Series H Bonds
Restriction to be fulfilled by Informant or Subsidiary	A ratio between Financial Obligations and Total Capitalization must be maintained of less than or equal to 0.64.	Maintain a Minimum Equity of Ch$761,661 million, a limit that is updated at the end of each fiscal year, as established in the contract.	Maintain a Financial Expense Coverage Coefficient of greater than or equal to 1.85.	Maintain a Net Active Position with Related Companies not exceeding the equivalent amount in pesos, legal tender, of US$500 million, according to the exchange rate observed on the date of its calculation.
Creditor	Banco Santander (Representative of Bondholders)	Banco Santander (Representative of Bondholders)	Banco Santander (Representative of Bondholders)	Banco Santander (Representative of Bondholders)
Registration Number	Registration in the CMF Securities Registry No. 317 for Series H and No. 522 for Series M	Registration in the CMF Securities Registry No. 317 for Series H and No. 522 for Series M	Registration in the CMF Securities Registry No. 317 for Series H and No. 522 for Series M	Registration in the Securities Registry of CMF No. 317
Indicator name or financial ratio	Consolidated Indebtedness Level	Equity Attributable to the Parent Company	Financial Expenses Coverage Coefficient	Net Active Position with Related Companies
Measurement frequency	Quarterly	Quarterly	Quarterly	Quarterly
Calculation mechanism or definition of the indicator or ratio	Financial Obligations corresponding to the sum between Loans that accrue interest, current, Loans that accrue interest, non-current, Other financial liabilities, current, Other financial liabilities, non-current and Other obligations guaranteed by the Issuer or its subsidiaries, while Total Capitalization is the sum between Financial Obligations and Total Equity.	The Equity corresponds to the Equity attributable to the owners of the parent company, which is contrasted with the level of Minimum Equity that will be readjusted by a percentage, provided it is positive, of the annual variation of the Consumer Price Index multiplied by the difference between 1 minus the ratio of Non-Monetary Assets in Chile recorded in pesos and the Equity Attributable to the Parent Company. If the annual variation of the Consumer Price Index is negative or if the ratio between Non-Monetary Assets in Chile recorded in pesos and Equity Attributable to the Parent Company is greater than one, there will be no readjustment in that year.	Financial expense coverage is the quotient between: i) Gross operating profit, plus Financial income and dividends received from associated companies, and ii) Financial expenses; both items refer to the period of four consecutive quarters ending at the end of the quarter being reported.	The Net Active Position with Related Companies is the difference between: i) the sum of Accounts Receivable from Related Entities of Current and Non-Current Assets and ii) the sum of Accounts Payable to Related Entities of Current and Non-Current Liabilities. The amounts corresponding to those that jointly comply with the following must be excluded from the foregoing: i) operations lasting less than 180 days, and ii) operations arising from the ordinary course of business of Enel Generación Chile or its subsidiaries.
Restriction that must be fulfilled (Range, Value and Unit of measure)	A ratio between Financial Obligations and Total Capitalization must be maintained of less than or equal to 0.64.	Maintain a Minimum Equity of Ch$761,661 million, a limit that is updated at the end of each fiscal year, as established in the contract.	Maintain a Financial Expense Coverage Coefficient of greater than or equal to 1.85.	Maintain a Net Active Position with Related Companies not exceeding the equivalent amount in pesos, legal tender, of US$500 million, according to the exchange rate observed on the date of its calculation.
Indicator or ratio determined by the company	0.37	Ch$1,499,913 million	3.99	-US$20.76 million
Compliance YES/NO	Yes	Yes	Yes	Yes
Accounts used in the calculation of the indicator or ratio	Financial Obligations and Total Capitalization	Equity attributable to the owners of the parent company.	Gross Operating Income and Financial Expenses	Current and Non-Current Accounts Receivable and Payable to Related Entities.

Finally, in most contracts, the acceleration of the debt due to non-compliance with covenants does not occur automatically. Certain conditions must be met, such as the expiration of remediation periods, among others.

As of December 31, 2021, Enel Chile and its subsidiaries comply with all the financial obligations summarized herein. They also comply with other financial obligations whose non-compliance could result in the acceleration of the maturity of its financial commitments.

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35.5. 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, Enel Distribución Chile S.A. 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.

Additionally, the Group issued guidelines to guarantee compliance with the measures introduced by the Chilean government and took a number of actions to adopt the most appropriate procedures to prevent and/or 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 ensures 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 proper and safe operation of the Company’s businesses, while safeguarding the health and safety of the Company’s employees.

On August 5, 2020, Law No. 21,249 the Law of Utility Services (Ley de Servicios Básicos) was enacted to prohibit electricity distribution companies from cutting services due to nonpayment for residential customers, small businesses, hospitals, and firefighters, among others. 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. These measures were effective through May 5, 2021.

Law No. 21,340 was enacted on May 13, 2021, which extends the effects of Law No. 21,249 until December 31, 2021. If the State of Constitutional Exception (Catastrophe) is still in force on this date, the terms will be extended up to 60 days from the end of this state. In addition, the maximum number of installments has been increased from 36 to 48.

In December 2021, the Chilean association of power distribution companies (“Empresas Eléctricas”) announced that its members (CGE, Chilquinta, Enel Distribución Chile S.A., and Grupo Saesa) would extend until January 31, 2022,

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the prohibition on cutting service to customers for non-payment of electricity bills, despite the law expiring on December 31, 2021.

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, 2021, these are fundamentally related to an increase in the impairment loss on trade receivables regarding the pre COVID-2019 situation (see Notes 3.g.3 and 8.d).

35.6. Other Commitments

On October 28, 2021, Enel X Chile acquired a 10% interest in Sociedad de Inversiones K Cuatro S.P.A. for ThCh$31,632, which is presented in other long-term financial assets (see Note 6). Sociedad de Inversiones K Cuatro S.P.A. was awarded the public bid for the complementary bus supply service for the Public Transportation System of the Province of Santiago and the communes of San Bernardo and Puente Alto. Consequently, it incorporated an SPV called Suministradora de Buses K Cuatro SpA.

As a result of this award, Suministradora de Buses K Cuatro SpA. will have to acquire 991 buses for subsequent leasing to the operators of the Public Transportation System. The approximate cost of this acquisition amounts to US$ 364 million plus VAT. In addition, the bidding conditions establish certain minimum capital obligations for Suministradora de Buses K Cuatro SpA, which are triggered with the notification of the supply order(s), a situation which at the time of issuance of these financial statements has not occurred. Once Suministradora de Buses K Cuatro SpA. is notified of the supply order(s), such company must make a capital increase estimated at US$ 63 million, of which, pro rata to its ownership interest, Enel X Chile must contribute its pro rata share of the capital increase through Sociedad de Inversiones K Cuatro S.P.A. (see Note 40).

