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

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

For the fiscal year ended December 31, 2022

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

For the transition period from to

☐	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 ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ◻

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b) ☐

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

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Enel Chile’s Simplified Organizational Structure⁽¹⁾

As of December 31, 2022

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

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TABLE OF CONTENTS

		Page
GLOSSARY		3

INTRODUCTION		6

PRESENTATION OF INFORMATION		7

FORWARD-LOOKING STATEMENTS		9

PART I

Item 1.	Identity of Directors, Senior Management and Advisers	10

Item 2.	Offer Statistics and Expected Timetable	10

Item 3.	Key Information	10

Item 4.	Information on the Company	27

Item 4A.	Unresolved Staff Comments	57

Item 5.	Operating and Financial Review and Prospects	57

Item 6.	Directors, Senior Management and Employees	85

Item 7.	Major Shareholders and Related-Party Transactions	91

Item 8.	Financial Information	94

Item 9.	The Offer and Listing	96

Item 10.	Additional Information	97

Item 11.	Quantitative and Qualitative Disclosures About Market Risk	116

Item 12.	Description of Securities Other Than Equity Securities	120

PART II

Item 13.	Defaults, Dividend Arrearages and Delinquencies	121

Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	121

Item 15.	Controls and Procedures	121

Item 16.	Reserved	122

Item 16A.	Audit Committee Financial Expert	122

Item 16B.	Code of Ethics	122

Item 16C.	Principal Accountant Fees and Services	125

Item 16D.	Exemptions from the Listing Standards for Audit Committees	126

Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	126

Item 16F.	Change in Registrant’s Certifying Accountant	126

Item 16G.	Corporate Governance	126

Item 16H.	Mine Safety Disclosure	127

Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	127

PART III

Item 17.	Financial Statements	128

Item 18.	Financial Statements	128

Item 19.	Exhibits	128

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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 64.93% ownership of Enel Chile as of December 31, 2022, 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.

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Enel Chile	Enel Chile S.A.	Our company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile. The registrant of this Report.

Enel Colina	Enel Colina S.A.	A subsidiary of Enel Distribution engaged in electricity distribution in Chile, formerly known as Empresa Eléctrica de Colina Ltda.

Enel Distribution	Enel Distribución Chile S.A.	A 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 corporation engaged in electricity transformation and transmission and a former subsidiary of Enel Chile. We sold Enel Transmission on December 9, 2022.

Enel X Chile	Enel X Chile S.p.A.	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 biomass, geothermal, mini-hydro, solar, tidal, or wind energy.

PMGD	Pequeños Medios de Generación Distribuida	A Chilean regime for distributed generation facilities.

OSM	Ordinary Shareholders’ Meeting	Ordinary Shareholders’ Meeting

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Pehuenche	Empresa Eléctrica Pehuenche S.A.	A Chilean publicly held limited liability stock corporation engaged in the electricity generation business 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$ 35,110.98 as of December 31, 2022.

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, 2022.

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 and distribution businesses in Chile through our subsidiaries and affiliates. We own 93.55% of Enel Generación Chile S.A. (“Enel Generation”), a Chilean electricity generation company with operations in Chile, 99.99% of Enel Green Power Chile S.A. (“EGP Chile”), a Chilean renewable electricity generation company, and 99.09% of Enel Distribución Chile S.A. (“Enel Distribution”), a Chilean electricity distribution company that operates in the Santiago Metropolitan Region.

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 64.93% 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, 2022, one UF was equivalent to Ch$ 35,110.98. The U.S. dollar equivalent of one UF was US$ 41.02 as of December 31, 2022, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2022, of Ch$ 855.86 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, 2022. 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 net installed capacity, which excludes the MW that each power plant consumes for its operation. Prior to 2022, we presented gross installed capacity figures, which did not exclude the MW that each power plant consumes for its operation.

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Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for a leap year like 2020, which is based instead on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators.

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

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

Calculation of Economic Interest

In this Report, references are made to the “economic interest” of Enel Chile in its related companies. We have direct and/or indirect interests 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 climatic and weather conditions as a result of climate change.

Climate change is a major global challenge that exposes our businesses to a variety of medium- and long-term risks. Our generation business has been in the past and could be in the future negatively affected by arid hydrological conditions, which has and could negatively affect our ability to dispatch energy from our hydroelectric generation facilities. Our operations and results have been adversely affected when hydrological conditions in Chile have been significantly below average, as 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 have and may in the future face increased pressure from the Chilean government or other third parties to further restrict our water use, which could have a material adverse effect on our business and results of operations.

Our distribution business is also affected by inclement weather conditions. With extreme temperatures, demand for electricity can increase significantly within a short period, affecting service and resulting in service outages that has resulted and may in the future result in the imposition of fines on our distribution business. Furthermore, with increased severity and frequency of extreme climate events, such as cyclones and floods, heavy rainfall or snowfall may occur in a short period of time, accompanied by windstorms and lightning. These events may damage our power distribution infrastructure, resulting in service outages. As a result, depending on weather conditions, our distribution business results can vary significantly from year to year. For example,

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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, or 18%, of our customers and 17% of our feeders. These events significantly increased our costs in 2017 due to emergency responses implemented, including payments related to damage compensation, fines, line maintenance, and tree trimming programs.

Our operating expenses also increase during drought periods when thermal power plants, which have higher operating costs relative to hydroelectric power plants, are dispatched more frequently to make up the electricity generation deficit from reduced hydroelectric generation. In addition, our thermal power plants generate greenhouse gas (“GHG”) emissions. Depending on our commercial obligations, we may need to buy electricity at higher spot prices to comply with our contractual supply obligations. Beyond increasing our operating costs, the cost of these electricity purchases has exceeded and may in the future exceed our contracted electricity sale prices, thus potentially producing losses from those contracts. For example, in 2022, spot prices reached historic highs, resulting in losses from certain 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, principally our facilities that use natural gas or diesel fuel. 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 in order to operate our thermal plants. These water purchases have and may continue to increase our operating costs and require us to negotiate further with the local communities. If such negotiations are unsuccessful, we may be unable to obtain the water necessary to operate our thermal power plants.

Recovery from current or future droughts affecting the regions in Chile where most of our hydroelectric power plants are located may take place over an extended period, and there can be no assurance that any recovery will reach pre-drought hydrological conditions or that any recovery will occur at all. Climate change may increase the likelihood of prolonged droughts and exacerbate the risks described above, which would have a further adverse effect on our business, results of operations, and financial condition.

Our non-conventional renewable energy businesses are also 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. The solar and wind conditions may be negatively 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 deficit. Our thermal power plants have higher operating costs than our renewable energy facilities and generate GHG emissions. We also have needed and may in the future 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,

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thus potentially producing losses from those contracts. These impacts have increased and could in the future 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.

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 inability to obtain distributions from our subsidiaries described above could adversely affect our business, results of operations, and financial condition.

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 thermal power plants 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 and may be 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.

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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.

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.

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Labor disputes, our inability to reach satisfactory collective bargaining agreements with our unionized employees or our inability to attract, train and retain key employees could adversely affect our business, results of operations, financial condition, and reputation.

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. 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 unionized employees could negatively impact our business, results of operations, financial condition, and reputation.

In addition, we may experience shortages of qualified key personnel. In April 2021, we announced an employee Voluntary Retirement Program, open to men at least 60 and women at least 55 years old, with incentives for qualifying employees who accept retirement. This program may reduce our headcount by more than our ability to hire new employees to fill key positions. There can be no assurances that we will be able to attract, train, or retain key personnel or be able to do so without costs or delays, which could adversely affect our business, results of operations, financial condition, and reputation.

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

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 several factors, including but not limited to:

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

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

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complications in retaining key employees, customers, and suppliers;

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

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

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.

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Interruption in or failure of our information technology, control, and communications systems or cyberattacks to or cybersecurity breaches of these systems could have a material adverse effect on our business, results of operations, and financial condition.

We operate in an industry that requires the continued operation of sophisticated information technology, control, and communications systems (“IT Systems”) and network infrastructure. We use our IT Systems and 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 the volume and sophistication of cybersecurity incidents from international activist organizations, nation-states, and individuals. In this context, proper cybersecurity risk management must be addressed with a long-term strategy leveraging a proactive approach and iterative actions performed over time. Approaching cyber-risk with a single initiative cannot be considered an efficient and effective strategy to manage and reduce risks related to cybersecurity.

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

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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.

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 power outages, 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 transitory 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 subsidiaries Enel Generation and, to a lesser extent, EGP Chile 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.

In December 2019, the Ministry of Energy’s Law No. 21,194 (the “Distribution Tariff Law”) 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.

In August 2020, in the context of the Covid-19 pandemic, 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 Distribution, 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.

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Basic Services Law until December 31, 2021, and increased the maximum number of monthly installments from 36 to 48.

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 customers may pay their debt in 48 equal monthly installments, with a maximum limit equivalent to 15% of their average billing. Distribution companies will absorb 50% of all debt not repaid within the 48 monthly installments, 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-installment period.

In July 2022, the Chilean Congress passed Law No. 21,472, which complements Law No. 21,185 by creating a new stabilization fund program and establishing a new transitory mechanism for stabilizing customers’ electricity prices under the regulated price system. The purpose of the mechanism is to limit the increase in electricity bills for regulated customers during 2022 and to allow such increases to occur gradually over the next 10 years. 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.

As a result of the application of the laws mentioned above as of December 31, 2022, our current and non-current accounts receivables increased, revenues from energy sales decreased, costs from energy purchases decreased, and financial income increased due to lower financial costs. Please see Note 9 and Note 34 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 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, the Bocamina I plant in December 2020, and the Bocamina II plant in September 2022, well ahead of the Bocamina II plant’s scheduled deadline of December 31, 2040. In doing so, we became the first generation company in the Chilean electricity sector to completely remove coal from its generation operations. However, our efforts to decarbonize our energy matrix by closing coal-fired power plants might be insufficient if our renewable energy projects suffer delays and do not enter into operation on schedule.

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

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:

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are for an unlimited duration;

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are absolute and unconditional property rights; and

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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.

Any revocation of or limitations on our current water rights (including as a result of changes to the Chilean constitution), 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.

We have experienced and may in the future experience increased interest in our environmental, social, and governance (“ESG”) practices and commitments from our stakeholders, investors, and regulatory bodies. Failure to disclose, meet, or address our ESG practices or commitments could negatively impact our reputation, investment in our common stock and ADSs, or our access to capital markets.

Our goal is to reduce carbon emissions from our electric generation facilities to achieve net-zero CO₂ emissions by 2040. We continue to monitor the financial and operational feasibility of taking more aggressive action to further reduce GHG emissions. Our strategic plan to replace older, fossil-fueled generation with zero-carbon emitting renewable generation will contribute to the achievement of our goals related to reducing CO₂ emissions. However, our ability to achieve such goals depends on many external factors, including the development of relevant energy technologies and the ability to execute our capital plan. These efforts could

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impact how we operate our electric generating units and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.

Our ability to successfully execute our strategic plan, including the transition of our generation facilities and achievement of our CO₂ emissions reduction targets, may affect customers’, investors’, legislators’, and regulators’ opinions and actions. If they have or develop a negative opinion of us due to increasing scrutiny of ESG practices or our failure to meet our announced ESG commitments, this could result in increased costs associated with regulatory oversight and could make it more difficult for our businesses to achieve favorable legislative or regulatory outcomes. In addition, increased focus and activism related to ESG matters may hinder our access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of our ESG practices. Any of these consequences could adversely affect our reputation, investment in our securities, or our access to capital markets and negatively impact our results of operations, financial position, and liquidity.

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. We are exposed to political volatility and social unrest in Chile due to the challenges arising from changes in economic conditions, regulatory policies, and laws governing foreign trade, manufacturing, development, investments, and taxation. For example, in July 2022, the government of President Gabriel Boric sent the Chilean Congress a tax reform bill to modify income and value-added taxes, reduce tax exemptions and tax evasion, and introduce new taxes on wealth and mining. The reforms are in the initial stages of consideration and are expected to be discussed in the Chilean Congress during 2023.

Chile is also vulnerable to crises and uncertainties, as well as external shocks in other countries, such as financial and political events, that could cause significant economic difficulties and adversely affect economic growth in Chile. 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.

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, changes in interest rates, 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 and our ability to access the capital markets.

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.

Following widespread protests and social unrest throughout Chile in October 2019, the Chilean government introduced several social reforms and implemented a constitutional convention process to draft a new Chilean Constitution to replace the current 1980 Constitution. A September 2022 national plebiscite

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rejected the proposed new constitution by 62% of the popular vote, leaving the current 1980 Constitution in place. However, widespread political support for a second constitutional process remains, and discussions about how to proceed with a new constitutional reform are ongoing. Any new constitution could alter the Chilean political situation, affect the Chilean economy, its business outlook, change existing rights to exploit natural resources, or change water and property rights, any of which could adversely affect our business, results of operations, and financial condition.

For example, the proposed new Chilean Constitution that was rejected in the September 2022 national plebiscite included a declaration that water is “non-appropriable” and would have significantly changed the current system of water rights if approved. There can be no assurance that a similar declaration would not be included in any new Chilean Constitution coming out of that process. Nor can there be any assurance that these reforms and proposals or a new constitution 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.

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

Global markets are currently operating in a period of economic uncertainty, volatility, and disruption as the armed conflict between Russia and Ukraine, which began in February 2022, continues. The armed conflict and the economic sanctions imposed on Russia and certain Russian citizens and enterprises could have a negative effect on the global economy and are highly uncertain and difficult to predict. 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, in 2020 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 voluntarily took further actions, such as adopting telecommuting wherever possible and closing commercial offices.

All these measures, as well as other government restrictions, temporarily disrupted our business and operations, decreased the electricity demand, destabilized financial markets, negatively affected the global supply chain, and compromised our ability to generate income. These disruptions significantly impacted our 2020 performance.

In 2021 and 2022, the Chilean government lifted many of these restrictions, which increased the demand for electricity and positively impacted our net income in 2021 and 2022. For further information with 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.

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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 2022, the Chilean peso only depreciated by approximately 1% against the U.S. dollar, but the U.S. dollar Observed Exchange Rate peaked at Ch$ 1,042.97 per US$ 1.00 on July 14, 2022, before ending the year at Ch$ 855.86 per US$ 1.00. 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 64.93% 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.

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We have in the past identified a material weakness in our internal controls over financial reporting and may experience additional material weaknesses or otherwise fail to maintain an effective system of internal control over financial reporting, which could result in material misstatements of our consolidated financial statements, or cause us to fail to meet our periodic reporting obligations.

In 2020, we identified a material weakness in our internal control over financial reporting, which has been remediated.

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 distribution assets that are exposed to damage from the increased severity and frequency of extreme weather events, such as cyclones 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, 2022, our net consolidated debt totaled Ch$ 3.1 trillion consisting of: (i) financial liabilities of Ch$ 2.4 trillion, (ii) accounts payable to related parties of Ch$ 1.6, and (iii) less cash and equivalents and hedge derivatives of Ch$ 0.9 trillion. Please see Notes 20, 10, and 6 of the Notes to our consolidated financial statements for further information on related-party transactions and financial liabilities, respectively.

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 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.

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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 fines, penalties, or sanctions 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 38 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 36.3 of the Notes to our consolidated financial statements for further information on our litigation proceedings.

E. Climate Change

General

Climate change is a principal challenge of the 21^st century, and we are actively contributing to drive the global energy transition towards zero emissions with actions and strategies aligned with the most ambitious objectives at national and international levels. Our aim is to reduce our vulnerability to the physical impacts of climate change by improving our adaptability while reducing carbon emissions through innovative technologies and processes.

Mitigating the effects of climate change is part of our strategy and is integrated into our existing processes, which allows us to assess climate-related risks and opportunities, thus helping us become more resilient and flexible, as well as improving our capital allocation. An integrated process allows us to assess how climate

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change impacts our businesses, and then make appropriate adjustments to other areas of risk, such as operational or financial risks.

Our strategy for managing climate change has been developed in line with the recommendations of the Task Force on Climate-related Financial Disclosures (“TCFD”) of the Financial Stability Board. We have established a universal climate change management framework across all business units and continuously monitor metrics and targets.

Identifying and Managing Risks

Climate change risk management affects various business units and processes across the Company, which implies risks and opportunities related to the management of our assets and delivery of services offered to our customers. Risks related to climate change cut across several risk categories classified and defined by the Company, each requiring appropriate metrics and analysis to measure and mitigate its effects, as well as to seize its opportunities.

Climate change produces phenomena that affect our business in the short-, medium-, or long-term, which we classify as:

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Physical acute phenomena affecting, for example, industrial assets in terms of damages and business operation.

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Physical chronic phenomena affecting both the energy system (e.g., temperature impact on energy demand) and assets (e.g., changes in climate affecting power production).

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Transition phenomena such as different industrial and business sectors trending towards a green economy (e.g., changes in policy and regulation or in technology and market dynamics).

We conduct impact assessment using a methodology related to the specific phenomena assessed, allowing for quantitative impact evaluation at the operational, economic, or financial level. The methodology used to assess the physical acute phenomena considers an event probability defined by scenarios. To connect scenarios to impacts, two elements are considered: (1) vulnerability (the value lost upon the occurrence of a given catastrophic event for each location and asset) and (2) exposure (the economic value that could be materially impacted).

To assess physical chronic phenomena, climate scenario metrics (e.g., increase in temperature, increase in rain precipitation, etc.) are applied to calculate the change in relevant key performance indicators (KPIs). Assessing physical impacts requires establishing links between climate variables and the business risks and opportunities. These links enable a quantitative assessment of effects on our business related to a selected climate phenomenon expected in the future.

Similarly, to assess the impact of transition phenomena, internal models weigh the effects of changes in selected variables with the greatest impact on the Company (e.g., price of electricity, power demand, commodity prices, local or global policies, increase in competition, etc.).

The results of the impact assessment are used across all levels and units in the Company and thoroughly integrated into processes and strategic planning. Strategic planning activities consider the consequences of climate change and define events and related risks and opportunities relevant to the Company. These activities also determine how short-, medium-, and long-term scenarios affect our assets and services. Analyzing climate change provides insight and information for direct investments to improve the development and operation and management of the current assets.

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Effects of Risks on Business and Strategy

We use scenarios in the planning, capital allocation, strategic positioning, risk assessment and strategic resilience processes. With the use of scenarios, we can model alternatives and determine some key variables of uncertainty, such as the achievement of the objectives defined in the 2015 Paris Agreement on Climate Change (the “Paris Agreement”). A forecasting approach that provides projections based on past behavior does not allow us to anticipate changes or incorporate assessments of risks or uncertainties. Conversely, the use of scenarios offers us greater flexibility and allows us to prepare for risks and opportunities. As part of the process of defining our scenarios, we have identified and analyzed in depth the medium- and long-term trends, as well as their expected impacts on our industry. This analysis is the basis for defining our actions to anticipate and adapt to changes and developments, as well as take advantage of opportunities in our businesses.

We analyze the different scenarios published by external bodies and organizations in order to compare the results in terms of energy mix, emissions trends, and technological options, and identify the main drivers of the energy transition for each of them. These scenarios are grouped by global and local contexts. We analyze reports, data, and scenarios supported by a constant dialogue with the analysts of the main scenario providers.

Global energy scenarios are typically classified according to the level of climate ambition:

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Business as usual/ Stated policies: energy scenario based on current policies that provides a conservative reference point for the future, representing the evolution of the energy system in the absence of additional climate and energy policies. These scenarios currently fail to achieve the goals of the Paris Agreement.

●

Paris Aligned: energy scenario aligned to the Paris Agreement that includes a goal of limiting the increase in global average temperature to “well below 2°C” compared to pre-industrial levels. To achieve this objective, the scenarios consider new and more ambitious policies for the electrification of end uses and for the development of renewable energies.

●

Paris Ambitious: global energy scenario that maps out a path to zero emissions by 2050, in line with the most ambitious goal of the Paris Agreement: the stabilization of the increase in global average temperature within 1.5°C, albeit with different probability intervals.

We collect the key metrics of the energy system. As a result of the data analysis, we are able to understand the key elements of the Business as usual / Stated policies scenario and to identify the drivers that lead to an acceleration of the energy transition in the Paris Aligned and Paris Ambitious scenarios. By way of example, comparing the rate of electrification and the share of renewables in the different scenarios, there is full consensus among energy analysts that the main drivers for achieving more ambitious climate goals are the process of electrifying end uses and the increase in electricity generation from renewable sources, both in the medium- and long-term.

The scenarios represent a possible non-deterministic evolution of the contribution of various energy sources to emissions. The main assumptions that we consider in defining the energy transition scenarios refer to:

●

Local regulatory policies and measures to combat climate change, increase energy security and promote sustainable development (i.e., measures to reduce carbon dioxide emissions and fossil fuel consumption), to increase energy efficiency, electrification of the consumption, participation in the generation of renewable electricity.

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●

Global macroeconomic and energy context in terms of gross domestic product, population, and commodity prices, taking into account international benchmarks.

●

Evolution of energy production, conversion, and consumption technologies, both in terms of technical operating parameters and costs.

In 2022, we reviewed the framework for medium- and long-term energy transition scenarios and defined a scenario considering the principal uncertainties and factors regarding macroeconomic and energy developments. Our reference scenario for long-term planning assumes the following:

●

Paris Aligned (i.e., achieving an increase in global average temperature compared to pre-industrial levels below 2°C, anticipating a higher level of climate ambition than the Business as usual/Stated policies scenarios, but without necessarily assuming global achievement of the zero-emission target by 2050);

●

Geopolitical tensions exacerbated by the Russia-Ukraine conflict will have lasting effects, resulting in an acceleration of electrification and renewables and increased use of liquified natural gas (“LNG”); and

●

Low or endemic Covid-19 expectancy, a high vaccination rate, and no need for large-scale lockdowns.

Regarding the possibility of assuming the achievement of the most challenging objective of the Paris Agreement, that is, stabilizing the global average temperature within +1.5°C, as a reference scenario for long-term planning, the uncertainty clearly remains that some countries could delay the decarbonization process towards zero emissions by 2050.

Considering the external context, we operate a business model with strategic guidelines that are in line with the maximum ambition of the objectives of the Paris Agreement. To mitigate climate change risks, we have set a goal for 2040 to achieve zero direct emissions (Scope 1), with fully renewable electricity generation, and zero emissions associated with retail energy sales (Scope 3). We continue to monitor the financial and operational feasibility of taking more aggressive action to further reduce our GHG emissions.

For further information regarding the effects of related risks on our strategy, business model, and outlook, please see “Item 3. Key Information — D. Risk Factors.”

Transition Plan

We are committed to transforming our energy matrix to achieve 100% renewable energy generation with zero direct GHG emissions by 2040. To achieve zero emissions, we are focusing on the following areas:

Closure of coal-fired power plants: We closed the Tarapacá plant (158 MW) in December 2019, the Bocamina I plant (128 MW) in December 2020, and the Bocamina II plant (350 MW) in September 2022.

●

Focus on renewable energy: We expect to add approximately 1 GW of net installed capacity from renewable energy sources by 2025, increasing to 79% our net installed capacity from renewable sources, including solar, hydroelectric, wind, and geothermal technology. The capital expenditure to develop these renewable energy plants between 2023 and 2025 is US$ 1.1 billion.

●

Innovation and new technologies: Coal phase-out and poor hydrology conditions affect spot prices. Thus, diversifying generation technologies and geography promotes a resilient strategy. In 2022 we developed the first project for green hydrogen production, several distributed generation projects, and we are currently adopting several battery energy storage systems (BESS) in our projects under construction. We are also exploring wave energy through our MERIC Open Sea Lab pilot project.

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●

Electrification: It is essential to our goal of zero emissions that we help consumers achieve and manage their emissions. To that end, our affiliate, Enel X Chile, has implemented e-home services (assistance services, air conditioning, and photovoltaic (PV) panels) and heating replacement to retail customers; PV and demand response solutions to commercial and industrial sector; public lighting, and public charging points, and e-buses solutions to the Chilean government as e-mobility solutions.

●

Sustainable financing: To promote a sustainable business model, we have entered into sustainability-linked credit agreements financing contracts that link the interest rate to the reduction of our direct GHG emissions (Scope 1 targets).

The following table sets forth our direct (Scope 1) and indirect (Scopes 2 and 3) GHG emissions for the year ended December 31 for the following periods:


	Year ended December 31,
Greenhouse Gas Emissions	2022	2021	2020

	(in millions of grams of CO₂ eq.)
Total direct emissions (Scope 1)	4,846	5,187	4,303
Total indirect emissions (Scope 2)	12	10	10
Total indirect emissions (Scope 3)	1,773	1,360	177

We operate a business model aligned with the goal of not exceeding a temperature increase of 1.5°C compared to pre-industrial levels. To achieve this and our zero emissions goals, we have closed our coal-fired power plants as of 2022 and aim to close our natural gas plants by 2040. We do not use renewable energy certificates (“RECs”) as part of our zero-emission plan. In 2022 the reference carbon price we considered was EUR 80.8 per ton, in line with the European Unionʼs Emissions Trading System.

Continuous investments in renewable energy that have been systematically carried out since 2012 allow us to set our own targets by limiting direct emissions (Scope 1) to 105 grams of CO₂eq./kWh by 2025, and zero emissions by 2040. To ensure transparency in communications and relations with stakeholders, we report the performance of our climate actions in line with international standards, such as the GHG Protocol. We also follow the guidelines for reporting indicators of the Sustainability Accounting Standards Board and report the impact of climate risks according to the recommendations of the TCFD.

Item 4. Information on the Company

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, 2022, Enel beneficially owned 64.93% 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

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	Santiago, Chile
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 in a spin-off transaction. As a result of the spin-off, Enersis Chile was created and changed its name to Enel Chile. As of December 31, 2022, Enel Chile owns 99.09% of Enel Distribution and 93.55% of Enel Generation.

Pursuant to Law No. 21,194, the Distribution Tariff Law adopted in 2019, 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. In addition, the energy commercialization segment, formerly operated by Enel Distribution, was transferred to Enel Generation Chile to improve synergies and cost-efficiency among affiliates.

On December 9, 2022, Enel Chile completed the sale of its remaining interest in Enel Transmission to Sociedad Transmisora Metropolitana SpA (a company 100% controlled by Inversiones Grupo Saesa Limitada, an unrelated company), consisting of 99.09% of Enel Transmission shares. For further information related to the sale of Enel Transmission, see Note 5 and Note 33 of the Notes to our consolidated financial statements.

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

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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 2023-2025 period, we expect to make capital expenditures of Ch$ 1.5 trillion in our subsidiaries (US$ 1.7 billion, calculated based on the Observed Exchange Rate as of December 31, 2022), 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. While our planned investments go beyond the 2023-2025 period, we report three years to align with Enel’s three-year industrial plan disclosed in November 2022. Please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further information.

The table below sets forth the cash flows used to purchase property, plant and equipment and intangible assets in 2022, 2021, and 2020:

Capital Expenditures in 2022, 2021, and 2020

In the last three years, our capital expenditures were principally related to the development of solar projects, distributed generation projects, hydroelectric power plants, wind farms, and maintenance of our existing power plants.

During 2022, 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 2022, our generation business investments focused primarily on (i) solar projects (Finis Terrae, Guanchoi (f.k.a. Campos del Sol II), and Valle del Sol); (ii) PMGD I, II, III, and IV solar projects, which comprise a portfolio of distributed generation projects; (iii) Los Cóndores hydroelectric project; (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.

Business Overview.

We are a publicly held limited liability stock corporation engaged in the generation and distribution of electricity in Chile through our subsidiaries and affiliates. As of December 31, 2022, we had 8,408 MW of net installed capacity and approximately 2.1 million distribution customers. Of our total net installed capacity, 76% corresponds to renewable energies, including 3,509 MW of hydroelectric power plants, 725 MW of wind farms, 2,042 MW of solar plants, and 83 MW of geothermal capacity. All our net thermoelectric installed capacity corresponds to gas/diesel power plants (2,049 MW). As of and for the year ended December 31, 2022, we had consolidated assets amounting to Ch$ 11.86 trillion and operating revenues of Ch$ 4.96 trillion.

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We also participate in other activities that are not core businesses and represent less than 1% of our 2022 revenues. We do not report them as a separate business segment in this Report or in our consolidated financial statements.

The table below presents our revenues:


	Year ended December 31,
Revenues	2022	2021	2020	Change 2022 vs. 2021

	(in millions of Ch$)			(in %)
Generation	3,877,759	1,953,288	1,577,422	98.5
Distribution	1,454,722	1,201,833	1,382,068	21.0
Other businesses and intercompany transaction adjustments	(376,049)	(299,891)	(374,088)	(25.4)
Total revenues	4,956,432	2,855,230	2,585,402	73.6

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 Note 36.5 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 2022, our consolidated electricity sales were 32,120 GWh, and our electricity production was 22,215 GWh, representing a 13.8% increase and 16.7% increase, respectively, compared to 2021. Our total net installed capacity in 2022 was 8,408 MW, representing a 5.5% increase compared to 2021, mainly due to solar projects that reached commercial operation during 2022.

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,
	2022	2021	2020
Number of generation facilities⁽¹⁾	61	52	46
Net installed capacity (MW)⁽²⁾⁽³⁾	8,408	7,973	7,200
Electricity generation (GWh)	22,215	19,034	19,330
Electricity sales (GWh)	32,120	28,214	22,960

(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 net installed capacity is the maximum capacity (MW) under specific technical conditions and characteristics and excludes the MW that each facility consumes for its own operation. 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 II plants were decommissioned on December 31, 2020, and September 30, 2022, 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

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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 2022, 44.0% was from hydroelectric sources, 37.0% was from thermal sources, and 9.7%, 7.6%, and 1.7% were from solar, wind, and geothermal energy sources, respectively.

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

GENERATION BY TYPE OF ENERGY (GWh)


	Year ended December 31,
	2022		2021		2020
	Generation	%	Generation	%	Generation	%
Hydroelectric	9,768	44.0	7,743	40.7	9,712	50.2
Solar	2,160	9.7	1,235	6.5	1,177	6.1
Wind	1,694	7.6	1,731	9.1	1,768	9.2
Geothermal	382	1.7	284	1.5	221	1.1
Thermal	8,211	37.0	8,041	42.2	6,452	33.4
Total generation	22,215	100.0	19,034	100.0	19,330	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,
	2022		2021		2020
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales Volume
Regulated customers	11,853	36.9	10,056	35.7	10,838	47.2
Unregulated customers	18,863	58.7	17,528	62.1	11,043	48.1
Total contracted sales⁽¹⁾	30,716	95.6	27,584	97.8	21,881	95.3
Electricity pool market sales	1,404	4.4	630	2.2	1,079	4.7
Total electricity sales	32,120	100.0	28,214	100.0	22,960	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.

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

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.

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 the 2021 process.

In July 2022, 777 GWh per year of energy were awarded in a tender process to supply electricity for 15 years starting in 2027. The average awarded price was US$ 37.38 per MWh. We did not have electricity awarded in the 2022 process.

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

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

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 weather 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, LNG, or diesel) and energy purchases on the spot market. These actions could result in higher costs.

Operations

We participate in electricity generation through our subsidiaries, Enel Generation, EGP Chile, and Pehuenche. As of December 31, 2022, we had 61 generation power plants in Chile with a total net installed capacity of 8,408 MW, representing 27% of the National Electricity System’s (“SEN” in its Spanish acronym) installed capacity in 2022.

Enel Generation owns 13 hydroelectric, 7 thermal, and 2 wind generation power plants, with a total net installed capacity of 4,851 MW. EGP Chile owns 2 hydroelectric power plants, 8 wind farms, 25 solar parks, and 1 geothermal power plant, with a total net installed capacity of approximately 2,861 MW. Pehuenche owns 3 hydroelectric power plants, with a net installed capacity of 697 MW. For information on the net 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 2022, the electricity demand throughout the SEN increased by 2.6%. The total electricity demand was 77,044 GWh in 2022 and 75,065 GWh in 2021. Our total generation amounted to 22,215 GWh in 2022, which represents 28.8% of the total demand.

Our total hydroelectric generation (including mini-hydro) accounted for 44.0% of our total generation in 2022, reaching 9,768 GWh, an increase of 26.1% compared to 2021, while our thermal generation accounted for 37.0% of our total generation in 2022, reaching 8,211 GWh, an increase of 2.1% compared to 2021.

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

ELECTRICITY GENERATION BY COMPANY (GWh)


	Year ended December 31,
	2022	2021	2020
Enel Generation	15,686	13,648	13,612
EGP Chile⁽¹⁾	4,486	3,451	3,418
Pehuenche	2,043	1,935	2,300
Total	22,215	19,034	19,330

(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,
	2022		2021		2020
	Generation	%	Generation	%	Generation	%
Hydroelectric generation	9,731	43.8	7,698	40.4	9,680	50.1
Thermal generation	8,211	37.0	8,041	42.2	6,452	33.4
Wind generation – NCRE	1,694	7.6	1,731	9.1	1,768	9.1
Mini-hydro generation – NCRE	37	0.2	45	0.2	32	0.2
Solar generation – NCRE	2,160	9.7	1,235	6.5	1,177	6.1
Geothermal generation – NCRE	382	1.7	284	1.5	221	1.1
Total generation	22,215	100.0	19,034	100.0	19,330	100.0

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 1958 agreement with DOH.

In October 2020 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 2021/2022 and 2022/2023 irrigation season.

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In October 2022, Enel Generation signed an agreement with the Biobío River Basin Vigilance Board to limit the use of the Ralco reservoir during the 2022/2023 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 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 2022, Enel Generation used 453 million cubic meters of LNG for its generation and commercialization requirements, which represents 63% more compared to 2021, mainly explained by the greater availability of Argentine gas compared to the previous year.

In 2022, Enel Generation imported 1,085 million cubic meters of natural gas under supply agreements with YPF, Total Austral, and Pan American Energy, among other producers.

Concerning the commercialization of LNG by truck, 112 million cubic meters were delivered in 2022, a 26% increase compared to 2021.

In December 2022, we reached an agreement with Shell Global LNG Limited, through which the parties agreed to a series of modifications to the current long-term supply contract, corresponding, among others, to a reduction of LNG volumes, which are projected to be surplus to meet its future needs.

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 2.6% in 2022 compared to 2021.

The following table sets forth SEN’s electricity sales:

ELECTRICITY SALES IN SEN (GWh)

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Our electricity sales reached 32,120 GWh in 2022, 28,214 GWh in 2021, and 22,959 GWh in 2020, which represented a 41.7%, 37.6%, and 32.0%, market share, respectively. Energy purchases increased by 7.9% in 2022, compared to 2021, mainly to comply with our contractual obligations with third parties.

The following table sets forth our electricity generation and purchases:

ELECTRICITY GENERATION AND PURCHASES (GWh)

Year ended December 31,

2022

2021

2020

(GWh)

%
of Volume

(GWh)

%
of Volume

(GWh)

%
of Volume

Electricity generation

22,215

69.2

19,034

67.5

19,330

84.2

Electricity purchases

9,905

30.8

9,180

32.5

3,629

15.8

Total

32,120

100.0

28,214

100.0

22,959

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 2022, 2021, and 2020, we had 993, 961, and 384 customers, respectively. In 2022 our customers included 21 regulated customers and 972 unregulated customers. The 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 are prohibited from selling electricity and power to unregulated customers. As a result, Enel Distribution transferred all its unregulated customers to Enel Generation.

For the year ended December 31, 2022, our principal distribution customers were (in alphabetical order): Empresa Eléctrica de Puente Alto, Enel Distribution, Grupo CGE, Grupo Chilquinta, and Grupo SAESA.

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.

Our principal unregulated customers were (in alphabetical order): Anglo American Sur, BHP Billiton, Compañia Minera Doña Inés de Collahuasi SCM, Minera Valle Central, and SCM Minera Lumina Copper Chile.

Electricity generation companies compete based mainly on price, technical experience, and reliability. We have lower marginal production costs than companies whose installed capacity is primarily thermal because 44.0% 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

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forced to buy more expensive electricity from thermal generators at spot prices to comply with our contractual obligations.

Electricity Distribution and Networks Business Segment

Our distribution and network operations are conducted through Enel Distribution, in which we have a 99.09% economic interest.

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, 2022, we distributed electricity to more than 2 million residential, commercial, industrial, and other customers, who are primarily municipalities, represented 36.0%, 11.3%, 0.8%, and 51.9%, respectively, of our total electricity sales of 17,534 GWh, which is an increase of 5.2% compared to 2021.

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


	Year ended December 31,
	2022	2021	2020
Electricity sales (GWh)	17,534	16,668	16,481
Residential	6,309	5,140	5,006
Commercial	1,986	2,029	4,606
Industrial	144	726	1,686
Other customers⁽¹⁾	9,095	8,773	5,183
Number of customers (thousands)	2,080	2,038	2,008
Residential	1,866	1,826	1,801
Commercial	157	156	154
Industrial	11	12	12
Other customers⁽¹⁾	46	44	41
Energy purchased (GWh)⁽²⁾	18,243	17,472	17,356
Total energy losses (%)⁽³⁾	5.1	5.2	5.2
SAIDI (minutes)⁽⁴⁾	157	152	171
SAIFI (times)⁽⁴⁾	1.5	1.5	1.5
Collection rate⁽⁵⁾	95.5	97.5	96.9

(1)	The data for other customers includes tolls.

(2)	In 2022, 2021, and 2020 Enel Distribution acquired 42%, 41%, 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)	Includes distribution and networks and transmission business segments.

(5)	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.

In September 2018, there was an extraordinary tariff update process, which was non-retroactive and will be in effect until the tariff-setting process for the 2020-2024 period is completed. The ongoing 2020-2024

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process began in January 2020 and should be concluded during 2023. However, due to the social unrest that began in October 2019, distribution tariffs for 2020 and 2021 were fixed under Law No. 21,185, which created a temporary electricity price stabilization mechanism for customers subject to tariff regulation. In July 2022, the Chilean Congress passed Law No. 21,472, which complements Law No. 21,185 by creating a new stabilization fund program and establishing a new transitory mechanism for stabilizing customers’ electricity prices under the regulated price system. The purpose of the mechanism is to limit the increase in electricity bills for regulated customers during 2022 and to allow such increases to occur gradually over the next 10 years. The tariff-setting process for the 2024-2028 period should start in 2023.

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 Andes S.A., Colbún S.A., Enel Generation, Engie Energía Chile S.A., and other companies.

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.

Cybersecurity

General

Since September 2016, Enel S.p.A. has had within the Global Digital Solutions area a “Cyber Security” unit committed to corporate governance, direction, and control of cybersecurity topics. The head of the Cyber Security unit, which is also Enel’s Chief Information Security Officer, reports directly to the head of Global Digital Solutions.

Enel also has a Cyber Security Committee, chaired by the Enel CEO and made up of top officers, that addresses and approves the cybersecurity strategy and checks the progress of its implementation at regular intervals (at least yearly). Therefore, the Enel CEO is engaged in the cybersecurity strategy process. Cybersecurity is always part of the agenda at managerial meetings (e.g., Business Reviews, Operating Review Meetings), Risk Control Committee meetings, and at the executive management level. The results of such evaluations guide Enel cybersecurity strategy in terms of strategic initiatives, processes, and organization.

Cybersecurity Framework

In 2018, Enel adopted the Cyber Security Framework (the “Framework”) and integrated it into each company throughout the entire organization, including Enel Chile. The Framework is based on sector best practices and international standards (ISO 27001/NIST) and addresses the principles and operational processes that support a global strategy of cyber risk analysis, prevention, and management. This document is structured in 8 processes fully applicable to the complexity of the usual Information Technology (“IT”), Operational Technology (“OT”), and Internet of Things (“IoT”) environment. The Framework defines roles and responsibilities by implementing the full involvement of business areas, assigning responsibilities to stakeholders in the context of the organization, and establishing a solid basis for the full merger of technologies,

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core processes, and people. It is focused and driven by a “risk-based” approach and a “cyber security by design” principle.

The “risk-based” approach places risk assessment as a prerequisite for our strategic decisions. The estimation of cybersecurity risk factors (impacts, threats, vulnerabilities) is critical to assess our level of cyber risk and to identify appropriate treatment actions to mitigate it. The cybersecurity by design principle ensures that we take cybersecurity requirements into consideration from the very early stages and along the entire lifecycle of systems and services.

The Framework provides the overall coverage of the following areas:

●

Cyber Security Risk Assessment: aims at identifying, analyzing, and evaluating cybersecurity risks, taking into consideration our risk posture.

●

Cyber Security Strategy: aims at steering cybersecurity strategy, defining cybersecurity objectives and priorities, addressing cybersecurity initiatives, and coordinating investment activities on cybersecurity topics for the Company. It ensures cybersecurity policy definitions, managerial reporting, and continuous monitoring of ongoing cybersecurity initiatives.

●

Cyber Security Engineering, Design, and Implementation: aims at ensuring the adoption of cybersecurity principles from the beginning and during the entire lifecycle of IT/OT/IoT solutions and infrastructures;

●

Cyber Security Risk Treatment: aims at defining and implementing the most appropriate risk treatment actions to face cybersecurity risks.

●

Cyber Security Assurance: aims at analyzing, verifying, and testing the effectiveness of the implemented risk response measures, detecting vulnerabilities, and assessing cybersecurity controls, ensuring the monitoring of remediation plans.

●

Cyber Emergency Readiness: aims at monitoring, tracking, and reporting risks exposures and handling cybersecurity incidents that could occur.

●

Identity Management and Access Control: aims at managing the full lifecycle of digital identities used within the Company and performing security controls on access privileges to highlight possible risks and security improvement areas, triggering the necessary remediation processes.

●

Cyber Security Awareness and Training: aims at driving and running our Cyber Security Awareness and Training initiatives to focus attention on critical cyber security topics, working on behaviors and on the human factor.

In accordance with the Framework, we have and use a Cyber Security Business Impact Analysis and Risk Assessment methodology (Cyber Risk Management Procedure). It aims to identify, prioritize, and estimate cybersecurity risks within the Company, taking into consideration established risk acceptance levels. The first phase of the process aims to identify the risk level associated with a logical or physical asset (Risk Center), while the second phase of the process aims to define what controls need to be implemented to achieve the desired level of risk mitigation.

We have a Cyber Emergency Readiness Team (CERT), whose mission is to protect its employees and assets (instrumental to our business that could be compromised by cyber threats), promoting a proactive approach based on “incident readiness” rather than “incident response”. The CERT operates with Threat

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Intelligence, Incident Response, and Information Sharing processes, and exchanges information within a network of accredited international partners.

In case a cybersecurity incident occurs, it is classified according to the Enel Cyber Impact Matrix considering the improved event correlation capabilities coming from the adoption of new cybersecurity services. Most incidents are classified at level 0/1 and are considered “day-by-day” instances because they do not significantly impact our systems. Generally, these incidents are automatically or semi-automatically blocked or managed by our systems, thus preventing and/or reducing the potential impact of a cyberattack. Incidents classified at level 2/3/4 of the Enel Cyber Impact Matrix may have an impact on the Group and are managed by the CERT in conjunction with the relevant stakeholders.

For the year ended December 31, 2022, there were no cybersecurity incidents classified at level 4, the maximum impact of the Enel Cyber Impact Matrix.

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

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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 (the “Distribution Tariff Law”), distribution companies may not enter into new electricity supply contracts with unregulated customers.

Concessions

Hydroelectric generation requires a concession granted by the authorities to operate for an indefinite time; however, 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 Decree with the Force of Law (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 provided in Resolution No. 667/2002 and the Distribution Tariff Law, 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.

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Owners of the STN must be limited liability stock corporations. Individual interests in the STN by companies operating in another electricity or unregulated customer segment cannot exceed, directly or indirectly, 8% of the total investment value of the STN. 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 its generation and distribution segments separate and manage them as independent business units; Enel Chile, Enel Generation and Enel Distribution are registered with the CMF and must remain subject to the regulatory authority of the CMF and comply with the regulations applicable to publicly held limited liability stock corporations, even if any of these companies should lose such designation. The members of the boards of directors of these companies must be elected from different and independent groups, and the external auditors of the companies must be different for local statutory purposes.

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 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, which is 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 on an aggregated or individual basis.

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 Electricity Law reorganized the sector, 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.

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

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 calculates 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 the 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

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

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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 2020-2023 period was concluded in February 2023 and has been effective retrospectively since January 1, 2020.

Distribution Tariffs

The Distribution Tariff Law 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 the 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, the Distribution Tariff Law establishes that the after-tax rate of return for each distributor must be between three percentage points below and two percentage points above the rate of return calculated by the CNE. The real return on investment for a distribution company depends on its actual performance relative to the standards chosen by the CNE for the efficient model company. The tariff system allows for a higher return to distribution companies that are more efficient than the model company.

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

The tariff-setting process for 2016-2020 was concluded in August 2017 and had been effective, retroactively, since November 4, 2016. In September 2018, there was an extraordinary tariff update process, which was non-retroactive and will be in effect until the tariff-setting process for the 2020-2024 period is completed. The ongoing 2020-2024 process began in January 2020 and should be concluded in 2023. However, due to the social unrest that began in October 2019, Law No. 21,185 fixed distribution tariffs for 2020 and 2021, which created a temporary electricity price stabilization mechanism for customers subject to tariff regulation. In July 2022, the Chilean Congress passed Law No. 21,472, which complements Law No. 21,185 by creating a new stabilization fund program and establishing a new transitory mechanism for stabilizing customers’ electricity prices under the regulated price system. The purpose of the mechanism is to limit the increase in electricity bills for regulated customers during 2022 and to allow such increases to occur gradually over the next 10 years. The tariff-setting process for the 2024-2028 period is expected to start in 2023.

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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.

On June 13, 2022, Law No. 21,455 (the “Climate Change Framework Law”) was enacted. The law establishes that Chile be carbon neutral and climate resilient by 2050, which could be moved up if circumstances allow for it. To address climate change, the law establishes concrete actions for 17 executive departments as well as powers and obligations at regional and local levels. It also establishes the Long-Term Climate Strategy, a roadmap detailing how Chile will fulfill its commitments through concrete actions over a 30-year period and requires the preparation of sectoral mitigation and adaptation plans with concrete measures and actions to meet these goals.