36.  HEADCOUNT

Enel Chile’s personnel, as of December 31, 2021 and 2020, is as follows:

8
	12-31-2021
Country	Managers and key executives	Professionals and Technicians	Staff and others	Total
Chile	56	2,042	95	2,193
Argentina	—	5	17	22
Total	56	2,047	112	2,215
Average	57	2,048	116	2,221
	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

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37.  SANCTIONS

The following Group companies have received sanctions from administrative authorities:

1. Enel Generación Chile S.A.

1.1. As of December 31, 2021, the request for reconsideration of the sanction proceedings initiated by the Bío Bío Regional Health Ministry, by Act 180566 for alleged breaches by Enel Generación Chile S.A. of obligations and regulations related to waste disposal regulations in the Cantarrana landfill, is pending. The amount of the fine is 500 UTM (ThCh$27,086).

1.2. As of December 31, 2021, the Valparaíso Regional Health Ministry initiated sanction proceedings with respect to Inspection Record 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$27,086).

1.3. As of December 30, 2021, the Tarapacá Regional Health Ministry initiated sanction proceedings with respect to Inspection Record No. 000766 for the alleged breach by CELTA in the use of lime in the Tarapacá Thermal Power Station, which is pending resolution. The amount of this fine is 500 UTM (ThCh$27,086).

1.4. As of December 30, 2021, the Coquimbo Regional Health Ministry initiated sanction proceedings with respect to Inspection Record No. 10066, dated June 21, 2016 for the alleged breach committed by Gasatacama, (today Enel Generación Chile S.A., its successor by merger) for keeping waste in an unauthorized area, is pending resolution. The amount of this fine is 500 UTM (ThCh$27,086).

1.5. As of December 30, 2021, the Regional Health Ministry of the Metropolitan Region initiated sanction proceedings with respect to Exempt Resolution No. 20131261 for the alleged violation of health regulations due to COVID-19, which is pending resolution. The amount of this fine is 50 UTM (ThCh$2,709).

2. Enel Distribución Chile S.A.

2.1. By means of Exempt Resolution No. 13,630 dated May 23, 2016, the Superintendence of Electricity and Fuels imposed on Enel Distribución Chile S.A. a fine equivalent to 2,000 UTM (ThCh$108,342), alleging that Enel Distribución Chile S.A. failed to fulfill its obligation to maintain its electrical installations in good condition to meet quality and supply continuity requirements, 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 resolution.

2.2. By means of Exempt Resolution No. 33,646 dated November 23, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. equivalent to 15,000 UTM (ThCh$812,565), alleging that Enel Distribución Chile S.A. did not include Charges for the Use of the Transmission System in the April 2020 bills. Enel Distribución Chile S.A. has filed a request for reconsideration against this fine, which is pending resolution.

2.3. By means of Exempt Resolution No. 34,866 dated September 3, 2021, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A.  equivalent to 1,700 UTM (ThCh$92,091), alleging that Enel Distribución Chile S.A. did not comply with the provisions of the regulation of the general law of electric services, since it did not read the consumption of all its customers, nor did it estimate the consumption in accordance with the provisions of the current regulations, nor did it deliver the electricity bills to all its customers. Enel Distribución Chile S.A. has filed a request for reconsideration against this fine, which is pending resolution.

2.4. By means of Exempt Resolution No. 8480 dated September 20, 2021, the Superintendence of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. equivalent to 700 UTM (ThCh$37,920), alleging

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that Enel Distribución Chile S.A. did not comply with the maintenance of the José Domingo Cañas feeder in the district of Ñuñoa, to detect irregularities related to the presence of vegetation that puts the distribution line at risk due to falling branches or trees. Enel Distribución Chile S.A. filed a request for reconsideration against this fine. Enel Distribución Chile S.A.’s arguments were dismissed and the fine is now pending payment.

3. Enel Green Power Chile S.A.

3.1. By means of Resolution No. 1 dated August 9, 2018, the Superintendence of Environment alleged that Enel Green Power Chile S.A. committed sixteen environmental violations during the construction phase of the Cerro Pabellón geothermal power plant, of which thirteen were classified as minor and three as serious violations. The three serious violations relate to archaeological matters. A compliance program filed by Enel Green Power Chile S.A. was dismissed. Subsequently, by means of Resolution dated December 16, 2019, the Superintendence of Environment sent an official notice to the National Monuments Council to issue a statement regarding Geotérmica del Norte S.A.’s archaeological defenses and required information to determine the applicable sanction. As of December 31, 2021, the National Monuments Council’s statement is still pending.

In relation to the sanctions described above, the Enel Chile Group has established provisions for ThCh$5,094,403 as of December 31, 2021 (see Note 24). 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.

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38.  ENVIRONMENT

Environmental expenses for the years ended December 31, 2021, 2020 and 2019, are as follows:

				12-31-2021						12-31-2020
Disbursing Company	Project Name	Environmental Description	Project status [Completed, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements	Amount of prior period disbursement
		Waste Management	In progress	18,513	—	18,513	13,128	12-31-2021	31,641	32,425
	PEHUENCHE CENTRAL	Environmental Sanitation	In progress	4,467	—	4,467	3,528	12-31-2021	7,995	8,862
Pehuenche		Campaigns and Studies	In progress	714	—	714	4,235	12-31-2021	4,949	29,713
		Materials Environment	In progress	27,253	—	27,253	4,994	12-31-2021	32,246	10,415
	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	251,298	—	251,298	—	—	251,298	305,701
		This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	In progress	344,571	—	344,571	—	—	344,571	303,873
	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. 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.	In progress	192,924	—	192,924	—	—	192,924	340,704
	VEGETATION CONTROL IN MT/BT	Pruning of trees near the media network and low voltage.	In progress	3,136,872	—	3,136,872	—	—	3,136,872	3,296,066
Enel Distribución Chile S.A.	IMPROVEMENTS IN THE MT NETWORK	Replacement underground transformers by Technical Standard (PCB)	In progress	481,556	481,556	—	—	—	481,556	91,353
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in the Metropolitan Park.	In progress	2,875	—	2,875	—	—	2,875	1,374
	SEC STANDARDIZATION PROJECT (CAPEX)	Underground Networks Interaction Project between Enel and Metrogas	In progress	4,403,751	4,403,751	—	—	—	4,403,751	1,774,155
	OIL ANALYSIS AT TD OF POWER (OPEX)	Consider chromatographic analysis, furans, and physical-chemical analysis.	In progress	32,363	—	32,363	—	—	32,363	32,096
	REPLACING TRIFAS TRANSFORMERS BETTER QUALITY	This project corresponds to: - replacement of traditional network by Calpe BT - replacement of concentrical network by Calpe BT - replacement of transformers with loadability problems	In progress	5,330,561	5,330,561	—	—	—	5,330,561	3,649,294
	SILICA GEL REPLACEMENT IN POWER TRANSFORMERS	Considers the replacement of silica gel (hygroscopic salt) to one (1) power transformer.	In progress	5,837	—	5,837	—	—	5,837	—
	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	2,245,303	833,395	1,411,908	450,786	12-31-2021	2,696,089	1,195,131
Enel Generación Chile S.A.	ENVIRONMENTAL EXPENSES CC.TT.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	1,255,958	445,611	810,347	617,221	12-31-2021	1,873,179	3,568,968
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (C.H.)	In progress	378,958	—	378,958	263,737	12-31-2021	642,695	263,737
	Waste management	Contracts for the removal of hazardous and non-hazardous waste, and removal of household waste.	In progress	90,712	—	90,712	—	—	90,712	232,560
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	75,483	—	75,483	—	—	75,483	151,405
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	47,996	—	47,996	—	—	47,996	—
	Rent/Vehicle Expenses	Vehicle rental for environmental trips (field visits / Plants)	In progress	48,171	—	48,171	—	—	48,171	118,458
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	214,493	—	214,493	—	—	214,493	544,871
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	85,802	—	85,802	—	—	85,802	72,610
Enel Green Power Chile S.A.	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	6,743	—	6,743	—	—	6,743	39,657
	Outsourced Services	Other services (contracts with third parties)	In progress	213,326	—	213,326	—	—	213,326	519,458
	Permitting Framework Agreement	Management contract for environmental and sectoral permits	In progress	97,998	—	97,998	—	—	97,998	—
	Domestic Waste Removal	Household / domestic waste removal contract	In progress	40,320	—	40,320	—	—	40,320	—
	Environment Travel	Tickets - accommodation and viatics for site visit in facilities	In progress	3,045	—	3,045	—	—	3,045	140,368
	Waste Management	Contracts for vector control, deratization, disinsection.	In progress	65,536	—	65,536	—	—	65,536	54,910
	Environmental Sanitation	Monitoring and analysis of drinking water and sewage	In progress	12,865	—	12,865	—	—	12,865	20,819
	Water Analysis	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	3,780	—	3,780	—	—	3,780	—
	Campaigns and Studies	Buy environmental materials (containers, spill kit, others)	In progress	290,803	—	290,803	—	—	290,803	652,451
Geotérmica del Norte S.A.	Materials Environment	Contract for removal and cleaning of pits and sewage	In progress	5,294	—	5,294	—	—	5,294	3,650
	Treatment Plant Wastewater	Management contract for environmental and sectoral permits	In progress	947	—	947	—	—	947	6,140
	Permitting Framework Agreement	Household / domestic waste removal contract	In progress	2,677	—	2,677	—	—	2,677	—
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	4,000	—	4,000	—	—	4,000	—
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	53,384	—	53,384	—	—	53,384	76,595
Parque Eólico Talinay Oriente S.A.	Materials Environment	Buy environmental materials (containers, spill kit, others)	In progress	3,801	—	3,801	—	—	3,801	—
	Treatment Plant Wastewater	Contract for removal and cleaning of pits and sewage	In progress	250	—	250	—	—	250	2,087
	Domestic Waste Removal	Household / domestic waste removal contract	In progress	11,999	—	11,999	—	—	11,999	—
		Total		19,493,202	11,494,874	7,998,327	1,357,628	—	20,850,830	17,539,906

F-134

				12-31-2020
Disbursing Company	Project Name	Environmental Description	Project status [Completed, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
		Waste Management	In progress	13,128	—	13,128	19,298	12-31-2021	32,426
		Environmental Sanitation	In progress	3,528	—	3,528	5,334	12-31-2021	8,862
Pehuenche	PEHUENCHE CENTRAL	Materials Environment	In progress	4,993	—	4,993	24,720	12-31-2021	29,713
		Campaigns and Studies	In progress	4,235	—	4,235	6,180	12-31-2021	10,415
	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
		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
	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
	IMPROVEMENTS IN THE MT NETWORK	Replacement underground transformers by Technical Standard (PCB)	Completed	91,353	91,353	—	—	12-31-2020	91,353
Enel Distribución Chile S.A.	REPLACING TRIFAS TRANSFORMERS BETTER QUALITY	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
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of the maintenance of green areas with the replacement of species and lawns in Enel substation enclosures. Maintenance of afforestation 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
	RESPEL MANAGEMENT	Hazardous waste removal and treatment management	Completed	19,122	—	19,122	—	12-31-2020	19,122
	SEC NORMALIZATION PROJECT (CAPEX)	Maintenance of afforestation of 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 Metropolitan Park.	Completed	1,374	—	1,374	—	12-31-2020	1,374
	OIL ANALYSIS AT TD OF POWER (OPEX)	The removal and transfer to a dump of waste material from a Substation was carried out.	Completed	32,096	—	32,096	—	12-31-2020	32,096
	ENVIRONMENTAL EXPENSES CC.CC.	The main expenses incurred are: Operation and maintenance monitoring of air and meteorological quality stations, Environmental audit monitoring network 1 per year, CEMS Annual Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements, SGI Works (Objective NC, 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
Enel Generación Chile S.A.	ENVIRONMENTAL EXPENSES CC.TT.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric power plants (C.T.)	In progress	2,048,635	158,028	1,890,607	1,520,333	12-31-2021	3,568,968
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric power plants (C.H.)	In progress	263,737	—	263,737	—	12-31-2020	263,737
	Waste Management	Contracts for the removal of hazardous and non-hazardous waste, and household waste removal	In progress	84,113	—	84,113	148,447	12-31-2021	232,560
	Environmental Sanitation	Contracts for vector control, rat extermination, disinsection	In progress	46,957	—	46,957	104,448	12-31-2021	151,405
	Water Analysis	Monitoring and analysis of drinking water and wastewater	In progress	—	—	35,266	44,588	12-31-2021	—
	Rental/Vehicle Expenses	Vehicle rental for Environment trips (site visits / Plants	In progress	51,716	—	51,716	66,741	12-31-2021	118,457
Enel Green Power Chile S.A.	Campaigns and Studies	Contracts for Environmental Monitoring (Bird Collision- Flora and Fauna- Archeology, others)	In progress	189,321	—	189,321	355,550	12-31-2021	544,871
	Technical Counterpart Environmental Studies	Technical Counterpart Environmental Studies	In progress	—	—	—	5,287	12-31-2021	5,287
	Materials Environment	Buy environmental materials (containers, anti-spill kit, others)	In progress	32,032	—	32,032	40,578	12-31-2021	72,610
	Treatment Plant Wastewater	Contract for withdrawal and cleaning of pits and sewage	In progress	8,066	—	8,066	31,591	12-31-2021	39,657
	Outsourced Services	Other services (contracts with third parties)	In progress	222,291	—	222,291	297,167	12-31-2021	519,458
	Environment Travel	Tickets- lodging and per diem for visits to the field in facilities	In progress	56,820	—	56,820	85,150	12-31-2021	140,368
	Waste Management	Contracts for the removal of hazardous and non-hazardous waste, and household waste removal	In progress	21,992	—	21,992	32,918	12-31-2021	54,910
	Environmental Sanitation	Contracts for vector control, rat extermination, disinsection	In progress	6,500	—	6,500	14,319	12-31-2021	20,819