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 64.93% of our shares as of December 31, 2022. 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 30 countries worldwide and a consolidated installed capacity of 93 GW. Enel distributes electricity through a network of 2.3 million kilometers to more than 75 million customers. 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 December 31, 2022

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

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We consolidated the principal subsidiaries listed in the following table as of December 31, 2022. 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	Consolidated Assets	Consolidated Revenues and Other Operating Income
	(in %)	(in billions of Ch$)
Electricity Generation
Enel Generation	93.55%	4,407	3,819
EGP Chile	99.99%	4,026	510
Electricity Distribution
Enel Distribution	99.09%	2,021	1,390

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 61 generation power plants, all located in Chile, of which 18 are hydroelectric (3,508 MW of net installed capacity), 7 are thermal (2,050 MW of net installed capacity), 25 are solar (2,042 MW of net installed capacity), and 10 are wind-powered (725 MW of net installed capacity), and one is geothermal (83 MW of net 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

Property, Plant, and Equipment of Generation Companies
			Net Installed Capacity⁽¹⁾ As of December 31,
Company	Power Plant Name	Power Plant Type⁽²⁾	2022	2021	2020

			(in MW)
Enel Generation	Ralco	Reservoir	689	689	689
	Pangue	Reservoir	466	466	466
	El Toro	Reservoir	449	449	449
	Rapel	Reservoir	375	375	375
	Antuco	Run-of-the-river	320	320	320
	Cipreses	Reservoir	106	106	106
	Abanico	Run-of-the-river	93	136	136
	Sauzal	Run-of-the-river	80	79	79
	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	11	12	12
	Ojos de Agua	Run-of-the-river	9	9	9
	Total hydroelectric		2,720	2,763	2,762

	Atacama	Combined Cycle /Natural Gas+Diesel Oil	716	716	716
	San Isidro 2⁽³⁾	Combined Cycle /Natural Gas+Diesel Oil	380	380	380
	San Isidro 1⁽³⁾	Combined Cycle /Natural Gas+Diesel Oil	372	372	371
	Quintero	Gas Turbine/Natural Gas	255	255	255
	Taltal	Gas Turbine/Natural Gas+Diesel Oil	242	239	239
	Huasco	Gas Turbine	64	64	64
	Tarapacá	Gas Turbine/Diesel Oil	20	20	20
	Bocamina⁽⁴⁾	Steam Turbine/Coal	—	320	320
	Diego de Almagro⁽⁵⁾	Gas Turbine/Diesel Oil	—	24	24
	Total thermal		2,049	2,390	2,389

	Canela II	Wind	64	60	60
	Canela I	Wind	18	18	18
	Total wind		82	78	78

	Total Enel Generation		4,851	5,231	5,229

Pehuenche	Pehuenche	Reservoir	568	568	568
	Curillinque	Run-of-the-river	89	89	89
	Loma Alta	Run-of-the-river	40	40	40
	Total Pehuenche		697	697	697

EGP Chile	Cerro Pabellón (1,2, & 3)	Geothermal	83	69	41
	Total geothermal		83	69	41

	Pullinque	Run-of-the-river	51	51	51
	Pilmaiquén	Reservoir	41	41	41
	Total hydroelectric		92	92	92

	Guanchoi	Solar	398	—	—
	Campos del Sol	Solar	375	375	—
	Domeyko	Solar	204	204	—
	Valle del Sol	Solar	163	—	—
	Sol de Lila	Solar	161	161	—
	Finis Terrae	Solar	160	160	160
	Finis Terrae Ext	Solar	126	22	—
	Carrera Pinto	Solar	97	97	97
	Pampa Norte	Solar	79	79	79
	Azabache	Solar	61	61	4
	Lalackama	Solar	60	60	60
	Chañares	Solar	40	40	40
	Solar Diego de Almagro	Solar	36	36	36
	Lalackama 2	Solar	18	18	18
	Finis Terrae 3	Solar	18	—	—
	PMGD La Colonia	Solar	11	—	—
	PMGD Rinconada Alcones	Solar	10	—	—
	PMGD Don Rodrigo	Solar	5	—	—
	PMGD Caracoles	Solar	3	—	—
	PMGD Coinco	Solar	3	—	—
	PMGD Dadinco	Solar	3	3	—
	PMGD El Sharon	Solar	3	—	—
	PMGD Piduco	Solar	3	—	—
	PMGD San Camilo	Solar	3	3	—
	La Silla	Solar	2	2	2
	Total solar		2,042	1,321	496

	Sierra Gorda Este	Wind	112	112	112
	Eólico Taltal	Wind	106	99	99
	Talinay Oriente	Wind	90	90	90
	Valle De Los Vientos	Wind	90	90	90
	Renaico	Wind	88	88	88
	Renaico 2	Wind	72	—	—
	Talinay Poniente	Wind	61	61	61
	Los Buenos Aires	Wind	24	24	24
	Total wind		643	564	564

	Total EGP Chile (NCRE)		2,861	2,046	1,193
	Total Net Capacity Enel Chile		8,408	7,973	7,118

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(1)

As of 2022, all figures have been restated to show each plant’s net installed capacity, which excludes the MW that each power plant consumes for its operation. Prior to 2022, we presented gross installed capacity figures, which did not exclude 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, diesel, or fuel oil to produce steam that moves the turbines. “Gas Turbine” or “Open Cycle” refers to thermal power that uses either diesel or natural gas to produce steam that turns the turbines. “Combined-Cycle” refers to a thermal power plant that burns natural gas, diesel oil, or fuel oil to turn the first turbine and then recovers the heat to generate steam to turn a second turbine.

(3)

The environmental permit limits the capacity of San Isidro 1 and 2 combined to 740 MW.

(4)

The Bocamina I and II plants were decommissioned on December 31, 2020, and September 30, 2022, respectively.

(5)

The Diego de Almagro gas turbine plant was sold on February 4, 2022.

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 subsidiaries’ 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, 2022			As of December 31, 2021			As of December 31, 2020
	Concession Area (km²)	MV (km)	LV (km)	Concession Area (km²)	MV (km)	LV (km)	Concession Area (km²)	MV (km)	LV (km)
Enel Distribution	2,105	5,598	12,068	2,105	5,568	12,011	2,105	5,406	11,960

(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, 2022

As of December 31, 2021

As of December 31, 2020

Number of
Transformers

Capacity
(MVA)

Number of
Transformers

Capacity
(MVA)

Number of
Transformers

Capacity
(MVA)

Enel Distribution

22,356

5,347

22,137

5,215

21,997

5,108

(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. On December 9, 2022, Enel Transmission was sold in a stock purchase agreement and is no longer our subsidiary as of December 31, 2022.

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

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


	As of December 31, 2022				As of December 31, 2021				As of December 31, 2020
	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⁾	0	0	0	0	57	169	8,531	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.

(5)	As of January 1, 2021, the transmission business assets were spun-off from Enel Distribution. Figures for 2020 correspond to Enel Distribution. On December 9, 2022, Enel Transmission was sold in a stock purchase agreement and is no longer our subsidiary as of December 31, 2022.

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 completed, under construction, and under development during the fiscal year ended December 31, 2022. 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

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

Distribution and Networks and Transmission Businesses Projects

In 2022 our subsidiaries Enel Distribution, its subsidiary Enel Colina, and Enel Transmission, which was sold on December 9, 2022, invested a total of Ch$ 145.1 billion in projects related to our customers’ natural growth rate, service quality requirements, and safety and information system needs.

The most relevant investments in 2022 include the following:

●

Ch$ 60.3 billion in the medium and low voltage network to facilitate new customer connections, including residential customers, large volume clients, and real estate projects.

●

Ch$ 28.6 billion to reinforce quality of service: Ch$ 12 billion due to the purchase of land for SE Providencia; Ch$ 10.7 billion to reinforce feeders through maintenance and telecontrol equipment; and Ch$ 5.9 billion in smart meter program.

●

Ch$ 18.3 billion oriented to the digitalization process.

●

Ch$ 14.5 billion to increase our distribution capacity: Ch$ 11 billion for high and medium voltage primary substations; and Ch$ 3.5 billion for construction and reinforcement of new feeders

●

Ch$12.9 billion for corrective network maintenance and technological adaptation

●

Ch$ 5.1 billion to comply with regulations and higher standards regarding network and substation normalization.

●

Ch$ 3.5 billion in anti-theft measures, such as the shielding and reinforcement of the network.

●

Ch$ 1.9 billion in network relocations due to new highways and requests from municipalities

Generation Business Projects

Projects Completed in 2022

EGP Chile

Cerro Pabellón Geothermal Extension Project

The Cerro Pabellón extension project is a geothermal energy plant with a net installed capacity of 32 MW and is in the Antofagasta Region in northern Chile. It has synergies with our Cerro Pabellón geothermal project and uses existing infrastructure such as a substation and a transmission line.

The total investment has been US$ 131.1 million. Construction began in August 2019, and the project was completed in June 2022, reaching commercial operation in December 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 a net installed capacity of 126 MW.

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

The total investment has been US$ 119.5 million. Construction began in May 2020, and the project was completed in 2022. We expect the project to reach commercial operation in 2023.

Finis Terrae 3 Solar Project

The Finis Terrae 3 solar project is in the Antofagasta Region of Chile. It has a net installed capacity of 18 MW and is an extension of the Finis Terrae Solar Extension project.

The total approved investment was US$ 11.1 million, of which US$ 6.4 million had been incurred as of December 31, 2022. Construction began in August 2021, and the project was completed in 2022. We expect the project to reach commercial operation in 2023.

Guanchoi Solar Project (f.k.a. Campos del Sol II)

The Guanchoi solar project is in Copiapó in the Atacama Region and has a net installed capacity of 398 MW. Guanchoi is a PV solar power plant consisting of 893,508 crystalline bifacial PV modules with a solar tracking system. The project site occupies approximately 1,000 hectares.

The project connects to the Bella Mónica step-up substation, located between Campos del Sol I and Guanchoi. 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 was US$ 313.5 million, of which US$ 293.8 million had been incurred as of December 31, 2022. Construction began in July 2021, and the project was completed in 2022. We expect the project to reach commercial operation in 2023

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 net installed capacity and an electrolyzer with a net installed capacity of 1.2 MW.

The total approved investment was US$ 4.1 million, of which US$ 2.4 million had been incurred as of December 31, 2022. Construction began in August 2021, and the project was completed in 2022, reaching commercial operation in 2022.

PMGD I Solar Project (Caracoles, La Colonia, Piduco, and Rinconada)

Caracoles, La Colonia, Piduco, and Rinconada are part of the PMGD I Solar Project, which consists of a portfolio of eight solar PV plants to develop 54 MW of net installed capacity in the Metropolitan, O’Higgins, and Maule Regions of Chile. The four plants (Carcoles, La Colonia, Piduco, and Rinconada) total 27 MW of net installed capacity, and each plant is connected to distribution lines.

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The total approved investment for the four solar plants was US$ 19.2 million, of which US$ 18.6 million had been incurred as of December 31, 2022. Construction began in August 2021, and the four solar plants were completed in 2022. We expect the project to reach commercial operation in 2023.

PMGD II Solar Project

Coinco, Don Rodrigo, and El Sharon are part of the PMGD II Solar Project, which consists of a portfolio of three solar PV plants in the Maule Region of Chile to develop 11 MW of net installed capacity. The three plants (Coinco (f.k.a. Valera) 3 MW, Don Rodrigo – 5 MW, and El Sharon – 3 MW) are connected to distribution lines.

The total approved investment was US$ 9.9 million, of which US$ 9.2 million had been incurred as of December 31, 2022. Construction began in July 2021, and the project was completed in 2022. We expect the project to reach commercial operation in 2023.

Valle del Sol Solar Project

The Valle del Sol PV solar project is in the Atacama Desert, approximately 100 km west of Calama in the Antofagasta Region in northern Chile.

It is a greenfield solar project with a net installed capacity of 163 MW that consists of 406,980 monocrystalline bifacial PV modules with a solar tracking system. The project site occupies 320 hectares. Valle del Sol will connect to the Miraje substation 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 an interconnection 10 km, 220 kV transmission line.

The total investment has been US$ 142.5 million. Construction began in 2021, and the project was completed in 2022. We expect the project to reach commercial operation in 2023.

Enel Generation

San Isidro Power Plant Upgrade

The San Isidro power plant is a combined cycle plant in the Valparaiso Region in central Chile. The power plant has two combined-cycle units (Unit 1 and Unit 2), limited by environmental authorizations to 740 MW of net installed capacity. The project consists of upgrading the existing gas turbine to improve the efficiency of both units and recover 15 MW for each unit, within the approved environmental permit.

The total approved investment was € 23.2 million (US$ 24.8 million as of December 31, 2022), of which € 8 million (US$ 8.6 million) had been incurred as of December 31, 2022. Of the remaining amount, € 9 million (US$ 9.6 million) and € 6.2 million (US$ 6.6 million) will be incurred in 2023 and 2024, respectively. The project began in September 2022 and was completed in November 2022. We expect Unit 2 and Unit 1 to reach commercial operation in 2023 and 2024, respectively.

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Projects under Construction in 2022

EGP Chile

El Manzano Solar Project

El Manzano solar project is located 30 km north of Santiago in the Metropolitan Region. It is a greenfield solar project with a net installed capacity of 99 MW that consists of 162,000 monocrystalline bifacial PV modules as well as a solar tracking system. The power plant will be able to incorporate a BESS in the future. The project site occupies 185 hectares. El Manzano will connect to the El Manzano substation, owned by Enel Distribution, through a 6.3 km medium-voltage transmission line.

The total approved investment is US$ 88.6 million, of which US$ 41.5 million had been incurred as of December 31, 2022. We expect the project to be completed in 2023-2024.

La Cabaña Wind Farm and BESS

The La Cabaña wind farm is in the Araucanía Region in southern Chile and has a net installed capacity of 106 MW and includes a BESS with a storage capacity of 34 MW. The project will connect to the national system through the Renaico wind farm substation.

The total approved investment is US$ 184 million, of which US$ 93.9 million had been incurred as of December 31, 2022. Construction began in 2022, and we expect the project to be completed in 2023.

PMGD I Solar Project (Cabimas – f.k.a. Curamachi; and Pataguas – f.k.a. Agrovision)

Cabimas and Pataguas are part of the PMGD I Solar Project, which consists of a portfolio of eight solar PV plants to develop 54 MW of net installed capacity in the Metropolitan, O’Higgins, and Maule Regions of Chile. Each project is or will be connected to distribution lines.

Four projects (Caracoles, La Colonia, Piduco, and Rinconada) were completed in 2022, and currently two additional projects (Cabimas (f.k.a. Curamachi) and Pataguas (f.k.a. Agrovision) are under construction, with a total of 21 MW of net installed capacity.

The total approved investment for the two projects is US$ 18 million, of which US$ 15.2 million had been incurred as of December 31, 2022. Construction began in August 2021, and we expect the projects to be completed in 2023.

PMGD III Solar Project

The PMGD III Solar Project consists of a portfolio of three solar PV plants (Bandurrias, Graneros, and Maitencillo), in central Chile. Each project has a net installed capacity of 3 MW, for a total of 9 MW of net installed capacity. Each plant will be connected to distribution lines.

The total approved investment for these three projects is US$ 9.4 million, of which US$ 5.8 million had been incurred as of December 31, 2022. We expect construction to begin in 2023 and the projects to be completed in 2024.

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PMGD IV Solar Project

The PMGD IV Solar Project consists of a portfolio of three solar PV plants (Doña Rubena, Hijuelas IV, and Mora) to develop 9 MW of net installed capacity in the Metropolitan and Maule Regions of Chile. Each project will be connected to distribution lines. The land has been secured and environmental approval has been obtained.

The total approved investment is US$ 9.4 million, of which US$ 5.1 million had been incurred as of December 31, 2022. We expect construction to begin in 2023 and the projects to be completed in 2024.

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 was 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$ 221.5 million, of which US$ 186.2 million had been incurred as of December 31, 2022. Construction began in April 2020. As of December 2022, 72 MW of net installed capacity had been connected. We expect the remainder of the project to be completed in 2023.

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 a net installed capacity of 205 MW, which was reduced from 357 MW in February 2023. The site occupies 850 hectares, with a perimeter of approximately 28 km.

It is a greenfield project inside the existing Sierra Gorda wind farm owned by EGP Chile. The project has five main areas for PV modules inside the wind farm and an independent space for the medium voltage/high voltage substation. It consists of 830,000 monocrystalline bifacial PV modules with a solar tracking system. The 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$ 306.5 million, of which US$ 231.8 million had been incurred as of December 31, 2022. Construction began in July 2021, and we expect the project to be completed in 2023.

Enel Generation

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

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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.

The total approved investment is US$ 1.15 billion, of which US$ 1.1 billion had been incurred as of December 31, 2022. Construction began in April 2014, and we expect the project to be completed in 2024.

Rapel Hydroelectric Repowering Project

The Rapel Hydroelectric Repowering project is being carried out within our existing 375 MW Rapel power plant 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 our net installed capacity by 2 MW (1 MW for 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.

The engineering design has been completed while model tests and the principal manufacturing activities have been executed. Supply for Unit 3 arrived at the project site in August 2022, and transport of Unit 4 supply began in December 2022. Site activities for both units were postponed until 2023 due to a lack of technical capability of a subcontractor. The project’s principal contractor is currently in the process of selecting a new subcontractor.

The total approved investment is US$ 11.9 million, of which US$ 5.1 million had been incurred as of December 31, 2022. We expect both units to be installed and the project to be completed in 2023.

Projects under Development in 2022

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.

EGP Chile

Andino Las Pataguas Solar Project

The Andinos Las Pataguas Solar project is in San Pedro in the Metropolitan Region. The project has a net installed capacity of 100 MW and includes a BESS with a storage capacity of 60 MW. The plant will be built on approximately 270 hectares and connected to the Las Arañas substation at 110 kV. The land has been secured, and environmental approval is in progress.

The total estimated investment is US$ 200 million, none of which had been incurred as of December 31, 2022. We expect construction to start in 2024 and the project to be completed in 2025.

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Don Humberto Solar Project and BESS

Don Humberto is a solar project located in the Metropolitan Region. The project has a net installed capacity of 79 MW and includes a BESS with a storage capacity of 67 MW. The land has been secured, and environmental approval has been obtained.

The total approved investment is US$ 137.8 million, of which US$ 11.3 million had been incurred as of December 31, 2022. We expect construction to begin in 2023 and the project to be completed in 2024.

Ovejera Sur Wind Project

The Ovejera Sur Wind project is in La Unión in Los Ríos Region. The project has a net installed capacity of 170 MW and includes a BESS with a storage capacity of 100 MW. The project consists of 38 wind turbines with a net installed capacity of approximately 4.5 MW each. The project will be built on approximately 5,500 hectares and will connect to the grid through the new Pichirropulli substation (220 kV). The land has been secured, and environmental approval is in process.

The total estimated investment is US$ 274 million, none of which had been incurred as of December 31, 2022. We expect construction to begin in 2024 and the project to be completed in 2025.

Rihue Wind Farm and BESS

The Rihue wind farm is in the Bio-Bio Region in southern Chile and has a net installed capacity of 120 MW and includes a BESS with a storage capacity of 34 MW. The project will connect to the national system through the Renaico Wind Farm substation.

The total approved investment is US$ 205.1 million, of which US$ 42.5 million had been incurred as of December 31, 2022. We expect the project to be completed in 2024.

Major Encumbrances

As of December 31, 2022, 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, 2022, and 2021, and for the three years ended December 31, 2022, 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.

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, 2022, has been converted at the U.S. dollar Observed Exchange Rate for that date of

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Ch$ 855.86 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,
	2022⁽¹⁾	2022	2021	2020

	(US$ millions)	(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income	5,791	4,956,432	2,855,230	2,585,402
Raw materials and consumables used	(3,972)	(3,399,524)	(2,011,305)	(1,374,445)
Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense, by nature	(753)	(644,551)	(584,330)	(1,245,212)
Operating income (loss)	1,066	912,357	259,594	(34,255)
Financial results⁽²⁾	(139)	(118,939)	(157,059)	(112,435)
Other gains	1,147	981,981	10,137	9,489
Share of profit (loss) of associates and joint ventures accounted for using the equity method	4	3,282	3,177	3,509
Income (loss) before income taxes	2,078	1,778,681	115,849	(133,692)
Income taxes	(549)	(469,697)	(15,139)	81,305
Net income	1,529	1,308,984	100,710	(52,387)
Net income attributable to the parent Company	1,463	1,252,082	85,154	(50,860)
Net income attributable to non-controlling interests	66	56,902	15,556	(1,527)
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)	0.021	18.10	1.23	(0.74)
Total basic and diluted earnings per average number of ADS (Ch$/US$ per ADS)	1.058	905.12	61.56	(36.77)
Cash dividends per share (Ch$/US$ per share)	0.00043	0.37	3.08	4.23
Cash dividends per ADS (Ch$/US$ per ADS)	0.022	18.47	154.00	211.50
Weighted average number of shares of common stock (millions)	69,167	69,167	69,167	69,167

Consolidated Statement of Financial Position Data
Total assets	13,864	11,865,580	9,500,324	7,904,472
Non-current liabilities	5,034	4,308,149	4,021,504	3,264,717
Equity attributable to the parent company	4,787	4,097,201	3,097,868	3,351,916
Equity attributable to non-controlling interests	341	291,738	248,625	242,359
Total equity	5,128	4,388,939	3,346,493	3,594,275
Capital stock ⁽³⁾	4,536	3,882,103	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$ 855.86 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)	Capital stock represents issued capital.

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.

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There are two currency markets in Chile, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal). The Formal Exchange Market consists of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market includes entities that are not expressly permitted to operate in the Formal Exchange Market, such as stockbrokers, securities agents, and foreign currency exchange houses, 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 executed 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. Foreign currency for payments and distributions concerning the ADS are purchased and remitted in 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 2022, one determines the percentage change between the reciprocal of Ch$ 844.69, the value of one U.S. dollar as of December 31, 2021, or 0.0011839, and the reciprocal of Ch$ 855.86, the value of one U.S. dollar as of December 31, 2022, or 0.0011684. In this example, the percentage change between the two dates is 1.3%, representing the 2022 year-end depreciation of the Chilean peso against the 2021 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, 2018, through December 31, 2022, 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,
2022	855.86	(1.3)
2021	844.69	(15.8)
2020	710.95	5.3
2019	748.74	(7.2)
2018	694.77	(11.5)

Source: Central Bank of Chile.

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

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

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audited consolidated financial statements as of December 31, 2022, and 2021 and for each year in the three-year period ended December 31, 2022, 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 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 (the “Tariff Stabilization Law”), which established a transitional mechanism for stabilizing customers’ electricity prices under the regulated price system. In 2021, we executed an agreement to sell up to US$ 290 million of the accounts receivables generated through this mechanism 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.

On August 2, 2022, the Chilean Ministry of Energy published Law No. 21,472, which establishes a Temporary Customer Protection Mechanism (Mecanismo de Protección al Cliente or “MPC” in its Spanish acronym) that stabilizes energy prices in the SEN and medium-sized systems in addition to those established by the Tariff Stabilization Law for regulated customers under the Electricity Law. The purpose of the MPC is to pay for the differences that may arise between the billing of the distribution companies to end customers and the amount payable to generation companies. The resources available for the MPC may not exceed US$ 1,800 million. This mechanism will be extended until the balances contemplated in the law are extinguished.

The effects of the Tariff Stabilization Law as of December 31, 2022, and 2021 are described in Note 9a.1 of the Notes to our consolidated financial statements.

On November 21, 2022, Law No. 21,505 was published, which encourages the storage of electric power through remuneration for energy, power sufficiency, and complementary services to energy storage systems, as well as electromobility through a temporary price reduction of the registration certificate for electric vehicles. This law enables new electromobility business models and the option to charge electric vehicles batteries through the provision of services to the grid. In addition, it incorporates projects related to generation and consumption infrastructure for renewable energy projects, plus storage in order to withdraw energy from and inject surpluses into the electric system.

By the first half of 2023, the Chilean Ministry of Energy plans to resubmit to the Comptroller of the Republic a new electric power regulation that will modify the electric capacity market, outline an efficiency

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factor affecting high variable cost generation units, and modify the methodology for recognition for sufficient power for hybrid and pure storage systems to eliminate technological discretion. In addition, companies will be able to choose to stay under the current methodology or to migrate to the proposed methodology immediately. Finally, the regulations will modify the capacity market demand.

In 2021 and 2020, we recorded impairment costs associated with accelerating the closures of the Tarapacá, Bocamina I, and Bocamina II coal-fired power plants (see Notes 16.c.iv and 31.b. of the Notes to our consolidated financial statements).

On July 3, 2020, the CNE issued Exempt Resolution No. 237 authorizing the final withdrawal, disconnection, and termination of operations of the Bocamina I generation unit on December 31, 2020.

Regarding Bocamina II, we also intended to accelerate its closure, promoting the discontinuation of its operations in strict coordination with the Chilean government. In this context, on July 23, 2020, the CNE issued Exempt Resolution No. 266 authorizing the final withdrawal, disconnection, and termination of operations of the Bocamina II generation unit as of May 31, 2022.

On May 3, 2022, the CNE issued Exempt Resolution No. 325, which, based on technical studies and system operation projections, ordered Enel Generation to perform the final withdrawal, disconnection, and termination of operations at the Bocamina II generation unit beginning on September 30, 2022, in accordance with article No. 72-18 of the Electricity Law.

At the end of 2022, we decided not to proceed with certain projects, which resulted in Enel Generation writing off assets for ThCh$ 22,912,146, which were mainly associated with thermal and hydroelectric projects, including the Quintero and Vallecito projects. Likewise, EGP Chile wrote off ThCh$ 29,887,851 associated with a geothermal project, which was being developed in the Antofagasta region. See Notes 16.c). v) and 32 to the Notes of our consolidated financial statements.

On December 9, 2022, we completed the sale of our subsidiary Enel Transmission to Sociedad Transmisora Metropolitana S.p.A. (a subsidiary of Inversiones Grupo Saesa Ltda.). The sale was made through an initial public offering between November 7 and December 6, 2022. Consequently, all the shares of Enel Transmission owned by us, equivalent to 99.09%, were transferred to the new controlling shareholder. The gain recorded on this sale amounted to ThCh$ 981,856,639. See Notes 5.2 and 33 to the Notes of our consolidated financial statements.

On December 19, 2022, Enel Generation amended its gas supply contract with Shell Global LNG Limited (“Shell”), primarily to reduce the volume of gas to be purchased. The contract amendments involved a US$ 520 million payment by Shell to Enel Generation, which was recorded as other operating income in 2022. The reduction in the volume of gas purchased by Enel Generation aligns with the total projected gas surplus upon fulfilling the Company’s contractual commitments. See Note 28 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 net installed capacity as of December 31, 2022, 2021, and 2020 was 8,408 MW, 7,973 MW, and 7,118 MW, respectively, of which 41.7%, 44.5%, and 49.9% were hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”

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Hydroelectric generation was 9,768 GWh, 7,743 GWh, and 9,712 GWh in 2022, 2021, and 2020, respectively. Our hydroelectric generation increased in 2022 compared to 2021, mainly related to better hydrological conditions.

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

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

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

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

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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.

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 spot market purchases or increases spot market sales at higher prices.

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

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technical or other reasons, the spot price may increase, altering the impact of hydrological conditions discussed in the table above.

b.	Distribution and Networks Business

Our electricity distribution business is conducted through Enel Distribution in the Santiago metropolitan area, providing electricity to approximately 2.1 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, 2022, electricity sales were 17,534 GWh, representing a 5.2% increase compared to 2021. For the year ended December 31, 2021, electricity sales amounted to 16,668 GWh, representing a 1.1% increase compared to 2020.

Distribution and networks 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 networks business typically consist of networks 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 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 2019-2022 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 an extraordinary tariff update process, which was not-retroactive and will be in effect until the tariff-setting process for the 2020-2024 period is completed. This tariff increase recognizes the

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necessary investments to comply with the new requirements on the quality-of-service standards. Tariff reviews seek to capture distribution efficiencies and economies of scale resulting from economic growth.

The technical bases for the tariff-setting process for the 2020-2024 period were published at the end of the first half of 2020. This is the first tariff-setting process where the CNE determined the tariff by a single study performed by CNE. 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. On December 23, 2022, the CNE approved the Technical Report on the Calculation of Components of Distribution Value Added for the 2020-2024 period, through Exempt Resolution No. 908. The 2020-2024 tariff setting process should be concluded in 2023.

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, 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.

On February 11, 2022, Law No. 21,423 established a payment schedule for all debts arising from the application of the Basic Services Law, 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.

On August 2, 2022, Law No. 21,472 was published, which complements Law No. 21,185 by creating a new stabilization fund program and establishing the MPC, a new transitory mechanism for stabilizing customers’ electricity prices under the regulated price system. The purpose of the MPC is to limit the increase in electricity bills for regulated customers during 2022 and to allow such increases to occur gradually over the next 10 years. The resources available for the MPC may not exceed US$1,800 million. The MPC will be extended until the balances contemplated in the law are extinguished.

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As a result of the application of these mentioned laws as of December 31, 2022, our current and non-current accounts receivable increased, revenues from energy sales decreased, costs from energy purchases decreased, and financial income increased due to lower financial costs. Please see Notes 9 and 34 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

2022

2021

2020

Average

Year End

Average

Year End

Average

Year End

Chilean pesos per U.S. dollar

871.19

855.86

759.06

844.69

790.92

710.95

Source: Central Bank of Chile

2.	Analysis of Results of Operations for the Years Ended December 31, 2022, and 2021

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, 2022, and 2021:


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	3,877,759	1,953,288	1,924,471	98.5
Distribution and Networks Business
Enel Distribution, Enel Transmission, and subsidiary	1,454,722	1,201,833	252,889	21.0
Non-electricity business and consolidation adjustments	(376,049)	(299,891)	(76,158)	(25.4)
Total Revenues and Other Operating Income	4,956,432	2,855,230	2,101,202	73.6

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business increased Ch$ 1,924.5 billion, or 98.5%, in 2022 compared to 2021, due to:

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(i) an Ch$ 822.5 billion increase in energy sales, mainly due to:

a Ch$ 571.1 billion positive price effect resulting from exchange rate hedges that compensated the negative price effect due to the depreciation of the Chilean peso against the U.S. dollar;

a Ch$ 250.1 billion increase mainly due to 3,906 GWh of higher physical energy sales to unregulated customers primarily related to new customer contracts; and

Ch$ 47.1 billion of higher ancillary services revenue related to safety and service quality and other revenues.

These effects were partially offset by lower revenue from commodity hedges for Ch$ 45.8 billion.

(ii)a Ch$ 556.4 billion increase in other operating income mainly due to:

a Ch$ 460.7 billion gain related to the gas supply agreement amendment signed by Enel Generation with Shell in December 2022 mainly reducing the volume of gas to be supplied under the gas supply contract;

Ch$ 59.7 billion of higher revenue from commodity derivatives; and

Ch$ 29.8 billion of higher regasification services revenue.

(iii) an increase of Ch$ 542.5 billion in other sales mainly due to greater gas sales for Ch$ 542.3 billion.

Distribution and Networks Business: Revenues and other operating income

Revenues and other operating income from our distribution and networks business increased Ch$ 252.9 billion, or 21.0%, in 2022 compared to 2021 primarily due to:

(i)an increase of Ch$ 231.2 billion in energy sales mainly due to:

a higher average sales price as a consequence of a Ch$ 181.0 billion positive exchange rate effect during the period and the tariff review process; and

Ch$ 50.2 billion mainly due to 534 GWh of higher physical energy sales, primarily in the residential customer segment.

(ii)an increase of Ch$ 23.0 billion in revenue from other services, primarily due to higher tolls in the zonal networks segment of Ch$33.0 billion.

This effect was partly offset by:

Ch$ 7.3 billion in lower revenue from the construction of new customer connections and public lighting; and

Ch$ 2.7 billion in lower revenue from other services.

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Total raw materials and consumables used

The following table set forth our total raw materials and consumables used for the years ended December 31, 2022, and 2021 by business segment.


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	2,573,293	1,346,982	1,226,311	91.0
Distribution and Networks Business
Enel Distribution, Enel Transmission, and subsidiary	1,194,700	974,858	219,842	22.6
Non-electricity business and consolidation adjustments	(368,469)	(310,535)	(57,934)	(18.7)
Total Raw materials and consumables used	3,399,524	2,011,305	1,388,219	69.0

Generation Business: Raw materials and consumables used

Raw materials and consumables used in our generation business increased Ch$ 1,226.3 billion, or 91.0%, in 2022 compared to 2021, mainly due to:

(i)

a Ch$ 442.2 billion increase in energy purchases mainly due to 604 GWh of higher physical energy purchases in the spot market and 121 GWh of physical energy purchases from other electricity generation companies mostly needed to satisfy greater electricity demand from regulated and unregulated customers, in addition to a higher average purchase price due to electricity market conditions;

(ii)

a Ch$ 425.6 billion increase in other variable procurement and services costs mainly due to:

a)Ch$ 408.6 billion higher gas commercialization cost of sales; and

b)Ch$ 10.1 billion higher commodity hedging costs.

(iii)

a Ch$ 212.2 billion increase in fuel consumption costs mainly due to:

a)a Ch$ 188.2 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$ 17.8 billion increase due to a higher average purchase price primarily as a consequence of higher fuel oil consumption costs; and

c)a Ch$ 4.2 billion increase and a Ch$ 0.4 billion increase in impairment losses on coal and diesel inventories, respectively, both related to the impairment of Bocamina II.

(iv)

Ch$ 146.3 billion in higher transmission tolls mainly due to:

a)Ch$ 96.5 billion in higher costs of tariff revenue as a consequence of higher marginal costs;

b)Ch$ 43.7 billion in higher gas regasification costs; and

c)Ch$ 10.1 billion in higher gas transportation costs.

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Distribution and Networks Business: Raw materials and consumables used

Raw materials and consumables used in our distribution and networks business increased by Ch$ 219.8 billion, or 22.6% in 2022 compared to 2021 mainly due to:

(i)

Ch$ 205.6 billion in higher energy purchases mainly due to a higher average purchase price of Ch$ 170.9 billion, and an increase of Ch$ 34.6 billion mainly due to 527 GWh of higher physical energy purchases;

(ii)

Ch$ 9.3 billion in a higher other variable procurement and services costs mainly due to a Ch$ 9.01 billion increase in fines that were imposed by the Superintendence of Electricity and Fuel; and

(iii)

Ch$ 4.9 billion in higher transportation costs mainly due to higher tolls from the sale of Enel Transmission to Grupo Saesa.

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, 2022, and 2021, by business segment:


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	432,410	383,470	48,940	12.8
Distribution and Networks Business
Enel Distribution, Enel Transmission, and subsidiary	176,490	168,792	7,698	4.6
Non-electricity business and consolidation adjustments	35,651	32,069	3,582	11.2
Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expenses	644,551	584,331	60,220	10.3

Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased Ch$ 60.2 billion, or 10.3%, in 2022 compared to 2021, mainly due to:

(i)

a Ch$ 68.7 billion increase in impairment in the generation business mainly explained due to:

a Ch$ 52.8 billion impairment of thermal, hydroelectric, and geothermal generation projects that will not be carried out due to the decarbonization strategy and new market conditions;

a Ch$ 9.08 billion increase in professional and technical support services primarily related to EGP Chile projects under development and in operation; and

a Ch$ 6.3 billion increase in maintenance and repair services.

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(ii)

an increase of Ch$ 27.3 billion, or 63.7%, in the generation, distribution and networks business in depreciation and amortization in 2022 compared to 2021, mainly due to:

Ch$ 19.4 billion greater depreciation and amortization in EGP Chile, principally due to the exchange rate effect and, to a lesser degree, by the commissioning of new power plants; and

Ch$ 8.4 billion in greater depreciation and amortization in the distribution and networks business segment, due to the greater amortization of intangible assets related to IT developments of Ch$ 7.8 billion, and also the commissioning of investment projects for Ch$ 2.7 billion, both in Enel Distribution, partially compensated by lower amortization and depreciation from Enel Transmission for Ch$ 1.9 billion, primarily due to the deconsolidation of Enel Transmission as of December 9, 2022.

(iii)

Ch$ 3.3 billion in higher accounts receivable impairment losses, primarily in the distribution and networks business segment for Ch$ 2.6 billion, and a Ch$ 1.3 billion increase in the generation business segment primarily related to higher trade accounts receivables and an expected weaker financial condition of regulated customers.

These effects were mostly offset by:

(i)

Ch$ 31.3 billion in lower fixed asset impairment losses mainly explained due to Ch$ 28.8 billion of impairment loss for our Bocamina II coal-fired power plant recorded in 2021;

(ii)

a Ch$ 9.3 billion decrease in the generation business, mainly due to:

an Ch$ 8.3 billion decrease in the Company’s restructuring costs related to the Enel’s digitalization strategy for 2021-2024; and

Ch$ 10.3 billion in higher capitalization of personnel expenses, primarily related to EGP Chile’s new projects. This was partially offset by: (i) a Ch$ 6.07 billion increase in salaries, mainly related to salary reviews and indexation; (ii) a Ch$ 3.3 billion increase in annual performance bonuses and other recurrent expenses; and (iii) a Ch$ 0.7 billion increase in employee collective bargaining related bonuses.

Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2022, and 2021:


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	872,055	222,836	649,219	2.9
Distribution and Networks Business
Enel Distribution, Enel Transmission, and subsidiary	83,532	58,183	25,349	43.6
Non-electricity business and consolidation adjustments	(43,230)	(21,425)	(21,805)	(101.8)
Total Consolidated Operating Income	912,357	259,594	652,763	2.5
Operating margin⁽¹⁾	18.4%	9.1%	—	—

(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

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losses, as was the case in 2022 and 2021 with the expense related to impairment arising from the closure of two coal-fired power plants.

Our operating income in 2022 increased compared to 2021 due to the following:

Generation Business

Revenues totaled Ch$ 3,877.8 billion as of December 31, 2022, an increase of Ch$ 1,924.5 billion, or 98.5%, primarily due to additional gain from the Shell gas supply agreement amendment, higher physical energy sales, a higher average energy sales price when expressed in Chilean pesos, and higher gas sales.

The raw materials and consumables used totaled Ch$ 2,573.3 billion as of December 31, 2022, an increase of Ch$ 1,226.3 billion, or 91.0%, compared to 2021 mainly due to higher electricity purchase costs due to both higher physical purchases and a higher average purchase price, higher gas sales costs, and higher fuel consumption costs due to greater thermal electricity dispatch and higher commodity prices.

Other expenses increased 54.2% to Ch$ 195.6 billion as of December 31, 2022, mainly explained by the impairment of thermal generation projects due to our parent company’s decarbonization strategy, and the impairment of hydroelectric and geothermal projects that will not be implemented due to new market conditions, which altogether amounted to Ch$ 52.8 billion and were accounted for in the fourth quarter of 2022.

Distribution and Networks Business

Revenues were Ch$ 1,454.7 billion as of December 31, 2022, an increase of Ch$ 252.9 billion, or 21.0%, compared to 2021, mainly due to higher energy sales of Ch$ 231.2 billion primarily resulting from: (i) a higher average sales price for Ch$ 181.01 billion due to a higher positive exchange rate effect; and (ii) a Ch$ 50.2 billion increase mainly due to 534 GWh of higher physical energy sales, primarily in the residential customer segment; and higher other services revenue of Ch$ 23.01 billion.

The raw materials and consumables used totaled Ch$ 1,194.7 billion as of December 31, 2022, an increase of Ch$ 219.8 billion, or 22.6%, compared to 2021, mainly due to higher energy purchases corresponding to a higher average purchase price for Ch$ 170.9 billion, and higher physical energy purchases of 527 GWh.

Operating income was mainly affected by (i) a higher depreciation and amortization of Ch$ 8.3 billion due to the greater amortization of intangible assets related to IT developments of Ch$ 7.8 billion, and also the commissioning of investment projects of Ch$ 2.7 billion, both in Enel Distribution, partially compensated by lower amortization and depreciation from Enel Transmission of Ch$ 1.9 billion, primarily due to the deconsolidation of Enel Transmission as of December 9, 2022; and (ii) an increase in other expenses, mainly due to higher maintenance and repair costs.

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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, 2022, and 2021:


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Financial results
Financial income	50,415	26,420	23,995	90.8
Financial costs	(193,618)	(174,043)	(19,575)	(11.2)
Gain from indexed assets and liabilities	5,863	5,898	(35)	(0.6)
Foreign currency exchange differences	18,401	(15,334)	33,735	n.a.
Total financial results	(118,939)	(157,059)	38,120	(24.3)
Other Results
Share of the profit of associates and joint ventures accounted for using the equity method	3,282	3,177	105	3.3
Other gains	981,981	10,137	971,844	9,587.1
Total Other results	985,263	13,314	971,949	7,300.2
Total Consolidated Financial and Other Results	866,324	(143,745)	1,010,069	n.a.

Financial Results

We recorded a decrease in financial results in 2022 compared to 2021, primarily attributable to:

(i)

an increase of Ch$ 33.7 billion in foreign currency exchange rate differences mainly due to:

a Ch$ 65.5 billion higher positive exchange rate difference effect in accounts payables to related parties due to loans granted by Enel Finance International N.V. (“EFI”); and

a Ch$ 51.2 billion higher positive exchange rate difference effect in financial debt and derivative instruments.

These effects were partially offset by the following negative exchange rate difference effects:

Ch$ 71.9 billion in higher negative exchange rate differences on trade accounts receivables, including Ch$ 47.0 billion 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

Ch$ 10.5 billion in higher negative exchange rate difference effect on cash and cash equivalents.

(ii)

an increase of Ch$ 24.0 billion in financial income mainly due to:

a Ch$ 16.6 billion increase in income resulting from short-term fixed investments;

Ch$ 3.8 billion in higher financial income from accounts receivables related to the enactment of the Basic Services Law;

Ch$ 2.9 billion higher financial income related to customer payment plans, and

a Ch$ 2.7 billion increase related to financial income due to the Tariff Stabilization Law.

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These effects were partially offset by:

Ch$ 3.5 billion in lower financial income related to the financial restatement of the decommissioning or restoration provisions of the impaired power plants related to the decarbonization process as a result of the increase in discount rates in 2022.

(iii)

an increase of Ch$ 19.6 billion in financial costs mainly due to:

Ch$ 30.7 billion in higher financial expenses with related parties due to new loans granted by EFI;

Ch$ 15.3 billion in higher interest expenses on bonds and bank loans;

Ch$ 10.5 billion in higher interest expenses due to arrangements with suppliers to postpone payments;

Ch$ 8.3 billion in higher financial expenses from the restatement of dismantling provisions;

Ch$ 7.6 billion in higher financial expenses related to withholding taxes on interest payments; and

Ch$ 4.8 billion in higher other miscellaneous financial costs and expenses.

These effects were partially offset by:

Ch$ 21.8 billion in lower financial expenses due to greater capitalization of interest primarily related to the development of NCRE projects and the extension of the construction of the Los Cóndores project;

Ch$ 18.3 million in lower financial expenses on trade accounts receivables factoring mainly related to a decrease of Ch$ 29.7 billion in accounts receivables factoring that arose from the Tariff Stabilization Law;

Ch$ 9.2 billion in lower financial expenses due to the reduction of accounts receivables resulting from the enactment of the Basic Services Law; and

Ch$ 8.2 billion in lower financial expenses related to customer payment plans.

Other Results

Our gain on disposal of assets increased Ch$ 971.9 billion in 2022 compared to 2021 mainly due to the sale of Enel Transmission for Ch$ 981.8 billion, which became effective on December 9, 2022. This was offset by the Ch$ 9.9 billion in income recorded in 2021 from the sale of the stake that that our subsidiary Enel Generation had in the joint control of Transmisora Eléctrica Quillota Ltda.

Consolidated Income Tax Expenses

The effective tax rate was an income tax expense of 26.4% in 2022 compared to 13.1% in 2021.

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Consolidated income tax expense increased more than 3,000% to Ch$ 469.7 billion in 2022 compared to 2021 mainly due to:

(i)

a Ch$ 311.7 billion increase in income tax on the profits from the sale of Enel Transmission;

(ii)

a Ch$ 124.4 billion increase in income tax due to the additional gain from the gas supply agreement amendment signed by Enel Generation with Shell; and

(iii)

a Ch$ 59.5 billion increase in income tax due to the Company’s higher revenues.

These effects were partially offset by:

(iv)

Ch$ 35.2 billion in lower tax expense as a consequence of the price-level restatement of the period.

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

Consolidated Net Income

The following table sets forth our consolidated net income before taxes, income tax expenses, and net income for the years ended December 31, 2022, and 2021:


	Years ended December 31,
	2022	2021	Change	Change

	(in millions of Ch$)			(in %)
Operating income	912,357	259,594	652,763	251.5
Financial and other results	866,324	(143,745)	1,010,069	n.a.
Net Income before Taxes	1,778,681	115,849	1,662,832	1,435.3
Income tax (expenses)	(469,697)	(15,139)	(454,558)	(3,002.6)
Consolidated Net Income	1,308,984	100,710	1,208,274	1,199.8
Net income attributable to the Parent Company	1,252,082	85,154	1,166,928	1,370.4
Net income attributable to non-controlling interests	56,902	15,556	41,346	265.8

Net income attributable to the Parent Company increased Ch$ 1,166.9 billion in 2022 compared to 2021 mainly explained by the gain on the sale of Enel Transmission, in addition to greater electricity and gas sales, and the additional gain from Enel Generation’s amendment of its gas supply agreement with Shell. Also, during 2022, thermal generation projects were impaired as a consequence of the Company’s decarbonization strategy, and hydroelectric and geothermal projects were impaired due to new market conditions.

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

The comparative analysis of our results of operations for the years ended December 31, 2021, and 2020, is incorporated herein by reference from Item 5.A. of our Annual Report on Form 20-F for the year ended December 31, 2021, filed with the SEC on April 28, 2022.