F-135

Geotérmica del Norte S.A.	Campaigns and Studies	Contracts for Environmental Monitoring (Bird Collision- Flora and Fauna- Archeology, others)	In progress	313,280	—	313,280	339,170	12-31-2021	652,450
	Materials Environment	Buy environmental materials (containers, anti-spill kit, others)	In progress	91	—	91	3,559	12-31-2021	3,650
	Treatment Plant Wastewater	Contract for withdrawal and cleaning of pits and sewage	In progress	4,816	—	4,816	1,324	12-31-2021	6,140
	Waste Management	Contracts for the removal of hazardous and non-hazardous waste, and household waste removal	In progress	13,064	—	13,064	18,580	12-31-2021	31,644
Parque Eolico Talinay Oriente S.A.	Environmental Sanitation	Contracts for vector control, rat extermination, disinsection	In progress	6,939	—	6,939	4,109	12-31-2021	11,048
	Campaigns and Studies	Contracts for Environmental Monitoring (Bird Collision- Flora and Fauna- Archeology, others)	In progress	76,595	—	76,595	—	12-31-2021	76,595
	Treatment Plant Wastewater	Contract for withdrawal and cleaning of pits and sewage	In progress	2,087	—	2,087	—	12-31-2021	2,087
	Waste Management	Contracts for the removal of hazardous and non-hazardous waste, and household waste removal	In progress	39,521	—	39,521	31,508	12-31-2021	71,029
	Environmental Sanitation	Contracts for vector control, rat extermination, disinsection	In progress	33,992	—	33,992	36,542	12-31-2021	70,534
Almeyda Solar Spa	Water Analysis	Monitoring and analysis of drinking water and wastewater	In progress	—	—	—	24,435	12-31-2020	24,435
	Campaigns and Studies	Contracts for Environmental Monitoring (Bird Collision- Flora and Fauna- Archeology, others)	In progress	63,736	—	63,736	64,160	12-31-2021	127,896
	Materials Environment	Buy environmental materials (containers, anti-spill kit, others)	In progress	16,663	—	16,663	28,702	12-31-2021	45,365
	Treatment Plant Wastewater	Contract for withdrawal and cleaning of pits and sewage	In progress	8,149	—	8,149	12,795	12-31-2021	20,944
		Total		14,046,722	5,768,806	8,313,182	3,966,677		17,967,209

F-136

				12-31-2019
Disbursing Company	Project Name	Environmental Description	Project status [Completed, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
	PEHUENCHE CENTRAL	Waste Management	In progress	3,165	—	3,165	—	—	3,165
		Environmental Sanitation	In progress	1,988	—	1,988	—	—	1,988
Pehuenche	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
	CHANGE OF TRAD X CALPE NETWORK	Replacement of traditional network by Calpe (Preassembled 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 to which the foliage must be left with respect to the conductors.	Completed	2,600	—	2,600	—	12-31-2019	2,600
		This activity contemplates the maintenance of the easement strip of a high voltage line between 34.5 and 500 kV.	Completed	67,291	—	67,291	—	12-31-2019	67,291
	VEGETATION CONTROL IN MT/BT	Pruning of trees in the vicinity of the low voltage network	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 of afforestation of SSEE and removal of weeds, debris and garbage, exterior perimeter.	Completed	64,737	—	64,737	—	12-31-2019	64,737
Enel Distribución Chile S.A.	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of weeding and weed control in electrical power substation enclosures with the aim of keeping 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 a dump of waste material from a Substation was carried out.	Completed	21,719	—	21,719	—	12-31-2019	21,719
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in Metropolitan Park.	Completed	2,337	—	2,337	—	12-31-2019	2,337
	IMPROVEMENTS IN THE MT NETWORK	Replacement of bare MT network with protected cable	In progress	170,077	170,077	—	—	12-31-2019	170,077
	RESPEL MANAGEMENT	Hazardous waste removal and treatment management	Completed	103,847		103,847	—	12-31-2019	103,847
	REPLACING TRIFAS TRANSFORMERS BETTER QUALITY	Replacement of transformers with chargeability problems	In progress	1,168,343	1,168,343	—	—	12-31-2019	1,168,343
	REPLACEMENT TD DAE CONCENTRIC X TD. TRIF. CALPE NETWORK	Replacement of concentrical network by Calpe (Preassembled aluminum cable) LV	In progress	492,260	492,260	—	—	12-31-2019	492,260
	ENVIRONMENTAL MONITORING	Environmental Monitoring Cto. with SK Ecology, operation and maintenance CEMS	In progress	576,519	—	576,519	—	—	576,519
	CEMS STANDARDIZATION	Winery standardization, environmental management, environmental impact assessment regularization (EIA)	In progress	207,966	207,966	—	—	—	207,966
	HYDRAULIC POWER STATIONS	Waste management and sanitation	In progress	2,315	—	2,315	—	—	2,315
Enel Generación Chile S.A.	ENVIRONMENTAL EXPENSES CC.CC.	The main expenses incurred are: U1-2 Entrance: Operation and maintenance monitoring air quality and meteorological stations, Environmental Audit monitoring network 1 per year, CEMS Annual Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements, SGI works (Objective NC, 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 power 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 power plants (C.H.)	In progress	339,103	—	339,103	420,877	12-31-2020	759,980
	QUINTERO PLANT	Central Quinteros CEMS	In progress	458,001	110,923	347,078	37,983	12-31-2020	495,984
		Waste Management	Completed	4,432	—	4,432	—	—	4,432
	Carrera Pinto	Environmental Sanitation	Completed	6,466	—	6,466	—	—	6,466
		Treatment Plant Wastewater	Completed	4,436	—	4,436	—	—	4,436
		Waste Management	Completed	10,954	—	10,954	—	—	10,954
	Finis Terrae	Environmental Sanitation	Completed	7,674	—	7,674	—	—	7,674
		Treatment Plant Wastewater	Completed	2,154	—	2,154	—	—	2,154
	La Silla	Environmental Sanitation	Completed	2,902	—	2,902	—	—	2,902
		Waste Management	Completed	1,509	—	1,509	—	—	1,509
		Campaigns and Studies	Completed	20,613	—	20,613	—	—	20,613
	Los Buenos Aires	Environmental Sanitation	Completed	3,989	—	3,989	—	—	3,989
		Treatment Plant Wastewater	Completed	882	—	882	—	—	882
		Materials Environment	Completed	5,589	—	5,589	—	—	5,589
		Waste Management	Completed	5,098	—	5,098	—	—	5,098
Enel Green Power del Sur Spa.	Pampa Norte	Environmental Sanitation	Completed	6,618	—	6,618	—	—	6,618
		Treatment Plant Wastewater	Completed	3,459	—	3,459	—	—	3,459
		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
	Renaico	Treatment Plant Wastewater	Completed	982	—	982	—	—	982
		Materials Environment	Completed	4,822	—	4,822	—	—	4,822
		Outsourced Services	Completed	53,970	—	53,970	—	—	53,970
		Waste Management	Completed	13,999	—	13,999	—	—	13,999
	Sierra Gorda	Campaigns and Studies	Completed	42,959	—	42,959	—	—	42,959
		Environmental Sanitation	Completed	3,300	—	3,300	—	—	3,300
		Treatment Plant Wastewater	Completed	127	—	127	—	—	127
		Waste Management	Completed	1,613	—	1,613	—	—	1,613
	Chañares	Campaigns and Studies	Completed	7,981	—	7,981	—	—	7,981
		Environmental Sanitation	Completed	5,262	—	5,262	—	—	5,262
		Treatment Plant Wastewater	Completed	5,591	—	5,591	—	—	5,591
		Waste Management	Completed	1,678	—	1,678	—	—	1,678
	Lalackama	Environmental Sanitation	Completed	7,091	—	7,091	—	—	7,091
		Treatment Plant Wastewater	Completed	3,273	—	3,273	—	—	3,273
Empresa Electrica Panguipulli S.A.	Pilmaiquen	Waste Management	Completed	1,450	—	1,450	—	—	1,450
		Environmental Sanitation	Completed	6,822	—	6,822	—	—	6,822
		Waste Management	Completed	785	—	785	—	—	785
	Pullinque	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
	Talinay Poniente	Campaigns and Studies	Completed	46,026	—	46,026	—	—	46,026
		Waste Management	Completed	10,745	—	10,745	—	—	10,745
Parque Eolico Tal Tal S.A.	Taltal	Campaigns and Studies	Completed	44,656	—	44,656	—	—	44,656
		Environmental Sanitation	Completed	2,476	—	2,476	—	—	2,476
		Treatment Plant Wastewater	Completed	2,515	—	2,515	—	—	2,515