B. Liquidity and capital resources.

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

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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, 2022, 2021, and 2020:


	Year ended December 31,
	2022	2021	2020

	(in billions of Ch$)
Net cash flows provided by operating activities	745	413	756
Net cash flows provided by (used in) investing activities	456	(736)	(555)
Net cash flows provided by (used in) financing activities	(629)	293	(128)
Net increase (decrease) in cash and cash equivalents before the effect of exchange rates changes	572	(30)	73
Effect of exchange rate changes on cash and cash equivalents	(6)	8	23
Cash and cash equivalents at the beginning of the period	310	332	236
Cash and cash equivalents at the end of the period	876	310	332

For the year ended December 31, 2022, net cash flow provided by operating activities increased Ch$ 332 billion, or 80.4%, compared to the same period in 2021. The increase was in part the result of:

(i)

Ch$ 1,823 billion from increased cash collections from the sale of goods and services principally from (i) our generation segment of Ch$ 1,148.1 billion due to higher energy sales of 3,906 GWh mainly to unregulated customers, and an increase in new contracts for the period; (ii) the gas supply agreement amendment signed by Enel Generation Chile with Shell in December 2022 which accounts for Ch$ 460.4 billion; and (iii) our distribution segment of Ch$ 192.1 billion due to higher physical energy sales of 534 GWh mainly due to higher sales to residential customers and tolls.

(ii)

Ch$ 52.3 billion in lower income tax payments in 2022, mainly due to (i) a Ch$ 44.6 billion decrease in Enel Generation’s income tax payments due to higher tax losses in 2022; (ii) a Ch$ 13.6 billion decrease in Enel Distribution related to a decrease in monthly advance income tax payment, and (iii) a Ch$ 5.5 billion decrease in Pehuenche related to a decrease in monthly advance income tax payments. These were partially offset by Ch$ 16.8 billion in Enel Transmission from higher payments on income tax for fiscal year 2022.

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

(iii)

Ch$ 1,552.4 billion in higher payments to suppliers mainly from (i) our generation segment due to higher energy purchase costs due to a greater quantity and average price, a higher cost for fuel consumption due to the lower efficiency of the generation mix as a result of dry hydrology conditions and higher commodity prices, together with higher gas costs of Ch$ 1,449.9 billion; and (ii) our distribution segment totaled Ch$ 86.5 billion due to higher cost of energy purchases with an higher average price to satisfy a greater demand.

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:

(iii)

Ch$ 481.0 billion from increased collections in the generation and distribution and networks 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);

(iv)

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

(v)

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 further information regarding our operating results in 2022, 2021, and 2020, please see “— A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2022, and 2021” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2021, and 2020.”

For the year ended December 31, 2022, net cash flows provided by investing activities were inflows amounting to Ch$ 456 billion, representing an increase of 162%, or Ch$ 1,192 billion, compared to the same period in 2021, mainly due to:

(i)

Ch$ 1,234.5 billion in cash flows from the loss or gains of control of subsidiaries or other businesses due to the amounts received for the sales of: a) Enel Transmission for Ch$ 1,221.2 billion; b) Enel X Way Chile for Ch$ 11.4 billion Enel; and c) Enel X AMPCI Ebus Chile for Ch$ 2.0 billion; and

(ii)

Proceeds from the repayment of advances and loans granted to third parties amounting to Ch$ 172.4 billion, due to cash flows received for the payment of Enel Transmission’s debt with Enel Chile (See Note 2.4.1.v. and Note 5.2 to the Notes of our consolidated financial statements).

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

(iii)

Ch$ 167.7 billion in investments in fixed assets carried out by our subsidiaries, mainly due to Ch$ 140.1 billion by EGP Chile in developing renewable projects, Ch$ 15.4 billion by Enel Transmission to improve its networks, and Ch$ 12.5 billion by Enel Generation, mainly due to the construction of the Los Cóndores power plant; and

(iv)

Ch$ 29.9 billion in other cash payments to acquire shares in joint ventures mainly due to the payment of Enel X Chile’s capital contribution in Sociedad de Inversiones K Cuatro S.p.A. for Ch$ 29.6 billion.

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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:

(ii)

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

(iii)

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

(iv)

dividends received of Ch$ 7 billion.

For the year ended December 31, 2022, net cash used from financing activities were Ch$ (629) billion compared to the cash provided by in financing activities of Ch$ 293 billion in 2021.

The aggregate cash payments associated with financing activities in 2022 were primarily due to:

(i)

Ch$ 510 billion in loan and bond principal and interest payments by Enel Generation.

(ii)

Ch$ 187 billion of interest payments (Ch$ 78.5 billion paid by Enel Generation, Ch$ 51.6 billion paid by EGP Chile, and Ch$ 59.9 billion paid by Enel Chile); and

(iii)

Ch$ 39.6 billion in dividend payments, of which Ch$ 16.4 billion was paid to Enel, our controlling shareholder, and Ch $23.2 billion to third parties.

These financing activities were partially offset by:

(iv)

aggregate cash inflows and outflows from financing activities in 2022: inflows primarily from loans provided to Enel Chile by EFI, a related company, of Ch$ 602 billion; and outflows primarily from loan payments to EFI for Ch$ 1,187.7 billion.

(v)

aggregate inflows from financing activities from short- and long-term loans in 2022 of Ch$ 263.8 billion and Ch$ 448.9 billion, respectively.

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:

(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

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(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 EFI, 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.

The table below sets forth our cash payment of contractual obligations as of December 31, 2022:


	Payments Due by Period
Contractual Obligation	Total	2023	2024-2025	2026-2027	After 2027

	In billions of Ch$
Purchase obligations⁽¹⁾	19,167	7,354	6,255	2,940	2,618
Bank debt⁽²⁾	2,035	419	361	446	809
Yankee bonds	1,469	—	342	176	951
Interest expense	1,162	165	276	220	501
Local bonds⁽²⁾	252	36	65	78	73
Lease obligations	231	14	10	10	197
Pension and post-retirement obligations⁽³⁾	59	7	12	12	28
Total contractual obligations ⁽⁴⁾	24,375	7,995	7,321	3,882	5,177

(1)

Includes generation and distribution and networks business purchase obligations, comprised mainly of electricity purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 19,167 billion, 60% corresponds to electricity purchased for distribution, 38% primarily to fuel supply, maintenance of medium- and low-voltage lines, cable and utility poles, and electricity purchased for generation. The remaining 2% corresponds to miscellaneous services, such as LNG regasification and fuel transportation.

(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 “Item 5. Operating and Financial Review and Prospects — B. Liquidity and capital resources.”

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As of December 31, 2022, our gross consolidated interest-bearing debt totaled Ch$ 4.0 trillion, including Ch$ 1.6 trillion in debt that Enel Chile incurred with EFI, and had the following maturity profile:

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, 2022:


					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$ 527 billion as of December 31, 2022). As of December 31, 2022, 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, 2022:


			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 M	21 years	December 2029	4.75%	10.00	6.36	223
Enel Generation Series H	25 years	October 2028	6.20%	4.00	1.30	46

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Total

5.00%

⁽¹⁾

14.00

7.66

269

(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 20.2 of the Notes to our consolidated financial statements.

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, 2022, are summarized in the table below.


Borrower	Type	Lender	Maturity⁽¹⁾	Facility Amount	Amount Drawn
				(in millions of US$)	(in millions of US$)
Enel Chile	SDG-linked Bilateral Revolving Loan	EFI	April 2026	290	290⁽²⁾
Enel Chile	SDG-linked Bilateral Revolving Loan	SMBC	October 2025	50	50⁽³⁾
Enel Chile	Bilateral Revolving Loan	EFI	June 2024	50	—
Enel Chile	SDG-linked Bilateral Revolving Loan	EFI	September 2025	200	—
Enel Chile	Syndicated Revolving Loan	BBVA S.A. and Mizuho Bank Ltd	June 2024	100	—
Total				690	340

(1)	Refers to the facility’s maturity.

(2)	The amount drawn matured in January 2023. As of March 31, 2023, the facility was undrawn.

(3)	The amount drawn matures at the facility’s maturity.

Our Chilean pesos revolving loan and the amounts outstanding as of December 31, 2022, are summarized in the table below.


Borrower	Type	Lender	Maturity⁽¹⁾	Facility Amount	Amount Drawn
				(in millions of Ch$)	(in millions of Ch$)
Enel Chile	Syndicated Revolving Loan	Scotiabank Chile	June 2024	34,000	—

(1)	Refers to the facility’s maturity.

Some of the 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 contract with committed credit lines, which allows us complete flexibility for a drawdown under any circumstances including situations involving an MAE, was up to US$ 190 million as of December 31, 2022, and up to US$ 193 million as of March 31, 2023, US$ 50 million of which was drawn as of March 31, 2023.

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Additionally, we and our subsidiaries have also entered into uncommitted Chilean bank facilities for approximately Ch$ 108 billion in the aggregate, none of which was drawn as of March 31, 2023. 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.

As for our term loans, the detail of each transaction and the outstanding principal amount as of December 31, 2022, 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
Enel Chile	Term Loan	EFI	March 2020	March 2030	400
Enel Chile	SDG-linked Term Loan	EFI	April 2021	April 2031	300
Enel Chile	Term Loan	European Investment Bank	December 2022	December 2037	244
Enel Chile	Term Loan	EFI	January 2020	July 2023	200
Enel Chile	SDG-linked Term Loan	Scotiabank Chile	December 2021	December 2026	150
Enel Chile	SDG-linked Term Loan	Santander Chile	July 2021	June 2024	50
Enel Chile	Term Loan	European Investment Bank	October 2022	October 2037	50
Total					2,038

For a complete description of our credit lines and term loans, see Note 10.1.d) and Note 20.1 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, 2022, 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. 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 36.4 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

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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 2023 through 2025 are expected to amount to Ch$ 1,455 billion, which includes maintenance capital expenditures, investment in expansion projects under execution, as well as water rights and expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

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

LIBOR Transition

The U.K. Financial Conduct Authority found that the London Interbank Offered Rate (“LIBOR”) had inconsistencies in its calculations and recommended that it be based on actual transactions. As a result, the authority agreed to stop requiring banks to comply with the submission of interbank rates to calculate LIBOR as of December 31, 2021. On March 5, 2021, LIBOR succession dates were announced (December 31, 2021, for all tenors EUR, CHF, JPY, and GBP LIBOR, and one-week and two-month USD LIBOR; and June 30, 2023, for all other USD LIBOR tenors). The Secured Overnight Financing Rate (“SOFR”) will be the successor benchmark rate.

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, 2023, our total debt exposure to LIBOR was US$ 250 million and all of them include provisions to transition from LIBOR to an alternative benchmark rate.

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.

In 2021, we executed three Revolving Credit Facility Agreements (“RCFA”) linked to sustainable development goals, for up to US$ 290 million and US$ 200 million, both with EFI, 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

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million, due in 2026, which is linked to sustainable development goals, and the other with Santander for US$ 50 million, due in 2024. Both loan contracts are subject to LIBOR and include specific fallback rate provisions. As of March 31, 2023, the 2021 RCFAs had an outstanding principal amount of US$ 50 million.

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 RCFA for up to US$ 50 million with EFI, 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, 2023, the SURCA and the 2019 RCFA were undrawn.

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 2024, we expect significant price decreases, mainly due to the start of operations of projects tendered in 2016 and 2017, respectively.

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 that 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

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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. We expect our first pilot hydrogen project to reach commercial operation in 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 2022 — Pilot Green Hydrogen Project.”

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 Distribution Tariff Law, which reduces the profitability of distribution companies, and the Basic Services Law, 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 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 choose early 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.

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

For information regarding our critical accounting estimates, see 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, 2022, were as follows:


Directors	Position	Age⁽¹⁾	Current Position Held Since
Herman Chadwick Piñera	Chairman	78	2016
Gonzalo Palacios Vásquez	Director	72	2021
Pablo Cabrera Gaete	Director	75	2016
Fernán Gazmuri Plaza	Director	78	2016
Salvatore Bernabei	Director	49	2016
Mónica Girardi	Director	43	2021
Isabella Alessio	Director	48	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, 2022.

Herman Chadwick Piñera: Mr. Chadwick is a partner at the Chilean law firm of Chadwick & Cía. He is a director of several companies unrelated to Enel Chile, including Inversiones Aguas Metropolitanas, a Chilean holding company that owns a water utility company, and Viña Santa Carolina, a Chilean winery, as well as president of Fundación San Ignacio del Huinay, an environmental protection foundation, and of Club 50, a business and event center. He is also a member of the Consejo del Centro de Estudios Públicos, a public policy think tank. In the past, Mr. Chadwick has served as president of the Arbitration and Mediation Center of the Santiago Chamber of Commerce, an association that provides arbitration services. 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 was an independent director on the board at Naturgy Ban, a gas distribution company in Argentina, until April 2023. 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.

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Pablo Cabrera Gaete: 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.

Fernán Gazmuri Plaza: Mr. Gazmuri has served on the boards of companies unrelated to Enel Chile. He is currently vice-chairman of Invexans S.A., a holding company that owns NEXANS, a French telecom and maritime cable company, chairman of Citroën Chile S.A.C. and 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 is currently the CEO of Enel Green Power and head of global power generation. He was head of global procurement of Enel (2017-2020), 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, and 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 investor relations of Enel S.p.A. She worked at Barclays as a senior research analyst responsible for Italian and Iberian public services (2009-2018). Previously, she worked at Lehman Brothers as an analyst covering European public services and infrastructure (2003-2009). She holds a degree in business administration from Università Commerciale Luigi Bocconi in Milan and graduated summa cum laude.

Isabella Alessio: Isabella is head of legal and corporate affairs for global procurement of Enel S.p.A. 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 holds a law degree from the University of Rome “La Sapienza” and has a master’s degree in European law.

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Executive Officers

Set forth below are our executive officers as of December 31, 2022:


Executive Officers	Position	Age⁽¹⁾	Year Joined Enel or Affiliate	Current Position Held Since
Fabrizio Barderi	Chief Executive Officer	52	2001	2022
Giuseppe Turchiarelli	Chief Financial Officer	52	1998	2019
Juan Diaz Valenzuela	Internal Audit Officer	36	2010	2022
Liliana Schnaidt Hagedorn	Human Resources Officer	43	2009	2018
Domingo Valdés Prieto	General Counsel	59	1993	2016
Montserrat Palomar Quilez	Sustainability & Community Relations Officer	41	2017	2022

(1)	As of the date of this Report.

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

Fabrizio Barderi: Mr. Barderi has experience in operations, strategic planning, and business negotiations in different sectors. He joined Enel in 2001 and has worked in various positions in Europe and Latin America. Between October 2014 and July 2017, he was in charge of all of Enel’s generation assets in Latin America. In 2017 he was appointed member of the board of directors of Enel Generation. Mr. Barderi holds a degree in electrical engineering from Università di Pisa and a master’s degree in economics and energy and environmental management from Scuola Superiore Enrico Mattei.

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.

Juan Diaz Valenzuela: Mr. Diaz joined Enel in 2010 and has held different positions in Internal Audit in Latin America. Between 2019 and 2022, he worked as audit and compliance manager of Enel Peru and its subsidiaries where he successfully implemented the Anti-Bribery Management System and the Local Crime Prevention Compliance Model. He holds a degree in information and management control engineering from Universidad de Chile, as well as specializations in electricity markets and project management from Universidad del Desarrollo and Universidad de Chile.

Liliana Schnaidt Hagedorn: Ms. Schnaidt joined Enel Green Power in 2009 in Business Development. She later became a business manager and focused on solar energy development. She holds a degree in civil engineering from Pontificia Universidad Católica de Chile.

Domingo Valdés Prieto: 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 was a member of the board of directors of Empresa Distribuidora de Energía Sur S.A. (Edesur - Argentina) and Chairman of Enel Transmission. 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 and an MPL from Yale University.

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Montserrat Palomar Quilez: Ms. Palomar joined Enel in 2017 as head of sustainability for Enel Green Power Mexico and has been working as sustainability and community relations manager at Enel Chile since October 2022. Prior to joining Enel, she held positions in sustainability at KPMG and Deloitte. She also led the development of social projects at Telefónica and Coca-Cola FEMSA. Ms. Palomar holds a degree in psychology from Universidad Iberoamericana in Mexico City, as well as a specialization in mediation and conflict resolution from Universidad Oberta de Catalunya.

B.	Compensation.

At the OSM held on April 27, 2022, our shareholders approved our board of directors’ compensation policy for 2022. 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.

In 2022, 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 Piñera	171,953	78,466	—	—	—	250,419
Gonzalo Palacios Vásquez	85,976	39,233	28,659	13,029	—	166,897
Pablo Cabrera Gaete	85,976	39,233	28,659	13,029	—	166,897
Fernán Gazmuri Plaza	85,976	39,233	28,659	13,029	—	166,897
Salvatore Bernabei⁽¹⁾	—	—	—	—	—	—
Mónica Girardi⁽¹⁾	—	—	—	—	—	—
Isabella Alessio⁽¹⁾	—	—	—	—	—	—
Total	429,881	196,165	85,977	39,087	—	751,110

(1)	Directors Alessio, Bernabei, and Girardi waived their compensation as directors of Enel Chile due to their positions as employees of Enel or other companies affiliated with 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.

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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, 2022, the aggregate gross compensation, paid and accrued, for all our executive officers, attributable to the fiscal year 2022, was Ch$ 2.2 billion in fixed compensation, and Ch$ 405 million in variable compensation and benefits.

In 2022, under an established restricted stock unit (“RSU”) program that was implemented for that year only, certain key personnel of Enel Chile received a one-time issuance of Enel S.p.A. shares for the corresponding RSU award. These shares were not issued on a discretionary basis, but were automatically issued upon vesting of the RSUs on a pre-established date once certain performance-based vesting conditions were met. The cost of the RSU program is subject to an outstanding recharge agreement; accordingly, such cost has been supported by Enel Chile. This agreement establishes that all fixed and variable remuneration of certain expatriate executives (whether in cash or in kind) is paid by the company to which the expatriate executive provides services. Please see Note 10.6 of the notes to our financial statements for further information regarding executive officer compensation.

We entered into severance indemnity agreements with all 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 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 2022. There are no other amounts set aside or accrued to provide for pension, retirement, or similar benefits for our executive officers.

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, 2022, 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, 2022:


Committee Member		Position in Committee
Fernán Gazmuri Plaza		President
Pablo Cabrera Gaete		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;

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●

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 transaction 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

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, 2022, 2021, and 2020:


Company	2022	2021	2020
Enel Generation	616	656	668
Enel Distribution⁽¹⁾	587	556	755
Enel Chile	498	500	494
EGP Chile	363	304	285
Enel X	93	99	15
Pehuenche	1	2	2
Enel Transmission⁽²⁾⁽³⁾	0	98	0
Total Personnel⁽⁴⁾	2,158	2,215	2,219

(1)	Includes Enel Colina S.A.

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

(3)	On December 9, 2022, Enel Transmission was sold in a stock purchase agreement and is no longer our subsidiary as of December 31, 2022.

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

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

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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 2022	July 2025
Enel Chile - Collective Bargaining Agreement 2	January 2023	December 2025
Enel Chile - Collective Bargaining Agreement 3	January 2023	December 2025
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 2022	June 2025
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
EGP Chile - Collective Bargaining Agreement 3	December 2021	December 2024
Enel Colina	November 2022	October 2025

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, 2022, 6,035 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 ADSs equivalent to 572,889,949 shares, aggregating a 64.93% 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

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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, 2022, Chilean private pension funds (“AFPs”) owned 6.2% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 22.7% of our shares. ADS holders owned 4.1% of our shares, and 5,889 minority shareholders held the remaining 2.1% of our shares.

The following table sets forth information concerning ownership of the common stock as of April 1, 2023, 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	64.93%

Enel, an Italian company and our controlling shareholder that beneficially owned 64.93% of our shares as of December 31, 2022, 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 30 countries worldwide and a consolidated installed capacity of approximately 93 GW. Enel distributes electricity through a network of 2.3 million kilometers to more than 75 million customers. 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 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 subsidiaries, 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.

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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, 2022, and March 31, 2023.

Lender

Borrower

Issuance Date

Maturity Date

Amount (millions)

Interest Rate

Outstanding Principal⁽¹⁾

Contract Type

EFI⁽²⁾

Enel Chile

Feb-22

Aug-23

US$300

SOFR + 0,75%

—

Revolving facility

EFI⁽²⁾

Enel Chile

Jun-22

Dec-23

US$150

SOFR + 0,86%

—

Revolving facility

EFI⁽²⁾

Enel Chile

Jul-22

Jul-23

US$250

SOFR + 0,77%

—

Revolving facility

Enel Chile

EGP Chile

Jan-22

Jan-27

US$242

3.95%

US$242

Term loan

Enel Chile

EGP Chile

Apr-22

Apr-28

US$152

5.73%

US$152

Term loan

Enel Chile

EGP Chile

Aug-22

Aug-23

US$150

6.49%

US$150

Term loan

Enel Chile

EGP Chile

Oct-22

Oct-28

US$175

7.08%

US$175

Term loan

Enel Chile

EGP Chile

Mar-23

Mar-29

US$200

6.43%

US$200

Term loan

Enel Chile

Enel Distribution

Mar-22

Mar-27

Ch$134,000

8.58%

Ch$134,000

Term loan

Enel Chile

Enel Distribution

Mar-23

Mar-26

Ch$195,000

8.57%

Ch$195,000

Term loan

Enel Chile⁽³⁾

Enel Generation

Jul-22

Jul-23

US$250

4.99%

—

Term loan

Enel Chile

Enel Transmission

Jan-22

Dec-22

Ch$87,000

8.18%

—

Term loan

Enel Chile

Geotérmica del Norte

Jul-22

Jul-23

US$30

4.55%

US$30

Term loan

(1)	Expressed in millions as of March 31, 2023.

(2)	The revolving facility was terminated in December 2022.

(3)	The outstanding principal amount was paid in December 2022, prior to maturity.

Our internal procedure provides 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 an 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 these transactions are subject to the supervision of our Directors Committee. As of March 31, 2023, the peso-denominated transactions were priced at TAB 1m (a Chilean interbank interest rate published daily) plus 1.44% when lending to subsidiaries and TAB 1m minus 0.18% when accepting deposits of cash surpluses from subsidiaries. The US$-denominated transactions were priced at SOFR 1m plus 2.06% when lending to subsidiaries and SOFR 1m plus 0.65% when accepting deposits of cash surpluses from subsidiaries.

The following are related-party transactions under the centralized cash management mechanism conducted between January 1, 2022, and March 31, 2023.

●

We granted short-term intercompany loans to our subsidiaries Enel Colina, Enel X Chile, and Sociedad Agrícola De Cameros Ltda. As of March 31, 2023, the total outstanding balance of these loans was Ch$ 135 billion, including interest.

●

Under our cash management contracts, EGP Chile, Enel Distribution, Enel Generation, Geotermica del Norte, Parque Talinay Oriente S.A., and Pehuenche all transferred cash surpluses to Enel Chile. As of March 31, 2023, the total outstanding balance of these transfers was Ch$ 555 billion, including interest.

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

We have various contractual relationships with EGP Chile, Enel Americas, Enel Distribution, Enel Generation, Enel Green Power S.p.A., Enel S.p.A., and Enel X Chile to provide intercompany services. We entered into intercompany agreements under which we provide services directly and indirectly to Enel Americas, 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 one-year terms as of July 21, 2021, and subject every year to automatic renewal for one year.

As of the date of this Report, the transactions above have not experienced material changes. As of December 31, 2022, there were some commercial transactions with related parties. Please see Note 10 of the Notes to our consolidated financial statements for more information regarding related-party transactions.

C.	Interests of Experts and Counsel.

Not applicable.

Item 8. Financial Information.

A.	Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements.”

Legal Proceedings

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

Please refer to Note 36.3 of the Notes to our consolidated financial statements for detailed information as of December 31, 2022, 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

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the following year and deducted from the final dividend payable in May of the next year. The board of directors establishes the interim dividend, which can be freely determined by the board, provided there are no accumulated losses.

For dividends accrued in the fiscal year 2022, on November 25, 2022, the board of directors agreed to distribute an interim dividend of Ch$ 0.32409 per share of common stock on January 27, 2023, equal to 15% of consolidated net income as of September 30, 2022. At the OSM held on April 26, 2023, our shareholders approved a final dividend of Ch$ 5.43073 per share for the year 2022, equivalent to a payout of 30% of annual net income for the fiscal year 2022. The final dividend for the fiscal year 2022 will be distributed in May 2023, after deducting the interim dividend paid in January 2023.

For dividends relating to the fiscal year 2023, our board of directors presented at the OSM held on April 26, 2023, the following proposed dividend policy:

●

An interim dividend, accrued in the fiscal year 2023 and amounting to 15% of consolidated net income as of September 30, 2023, to be paid in January 2024.

●

A final dividend payout of 50% of annual net income for the fiscal year 2023, to be paid in May 2024, from which the interim dividend to be paid in January 2024 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⁾
2022	0.37	0.02
2021	3.08	0.18
2020	4.23	0.30

(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, 2022, the SSE and ESE accounted for 88.3% and 11.7%, 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 2022:


Market	Number of Common Shares Traded	Percentage of Shares Traded
Chile⁽¹⁾	31,375,824,018	78%
United States (One ADS = 50 shares of common stock)⁽²⁾	8,952,262,250	22%
Total	40,328,086,268	100%

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(1)	Includes SSE and ESE.

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

D.	Selling Shareholders.

Not applicable.

E.	Dilution.

Not applicable.

F.	Expenses of the Issue.

Not applicable.

Item 10. Additional Information

A.	Share Capital.

Not applicable.

B.	Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a summary of certain significant Chilean law provisions and our bylaws.

General

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$ 176 million as of December 31, 2022) 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.

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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.

Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Norm Regulation 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 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.

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Corporate Objectives and Purposes

Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transformation, or sale of energy in Chile in any form, directly or through other companies, as well as to provide engineering consulting services related to these objectives and to make loans to related companies, subsidiaries, and affiliates.

Board of Directors

Our board of directors consists of seven members 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.

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Certain Provisions Regarding Shareholder Rights

As of the date of this Report, our capital comprises only one class of shares, all of which are common shares and have the same rights.

Our bylaws do not contain any provisions relating to:

●

redemption provisions;

●

sinking funds; or

●

liability for capital reductions by us.

Under Chilean law, the rights of our shareholders may only be modified by an amendment to the bylaws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association — Shareholders’ Meetings and Voting Rights.”

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under 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, 2022, the Company’s subscribed and fully paid capital totaled Ch$ 3.9 trillion consisting of 69,166,557,220 shares.

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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.

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 26, 2023. 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.

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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 in 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;

●

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 calendar days before its scheduled shareholders’

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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.

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.

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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

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statements, the entire board of directors is deemed removed from office, and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the board of directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies that publicly offer their shares or convertible securities. This offer is made to shareholders to purchase their shares under conditions that allow the bidder to reach a certain percentage of ownership of the company within a fixed period. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

No provision in our bylaws discriminates against any existing or prospective holder of shares due to such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of our stock’s outstanding shares. The preceding restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our bylaws currently prohibit any shareholder from exercising voting power concerning more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Corporations Law provides that upon adopting any of the resolutions enumerated below at a shareholders’ meeting, dissenting shareholders acquire the right to withdraw from the company and compel the company to repurchase their shares, subject to the fulfillment of specific terms and conditions. To exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs under the Deposit Agreement’s terms. In case of a bankruptcy proceeding, the withdrawal right from an adopted resolution is suspended until the existing debt has been paid.

“Dissenting” shareholders are defined as those at a shareholders’ meeting who vote against a resolution that results in the withdrawal right or who, if absent from such meeting, state in writing their opposition to the respective resolution within the 30 days following the shareholders’ meeting. Shareholders 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

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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 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:

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the transformation of the company into an entity that is not a publicly held limited liability stock corporation governed by the Chilean Corporations Law;

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the merger of the company with another company;

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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;

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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;

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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);

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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;

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certain remedies for the nullification of the corporate bylaws; and

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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.

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Companies subject to Title XII provisions are required to have bylaws that:

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limit the ownership of any shareholder to a specified maximum percentage, currently 65%;

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require that certain actions be taken only at a meeting of the shareholders; and

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give the shareholders the right to approve certain investment and financing policies.

Registrations and Transfers

Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our shareholders’ registry. In the case of jointly owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with us.

C.	Material Contracts.

None.

D.	Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently, applicable foreign exchange regulations are 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.

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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.

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

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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 2022, 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 rate for 2022 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%).

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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

In February 2022, a new tax reform eliminated the tax exemption on capital gains obtained from the sale of shares that meet certain requirements detailed below, and established a new tax that applies to sales of shares that are made as of September 1, 2022. For non-residents, the tax will be withheld by the purchaser, stockbroker, or securities agent acting on behalf of the seller.

As a result of the new tax reform, the Chilean Income Tax Law provides for a 10% tax 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 10% tax: (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, the sale of our shares will be subject to the general tax regime, which will apply at varying levels depending on the time of the sale with respect to the date of loss of sufficient trading volume to qualify as a “high presence” security. If our shares regain a “high presence,” the 10% tax will again be available to holders thereof.

If the shares do not qualify for the 10% tax, 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, with a 27% Chilean CIT, the rate applicable during 2022, 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

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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:

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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;

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

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persons liable for the alternative minimum tax;

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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,

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including the amount of any Chilean taxes withheld, other than certain pro-rata distributions of shares to all shareholders, will constitute foreign-source income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. The amount of dividend income paid in Chilean pesos that a U.S. Holder will be required to include in income will equal the U.S. dollar value of the distributed Chilean peso, calculated by reference to the exchange rate in effect on the date the payment is received, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder will generally not be required to recognize foreign currency gain or loss regarding the dividend income. A U.S. Holder may have foreign currency gain or loss if the dividend is converted into U.S. dollars after the date of its receipt, which would be ordinary income or loss and would be treated as income from U.S. sources for foreign tax credit purposes. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s, or in the case of ADSs, the depositary’s, receipt of the dividend. Corporate U.S. Holders will not be entitled to claim the dividends-received deduction with respect to dividends paid by us.

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 believe that we were a PFIC for U.S. federal income tax purposes with respect to our 2022 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 2023 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

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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 “— 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 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. U.S. Holders are urged to consult their own tax advisors with respect to the particular consequences to them of owning or disposing of our shares or ADSs.

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.

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Passive Foreign Investment Company Rules

We do not believe that we were a PFIC for U.S. federal income tax purposes with respect to our 2022 taxable year and do not anticipate being a PFIC for our 2023 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.

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.

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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.”

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 some commodities, mainly through fuel purchases for the electricity generation process and energy purchase-sale transactions carried out in local markets.

In order to reduce risk under extreme drought conditions, we have designed a commercial policy that aligns sale commitment levels with generation capacity during a dry year by including risk mitigation clauses with unregulated clients in some contracts. 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, 2022, we held the following hedges:

●

450 kBbl of Brent oil for purchases to be settled in 2023;

●

Regarding natural gas, 2.7 TBtu of Henry Hub natural gas swap for sales to be settled in 2023 and 18.9 TBtu of Henry Hub natural gas future for purchases to be settled in 2023; and

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●

Regarding coal, 175.6 kTon of Coal API2 for purchases to be settled in 2023.

As of December 31, 2021, we held the following swaps:

●

1.93 kBbl of Brent oil settled in 2022; and

●

9.1 TBtu of Henry Hub gas settled in 2022.

Depending on the operating conditions that are updated continuously, these hedging measures may be modified or included in other commodities.

Interest Rate and Foreign Currency Risk

As of December 31, 2022, 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,

2023

2024

2025

2026

2027

Thereafter

Total

Fair
Value⁽²⁾

(in millions of Ch$)⁽¹⁾

Fixed Rate

Ch$/UF

261

—

276

Weighted average interest rate

3.1%

6.2%

—

3.3%

n.a.

US$

177,443

480,321

137,977

158,946

335,151

1,760,546

3,050,384

2,933,192

Weighted average interest rate

2.8%

4.0%

2.9%

3.2%

5.9%

4.5%

4.4%

n.a.

Other currencies

717

953

4,363

8,892

Weighted average interest rate

4.9%

4.7%

4.8%

Total fixed rate

178,421

481,289

138,930

159,899

336,104

1,764,909

3,059,552

2,942,360

Weighted average interest rate

2.9%

4.0%

3.0%

3.2%

5.8%

4.5%

4.4%

n.a.

Variable Rate

Ch$/UF

46,151

46,257

46,089

45,965

45,849

252,893

483,204

503,741

Weighted average interest rate

5.0%

4.9%

5.0%

4.1%

4.5%

n.a.

US$

248,199

42,793

128,379

—

462,164

Weighted average interest rate

5.0%

1.8%

2.8%

2.7%

—

3.9%

—

Total variable rate

294,350

89,050

88,882

174,344

45,849

252,893

945,368

965,905

Weighted average interest rate

5.0%

3.4%

3.9%

3.3%

5.0%

4.1%

4.2%

n.a.

Total

472,771

570,339

227,812

334,243

381,953

2,017,802

4,004,920

3,908,265

(1)	Calculated based on the Observed Exchange Rate as of December 31, 2022.

(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, 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

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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

—

262

Weighted average interest rate

2.5%

5.9%

6.2%

—

3.0%

n.a.

US$

28,796

175,101

474,120

136,244

1,841,242

2,791,748

3,044,846

Weighted average interest rate

2.1%

2.8%

4.0%

2.9%

4.7%

4.3%

n.a.

Other currencies

778

743

4,256

8,008

Weighted average interest rate

4.9%

4.8%

n.a.

Total fixed rate

29,797

175,864

474,882

136,987

1,845,498

2,800,018

3,053,116

Weighted average interest rate

2.2%

2.9%

4.0%

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%

5.0%

4.1%

4.5%

n.a.

US$

794,009

—

42,235

126,704

—

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.

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, 2022, and 2021, 84% and 82%, respectively, of our total outstanding debt had fixed interest rates, and 16% and 18%, respectively, of our total outstanding debt 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, 2022, 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,	2023	2024	2025	2026	2027	Thereafter	Total	Fair Value⁽²⁾

	(in millions of Ch$)⁽¹⁾
Variable to fixed rates	—	42,793	—	—	—	—	42,793	2,650
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	—	42,793	—	—	—	—	42,793	2,650

(1)	Calculated based on the Observed Exchange Rate as of December 31, 2022.

(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, 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	337,876	—	42,235	—	—	—	380,111	(6,101)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	337,876	—	42,235	—	—	—	380,111	(6,101)

(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.

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, 2022, 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,	2023	2024	2025	2026	2027	Thereafter	Total	Fair Value⁽²⁾

	(in millions of Ch$)⁽¹⁾
UF to US$	—	389,179	79,048	—	—	—	468,227	8,260
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	389,179	79,048	—	—	—	468,227	8,260

(1)	Calculated based on the Observed Exchange Rate as of December 31, 2022.

(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, 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$)⁽¹⁾
UF to US$	—	—	441,376	91,105	—	—	532,481	(37,403)
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	—	441,376	91,105	—	—	532,481	(37,403)

(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.

Please refer to Note 22 of the Notes to our consolidated financial statements for further detail.

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(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 2022

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2022, the Depositary reimbursed us for expenses related primarily to investor relations activities for approximately US$ 0.6 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, 2022.

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.

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Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2022. 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, 2022, our internal control over financial reporting was effective.

(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, 2022. Their attestation report appears on page F-3.

(d)

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d) or 15d-15(d) under the Exchange Act that occurred during the year ended December 31, 2022, 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, 2022, 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 approved by our board of directors: (i) the Manual for the Management of Information of Interest to the Market (the “Manual”); (ii) the Human Rights and Politically Exposed Person Policy; (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 Control and Management System; (viii) procedures issued in compliance with the requirements of CMF General Norm Regulation No. 385, which was in force and subsequently replaced by CMF General Norm Regulation No. 461 (“NCG 461” in its Spanish acronym); and (ix) the Diversity Policy.

The Manual 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 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.

The Manual also includes our insider trading policy and procedure, which determines the general behavior criteria that our directors, management, principal executives, employees, and other related parties (“the Parties”) must follow in the transactions they carry out, contributing to the transparency and protection of investors.

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The Manual regulates the following:

●

the Parties’ actions involving the transactions and holding of securities issued either by the Company or by other companies belonging to our business group, or of securities whose price or result depends on or is conditioned, in whole or in significant part, to the variation or evolution of the same in accordance with the provisions of CMF General Norm Regulation No. 269. For further information concerning the reporting requirements under this regulation, please refer to “Item 10. Additional Information — B. Memorandum and Articles of Association — Reporting Requirements Regarding Acquisition of Sale of Shares”;

●

the type, form, and content of the information that should be made known to the market in general regarding such transactions and holdings;

●

the dissemination to the general public of material facts and confidential or privileged information;

●

the procedures for safeguarding confidential information about the Company and its dissemination mechanisms to prevent such information from being disclosed to persons other than those who, due to their position or activity at the Company must know such information before it is made available to shareholders and the public; and

●

the policies that govern relationships with the media, analysts, or investment banks.

The Politically Exposed Person Policy includes procedures for regulating the commercial and contractual relationships between Politically Exposed People and us, and the Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into our corporate policies. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, and other ethical standards, 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.

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 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.

The Internal Control and Risk Management System is a set of guidelines defined by Enel for the standards, procedures, and systems applied at different levels of our company 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; as well as 38 sub-categories.

Enel Chile’s Risk Control and Management policy is guided by our principles rooted in Enel’s Internal Control and Risk Management System and contains policies that monitor limits and indicators related to our specific risks, corporate functions, or businesses. Our main risk control and management policies are described as follows:

●

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

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●

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 risk of commodities.

●

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 risks involving financial markets, financial counterparties, liquidity, and operations.

●

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 Chile area is ISO 31000:2022 (G31000) certified and acts under the guidelines of these international standards. The primary objective is to identify internal and external risks preemptively and to analyze, evaluate, and quantify the probability of their occurrence and impact on the Company. Each area within the Company 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.

NCG 461, issued by CMF, establishes a new structure and contents for the Company’s annual report, including corporate social responsibility practices, 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. 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 2018, the board of directors approved a policy dealing with environmental and biodiversity issues. ESG criteria are integrated into our business model. 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.

In 2016, we established the Diversity Policy that 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 of our employees. The Company is committed to creating an inclusive work environment where employees 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

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Comuna de Santiago, Santiago, Chile

(56-2) 2353-4400

In the fiscal year 2022, 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 2022.

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	2022	2021

	(in millions of Ch$)
Audit fees	1,258	1,175
Audit-related fees	84	68
Tax fees	—	—
All other fees	—	—
Total	1,342	1,243

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.

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The Directors Committee has designed, approved, and implemented the necessary procedures to fulfill the SEC requirements regarding the Audit Committee’s pre-approval of certain tax services.

Item 16D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

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

In the fiscal year 2022, 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

None.

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 Corporations 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$ 53 billion as of December 31, 2022) 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

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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.

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 461 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.

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PART III

Item 17. Financial Statements

Not Applicable.

Item 18. Financial Statements

See Financial Statements included at the end of this Report.

Item 19. Exhibits


Exhibit		Description
1.1		By-laws (Estatutos) of Enel Chile S.A.
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, 2022.
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 non-filed instruments that define the rights of holders of long-term debt 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 26, 2023

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Enel Chile and subsidiaries

Index to the Audited Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:


Report of KPMG Auditores Consultores SpA (PCAOB ID No. 1273) at December 31,2022, 2021, and 2020			F-1 - F-4

Consolidated Financial Statements:

Consolidated Statements of Financial Position			F-5
Consolidated Statements of Comprehensive Income			F-7
Consolidated Statements of Changes in Equity			F-9
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

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, 2022 and 2021, the related consolidated statements of comprehensive income by nature, changes in equity, and cash flows direct for each of the years in the three-year period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022, 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 26, 2023, 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 audit 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 Ltda, a Chilean joint-stock company and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. 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 judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Unbilled Revenue

As discussed in Notes 3q and 28 to the consolidated financial statements, revenue from sales to customers includes estimates of energy provided and not billed as of December 31, 2022, amounting to ThCh$812,406,845 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 distribution and generation entities. This included controls related to:

• the price used for estimation of unbilled sales to customers

• inputs used to estimate the quantity of energy consumed by customers, such as energy purchased from the Company and the customer´s historical consumption information, including the energy consumption by customers in the previous month

• the comparison between the estimate of unbilled revenue at the end of the month versus the actual volume of energy subsequently measured and billed to customers (back-testing) for the distribution and generation entities.

We compared the volume used in the estimate of unbilled revenue at the end of the year versus the actual volume of energy subsequently measured and billed to customers (back-testing) or to external data provided by the local regulator, as applicable. We reassessed a sample of the price used to calculate the unbilled sales to customers based on current contracts and decrees issued by the local regulator. We evaluated the reconciliation of the sales ledger to the actual sales report as of year-end. In addition, we assessed the sufficiency of the nature and extent of the audit evidence obtained, as well as the Company’s disclosures of this matter in Note 28 to the consolidated financial statements.

/s/ KPMG

KPMG Auditores Consultores SpA

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

Santiago, Chile

April 26, 2023

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, 2022, 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, 2022, 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, 2022 and 2021, the related consolidated statements of comprehensive income by nature, changes in equity, and cash flows direct for each of the years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated April 26, 2023 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.

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 26, 2023

F-4

Consolidated Financial Statements

ENEL CHILE S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2022 and 2021


	Note	12-31-2022	12-31-2021
		ThCh$	ThCh$
ASSETS
CURRENT ASSETS
Cash and cash equivalents	6	875,213,699	309,975,140
Other current financial assets	7	3,530,216	4,041,415
Other current non-financial assets	8.a	192,640,352	66,825,997
Trade and other receivables, current	9	1,509,513,355	688,185,127
Current accounts receivable from related parties	10	256,268,604	56,440,088
Inventories	11	77,916,093	31,247,710
Current tax assets	12	120,558,367	111,537,016
Total current assets other than assets or groups of assets for disposal classified as held for sale or as held for distribution to owners		3,035,640,686	1,268,252,493
Non-current assets or disposal groups held for sale	5	28,601,633	—
TOTAL CURRENT ASSETS		3,064,242,319	1,268,252,493

NON-CURRENT ASSETS
Other non-current financial assets	7	59,827,640	39,379,065
Other non-current non-financial assets	8.a	78,276,341	89,616,648
Trade and other non-current receivables	9	691,147,645	515,786,340
Non-current accounts receivable from related parties	10	—	6,348,001
Investments accounted for using the equity method	13	17,752,778	9,923,933
Intangible assets other than goodwill	14	191,441,263	191,221,555
Goodwill	15	883,613,429	921,078,198
Property, plant and equipment	16	6,572,353,994	6,110,688,761
Investment property	17	7,348,262	7,539,005
Right-of-use assets	18	233,698,432	160,788,861
Deferred tax assets	19.b	65,877,629	179,700,736
TOTAL NON-CURRENT ASSETS		8,801,337,413	8,232,071,103

TOTAL ASSETS		11,865,579,732	9,500,323,596

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

F-5

ENEL CHILE S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position (continued)

As of December 31, 2022 and 2021


	Note	12-31-2022	12-31-2021
		ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Other current financial liabilities	20	68,519,783	88,339,890
Current lease liabilities	21	19,020,636	11,105,018
Trade and other payables, current	24	1,743,892,909	978,324,487
Current accounts payable to related parties	10	946,498,574	1,004,597,958
Other current provisions	25	22,902,006	19,756,317
Current tax liabilities	12	334,336,370	13,148,707
Other current non-financial liabilities	8.b	33,321,602	17,053,840
TOTAL CURRENT LIABILITIES		3,168,491,880	2,132,326,217

NON-CURRENT LIABILITIES
Other non-current financial liabilities	20	2,183,803,256	1,941,874,378
Non-current lease liabilities	21	216,664,919	148,557,059
Trade and other payables non-current	24	308,308,862	179,397,412
Non-Current accounts payable to related parties	10	1,147,096,713	1,300,059,097
Other long-term provisions	25	189,470,243	194,112,714
Deferred tax liabilities	19.b	199,016,494	197,416,950
Non-current provisions for employee benefits	26	62,699,415	58,951,586
Other non-current non-financial liabilities	8.b	1,088,647	1,135,285
TOTAL NON-CURRENT LIABILITIES		4,308,148,549	4,021,504,481

TOTAL LIABILITIES		7,476,640,429	6,153,830,698

EQUITY
Share and paid-in capital	27.1	3,882,103,470	3,882,103,470
Retained earnings		2,474,432,817	1,603,186,295
Other reserves	27.5	(2,259,335,392)	(2,387,421,412)
Equity attributable to shareholders of Enel Chile		4,097,200,895	3,097,868,353
Non-controlling interests	27.6	291,738,408	248,624,545
TOTAL EQUITY		4,388,939,303	3,346,492,898

TOTAL LIABILITIES AND EQUITY		11,865,579,732	9,500,323,596

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

F-6

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2022, 2021 and 2020


	Note	2022	2021	2020
		ThCh$	ThCh$	ThCh$
STATEMENTS OF PROFIT (LOSS)
Revenues	28	4,379,000,090	2,829,682,404	2,548,384,317
Other operating income	28	577,431,773	25,547,131	37,017,880
Revenues and other operating income		4,956,431,863	2,855,229,535	2,585,402,197
Raw materials and consumables used	29	(3,399,524,067)	(2,011,305,404)	(1,374,445,639)
Contribution Margin		1,556,907,796	843,924,131	1,210,956,558

Other work performed by the entity and capitalized	16.b.2	44,569,685	31,157,196	25,539,316
Employee benefits expense	30	(158,239,393)	(163,345,154)	(137,226,748)
Depreciation and amortization expense	31.a	(238,272,951)	(210,927,656)	(229,957,019)
Impairment (loss) reversal recognized in profit or loss	31.b	(1,547,699)	(32,898,854)	(697,806,441)
Impairment (loss) impairment gain and reversal of impairment loss determined in accordance with IFRS 9	31.b	(22,025,354)	(18,765,175)	(15,167,707)
Other expenses, by nature	32	(269,034,847)	(189,550,825)	(190,593,334)
Operating Income		912,357,237	259,593,663	(34,255,375)

Other gains	33	981,981,296	10,137,284	9,488,815
Financial income	34	50,414,585	26,420,400	36,160,460
Financial costs	34	(193,618,033)	(174,043,116)	(127,408,771)
Share of profit of associates and joint ventures accounted for using the equity method	13	3,281,241	3,177,409	3,509,392
Foreign currency exchange differences	34	18,401,453	(15,334,368)	(23,272,231)
Gains or losses from indexed assets and liabilities	34	5,862,890	5,897,520	2,085,768
Profit (loss) before taxes		1,778,680,669	115,848,792	(133,691,942)
Income tax expense	19.a	(469,696,880)	(15,138,658)	81,305,107
PROFIT (LOSS)		1,308,983,789	100,710,134	(52,386,835)

Profit (loss) attributable to
Profit (loss) attributable to owners of the parent		1,252,082,258	85,153,969	(50,860,313)
Profit (loss) attributable to non-controlling interests	27.6	56,901,531	15,556,165	(1,526,522)
Profit (loss)		1,308,983,789	100,710,134	(52,386,835)

Basic earnings per share
Basic earnings (losses) per share	Ch$/Share	18.10	1.23	(0.74)
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	18.10	1.23	(0.74)
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-7

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2022, 2021 and 2019

(In thousands of Chilean pesos – ThCh$)


	Note	2022	2021	2020
		ThCh$	ThCh$	ThCh$
STATEMENTS OF COMPREHENSIVE INCOME
Gains (losses)		1,308,983,789	100,710,134	(52,386,835)
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
Profit (loss) from defined benefit plans	26.2.b	(7,304,757)	12,547,898	(8,545,834)
Other comprehensive loss that will not be reclassified subsequently to profit or loss		(7,304,757)	12,547,898	(8,545,834)
Components of other comprehensive income that will be reclassified subsequently to profit or loss, before taxes
Gains (losses) from foreign currency translation differences		18,994,934	197,099,813	(69,218,245)
Gains (losses) on measuring financial asset at fair value through other comprehensive income		(2)	31	(9,125)
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	13.1	1,043,185	359,797	18,982
Gains (losses) on cash flow hedges		67,832,602	(455,116,679)	208,749,917
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		79,672,895	48,145,467	58,790,411
Other comprehensive income that will be reclassified subsequently to profit or loss		167,543,614	(209,511,571)	198,331,940
Total components of other comprehensive income (loss) before taxes		160,238,857	(196,963,673)	189,786,106
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		1,972,561	(3,387,932)	2,308,510
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		1,972,561	(3,387,932)	2,308,510
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		(39,826,484)	109,882,227	(72,741,119)
Income tax related to financial assets at fair value through other comprehensive income		1	(8)	2,464
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		(39,826,483)	109,882,219	(72,738,655)

Total other comprehensive income		122,384,935	(90,469,386)	119,355,961
TOTAL COMPREHENSIVE INCOME		1,431,368,724	10,240,748	66,969,126

Comprehensive income (loss) attributable to:
Owners of Enel Chile		1,363,350,140	(17,917,889)	68,669,685
Non-controlling interests		68,018,584	28,158,637	(1,700,559)
TOTAL COMPREHENSIVE INCOME		1,431,368,724	10,240,748	66,969,126

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

F-8

ENEL CHILE S.A.

Consolidated Statements of Changes in Equity

For the years ended December 31, 2022, 2021 and 2020


			Changes in Other Reserves
	Share and Paid-in Capital (1)	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 through Other Comprehensive Income	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 1-1-2022	3,882,103,470	279,801,463	(391,523,134)	—	1,804	(111,719,867)	(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 equity						—	—	—	—	—	—	—
Comprehensive income
Profit (loss)	—	—	—	—	—	—		—	1,252,082,258	1,252,082,258	56,901,531	1,308,983,789
Other comprehensive income (loss)	—	17,081,503	99,387,492	(5,211,060)	(2)	111,257,933	9,949	111,267,882	—	111,267,882	11,117,053	122,384,935
Comprehensive income	—	—	—	—	—	—	—	—	—	1,363,350,140	68,018,584	1,431,368,724
Dividends	—	—	—	—	—	—	—	—	(375,624,676)	(375,624,676)	(23,365,365)	(398,990,041)
Increase (decrease) from other changes	—	(178,457)	(1,033,235)	5,211,060	—	3,999,368	12,818,770	16,818,138	(5,211,060)	11,607,078	(1,539,356)	10,067,722
Total changes in equity	—	16,903,046	98,354,257	—	(2)	115,257,301	12,828,719	128,086,020	871,246,522	999,332,542	43,113,863	1,042,446,405

Equity at end of period 12-31-2022	3,882,103,470	296,704,509	(293,168,877)	—	1,802	3,537,434	(2,262,872,826)	(2,259,335,392)	2,474,432,817	4,097,200,895	291,738,408	4,388,939,303


			Changes in Other Reserves
	Share and Paid-in Capital (1)	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 through Other Comprehensive Income	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 1-1-2021	3,882,103,470	103,650,093	(102,946,095)	—	1,783	705,781	(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	(103,431,655)	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 changes	—	—	—	(8,993,993)	—	(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	(112,425,648)	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	(111,719,867)	(2,275,701,545)	(2,387,421,412)	1,603,186,295	3,097,868,353	248,624,545	3,346,492,898

F-9


			Changes in Other Reserves
	Share and Paid-in Capital (1)	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 through Other Comprehensive Income	Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity attributable to owners of the parent to Shareholders of Enel Chile	Non-Controlling Interests (4)	Total Equity
Consolidated Statement of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2020	3,882,103,470	166,116,569	(291,006,520)	—	8,384	(124,881,567)	(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)	119,511,016	18,982	119,529,998	—	119,529,998	(174,037)	119,355,961
Comprehensive income	—	—	—	—	—	—	—	—	—	68,669,685	(1,700,559)	66,969,126
Dividends	—	—	—	—	—	—	—	—	(203,729,201)	(203,729,201)	(18,163,142)	(221,892,343)
Increase (decrease) from other changes	—	—	—	6,076,332	—	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)	125,587,348	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	705,781	(2,278,331,266)	(2,277,625,485)	1,747,437,805	3,351,915,790	242,358,709	3,594,274,499

(1) See Note 27.1

(2) See Note 27.3

(3) See Note 27.5

(4) See Note 27.6

F-10

Table of Contents

ENEL CHILE S.A.

Consolidated Statements of Cash Flows, Direct Method

For the years ended December 31, 2022, 2021 and 2020


		2022	2021	2020
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		5,509,393,246	3,686,363,387	2,961,814,449
Collections from premiums and services, annual payments, and other obligations from policies held		554,616	14,095,650	6,846,414
Collections from leasing and subsequent sale of such assets		14,082,550	13,674,456	102,436,230
Other collections from operating activities		43,343,670	142,770	16,403,356

Types of payment in cash from operating activities
Payments to suppliers for goods and services		(4,469,547,402)	(2,917,132,449)	(1,935,080,572)
Payments to and on behalf of employees		(147,549,249)	(134,092,365)	(140,378,194)
Payments of premiums and services, annual payments, and other obligations from policies held		(26,594,156)	(23,852,317)	(25,114,326)
Payments to manufacture or acquire assets held to lease to others and subsequently held for sale		—	(1,026,749)	(56,489,776)
Other payments for operating activities		(108,055,801)	(108,405,395)	(170,290,593)

Cash flows from (used in) operating activities
Income taxes paid		(59,828,183)	(112,104,283)	(1,342,494)
Other cash outflows, net		(11,020,478)	(4,769,890)	(2,938,296)
Net cash flows from operating activities		744,778,813	412,892,815	755,866,198


Cash flows from (used in) investing activities
Cash flows from the loss of control of subsidiaries or other businesses, net	6.d)	1,234,493,876	—	—
Other cash payments to acquire equity or debt instruments of other entities		(4,664,044)	(69,575)	(2,769,624)
Other collections from the sale of shares in joint ventures	12.3.c)	—	11,786,767	—
Other cash payments to acquire shares in joint ventures		(29,940,350)	—	—
Loans to related companies		(43,013)	(1,402,847)	—
Proceeds from the sale of property, plant and equipment		1,482,597	18,197,075	—
Purchases of property, plant and equipment		(915,692,779)	(748,013,237)	(514,807,265)
Proceeds from the sale of intangible assets		—	2,489,340	—
Purchases of intangible assets		(21,868,532)	(38,059,298)	(39,506,950)
Collections from reimbursement of advances and loans granted to others	6.e)	172,369,859	—	—
Payments for future, forward, option and swap contracts		(26,695,926)	(4,791,872)	(3,260,921)
Collections from future, forward, option and swap contracts		25,298,133	11,607,175	22,229
Collections from related entities		—	1,381,763	—
Dividends received		484,369	7,023,030	—
Interest received		20,152,225	3,296,869	5,671,141
Other cash inflows (outflows)		194,964	—	—
Net cash flows from (used in) investing activities		455,571,379	(736,554,810)	(554,651,390)

Cash flows from (used in) financing activities
Payments for other equity interests		—	—	(519,943)
Total proceeds from loans	6.f)	712,746,614	77,273,500	—
Proceeds from long-term loans	6.f)	263,892,100	77,273,500	—
Proceeds from short-term loans	6.f)	448,854,514	—	—
Loans from related companies	6.f)	602,033,501	633,799,000	484,520,001
Payments of loans	6.f)	(510,046,267)	(33,736,628)	(150,878,247)
Payments on borrowings and lease liabilities	6.f)	(6,613,399)	(6,060,566)	(4,940,582)
Payments of loans to related entities	6.f)	(1,187,697,500)	—	—
Dividends paid		(39,609,648)	(231,068,611)	(312,714,789)
Interest paid	6.f)	(186,961,822)	(142,891,300)	(139,251,404)
Other outflows of cash, net	6.f)	(12,507,838)	(4,083,886)	(3,884,370)
Net cash flows (used in) from financing activities		(628,656,359)	293,231,509	(127,669,334)

Net increase (decrease) in cash and cash equivalents before effect of exchange rate movements		571,693,833	(30,430,486)	73,545,474

Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(6,455,274)	8,369,613	22,806,039
Net increase (decrease) in cash and cash equivalents		565,238,559	(22,060,873)	96,351,513
Cash and cash equivalents at beginning of year	6	309,975,140	332,036,013	235,684,500
Cash and cash equivalents at end of year	6	875,213,699	309,975,140	332,036,013

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

F-11

Table of Contents

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-21
2.4 Subsidiaries		F-22
2.5 Investment in associates		F-23
2.6 Joint arrangements		F-24
2.7 Basis of consolidation and business combinations		F-25
2.8 Functional currency		F-26
2.9 Conversion of financial statements denominated in foreign currency		F-26
3. ACCOUNTING POLICIES		F-28
a) Property, plant and equipment		F-28
b) Investment property		F-29
c) Goodwill		F-30
d) Intangible assets other than goodwill		F-30
d.1) Research and development expenses		F-30
d.2) Other intangible assets		F-31
e) Impairment of non-financial assets		F-31
f) Leases		F-33
f.1) Lessee		F-33
f.2) Lessor		F-34
g) Financial instruments		F-34
g.1) Financial assets other than derivatives		F-34
g.2) Cash and cash equivalents		F-35
g.3) Impairment of financial assets		F-35
g.4) Financial liabilities other than derivatives		F-36
g.5) Derivative financial instruments and hedge accounting		F-38
g.6) Derecognition of financial assets and liabilities		F-39
g.7) Offsetting of financial assets and financial liabilities		F-39
g.8) Financial guarantee contracts		F-39
h) Fair value measurent		F-39
i) Investments accounted for using the equity method		F-41
j) Inventories		F-41
k) Non-current assets (or disposal group of assets) held for sale or held for distribution to owners and discontinued operations		F-41
l)Treasury shares		F-42
m) Provisions		F-42
m.1) Provisions for post-employment benefits and similar obligations		F-43
n) Translation of foreign currency balances		F-43
o) Classification of balances as current and non-current		F-43
p) Income taxes		F-44
q) Revenue and expense recognition		F-44
r) Earnings per share		F-46
s) Dividends		F-46
t) Share issuance costs		F-47
u) Statement of cash flows		F-47
4. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS		F-48
a) Regulatory framework		F-48
b) Regulatory matters		F-51
c) Tariff Revisions and Supply Processes		F-55
5. NON-CURRENT ASSETS HELD FOR SALE		F-59
6. CASH AND CASH EQUIVALENTS		F-61
7. OTHER FINANCIAL ASSETS		F-64
8. OTHER NON-FINANCIAL ASSETS AND LIABILITIES		F-64

F-12

Table of Contents

9. TRADE AND OTHER RECEIVABLES		F-65
10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES		F-72
10.1 Balances and transactions with related parties		F-73
a) Receivables from related parties		F-73
b) Accounts payable to related parties		F-74
c) Significant transactions and effects on profit or loss		F-75
d) Significant transactions		F-75
10.2 Board of Directors and key management personnel		F-77
10.3 Compensation of key management personnel		F-80
10.4 Incentive plans for key management personnel		F-80
10.5 Compensation plans linked to share price		F-80
10.6 Restricted stock unit program		F-80
11. INVENTORY		F-81
12. CURRENT TAX ASSETS AND LIABILITIES		F-81
13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD		F-82
13.1. Investments accounted for using the equity method		F-82
13.2. Additional financial information on investments in associates		F-83
13.3. Joint ventures		F-84
14. INTANGIBLE ASSETS OTHER THAN GOODWILL		F-86
15. GOODWILL		F-88
16. PROPERTY, PLANT AND EQUIPMENT		F-90
17. INVESTMENT PROPERTY		F-95
18. RIGHT-OF-USE-ASSETS		F-96
19. INCOME TAX AND DEFERRED TAXES		F-97
a) Income taxes		F-97
b) Deferred taxes		F-98
20. OTHER FINANCIAL LIABILITIES		F-100
20.1 Interest-bearing borrowings		F-100
20.2 Unsecured liabilities		F-102
20.3 Secured liabilities		F-103
20.4 Hedged debt		F-103
20.5 Other information		F-104
20.6 Future Undiscounted debt flows		F-104
21. LEASE LIABILITIES		F-105
22. RISK MANAGEMENT POLICY		F-106
22.1 Interest rate risk		F-106
22.2 Exchange rate risk		F-107
22.3 Commodities risk		F-107
22.4 Liquidity risk		F-108
22.5 Credit risk		F-108
22.6 Risk measurement		F-109
23. FINANCIAL INSTRUMENTS		F-110
23.1 Financial instruments, classified by type and category		F-110
23.2 Derivative instruments		F-111
23.3 Fair value hierarchy		F-114
24. CURRENT AND NON-CURRENT PAYABLES		F-115
25. PROVISIONS		F-116
26. POST-EMPLOYMENT BENEFIT OBLIGATIONS		F-117
26.1 General information		F-117
26.2 Details, movements and presentation in financial statements		F-117
26.3 Other disclosures		F-118
27. EQUITY		F-119
27.1 Equity attributable to the owners of Enel Chile		F-119
27.1.1 Subscribed and paid capital and number of shares		F-119
27.2 Dividends		F-119
27.3 Foreign currency translation reserves		F-119
27.4 Restrictions on subsidiaries transferring funds to the parent		F-119
27.5 Other reserves		F-120
27.6 Non-controlling Interests		F-121
28. REVENUE AND OTHER OPERATING INCOME		F-122

F-13

Table of Contents

29. RAW MATERIALS AND CONSUMABLES USED		F-123
30. EMPLOYEE BENEFITS EXPENSE		F-123
31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSS OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9		F-124
32. OTHER EXPENSES, BY NATURE		F-124
33. OTHER GAINS (LOSSES)		F-125
34. FINANCIAL RESULTS		F-125
35. INFORMATION BY SEGMENT		F-128
35.1 Basis of segmentation		F-128
35.2 Generation and distribution		F-130
36. GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS		F-132
36.1 Direct guarantees		F-132
36.2 Indirect guarantees		F-132
36.3 Litigation and arbitration proceedings		F-132
36.4 Financial restrictions		F-134
36.5 COVID-19 contingency		F-136
37. HEADCOUNT		F-136
38. SANCTIONS		F-136
39. ENVIRONMENT		F-138
40. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED		F-141
41. SUBSEQUENT EVENTS		F-143
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY		F-144
APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012		F-146
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES		F-148
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY, POWER AND TOLL		F-150
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS		F-151

F-14

Table of Contents

ENEL CHILE S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2022 AND 2021 AND FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020.

(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 Chilean Financial Market Commission (“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, 2022, the Group had 2,158 employees. During the fiscal year ended December 31, 2022, the Group averaged a total of 2,256 employees (see Note 37).

The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy of any kind or form, whether in Chile or abroad, either directly or through other companies. It is also engaged in telecommunications activities, and it provides engineering consulting services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing, its investments in subsidiaries and associates which generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:

Energy of any kind or form,

ii)

Supplying public services, or services whose main component is energy,

iii)

Telecommunications and information technology services, and

iv)

Internet-based intermediation business.

F-15

Table of Contents

2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1. Accounting principles

The consolidated financial statements of Enel Chile as of December 31, 2022, approved by its Board of Directors at its meeting held on April 26, 2023, 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, 2022 and 2021, and the results of operations, changes in equity and cash flows for the years ended December 31, 2022, 2021 and 2020, and the 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

The following accounting pronouncements have been adopted by the Group effective beginning on January 1, 2022:


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: References 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 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 apply these amendments early.

F-16

Table of Contents

The adoption of these amendments generated no impacts on the Group’s consolidated financial statements on the date of initial application.

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 liabilities and contingent liabilities, within the scope of IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, or IFRIC 21: “Levies”, an acquirer applying IFRS 3 should refer to these standards, instead of the 2018 Conceptual Framework. Without this exception, an entity would have recognized certain liabilities in a business combination that would not be recognized in accordance with IAS 37.

The amendments are applicable prospectively to business combinations with acquisition dates beginning on or after January 1, 2022.

The adoption of these amendments generated no impacts on the Group’s consolidated financial statements on the date of initial application.

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 an item 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 proceeds from sales and related costs in profit or loss for the period. The amendments also clarify that an entity is “testing whether an asset operates properly” when it assesses 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 retrospectively, 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 another equity component as applicable) at the beginning of the first period reported .

The adoption of these amendments generated no impacts on the Group’s consolidated financial statements on the date of initial application.

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 to annual reporting 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 annual reporting 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) at the date of initial application.

F-17

Table of Contents

The adoption of these amendments generated no impacts on the Group’s consolidated financial statements on the date of initial application.

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.

These improvements are applicable to annual reporting 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 annual reporting 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.

The adoption of these amendments generated no impacts on the Group’s consolidated financial statements on the date of initial application.

Accounting pronouncements effective beginning on or after January 1, 2023

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:

IFRS 17 Insurance Contracts		January 1, 2023

Amendments to IAS 1 and Practice Statement No. 2: Disclosure of Accounting Policies		January 1, 2023

Amendments to IAS 8: Definition of Accounting Estimates		January 1, 2023

Amendments to IAS 12: Deferred Taxes Relating to Assets and Liabilities Arising from a Single Transaction		January 1, 2023

Amendments to IFRS 16: Lease Liability in a Sale and Leaseback		January 1, 2024

Amendments to IAS 1: Classification of Liabilities as Current or Non-Current and Non-Current Liabilities with Covenants		January 1, 2024

IFRS 17 “Insurance Contracts”

On May 18, 2017, the IASB issued IFRS 17 Insurance Contracts, with the objective of helping investors and others to gain a better understanding of the risk exposure, profitability and financial position of insurance companies. The new standard is applicable to all types of insurance contracts, regardless of the type of entity that issuing them. This standard is also applicable to certain guarantees and financial instruments with specific discretionary participation features.

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IFRS 17 replaces IFRS 4 Insurance Contracts, which was introduced as an interim standard in 2004, to solve comparison issues created by the latter. IFRS 17 requires that all insurance contracts be accounted for consistently. Insurance obligations will be accounted for at present value, rather than at historical cost. The information will be updated periodically, thereby providing more useful information to financial statement users.

In December 2021, the IASB amended IFRS 17 to add a "classification overlay" transition option to address possible accounting mismatches between financial assets and insurance contract liabilities in the comparative information presented on the initial application of IFRS 17.

This standard is applicable retrospectively, with certain exceptions, for annual periods beginning on or after January 1, 2023.

The adoption of these amendments generated no impacts of this amendment and Management has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

Amendments to IAS 1 and IFRS Practice Statement No. 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 Practice Statement 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.

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 in estimates and accounting policies that occur from the beginning of the first year in which the entity applies the amendments.

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Amendments to IAS 12: “Deferred Taxes 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. The amendments clarify that the exemption is not applicable to transactions that at the time of initial recognition give rise to equal taxable and deductible temporary differences and accordingly, companies are required to recognize deferred taxes on such transactions.

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

Amendments to IFRS 16 “Lease Liability in a Sale and Leaseback”

On September 22, 2022, the IASB issued amendments to IFRS 16 Leases, in order to clarify how a lessee-seller measures a leaseback operation after the transaction date in order to meet the requirements of IFRS 15 Revenue from Contracts with Customers, in order to be recorded as a sale.

These amendments apply to annual periods beginning on or after January 1, 2024, and early adoption is permitted. The amendments will be applied retrospectively to leaseback transactions performed after the initial application of IFRS 16.

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

Amendments to IAS 1 “Classification of Liabilities as Current and Non-Current” and “Non-Current Liabilities with Covenants”

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 by 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.

In addition, on October 31, 2022, the IASB issued new amendments to IAS 1, with the aim of improving the information that companies provide on long-term debt with covenants. The amendments also respond to comments from stakeholders on the classification of debt as current or non-current when applying the requirements issued in 2020.

The amendments are effective for annual periods beginning on or after January 1, 2024. Early adoption is permitted.

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

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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 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 to:

-The valuations performed to determine the existence of impairment losses in non-financial assets and goodwill (see Note 3.e).

-The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 3.m.1 and 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 Notes 4 and 9).

-The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.m).

-Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 3.a).

-The tax results of the different Group subsidiaries that will be reported to the respective tax authorities in the future, and other estimates have been used as a basis for recording the different income tax related balances in these consolidated financial statements (see Note 3.p).

-The fair value of assets acquired, and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

-Determination of expected credit losses on financial assets (see Note 3.g.3)

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-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, 2022, 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.

2.4Subsidiaries

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.

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:


Taxpayer ID				Ownership % at 12-31-2022			Ownership % at 12-31-2021
No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
77.282.311-8	Enel Transmisión Chile S.A. (i) (iv) (v)	Chile	Chilean peso	—	—	—	99.09%	—	99.09%
96.800.570-7	Enel Distribución Chile S.A. (i)	Chile	Chilean peso	99.09%	—	99.09%	99.09%	—	99.09%
96.783.910-8	Enel Colina S.A.	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%
76.412.562-2	Enel Green Power Chile S.A. (ii)	Chile	U.S. dollar	99.99%	—	99.99%	99.99%	—	99.99%
96.971.330-6	Geotérmica del Norte S.A.	Chile	U.S. dollar	—	84.59%	84.59%	—	84.59%	84.59%
76.126.507-5	Parque Talinay Oriente S.A.	Chile	U.S. dollar	—	60.91%	60.91%	—	60.91%	60.91%
76.321.458-3	Almeyda Solar SpA (ii)	Chile	U.S. dollar	—	—	—	—	—	—
99.577.350-3	Empresa Nacional de Geotermia S.A. (iii)	Chile	U.S. dollar	—	—	—	—	—	—
76.722.488-5	Empresa de Transmisión Chena S.A. (iv)	Chile	Chilean peso	—	—	—	—	—	—

2.4.1Changes in the scope of consolidation

2021

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

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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.

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.

2022

On December 9, 2022, Enel Chile completed the sale of its subsidiary Enel Transmisión Chile S.A. to Sociedad Transmisora Metropolitana SpA (a company that is 100% controlled by Inversiones Grupo Saesa Ltda.). The sale was made through an Initial Public Offering between November 7 and December 6, 2022. Consequently, all the shares of Enel Transmisión Chile S.A. owned by Enel Chile, (equivalent to 99.09%), were transferred to the new controlling shareholder (see Notes 5.2 and 33).

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:


Taxpayer ID				Ownership % at 12-31-2022			Ownership % at 12-31-2021
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%
77.569.067-4	Enel X Way Chile SpA (i)	Chile	Chilean peso	49.00%	—	49.00%	—	—	—
77.157.779-2	Enel X AMPCI Ebus Chile SpA (ii)	Chile	U.S. dollar	—	—	—	—	20.00%	20.00%

On April 4, 2022, the division of Enel X Chile S.A. was finalized to create a new company by the name of Enel X Way Chile SpA. Then, on May 31, 2022, 1,020 shares of that company were sold for ThCh$11,358,338, equivalent to a 51% interest ownership (see Note 6.d).

ii.

On December 6, 2022, our subsidiary Enel X Chile S.A. completed the sale of its 20% interest in Enel X AMPCI Ebus Chile SpA. to AMPCI EBUS Developments LLC (see Notes see 6.d and 33).

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 12-31-2022			Ownership % at 12-31-2021
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
77.110.358-8	HIF H2 SpA. (i)	Chile	U.S. dollar	—	50.00%	50.00%	—	50.00%	50.00%
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (ii)	Chile	Chilean peso	—	—	—	—	—	—
77.230.801-9	Sociedad de Inversiones K Cuatro SpA (iii)	Chile	Chilean peso	—	—	—	—	—	—

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

ii.

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.

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iii.

On October 28, 2021, our subsidiary Enel X Chile purchased a 10% interest in Sociedad de Inversiones K Cuatro SpA., and this interest is conditioned upon the long-term financial asset, because the Group did not have significant influence over it. On February 28, 2022, Enel X Chile increased its interest in Sociedad de Inversiones K Cuatro SpA. to 50%, thus satisfying the conditions to be classified as a joint venture, see Note 13.3.b.

Subsequently, on December 6, 2022, our subsidiary Enel X Chile completed the sale of its entire stake in Sociedad de Inversiones K Cuatro SpA. to Enel X AMPCI Ebus Chile SpA, see Note 13.3. b.

Currently, Enel Chile is not involved in any joint arrangement that qualifies as a joint operation.

2.7. Basis of consolidation and business combinations

The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations of intra-group transactions have been made.

The comprehensive income from subsidiaries is included in the consolidated statement of comprehensive income from the date when the Enel Chile 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 Enel Chile and its subsidiaries have been consolidated under the following basic principles:

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.

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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.

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.

Balances and transactions between consolidated companies have been fully eliminated on consolidation.

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.

Business combinations under common control are accounted for using 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 recorded 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 apply a retrospective item of 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:

Assets and liabilities, using the exchange rate prevailing at the closing date of the financial statements.

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).

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.

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).

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The financial statements of subsidiaries the functional currency of which 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 account "Other reserves"; and (ii) the translation effect is recognized in Gains (losses) from foreign currency translation, in the consolidated statements of 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.

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 2020	36.13	%
From January to December 2021	50.95	%
From January to December 2022	94.79	%

The effects of the application of this standard on these consolidated financial statements are detailed in Note 34.

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3. ACCOUNTING POLICIES

The main accounting policies used in preparing the accompanying consolidated financial statements are the following:

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 performance of activities for a qualifying asset has been interrupted, if these periods are extended over time. The interest rate used is that corresponding to the specific financing or, if it does not exist, the average financing rate of the company making the investment (see Note 16.b.1).

Employee expenses directly related to construction in progress (see Note 16.b.2).

Future disbursements that the Group will have to make to close its facilities are added to the value of the asset at fair value, recognizing the related provision for dismantling or restoration. Changes in the measurement of the provision resulting from changes in the estimated amount or timing of future expenditures required to settle the obligation, or changes in the discount rate, are added to or deducted from the cost of the asset, as appropriate (see Note 25).

Assets under 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:


Class 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.

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.

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Gains or losses arising from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the statement of comprehensive income and determined as the difference between the sales amount and the net carrying amount of the asset.

The fair value of investment property is disclosed in Note 17.

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).

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, 2022, and December 31, 2021, intangible assets with indefinite useful lives amounted to ThCh$6,550,168 and ThCh$14,766,953, respectively, mainly related to easements and water rights. The decrease in these assets at the end of December 2022 is mainly due to the transfer of ThCh$ 9,377,135 to assets classified as held for sale from Enel Transmisión Chile S.A. (see Note 5.2).

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.

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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.

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 2022 and 2021, the rates used to extrapolate the projections were between 2.0% and 3.0%.

These flows are discounted to calculate their present value at a pre-tax rate that includes the cost of capital of the business and the geographical zone where it is carried out. This calculation considers the current cost of money and the risk premiums used in general among analysts for the business and geographical zone.

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 2022 were between 7.4% and 11.1% (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.

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Energy purchase and sale prices: based on specifically developed internal projection models. The price of the planned “pool” is estimated by considering a number of determining factors, such as the different technology’ costs and productions and energy demand, among other items.

Regulatory measures: an important part of the Company’s business is regulated and subject to extensive standards, which could undergo revisions, either as a result of new laws or the amendment of existing laws, and therefore the projections include adequate application of the current standards, those that are currently being developed, and those expected to be effective during the projected period.

Installed capacity: in the estimating of the Group’s installed capacity, the existing facilities are taken into account, as well as the plans for both increasing capacity and capacity closure. The investment plan is constantly updated based on the evolution of the business, quality of service regulations determined by the regulator and changes in the business development strategy adopted by management. In the generation area, the investments necessary to maintain the installed capacity in adequate operating conditions are taken into account; in the distribution activity, 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 2022, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2021, were not significant and cash flows generated in 2022 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.

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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 consist of: i) the amount of the initial measurement of the lease liability; (ii) lease payments made until the commencement date less lease incentives received, (iii) initial direct costs incurred; and (iv) the estimate of decommissioning or restoration costs.

Subsequently, the right-of-use asset is measured at cost, adjusted by any remeasurement 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.

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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.

Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.

g.1) Financial assets other than derivatives

The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method (see Notes 3.i and 13) and non-current assets 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.

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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.

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.

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•

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 receivables 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

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 pending issuance 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 and, accordingly, in the impairment of receivables.

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.

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In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 23, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and floating interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that debt issued at floating interest rate, i.e., each coupon is established at the beginning of each period based on the benchmark interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.

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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”.

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.

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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.

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.

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.

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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 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.

•

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 23.3.

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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 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 a 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”.

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.

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.

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The assets or disposal groups classified as held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.

Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.

Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution, less any depreciation, amortization or revaluation that would have been recognized had they had not been 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.

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.

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.

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Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.

A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.

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”.

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.

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.

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Income taxes

Income tax expense for the period is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the period, after deductions allowed have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the carrying amount and tax basis of assets and liabilities generate deferred tax assets and liabilities, which are calculated using the tax rates expected to 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.

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.

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The following are the criteria for revenue recognition by type of good or service provided by the Group:

•

Electricity supply (sale and transportation): corresponds to a single performance obligation that transfers to the customer a number of different goods/services that are substantially the same and that have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits provided by the Company, it is considered a performance obligation met over time. In these cases, the Group applies an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

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

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

These revenues include an estimate of the service provided and not invoiced, through the reporting date of the financial statements (see Notes 2.3 and 28 and Appendix 2.2).

•

Gas sale and transport: revenue is recognized over time based on the actual physical deliveries of gas in the consumption period, at the prices established in the respective contracts.

•

Other Services: mainly the provision of supplementary services to the electricity business, construction of works and engineering and consulting services. Customers control committed assets as they are created or improved. Therefore, the Company recognizes this revenue over time based on the progress, measuring progress through output methods (percentage of completion through the present date, milestones reached, etc.), or costs incurred (resources consumed, hours of labor spent, etc.), as appropriate in each case.

•

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

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or jointly to two or more transactions, when these are linked to contracts with customers that are negotiated with a single business purpose and the goods and services committed represent a single performance obligation and their selling prices are not independent.

The Group determines the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable, to reflect the effects of the time value of money. However, the Group applies the practical expedient provided by IFRS 15, and will not adjust the value of the consideration committed for the purpose of a significant financing component, if it expects, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.

The Group excludes the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue amount. The Group only records as revenue the payment or commission to which it expects to be entitled.

Because the Group mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the disclosure practical expedient provided in IFRS 15, through which it is not required to disclose the aggregate

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amount of the transaction price allocated to the performance obligations not met (or not met partially) at the end of the reporting period.

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

As of December 31, 2022, and 2021, 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.

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.

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.

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Share issuance costs

Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in equity as a deduction from “Share premiums,” net of any applicable taxes.

If the share premium account has a zero balance or if the costs described exceed the balance, they are recognized in “Other reserves”. Subsequently, these costs must be deducted from paid-in capital, and this deduction must be approved at the closest 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 conditions change and the transaction is no longer expected to occur.

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

Regulatory Framework

The Chilean electricity sector is regulated by the General Law of Electricity Services (Ley General de Servicios Eléctricos), contained in Decree 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”) its subsequent amendments and its corresponding Regulations, contained in Supreme Decree 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 an Expert Panel, 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 Domestic Transmission segment and prohibits Domestic 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 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: Domestic 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. This process determines the Annual Value of Transmission, composed of efficient operating and maintenance costs and the annual value of investment, determined according to a discount rate (7% minimum and 10% maximum, after taxes) set by the authority and the economic useful lives of the facilities.

The planning of the National, Zonal and Development Pole Transmission systems relates 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 Expert Panel.

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 (customers 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 performed 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.

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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Regulatory matters

2019 – 2022 Laws

(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 beginning on January 1, 2021, based on the same date (adjusted PEC). The billing differences due to the application of this mechanism lead to an account receivable in favor of the generators with a limit of US$1,350 million. The balance must be recovered by December 31, 2027. The technical provisions of this mechanism are established in the National Energy Commission’s Exempt Resolution No. 72/2020 and its amendments. It should be noted that the fund limit was reached in January 2022.

(ii)

Law No. 21,472 – Creates a price stabilization fund and establishes a new temporary electricity price stabilization mechanism for customers subject to price regulation

On August 2, 2022, the Ministry of Energy published Law No. 21,472. This law establishes a Temporary Customer Protection Mechanism (MPC) that will stabilize energy prices in the National Electric System and medium-sized systems in addition to those established by Law No. 21,185, for regulated customers under the General Law of Electric Services. The purpose of the MPC is to pay for the differences that may arise between the billing of the distribution companies to end customers and the amount payable to generation companies. The resources available for the MPC may not exceed US$1,800 million. This mechanism will be extended until the amount contemplated by the law is used in full. From 2023 onwards, the National Energy Commission must project the payment of the Remaining Balance every six months up to December 31, 2032 (but not later). On March 14, 2023, Exempt Resolution No. 86 was published, establishing provisions, procedures, deadlines, and conditions for the proper application of Law.

(iii)

Law No. 21,194 - Reduces the Profitability of Distribution Companies and Modifies the Electricity Distribution rate process

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 tariff setting process. The Distribution Short Law eliminates prior methodology that involved weighing the results of the VAD study performed by the CNE (two-thirds) and 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 6-8% real annual after-tax discount rate to be calculated every four years. 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. Additionally, distribution companies must have an exclusive line of business as of January 2021.

(iv)

Law No. 21,505 on Promotion of Energy Storage and Electromobility

On November 21, 2022, Law No. 21,505 was published, which encourages the storage of electric power through remuneration for energy, power sufficiency and complementary services to energy storage systems; as well as electromobility, through a temporary price reduction of the registration certificate for electric vehicles. This law allows for new electromobility business models and the option to charge electric vehicles batteries through the provision of services to the grid. In addition, it includes projects related to generation and consumption infrastructure for renewable energy projects, plus storage in order to remove energy from and inject surpluses into the electric system.

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(v)

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 amendments, the distribution companies acting as public service concessions companies and operating in the National Electricity System must be constituted exclusively as distribution companies and may only perform economic activities aimed at providing public distribution services, in accordance with the requirements established by law and current regulations. The requirements contained in such resolution have been applicable since January 1, 2021. Notwithstanding the above, those operations that by nature could not be performed prior to such date had to be reported and explained to the CNE, along with a planning schedule and compliance periods for the respective requirements, which under no circumstances could extend beyond January 1, 2022.

(vi)

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 respective Department of Municipal Works.

It also establishes that the Ministry of Energy will regulate the interoperability of the electric vehicle charging system. On February 25, 2022, Supreme Decree No. 12 ratified the regulations establishing the interoperability of electric vehicle charging systems, which was sent to the Comptroller General's Office of the Republic on May 13, 2022. This decree has not yet been reviewed by the Comptroller General's Office of the Republic. It will go into effect once it has been published in the Official Gazette.

This plan was created based on Article 1 of the Energy Efficiency Law, which indicates that, every five years, the Ministry of Energy must prepare a National Energy Efficiency Plan that includes the following matters, at a minimum: residential energy efficiency; minimum standards and device labels; energy efficiency in construction and transport; energy efficiency and smart cities; energy efficiency in production sectors; and education and training on energy efficiency. Moreover, short-, medium-, and long-term goals must be established, as well as the necessary plans, programs, and actions to achieve these goals.

On March 4, 2022, the National Energy Efficiency Plan was ratified, but was later withdrawn by the Ministry of Energy.

On September 13, 2022, the Ministry of Energy published Decree No. 28 corresponding to the Regulations on Energy Management of consumers with energy management capacity and of public entities, as referred to by articles 2 and 5 of Law No. 21,305.

(vii)

Law No. 21,249 – Exceptional provision of the measures indicated for end users of water and sanitation, electricity, and gas services.

On August 8, 2020, Law No. 21,249 the Law on Utility Services (Ley de Servicios Básicos), was passed, this law considers extraordinary measures to support the most vulnerable customers. 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.

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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. Additionally, the number of installments was modified to a maximum of 48, instead of the previously defined maximum of 36 installments.

(viii)Law No. 21,423 – Regulates the proration and payment of water and electricity service debts incurred during the Covid-19 pandemic and establishes subsidies for vulnerable customers

On February 11, 2022, the law was published to regulate the proration and payment of water and electricity service debts incurred during the Covid-19 pandemic and establish subsidies for vulnerable customers, in order to address electricity debts generated between March 18, 2020, and December 31, 2021, on past-due bills.

The law establishes that the debts of customers with an average consumption of less than 250 kWh per month during 2021 will be automatically divided into 48 monthly installments. These installments may not exceed 15% of the average monthly bill. These customers will receive a subsidy from the Chilean government equivalent to this same value (15% of the average monthly bill). Therefore, in practice, users will only have to pay their monthly electricity consumption and stay up-to-date with payments.

In the case of customers with an average monthly consumption of over 250 kWh per month during 2021, the term was extended until June 30, 2022, for them to approach their electricity distribution companies to prorate the total debt in up to 48 installments, with no fines or interest.

On June 23, 2022, the Ministry of Energy published the procedure for the payment of subsidies established in Law No. 21,423, which regulates the proration and payment of water and electricity services generated during COVID-19 and establishes subsidies for vulnerable customers.

On September 30, 2022, the Superintendency of Electricity and Fuel issued Circular No. 140129 to modify the instructions provided by SEC Circular No. 119977, regarding the termination of the customer subsidy benefit. Among these amendments is the reincorporation of the customer subsidy benefit once the customer has paid off its debt with the respective concessionaire company.

(ix)

Law No. 21,455 – Framework for Climate Change

On May 30, 2022, the Ministry of Energy published Law No. 21,455 Framework for Climate Change, which establishes the country's carbon neutrality by 2050 at the latest, and creates the Long-Term Climate Strategy, an instrument recognized in the Paris Agreement, and which will define the national greenhouse gas emissions budget by 2030 and 2050, and sectoral greenhouse gas emissions budget by 2030.

(x)

Electricity Portability Bill

On September 9, 2020, a bill was submitted to the Chilean Chamber of Deputies that would modify the Electricity Law in order to establish the right to electricity portability and to introduce the figure of energy trader. This would uncouple all services that may be offered to the distribution company’s final customers, so that the distribution company would 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 energy trader. The main point of discussion of this bill is related to the gradual market liberalization and could affect existing regulated contracts.

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(xi)

Non-Conventional Renewable Energies Bill

On November 23, 2021, a bill was submitted to the Chilean Chamber of Deputies to establish the participation of renewable energies in the Chilean energy matrix through fostering small-scale distributed generation, especially in net billing projects, the creation of a renewable energy traceability system and an increased share of NCREs in the National Electric System. This bill establishes an annual production goal of 60% renewable energy by 2030, for contracts signed after January 1, 2023; and 40% per hour block for contracts signed after July 1, 2023. The bill is currently under legislative discussion.

(xii)

Green Hydrogen Bill

On November 23, 2021, a bill was submitted to the Chilean Chamber of Deputies to establish the production and use of green hydrogen in the country, establishing hydrogen blends in natural gas networks and allowing Empresa Nacional del Petróleo (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 - 2022

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 beginning on 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 corresponding to the regulation that establishes the provisions applicable to the coordination and operation of the National Electric System, as well as other matters necessary for the proper exercise of the functions of the Independent Coordinator of the National Electric System, and the rights and duties of the entities subject to such coordination.

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 Sufficiency 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. In addition, a calculation methodology is established to recognize sufficiency power for hydroelectric power plants with storage capacity.

New Regulations on Sufficiency Capacity: Within the first six months of 2023, the Ministry of Energy plans to resubmit new electric power regulations to the General Comptroller of the Republic. These regulations will introduce significant modifications to the electric capacity market. They will outline an efficiency factor that affects high variable cost generation units. Hybrid and pure storage systems will have sufficient power recognition, and the methodology for sufficient power recognition is modified by eliminating technological discretion. In addition, companies will be able to choose to stay under the current methodology or to migrate to the proposed methodology immediately. Finally, the regulations will modify the capacity market demand.

Draft Regulation on Distribution Tolls: On November 5, 2021, the Ministry of Energy issued the draft regulation on distribution tolls, which establishes the procedure for setting and applying distribution tolls.

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Preventive Decree on Rationing:

●

On August 18, 2021, the Ministry of Energy issued Supreme Decree No. 51/202 to implement preventive measures of electricity rationing until June 30, 2022, introducing actions for the generation, transmission, and distribution segments. It allows the coordinator to establish water reserves and orders conservative criteria when using water for the programming of operations.

●

On January 12, 2022, the Ministry of Energy issued Supreme Decree No. 1/2022, which extends the preventive decree on rationing until September 30, 2022, and designates the National Electric Coordinator to determine a security diesel for the purpose of remunerating the additional availability of plants powered by this fuel. The fixed costs of the provision will be remunerated proportionally to the withdrawal made by the generation companies.

●

On March 22, 2022, the Ministry of Energy issued Supreme Decree No. 29/2022 to define a Water Reserve of 650 GWh.

●

On March 22, 2022, the Ministry of Energy issued Supreme Decree No. 66/2022 to reduce the Water Reserve to 205 GWh.

●

On August 31, 2022, the Ministry of Energy issued Supreme Decree No. 74/2022 to extend the preventative decree on rationing to March 31, 2023 and reduce the Water Reserve to 66 GWh.

Modification of the GNL Technical Standards: On October 13, 2021, the CNE issued Exempt Resolution No. 411, which approves the modification of the technical standards for operations programming in units that use regasified liquefied natural gas (GNL). Such technical standard assigns responsibility to 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.

Regulation for small-scale means of generation: On October 8, 2020, the Ministry of Energy published Decree No. 88 corresponding to the Regulation for small-scale means of generation, which was amended on March 16, 2022, by Decree No. 27.

Modification of the Regulations of the General Law of Electric Services: On June 14, 2021, the Ministry of Energy published Decree No. 68, which amends the Regulations of the General Electric Services Law approved by Decree No. 327/1997, regarding electric concessions.

Emissions Standard: In Chile, there is an emissions standard that governs thermal power plants (D.S. No. 13/2011 of the Ministry of the Environment) and establishes a limit on airborne particulate matter (PM), nitrogen oxides (NOx), sulfur dioxide (SO2) and mercury (Hg), in order to prevent pollution and protect human health and the environment. The emissions standard is enforced throughout national territory and applicable to electrical generation units, composed of boilers or turbines, with a thermal power of 50 MWt or greater. Compliance with this standard is overseen by the Superintendency of the Environment. The owners of emissions sources must submit an ongoing emissions monitoring report to the Superintendency once a quarter, during a calendar year.

Tariff Revisions and Supply Processes

In the electricity market there is a continuous revision of tariffs and supply processes that affect those volumes that were realized in previous periods on the dates of publication of these revisions. Therefore, the following discloses those rules that are currently applicable to the Group.

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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 retrospectively beginning on September 28, 2018.

The final customer rates that have governed during 2021 are determined according to the following decrees and resolutions:


Decree No.	Date	Matter	Effective from
11T/2016	08-24-2017	Establishes the rate formulas applicable to electricity supply subject to regulated prices.	11-04-2016
2T/2018	10-05-2019	Establishes the rate formulas applicable to electricity supply subject to regulated prices.	11-01-2016 to 11-31-2020
5T/2018	09-28-2018	Establishes the rate formulas applicable to electricity supply subject to regulated prices.	09-28-2018
Ordinary Comm. SEC N°15699/2019	07-26-2019	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.	09-28-2018 to 11-03-2020

Price Decrees:

Average Prices in the National Electric System


Decree No.	Date	Matter	Effective from
20T/2018	05-06-2019	Establishes prices and surcharges for application of the Residential Tariff Equity Mechanism.	01-01-2019
7T/2019	10-05-2019	Establishes prices and surcharges for application of the Residential Tariff Equity Mechanism.	07-01-2019
Ley No.21,185	11-02-2019	Creates a transitory mechanism to stabilize electricity prices for customers subject to rate regulation. Article 5 of this Law repeals Decree 7T/2019, and extends the effective term of Decree No. 20T/2018.	Publication of the corresponding node price decree.
6T/2020	11-02-2019	Establishes prices and adjustment factor for application of Law No. 21,185. It had no effect on the final regulated customer rate.	01-01-2020
16T/2020	03-02-2021	Establishes prices and adjustment factor for application of Law No. 21,185. It had no effect on the final regulated customer rate.	07-01-2020
19T/2020	05-20-2021	Establishes prices and adjustment factor for application of Law No. 21,185. It had no effect on the final regulated customer rate.	01-01-2021
8T/2021	07-12-2021	Establishes prices and adjustment factor for application of Law No. 21,185.	07-01-2021
9T/2022	06-17-2022	Establishes prices and adjustment factor for application of Law No. 21,185.	01-01-2022
475	06-28-2022	Exempt Resolution of the National Energy Commission that approves the Definitive Technical Report for setting the Average Node Prices of the National Electric System and the adjustment factor (Repealed by the following 586).	N/A
836	11-16-2022	Establishes prices and adjustment factor for application of Law No. 21,185.	07-01-2022
886	12-12-2022	Establishes prices and adjustment factor for application of Law No. 21,185.	11-01-2022

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Short term Node Prices for electricity supply


Decree No.	Date	Matter	Effective from
12T/2020	12-03-2020	Establishes the regulated prices for electricity supply.	10-01-2020
3T/2021	03-22-2021	Establishes the regulated prices for electricity supply.	04-01-2021
9T/2021	02-26-2022	Establishes the regulated prices for electricity supply.	10-01-2021
3T/2022	07-07-2022	Establishes the regulated prices for electricity supply.	04-01-2022
11T/2022	11-09-2022	Establishes the regulated prices for electricity supply.	10-01-2022

Stabilized Price for small scale means of generation


Decree No.	Date	Matter	Effective from
5T/2021	02-22-2022	Establishes stabilized prices.	02-22-2022
14T/2021	02-26-2022	Establishes stabilized prices.	02-26-2022
8T/2022	10-13-2022	Establishes stabilized prices.	10-13-2022

ii)

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


Decree No.	Date	Matter	Effective from
495	12-29-2020	Establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services	01-01-2021
192	06-17-2021	Establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services	07-01-2021
551	12-15-2021	Establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services	01-10-2022
442	06-20-2022	Establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services	07-01-2022
898	12-21-2022	Establishes transmission charges as referred to in articles 115 and 116 of the General Law on Electric Services	01-01-2023

iii)

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 beginning on July 1, 2019, and establishes the cut-off and restitution factor applicable for the period between July 1, 2019, and December 31, 2019.

iv)

Exempt Resolution of the National Energy Commission that establishes and communicates the Public Service Charge.