F-137

		Waste Management	Completed	11,546	—	11,546	—	—	11,546
Parque Eolico Valle De Los Vientos S.A.	Valle de los Vientos	Campaigns and Studies	Completed	20,216	—	20,216	—	—	20,216
		Environmental Sanitation	Completed	2,471	—	2,471	—	—	2,471
		Waste Management	Completed	11,865	—	11,865	—	—	11,865
Parque Eolico Talinay Oriente S.A.	Talinay Oriente	Campaigns and Studies	Completed	63,666	—	63,666	—	—	63,666
		Environmental Sanitation	Completed	9,419	—	9,419	—	—	9,419
		Treatment Plant Wastewater	Completed	1,738	—	1,738	—	—	1,738
		Waste Management	Completed	10,087	—	10,087	—	—	10,087
Almeyda Solar Spa	Diego de Almagro	Environmental Sanitation	Completed	5,216	—	5,216	—	—	5,216
		Treatment Plant Wastewater	Completed	6,040	—	6,040	—	—	6,040
		Total		16,132,535	6,245,845	9,886,690	3,078,356	—	19,210,891

F-138

39.  FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of December 31, 2021, 2020 and 2019, summarized financial information of the Company’s principal consolidated subsidiaries prepared under IFRS is as follows:

	12-31-2021
	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	355,550,335	1,276,352,458	1,631,902,793	597,095,713	355,313,363	679,493,717	1,631,902,793	1,164,996,417	(1,000,659,317)	164,337,100	72,015,180	16,530,439	(9,474,782)	7,056,882	9,609,968	16,666,850	4,877,440	21,544,290
Grupo Enel Transmisión Chile	Consolidated	48,577,101	314,425,878	363,002,979	172,645,950	15,974,544	174,382,485	363,002,979	69,228,629	(2,571,288)	66,657,341	51,518,389	41,653,048	(2,210,228)	39,442,820	(7,334,537)	32,108,283	203,377	32,311,660
Enel Generación Chile	Separate	530,408,211	2,705,722,064	3,236,130,275	483,172,950	1,242,808,323	1,510,149,002	3,236,130,275	1,869,125,271	(1,629,466,468)	239,658,803	110,284,335	16,150,815	(43,993,753)	77,683,613	33,147,652	110,831,265	(130,158,612)	(19,327,347)
Enel Distribución Chile	Separate	352,304,900	1,267,457,144	1,619,762,044	591,495,830	355,253,688	673,012,526	1,619,762,044	1,160,793,856	(999,492,100)	161,301,756	69,894,610	15,278,349	(9,696,737)	5,581,612	9,752,809	15,334,421	4,866,485	20,200,906
Empresa Eléctrica Pehuenche S.A.	Separate	71,263,125	160,836,183	232,099,308	45,665,642	40,961,161	145,472,505	232,099,308	208,152,869	(50,164,405)	157,988,464	149,853,935	142,376,688	1,549,390	143,926,078	(38,959,905)	104,966,173	—	104,966,173
Enel Transmision Chile S.A.	Separate	48,577,102	314,425,879	363,002,981	172,645,951	15,974,544	174,382,485	363,002,981	68,238,700	(2,174,763)	66,063,937	51,053,425	41,201,514	(2,219,446)	41,152,259	(7,234,900)	33,917,359	203,377	34,120,736
Empresa De Transmision Chena S.A.	Separate	—	—	—	—	—	—	—	989,929	(396,525)	593,403	464,964	451,535	9,219	460,753	(99,637)	361,116	—	361,116
Geotermica del Norte S.A.	Separate	5,894,673	480,845,799	486,740,472	63,249,169	4,392,957	419,098,346	486,740,472	29,824,491	(751,374)	29,073,117	17,531,064	(3,248,229)	(4,531,802)	(7,780,032)	1,128,172	(6,651,860)	70,443,147	63,791,287
Parque Eolico Talinay Oriente S.A.	Separate	104,653,972	89,697,647	194,351,619	6,633,281	27,036,007	160,682,331	194,351,619	12,818,816	(1,446,268)	11,372,548	8,267,530	2,113,875	59,282	2,173,157	(614,662)	1,558,495	26,745,027	28,303,522
Enel Green Power Chile S.A	Separate	99,047,153	2,955,681,630	3,054,728,783	633,476,536	1,369,691,239	1,051,561,008	3,054,728,783	314,323,284	(133,738,760)	180,584,524	135,344,197	65,819,037	(18,369,603)	47,449,434	(19,571,243)	27,878,191	167,145,499	195,023,690
Grupo Enel Green Power	Consolidated	197,492,004	3,113,557,814	3,311,049,818	691,255,192	1,405,135,706	1,214,658,920	3,311,049,818	325,711,059	(109,034,364)	216,676,695	161,136,930	64,308,728	(20,252,770)	43,993,474	(18,854,738)	25,138,736	264,760,275	289,899,011
Grupo Enel Generación Chile	Consolidated	546,172,832	2,755,711,323	3,301,884,155	508,122,463	1,283,153,774	1,510,607,918	3,301,884,155	1,899,774,388	(1,505,110,838)	394,663,550	260,005,226	158,527,503	(42,444,363)	129,470,720	(5,812,252)	123,658,468	(129,444,345)	(5,785,877)
	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	(148,682,651)	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 del Sur	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	(47,841,224)	(4,396,031)	(52,237,255)

F-139

40.  SUBSEQUENT EVENTS

Enel Chile S.A.

i. On January 31, 2022, Enel Chile formalized a revolving credit facility with Enel Finance International N.V. in U.S. dollars for US$300 million, at a SOFR 1M, 3M or 6M variable rate plus a spread of 0.75%, with monthly, quarterly or semiannual interest payments, and a maturity date of August 8, 2023. On February 17, 2022 the first draw of the facility was for US$200 million, at a SOFR 6M rate + spread, maturing on August 17, 2022. On March 4, 2022, the remaining balance of the line was drawn for US$100 million, at a SOFR 6M rate + spread, maturing on September 2, 2022. Based on its revolving nature, at maturity, the decision will be made to renew or pay, but this decision may not be extended beyond the maturity date of the facility.

ii. On February 28, 2022 Enel Chile announced in a significant event filing that in the regular meeting of the Board of Directors held on the same date, the Chief Executive Officer of the Company, Mr. Paolo Pallotti, tendered his resignation to assume new duties in the Enel Group. The resignation is effective as of March 1, 2022.