Decree No.	Date	Matter	Effective from
434	11-18-2020	Establishes and communicates the Public Service Charge	12-01-2020
486	11-18-2021	Establishes and communicates the Public Service Charge	12-01-2021
841	11-18-2022	Establishes and communicates the Public Service Charge	12-01-2022

c.2 Distribution Price Setting 2020-2024

On December 23, 2022, the National Energy Commission approved the Technical Report on the Calculation of Components of Distribution Value Added for the four years from 2020 - November 2024, through Exempt Resolution No. 908.

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

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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 such 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.

c.4 Supply Bids (Regulated Power Purchase Agreements, - Regulated PPAs)

Under the new bids law, five processes have been performed: Supply Bid 2015/01, Supply Bid 2015/02, Supply Bid 2017/01, Supply Bid 2021/01, and Supply Bid 2022/01. Supply Bid 2022/01 considers the supply period between 2027 and 2041 and a volume of 5,250 GWh/year. The process ended on August 8, 2022, with the awarding of only 15% of the energy requested at an average price of US$37.88 per MWh. Enel Generación was not awarded any supply blocks in the Supply Bid bidding process. The energy that was not awarded in 2022 must be included in a future bidding process conducted by the authority.

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5. NON-CURRENT ASSETS HELD FOR SALE

The composition and movements in non-current assets held for sale for the year ended December 31, 2022 is as follows:


ASSETS	01-01-2022	Reclassification to / from current and non-current assets	Impairment	Dispositions and changes in the scope of consolidation	Other movements	12-31-2022

Current assets
Cash and cash equivalents	-	119,634	-	(122,866)	3,232	-
Other current non-financial assets	-	633,263	-	(1,611,053)	977,790	-
Trade and other receivables, current	-	40,681,609	-	(55,141,056)	14,459,447	-
Inventories	-	3,022	-	(4,311)	1,289	-
Current tax assets	-	15,212,532	-	(42,905)	(15,169,627)	-
Total current assets	-	56,650,060	-	(56,922,191)	272,131	-

Non-current assets
Trade and other non-current receivables	-	535,508	-	(476,595)	(58,913)	-
Intangible assets other than goodwill	-	18,585,149	-	(19,296,314)	711,165	-
Goodwill	-	37,912,005	-	(37,912,005)	-	-
Property, plant, and equipment	-	338,640,267	(2,286,438)	(316,882,166)	9,129,970	28,601,633
Right-of-use assets	-	1,130,769	-	(1,164,229)	33,460	-
Total non-current assets	-	396,803,698	(2,286,438)	(375,731,309)	9,815,682	28,601,633

Total assets	-	453,453,758	(2,286,438)	(432,653,500)	10,087,813	28,601,633


Liabilities	01-01-2022	Reclassification to / from current and non-current assets	Impairment	Dispositions and changes in the scope of consolidation	Other movements	12-31-2022

Current liabilities
Other current financial liabilities	-	304,170	-	(199,032)	(105,138)	-
Trade and other payables, current	-	4,557,459	-	(5,058,696)	501,237	-
Current accounts payable to related parties	-	1,352,928	-	(1,222,022)	(130,906)	-
Other current provisions	-	35,777	-	-	(35,777)	-
Current tax liabilities		-	-	(10,494,732)	10,494,732	-
Other current non-financial liabilities	-	3,546,211	-	(2,617,809)	(928,402)	-
Total current liabilities	-	9,796,545	-	(19,592,291)	9,795,746	-

Non-current liabilities
Other non-current financial liabilities	-	1,001,937	-	(1,146,536)	144,599	-
Other long-term provisions	-	987,536	-	(1,487,899)	500,363	-
Deferred tax liabilities	-	16,522,780	-	(4,676,249)	(11,846,531)	-
Non-current provisions for employee benefits	-	1,440,044	-	(1,208,970)	(231,074)	-
Total non-current liabilities	-	19,952,297	-	(8,519,654)	(11,432,643)	-

Total liabilities	-	29,748,842	-	(28,111,945)	(1,636,897)	-

Net assets and liabilities value	-	423,704,916	(2,286,438)	(404,541,555)	11,724,710	28,601,633

5.1 Sale of Corporate Building

On November 4, 2022, our subsidiary Enel Generación Chile received a purchase offer for the Santa Rosa Complex, which is located in Santiago and comprises four properties:

-76 Santa Rosa Avenue, where the Company’s Headquarters are currently located.

-65 San Isidro.

-634 Marcoleta.

-638 Marcoleta.

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Considering the progress of negotiations, as of the closing date of fiscal year 2022, the Company reclassified the Santa Rosa Complex assets as held for sale; measuring the former at the lower between their carrying value and their fair value, in conformity with the provisions of IFRS 5 "Non-Current Assets Held for Sale and Discontinued Operations" and the accounting criteria described in Note 3.k.

As of December 31, 2022, the carrying value of the Santa Rosa Complex assets amounts to ThCh$28,601,633. This includes the value of certain movable assets belonging to Enel Chile, Enel Generación Chile and Enel Distribución Chile, that should also be sold to the offeror. The above implied the recognition of an impairment loss for ThCh$2,286,438 in the consolidated financial statements of Enel Chile S.A. (see Note 31.b).

For additional information see Note 41.iv.

5.2 Enel Transmisión Sale

On July 28, 2022, the “Stock Purchase Agreement” was signed by Enel Chile, who agreed to sell to Sociedad Transmisora Metropolitana SpA., all shares it owned that wereissued by Enel Transmisión Chile S.A. (the “Sale”), equivalent to 99.09% of such company. Sociedad Transmisora Metropolitana SpA. is company wholly owned by Inversiones Grupo Saesa Limitada.

The execution of the Sale and subsequent transfer of shares owned by Enel Chile that were issued by Enel Transmisión Chile S.A. has been subject to certain regular conditions precedent applicable to these types of transactions, including the approval by the National Economic Attorney General's Office in accordance with D.L. 211 of 1973. According to Law No. 18,045 on the Securities Market, the Sale was carried out by the buyer making a Takeover Bid for all of the shares of Enel Transmisión Chile S.A.

The Sale price was US$1,345 million for 99.09% of the capital of Enel Transmisión Chile S.A. held by Enel Chile, which may vary upon the application of the purchase price adjustments stipulated in the Sale.

Enel Transmisión Chile S.A. operates and owns 683 kilometers of transmission lines, of which 183 kilometers correspond to the Domestic Transmission System, 499 kilometers to the Zone D Transmission System, 0.1 kilometers to the Zone C Transmission System, and 0.2 kilometers to a dedicated transmission line. It also operates 57 of its own substations and owns and operates assets installed in 3 substations owned by third parties.

Considering the sale process and the provisions of IFRS 5: “Non-Current Assets Held for Sale and Discontinued Operations”, and following the accounting criterion established in note 3.k, the assets and liabilities of the subsidiary Enel Transmisión Chile S.A. were classified as held for sale.

On December 9, 2022, the announcement of the successful results of the Takeover Bid for all the shares of Enel Transmisión Chile S.A was published. Consequently, after the related obligations were fulfilled, the change of control of Enel Transmisión Chile S.A was confirmed, and it ceased to be a subsidiary of Enel Chile S.A. and became controlled by Sociedad Transmisora Metropolitana SpA. The gain obtained from this sale amounted to ThCh$981,856,639 (see Note 33).

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6. CASH AND CASH EQUIVALENTS

The detail of cash and cash equivalents as of December 31, 2022, and 2021 is as follows:


	As of December 31,
	2022	2021
Cash and Cash Equivalents	ThCh$	ThCh$
Cash balances	25,742	37,852
Bank balances	245,199,924	282,625,181
Time deposits	454,776,178	28,923
Other fixed-income instruments	175,211,855	27,283,184
Total	875,213,699	309,975,140

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.

The detail, by type of currency, of the above balance is as follows:


	As of December 31,
	2022	2021
Currency	ThCh$	ThCh$
Chilean peso	745,956,809	245,516,611
UF	32,892	—
Argentine peso	242,734	195,683
Euro	176,894	196,498
U.S. dollar	128,804,370	64,066,348
Total	875,213,699	309,975,140

For further detail of the Statement of Cash Flows see below:

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, 2022, 2021 and 2020:


	2022	2021	2020
Other payments from operating activities	ThCh$	ThCh$	ThCh$
VAT tax debit	(74,401,438)	(80,921,378)	(135,096,018)
Tax on emissions	(24,277,529)	(16,465,950)	(23,800,541)
Other	(9,376,834)	(11,018,067)	(11,394,034)
Total	(108,055,801)	(108,405,395)	(170,290,593)

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The following table presents the detail of "Cash flows from loss of control of subsidiaries or other businesses" in the Statement of Cash Flows as of December 31, 2022, 2021 and 2020:


	2022	2021	2020
	ThCh$	ThCh$	ThCh$
Amounts received for the sale of Enel X Way Chile S.p.A.	11,358,338	—	—
Amounts received for the sale of Enel Transmisión Chile S.A.	1,228,616,013	—	—
Amounts received for the sale of Enel X AMPCI Ebus Chile SpA	2,001,407	—	—
Amounts of cash and cash equivalents of Enel Transmisión Chile S.A., which is not a part of the Group	(7,481,882)	—	—
Total	1,234,493,876	—	—

In 2022, "Collections from the reimbursement of advance payments and loans granted to third parties" include cash flows received for payment of Enel Transmisión Chile’s debt to Enel Chile, made on December 9, 2022. The sale of Enel Transmisión Chile S.A was completed on the same date (See Notes 2.4.1.v. and 5.2).

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Reconciliation of liabilities arising from financing activities for the years ended December 31, 2022, 2021 and 2020:


		Financing Cash Flows				Movements that do not represent cash flows
Liabilities arising from financing activities	Balance as of 01-01-2022	From	Used	Interest paid	Total	Affiliate sales	Movements in fair value	Foreign exchange differences	Financial costs (1)	New leases	Other Movements	Balance as of 12-31-2022
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Short-term loans	881,659,765	1,050,888,015	(1,711,034,741)	(182,171,676)	(842,318,402)	—	—	53,561,223	192,928,894	—	199,101,144	484,932,624
Long-term loans	3,241,250,805	263,892,100	(37,020,850)	—	226,871,250	—	(792,940)	58,670,485	4,081,277	—	(199,180,908)	3,330,899,969
Lease liabilities (Note 20)	159,662,077	—	(6,613,399)	(4,790,146)	(11,403,545)	(1,450,648)	—	20,751,687	6,810,965	61,996,854	(681,835)	235,685,555
Assets held to cover liabilities arising from financing activities	(36,094,475)	37,803,988	—	—	37,803,988	—	(23,814,586)	(34,664,273)	(21,188)	—	—	(56,790,534)
Total	4,246,478,172	1,352,584,103	(1,754,668,990)	(186,961,822)	(589,046,709)	(1,450,648)	(24,607,526)	98,319,122	203,799,948	61,996,854	(761,599)	3,994,727,614


		Financing Cash Flows				Movements that do not represent cash flows
Liabilities arising from financing activities	Balance as of 01-01-2021	From	Used	Interest paid	Total	Affiliate sales	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$	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				Movements that do not represent cash flows
Liabilities arising from financing activities	Balance as of 01-01-2020	From	Used	Interest paid	Total	Affiliate sales	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$	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

(1) It relates to accrual of interest

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7. OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2022 and 2021 is as follows:


	Current		Non-current
	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Other Financial Assets	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value through other comprehensive income	127,854	127,854	2,326,509	2,358,143
Financial assets measured at amortized cost	156,773	118,547	—	—
Hedging derivatives	2,230,787	3,584,937	57,480,749	37,020,922
Non-Hedging derivatives	1,014,802	210,077	20,382	—
Total	3,530,216	4,041,415	59,827,640	39,379,065

8. OTHER NON-FINANCIAL ASSETS AND LIABILITIES

Other non-financial assets

The detail of other non-financial assets as of December 31, 2022 and 2021 is as follows:


	Current		Non-Current
Other non-financial assets	12-31-2022	12-31-2021	12-31-2022	12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Tax Credit and Other Taxes	154,017,802	30,879,791	53,771,356	67,966,488
Prepaid expenses	36,659,062	34,623,121	—	—
Guarantee deposit	—	—	125,724	128,724
Water rights credits	—	—	10,113,848	9,298,704
Spare parts with a consumption schedule of more than 12 months	—	—	7,289,051	7,392,047
Other	1,963,488	1,323,085	6,976,362	4,830,685
Total	192,640,352	66,825,997	78,276,341	89,616,648

Other non-financial liabilities

The detail of other non-financial liabilities as of December 31, 2022 and 2021 is as follows:


	Current		Non-Current
Other non-financial liabilities	12-31-2022	12-31-2021	12-31-2022	12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Credit and Other Taxes	25,584,528	12,741,963	—	—
Reimbursable financial contributions	—	—	1,088,647	1,135,285
Deferred revenue from splices	1,050,552	1,149,415	—	—
Deferred revenue from transfer of networks	225,319	696,675	—	—
Deferred revenue from lighting services	565,680	564,465	—	—
Deferred revenue from other services	4,863,505	1,260,078	—	—
Other	1,032,018	641,244	—	—
Total	33,321,602	17,053,840	1,088,647	1,135,285

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9. TRADE AND OTHER RECEIVABLES

The detail of trade and other receivables as of December 31, 2022 and 2021 is as follows:


	Current		Non-current
Trade and Other Receivables, Gross	12-31-2022	12-31-2021	12-31-2022	12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, gross	1,586,535,818	767,900,561	703,330,626	515,856,801
Trade receivables, gross	1,437,903,199	694,597,739	529,584,066	442,941,968
Accounts receivable from finance leases, gross	21,037,785	10,735,484	170,338,861	69,873,385
Other receivables, gross	127,594,834	62,567,338	3,407,699	3,041,448

	Current		Non-current
Trade and Other Receivables, Net	12-31-2022	12-31-2021	12-31-2022	12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, net	1,509,513,355	688,185,127	691,147,645	515,786,340
Trade receivables, net	1,372,573,201	628,681,800	518,816,944	442,871,507
Accounts receivable from finance leases, net	20,775,688	8,365,583	168,923,002	69,873,385
Other receivables, net (1)	116,164,466	51,137,744	3,407,699	3,041,448

(1)

The detail of other accounts receivable is as follows:


	Current		Non-current
Other receivables, net (1)	12-31-2022	12-31-2021	12-31-2022	12-31-2021
	ThCh$	ThCh$	ThCh$	ThCh$
Accounts receivable from employees	12,929,933	11,808,014	2,779,599	2,522,560
Advances to suppliers and creditors	64,664,538	33,079,980	511,771	514,119
Sale of investment in Sociedad de Inversiones K Cuatro SpA (i)	29,681,532	—	—	—
Others	8,888,463	6,249,750	116,329	4,769
Total	116,164,466	51,137,744	3,407,699	3,041,448

i.See Note 13.3.b.

a.1) Increase in trade and other receivables:

a.1.i) As of December 31, 2022, short-term trade receivables increased by ThCh$743,305,460 compared with December 2021. This variation is mainly due to the following factors: (i) an increase of ThCh$266,843,088 due to the effects of Law No. 21,472, (whose implementation is still pending); (ii) an increase of ThCh$129,508,002 associated with pending billing re-settlements to Electricity Distribution companies; and (iii) an increase of ThCh$200,889,730 due to higher sales and average prices expressed in Chilean Pesos in the Generation and Distribution and Networks segments.

General background:

During the month of January 2022, the limit of US$1,350 million was reached for accounts receivable from regulated customers, as established by Law No. 21,185, which created a Temporary Price Stabilization Mechanism for that segment of customers (see Note 9.a.1.ii). This implied that the mechanism was no longer applied and, as a result, short-term accounts receivable from regulated customers have accumulated since February 2022, for the difference between the theoretical prices based on the conditions established in the contracts with the respective Electricity Distribution companies and the regulated rates currently applied to the end user’s bill.

On August 2, 2022, Law No. 21,472 was published, which created a price stabilization fund and established a new temporary price stabilization mechanism for regulated customers.

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Law No. 21,472 establishes a customer protection mechanism aimed at paying differences resulting between the prices of the respective regulated supply contracts and the stabilized price. These differences will be covered by a temporary fund of US$1,800 million through a new instrument known as a Payment Document, issued monthly by the General Treasury of the Republic to electricity generation companies, denominated in United States dollars, adjustable, transferable, with a maximum maturity date of December 2032 and state guarantee. It should be noted that all fund balances generated that are over US$1,350 million as indicated in Law No. 21,185, are recognized as part of the mechanism established in Law No. 21,472.

The fund will be financed through an additional fee charged to end users segmented by consumption level, where customers with a monthly consumption of less than 350 kWh will be exempt from such fee, as well as micro and small companies with monthly consumption up to 1,000 kWh. The fund will be managed by the General Treasury of the Republic, with fiscal contribution of US$20 million per year, effective until December 31, 2032.

The Exempt Resolution No. 86 that establish the technical provisions for implementation of Law No. 21,472 was published on March 14, 2023, that enable the settlement of accounts receivable associated with the implementation of this Law.

a.1.ii) On the one hand, long-term accounts receivable increased by ThCh$86,642,098 with respect to the close of 2021, and this increase is explained primarily by the following: (i) an increase of ThCh$133,652,713 in accounts receivable that the Group should transfer to end customers and then repay to the tariff stabilization fund (by application of Law 21,472); and (ii) a decrease of ThCh$60,431,732 related to new sales of accounts receivable associated with Law 21,185 (see section a.2.II in this same note), which are described as follows:

The law was published on November 2, 2019, by the Ministry of Energy, and creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation. Pursuant to 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 could not be higher than the adjusted PEC according to the Consumer Price Index beginning on January 1, 2021, based on the same date (adjusted PEC).

The differences to be 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 limit was reached in January 2022.

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 Law No. 21,185. 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.

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In addition, this resolution established that the payment of balances shall be performed using the US$ exchange rate observed on the sixth business day following publication of the Coordinator’s Balance Payment Chart, instead of the average US$ exchange rate during the billing month, as established up to that moment.

As a result of the abovementioned situations in paragraphs a.1.i) and a.1.ii) and after eliminating transactions between related companies, the accounting effects recorded by the Group are summarized as follows:

Classification as current in trade receivables in the amount of ThCh$266,843,088 as of December 31, 2022 (ThCh$0 as of December 31, 2021).

Classification as non-current in trade receivables in the amount of ThCh$500,707,110 as of December 31, 2022 (ThCh$415,664,120 as of December 31, 2021) and trade payables for the purchase of energy from suppliers in the amount of ThCh$308,013,985 (ThCh$174,373,938 as of December 31, 2021). See note 24.

Lower energy sales revenue of ThCh$6,706,741 as of December 31, 2022 (ThCh$12,245,142 as of December 31, 2021).

Lower energy purchase of ThCh$2,088,485 as of December 31, 2022 (ThCh$3,388,944 as of December 31, 2021).

Higher finance income of ThCh$7,455,121 as of December 31, 2022 (ThCh$4,802,376 and ThCh$15,328,268 as of December 31, 2021 and 2020). See note 34.

Higher finance costs of ThCh$2,235,708 as of December 31, 2022 (higher financial costs ThCh$2,409,504 and ThCh$4,518,268 as of December 31, 2021, and 2020). See note 34.

Net gain from foreign currency translation of ThCh$4,801,364 as of December 31, 2022 (corresponding to a gain of ThCh$28,572,166 and a loss of ThCh$25,260,383 of December 31, 2021, and 2020), for the dollarization of accounts receivable pending invoicing. See note 34.

The aforementioned trade and non-trade concepts, while included in the model to determine impairment losses (see Note 3.g.3), have no greater impact at the close of December 31, 2022 and 2021 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 from customers

Distribution Segment

•

On December 28, 2020, Enel Distribución Chile and the 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, 2022, collection rights were assigned for ThCh$265,929,804 (ThCh$324,134,944 as of December 31, 2021). 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 costs of ThCh$9,535,442 (ThCh$5,872,765 as of December 31, 2021).

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.

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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 the “Commitment and Engagement Letter” dated December 31, 2020, which is subject to foreign governing law. The “Commitment and Engagement Letter” was entered into 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 performed 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” 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 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 Generación Chile and Enel Green Power Chile may decide to effect.

Detail of sales and disposals:

-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.

-On March 4, 2022, Enel Generación Chile and Enel Green Power Chile sold and assigned Balances to Chile Electricity PEC SpA for a nominal value of approximately US$17.1 million (ThCh$13,722,935) and US$1.67 million (ThCh$1,335,345), respectively.

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-On July 14, 2022, Enel Generación Chile and Enel Green Power Chile sold and assigned Balances to Chile Electricity PEC SpA for a nominal value of approximately US$42.2 million (ThCh$42,652,823) and US$4.36 million (ThCh$2,720,629), respectively.

As a result of the sale and assignment of Balances as of December 31, 2022, Enel Generación Chile and Enel Green Power Chile recognized finance costs of ThCh$12,623,444 and ThCh$1,033,564, respectively (as of December 31, 2021, ThCh$39,919,437 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.

In addition, in 2022, short-term accounts receivable were sold, which are not related to PEC balances. Enel Generación Chile and Enel Green Power Chile sold and assigned accounts receivable for a nominal amount of ThCh$955,342,410 and ThCh$21,395,481, respectively (ThCh$572,123,608 and $0, respectively, as of December 31, 2021), recognizing a financial cost of ThCh$8,226,102 and ThCh$208,364 (ThCh$682,389 and $0, respectively, as of December 31, 2021).

For the year ended December 31, 2022, the effects of the aforementioned finance costs on the Distribution and Generation segments totaled ThCh$31,626,916 (ThCh$49,933,286 and ThCh$533,615 as of December 31, 2021 and 2020) (see Note 34).

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, 2022 and 2021:

Compañía General de Electricidad S.A.

For amounts, terms and conditions related to accounts receivable due from related parties, refer to Note 10.1.

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Financial lease receivables

As of December 31, 2022 and 2021, future collections on financial lease receivables are the following:


	12-31-2022			12-31-2021
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	27,550,419	6,512,634	21,037,785	12,574,641	1,839,157	10,735,484
From one to two years	17,871,553	3,383,443	14,488,110	11,492,554	1,833,885	9,658,669
From two to three years	16,507,313	2,477,022	14,030,291	11,377,461	1,628,175	9,749,286
From three to four years	14,941,493	1,865,003	13,076,490	11,308,946	1,056,999	10,251,947
From four to five years	12,640,235	1,314,700	11,325,535	9,494,846	602,282	8,892,564
More than five years	135,444,145	18,025,710	117,418,435	31,618,242	297,323	31,320,919
Total	224,955,158	33,578,512	191,376,646	87,866,690	7,257,821	80,608,869

The amounts correspond to the performance 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, 2022, financial income from lease debtors reached ThCh$1,782,747 (ThCh$1,829,631 and ThCh$1,562,017 as of December 31, 2021 and 2020, respectively).

As of December 31, 2022 and 2021, 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,
	2022	2021
Trade accounts receivables due and unpaid, but for which no impairment losses have been recorded	ThCh$	ThCh$
Less than three months	195,879,586	103,142,026
Between three and six months	52,964,326	22,902,308
Between six and twelve months	20,180,791	17,421,962
More than twelve months	54,261,319	51,177,749
Total	323,286,022	194,644,045

The movement of impairment loss of trade receivables, determined according to Note 3.g.3, is detailed as follows:

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		Current and
		Non-current
Trade accounts receivables due and unpaid, with impairment losses		ThCh$
Balance as of January 1, 2021		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 as of December 31, 2021		79,785,895
Increases (decreases) for the year (1)		22,025,354
Amounts written off		(10,915,012)
Increases (decreases) in foreign currency translation differences		(1,334)
Decreases to be classified as held for sale (2)		(1,689,459)
Balance as of December 31, 2022		89,205,444

(1)

During 2022, impairment losses on trade receivables amounted to ThCh$22,025,354, which represents an increase of 17.4% over the prior year (See note 31). This increase is due to the increase in accounts receivable from customers and, as a consequence, the expected credit loss.

(2)

See note 5.2.

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 22.5).

Additional Information:

Additional statistical information required by CMF Circular No. 715, dated February 3, 2012, (XBRL taxonomy). See Appendix 2.

Complementary information on trade receivables, see Appendix 2.1.

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10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES

Related party transactions are performed at current market conditions.

Transactions between companies comprising the Group have been eliminated in the consolidation process and are not disclosed in this Note.

As of the date of these consolidated financial statements, there are no allowances for doubtful accounts between related entities.

The controlling company of Enel Chile is the Italian company Enel S.p.A.

Enel Chile S.A. provides administrative services to its subsidiaries, through a centralized cash contract used to finance cash deficits or consolidate cash surpluses. These accounts may have a debtor or creditor balance and are prepayable, short-term accounts with a variable interest rate that represents market conditions. To reflect these market conditions, the interest rates are reviewed periodically through an update procedure approved by the Boards of Directors of the respective companies.

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10.1 Balances and transactions with related parties

The balances of accounts receivable and payable as of December 31, 2022 and 2021, are as follows:

Receivables from related parties


						Current		Non-current
Taxpayer ID No.	Company	Country	Relationship	Currency	Transaction Description	12-31-2022	12-31-2021	12-31-2022	12-31-2021
						ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	US$	Other Services	184,318	90,777	—	—
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	US$	IT Services	1,619,319	1,543,540	—	—
Foreign	Enel Generación Costanera S.A.	Argentina	Common Immediate Parent	US$	Engineering Services	187,436	184,990	—	—
Foreign	Enel Generación El Chocón S.A.	Argentina	Common Immediate Parent	US$	Engineering Services	14,390	14,203	-	-
Foreign	Enel Green Power Argentina	Argentina	Common Immediate Parent	US$	Other Services	322,890	320,138	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	CLP	Other Services	222,193	-	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	US$	Engineering Services	15,178	14,980	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	US$	Other Services	1,451,125	1,435,123	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Common Immediate Parent	US$	Other Services	67,658	31,841	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	IT Services	881,246	737,980	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	Other Services	158,018	1,533,188	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	US$	Other Services	188,236	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	Technical Services	389,126	486,802	—	—
77.157.779-2	Enel X AMPCI Ebus Chile SpA	Chile	Associated	US$	Management services	-	3,239	—	—
77.157.781-4	Enel X AMPCI L1 Holdings SpA	Chile	Associated	US$	Management services	-	3,239	—	—
77.157.783-0	Enel X AMPCI L1 SpA	Chile	Associated	US$	Management services	-	16,471	—	—
77.569.067-4	Enel X Way Chile SpA	Chile	Associated	CLP	Technical Services	267,241	-	—	—
77.569.067-4	Enel X Way Chile SpA	Chile	Associated	CLP	Other Services	974,759	-	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CLP	Technical Services	232,786	33,905	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CLP	Other Services	154,180	189,150	—	—
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Gas Purchase Advance	8,623,438	15,677,431	—	6,348,001
77.374.847-0	HIF H2 S.p.A	Chile	Joint venture	CLP	Capital advance	-	1,987,978	—	—
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	EUR	IT Services	-	96,464	—	—
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	US$	Other Services	-	51,915	—	—
Foreign	Enel Colombia S.A. ESP.	Colombia	Common Immediate Parent	US$	IT Services	122,891	—	—	—
Foreign	Enel Colombia S.A. ESP.	Colombia	Common Immediate Parent	US$	Engineering Services	1,627,025	734,715	—	—
Foreign	Enel Colombia S.A. ESP.	Colombia	Common Immediate Parent	US$	Other Services	89,269	140,226	—	—
Foreign	Endesa Energía	Spain	Common Immediate Parent	EUR	Gas Sales	31,754,264	-	—	—
Foreign	Endesa España	Spain	Common Immediate Parent	EUR	Other Services	28,514	29,197	—
Foreign	Endesa Generación	Spain	Common Immediate Parent	EUR	Engineering Services	51,516	50,844	—	—
Foreign	Enel North America Inc	United States	Common Immediate Parent	CLP	Other Services	158,958	-	—	—
Foreign	Enel North America Inc	United States	Common Immediate Parent	US$	Other Services	63,594	222,740	—	—
Foreign	Enel X North America Inc	United States	Common Immediate Parent	US$	Other Services	-	96,448	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Technical Services	1,726,897	1,223,525	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Other Services	464,774	477,950	—	—
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Commodity derivatives	195,403,892	21,198,832	—	—
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Engineering Services	123,427	126,210	—	—
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	US$	Engineering Services	474,458	470,414	—	—
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Other Services	2,188	2,294	—	—
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	CLP	Other Services	230,975	-	—	—
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	US$	Other Services	428,285	721,622	—	—
Foreign	Enel Grids S.r.L	Italy	Common Immediate Parent	EUR	Other Services	530,205	519,340	—	—
Foreign	Enel Innovation Hubs Srl	Italy	Common Immediate Parent	EUR	IT Services	—	102,449	—	—
Foreign	Enel Italia SrL.	Italy	Common Immediate Parent	EUR	Other Services	776,929	761,119	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Other Services	262,931	230,049	—	—
Foreign	Enel S.p.A.	Italy	Parent	EUR	Other Services	845,251	882,361	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Other Services	51,406	51,303	—	—
Foreign	Enel Green Power Morocco	Morocco	Common Immediate Parent	EUR	Other Services	456,512	377,899	—	—
Foreign	Chinango S.A.C.	Peru	Common Immediate Parent	US$	Engineering Services	18,511	18,269	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Common Immediate Parent	US$	IT Services	334,125	384,250	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Immediate Parent	CLP	Other Services	71,534	71,862	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Immediate Parent	US$	Engineering Services	1,228,039	1,036,601	—	—
Foreign	Enel Generación Perú S.A.	Peru	Common Immediate Parent	US$	Other Services	605,760	558,576	—	—
Foreign	Enel Generación Piura S.A.	Peru	Common Immediate Parent	US$	Engineering Services	78,511	77,487	—	—
Foreign	Enel Green Power Perú	Peru	Common Immediate Parent	US$	Engineering Services	1,364,051	489,630	—	—
Foreign	Enel Green Power Perú	Peru	Common Immediate Parent	US$	Other Services	4,450	4,411	—	—
Foreign	Energetica Monzon S.A.C.	Peru	Common Immediate Parent	US$	Engineering Services	784,712	776,841	—	—
Foreign	Proyectos y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	US$	Other Services	151,213	149,270	—	—
					Total	256,268,604	56,440,088	-	6,348,001

F-73

Table of Contents

Accounts payable to related parties

Taxpayer

Current

Non-current

ID No.

Company

Country

Relationship

Currency

Transaction Description

12-31-2022

12-31-2021

12-31-2022

12-31-2021

ThCh$

Foreign

Enel Generación Costanera S.A.

Argentina

Common Immediate Parent

US$

Purchase of materials

6,780

1,331,438

—

Foreign

Enel Trading Argentina S.R.L.

Argentina

Common Immediate Parent

CLP

IT Services

83,004

81,921

—

Foreign

Enel Trading Argentina S.R.L.

Argentina

Common Immediate Parent

US$

Other Services

18,083

17,846

—

Foreign

Enel Brasil S.A.

Brazil

Common Immediate Parent

US$

Other Services

33,026

—

Foreign

Enel Distribución Sao Paulo

Brazil

Common Immediate Parent

US$

Other Services

492,612

307,897

—

Foreign

Enel X Brasil Gerenciamento de Energia Ltda

Brazil

Common Immediate Parent

US$

Other Services

1,057

1,478

—

94.271.000-3

Enel Américas S.A.

Chile

Common Immediate Parent

CLP

Other Services

179,409

2,515,035

—

94.271.000-3

Enel Américas S.A.

Chile

Common Immediate Parent

US$

Other Services

144,953

—

77.569.067-4

Enel X Way Chile SpA

Chile

Associated

CLP

Other Services

3,891,398

—

77.569.067-4

Enel X Way Chile SpA

Chile

Associated

CLP

IT Services

528,182

—

76.802.924-3

Energía y Servicios South America Spa

Chile

Common Immediate Parent

CLP

Other Services

285,648

407,152

—

76.802.924-3

Energía y Servicios South America Spa

Chile

Common Immediate Parent

US$

Other Services

197,933

246,923

—

76.418.940-K

GNL Chile S.A.

Chile

Associated

US$

Gas Purchase

18,616,494

6,484,164

—

77.017.930-0

Transmisora Eléctrica de Quillota Ltda.

Chile

Joint venture

CLP

Tolls

—

13,887

—

Foreign

Codensa S.A.

Colombia

Common Immediate Parent

US$

Other Services

—

5,167

—

Foreign

Enel Colombia S.A. E.S.P.

Colombia

Common Immediate Parent

US$

Other Services

35,836

—

Foreign

Enel Colombia S.A. E.S.P.

Colombia

Common Immediate Parent

COP

Other Services

5,077

—

Foreign

Endesa España

Spain

Common Immediate Parent

EUR

Other Services

29,270

—

Foreign

Endesa Generación

Spain

Common Immediate Parent

EUR

Coal purchase

508,311

501,677

—

Foreign

Endesa Generación

Spain

Common Immediate Parent

EUR

Other Services

88,636

—

Foreign

Enel Green Power España SL

Spain

Common Immediate Parent

EUR

Other Services

658,207

561,326

—

Foreign

Enel Iberia SRL

Spain

Common Immediate Parent

EUR

IT Services

656,798

225,322

—

Foreign

Enel Iberia SRL

Spain

Common Immediate Parent

EUR

Other Services

88,171

536,809

—

Foreign

Enel Green Power North America Inc

United States

Common Immediate Parent

US$

Other Services

440,402

436,649

—

Foreign

Enel Finance International NV (*)

Netherlands

Common Immediate Parent

US$

Loan payable

428,466,443

799,265,075

1,147,096,713

1,300,059,097

Foreign

Cesi S.p.A.

Italy

Common Immediate Parent

EUR

Engineering Services

71,579

316,622

—

Foreign

Enel Energía

Italy

Common Immediate Parent

EUR

Other Services

552,771

556,018

—

Foreign

Enel Global Services S.r.l.

Italy

Common Immediate Parent

EUR

Technical Services

1,327,547

1,324,716

—

Foreign

Enel Global Services S.r.l.

Italy

Common Immediate Parent

EUR

IT Services

9,025,183

5,916,002

—

Foreign

Enel Global Services S.r.l.

Italy

Common Immediate Parent

EUR

Other Services

70,811

95,565

—

Foreign

Enel Global Thermal Generation S.r.l.

Italy

Common Immediate Parent

EUR

Technical Services

8,123,201

5,977,965

—

Foreign

Enel Global Thermal Generation S.r.l.

Italy

Common Immediate Parent

EUR

IT Services

1,329,550

3,050,405

—

Foreign

Enel Global Thermal Generation S.r.l.

Italy

Common Immediate Parent

EUR

Engineering Services

215,601

203,833

—

Foreign

Enel Global Thermal Generation S.r.l.

Italy

Common Immediate Parent

EUR

Other Services

1,298,786

1,304,026

—

Foreign

Enel Global Trading S.p.A.

Italy

Common Immediate Parent

EUR

Other Services

819,835

787,719

—

Foreign

Enel Global Trading S.p.A.

Italy

Common Immediate Parent

EUR

Engineering Services

24,982

26,185

Foreign

Enel Global Trading S.p.A.

Italy

Common Immediate Parent

US$

Commodity derivatives

74,001,856

36,208,560

—

Foreign

Enel Global Trading S.p.A.

Italy

Common Immediate Parent

EUR

Technical Services

8,739,608

7,562,517

—

Foreign

Enel Global Trading S.p.A.

Italy

Common Immediate Parent

EUR

IT Services

534,305

303,992

—

Foreign

Enel Green Power Spa

Italy

Common Immediate Parent

CLP

Other Services

273,636

274,891

—

Foreign

Enel Green Power Spa

Italy

Common Immediate Parent

EUR

Technical Services

35,965,138

31,580,956

—

Foreign

Enel Green Power Spa

Italy

Common Immediate Parent

EUR

Engineering Services

21,467,585

17,274,445

—

Foreign

Enel Green Power Spa

Italy

Common Immediate Parent

EUR

Other Services

16,387,650

16,248,379

—

Foreign

Enel Green Power Spa

Italy

Common Immediate Parent

EUR

IT Services

6,528,805

4,485,802

—

Foreign

Enel Grids S.r.L

Italy

Common Immediate Parent

EUR

Other Services

325,189

330,865

—

Foreign

Enel Grids S.r.L

Italy

Common Immediate Parent

EUR

IT Services

14,243,095

2,532,663

—

Foreign

Enel Grids S.r.L

Italy

Common Immediate Parent

EUR

Technical Services

5,453,612

5,170,559

—

Foreign

Enel Italia S.p.A

Italy

Common Immediate Parent

EUR

Engineering Services

1,113,099

1,145,568

—

Foreign

Enel Italia S.p.A

Italy

Common Immediate Parent

EUR

Other Services

1,552,756

1,617,382

—

Foreign

Enel Produzione

Italy

Common Immediate Parent

EUR

Other Services

990,303

1,033,214

—

Foreign

Enel Produzione

Italy

Common Immediate Parent

EUR

Engineering Services

1,678,743

1,880,143

—

Foreign

Enel S.p.A.

Italy

Parent

CLP

Dividends

229,338,163

16,527,560

—

Foreign

Enel S.p.A.

Italy

Parent

US$

Dividends

1,939

1,923

—

Foreign

Enel S.p.A.

Italy

Parent

EUR

Technical Services

11,149,442

9,935,189

Foreign

Enel S.p.A.

Italy

Parent

EUR

IT Services

3,485,259

2,142,992

—

Foreign

Enel S.p.A.

Italy

Parent

EUR

Dividends

14,369,214

—

Foreign

Enel S.p.A.

Italy

Parent

EUR

Other Services

5,708,090

5,410,491

—

Foreign

Enel X S.R.L.

Italy

Common Immediate Parent

EUR

Other Services

121,786

127,063

—

Foreign

Enel X S.R.L.

Italy

Common Immediate Parent

EUR

IT Services

935,155

890,918

—

Foreign

Enel X S.R.L.

Italy

Common Immediate Parent

EUR

Technical Services

12,779,052

8,826,081

—

Foreign

Gridspertise s.r.l.

Italy

Common Immediate Parent

EUR

IT Services

1,189,548

403,567

—

Foreign

Tecnatom SA

Italy

Common Immediate Parent

EUR

Engineering Services

33,386

—

Total

946,498,574

1,004,597,958

1,147,096,713

1,300,059,097

(*) See letter d below.

F-74

Table of Contents

Significant transactions and effects on profit or loss

The significant transactions with related companies that are not consolidated, are as follows:

For the years ended December 31,

Taxpayer ID No.

Company

Country

Relationship

Transaction Description

2022

2021

2020

ThCh$

Foreign

Endesa Energía S.A.

Spain

Common Immediate Parent

Gas Sales

180,214,107

—

94.271.000-3

Enel Américas S.A.

Chile

Common Immediate Parent

Provision of administration services and others

7,859,162

5,632,424

5,021,265

76.418.940-K

GNL Chile S.A.

Chile

Associated

Gas consumption

(443,243,955)

(314,415,258)

(164,410,577)

Foreign

Enel X S.R.L.

Italy

Matriz Común

Technical Services

(3,545,918)

(5,284,971)

(3,435,918)

Foreign

Enel Global Services S.r.l.

Italy

Common Immediate Parent

Engineering Services

—

(5,097,105)

Foreign

Enel Grids S.r.L

Italy

Common Immediate Parent

Technical Services

(2,260,739)

—

Foreign

Enel Grids S.r.L

Italy

Common Immediate Parent

IT Services

—

(2,230,293)

—

Foreign

Enel S.p.A.

Italy

Parent

Technical Services

(2,340,510)

(5,305,537)

(3,800,471)

Foreign

Enel Global Trading SpA.

Italy

Common Immediate Parent

Commodity derivatives

36,940,008

35,815,215

(37,771,702)

Foreign

Enel Global Trading SpA.

Italy

Common Immediate Parent

Gas Sales

166,792,281

—

Foreign

Enel Global Trading SpA.

Italy

Common Immediate Parent

Gas Purchase

—

(2,618,484)

—

Foreign

Enel Global Trading SpA.

Italy

Common Immediate Parent

Technical Services

—

(2,227,749)

(2,183,183)

Foreign

Enel Finance International NV

Netherlands

Common Immediate Parent

Financial expenses

(72,578,171)

(42,040,047)

(35,079,947)

Foreign

Enel Global Thermal Generation S.r.l.

Italy

Common Immediate Parent

Technical Services

—

(3,172,872)

Foreign

Enel Green Power SpA

Italy

Common Immediate Parent

Engineering Services

—

(7,263,535)

Foreign

Enel Green Power SpA

Italy

Common Immediate Parent

Technical Services

(6,136,692)

(7,861,111)

(4,674,437)

76.802.924-3

Energía y Servicios South America SpA

Chile

Common Immediate 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.

Significant transactions

•

On December 21, 2018, Enel Finance International NV granted a revolving credit facility in US$ 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. The credit facility allowed Enel Chile S.A. to make indefinite drawings for up to the committed amount until June 21, 2019, defined as the availability period, during which Enel Chile S.A. must pay an annual availability fee equivalent to 35% of the margin on the undrawn 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.

As of December 31, 2022, this debt has been settled, and it was fully paid at maturity on December 21, 2022. As of December 31, 2021, the amount owed was US$400 million, equivalent to ThCh$337,876,000.

•

In June 2019, Enel Chile entered into a revolving credit facility with Enel Finance International N.V. in US$ 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 undrawn 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 line of credit was entirely drawn down. The interest period is defined upon each withdrawal at 1M, 3M, or 6M renewable, until the maturity of the credit line. On December 14, 2022, the credit line was fully paid off. As of December 31, 2022, this credit line is completely available. See Note 41.vi.

•

On January 3, 2020, Enel Finance International NV granted a loan in US$ 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

F-75

Table of Contents

of December 31, 2022, was US$200 million, equivalent to ThCh$171,172,000 (ThCh$168,938,000 as of December 31, 2021). As of December 31, 2022, accrued interest amounts to ThCh$2,262,323 (ThCh$12,201 as of December 31, 2021.

•

On March 11, 2020, Enel Finance International NV granted a loan in US$ 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, 2022, was US$400 million, equivalent to ThCh$342,344,000 (ThCh$337,876,000 as of December 31, 2021). As of December 31, 2022, accrued interest amounts to ThCh$3,546,113 (ThCh$3,468,860 as of December 31, 2021).

•

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, 2022, the debt balance amounts to US$300 million, equivalent to ThCh$256,758,000 (as of December 31, 2021, it amounted to US$300 million, equivalent to ThCh$253,407,000). As of December 31, 2022, accrued interest amounts to ThCh$1,640,398 (ThCh$1,601,391 as of December 31, 2021).

•

On April 1, 2021, Enel Chile S.A. secured an 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 draw 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, 2022, this credit line is US$290 million drawn, equivalent to ThCh$248,199,400 (US$290 million, equivalent to ThCh$244,960,100, as of December 31, 2021). As of December 31, 2022, accrued interest amounts to ThCh$1,855,378 (Th$345,148 as of December 31, 2021). See Note 41.i, ii and iii.

•

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. This debt can be voluntarily prepaid, including “breakage costs. As of December 31, 2022, the balance of this debt amounts to US$644 million, equivalent to ThCh$551,491,708 (as of December 31, 2021, it amounted to US$644 million, equivalent to ThCh$544,294,079). As of December 31, 2022, this debt does not have any accrued interest, which was fully paid on December 30, 2022.

•

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 of 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

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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 draws 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. Upon each draw from the credit line, the interest period is defined at 1M, 3M or 6M renewable until maturity. On December 14, 2022, the first prepayment of the credit line was made for US$100 million. On December 16, 2022, a second prepayment for US$100 million was made to repay 100% of the credit line. As of December 31, 2022, this credit line is completely available

•

On January 31, 2022, Enel Chile S.A. formalized a revolving line of credit with Enel Finance International N.V. in US$ for a total of US$300 million, at a SOFR 1M, 3M or 6M variable rate plus a margin of 0.75%, with monthly, quarterly or semiannual interest payments, and a maturity date of August 1, 2023. During the availability period, Enel Chile S.A. will pay an annual availability commission equivalent to 35% of the margin over the undrawn amount. On February 17, 2022, the first draw of the line was performed in the amount of US$200 million followed by a second draw of US$100 million on March 4, 2022. At the time of each draw, the interest period is defined as 1M, 3M or 6M, renewable until the line's maturity date. On December 16, 2022, the credit line was fully prepaid and was closed ahead of schedule.