Mr. Fabrizio Barderi was appointed as the new Chief Executive Officer of Enel Chile as of March 1, 2022.

iii. On April 12, 2022, Enel Chile S.A. formalized a revolving credit facility with Bank of Nova Scotia and Mizuho in US dollars for US$300 million, at a SOFR 1M, 3M or 6M variable rate plus a spread of 0.65%, with monthly, quarterly or semiannual interest payments and a maturity date of October 12, 2023. During the availability period, Enel Chile S.A. must pay an annual availability commission equivalent to 0.25% on the amount not withdrawn. On April 19, 2022, the first draw of the facility was for US$150 million, with a 6-month term maturing on October 19, 2022. Based on its revolving nature, at maturity, the decision will be made to renew or pay, but this decision may not be extended beyond the maturity date of the facility.

Enel Distribución Chile S.A.

iv. On February 11, 2022, Law No. 21,423 was published in the Official Gazette of the Republic of Chile, which regulates the prorate and payment of water and electricity services generated during COVID-19 and establishes subsidies for vulnerable customers. As a result of the application of this Law Enel Distribución Chile S.A. believes that during 2022, a greater loss must be recognized for the impairment of its accounts receivable up to approximately ThCh$980,000.

v. On February 21, 2022, Enel Distribución Chile S.A. was notified by means of Exempt Resolution No. 10,921 of the Superintendency of Electricity and Fuels of a fine equivalent to 39,261 UTM (ThCh$2,137,447) for the alleged breach of the provisions of Article 4-1 of the Technical Standard of Service Quality for Distribution Systems, in relation to Articles 145º and 222°, letter h), of the Regulations of the General Law of Electrical Services and Articles 72-14° and 130° of the General Law of Electrical Services, because the maximum limit of time of supply replacement established in the regulations was exceeded. The deadlines for filing the corresponding legal appeals are pending.

Enel X Chile S.A.

vi. On February 28, 2022, Enel X Chile increased its ownership interest in Sociedad de Inversiones K Cuatro S.P.A. from 10% to 50% by acquiring 400 additional shares for ThCh$259,393.

During 2021, Sociedad de Inversiones K Cuatro S.P.A. was awarded the public bid for the service of supplying buses for the Public Transportation System of the Province of Santiago and the communes of San Bernardo and Puente Alto. For this purpose, it incorporated an SPV called Suministradora de Buses K Cuatro S.P.A. (“Supplier”), a company that will have to acquire 991 buses for subsequent leasing to the operators of the Public Transportation System. The bidding conditions established certain minimum capital obligations

F-140

for the Supplier, which were triggered with the notification of the supply order(s), which occurred on March 9, 2022.

As a consequence of the foregoing, the Supplier must make a capital increase of US$ 63 million, of which, pro rata to its new shareholding, Enel X Chile must contribute U.S. dollars $31.5 million (ThCh$26,607,735), through Sociedad de Inversiones K Cuatro S.P.A. This capital contribution must be made during June 2022 (see other information in note 35.6).

Between January 1, 2022 and the date of issuance of these consolidated financial statements, we are not aware of other events of a financial or any other nature that could significantly affect the financial position and the results presented herein.

F-141

APPENDIX 1 DETAIL OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY

This appendix forms an integral part of these consolidated financial statements.

The detail of assets and liabilities denominated in foreign currency is as follows:

	12-31-2021
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	—	245,516,611	64,066,348	196,498	—	195,683	—	309,975,140
Other current financial assets	—	1,964,183	2,077,232	—	—	—	—	4,041,415
Other current non-financial assets	4,368,548	38,910,048	16,741,321	5,593,825	—	1,212,255	—	66,825,997
Trade and other current receivables	1,913,471	673,441,405	12,501,931	328,320	—	—	—	688,185,127
Current accounts receivable from related parties	—	5,923,226	25,269,387	25,247,475	—	—	—	56,440,088
Inventories	135,552	20,464,746	8,745,117	1,876,620	—	25,675	—	31,247,710
Current tax assets	—	108,728,114	2,808,902	—	—	—	—	111,537,016
TOTAL CURRENT ASSETS	6,417,571	1,094,948,333	132,210,238	33,242,738	—	1,433,613	—	1,268,252,493
NON-CURRENT ASSETS
Other non-current financial assets	16,863,692	21,588,925	926,448	—	—	—	—	39,379,065
Other non-current non-financial assets	62,133	89,522,912	31,603	—	—	—	—	89,616,648
Trade and other non-current receivables	7,415,493	507,930,913	439,122	—	—	812	—	515,786,340
Non-current accounts receivable from related parties	—	—	6,348,001	—	—	—	—	6,348,001
Investments accounted for using the equity method	—	1,277	9,535,521	—	—	387,135	—	9,923,933
Intangible assets other than goodwill	—	116,823,399	74,306,735	—	—	91,421	—	191,221,555
Goodwill	—	887,257,655	33,820,543	—	—	—	—	921,078,198
Property, plant and equipment	—	3,303,144,446	2,792,960,024	—	—	14,584,291	—	6,110,688,761
Investment property	—	7,539,005	—	—	—	—	—	7,539,005
Right-of-use asset	84,224,468	19,550,176	49,521,196	7,493,021	—	—	—	160,788,861
Deferred tax assets	—	168,154,950	11,545,786	—	—	—	—	179,700,736
TOTAL NON CURRENT ASSETS	108,565,786	5,121,513,658	2,979,434,979	7,493,021	—	15,063,659	—	8,232,071,103
TOTAL ASSETS	114,983,357	6,216,461,991	3,111,645,217	40,735,759	—	16,497,272	—	9,500,323,596

	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

F-142

	12-31-2021
LIABILITIES	U.F.	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	35,691,780	3	52,648,107	—	—	—	88,339,890
Current lease liability	5,891,047	81,203	3,654,887	1,477,881	—	—	11,105,018
Trade and other current payables	11,595,068	686,640,406	271,863,500	7,550,846	—	674,667	978,324,487
Current accounts payable to related parties	—	20,240,202	808,325,434	176,027,245	5,077	—	1,004,597,958
Other current provisions	—	19,341,067	186,526	—	—	228,724	19,756,317
Current tax liabilities	—	10,686,838	2,461,869	—	—	—	13,148,707
Other current non-financial liabilities	—	12,453,608	691,075	3,885,531	—	23,626	17,053,840
TOTAL CURRENT LIABILITIES	53,177,895	749,443,327	1,139,831,398	188,941,503	5,077	927,017	2,132,326,217
NON-CURRENT LIABILITIES
Other non-current financial liabilities	232,572,049	—	1,709,302,329	—	—	—	1,941,874,378
Non-current lease liability	133,208,951	37,922	8,080,578	7,229,608	—	—	148,557,059
Trade and other non-current payables	—	27,661	179,369,751	—	—	—	179,397,412
Non-current accounts receivable to related parties	—	—	1,300,059,097	—	—	—	1,300,059,097
Other long-term provisions	—	177,253,679	16,859,035	—	—	—	194,112,714
Deferred tax liabilities	—	58,397,322	139,019,628	—	—	—	197,416,950
Non-current provisions for employee benefits	—	58,091,481	860,105	—	—	—	58,951,586
Other non-current non-financial liabilities	—	1,135,285	—	—	—	—	1,135,285
TOTAL NON-CURRENT LIABILITIES	365,781,000	294,943,350	3,353,550,523	7,229,608	—	—	4,021,504,481
TOTAL LIABILITIES	418,958,895	1,044,386,677	4,493,381,921	196,171,111	5,077	927,017	6,153,830,698

	12-31-2020
LIABILITIES	U.F.	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

F-143

APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012

This appendix forms an integral part of these consolidated financial statements.

a) Portfolio stratification

-Trade and other receivables by maturity:

	As of December 31, 2021
	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	446,237,669	74,471,160	22,450,779	9,642,258	9,167,019	13,722,247	11,648,433	8,508,022	10,709,953	88,040,199	694,597,739	442,941,968
Impairment provision	(12,199,914)	(538,295)	(1,271,819)	(1,612,055)	(2,007,354)	(5,163,509)	(4,464,527)	(4,772,548)	(5,319,334)	(28,566,584)	(65,915,939)	(70,461)
Accounts receivable for leasing, gross	10,735,484	—	—	—	—	—	—	—	—	—	10,735,484	69,873,385
Impairment provision	(2,369,901)	—	—	—	—	—	—	—	—	—	(2,369,901)	—
Other receivables, gross	51,137,744	—	—	—	—	—	—	—	—	11,429,594	62,567,338	3,041,448
Impairment provision	—	—	—	—	—	—	—	—	—	(11,429,594)	(11,429,594)	—
Total	493,541,082	73,932,865	21,178,960	8,030,203	7,159,665	8,558,738	7,183,906	3,735,474	5,390,619	59,473,615	688,185,127	515,786,340
	As of December 31, 2020
	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	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

F-144

- By type of portfolio:

	December 31, 2021						December 31, 2020
	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	2,230,792	527,654,070	26,165	361,525,567	2,256,957	889,179,637	1,466,900	523,805,724	52,534	231,101,548	1,519,434	754,907,272
1 to 30 days	102,883	73,364,730	6,645	1,106,430	109,528	74,471,160	395,186	34,812,023	20,715	1,572,994	415,901	36,385,017
31 to 60 days	43,856	21,393,764	4,206	1,057,015	48,062	22,450,779	80,032	9,839,311	6,815	2,567,881	86,847	12,407,192
61 to 90 days	8,738	8,935,098	1,030	707,160	9,768	9,642,258	33,889	6,030,130	3,116	507,384	37,005	6,537,514
91 to 120 days	21,811	8,855,902	3,267	311,117	25,078	9,167,019	20,530	6,763,017	2,021	137,724	22,551	6,900,741
121 to 150 days	12,729	12,958,406	2,739	763,841	15,468	13,722,247	14,558	6,398,089	1,478	1,148,881	16,036	7,546,970
151 to 180 days	12,155	11,029,547	3,938	618,886	16,093	11,648,433	14,025	5,653,084	1,393	1,402,958	15,418	7,056,042
181 to 210 days	6,683	7,587,824	2,759	920,198	9,442	8,508,022	9,955	3,625,873	1,311	243,359	11,266	3,869,232
211 to 250 days	7,367	10,185,568	1,353	524,385	8,720	10,709,953	8,864	3,314,300	1,526	225,402	10,390	3,539,702
More than 251 days	484,362	85,302,461	23,839	2,737,738	508,201	88,040,199	52,024	68,459,538	15,224	730,712	67,248	69,190,250
Total	2,931,376	767,267,370	75,941	370,272,337	3,007,317	1,137,539,707	2,095,963	668,701,089	106,133	239,638,843	2,202,096	908,339,932

b) Portfolio in default and in legal collection process

	As of December 31,
	2021		2020
	Number of	Amount	Number of	Amount
Portfolio in Default and in Legal Collection Process	Customers	ThCh$	Customers	ThCh$
Notes receivable in default	1,864	255,977	1,878	256,927
Notes receivable in legal collection process (*)	1,368	5,608,066	1,140	5,600,040
Total	3,232	5,864,043	3,018	5,856,967

(*) Legal collections are included in the portfolio in arrears.

c) Provisions and write-offs

	As of December 31,
	12-31-2021	12-31-2020
Provisions and Write-offs	ThCh$	ThCh$
Provision for non-renegotiated portfolio	10,188,647	12,467,992
Provision for renegotiated portfolio	8,576,528	2,699,715
Total	18,765,175	15,167,707

d) Number and value of transactions

	12-31-2021		12-31-2020
	Total detail by type of transaction ThCh$	Total detail by type of operation ThCh$	Total detail by type of transaction ThCh$	Total detail by type of operation ThCh$
Number and Amount of Transactions	Last Quarter	Year-to-date	Last Quarter	Year-to-date
Allowance for impairment and recoveries:
Number of Transactions	24,625	83,672	10,390	72,590
Amount of the transactions	3,840,423	18,765,175	7,768,107	15,167,707

F-145

APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:

This appendix forms an integral part of these consolidated financial statements.

a) Portfolio stratification

- Trade receivables by time in arrears:

	12-31-2021
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	239,206,312	53,529,239	5,068,187	1,699,828	555,824	529,143	1,642,032	780,749	1,662,418	3,827,927	11,826,850	320,328,509	98,464,396
- Large customers	236,623,099	53,489,015	5,048,035	1,679,005	526,570	486,746	1,536,563	731,150	1,624,299	3,540,039	11,424,365	316,708,886	98,464,396
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—	—
- Others	2,583,213	40,224	20,152	20,823	29,254	42,397	105,469	49,599	38,119	287,888	402,485	3,619,623	—
Allowance for impairment	(831,459)	(34)	(44,694)	(33,223)	(10,689)	(25,879)	(83,565)	(113,137)	(12,055)	(23,558)	(3,426,898)	(4,605,191)	(70,461)
Unbilled services	48,467,567	—	—	—	—	—	—	—	—	—	—	48,467,567	5,315,369
Billed services	190,738,745	53,529,239	5,068,187	1,699,828	555,824	529,143	1,642,032	780,749	1,662,418	3,827,927	11,826,850	271,860,942	93,149,027
Trade receivables, Distribution	207,031,357	20,941,921	17,382,592	7,942,430	8,611,195	13,193,104	10,006,401	7,727,273	9,047,535	14,466,560	57,918,862	374,269,230	344,477,572
- Mass-market customers	184,932,481	5,491,380	13,707,222	6,926,780	2,531,592	8,515,887	5,638,984	4,846,195	5,421,728	11,551,826	44,481,081	294,045,156	338,671,964
- Large Clients	21,292,324	15,164,974	2,576,480	(67,893)	3,960,872	2,161,778	1,573,396	1,129,525	550,515	1,061,673	4,931,358	54,335,002	604,764
- Institutional customers	806,552	285,567	1,098,890	1,083,543	2,118,731	2,515,439	2,794,021	1,751,553	3,075,292	1,853,061	8,506,423	25,889,072	5,200,844
Allowance for impairment	(11,368,455)	(538,261)	(1,227,125)	(1,578,832)	(1,996,665)	(5,137,630)	(4,380,962)	(4,659,411)	(5,307,279)	(9,975,061)	(15,141,067)	(61,310,748)	—
Unbilled services	198,801,542	—	—	—	—	—	—	—	—	—	—	198,801,542	—
Billed services	8,229,815	20,941,921	17,382,592	7,942,430	8,611,195	13,193,104	10,006,401	7,727,273	9,047,535	14,466,560	57,918,862	175,467,688	344,477,572
Total trade receivables, gross	446,237,669	74,471,160	22,450,779	9,642,258	9,167,019	13,722,247	11,648,433	8,508,022	10,709,953	18,294,487	69,745,712	694,597,739	442,941,968
Total Allowance for impairment	(12,199,914)	(538,295)	(1,271,819)	(1,612,055)	(2,007,354)	(5,163,509)	(4,464,527)	(4,772,548)	(5,319,334)	(9,998,619)	(18,567,965)	(65,915,939)	(70,461)
Total trade receivables, net	434,037,755	73,932,865	21,178,960	8,030,203	7,159,665	8,558,738	7,183,906	3,735,474	5,390,619	8,295,868	51,177,747	628,681,800	442,871,507