•

On June 8, 2022, Enel Chile S.A. formalized a revolving line of credit with Enel Finance International N.V. in US$ for a total of US$150 million, at a SOFR 1M, 3M or 6M variable rate plus a margin of 0.86%, with monthly, quarterly or semiannual interest payments, and a maturity date of August 8, 2023. During the availability period, Enel Chile S.A. will pay an annual availability commission equivalent to 35% of the margin over the undrawn amount. On February 14, 2022, the first draw of the line was performed in the amount of US$100 million followed by a second draw of US$50 million on July 7, 2022. At the time of each draw, the interest period is defined as 1M, 3M or 6M, renewable until the line's maturity date. On December 14, 2022, the first prepayment of the credit line was made for US$100 million. On December 16, 2022, a second payment for US$50 million was made to repay 100% of the credit line. On December 16, 2022, this credit line was closed ahead of schedule.

•

On July 31, 2022, Enel Chile S.A. formalized a revolving line of credit with Enel Finance International N.V. in US$ for a total of US$250 million, at a SOFR 1M, 3M or 6M variable rate plus a margin of 0.77%, with monthly, quarterly or semiannual interest payments, and a maturity date of July 31, 2023. During the availability period, Enel Chile S.A. will pay an annual availability commission equivalent to 25% of the margin over the undrawn amount. On August 11, 2022, a first draw from the credit line was made for US$150 million. On August 19, 2022, a second draw was made for US$100 million. Upon each draw, the interest period is defined at 1M, 3M or 6M renewable until maturity of the credit line. On December 16, 2022, this credit line was fully prepaid and was closed ahead of schedule.

10.2 Board of directors and key management personnel

Enel Chile is managed by a Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors in office as of December 31, 2022, 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. Herman 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.

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.

Guarantees given by the Company in favor of the directors

No guarantees have been given to the Directors.

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.

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Directors’ Committee:

Each member will be paid 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, 2022, 2021 and 2020:

December 31, 2022

Taxpayer ID No.

Name

Position

Period in position

Enel Chile Board

Board of subsidiaries

Directors' Committee

ThCh$

4.975.992-4

Herman Chadwick Piñera

Chairman

January -December 2022

250,419

4.461.192-9

Fernán Gazmuri Plaza

Director

January -December 2022

125,209

41,688

4.774.797-K

Pablo Cabrera Gaete

Director

January -December 2022

125,209

41,688

5.545.086-2

Luis Gonzalo Palacios Vasquez

Director

January -December 2022

125,209

41,688

Foreign

Monica Girardi

Director

January -December 2022

Foreign

Isabella Alessio

Director

January -December 2022

Foreign

Salvatore Bernabei

Director

January -December 2022

TOTAL

626,046

125,064


				December 31, 2021
Taxpayer ID No.	Name	Position	Period in position	Enel Chile Board	Board of subsidiaries	Directors' Committee
				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	Fernan Gazmuri Plaza	Director	January -December 2021	105,796	-	34,466
4.774.797-K	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
Taxpayer ID No.	Name	Position	Period in position	Enel Chile Board	Board of subsidiaries	Directors' Committee
				ThCh$	ThCh$	ThCh$
4.975.992-4	Herman Chadwick Piñera	Chairman	January -December 2020	207,918	-	-
Foreign	Giulio Fazio	Director	January -December 2020	-	-	-
4.461.192-9	Fernan Gazmuri Plaza	Director	January -December 2020	103,959	-	34,653
4.774.797-K	Pablo Cabrera Gaete	Director	January -December 2020	103,959	-	34,653
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January -December 2020	103,959	-	34,653
Foreign	Daniele Caprini	Director	January -December 2020	-	-	-
Foreign	Salvatore Bernabei	Director	January -December 2020	-	-	-
			Total	519,795	-	103,959

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10.3 Compensation of key management personnel

Enel Chile’s key management personnel as of December 31, 2022 is comprised of the following people:


Key Management Personnel
Taxpayer ID No.	Name	Position
Foreign	Fabrizio Barderi (1)	Chief Executive Officer
Foreign	Giuseppe Turchiarelli	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
16.261.687-0	Juan Francisco Díaz Valenzuela (2)	Internal Audit Manager
27.965.892-2	Montserrat Palomar Quilez (3)	Sustainability and Relationship Manager

(1)

On March 1, 2022, Mr. Fabrizio Barderi was appointed Chief Executive Officer, replacing Mr. Paolo Palloti.

(2)

On February 1, 2022, Mr. Juan Francisco Díaz Valenzuela was appointed Internal Audit Manager, replacing Mr. Eugenio Belinchon Gueto.

(3)

On November 1, 2022, Ms. Montserrat Palomar Quilez took over as Sustainability and Relations Manager.

10.4 Incentive plans for key management personnel

Enel Chile has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Group. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.

Compensation received by key management personnel as of December 31, 2022, 2021 and 2020 was as follows:


	December 31, 2022	December 31, 2021	December 31, 2020
	ThCh$	ThCh$	ThCh$
Remuneration	2,241,508	2,060,928	2,133,063
Short-term benefits for employees	261,306	260,400	272,714
Other long-term benefits	143,969	38,713	146,404
Total	2,646,783	2,360,041	2,552,181

Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

10.5 Compensation plans linked to share price

There are no payment plans granted to the Directors or key Management personnel based on the share price of the Enel Chile common stock.

10.6 Restricted stock unit program

In 2022, under an established restricted stock unit (“RSU”) program that was implemented for that year only, certain key personnel of Enel Chile received a one-time issuance of Enel S.p.A. shares for the corresponding RSU award. These shares were not issued on a discretionary basis, but were automatically issued upon vesting of the RSUs on a pre-established date once certain performance-based vesting conditions were met. The cost of the RSU program is subject to an outstanding recharge agreement; accordingly, such cost has been supported by Enel Chile. This agreement establishes that all fixed and variable remuneration of certain expatriate executives (whether in cash or in kind) is paid by the company to which the expatriate executive provides services. The cost of the program amounted to ThCh$27,395. This cost is included in the item Remuneration Expenses for 2022.

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11. INVENTORIES

The detail of inventories as of December 31, 2022 and 2021, is as follows:


	As of December 31,
	2022	2021
	ThCh$	ThCh$
Supplies for Production	18,678,262	6,130,065
Gas	7,050,658	2,764,539
Oil	11,627,604	3,365,526
Supplies for projects and spare parts	30,215,221	22,131,301
Electrical materials	29,022,610	2,986,344
Total	77,916,093	31,247,710

There are no inventories acting as security for liabilities.

For the years ended December 31, 2022, 2021 and 2020, raw materials and inputs recognized as fuel cost was ThCh$587,063,837, ThCh$ 374,868,794 and ThCh$ 231,176,489, respectively. See note 29.

In the 2022 fiscal year, adjustments were recorded due to coal and diesel inventory impairment for ThCh$51,213,588. These adjustments are related to the discontinuity of the Bocamina II plant. For this same reason, during the 2021 fiscal year, coal and diesel inventory impairment was recorded for ThCh$46,572,145. For further information, see Notes 16.c.iv and 29.

12. CURRENT TAX ASSETS AND LIABILITIES

The detail of current tax receivables as of December 31, 2022 and 2021, is as follows:


	As of December 31,
	2022	2021
Tax Receivables	ThCh$	ThCh$
Advance income tax payments	42,504,237	51,691,573
Credit for adsorbed tax profits	77,515,647	59,372,737
Tax credit for training expenses	538,483	472,706
Total	120,558,367	111,537,016

The detail of current tax payables as of December 31, 2022 and 2021, is as follows:


	As of December 31,
	2022	2021
Current tax liabilities	ThCh$	ThCh$
Income tax	334,336,370	13,148,707
Total	334,336,370	13,148,707

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13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

13.1. 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, 2022 and 2021:


								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)	12-31-2022	Equity	12-31-2022
Number	Associates and Joint Ventures	Relationship	Country	Currency	Percentage	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%	5,706,636	—	6,846,528	—	(149,017)	—	—	12,404,147	—	12,404,147
76.014.570-K	Enel Argentina S.A.	Associate	Argentina	Argentine Peso	0.08%	387,135	—	(22,337)	(42,758)	(144,639)	—	210,927	388,328	—	388,328
76.364.085-K	Energías Marina SpA	Associate	Chile	Chilean Peso	25.00%	—	16,493	(59,317)	—	—	—	—	(42,824)	42,824	—
77.157.779-2	Enel X AMPCI Ebus Chile SpA	Associate	Chile	U.S. dollar	20.00%	3,828,885	—	(29,621)	(384,087)	(67,686)	1,033,236	(4,380,727)	—	—	—
77.374.847-0	HIF H2 SpA (1)	Joint venture	Chile	U.S. dollar	50.00%	1,277	2,744,259	(2,750,793)	—	146	—	—	(5,111)	5,111	—
77.230.801-9	Sociedad de Inversiones K Cuatro SpA (2)	Joint venture	Chile	Chilean Peso	50.00%	—	29,352,972	(266,328)	—	—	—	(29,086,644)	—	—	—
77.371.406-1	Suministradora de Buses K Cuatro SPA (2)	Joint venture	Chile	Chilean Peso	0.50%	—	296,809	(3,259)	—	—	—	(293,550)	—	—	—
77.569.067-4	Enel X Way Chile S.p.A.	Associate	Chile	Chilean Peso	49.00%	—	6,196,475	(433,632)	—	—	9,949	(812,489)	4,960,303	—	4,960,303
					TOTAL	9,923,933	38,607,008	3,281,241	(426,845)	(361,196)	1,043,185	(34,362,483)	17,704,843	47,935	17,752,778


								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)	12-31-2021	Provision	12-31-2021
Number	Associates and Joint Ventures	Relationship	Country	Currency	'Percentage	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%	1,729,383	—	3,620,701	(381,860)	738,412	—	—	5,706,636	—	5,706,636
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (3)	Joint venture	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	0.08%	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 (1)	Joint venture	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

(1)

See Note 13.3.a).

(2)

See Note 13.3.b).

(3)

See Note 13.3.c).

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13.2. Additional financial information on investments in associates

Financial information as of December 31, 2022 and 2021 of the main companies in which the Group exercises significant influence is detailed below:


	As of December 31, 2022
	Direct / Indirect	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Ownership %	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A.	33.33%	168,628,712	1,732,116,130	258,607,318	1,604,925,084	1,342,760,054	20,539,585	(447,055)	20,092,530
Enel X AMPCI Ebus Chile SpA	20.00%	—	—	—	—	—	(148,103)	4,827,752	4,679,649
Enel X Way Chile S.p.A.	49.00%	15,891,445	2,214,410	7,578,722	404,066	4,239,501	(884,964)	20,305	(864,659)


	As of December 31, 2021
	Direct / Indirect	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Ownership %	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

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

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13.3. 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, 2022 and 2021, are as follows:

HIF H2 SpA.:


	HIF H2 SpA
% Ownership	50.0%	50.0%
	12-31-2022	12-31-2021
	ThCh$	ThCh$
Total current assets	2,556	4,008,576
Total current liabilities	12,779	—
Total non-current liabilities	—	4,006,021
Cash and cash equivalents	2,556	2,555

Other fixed operating expenses	(5,501,586)	—
Profit (Loss)	(5,501,586)	—
Comprehensive income	(5,501,586)	—

Sociedad de Inversiones K Cuatro SpA.:


		Sociedad de Inversiones
		K Cuatro SpA
% Ownership		50.0%
		06-12-2022
		ThCh$
Total current assets		237,410
Total non-current assets		59,474,494
Total current liabilities		1,927
Total non-current liabilities		886,326
Cash and cash equivalents		1,557

Other fixed operating expenses		(600,822)
Financial costs		(129)
Foreign exchange gains (losses)		58,279
Income per adjustment units		3,497
Profit (loss)		(539,175)
Comprehensive income		(539,175)

On October 28, 2021, Enel X Chile purchased a 10% interest in Sociedad de Inversiones K Cuatro SpA for ThCh$31,632. Before February 28, 2022, this interest was conditioned upon the long-term financial asset, because the Group did not have significant influence over the company. Then, on February 28, 2022, Enel X Chile increased its interest in Sociedad de Inversiones K Cuatro SpA to 50%, through the acquisition of 400 shares for a total of ThCh$259,393, thus meeting the conditions to be classified as a joint venture (see Note 2.6).

Sociedad de Inversiones K Cuatro SpA was awarded the public bid for the complementary bus supply service for the Public Transportation System of the Province of Santiago and the communities of San Bernardo and Puente Alto. Therefore, it formed a corporation known as Suministradora de Buses K Cuatro SpA. (hereinafter, the Supplier).

As a result of the aforementioned bid, the Supplier must purchase 991 buses which will then be leased to the operators of the Public Transportation System. The approximate cost of this acquisition is US$364 million plus VAT. The bid terms and conditions establish certain minimum capital obligations for the Supplier and, on May 13, 2022, the Supplier performed a capital increase of US$63.5 million (ThCh$58,769,207), of which, proportional to its new shareholder interest, Enel X Chile contributed US$31.5 million (ThCh$29,384,103), through Sociedad de Inversiones K Cuatro SpA.

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On December 6, 2022, our subsidiary Enel X Chile completed the sale of its entire stake in Sociedad de Inversiones K Cuatro SpA and Suministradora de Buses K Cuatro SpA. (See Note 9.a) detail of Other accounts receivable, and Note 33).

Transmisora Eléctrica de Quillota Ltda.:


		Transmisora Eléctrica
		de Quillota Ltda.
% Ownership		50.0%
		12-31-2021
		ThCh$
Total current assets		—
Total non-current assets		—
Total current liabilities		—
Total non-current liabilities		—
Cash and cash equivalents		—

Revenues		896,616
Other fixed operating expenses		(239,154)
Depreciation and amortization expense		(824,314)
Other Income		25,735
Interest income		61,769
Income tax expense		(505,710)
Profit (loss)		(585,058)
Comprehensive income		(585,058)

On December 30, 2021, the Company sold its 50% equity interest in Transmisora Eléctrica de Quillota Ltda. (see Note 2.6.ii) for US$13,862,707, equivalent to ThCh$11,786,767, resulting in a profit of ThCh$9,968,845.

There are no significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.

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14. INTANGIBLE ASSETS OTHER THAN GOODWILL

The balances of this caption as of December 31, 2022 and 2021 are presented below:


	As of December 31,
	2022	2021
Classes of Intangible Assets, Gross	ThCh$	ThCh$
Intangible Assets, Gross	334,904,014	317,349,834
Easements and water rights	13,227,138	22,169,638
Concessions	78,027,417	68,707,575
Patents, registered trademarks and other rights	1,654,706	1,560,467
Software licenses	232,572,572	215,606,140
Other identifiable intangible assets	9,422,181	9,306,014


	As of December 31,
	2022	2021
Classes of Intangible Assets, Amortization and Impairment	ThCh$	ThCh$
Accumulated Amortization and Impairment, Total	(143,462,751)	(126,128,279)
Easements and water rights	(5,040,675)	(6,203,360)
Concessions	(16,016,387)	(13,306,986)
Patents, registered trademarks and other rights	(764,612)	(502,432)
Software Licenses	(118,655,592)	(103,254,572)
Other Identifiable Intangible Assets	(2,985,485)	(2,860,929)


	As of December 31,
	2022	2021
Classes of Intangible Assets, Net	ThCh$	ThCh$
Intangibles Assets, Net	191,441,263	191,221,555
Easements and water rights	8,186,463	15,966,278
Concessions	62,011,030	55,400,589
Patents, registered trademarks and other rights	890,094	1,058,035
Software Licenses	113,916,980	112,351,568
Other Identifiable Intangible Assets	6,436,696	6,445,085

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The following table presents intangible assets other than Goodwill as of December 31, 2022 and 2021:


	Easements and water rights	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangible 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
Increase (decrease)	—	—	—	(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	Intangible Assets, Net
Movements in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2022	15,966,278	55,400,589	1,058,035	112,351,568	6,445,085	191,221,555
Movements in identifiable intangible assets
Increases other than from business combinations	—	8,604,379	—	31,344,129	—	39,948,508
Increase (decrease) from foreign currency translation differences	47,213	720,914	—	25,124	80,502	873,753
Amortization (1)	—	(2,335,352)	(262,180)	(19,675,792)	(12,917)	(22,286,241)
Increases (decreases) from transfers and other Movements	1,550,107	—	94,239	(1,699,271)	54,925	—
Increases (decreases) from transfers	1,550,107	—	94,239	(1,699,271)	54,925	—
Dispositions and removal from service	—	(398,799)	—	(2,730)	—	(401,529)
Dispositions	—	(398,799)	—	(2,730)	—	(401,529)
Argentina Hyperinflation Effect	—	—	—	—	(130,899)	(130,899)
Decreases to be classified as held for sale (2)	(9,377,135)	—	—	(9,208,014)	—	(18,585,149)
Increase (decrease)	—	19,299	—	781,966	—	801,265
Total Movements in identifiable intangible assets	(7,779,815)	6,610,441	(167,941)	1,565,412	(8,389)	219,708
Closing balance as of December 31, 2022	8,186,463	62,011,030	890,094	113,916,980	6,436,696	191,441,263

(1)

See Note 31 a).

(2)

See Note 5.2

No impairment losses have been recognized as of December 31, 2022 and 2021. According to the estimates and projections of the Group’s Management, the cash flows projections attributable to intangible assets allow recovering the net value of these assets recorded as of December 31, 2022 (see Note 3. e).

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15. 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, 2022 and 2021:


Company	Cash Generating Unit	Opening Balance 01-01-2021	Transfer	Foreign Currency Translation	Closing Balance 12-31-2021	Transfer to Held for Sale (1)	Foreign Currency Translation	Closing Balance 12-31-2022
		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	(37,912,005)	—	90,462,357	—	—	90,462,357
Enel Transmisión Chile S.A.	Enel Transmisión Chile	—	37,912,005	—	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	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	—	324,265	24,845,615
Geotérmica del Norte	Enel Green Power Chile	77,445	—	14,627	92,072	—	1,218	93,290
Parque Eólico Talinay Oriente	Enel Green Power Chile	7,744,451	—	1,462,670	9,207,121	—	121,753	9,328,874
	Total	915,705,369	—	5,372,829	921,078,198	(37,912,005)	447,236	883,613,429

(1)

See Note 5.2.

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, 2022 and 2021 (see Note 3.e).

The origin of the goodwill is detailed below:

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.

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.

Enel Transmisión Chile S.A. (see Note 5.2)

Enel Transmisión Chile S.A. was incorporated on January 1, 2021, as a result of the spin-off of Enel Distribución Chile S.A., and it was assigned the assets and liabilities associated with the electric power transmission business. The spin-off process was performed to comply with requirements related to the exclusive distribution business, in accordance with the latest amendments to Decree Law No. 4/2016 issued by 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 performed using the value in use method as of the 2020 year-end as reference.

On October 21, 2022, Enel Chile completed the sale of its subsidiary Enel Transmisión Chile S.A. to Sociedad Transmisora Metropolitana SpA., through a takeover bid. Consequently, control of Enel Transmisión Chile S.A. was transferred to the new controlling parent Sociedad Transmisora Metropolitana SpA. (see Notes 2.4.1.v and 33).

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

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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. (ex 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.

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.

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 on the companies Empresa Eléctrica Panguipulli S.A. and Empresa Eléctrica Puyehue S.A., where subsequently Puyehue merged 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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16. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2022 and 2021:


	As of December 31,
	2022	2021
Classes of Property, Plant and Equipment, Gross	ThCh$	ThCh$
Property, Plant and Equipment, Gross	11,569,978,697	11,142,172,107
Construction in progress	3,099,937,769	2,404,299,833
Land	64,680,270	78,715,479
Buildings	629,754,211	655,780,937
Generation Plant and Equipment	6,435,310,747	6,300,566,056
Network infrastructure	1,188,201,802	1,488,114,938
Fixtures and fittings	131,402,242	194,179,535
Other property, plant, and equipment	20,691,656	20,515,329


	As of December 31,
	2022	2021
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment	ThCh$	ThCh$
Total Accumulated Depreciation and Impairment in Property, Plant and Equipment	(4,997,624,703)	(5,031,483,346)
Buildings	(187,875,641)	(185,002,401)
Plant and equipment	(4,224,174,273)	(4,086,507,212)
Network infrastructure	(479,761,456)	(614,017,141)
Fixtures and fittings	(85,619,903)	(126,246,469)
Other property, plant, and equipment	(20,193,430)	(19,710,123)


	As of December 31,
	2022	2021
Classes of Property, Plant and Equipment, Net	ThCh$	ThCh$
Property, Plant and Equipment, Net	6,572,353,994	6,110,688,761
Construction in progress	3,099,937,769	2,404,299,833
Land	64,680,270	78,715,479
Buildings	441,878,570	470,778,536
Generation Plant and Equipment	2,211,136,474	2,214,058,844
Network infrastructure	708,440,346	874,097,797
Fixtures and fittings	45,782,339	67,933,066
Other property, plant, and equipment	498,226	805,206

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The composition and movements of the property, plant and equipment accounts during the fiscal year ended December 31, 2022 and 2021, are as follows:


	Construction in progress	Land	Buildings, Net	Generation Plant and Equipment Net	Network infrastructure, Net	Fixtures and Fittings, Net	Other property, plant and equipment, Net	Property, Plant and Equipment, Net
Movements in 2022	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2022	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
Increases other than from business combinations	1,010,059,037	—	(560,847)	925,250	1,752,776	145,616	—	1,012,321,832
Increases (decreases) from foreign currency translation differences	14,627,772	(84,493)	3,021,504	7,434,974	544,629	(300,948)	14,012	25,257,450
Depreciation (1)	—	—	(22,407,997)	(139,378,454)	(38,646,149)	(7,383,182)	(320,992)	(208,136,774)
Increases (decreases) from transfers and other movements	(229,013,784)	888,683	28,652,809	128,323,777	65,834,402	5,314,113	—	—
Increases (decreases) from transfers from construction in progress	(229,013,784)	888,683	28,652,809	128,323,777	65,834,402	5,314,113	—	—
Disposals and removals from service	(53,307,303)	-	—	(1,619,263)	(3,190,127)	—	—	(58,116,693)
Disposals	(369,837)	—	—	—	—	—	—	(369,837)
Removals (2)	(52,937,466)	—	—	(1,619,263)	(3,190,127)	—	—	(57,746,856)
Decreases to be classified as held for sale (3)	(69,519,016)	(16,388,131)	(40,708,934)	—	(192,857,093)	(19,167,093)	—	(338,640,267)
Other increases (decreases)	22,274,490	1,438,994	2,941,741	120,184	904,111	(1,153,320)	—	26,526,200
Argentine hyperinflationary economy	516,740	109,738	161,758	1,271,162	—	394,087	—	2,453,485
Total movements	695,637,936	(14,035,209)	(28,899,966)	(2,922,370)	(165,657,451)	(22,150,727)	(306,980)	461,665,233
Closing balance as of December 31, 2022	3,099,937,769	64,680,270	441,878,570	2,211,136,474	708,440,346	45,782,339	498,226	6,572,353,994


	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 (4)	(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)	(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

(1)

See Note 31.

(2)

See clause v) in section c) other information, contained in this same Note.

(3)

See Note 5.

(4)

See clause iv) in section c) other information, contained in this same Note.

Additional information on property, plant and equipment, net

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$3,099,937,769 and ThCh$2,404,299,833 as of December 31, 2022 and 2021, 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. The book value of these works in progress totaled ThCh$174,653,435 and ThCh$131,899,846 as of December 31, 2022 and 2021, respectively.

In the generation segment, investments include works towards the new capacity program. This includes:

(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

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150 MW. The carrying amount recorded in assets for this project was ThCh$919,548,128 and ThCh$790,358,312, as of December 31, 2022 and 2021, respectively.

(ii)

Progress on the Cerro Pabellón, Sol de Lila, Domeyko, Valle del Sol, Campos del Sol, Sierra Gorda Solar, El Manzano and La Cabaña projects, which together represent an installed capacity of approximately 1.35 GW, and which are being executed by Enel Green Power Chile. The carrying amount recorded in assets for this project was ThCh$1,801,784,315 and ThCh$1,092,094,271, as of December 31, 2022 and 2021, 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$2,233,139,570 and ThCh$1,675,012,361, as of December 31, 2022 and 2021 respectively.

Capitalized cost

b.1) Capitalized financial expenses in work-in-progress

The capitalized cost for financial expenses amounted to ThCh$83,292,276 as of December 31, 2022, (ThCh$61,513,684 and ThCh$33,109,819 as of December 31, 2021 and 2020, respectively) (see Note 34). The average financing rate ranged between 5.93% and 6.17% as of December 31, 2022 (6.86% and 7.39% as of December 31, 2021).

The increase in interest capitalization evidenced during 2022 is mainly explained by an improved performance of non-conventional renewable energy projects and by a greater continuity in the performance 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$44,569,685, ThCh$31,157,196 and ThCh$25,539,316 as of December 31, 2022, 2021 and 2020 respectively.

The increase in the capitalization of interest and personnel expenses in fiscal years 2022 and 2021 is mainly due to a improved performance of non-conventional renewable energy projects.

Other information

(i)

As of December 31, 2022 and 2021, the Group maintained commitments to acquire tangible fixed assets in the amount of ThCh$36,236,061 and ThCh$119,301,305, respectively.

(ii)

As of December 31, 2022 and 2021, 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$909,243,650), 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$363,697,460) 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$18,184,873). 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 conforming 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 19.b.

Development during 2022:

On May 3, 2022, the National Energy Commission issued Exempt Resolution No. 325, which based on technical studies and system operation projections, ordered Enel Generación Chile S.A. (“Enel Generación”) to perform the final removal, disconnection, and termination of operations at the Bocamina II generation unit beginning on September 30, 2022, in accordance with article 72-18 of the General Law of Electricity Services.

(v)

The Company has undertaken an in-depth analysis of its project portfolio, as part of its strategy for decarbonization and to improve relations with local communities. It has considered the current conditions that are prevalent in its increasingly competitive market, with a growing investment in non-conventional renewable energies. As a result, at the end of 2022, the Group decided to abandon certain projects. This is the reason why Enel Generación Chile had to write off assets for ThCh$22,912,146, which were mainly associated with thermal and hydroelectric projects, including the “Quintero” and “Vallecito” projects. Likewise, Enel Green Power Chile had to write off ThCh$29,887,851 associated with a geothermal project called “El Tatio”, which was being developed in the Antofagasta region (See Note 32).

(vi)

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 was finalized during the second half of 2021.

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17. INVESTMENT PROPERTY

The investment property breakdown and activity during 2022 and 2021 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, 2021	9,189,377	(1,767,437)	7,421,940
Depreciation expense	—	(19,812)	(19,812)
Reversals of value impairment loss recognized in the income statement	—	136,877	136,877
Balance as of December 31, 2021	9,189,377	(1,650,372)	7,539,005
Owner-occupied real property transfers	(1,479,063)	557,282	(921,781)
Depreciation expense	—	(7,701)	(7,701)
Reversals of value impairment recognized in the income statement	—	738,739	738,739
Balance as of December 31, 2022	7,710,314	(362,052)	7,348,262

As of December 31, 2022, and 2021, no real estate property has been sold.

Fair value measurement and hierarchy

As of December 31, 2022 and 2021, the fair value of the investment was ThCh$8,398,984 and ThCh$8,856,391 respectively. This value was determined according to independent appraisals.

The input data used in this valuation are considered 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	—	—	8,398,984

See Note 3.h.

The revenue and expenses derived from investment properties for the years ended December 31, 2022, 2021 and 2020, are detailed as follows:


	2022	2021	2020
Income and expense from investment properties	ThCh$	ThCh$	ThCh$
Income derived from rental income from investment properties	131,531	204,483	196,955
Direct operating expenses from investment properties that generate rental income	(18,551)	(39,727)	(36,761)
Total	112,980	164,756	160,194

There are no contracts for repairs, maintenance, acquisition, construction, or development which represent future obligations for the Group as of December 31, 2022 and 2021.

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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18. RIGHT-OF-USE-ASSETS

Right-of-use assets for the years ended December 31, 2022 and 2021, are detailed as follows:


	Land	Other Plants and equipment	Right-of-use assets, Net
Movements in 2022	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2022	140,588,971	20,199,890	160,788,861
New assets contracts, by right-of use	61,567,317	429,537	61,996,854
Increases (decreases) from foreign currency translation differences, net	19,926,031	368,947	20,294,978
Depreciation	(6,069,392)	(1,763,885)	(7,833,277)
Retirements	—	(418,215)	(418,215)
Decreases for classification as held for sale (1)	—	(1,130,769)	(1,130,769)
Total movements	75,423,956	(2,514,385)	72,909,571
Closing balance as of December 31, 2022	216,012,927	17,685,505	233,698,432

	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

(1)See Note 5.2.

As of December 31, 2022 and 2021, the main right-of-use assets and lease liabilities are detailed as follows:

These mainly derive from land lease contracts for the development of non-conventional renewable energy projects by Enel Green Power Chile Group. These include: "Campos del Sol", "Finis Terrae" and "La Cabaña", with remaining terms of 27, 22 and 28 years respectively, which accrue interest at an annual rate of 1.86%, 1.59% and 4.35%, respectively.

The present value of future payments derived from those contracts is detailed as follows:


	As of December 31,
	2022			2021
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	26,961,235	7,940,599	19,020,636	14,282,203	3,177,185	11,105,018
From one to two years	12,870,321	7,747,979	5,122,342	13,303,170	2,903,458	10,399,712
From two to three years	12,572,768	7,731,707	4,841,061	7,228,546	2,794,604	4,433,942
From three to four years	12,452,751	7,572,337	4,880,414	7,018,180	2,690,733	4,327,447
From four to five years	12,312,890	7,408,571	4,904,319	6,916,077	2,590,412	4,325,665
More than five years	326,982,549	130,065,766	196,916,783	160,449,882	35,379,589	125,070,293
Total	404,152,514	168,466,959	235,685,555	209,198,058	49,535,981	159,662,077

Short-term and low-value leases

The consolidated income statement for the years ended December 31, 2022, 2021 and 2020, includes expenses in the amounts of ThCh$5,436,911, ThCh$3,790,971, and ThCh$4,958,760, respectively, of which ThCh$3,614,981 correspond to short-term lease payments in 2022 (ThCh$3,129,893 in 2021 and ThCh$3,334,241 in 2020) and ThCh$1,821,930 relate to leases with variable payment clauses in 2022 (ThCh$661,078 in 2021 and ThCh$1,624,519 in 2020), which are exempt from the application of IFRS 16 (see Note 3.f).

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As of December 31, 2022 and 2021, future payments derived from those contracts are detailed as follows:


	As of December 31,	As of December 31,
	2022	2021
	ThCh$	ThCh$
Less than one year	1,371,547	2,797,608
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	1,371,547	2,797,608

19. INCOME TAX AND DEFERRED TAXES

Income taxes

The following are the components of income tax recorded in the consolidated statements of comprehensive income for the years 2022, 2021 and 2020:


	2022	2021	2020
Current Income Tax and Adjustments to Current Income Tax for Previous Periods	ThCh$	ThCh$	ThCh$
(Expense) / Current income tax	(394,133,842)	28,269,648	(155,196,656)
Adjustments to current tax from the previous period	(2,021,133)	(773,163)	3,694,656
(Expense) / Current tax (expenses) / benefit (related to cash flow hedges)	39,826,484	(109,882,227)	72,354,119
Other current tax benefit / (expense)	—	—	(98,646)
Current tax expense, net	(356,328,491)	(82,385,742)	(79,246,527)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	(113,368,389)	67,247,084	160,551,634
Total deferred tax benefit / (expense)	(113,368,389)	67,247,084	160,551,634
Income tax (expense) / income	(469,696,880)	(15,138,658)	81,305,107

The following table shows the reconciliation of the tax rate as of December 31, 2022, 2021 and 2020:


			2022		2021			2020
Reconciliation of Tax Expense	Tax Rate		ThCh$	Tax Rate	ThCh$	Tax Rate		ThCh$
Accounting income before tax			1,778,680,669		115,848,792			(133,691,942)
Total tax income (expense) using statutory rate	(27.00)	%	(480,243,781)	(27.00)%	(31,279,174)	27.00	%	36,096,825
Tax effect of rates applied in other countries	0.00	%	23,800	0.08%	96,520	0.04	%	55,915
Tax effect of tax-exempt revenue and other positive effects impacting the effective rate	1.28	%	22,736,630	2.53%	2,931,159	31.79	%	42,501,879
Tax effect of non-deductible expenses for determining taxable profit (loss)	(3.20)	%	(56,916,018)	(10.49)%	(12,156,154)	(7.32)	%	(9,790,603)
Tax effect of adjustments to income taxes in previous periods	(0.11)	%	(2,021,133)	(0.67)%	(773,163)	2.76	%	3,694,656
Price level restatement for tax purposes (investments and equity)	2.63	%	46,723,622	22.48%	26,042,154	6.54	%	8,746,435
Total adjustments to tax expense using statutory rate	0.59	%	10,546,901	13.93%	16,140,516	33.82	%	45,208,282
Income tax benefit (expense)	(26.41)	%	(469,696,880)	(13.07)%	(15,138,658)	60.82	%	81,305,107

The main temporary differences are described below.

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Deferred taxes

The origin of and changes in deferred tax assets and liabilities as of December 31, 2022 and 2021, are as follows:


	12-31-2022		12-31-2021
	Assets	Liabilities	Assets	Liabilities
Deferred Tax Assets/(Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$
Depreciations	29,734,809	(322,504,008)	79,595,812	(297,814,005)
Obligations for post-employment benefits	6,558,077	(226,762)	6,221,900	(65,201)
Tax loss	86,090,908	—	116,355,816	—
Provisions	105,031,784	(53,064)	104,211,997	—
Decommissioning Provision	51,516,840	—	50,001,807	—
Provision for Civil Contingencies	2,080,890	—	1,946,340	—
Provision for doubtful trade accounts	4,067,205	—	9,362,865	—
Provision of Human Resources accounts	11,372,224	—	11,902,160	—
Other Provisions	35,994,625	(53,064)	30,998,825	—
Other Deferred Taxes	54,518,180	(92,288,789)	19,147,266	(45,369,799)
Activation of expenses for issuance of financial debt	—	(19,635,737)	—	(11,282,929)
Gain from bargain purchase for tax purposes	—	(8,896,416)	—	(10,177,907)
Price-level Adjustment - Argentina	—	(11,526,750)	—	(2,160,549)
Other Deferred Taxes	54,518,180	(52,229,886)	19,147,266	(21,748,414)
Deferred tax Assets/(Liabilities) before compensation	281,933,758	(415,072,623)	325,532,791	(343,249,005)
Compensation deferred taxes Assets/Liabilities	(216,056,129)	216,056,129	(145,832,055)	145,832,055
Deferred tax Assets/(Liabilities) after compensation	65,877,629	(199,016,494)	179,700,736	(197,416,950)


		Movements
Recognized in others in comprehensive income	Net balance as of January 1, 2022	Recognized in profit or loss	Recognized in others in comprehensive income	Transfers to groups held for sale (i)	Foreign currency translation difference	Other increases (decreases)		Net balance as of December 31, 2022
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$		ThCh$
Depreciations	(218,218,193)	(97,270,017)	—	16,843,366	5,875,645	—		(292,769,199)
Obligations for post-employment benefits	6,156,699	(1,915,754)	1,972,561	119,179	(1,370)	—		6,331,315
Tax loss	116,355,816	(30,585,545)	—	—	320,637	—		86,090,908
Provisions	104,211,997	5,047,821	—	(439,765)	236,460	(4,077,793)		104,978,720
Decommissioning Provision	50,001,807	1,524,224	—	(3,556)	(5,635)	—		51,516,840
Provision for Civil Contingencies	1,946,340	134,550	—	—	—	—		2,080,890
Provision for doubtful trade accounts	9,362,865	(916,770)	—	(301,077)	(20)	(4,077,793)	(ii)	4,067,205
Provision of Human Resources accounts	11,902,160	(455,741)	—	(135,132)	60,937	—		11,372,224
Other Provisions	30,998,825	4,761,558	—	—	181,178	—		35,941,561
Other Deferred Taxes	(26,222,533)	(491,425)	1	—	(1,088,372)	(9,968,280)		(37,770,609)
Capitalization of expenses for issuance of financial debt	(11,282,929)	(8,352,808)	—	—	—	—		(19,635,737)
Gain from bargain purchase for tax purposes	(10,177,907)	1,314,278	—	—	(32,787)	—		(8,896,416)
Price-level adjustment - Argentina	(2,160,549)	1,325,126	—	—	(1,055,585)	(9,635,742)		(11,526,750)
Other Deferred Taxes	(2,601,148)	5,221,979	1	—	—	(332,538)		2,288,294
Deferred tax Assets/(Liabilities)	(17,716,214)	(125,214,920)	1,972,562	16,522,780	5,343,000	(14,046,073)		(133,138,865)


		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$
Depreciations	(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 tax Assets/(Liabilities)	(60,043,617)	67,247,084	(3,387,940)	(20,102,159)	(1,429,582)	(17,716,214)

(i) See Note 5.

(ii) This item corresponds to a reclassification of balances, from Deferred Tax Assets to Recoverable Taxes, due to a higher tax expense for the purposes of closing the 2022 tax return. This higher tax expense is related to higher write-off of trade receivables. The documentation that guarantees tax compliance with these trade receivables was completed during the first quarter of this year.

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Recovery of deferred tax assets will depend on whether sufficient taxable profits are obtained in the future. The Company’s Management believes that the future profit projections for its subsidiaries will allow these assets to be recovered.

As of December 31, 2022 and 2021, the Group has accounted for all deferred tax assets associated with its tax losses (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, 2022, amounts to ThCh$1,029,815,247 (ThCh$1,232,849,769 as of December 31, 2021). 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, 2022, such deductible temporary differences amount to ThCh$1,373,836,286 (ThCh$1,433,966,263 as of December 31,2021).

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 2021.

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, 2022, 2021 and 2020, are as follows:


	2022			2021			2020
Deferred Income Tax Effects on the Components of Other Comprehensive Income	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
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value with movements in other comprehensive income	(2)	1	(1)	31	(8)	23	(9,125)	2,464	(6,661)
Cash flow hedge	147,505,497	(39,826,484)	107,679,013	(406,971,212)	109,882,227	(297,088,985)	267,540,328	(72,741,119)	194,799,209
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	1,043,185	—	1,043,185	359,797	—	359,797	18,982	—	18,982
Foreign currency translation	18,994,934	—	18,994,934	197,099,813	—	197,099,813	(69,218,245)	—	(69,218,245)
Actuarial gains(losses) on defined-benefit pension plans	(7,304,757)	1,972,561	(5,332,196)	12,547,898	(3,387,932)	9,159,966	(8,545,834)	2,308,510	(6,237,324)
Income tax related to components of other income and expenses with a charge or credit in equity	160,238,857	(37,853,922)	122,384,935	(196,963,673)	106,494,287	(90,469,386)	189,786,106	(70,430,145)	119,355,961

The following table shows the reconciliation of deferred tax movements between balance sheet and income taxes in other comprehensive income as of December 31, 2022, 2021 and 2020:


	For the years ended December 31,
	2022	2021	2020
Deferred taxes of components of other comprehensive income	ThCh$	ThCh$	ThCh$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	1,972,562	(3,387,940)	1,923,974
Income tax of movements in cash flow hedge transactions	(39,826,484)	109,882,227	(72,354,119)
Total income tax relating to components of other comprehensive income	(37,853,922)	106,494,287	(70,430,145)

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20. OTHER FINANCIAL LIABILITIES.

The balance of other financial liabilities as of December 31, 2022 and 2021, is as follows:


	Current		Non-current
	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Other financial liabilities	ThCh$	ThCh$	ThCh$	ThCh$
Interest –bearing borrowings	55,977,988	75,182,769	2,138,411,462	1,868,805,671
Hedging derivatives (*)	7,593,354	11,647,944	45,391,794	72,386,037
Non-hedging derivatives (**)	4,948,441	1,509,177	—	682,670
Total	68,519,783	88,339,890	2,183,803,256	1,941,874,378

(*) See Note 23.2.a

(**) See Note 23.2.b

20.1 Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2022 and 2021, is as follows:


	Current		Non-current
	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Classes of Interest-bearing borrowings	ThCh$	ThCh$	ThCh$	ThCh$
Secured bank loans	700,871	25,389,270	251,622,840	—
Unsecured bank loans	926,860	210,122	213,543,720	210,558,388
Unsecured obligations with the public	54,350,257	49,583,377	1,673,244,902	1,658,247,283
Total	55,977,988	75,182,769	2,138,411,462	1,868,805,671

Bank borrowings by currency and contractual maturity as of December 31, 2022 and 2021, are as follows:

Summary of bank borrowings by currency and maturity


					12-31-2022
					Maturity			Maturity
Country	Currency	Effective Interest	Nominal Interest	Secured / Unsecured	One to three months	Three to twelve months	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than Five Years	Total Non-Current
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	5.08%	5.08%	Yes	—	700,871	700,871	—	—	—	20,968,571	230,654,269	251,622,840
Chile	CLP	3.04%	3.04%	No	83	—	83	—	—	—	—	—	—
Chile	US$	4.36%	4.36%	No	595	926,182	926,777	42,616,261	42,548,459	128,379,000	—	—	213,543,720
				Total	678	1,627,053	1,627,731	42,616,261	42,548,459	128,379,000	20,968,571	230,654,269	465,166,560

					12-31-2021
					Maturity			Maturity
Country	Currency	Effective Interest	Nominal Interest	Secured / Unsecured	One to three months	Three to twelve months	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than Five Years	Total Non-Current
		Rate	Rate		ThCh$	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

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Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2022, is ThCh$448,681,529 (ThCh$236,395,400 as of December 31, 2021). 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 debtor


											12-31-2022
											Maturity			Maturity
Taxpayer ID	Company	Country	Taxpayer ID	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	Secured	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Non-current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft facility)	Chile	CLP	6.00%	6.00%	Upon expiration	No	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	—	—	—	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.018.000-1	Overdraft facility (Banco Scotiabank)	Chile	CLP	6.00%	6.00%	Upon expiration	No	—	—	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.036.000-k	Banco Santander	Chile	US$	5.22%	5.22%	Upon expiration	No	—	24,825	24,825	42,616,261	—	—	—	—	42,616,261
76.536.353-5	Enel Chile S.A.	Chile	Foreign	Sumitomo Mitsui Banking Corp.NY	USA	US$	5.70%	5.70%	Upon expiration	No	—	318,451	318,451	—	42,548,459	—	—	—	42,548,459
76.536.353-5	Enel Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	6.29%	6.29%	Upon expiration	No	—	582,906	582,906	—	—	128,379,000	—	—	128,379,000
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	5.17%	5.17%	Annual	Yes	—	314,835	314,835	—	—	—	2,852,867	31,381,533	34,234,400
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	5.28%	5.28%	Annual	Yes	—	80,276	80,276	—	—	—	713,217	7,845,383	8,558,600
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	4.79%	4.79%	Annual	Yes	—	305,760	305,760	—	—	—	17,402,487	191,427,353	208,829,840
76.536.353-5	Enel Chile S.A.	Chile	97.018.000-1	Commitment fee (Scotiabank)	Chile	CLP	0.09%	0.09%	Quarterly	No	80	—	80	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Foreign	Commitment fee (BBVA ES)	Spain	US$	0.25%	0.25%	Quarterly	No	595	—	595	—	—	—	—	—	—
										Total	678	1,627,053	1,627,731	42,616,261	42,548,459	128,379,000	20,968,571	230,654,269	465,166,560


											12-31-2021
											Maturity			Maturity
Taxpayer ID	Company	Country	Taxpayer ID	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	Secured	Less than 90 years ThCh$	More than 90 years ThCh$	Total Current ThCh$	One to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	Non-current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft facility)	Chile	CLP	6.00%	6.00%	Upon expiration	No	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	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.018.000-1	Overdraft facility (Banco Scotiabank)	Chile	CLP	6.00%	6.00%	Upon expiration	No	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.036.000-k	Banco Santander	Chile	US$	5.22%	5.22%	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$	5.70%	5.70%	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$	6.29%	6.29%	Upon expiration	No	—	135,121	135,121	—	—	126,703,500	126,703,500
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	5.17%	5.17%	Annual	Yes	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	5.28%	5.28%	Annual	Yes	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Foreign	European Investment Bank	Luxembourg	US$	4.79%	4.79%	Annual	Yes	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.018.000-1	Commitment fee (Scotiabank)	Chile	CLP	0.09%	0.09%	Quarterly	No	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Foreign	Commitment fee (BBVA ES)	Spain	US$	0.25%	0.25%	Quarterly	No	—	—	—	—	—	—	—
										Total	3	25,599,389	25,599,392	41,944,576	41,910,312	126,703,500	210,558,388

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Table of Contents

20.2 Unsecured liabilities

The detail of unsecured liabilities by currency and maturity as of December 31, 2022 and 2021, is as follows:

Summary of Unsecured liabilities by currency and maturity.

12-31-2022

Maturity

Effective
Interest

Nominal
Interest

Secured

Less
than
90
days

More
than
90
days

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total
Non-Current

Country

Currency

Rate

ThCh$

Chile

US$

7.08%

6.49%

8,801,651

5,273,643

14,075,294

341,190,623

—

175,773,904

930,723,093

1,447,687,620

Chile

6.01%

5.48%

—

40,274,963

40,274,963

39,222,125

68,668,782

225,557,282

Total

8,801,651

45,548,606

54,350,257

380,412,748

39,222,125

214,996,029

999,391,875

1,673,244,902

12-31-2021

Maturity

Effective
Interest

Nominal
Interest

Secured

Less than 90 days

More
than
90
days

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total Non-
Current

Country

Currency

Rate

ThCh$

Chile

US$

7.08%

6.49%

8,686,780

5,204,817

13,891,597

—

335,926,442

—

1,089,748,792

1,425,675,234

Chile

6.01%

5.48%

—

35,691,780

35,691,780

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

1,183,838,593

1,658,247,283

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Table of Contents

-Individual identification of Unsecured liabilities by debtor.


											12-31-2022									12-31-2021
											Maturity			Maturity						Maturity			Maturity
Taxpayer ID	Company	Country	Taxpayer ID	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	Secured	Less than 90 days ThCh$	More than 90 days	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$	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 ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - First issuance S-1	USA	US$	8.00%	7.87%	Upon expiration	No	5,781,737	—	5,781,737	—	—	—	175,773,904	—	175,773,904	5,706,279	—	5,706,279	—	—	—	—	173,387,986	173,387,986
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - First issuance S-2	USA	US$	8.80%	7.33%	Upon expiration	No	1,848,884	—	1,848,884	—	—	—	—	59,583,109	59,583,109	1,824,754	—	1,824,754	—	—	—	—	58,776,668	58,776,668
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - First issuance S-3	USA	US$	8.68%	8.13%	Upon expiration	No	1,171,030	—	1,171,030	—	—	—	—	29,207,740	29,207,740	1,155,747	—	1,155,747	—	—	—	—	28,755,477	28,755,477
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Single 24296	USA	US$	4.67%	4.25%	Upon expiration	No	—	3,071,586	3,071,586	341,190,623	—	—	—	—	341,190,623	—	3,031,498	3,031,498	—	335,926,442	—	—	—	335,926,442
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	—	7,889,718	7,889,718	7,303,084	7,303,084	7,303,084	7,303,084	5,728,650	34,940,986	—	7,047,198	7,047,198	6,446,281	6,446,281	6,446,281	6,446,281	10,683,388	36,468,512
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	—	32,385,245	32,385,245	31,919,041	31,919,041	31,919,041	31,919,041	62,940,132	190,616,296	—	28,644,582	28,644,582	28,174,281	28,174,281	28,174,281	28,174,281	83,406,413	196,103,537
76.536.353-5	Enel Chile S.A.	Chile	Foreign	BNY Mellon - Single	USA	US$	5.24%	4.88%	Upon expiration	No	—	2,202,057	2,202,057	—	—	—	—	841,932,244	841,932,244	—	2,173,319	2,173,319	—	—	—	—	828,828,661	828,828,661
										Total Unsecured Bonds	8,801,651	45,548,606	54,350,257	380,412,748	39,222,125	39,222,125	214,996,029	999,391,875	1,673,244,902	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

20.3 Secured liabilities

As of December 31, 2022 and 2021, 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, 2022, was ThCh$1,785,501,986 (ThCh$2,008,803,043 as of December 31, 2021). 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).

20.4 Hedged debt

The debt denominated in U.S. dollars equivalent to ThCh$1,170,026,521 held by the Group as of December 31, 2022, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThCh$2,379,556,771 as of December 31, 2021) (see Note 3.g.5).

The following table details changes in “Reserve for cash flow hedges” as of December 31, 2022, 2021, and 2020, due to exchange differences:

F-103

Table of Contents


	For the years ended December 31,
	2022	2021	2020
	ThCh$	ThCh$	ThCh$
Balance in hedge reserves (income hedge) at the beginning of the year net	(281,553,799)	(60,345,663)	(189,813,409)
Exchange differences recorded in equity net	(79,982,722)	(248,168,691)	98,288,849
Allocation of exchange differences to income net	47,855,413	26,960,555	31,178,897
Balance in hedge reserves (income hedge) at the end of the year net	(313,681,107)	(281,553,799)	(60,345,663)

20.5 Other information

As of December 31, 2022, the Group has unconditional long-term lines of credit of ThCh$333,551,000 (ThCh$118,469,000 as of December 31, 2021).

20.6 Future Undiscounted debt flows.

The following tables are the estimates of undiscounted flows by type of financial debt:

Summary of secured and unsecured bank borrowings

12-31-2022

12-31-2021

Maturity

Country

Currency

Nominal
Interest
Rate

One
to
three
months

Three
to
twelve
months

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total
Non-current

One
to
three
months

Three
to
twelve
months

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total
Non-current

ThCh$

Chile

US$

4.72%

4,440,158

13,320,472

17,760,630

59,969,992

59,381,559

164,416,712

32,155,498

264,985,598

580,909,359

698,527

27,612,245

28,310,772

2,410,877

44,943,858

44,801,951

129,494,530

—

221,651,216

Chile

CLP

3.04%

—

Total

4,440,161

13,320,472

17,760,633

59,969,992

59,381,559

164,416,712

32,155,498

264,985,598

580,909,359

698,530

27,612,245

28,310,775

2,410,877

44,943,858

44,801,951

129,494,530

—

221,651,216

Summary of Guaranteed and Unsecured bonds

12-31-2022

Maturity

Country

Currency

Nominal
Interest
Rate

One
to
three
months

Three
to
twelve
months

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total
Non-Current

One
to
three
months

Three
to
twelve
months

Total
Current

One
to
two
years

Two
to
three
years

Three
to
four
years

Four
to
five
years

More
than
five
years

Total
Non-current

ThCh$

Chile

US$

6.49%

20,115,546

60,346,639

80,462,185

411,183,992

65,374,889

228,729,357

1,213,353,136

1,984,016,263

20,108,083

60,324,249

80,432,332

80,432,332

411,026,050

65,350,879

1,441,550,517

2,063,710,657

Chile

5.48%

3,438,027

48,772,585

52,210,612

50,193,204

48,175,796

46,158,387

44,140,978

76,708,509

265,376,874

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

Total

23,553,573

109,119,224

132,672,797

461,377,196

113,550,685

111,533,276

272,870,335

1,290,061,645

2,249,393,137

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

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Table of Contents

21. LEASE LIABILITIES

As of December 31, 2022 and 2021, the balance of lease liabilities is as follows:


	Current		Non-Current
Lease liability	12-31-2022 ThCh$	12-31-2021 ThCh$	12-31-2022 ThCh$	12-31-2021 ThCh$
Lease liability	19,020,636	11,105,018	216,664,919	148,557,059
Total	19,020,636	11,105,018	216,664,919	148,557,059

21.1. Individualization of Lease Liabilities


									12-31-2022									12-31-2021
									Maturiry			Maturity						Maturity			Maturity
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	838,089	5,234,124	6,072,213						—	776,668	2,404,736	3,181,404	5,992,962	—	—	—	—	5,992,962
91.081.000-6	Enel Generación Chile S.A.	Chile	10.579.624-2	Marcelo Alberto Amar Basulto	Chile	UF	2.06%	Monthly	3,260	17,450	20,710	23,685	24,173	24,669	25,176	185,955	283,658	4,933	15,092	20,025	20,485	20,906	21,337	21,775	184,656	269,159
91.081.000-6	Enel Generación Chile S.A.	Chile	91.004.000-6	Productos Fernandez S.A.	Chile	UF	2.09%	Monthly	10,952	32,810	43,762	44,546	45,478	46,429	47,399	373,619	557,471	16,794	28,366	45,160	38,515	39,320	40,142	40,982	368,423	527,382
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	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	78.392.580-K	Agricola el Bagual Ltda.	Chile	UF	1.91%	Annual	1,456	—	1,456		—	—	—	—	—	1,285	—	1,285	636	—	—	—	—	636
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	11,529		11,529		—	—	—	—	—	10,176	—	10,176	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	8.992.234-8	Roberto Guzman Borquez	Chile	CLP	1.37%	Monthly	126	1,003	1,129	247	—	—	—	—	247	371	1,114	1,485	1,377	—	—	—	—	1,377
91.081.000-6	Enel Generación Chile S.A.	Chile	19.048.130-1	Yaritza Alexandra Bernal	Chile	UF	1.37%	Monthly	303	1,260	1,563	157	—	—	—	—	157	409	1,232	1,641	1,525	—	—	—	—	1,525
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.643.660-3	Inmobiliaria El Roble S.A.	Chile	UF	1.41%	Monthly	5,757	—	5,757	—	—	—	—	—	—	5,097	—	5,097	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	70.015.730-K	Mutual de Seguros de Chile	Chile	UF	1.91%	Monthly	19,472	59,430	78,902	80,565	82,103	76,188	—	—	238,856	23,270	51,474	74,744	69,779	71,113	72,470	61,449	—	274,811
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.596.523-3	Capital Investi	Chile	UF	1.91%	Monthly	15,908	48,584	64,492	65,861	67,119	62,285	—	—	195,265	19,090	42,080	61,170	57,044	58,134	59,244	50,235	—	224,657
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.253.641-2	Bcycle Latam S.P.A	Chile	CLP	6.24%	Annual	99,528	—	99,528	18,825	—	—	—	—	18,825	79,717	—	79,717	17,719	18,825	—	—	—	36,544
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.203.089-6	Rentas Inmobiliarias Amanecer S.A.	Chile	UF	2.84%	Monthly	15,139	44,972	60,111	62,086	15,912	—	—	—	77,998	5,013	4,754	9,767	—	—	—	—	—	—
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	—	333,555	333,555	75,686	80,216	85,018	90,107	690,878	1,021,905	—	234,086	234,086	70,479	74,698	79,169	83,908	735,553	1,043,807
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	13,245	—	13,245	—	—	—	—	—	—	457,380	285,436	742,816	31,728	—	—	—	—	31,728
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.013.489-9	Inversiones Don Issa Ltda.	Chile	UF	1.77%	Monthly	201,001	80,152	281,153	95,842	37,307	—	—	—	133,149	98,029	115,211	213,240	109,492	77,991	32,930	—	—	220,413
96.800.570-7	Enel Distribución Chile S.A.	Chile	99.530.420-1	Inmobiliaria Nialem S.A.	Chile	UF	0.40%	Monthly	52,217	156,955	209,172	210,003	52,631	—	—	—	262,634	45,910	137,991	183,901	184,630	185,366	46,457	—	—	416,453
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.164.095-K	Inmobiliaria Mixto Renta Spa	Chile	UF	3.78%	Monthly	31,854	96,080	127,934	10,849	—		—	—	10,849	9,607	—	9,607	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2.99%	Annual	2,101,460	7,156,814	9,258,274	3,607,599	3,579,837	3,692,707	3,810,023	180,754,898	195,445,064	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
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	121,131	—	121,131	89,622	91,899	94,234	96,629	1,503,967	1,876,351	250,639	—	250,639	77,502	79,471	81,490	83,561	1,419,297	1,741,321
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4.94%	Annual	36,953	—	36,953	8,591	9,015	9,460	9,928	213,406	250,400	16,532	—	16,532	7,259	7,618	7,994	8,389	198,038	229,298
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4.94%	Annual	22,963	—	22,963	11,329	11,888	12,476	13,093	261,071	309,857	21,470	—	21,470	9,572	10,045	10,542	11,063	242,741	283,963
76.412.562-2	Enel Green Power Chile S.A.	Chile	4.595.479-K	Adriana Castro Parra	Chile	UF	4.94%	Annual	75,539	—	75,539	18,465	19,378	20,336	21,342	395,302	474,823	74,019	—	74,019	15,602	16,374	17,183	18,033	369,450	436,642
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.378.630-5	Agricola Santa Amalia	Chile	UF	4.94%	Annual	33,399	—	33,399	18,465	19,378	20,336	21,342	395,302	474,823	33,913	—	33,913	15,602	16,374	17,183	18,033	369,450	436,642
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.894.990-3	Orafti Chile S.A.	Chile	UF	4.94%	Annual	25,055	—	25,055	8,797	9,233	9,689	10,168	199,524	237,411	16,954	—	16,954	7,434	7,801	8,187	8,592	186,308	218,322
76.412.562-2	Enel Green Power Chile S.A.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4.94%	Annual	112,261	—	112,261	55,829	58,589	61,486	64,526	1,324,643	1,565,073	107,386	—	107,386	47,172	49,504	51,952	54,521	1,231,819	1,434,968
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	EUR	5.02%	Annual	—	1,043,226	1,043,226	209,571	220,089	231,135	242,735	2,076,728	2,980,258	—	1,050,760	1,050,760	209,159	219,656	230,680	242,258	2,431,078	3,332,831
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	67,213	24,583	91,796	50,505	52,343	54,247	56,221	1,305,833	1,519,149	85,721	21,033	106,754	43,211	44,784	46,414	48,103	1,207,776	1,390,288
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	—	77,088	77,088	46,997	48,378	49,800	51,264	1,102,981	1,299,420	—	76,729	76,729	40,483	41,673	42,898	44,159	1,023,505	1,192,718
76.412.562-2	Enel Green Power Chile S.A.	Chile	76.064.627-K	Fortestal Danco	Chile	UF	2.42%	Annual	—	69,487	69,487	37,734	38,646	39,580	40,536	2,059,587	2,216,083	—	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	4.35%	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
76.412.562-2	Enel Green Power Chile S.A.	Chile	96.629.120-6	Agricola Esmeralda	Chile	UF	5.24%	Annual	—	50,365	50,365	15,217	16,014	16,852	17,735	1,665,050	1,730,868	—	—	—	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	84.810.200-8	Huertos Carmen Sociedad Agrícola Limitada	Chile	US$	3.56%	Annual	—	23,269	23,269	5,355	—	—	—	—	5,355	—	—	—	—	—	—	—	—	—
76.126.507-5	Parque Eólico Talinay Oriente S.A.	Chile	76.248.317-3	Agricola Alto Talinay	Chile	EUR	4.61%	Annual	405,871	—	405,871	249,914	261,435	273,487	286,095	2,408,039	3,478,970	427,121	—	427,121	250,397	261,940	274,015	286,647	2,823,778	3,896,777
76.536.353-5	Enel Chile S.A.	Chile	96.565.580-8	Compañia de Leasing Tattersall S. A.	Chile	UF	0.10%	Monthly	3,288		3,288	—	—	—	—	—	—	4,339	4,338	8,677	498	—	—	—	—	498
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		4,469,429	14,551,207	19,020,636	5,122,342	4,841,061	4,880,414	4,904,319	196,916,783	216,664,919	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

21.2. Undiscounted debt cash flows.


			12-31-2022									12-31-2021
			Maturity			Maturity						Maturity			Maturity
Country	Currency	Nominal Interest Rate	One to three months	Three to twelve months	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	One to three months	Three to twelve months	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	5.35%	929,732	5,585,516	6,515,248	169,484	137,273	137,063	150,852	882,065	1,476,737	930,191	3,228,385	4,158,576	6,452,784	281,183	270,895	260,606	1,714,465	8,979,933
Chile	EUR	4.82%	445,609	—	445,609	843,610	813,686	783,763	753,839	2,081,974	5,276,872	418,674	—	418,674	660,889	638,249	615,610	592,971	2,145,489	4,653,208
Chile	UF	2.96%	3,303,831	12,202,205	15,506,036	14,971,118	14,502,444	14,159,140	13,784,036	304,466,585	361,883,323	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
Chile	CLP	3.81%	100,844	18,975	119,819	15,421	-	—	—	—	15,421	74,988	1,142	76,130	22,841	20,252	-	—	—	43,093
Total			4,780,016	17,806,696	22,586,712	15,999,633	15,453,403	15,079,966	14,688,727	307,430,624	368,652,353	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

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22. 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, in the business risk identification, analysis, evaluation, treatment, and communication processes the business addresses on a continuous basis. 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. The Enel Group has a risk taxonomy for the entire Group which considers 6 risk macro-categories: financial; strategic; governance and culture; digital technology; compliance; and operational; and 38 risk sub-categories to identify, analyze, assess, evaluate, treat, monitor and communicate their risks.

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.

22.1 Interest rate risk

Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

The Group’s financial debt structure per fixed and/or hedged interest rate on gross, net of hedging derivative instruments engaged, is as follows:


	For the years ended December 31,
	2022	2021
	%	%
Fixed interest rate	84%	82%

This ratio only considers debt transactions between third parties and Enel Finance International, if any.

Depending on the Group’s estimates and the objectives of the debt structure, hedging transactions are performed 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.

It is public knowledge that LIBOR will be gradually discontinued by June 30, 2023, and the market consensus is that it will be substituted by the SOFR reference rate, which is a risk-free rate.

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The Enel Chile Group has analyzed the potential impacts of this reform, which includes an identification of the contracts affected, an analysis of relevant clauses, and a work plan to adapt and update the documentation to new market standards. Additionally, in order to anticipate for this reform, all new financial operations signed by Enel Chile have been governed by the new SOFR reference interest rate.

However, this does not eliminate some potential risks inherent to the new reference rate adaptation process, such as a potential increase or decrease in the post-change interest rate, risk related to the availability of new rate data, operational risk derived from the need to adapt our new systems to the new reference, etc.

As of December 31, 2022, our total exposure to LIBOR debt is US$ 540 million (ThCh$462,164,400) and includes allowances for the transition from LIBOR to an alternative reference rate. Additionally, we have coverage through derivative instruments that reference LIBOR and mature after June 2023, in the amount of US$ 50 millions (ThCh$42,793,000), considering transition provisions according to the market standard.

22.2 Exchange rate risk

Exchange rate risks involve basically the following transactions:

Debt taken on by the Group’s companies that is denominated in a currency other than the currency in which its cash flows are indexed.

Payments to be made in a currency other than the one to which its cash flows are indexed, for example, for the acquisition of materials associated with projects and payments of corporate insurance policies, among others.

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.

During the fourth quarter of 2022, exchange rate risk management continued in the context of complying with the aforementioned risk management policy, without difficulty to access the derivatives market.

22.3 Commodities risk

The Group has a risk exposure to price fluctuations in certain commodities, basically due to:

-Purchases of fuel used to generate electricity.

-Energy purchase/sale transactions that take place in local markets.

To reduce the risk in situations of extreme drought, the Group has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year. It also includes risk mitigation terms in certain contracts with unregulated customers and with regulated customers subject to long-term tender processes, establishing indexation polynomials that allow for reducing commodities exposure risk.

Considering the operating conditions faced by the power generation market, with drought and highly volatile commodity prices on international markets, the Company is constantly evaluating the use of hedging to minimize the impacts that these price fluctuations have on its results.

As of December 31, 2022, there were Brent hedges on purchases for 450 Kbbl to be settled in 2023. There were also two hedges on gas commodities: a) the 2.7 TBtu HH Swap on sales to be settled in 2023; and b) the 18.9

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TBtu HH Future on purchases to be settled in 2023. There was also a hedge on purchases of 175.6 kTon of coal to be settled in 2023. As of December 31, 2021, there were Brent hedges on 1,930 Kbbl to be settled in 2022 and HH hedges on 9.1 TBtu to be settled in 2022.

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 the volatility of commodity prices on the results of the fourth quarter of 2022.

22.4 Liquidity risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

Despite having negative working capital at the end of 2022, the Company has the capacity to overcome this situation and mitigate the risk through its liquidity risk policy and actions described herein.

The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives see Notes 20, 21 and 23.

As of December 31, 2022, the Group recorded liquidity in the amount of ThCh$875,213,699 in cash and cash equivalents and ThCh$333,551,000 in unconditionally available long-term lines of credit. As of December 31, 2021, the Group recorded liquidity of ThCh$309,975,140 in cash and cash equivalents and ThCh$118,469,000 in unconditionally available long-term lines of credit.

22.5 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 and during 2021 two extensions to this Law 21,249 were published, which provide exceptional measures on behalf of 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, micro companies, among others). In February 2022, Law No. 21,423 established a payment schedule for all debts arising from the application of Law No. 21. 249 and its extensions, i.e., for debts incurred in the period March 18, 2020, through December 31, 2021, for customers with an average 2021 consumption of less than 250 kWh and who have debt from the period indicated above through February 11, 2022, through which each customer will receive a subsidy in 48 equal monthly installments, with a maximum limit equivalent to 15% of their average monthly billing for the year 2021.

The debt balance that cannot be covered in 48 installments will be absorbed in part (50%) by the company, and the rest will be applied to distribution rates in the pricing process after the 48 installments (installment 49). The collection system started on August 1, 2022. According to circular No. 140129 of September 30, 2022, the customer no longer completely loses its subsidy if its account is not up-to-date, but will lose the monthly subsidy when the account has not been paid 45 days after the due date of the first document in which the subsidy was charged. Therefore, only the proportional installment will be charged as the previous balance until the customer's situation is corrected.

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The Group's portfolio shows, to date, resilience in the face of the global pandemic crisis. This is due to strengthening digital collection channels and solid diversification of commercial customers that have had low exposure to the impact of COVID.

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).

22.6 Risk measurement

The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives in order to monitor the risk assumed by the Company, thereby reducing volatility in the income statement.

The portfolio of positions included for purposes of calculating the present VaR include:

Financial debt.

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:

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$602,754,498.

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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23. FINANCIAL INSTRUMENTS

22.1 Financial instruments classified by type and category

The detail of financial assets, classified by type and category, as of December 31, 2022 and 2021, is as follows:


	12-31-2022
	Financial assets at fair value through results	Financial assets measured at amortized cost	Financial assets at fair value through other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Equity instruments	—	—	127,854	—
Trade and other accounts receivable	—	1,602,605,620	—	—
Derivative instruments	1,902,642	—	162,288,499	2,230,787
Other financial assets	—	156,773	—	—
Total Current	1,902,642	1,602,762,393	162,416,353	2,230,787

Equity instruments	—	—	2,326,509	—
Trade and other accounts receivable	—	691,147,645	—	—
Derivative instruments	20,382	—	—	57,480,749
Total Non-current	20,382	691,147,645	2,326,509	57,480,749
Total	1,923,024	2,293,910,038	164,742,862	59,711,536

	12-31-2021
	Financial assets at fair value through results	Financial assets measured at amortized cost	Financial assets at fair value through 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

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The detail of financial liabilities, classified by type and category, as of December 31, 2022 and 2021, is as follows:


	12-31-2022
	Financial liabilities at fair value through results	Financial liabilities measured at amortized cost	Financial liabilities at fair value through other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	55,977,988	—	—
Trade and other accounts payable	—	2,632,538,771	—	—
Derivative instruments	14,965,265	—	46,937,977	7,593,354
Other financial liabilities	—	19,020,636	—	—
Total Current	14,965,265	2,707,537,395	46,937,977	7,593,354

Interest-bearing loans	—	2,138,411,462	—	—
Trade and other accounts payable	—	1,455,405,575	—	—
Derivative instruments	—	—	—	45,391,794
Other financial liabilities	—	216,664,919	—	—
Total Non-current	—	3,810,481,956	—	45,391,794
Total	14,965,265	6,518,019,351	46,937,977	52,985,148

	12-31-2021
	Financial liabilities at fair value through results	Financial liabilities measured at amortized cost	Financial liabilities at fair value through other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	75,182,769	—	—
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	2,064,339,184	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	5,561,158,423	3,396,389	84,033,980

The carrying value of trade receivables and payables approximates their fair value.

23.2 Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Company classifies its hedges as follows:

Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

Fair value hedges: Those that hedge the fair value of the underlying hedged item.

Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedging instruments are recognized at fair value through profit or loss (financial assets held for trading).

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Assets and liabilities for hedge derivative instruments

As of December 31, 2022 and 2021, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:

12-31-2022

12-31-2021

Assets

Liabilities

Assets

Liabilities

Current

Non-current

Current

Non-current

Current

Non-current

Current

Non-current

ThCh$

Interest rate hedge:

21,188

2,629,290

—

432,151

6,532,657

—

Cash flow hedge

21,188

2,629,290

—

432,151

6,532,657

—

Exchange rate hedge:

2,209,599

54,851,459

7,593,354

45,391,794

3,584,937

36,588,771

5,115,286

72,386,037

Cash flow hedge

2,209,599

54,851,459

7,593,354

45,391,794

3,584,937

36,588,771

5,115,286

72,386,037

Total

2,230,787

57,480,749

7,593,354

45,391,794

3,584,937

37,020,922

11,647,943

72,386,037

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	12-31-2022	12-31-2021	of
instrument	risk	item	ThCh$	ThCh$	risk hedged
SWAP	Exchange rate	Unsecured Obligations (Bonds)	8,260,069	(37,402,977)	Cash flow
SWAP	Interest rate	Loans with Related Companies	2,650,478	(6,100,506)	Cash flow
FORWARD	Exchange rate	Operational Income	2,606,439	(4,285,349)	Cash flow
FORWARD	Exchange rate	Property, plant & equipment investment	(1,592,476)	3,278,444	Cash flow
FORWARD	Exchange rate	Other	(5,198,122)	1,082,267	Cash flow

As of December 31, 2022 and 2021, 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.

Financial derivative instruments assets and liabilities at fair value through profit or loss

As of December 31, 2022 and 2021, 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:

12-31-2022

12-31-2021

Current
Assets

Current
Liabilities

Non-Current
Assets

Non-Current
Liabilities

Current
Assets

Current
Liabilities

Non-Current
Assets

Non-Current
Liabilities

ThCh$

Non-hedging derivative instrument

1,014,802

4,948,441

20,382

—

210,077

1,509,177

—

682,670

Total

1,014,802

4,948,441

20,382

—

210,077

1,509,177

—

682,670

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.

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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, 2022 and 2021:

12-31-2022

Notional Amount

Fair value

Less than 1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Financial derivatives

ThCh$

Interest rate hedge:

2,650,478

—

42,793,000

—

42,793,000

Cash flow hedge

2,650,478

—

42,793,000

—

42,793,000

Exchange rate hedge:

4,075,910

322,052,096

364,502,500

53,674,459

—

740,229,055

Cash flow hedge

4,075,910

322,052,096

364,502,500

53,674,459

—

740,229,055

Derivatives not designated for hedge accounting

(3,913,257)

480,643,867

409,241

—

481,053,108

Total

2,813,131

802,695,963

407,704,741

53,674,459

—

1,264,075,163

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$

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

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.

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23.3 Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 3.h.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2022 and 2021:


		Fair Value Measured at End of Reporting Period Using:
	12-31-2022	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	59,711,536	—	59,711,536	—
Financial derivatives not designated for hedge accounting	1,035,184	—	1,035,184	—
Derivatives of commodities designated as non-hedging of cash flow at fair value through profit or loss	887,840	—	887,840	—
Derivatives of commodities designated as cash flow hedges at fair value through other comprehensive income	162,288,498	—	162,288,498	—
Equity instruments at fair value through other comprehensive income	2,454,363	2,326,509	127,854	—
Total	226,377,421	2,326,509	224,050,912	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	52,985,148	—	52,985,148	—
Financial derivatives not designated for hedge accounting	4,948,441	—	4,948,441	—
Derivatives of commodities designated as cash flow hedges at fair value through profit or loss	10,016,824	—	10,016,824	—
Derivatives of commodities designated as cash flow hedges at fair value through other comprehensive income	46,937,977	—	46,937,977	—
Total	114,888,390	—	114,888,390	—


		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 through other comprehensive income	14,620,453	—	14,620,453	—
Equity instruments at fair value through 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 through profit or loss	2,333,911	—	2,333,911	—
Derivatives of commodities designated as cash flow hedges at fair value through other comprehensive income	3,396,389	—	3,396,389	—
Total	91,956,127	—	91,956,127	—

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24. CURRENT AND NON-CURRENT PAYABLES

The detail of trade and other current payables as of December 31, 2022 and 2021 is as follows:


	Current		Non-current
	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Trade payables	ThCh$	ThCh$	ThCh$	ThCh$
Energy suppliers (1)	504,236,945	237,889,432	308,013,985	175,580,989
Fuel and gas suppliers	236,836,190	86,288,004	—	—
Payables for goods and services	354,236,627	193,170,873	487	487
Payables for assets acquisition	443,512,746	396,820,422	161,040	3,730,996
Subtotal Trade Payables	1,538,822,508	914,168,731	308,175,512	179,312,472
Other Payables
Dividends payable to third parties	150,050,339	18,090,436	—	—
Accounts payables to employees	43,184,467	39,207,096	—	—
Other payables	11,835,595	6,858,224	133,350	84,940
Subtotal other current payables	205,070,401	64,155,756	133,350	84,940
Total	1,743,892,909	978,324,487	308,308,862	179,397,412

(1)The non-current portion shows delays in payments for energy purchases of ThCh$308,013,985 as of December 31, 2022, and ThCh$174,373,938 as of December 31, 2021, generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 9).

The description of the liquidity risk management policy is detailed in Note 22.4.

The details of trade payables, both current and past due as of December 31, 2022 and 2021, are presented in Appendix 3.

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25. PROVISIONS

The detail of provisions as of December 31, 2022 and 2021, is detailed as follows:


	Current		Non-current
	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Provision for legal proceedings (1)	1,386,074	1,264,710	15,718,485	13,149,618
Decommissioning or restoration (2)	19,307,862	13,375,095	172,703,975	173,341,364
Other provisions (3)	2,208,070	5,116,512	1,047,783	7,621,732
Total	22,902,006	19,756,317	189,470,243	194,112,714

(1)

See Note 36.3.

(2)

See Note 3.a.

(3)

As of December 31, 2022, this item includes an amount of ThCh$196,131 (ThCh$3,434,242 as of December 31, 2021) is included at short term, and ThCh$397,772 (ThCh$4,042,759 as of December 31, 2021) 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.

Movements in provisions as of December 31, 2022 and 2021 , 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, 2022	14,414,328	186,716,459	12,738,244	213,869,031
Increase (decrease) in existing provisions (1)	11,224,282	11,059,100	(1,697,843)	20,585,539
Provisions used	(7,178,867)	(16,548,540)	(7,250,696)	(30,978,103)
Reversal of unused provision	(1,300,906)	—	—	(1,300,906)
Increase from adjustment to time value of money (2)	—	11,338,594	—	11,338,594
Conversion Difference Foreign Currency Exchange	(54,278)	(72,347)	8,032	(118,593)
Other Increase (Decrease) (3)	—	(481,429)	(541,884)	(1,023,313)
Total movements in provisions	2,690,231	5,295,378	(9,482,391)	(1,496,782)
Balance as of December 31, 2022	17,104,559	192,011,837	3,255,853	212,372,249

	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 (4)	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

(1)

As of December 31, 2022, the increase in provisions for decommissioning or restoration for the year is mainly due to the decrease in interest rates during the period.

(2)

Corresponds to a financial update, see Note 34.

(3)

See Note 5.

(4)

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.

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26. POST-EMPLOYMENT BENEFIT OBLIGATIONS.

26.1 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.

26.2 Details, changes and presentation in financial statements:

The post-employment obligations associated with defined benefits plans and the related plan assets as of December 31, 2022 and 2021, are as follows:


	12-31-2022	12-31-2021
	ThCh$	ThCh$
Employee severance indemnities	42,264,281	39,469,461
Complementary Pension	14,971,439	14,349,089
Health Plans	2,545,406	2,459,163
Energy Supply Plans	2,918,289	2,673,873
Total post-employment obligations, net	62,699,415	58,951,586

The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2022, 2021 and 2020:


	For the years ended December 31,
Expense Recognized in	2022	2021	2020
Comprehensive Income	ThCh$	ThCh$	ThCh$
Cost of current defined benefit plan service	(1,362,838)	(1,099,554)	(2,132,231)
Defined benefit plan interest cost (1)	(3,072,155)	(1,818,983)	(2,146,386)
Past service cost	(31,456)	—	—
Expenses recognized in Profit or Loss	(4,466,449)	(2,918,537)	(4,278,617)
Gains (losses) from remeasurement of defined benefit plans	(7,304,757)	12,547,898	(8,545,834)
Total expense recognized in the Statement of Comprehensive Income	(11,771,206)	9,629,361	(12,824,451)

(1) See Note 34

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The balance and movements in post-employment defined benefit obligations as of December 31, 2022 and 2021, are as follows:


Actuarial Value of Post-employment Obligations		ThCh$
Balance as of January 1, 2021		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
Balance as of December 31, 2021		58,951,586
Current service cost		1,362,838
Interest cost		3,072,155
Actuarial (gains) losses from changes in financial assumptions		749,038
Actuarial (gains) losses from changes in experience adjustments		6,555,719
Foreign currency translation		1,274
Past service cost of defined benefit plan obligation		31,456
Decreases to be classified as held for sale (1)		(1,440,044)
Contributions paid		(6,890,911)
Transfer of employees		306,304
Closing balance December 31, 2022		62,699,415

(1)See Note 5.

26.3 Other disclosures:

•

Actuarial assumptions:

December 31, 2022 and 2021, the following assumptions were used in the actuarial calculation of defined benefit plans:


	12-31-2022	12-31-2021
Discount rates used	5.40%	5.60%
Expected rate of salary increases	3.80%	3.80%
Turnover rate	6.50%	6.90%
Mortality tables	CB-H-2014 and RV-M-2014	CB-H-2014 and RV-M-2014

•

Sensitivity:

As of December 31, 2022, 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$3,962,426 (ThCh$3,746,630 as of December 31, 2021) if the rate rises and an increase of ThCh$4,395,042 (ThCh$4,085,134 as of December 31, 2021) if the rate falls.

•

Defined contribution:

According to the available estimate, the disbursements foreseen to cover the defined benefit plans for 2022 amount to ThCh$7,299,923.

•

Length of commitments

Enel Chile´s obligations have a weighted average length of 7.04 years and the outflows of benefits for the next 10 years is expected to be as follows:


Years		ThCh$
1		7,299,923
2		6,126,642
3		6,040,121
4		5,747,857
5		5,647,068
6 to 10		27,966,288

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27. EQUITY

27.1.Equity attributable to the owners of Enel Chile

27.1.1. Subscribed and paid capital and number of shares

The issued capital of Enel Chile for the years ended December 31, 2022 and 2021, is ThCh$3,882,103,470 divided into 69,166,557,220 authorized, subscribed, and paid shares. All 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).

27.2 Dividends


Dividend No.	Type of Dividend	Agreement date	Payment Date	Total Amount ThCh$	CLP per Share	Charged to Fiscal
6	Provisional	11-29-2018	01-25-2019	31,288,371	0.45236	2018
7	Definitive	04-29-2019	05-17-2019	185,737,592	2.68537	2018
8	Provisional	11-26-2019	01-31-2020	30,933,437	0.44723	2019
9	Definitive	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	Provisional	11-26-2021	01-28-2022	7,260,512	0.10497	2021
12	Definitive	04-27-2022	05-27-2022	18,285,678	0.26437	2021
13	Provisional	11-25-2022	01-27-2023	22,416,356	0.32409	2022

(1)

On April 29, 2020, the distribution of the obligatory minimum dividend (final dividend No. 9) was agreed upon, with charge to the profit for 2019. Additionally, and to offset the resulting impairment of the subsidiary Enel Generación Chile in 2019 (see Note 16.c.iv, Development during 2019), the distribution of a provisional dividend 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 16.c.iv, Development during 2020).

27.3 Foreign currency translation reserves

The detail by company of the translation differences attributable to owners of the Group of the consolidated statement of financial position as of December 31, 2022, 2021, and 2020, is as follows:


	For the years ended December 31,
	12-31-2022	12-31-2021	12-31-2020
Reserves for Accumulated Currency Translation Differences	ThCh$	ThCh$	ThCh$
Enel Generación Chile S.A.	(4,083,680)	(7,729,810)	(7,746,933)
GNL Chile S.A.	1,459,238	1,598,641	907,869
Grupo Enel Green Power Chile	299,328,951	285,686,490	110,921,404
Enel X AMPCI Ebus Chile SpA	—	246,142	(432,247)
TOTAL	296,704,509	279,801,463	103,650,093

27.4 Restrictions on subsidiaries transferring funds to the parent

Our subsidiary Enel Generación Chile must comply with certain financial ratios or covenants, which require a minimum level of equity or contain other characteristics that restrict the transfer of assets to the Parent Company. As of December 31, 2022 and 2021, the Company’s interest in the net restricted assets of Enel Generación Chile was ThCh$712,519,037.

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27.5 Other reserves

Other reserves for the years ended December 31, 2022, 2021 and 2020, are as follows:


	01-01-2022	2022 Changes	12-31-2022
Detail of other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	279,801,463	16,903,046	296,704,509
Cash flow hedges	(391,523,134)	98,354,257	(293,168,877)
Financial assets at fair value through other comprehensive income	1,804	(2)	1,802
Other miscellaneous reserves	(2,275,701,545)	12,828,719	(2,262,872,826)
TOTAL	(2,387,421,412)	128,086,020	(2,259,335,392)

	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 through 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 through 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)

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 2.9).

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).

Other miscellaneous reserves:

The main items and their effects are the following:


	For the years ended
	2022	2021	2020
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)	18,688,009	13,222,164	11,216,652
Other miscellaneous reserves (vii)	15,007,926	7,645,052	7,020,843
TOTAL	(2,262,872,826)	(2,275,701,545)	(2,278,331,266)

Corporate restructuring reserve (Division): This represents the effect generated by the corporate reorganization of Enersis S.A. (currently Enel Américas), concluded in 2016, whereby 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.

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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.

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.

“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 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.

27.6 Non-controlling Interests

The detail of non-controlling interests as of December 31, 2022, 2021 and 2020, is as follows:


		Non-controlling Interests
		Equity		Profit (Loss)
	12-31-2022	12-31-2022	12-31-2021	2022	2021	2020
Companies	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile S.A.	0.91%	6,227,952	6,178,079	201,180	151,538	749,261
Enel Transmisión Chile S.A. (1)	0.91%	—	1,585,517	441,203	291,934	—
Enel Generación Chile S.A.	6.45%	133,643,846	96,773,030	38,554,346	7,480,423	(10,006,037)
Empresa Eléctrica Pehuenche S.A.	7.35%	12,839,546	10,695,281	13,741,749	7,717,216	6,403,829
Sociedad AgrÍcola de Cameros Ltda.	42.50%	2,305,275	2,120,237	194,687	52,068	230,557
Geotermica del Norte S.A.	15.41%	64,351,911	64,539,697	(1,408,970)	(760,576)	645,440
Empresa Nacional de Geotermia S.A. (2)	0.00%	—	—	—	(5,089)	(515,293)
Parque Eólico Talinay Oriente S.A.	39.09%	72,215,503	66,070,754	5,155,807	609,150	945,454
Others		154,375	661,950	21,529	19,501	20,267
TOTAL		291,738,408	248,624,545	56,901,531	15,556,165	(1,526,522)

(1)See Note 2.4.1.v and 33.

(2)See Note 2.4.1.iii.

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28. REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2022, 2021, and 2020, is as follows:


	For the years ended December 31,
	2022	2021	2020
Revenues	ThCh$	ThCh$	ThCh$
Energy sales	3,555,216,142	2,585,248,169	2,380,736,600

Generation	2,233,369,420	1,489,763,351	1,111,508,158
Regulated customers	822,190,715	532,353,167	480,168,004
Unregulated customers	1,209,931,004	893,147,380	571,587,710
Spot market sales	201,247,701	64,262,804	59,752,444
Distribution	1,321,846,722	1,095,484,818	1,269,228,442
Residential	732,865,039	597,631,419	608,703,250
Business	362,207,598	293,442,712	366,874,872
Industrial	109,083,560	99,516,111	168,931,181
Other consumers (1)	117,690,525	104,894,576	124,719,139

Other sales	716,907,816	156,907,706	58,870,872
Gas sales	671,732,249	129,442,332	38,808,266
Sales of goods and services	45,175,567	27,465,374	20,062,606

Revenue from other services	106,876,132	87,526,529	108,776,845
Tolls and transmission	52,534,938	29,341,568	41,859,311
Metering equipment leases	3,062,728	2,967,964	3,387,302
Services and Business Advisories provided (Public lighting, connections and electrical advisories)	35,353,775	44,126,106	53,121,851
Other services	15,924,691	11,090,891	10,408,381

Total Revenues	4,379,000,090	2,829,682,404	2,548,384,317

	For the years ended December 31,
	2022	2021	2020
Other Income	ThCh$	ThCh$	ThCh$
Income by agreement with Shell (2)	460,714,800	—	—
Commodity derivative income	66,506,258	6,814,747	4,473,463
Regasification service	29,739,775	—	—
Income from insurance claims (insurance)	8,233,249	6,352,546	10,799,437
Compensation from delayed suppliers	3,304,994	—	—
Income from sanctions to users	3,801,165	3,419,398	1,314,193
Temporary leasing of generating facilities	—	686,126	10,662,952
SEC fine revocation	—	1,161,837	—
Other	5,131,532	7,112,477	9,767,835
Total other income	577,431,773	25,547,131	37,017,880

(1)

For the year ended December 31, 2022, it includes revenue from the sale of energy to municipalities of ThCh$38,916,267 (ThCh$37,097,819 and ThCh$35,598,366 as of December 31, 2021 and 2020, respectively); government entities of ThCh$32,527,895 (ThCh$15,986,996 and ThCh$17,334,983 as of December 31, 2021, and 2020, respectively); agricultural companies of ThCh$7,203,781 (ThCh$7,798,059 and ThCh$10,324,464 as of December 31, 2021, and 2020, respectively); public and telecommunications service companies of ThCh$3,148,872 (ThCh$10,624,227 and ThCh$27,014,443 as of December 31, 2021, and 2020, respectively), educational institutions of ThCh$2,309,902 (ThCh$4,121,823 and ThCh$5,749,102 as of December 31, 2021, and 2020, respectively), healthcare services of ThCh$10,397,470 (ThCh$12,142,923 and ThCh$21,407,325 as of December 31, 2021, and 2020, respectively) and other of ThCh$23,186,338 (ThCh$17,122,729 and ThCh$7,290,456 as of December 31, 2021, and 2020, respectively).

(2)

On December 19, 2022, an agreement was signed between our subsidiary Enel Generación Chile and Shell Global Energy Limited Singapore Branch to amend the contract: “LNG Sale and Purchase Agreement”. The

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agreement primarily consists of accepting a reduction of volume from the supplier during the remaining term of the contract in order to maintain the same level of costs and mitigate pricing formula volatility. The price of the agreement (US$ 520 million) was fully paid by Shell Global Energy Limited on December 29, 2022.

29. RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2022, 2021 and 2020:


	For the years ended December 31,
	2022	2021	2020
Raw materials and consumables used	ThCh$	ThCh$	ThCh$
Energy purchases	(1,885,218,041)	(1,296,992,284)	(864,863,454)
Fuel consumption	(587,063,837)	(374,868,794)	(231,176,489)
Gas	(441,848,645)	(251,009,877)	(149,734,219)
Oil (*)	(45,657,067)	(27,576,693)	(6,100,077)
Coal (*)	(99,558,125)	(96,282,224)	(75,342,193)
Energy transmission cost	(295,519,943)	(151,738,224)	(141,539,687)
Gas sales costs	(519,475,247)	(110,831,219)	(34,332,998)
Other variable supplies and services	(112,246,999)	(76,874,883)	(102,533,011)
Total raw materials and consumables used	(3,399,524,067)	(2,011,305,404)	(1,374,445,639)

(*) During 2022, this item includes an impairment loss on coal inventory impairment of ThCh$50,136,749 as a consequence of the closure of the Bocamina II plant (ThCh$45,904,847 in 2021). For the same reason, adjustments due to impairment of diesel were also recorded for ThCh$1,076,839 (ThCh$667,298 in 2021). For further information see Note 11 and Note 16.c.iv.

30. EMPLOYEE BENEFITS EXPENSE

The detail of employee expenses for the years ended December 31, 2022, 2021, and 2020, is as follows:


	For the years ended December 31,
	2022	2021	2020
Employee Benefits Expense	ThCh$	ThCh$	ThCh$
Wages and salaries	(141,118,974)	(129,759,535)	(117,220,406)
Post-employment benefit obligations expense	(1,394,294)	(1,099,554)	(2,132,231)
Social security and other contributions	(14,545,508)	(13,059,172)	(12,346,828)
Other employee expenses (*)	(1,180,617)	(19,426,893)	(5,527,283)
Total Employee Benefits Expenses	(158,239,393)	(163,345,154)	(137,226,748)

(*) 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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31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSS OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9

The detail of depreciation and amortization for the years ended December 31, 2022, 2021, and 2020, is as follows:


	For the years ended December 31,
	2022	2021	2020
	ThCh$	ThCh$	ThCh$
Depreciation	(215,986,710)	(198,700,349)	(215,581,938)
Amortization	(22,286,241)	(12,227,307)	(14,375,081)
Total	(238,272,951)	(210,927,656)	(229,957,019)

The detail of the items related to impairment for the years ended December 31, 2022, 2021, and 2020, is as follows:


	For the years ended December 31,
	Generation			Distribution and Transmission			Other			Total
	2022	2021	2020	2022	2021	2020	2022	2021	2020	2022	2021	2020
Information on Impairment Losses by Reportable Segment	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Non-current assets held for sale (1)	(2,286,438)	—	—	—	—	—	—	—	—	(2,286,438)	—	—
Intangibles	—	—	(217,658)	—	—	—	—	—	—	—	—	(217,658)
Property, Plant and Equipment (2)	—	(33,035,731)	(698,235,380)	—	—	—	—	—	—	—	(33,035,731)	(698,235,380)
Investment Property (3)	—	—	—	—	—	—	738,739	136,877	646,597	738,739	136,877	646,597
Total Reversal of impairment losses (impairment losses) recognized in profit or loss	(2,286,438)	(33,035,731)	(698,453,038)	—	—	—	738,739	136,877	646,597	(1,547,699)	(32,898,854)	(697,806,441)
Impairment gain and reversals from impairment losses (impairment losses) in accordance with IFRS 9 (4)	(1,992,280)	(691,132)	(1,305,341)	(20,030,616)	(17,419,025)	(12,998,719)	(2,458)	(655,018)	(863,647)	(22,025,354)	(18,765,175)	(15,167,707)

(1)See Note 5.

(2)See Note 16.iv and vi.

(3)See Note 17.

(4)See Note 9.d).

32. OTHER EXPENSE, BY NATURE

Other miscellaneous operating expense for the years ended December 31, 2022, 2021, and 2020, are detailed as follows:


	For the years ended December 31,
	2022	2021	2020
Other Expenses by nature	ThCh$	ThCh$	ThCh$
Professional, outsourced and other services	(83,023,012)	(74,650,311)	(74,630,728)
Write-off of property, plant and equipment (1)	(52,799,997)	—	—
Repairs and maintenance	(50,001,947)	(43,670,583)	(49,051,950)
Insurance premiums	(24,551,805)	(23,487,377)	(19,992,385)
Environmental expenses	(10,091,657)	(7,998,327)	(8,313,182)
Administrative expenses	(9,895,827)	(9,072,602)	(7,214,238)
Taxes and charges	(6,773,397)	(6,316,351)	(5,675,978)
Leases and rental costs	(5,436,911)	(3,790,971)	(4,958,760)
Marketing, public relations and advertising	(2,991,329)	(1,971,879)	(2,491,884)
Travel expenses	(3,197,752)	(1,220,870)	(2,223,358)
Indemnities and fines	(354,539)	(76,693)	(1,029,517)
Other supplies and services	(19,916,674)	(17,294,861)	(15,011,354)
Total	(269,034,847)	(189,550,825)	(190,593,334)

(1)See explanation in Note 16 c) v).