F-146

	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 Clients	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 customers	—	—	—	—	—	—	—	—	—	—	—	—	—
- 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
- Massive Clients	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	—	—	469,117	6,492,927	82,731,771	807,561
- Institutional Clients	5,314,387	1,677,069	3,293,400	794,928	678,106	1,772,947	2,291,920	1,302,229	275,815	4,124,041	7,893,579	29,418,421	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

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	- Institutional Customers
- Large Customers	- By type of portfolio:

F-147

	12-31-2021
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	239,206,312	53,529,239	5,068,187	1,699,828	555,824	529,143	1,642,032	780,749	1,662,418	15,654,777	320,328,509	98,464,396
- Large Clients	236,623,099	53,489,015	5,048,035	1,679,005	526,570	486,746	1,536,563	731,150	1,624,299	14,964,404	316,708,886	98,464,396
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	2,583,213	40,224	20,152	20,823	29,254	42,397	105,469	49,599	38,119	690,373	3,619,623	—
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—
- Large Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	189,612,249	19,835,491	16,325,577	7,235,270	8,300,078	12,429,263	9,387,515	6,807,075	8,523,150	69,647,684	348,103,352	371,113
- Mass-market Clients	169,498,416	4,481,996	12,726,746	6,237,619	2,318,628	7,952,717	5,174,721	4,385,681	4,964,847	53,705,922	271,447,293	125,705
- Large Clients	20,575,913	15,120,780	2,552,779	(85,892)	3,960,872	2,145,245	1,573,146	1,129,274	550,515	5,993,031	53,515,663	245,408
- Institutional Clients	(462,080)	232,715	1,046,052	1,083,543	2,020,578	2,331,301	2,639,648	1,292,120	3,007,788	9,948,731	23,140,396	—
Renegotiated portfolio	17,419,108	1,106,430	1,057,015	707,160	311,117	763,841	618,886	920,198	524,385	2,737,738	26,165,878	344,106,459
- Mass-market Clients	15,434,064	1,009,382	980,476	689,161	212,965	563,170	464,262	460,514	456,881	2,326,986	22,597,861	338,546,260
- Large Clients	716,411	44,195	23,701	17,999	—	16,533	251	251	—	—	819,341	359,355
- Institutional Clients	1,268,633	52,853	52,838	—	98,152	184,138	154,373	459,433	67,504	410,752	2,748,676	5,200,844
Total gross portfolio	446,237,669	74,471,160	22,450,779	9,642,258	9,167,019	13,722,247	11,648,433	8,508,022	10,709,953	88,040,199	694,597,739	442,941,968

	12-31-2020
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	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 customers	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 customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	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 customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	—	—	—	—	—	—	—	—	—	—	—	—
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 customers	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 customers	61,579,935	6,530,802	1,801,692	772,761	1,855,461	1,031,268	358,060	—	—	6,962,044	80,892,023	223,507
- Institutional customers	2,617,301	1,451,119	1,384,582	791,851	678,106	975,284	1,347,634	1,302,215	256,794	12,015,155	22,820,041	—
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 customers	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 Customers	1,478,845	189,449	105,946	45,027	20,480	—	—	—	19,021	—	1,858,768	584,054
- Institutional Customers	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

F-148

APPENDIX 2.2 ESTIMATES OF SALES AND PURCHASES OF ENERGY, POWER AND TOLL

This appendix forms an integral part of these consolidated financial statements.

	12-31-2021		12-31-2020
	Energy and Capacity	Tolls	Energy and Capacity	Tolls
STATEMENT OF FINANCIAL POSITION	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, current	302,100,766	11,112,332	229,499,918	33,270,963
Trade and other receivables, non-current	389,606,316	—	396,509,053	—
Total Estimated Assets	691,707,082	11,112,332	626,008,971	33,270,963
Trade and other payables, current	106,108,407	5,855,074	68,569,674	13,216,339
Trade and other payables, non-current	157,402,765	—	121,315,888	—
Total Estimated Liabilities	263,511,172	5,855,074	189,885,562	13,216,339

	12-31-2021		12-31-2020
	Energy and power	Tolls	Energy and power	Tolls
INCOME STATEMENT	ThCh$	ThCh$	ThCh$	ThCh$
Energy Sales	466,620,691	11,112,332	434,442,879	33,270,962
Energy Purchases	151,312,313	5,855,074	147,662,168	11,928,862

F-149

APPENDIX 3 DETAIL OF DUE DATES OF PAYMENTS TO SUPPLIERS

This appendix forms an integral part of these consolidated financial statements.

	12-31-2021				12-31-2020
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers with Payments Up-to-Date	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Up to 30 days	84,896,490	342,566,432	320,708,771	748,171,693	133,063,016	89,574,397	166,733,893	389,371,306
Between 31 and 60 days	3,032,565	1,403,461	45,157,514	49,593,540	49,211,386	60,808,696	79,770	110,099,852
Between 61 and 90 days	14,137,065	30,231	102,236,203	116,403,499	78,114,700	343,314	187,027	78,645,041
Between 91 and 120 days	—	—	—	—	—	—	—	—
Between 121 and 365 days	—	—	—	—	—	—	—	—
More than 365 days	—	487	179,311,985	179,312,472	—	487	117,129,284	117,129,771
Total	102,066,120	344,000,611	647,414,473	1,093,481,204	260,389,102	150,726,894	284,129,974	695,245,970

	12-31-2021				12-31-2020
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers Details	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Suppliers for energy purchase	—	94,049,964	319,420,457	413,470,421	—	22,475,111	226,238,177	248,713,288
Suppliers for the purchase of fuels and gas	—	86,288,004	—	86,288,004	—	36,735,748	—	36,735,748
Accounts payable for goods and services	29,508,717	163,662,643	—	193,171,360	202,897,547	91,516,035	—	294,413,582
Accounts payable for the purchase of assets	72,557,403	—	327,994,015	400,551,418	57,491,555	—	57,891,797	115,383,352
Total	102,066,120	344,000,611	647,414,473	1,093,481,204	260,389,102	150,726,894	284,129,974	695,245,970

F-150