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33. OTHER GAINS (LOSSES)

The detail of other gains (loss) for the years ended December 31, 2022, 2021 and 2020 is as follows:


	For the years ended December 31,
	2022	2021	2020
Other Gains (Losses)	ThCh$	ThCh$	ThCh$
Gain on sale of Enel Transmisión Chile S.A. (1)	981,856,639	—	—
Result in sales of property, plant and equipment	810,776	—	9,384,038
Gain on sale of Transmisora Eléctrica de Quillota Ltda. (2)	—	9,968,845	—
Loss on sale of Enel X AMPCI Ebus Chile SpA (3)	(788,848)	—	—
Loss on sale of Sociedad de Inversiones K Cuatro SpA (4)	(20,938)	—	—
Result of other investments	123,667	168,439	104,777
Total	981,981,296	10,137,284	9,488,815

(1)See Note 5.2.

(2)See Note 13.3 c).

(3)See Note 2.5.ii.

(4)See Note 13.3 b).

34. FINANCIAL RESULTS

Finance income and costs for the years ended December 31, 2022, 2021, and 2020, are as follows:


	For the years ended December 31,
	2022	2021	2020
Finance Income	ThCh$	ThCh$	ThCh$
Income from deposits and other financial instruments	19,898,958	3,259,801	7,324,057
Interests charged to customers in energy accounts and billing	16,001,236	13,130,196	12,477,393
Financial income by Law No.21,185 (1)	7,455,121	4,802,376	15,328,829
Financial update of decommissioning provisions Bocamina I, II and Tarapacá	1,197,149	4,720,818	—
Financial income by law No.21,340 and No.21,249 (5)	3,833,564	—	—
Other financial income	2,028,557	507,209	1,030,181
Total Financial Income	50,414,585	26,420,400	36,160,460


	For the years ended December 31,
	2022	2021	2020
Finance Costs	ThCh$	ThCh$	ThCh$
Bank loans	(11,590,144)	(2,727,697)	(7,151,030)
Bonds payable to the public not guaranteed	(92,414,063)	(85,990,347)	(84,268,247)
Lease obligations	(6,822,606)	(1,960,901)	(2,128,360)
Valuation of financial derivatives for cash flow hedging	(3,034,351)	(9,327,966)	(5,887,498)
Financial cost by Law No.21,185 (1)	(2,235,708)	(2,409,504)	(4,518,268)
Financial update of provisions (2)	(11,338,594)	(3,048,796)	(4,115,292)
Post-employment benefit obligations (3)	(3,072,155)	(1,818,983)	(2,146,386)
Debt formalization expenses and other associated expenses	(4,822,933)	(5,003,674)	(2,646,906)
Capitalized borrowing costs	83,292,276	61,513,684	33,109,819
Financial cost related companies	(72,780,613)	(42,066,043)	(35,079,947)
Assignment of rights and sale of accounts receivable to customers (4)	(31,626,916)	(49,933,286)	(533,615)
Financial costs by law No.21,340 and No.21,249 (5)	(1,046,173)	(10,345,206)	—
Interest on overdue payments to suppliers	(11,412,536)	(852,435)	—
Trade agreements with customers	(5,090,971)	(13,313,725)	—
Interest taxes remitted abroad	(10,380,979)	(2,829,996)	(3,930,283)
Other financial costs	(9,241,567)	(3,928,241)	(8,112,758)
Total	(193,618,033)	(174,043,116)	(127,408,771)
*Gains or loss from indexed assets and liabilities, net ()**	5,862,890	5,897,520	2,085,768
Foreign currency exchange differences ()**	18,401,453	(15,334,368)	(23,272,231)
Total Finance Costs	(169,353,690)	(183,479,964)	(148,595,234)

Total Financial Results	(118,939,105)	(157,059,564)	(112,434,774)

(1)

Relates to finance income and costs generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 9).

(2)

See Note 25.

(3)

See Note 26.2, b).

(4)

See Note 9, section a.2.

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(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,
	2022	2021	2020
*Gains (losses) from Indexed Assets and Liabilities ()**	ThCh$	ThCh$	ThCh$
Other financial assets	41,683	—	—
Other non-financial assets	12,478,960	64,806	—
Trade and other receivables	3,086,549	1,837,037	2,212,324
Current tax assets and liabilities	4,405,500	4,168,869	1,026,963
Other financial liabilities (Financial Debt and Derivative Instruments)	41,681	2,743,973	980,933
Trade and other payables	(275,114)	(103,883)	241,532
Other provisions	(772,689)	(610,605)	(196,777)
Other non-financial liabilities	—	(101,358)	(643)
Subtotal	19,006,570	7,998,839	4,264,332

Inventories	57,829	20,926	—
Intangible assets other than goodwill	(130,899)	(77,239)	142
Property plant and equipment	2,453,485	1,451,708	764,982
Deferred tax liability	(9,635,742)	(1,429,582)	(548,505)
Equity	(5,842,818)	(2,143,830)	(2,434,384)
Other Provisions of Services	(1,900)	(1,849)	(1,246)
Personal expenses	286,371	161,385	130,213
Other fixed operating expenses	324,911	139,968	108,226
Financial income	(726,557)	(231,931)	(204,137)
Financial expenses	71,640	9,125	6,145
Subtotal Hyperinflation result (1)	(13,143,680)	(2,101,319)	(2,178,564)
Gains from indexed assets and liabilities net	5,862,890	5,897,520	2,085,768

	For the years ended December 31,
	2022	2021	2020
Foreign Currency Exchange Differences ()**	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	(8,613,242)	1,863,916	10,110,166
Other financial assets	13,779,941	8,922,639	6,316,333
Other non-financial assets	(4,278,891)	(5,754,262)	6,086,388
Trade and other receivables (2) and (3)	(12,070,666)	59,815,718	(24,262,013)
Current tax assets and liabilities	475,285	47,239	(4,361,506)
Other financial liabilities (Financial Debt and Derivative Instruments)	28,913,122	(22,271,858)	(10,265,859)
Trade and other payables (2) and (3)	(25,910,351)	(27,326,682)	(1,023,613)
Accounts payable to related entities	34,745,005	(30,778,711)	(4,974,416)
Other non-financial liabilities	(8,638,750)	147,633	(897,711)
Total Foreign Currency Exchange Differences	18,401,453	(15,334,368)	(23,272,231)

(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$14,855,933 and ThCh$(2,940,425), respectively, as of December 31, 2022, (ThCH$51,620,491 and ThCh$(23,048,375)), respectively as of December 31, 2021 and 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 Notes 4.b).(i) and Note 9).

(3)

Contains the exchange effect of the dollarization of trade receivables and payables of ThCh$(10,220,465) and ThCh$3,106,322, respectively, generated by the temporary mechanism for stabilizing electricity prices for customers subject to rate regulation, as established in Law No. 21,472 (see Note 4.b).(ii) and Note 9).

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35. INFORMATION BY SEGMENT

35.1. Basis of segmentation

The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on business and geographical areas of responsibility), and its subsidiaries are engaged in either the generation and the distribution business.

The Group adopted a “bottom-up” approach to determine its reportable segments. The generation and networks 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 Networks Segments: The electricity distribution and network business are comprised of the companies Enel Distribución Chile S.A. and its subsidiary Enel Colina S.A., which operate under an energy distribution concession regime, with service obligations and regulated rates to supply the electricity through their distribution networks to regulated customers.

It should be noted that on December 9, 2022, the Group disposed of its interest in Enel Transmisión Chile, a company belonging to the Distribution and Networks segment until that date. Following the accounting criteria described in note 3.k), the sale of this company did not qualify as a discontinued operation. Therefore, its results up to the sale date are part of the consolidated results of Enel Chile and are included in the results of the Distribution and Networks segment detailed below (see notes 33 (1) and 40).

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 Networks 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 ¹, Total Capex ², Profit for the Year, Total Energy Generation ³, Distribution and Networks⁴, 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:

The nature of the activities: generation on one hand, and distribution and networks on the other;

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;

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

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

¹ Corresponds to Profit (loss) before taxes excluding Depreciation and amortization expense, Impairment recognized in profit or loss, Impairment determined in accordance with IFRS 9, Financial result, Share of profit (loss) of associates and joint ventures accounted for using the equity method and Other gains (losses). This is represented by Gross Operating Income.

² Corresponds to purchases of Property, plant and equipment and Intangible assets.

³ Corresponds to electrical energy generated in power plant units, by technology, eliminating self-consumption in a determined period.

⁴ Corresponds to the amount of electricity distributed, free of any losses, in a determined period.

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capacity to regulated or unregulated customers; and Distribution and Networks 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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35.2 Financial information by business line


	Generation		Distribution and Networks		Holdings and eliminations		Total
	12-31-2022	12-31-2021	12-31-2022	12-31-2021	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
ASSETS
CURRENT ASSETS	1,937,857,990	704,953,231	517,448,833	381,074,530	608,935,496	182,224,732	3,064,242,319	1,268,252,493
Cash and cash equivalents	15,577,716	4,059,117	1,645,018	1,964,579	857,990,965	303,951,444	875,213,699	309,975,140
Other current financial assets	3,328,010	2,747,199	102,529	1,238,240	99,677	55,976	3,530,216	4,041,415
Other current non-financial assets	168,853,772	53,654,303	2,071,666	4,215,329	21,714,914	8,956,365	192,640,352	66,825,997
Trade and other current receivables	941,807,106	319,374,477	498,172,677	344,375,668	69,533,572	24,434,982	1,509,513,355	688,185,127
Current accounts receivable from related companies	686,500,891	262,328,437	3,546,493	11,763,448	(433,778,780)	(217,651,797)	256,268,604	56,440,088
Inventories	48,882,081	25,601,423	4,696,300	2,997,869	24,337,712	2,648,418	77,916,093	31,247,710
Current tax assets	46,194,764	37,188,275	6,555,521	14,519,397	67,808,082	59,829,344	120,558,367	111,537,016
Non-current assets or disposal groups held for sale	26,713,650	—	658,629	—	1,229,354	—	28,601,633	—
NON-CURRENT ASSETS	6,459,003,403	5,869,269,137	1,503,735,962	1,590,778,338	838,598,048	772,023,628	8,801,337,413	8,232,071,103
Other non-current financial assets	57,198,350	38,915,283	—	—	2,629,290	463,782	59,827,640	39,379,065
Other non-current non-financial assets	71,679,797	85,177,306	3,974,661	3,076,764	2,621,883	1,362,578	78,276,341	89,616,648
Trade and other non-current receivables	46,817,168	100,176,330	521,384,397	401,098,758	122,946,080	14,511,252	691,147,645	515,786,340
Non-Current accounts payable from related companies	147,613,887	148,999,820	—	—	(147,613,887)	(142,651,819)	—	6,348,001
Investments accounted for using the equity method	12,792,475	6,095,038	—	—	4,960,303	3,828,895	17,752,778	9,923,933
Intangible assets other than goodwill	107,712,453	101,567,646	76,341,449	82,839,363	7,387,361	6,814,546	191,441,263	191,221,555
Goodwill	34,282,519	34,159,548	2,240,478	2,240,478	847,090,432	884,678,172	883,613,429	921,078,198
Property, plant and equipment	5,715,336,720	5,031,641,934	866,265,376	1,093,444,389	(9,248,102)	(14,397,562)	6,572,353,994	6,110,688,761
Investment property	—	—	—	—	7,348,262	7,539,005	7,348,262	7,539,005
Assets for right of use	231,835,979	156,537,247	2,552,157	4,244,878	(689,704)	6,736	233,698,432	160,788,861
Deferred tax assets	33,734,055	165,998,985	30,977,444	3,833,708	1,166,130	9,868,043	65,877,629	179,700,736

TOTAL ASSETS	8,396,861,393	6,574,222,368	2,021,184,795	1,971,852,868	1,447,533,544	954,248,360	11,865,579,732	9,500,323,596


	Generation		Distribution and Networks		Holdings and eliminations		Total
	12-31-2022	12-31-2021	12-31-2022	12-31-2021	12-31-2022	12-31-2021	12-31-2022	12-31-2021
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES	1,815,369,972	1,160,666,050	707,079,955	746,688,757	646,041,953	224,971,410	3,168,491,880	2,132,326,217
Other current financial liabilities	55,252,071	79,273,121	5,288,702	150,674	7,979,010	8,916,095	68,519,783	88,339,890
Current lease liabilities	17,743,500	9,242,799	1,273,849	1,853,542	3,287	8,677	19,020,636	11,105,018
Trade and other current payables	1,077,964,004	668,905,400	371,911,869	262,862,315	294,017,036	46,556,772	1,743,892,909	978,324,487
Current accounts payable to related companies	607,176,390	373,766,861	315,459,903	465,826,390	23,862,281	165,004,707	946,498,574	1,004,597,958
Other current provisions	22,008,065	17,906,766	180,851	1,266,514	713,090	583,037	22,902,006	19,756,317
Current tax liabilities	21,154,968	2,461,869	944,932	9,202,761	312,236,470	1,484,077	334,336,370	13,148,707
Other current non-financial liabilities	14,070,974	9,109,234	12,019,849	5,526,561	7,230,779	2,418,045	33,321,602	17,053,840
NON-CURRENT LIABILITIES	3,232,461,558	2,688,289,480	629,125,828	371,287,907	446,561,163	961,927,094	4,308,148,549	4,021,504,481
Other non-current financial liabilities	876,704,452	902,487,329	—	—	1,307,098,804	1,039,387,049	2,183,803,256	1,941,874,378
Non-current lease liabilities	214,705,438	145,264,339	1,959,481	3,292,221	—	499	216,664,919	148,557,059
Trade and other non-current payables	267,218	3,788,764	308,041,157	175,608,162	487	486	308,308,862	179,397,412
Non-current accounts payable to related companies	1,742,214,913	1,245,386,779	281,625,788	142,651,760	(876,743,988)	(87,979,442)	1,147,096,713	1,300,059,097
Other long-term provisions	177,512,333	181,398,929	11,957,910	12,319,020	—	394,765	189,470,243	194,112,714
Deferred tax liabilities	201,374,515	192,175,894	—	11,639,461	(2,358,021)	(6,398,405)	199,016,494	197,416,950
Non-current provisions for employee benefits	19,682,689	17,787,446	24,452,845	24,641,998	18,563,881	16,522,142	62,699,415	58,951,586
Other non-current non-financial liabilities	—	—	1,088,647	1,135,285	—	—	1,088,647	1,135,285
EQUITY	3,349,029,863	2,725,266,838	684,979,012	853,876,204	354,930,428	(232,650,144)	4,388,939,303	3,346,492,898
Equity attributable to owners of the parent	3,349,029,863	2,725,266,838	684,979,012	853,876,204	354,930,428	(232,650,144)	4,097,200,895	3,097,868,353
Issued capital	1,270,222,769	1,264,108,957	177,568,664	230,137,980	2,434,312,037	2,387,856,533	3,882,103,470	3,882,103,470
Retained earnings	1,900,047,598	1,455,385,686	778,754,348	946,912,262	(204,369,129)	(799,111,653)	2,474,432,817	1,603,186,295
Issuance premiums	85,511,492	85,511,492	273,307	354,220	(85,784,799)	(85,865,712)	—	—
Other reserves	93,248,004	(79,739,297)	(271,617,307)	(323,528,258)	(1,789,227,681)	(1,735,529,312)	(2,259,335,392)	(2,387,421,412)
Non-controlling interests	—	—	—	—	—	—	291,738,408	248,624,545

Total Liabilities and Equity	8,396,861,393	6,574,222,368	2,021,184,795	1,971,852,868	1,447,533,544	954,248,360	11,865,579,732	9,500,323,596

The Holdings and eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

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	Generation			Distribution and Networks			Holdings and eliminations			Total
	2022	2021	2020	2022	2021	2020	2022	2021	2020	2022	2021	2020
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
REVENUES AND OTHER OPERATING INCOME	3,877,758,513	1,953,287,738	1,577,422,263	1,454,721,924	1,201,833,293	1,382,068,220	(376,048,574)	(299,891,496)	(374,088,286)	4,956,431,863	2,855,229,535	2,585,402,197
Revenues	3,302,181,412	1,934,131,175	1,543,647,794	1,449,144,572	1,193,549,267	1,376,425,433	(372,325,894)	(297,998,038)	(371,688,910)	4,379,000,090	2,829,682,404	2,548,384,317
Energy sales	2,625,836,969	1,803,343,706	1,494,203,779	1,334,971,825	1,103,758,191	1,270,159,653	(405,592,652)	(321,853,728)	(383,626,832)	3,555,216,142	2,585,248,169	2,380,736,600
Other sales	672,104,106	129,626,809	38,825,239	6,719,051	5,347,333	6,601,069	38,084,659	21,936,360	13,444,564	716,907,816	156,910,502	58,870,872
Other services rendered	4,240,337	1,160,660	10,618,776	107,453,696	84,443,743	99,664,711	(4,817,901)	1,919,330	(1,506,642)	106,876,132	87,523,733	108,776,845
Other operating income	575,577,101	19,156,563	33,774,469	5,577,352	8,284,026	5,642,787	(3,722,680)	(1,893,458)	(2,399,376)	577,431,773	25,547,131	37,017,880
RAW MATERIALS AND CONSUMABLES USED	(2,573,293,127)	(1,346,981,551)	(616,852,308)	(1,194,700,166)	(974,857,661)	(1,116,324,483)	368,469,226	310,533,808	358,731,152	(3,399,524,067)	(2,011,305,404)	(1,374,445,639)
Energy purchases	(1,102,539,973)	(660,360,745)	(177,049,909)	(1,139,342,609)	(933,785,293)	(1,060,494,642)	356,664,541	297,153,754	372,681,097	(1,885,218,041)	(1,296,992,284)	(864,863,454)
Fuel consumption	(587,063,837)	(374,868,794)	(231,176,490)	—	—	—	—	—	—	(587,063,837)	(374,868,794)	(231,176,490)
Transportation expenses	(305,760,332)	(159,477,763)	(113,704,101)	(17,909,689)	(12,947,272)	(23,694,571)	28,150,078	20,686,811	(4,141,015)	(295,519,943)	(151,738,224)	(141,539,687)
Other miscellaneous supplies and services	(577,928,985)	(152,274,249)	(94,921,808)	(37,447,868)	(28,125,096)	(32,135,270)	(16,345,393)	(7,306,757)	(9,808,930)	(631,722,246)	(187,706,102)	(136,866,008)
CONTRIBUTION MARGIN	1,304,465,386	606,306,187	960,569,955	260,021,758	226,975,632	265,743,737	(7,579,348)	10,642,312	(15,357,134)	1,556,907,796	843,924,131	1,210,956,558
Other work performed by the entity and capitalized	23,738,963	13,352,715	15,581,738	16,574,703	17,403,271	9,805,315	4,256,019	401,210	152,263	44,569,685	31,157,196	25,539,316
Employee benefits expense	(72,744,313)	(71,617,409)	(65,564,485)	(39,078,134)	(49,357,037)	(37,496,730)	(46,416,946)	(42,370,708)	(34,165,533)	(158,239,393)	(163,345,154)	(137,226,748)
Other expenses, by nature	(195,666,710)	(126,899,337)	(121,366,276)	(77,662,552)	(71,488,295)	(79,580,559)	4,294,415	8,836,807	10,353,501	(269,034,847)	(189,550,825)	(190,593,334)
GROSS OPERATING INCOME	1,059,793,326	421,142,156	789,220,932	159,855,775	123,533,571	158,471,763	(45,445,860)	(22,490,379)	(39,016,903)	1,174,203,241	522,185,348	908,675,792
Depreciation and amortization expense	(183,459,507)	(164,579,061)	(185,479,080)	(56,293,022)	(47,931,057)	(45,583,947)	1,479,578	1,582,462	1,106,008	(238,272,951)	(210,927,656)	(229,957,019)
Impairment losses (reversal of impairment losses) recognized in profit or loss	(2,286,438)	(33,035,731)	(698,453,039)	—	—	—	738,739	136,877	646,598	(1,547,699)	(32,898,854)	(697,806,441)
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9.	(1,992,280)	(691,132)	(1,305,341)	(20,030,616)	(17,419,025)	(12,998,719)	(2,458)	(655,018)	(863,647)	(22,025,354)	(18,765,175)	(15,167,707)
OPERATING INCOME	872,055,101	222,836,232	(96,016,528)	83,532,137	58,183,489	99,889,097	(43,230,001)	(21,426,058)	(38,127,944)	912,357,237	259,593,663	(34,255,375)
FINANCIAL RESULT	(85,132,092)	(62,697,134)	(80,090,891)	(20,577,980)	(11,685,010)	5,929,058	(13,229,033)	(82,677,420)	(38,272,941)	(118,939,105)	(157,059,564)	(112,434,774)
Financial income	13,008,285	8,178,108	15,080,015	29,585,814	19,109,146	22,717,208	7,820,486	(866,854)	(1,636,763)	50,414,585	26,420,400	36,160,460
Cash and cash equivalents	18,295	29,479	597,718	4,038,512	1,093,452	1,562,194	15,842,151	2,136,870	5,164,145	19,898,958	3,259,801	7,324,057
Other financial income	12,989,990	8,148,629	14,482,297	25,547,302	18,015,694	21,155,014	(8,021,665)	(3,003,724)	(6,800,908)	30,515,627	23,160,599	28,836,403
Financial costs	(115,872,168)	(94,212,401)	(59,088,322)	(50,482,680)	(30,325,667)	(17,696,544)	(27,263,185)	(49,505,048)	(50,623,905)	(193,618,033)	(174,043,116)	(127,408,771)
Bank loans	(347,388)	(2,465,972)	(7,112,931)	(184)	—	(33,244)	(11,242,572)	(261,725)	(4,855)	(11,590,144)	(2,727,697)	(7,151,030)
Secured and unsecured obligations	(50,378,424)	(47,518,870)	(47,654,290)	—	—	—	(42,035,639)	(38,471,477)	(36,613,957)	(92,414,063)	(85,990,347)	(84,268,247)
Others	(65,146,356)	(44,227,559)	(4,321,101)	(50,482,496)	(30,325,667)	(17,663,300)	26,015,026	(10,771,846)	(14,005,093)	(89,613,826)	(85,325,072)	(35,989,494)
Income from indexation units	609,680	3,385,938	(703,130)	4,023,279	1,851,124	1,124,304	1,229,931	660,458	1,664,594	5,862,890	5,897,520	2,085,768
Foreign exchange profits (losses)	17,122,111	19,951,221	(35,379,454)	(3,704,393)	(2,319,613)	(215,910)	4,983,735	(32,965,976)	12,323,133	18,401,453	(15,334,368)	(23,272,231)
Positive	167,251,274	89,910,296	120,757,605	43,076,163	67,179,990	20,978,492	193,183,643	178,120,351	(10,034,714)	403,511,080	335,210,637	131,701,383
Negative	(150,129,163)	(69,959,075)	(156,137,059)	(46,780,556)	(69,499,603)	(21,194,402)	(188,199,908)	(211,086,327)	22,357,847	(385,109,627)	(350,545,005)	(154,973,614)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	4,014,081	3,157,673	2,424,250	—	361	—	(732,840)	19,375	1,085,142	3,281,241	3,177,409	3,509,392
Other gains (losses)	935,428	10,137,284	9,478,528	—	2,171,056	10,287	981,045,868	(2,171,056)	—	981,981,296	10,137,284	9,488,815
Gain (loss) from other investments	124,652	10,137,284	94,490	—	2,171,056	10,287	981,045,868	(2,171,056)	—	981,170,520	10,137,284	104,777
Gain (loss) from the sale of assets	810,776	—	9,384,038	—	—	—	—	—	—	810,776	—	9,384,038
Profit (loss) before taxes	791,872,518	173,434,055	(164,204,641)	62,954,157	48,669,896	105,828,442	923,853,994	(106,255,159)	(75,315,743)	1,778,680,669	115,848,792	(133,691,942)
Income tax	(151,330,979)	(24,666,990)	97,419,625	7,698,062	2,275,431	(23,421,217)	(326,063,963)	7,252,901	7,306,699	(469,696,880)	(15,138,658)	81,305,107
PROFIT (LOSS)	640,541,539	148,767,065	(66,785,016)	70,652,219	50,945,327	82,407,225	597,790,031	(99,002,258)	(68,009,044)	1,308,983,789	100,710,134	(52,386,835)

Profit (loss) attributable to	640,541,539	148,767,065	(66,785,016)	70,652,219	50,945,327	82,407,225	597,790,031	(99,002,258)	(68,009,044)	1,308,983,789	100,710,134	(52,386,835)
Profit (loss) attributable to owners of the parent	—	—	—	—	—	—	—	—	—	1,252,082,258	85,153,969	(50,860,313)
Profit (loss) attributable to non-controlling interests	—	—	—	—	—	—	—	—	—	56,901,531	15,556,165	(1,526,522)

	Generation			Distribution and Networks			Holdings and eliminations			Total
	12-31-2022	12-31-2021	12-31-2020	12-31-2022	12-31-2021	12-31-2020	12-31-2022	12-31-2021	12-31-2020	12-31-2022	12-31-2021	12-31-2020
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF CASH FLOWS
Net cash flows from (used in) operating activities	689,196,260	445,854,355	551,979,917	91,074,469	17,684,402	111,689,249	(35,491,916)	(50,645,942)	92,197,032	744,778,813	412,892,815	755,866,198
Net cash flows from (used in) investing activities	(990,157,962)	(604,078,037)	(100,557,328)	(98,077,760)	(85,111,489)	(111,939,127)	1,543,807,101	(47,365,284)	(342,154,935)	455,571,379	(736,554,810)	(554,651,390)
Net cash flows from (used in) financing activities	315,350,620	157,788,515	(469,832,875)	9,965,731	67,203,137	1,578,034	(953,972,710)	68,239,857	340,585,507	(628,656,359)	293,231,509	(127,669,334)

The Holding, and eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

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36. GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS

36.1 Direct guarantees

As of December 31, 2022, Enel Chile had future energy purchase commitments amounting to ThCh$12,862,690,830 (ThCh$7,347,166,465 as of December 31, 2021).

36.2 Indirect guarantees

Debtor

Guarantee

Outstanding balance as of

Contract

Maturity

Creditor of Guarantee

Company

Relationship

Guarantor

Type of Guarantee

Currency

12-31-2022
ThCh$

12-31-2021
ThCh$

B Bond (*)

June 2022

Bond holders Enel Américas´ Bond Program

Enel Américas

Common control

Companies divided from the original debtor Enersis (solidarity debtor Enel Chile)

Joint and several co-signer

2,803,327

Credit opening contract

November 2022

GDN BID Loan

Enel Green Power Chile

Subsidiary

Enel Chile

Guarantor

US$

25,389,270

Credit opening contract

October 2037

European Investment Bank

Enel Chile

Parent

Enel SpA

Guarantor

US$

8,638,876

Credit opening contract

December 2037

European Investment Bank

Enel Chile

Parent

Enel SpA

Guarantor

US$

41,827,120

Total

50,465,996

28,192,597

(*) Upon the demerger of the original issuer, Enersis (currently Enel Américas), and in accordance with the bond indenture, all entities arising from the demerger are liable for the debt, regardless of the fact that that the payment obligation remains in Enel Américas.

36.3 Litigation and arbitration proceedings

1.Enel Chile S.A.

1.1.

In October 2020, Inversiones Tricahue S.A. filed a tort claim 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 claims in the amounts of ThCh$72,558,025 and ThCh$12,431,395, respectively. The evidentiary stage of the case is closed, with some procedures still pending.

1.2.

On August 25, 2021, three investors, Inversiones Inmobiliarias y Asesorías Anaelen Ltda., Inversiones León Obrecht Ltda. and Inversiones Antares Ltda., filed before the 7th Criminal Court of Santiago a criminal complaint (i) for the crime of mismanagement, against the Directors of Empresa Eléctrica Pehuenche S.A. and (ii) for the crime of infringement of the duties of supervision and oversight that generate liability to the legal entity, against Enel Chile. This second criminal claim was based on the allegation that Enel Chile allowed the crime of mismanagement to be committed within it (by Pehuenche as a related company). The complaint was admitted for processing by the 7th Criminal Court of Santiago on August 25, 2021. The Criminal Court 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 March 21, 2022, Inversiones Tricahue S.A. filed a lawsuit against Enel Generación before arbitrator Rafael Gómez Balmaceda, claiming the breach of a settlement agreement dated August 22, 2012, requesting that the breach be judicially declared and requesting that Enel Generación be ordered to pay the fine or penalty clause established in the settlement agreement. This matter has completed the evidentiary stage.

3.Enel Distribución Chile S.A.

3.1.

The National Consumer and User Protection Agency, CONADECUS, filed a class action lawsuit against Enel Distribución 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. The case is presently in the admissibility stage.

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3.2.

The National Consumer Service, SERNAC, filed a lawsuit against Enel Distribución and Empresa Eléctrica Colina for the power outages that occurred between January 29 and February 2, 2021, the amount of which is undetermined. The case is in the reconciliation stage.

3.3.

The Municipality of Recoleta filed an enforcement lawsuit against Enel Distribución 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. The case is in the discussion stage.

3.4.

The National Consumer Service, SERNAC, filed a lawsuit against Enel Distribución for alleged violations related to the contracting of insurance, the amount of which is undetermined. The case is in the reconciliation stage.

3.5.

By means of Exempt Resolution No. 33,646 dated November 23, 2020, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 15,000 UTM (ThCh$917,355) on the basis that Enel Distribución did not include Charges for the Use of the Transmission System in bills issued in April 2020. Enel Distribución filed an appeal for reconsideration against this resolution, which was partially accepted, reducing the fine to 10,000 UTM (ThCh$611,570). On June 29, 2022, an appeal was filed before the Court of Appeals of Santiago, which is pending.

3.6.

By means of Exempt Resolution No. 35,004 dated November 12, 2021, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 35,611 UTM (ThCh$2,177,862) on the basis that Enel Distribución exceeded the maximum values allowed by the current regulations in the continuity indexes at the level of the primary feeders, which constitutes a breach of the supply quality standards. Enel Distribución filed an appeal for reconsideration against this resolution, which was rejected by Exempt Resolution No. 35,282. On June 1, 2022, an appeal for reconsideration was filed before the Court of Appeals of Santiago, which was rejected. A further appeal is pending before the Supreme Court.

3.7.

By means of Exempt Resolution No. 11,897 dated April 22, 2022, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 9,375 UTM (ThCh$573,347) on the basis that Enel Distribución did not comply with the instruction of the National Electric Coordinator. Enel Distribución filed an appeal for reconsideration against this resolution, which was rejected on July 28, 2022. On October 5, 2022, an appeal was filed before the Court of Appeals of Santiago, which was rejected.

3.8.

By means of Exempt Resolution No. 11,969 dated April 26, 2022, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 43,200 UTM (ThCh$2,641,982) on the basis that Enel Distribución exceeded the SAIDI limit in the districts of Independencia, La Cisterna, Lo Espejo, Lo Prado, Maipú and Pedro Aguirre Cerda. Enel Distribución filed an appeal for reconsideration against this resolution, which was rejected. On September 14, 2022, an appeal was filed before the Court of Appeals of Santiago, which is pending.

In relation to the litigation described above, the Enel Chile Group has recorded provisions of ThCh$6,004,761 as of December 31, 2022 (see Note 25). There are other litigation matters 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 litigation risks and, therefore, does not expect additional liabilities other than those already recorded.

Given the characteristics of the risks covered by these provisions, it is not possible to determine a reasonable schedule of payment dates, if any.

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36.4. Financial restrictions

Several debt contracts of the Company, and of some of its subsidiaries include the obligation to comply with certain financial ratios, which is common in contracts of this nature. There are also affirmative and negative covenants that require monitoring of these commitments. In addition, there are restrictions in the sections of events of default that must be fulfilled to avoid acceleration of the debt.

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 past due, 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 past due, 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 past due, 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 past due, 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 past due, 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) and SMBC	Santander Chile, Scotiabank and European Investment Bank	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
Name of financial indicator or 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 past due greater than US$150 million of principal individually.	Debt past due greater than US$150 million of principal individually.	Debt past due greater than US$150 million of principal individually.	Debt past due greater than US$30 million of principal individually.	Debt past due greater than US$50 million of principal individually.
Restriction that must be fulfilled (Range, Value and Unit of measure)	Not have individual debts past due greater than US$150 million.	Not have individual debts past due greater than US$150 million.	Not have individual debts past due greater than US$150 million.	Not have individual debts past due greater than US$150 million.	Not have individual debts past due greater than US$150 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 Distribución Chile
Instrument type with restriction	Series H and M Bonds	Cred. with Fin. Inst.	Cred. with Fin. Inst.
Restriction to be fulfilled by Informant or Subsidiary	Any financial debt held by Enel Generación Chile, for any amount past due, 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 Generación Chile, for any amount past due.	Any financial debt held by Enel Distribución Chile, for any amount past due.
Creditor	Banco Santander (Representative of Bondholders)	Banco Santander Chile	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
Measurement frequency	Quarterly	Quarterly	Quarterly
Calculation mechanism or definition of the indicator or ratio	Debt past due greater than US$50 million of principal individually.	Delinquent debt.	Delinquent debt.
Restriction that must be fulfilled (Range, Value and Unit of measure)	Not have individual debts past due greater than US$50 million.	Not have individual debts past due.	Not have individual debts past due.
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 delinquent debts.
Compliance YES/NO	Yes	Yes	Yes
Accounts used in the calculation of the indicator or ratio	-	-	-

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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	0.30	Ch$2,071,385 million	11.96	US$169.64 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, 2022, 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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36.5. COVID-19 contingency

The Group continues to closely monitor the evolution of COVID-19, and all of the company's efforts are aimed at guaranteeing correct and safe continuity of our operations, while also ensuring the health and safety of our people.

On the other hand, the Company is closely following the potential implications of COVID-19 in areas of interest in order to evaluate, based on specific commercial circumstances and the availability of reliable information, the relevance of the pandemic for the Group's financial position and performance. The main risks identified are related to losses for the impairment of accounts receivable (see note 3.g.3 and 9.d).

37. HEADCOUNT

Enel Chile’s personnel, as of December 31, 2022 and 2021, is as follows:


Country	12-31-2022	12-31-2021
Chile	2,136	2,193
Argentina	22	22
Total	2,158	2,215
Average	2,256	2,221

38. SANCTIONS

The following Enel Chile Group companies have received sanctions from administrative authorities:

Enel Generación Chile S.A.

1.1.

As of December 31, 2022, the sanction proceeding before the Regional Health Ministry (SEREMI) of Valparaiso, initiated by Inspection Record No. 1705213, in the amount of 500 UTM (ThCh$30,579) for alleged breaches of obligations and regulations related to the Noise Exposure Protocols and other health surveillance regulations at the Quintero plant is pending resolution.

1.2.

As of December 31, 2022, the sanction proceeding before the Regional Health Ministry (SEREMI) of Tarapacá, initiated by Inspection Record No. 000766, in the amount of 500 UTM (ThCh$30,579) for the alleged breach by CELTA in the use of lime in the Tarapacá Thermal Power Station is pending resolution.

1.3.

As of December 31, 2022, the sanction proceeding before the Regional Health Ministry (SEREMI) of Coquimbo, initiated by Inspection Record No. 10066, as of June 21, 2016, in the amount of 500 UTM (ThCh$30,579) for the alleged breach by GasAtacama (now Enel Generación Chile, its successor by merger) for keeping waste in an unauthorized area is pending resolution.

1.4.

As of December 31, 2022, the sanction proceeding initiated by the Regional Health Ministry (SEREMI) of the Metropolitan Region, initiated by Exempt Resolution No. 20131261, in the amount of 50 UTM (ThCh$3,058) for the alleged violation of health regulations due to COVID-19 is pending resolution.

Enel Distribución Chile S.A.

2.1.

By means of Exempt Resolution No. 10,921 dated February 21, 2022, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 39,261 UTM (ThCh$2,401,085) on the basis that Enel Distribución did not comply with the provisions of Article 4-1 of the Technical Norm of Service Quality for Distribution Systems, in relation to Articles 145 and 222, letter h), of the Regulation of the General Law of Electric Services and, in turn, in relation to Articles 72-14 and 130 of the General Law of Electric Services, which is evident from the information provided by the company in the process titled

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“Interruptions 2018”. Enel Distribución filed an appeal for reconsideration against this resolution, which is pending resolution.

2.2.

By means of Exempt Resolution No. 13,476-22 dated August 16, 2022, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 16,911 UTM (ThCh$1,034,226) on the basis that Enel Distribución did not comply with SAIDI-SAIFI limits in December 2015 to November 2016. Enel Distribución filed an appeal for reconsideration against this resolution, which is pending resolution.

2.3.

By means of Exempt Resolution No. 13,122-22 dated July 14, 2022, the Superintendence of Electricity and Fuels applied to Enel Distribución a fine equivalent to 200 UTM (ThCh$12,231) on the basis that Enel Distribución S.A. did not comply with its obligation to comply with connection deadlines. Enel Distribución filed an appeal for reconsideration against this resolution, which is pending resolution.

2.4.

By means of Exempt Resolution No. 13,547-22 dated August 25, 2022, the Superintendence of Electricity and Fuels imposed on Enel Distribución a fine equivalent to 200 UTM (ThCh$12,231) on the basis that Enel Distribución did not comply with its obligation to exceed the voltage regulation limit for its small means of distributed generation (PMGD) Lipangue plant. Enel Distribución filed an appeal for reconsideration against this resolution, which is pending resolution.

Enel Green Power Chile S.A.

3.1.

The Superintendence of Environment (SMA) brought charges against Enel Green Power Chile for alleged environmental violations committed by its subsidiary Geotérmica del Norte S.A. (“GDN”). There are sixteen violations charged thirteen classified as minor and three as serious. The three serious charges relate to archaeological matters. A compliance program was filed, which was dismissed. Subsequently, by resolution dated December 16, 2019, the SMA sent an official notice to the National Monuments Council to issue a statement regarding GDN’s archaeological defenses. The sanction process was resumed and remains pending resolution.

In relation to the sanctions described above, the Enel Chile Group has recorded provisions of ThCh$3,554,568 as of December 31, 2022 (see Note 25). There are other sanctions matters 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 and, therefore, does not expect additional liabilities other than those already recorded.

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39. ENVIRONMENT

Environmental expenses for the years ended December 31, 2022, 2021 and 2020, are as follows:


				12-31-2022						12-31-2021
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
Pehuenche S.A.	PEHUENCHE CENTRAL	Waste Management	In progress	29,164	—	29,164	5,405	12-31-2023	34,569	31,641
		Environmental Sanitation	In progress	3,105	—	3,105	19,298	12-31-2023	22,403	7,995
		Materials Environment	In progress	25,144	—	25,144	24,720	12-31-2023	49,864	32,246
Enel Distribución Chile S.A.	VEGETATION CONTROL IN AT NETWORKS (OPEX)	This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	In progress	525,809	—	525,809	—	-	525,809	344,571
	VEGETATION CONTROL IN MT/BT	Pruning of trees near the media network and low voltage.	In progress	2,383,970	—	2,383,970	—	-	2,383,970	3,136,872
	IMPROVEMENTS IN THE MT NETWORK	Replacement underground transformers by Technical Standard (PCB)	In progress	139,820	—	139,820	—	-	139,820	481,556
	SEC STANDARDIZATION PROJECT (CAPEX)	Underground Networks Interaction Project between Enel and Metrogas	In progress	2,932,689	—	2,932,689	—	-	2,932,689	4,403,751
Enel Generación Chile S.A.	Environmental expenses, and certifications CC.CC.	The main expenses incurred are: Investments, improvements and work carried out to obtain certificates in Diesel tanks,. 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	1,611,874	689,327	922,547	632,635	12-31-2023	2,244,509	2,696,089
	Environmental expenses, adaptations and certifications CC.TT.	Adaptations to comply with the environmental impact statement of Central Atacama, investment in tanks for the accumulation of raw water and improvements, studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	1,231,175	182,861	1,048,314	2,120,483	12-31-2023	3,351,658	1,873,179
	Environmental expenses CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (C.H.)	In progress	426,453	—	426,453	718,751	12-31-2023	1,145,204	642,694
Enel Green Power Chile S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste	In progress	75,422	—	75,422	193,828	12-31-2023	269,250	90,712
	Environmental Sanitation	Contracts for vector control, deratization, disinfection.	In progress	22,316	—	22,316	195,796	12-31-2023	218,112	75,483
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	61,552	—	61,552	91,153	12-31-2023	152,705	47,996
	Rent/Vehicle Expenses	Vehicle rental for environmental trips (field visits / Plants)	In progress	75,481	—	75,481	114,211	12-31-2023	189,692	48,171
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	13,234	—	13,234	109,770	12-31-2023	123,004	214,493
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	14,203	—	14,203	46,944	12-31-2023	61,147	85,802
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	65,043	—	65,043	110,887	12-31-2023	175,930	6,743
	Outsourced Services	Other services (contracts with third parties)	In progress	10,932	—	10,932	227,590	12-31-2023	238,522	213,326
	Permitting Framework Agreement	Management contract for environmental and sectoral permits	In progress	43,576	—	43,576	181,299	12-31-2023	224,875	97,998
	Domestic Waste Removal	Household / domestic waste removal contract	In progress	78,617	—	78,617	69,700	12-31-2023	148,317	40,320
	Environment Travel	Tickets - accommodation and viatics for site visit in facilities	In progress	49,605	—	49,605	99,316	12-31-2023	148,921	3,045
	Legal Requirements Contract	Environmental and sectorial permit management contract.	In progress	217,870	—	217,870	617,101	12-31-2023	834,971	—
	Bird Collision Monitoring Contract	Bird Collision Monitoring Contract	In progress	71,680	—	71,680	63,000	12-31-2023	134,680	—
Geotérmica del Norte S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste	In progress	26,667	—	26,667	36,764	12-31-2023	63,431	—
	Environmental Sanitation	Contracts for vector control, deratization, disinfection.	In progress	2,293	—	2,293	37,750	12-31-2023	40,043	65,536
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	5,589	—	5,589	5,378	12-31-2023	10,967	12,865
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	277,126	—	277,126	406,915	12-31-2023	684,041	3,780
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	4,209	—	4,209	5,227	12-31-2023	9,436	290,803
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	—	—	—	3,659	12-31-2023	3,659	5,294
	Permitting Framework Agreement	Management contract for environmental and sectoral permits	In progress	31,411	—	31,411	—	12-31-2023	31,411	947
	Domestic Waste Removal	Household / domestic waste removal contract (paid municipal retreat)	In progress	8,150	—	8,150	10,950	12-31-2023	19,100	2,677
Enel Transmisión Chile S.A.	VEGETATION CONTROL IN AT NETWORKS	This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	In progress	102,015	—	102,015	142,081	11-30-2022	244,096	—
		It consists of cutting branches until reaching the safety conditions that the foliage must be left with respect to the drivers.	In progress	223,178	—	223,178	—	-	223,178	—
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of the maintenance of green areas with replacement of species and grass in Enel substation enclosures	In progress	59,999	—	59,999	81,570	11-30-2022	141,569	—
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in the Metropolitan Park.	In progress	7,715	—	7,715	2,580	11-30-2022	10,295	—
		Nests and Others	In progress	1,590	—	1,590	6,010	11-30-2022	7,600	—
	SILICA GEL REPLACEMENT IN POWER TRANSFORMERS	Considers the replacement of silica gel (hygroscopic salt) to one (1) power transformer.	Completed	113	—	113	—	-	113	—
Parque Eólico Talinay Oriente S.A.	Waste Management	Contracts for the removal of hazardous and non-hazardous waste	In progress	6,496	-	6,496	7,841	12-31-2023	14,337	-
	Environmental Sanitation	Contracts for vector control, deratization, disinfection.	In progress	1,789	-	1,789	15,642	12-31-2023	17,431	-
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	4,916	-	4,916	4,640	12-31-2023	9,556	4,000
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	39,093	-	39,093	—	-	39,093	53,384
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	1,949	—	1,949	5,227	12-31-2023	7,176	3,801
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	—	—	—	1,830	12-31-2023	1,830	250
	Permitting Framework Agreement	Management contract for environmental and sectoral permits	In progress	453	—	453	—	-	453	-
	Domestic Waste Removal	Household / domestic waste removal contract (paid municipal retreat)	In progress	8,884	—	8,884	25,027	12-31-2023	33,911	11,999
	Bird Collision Monitoring Contract	Bird Collision Monitoring Contract	In progress	41,476	—	41,476	—	-	41,476	-
		Total		10,963,845	872,188	10,091,657	6,440,978		17,404,823	15,030,019

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				12-31-2021
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 S.A.	PEHUENCHE CENTRAL	Waste Management	In progress	18,513	—	18,513	13,128	12-31-2021	31,641
		Environmental Sanitation	In progress	4,467	—	4,467	3,528	12-31-2021	7,995
		Campaigns and Studies	In progress	714	—	714	4,235	12-31-2021	4,949
		Materials Environment	In progress	27,253	—	27,253	4,993	12-31-2021	32,246
Enel Distribución Chile S.A.	VEGETATION CONTROL IN AT NETWORKS	It consists of cutting branches until reaching the safety conditions that the foliage must be left with respect to the drivers.	In progress	251,298	—	251,298	—	-	251,298
		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
	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
	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
	IMPROVEMENTS IN THE MT NETWORK	Replacement underground transformers by Technical Standard (PCB)	In progress	481,556	481,556	—	—	-	481,556
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in the Metropolitan Park.	In progress	2,875	—	2,875	—	-	2,875
	SEC STANDARDIZATION PROJECT (CAPEX)	Underground Networks Interaction Project between Enel and Metrogas	In progress	4,403,751	4,403,751	—	—	-	4,403,751
	OIL ANALYSIS AT TD OF POWER (OPEX)	Consider chromatographic analysis, furans, and physical-chemical analysis.	In progress	32,364	—	32,364	—	-	32,364
	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 load ability problems	In progress	5,330,561	5,330,561	—	—	-	5,330,561
	SILICA GEL REPLACEMENT IN POWER TRANSFORMERS	Considers the replacement of silica gel (hygroscopic salt) to one (1) power transformer.	In progress	5,838	—	5,838	—	-	5,838
Enel Generación Chile S.A.	Environmental expenses, and certifications CC.CC.	The main expenses incurred are: Investments, improvements and work carried out to obtain certificates in Diesel tanks,. 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	2,245,304	833,395	1,411,908	450,786	12-31-2021	2,696,090
	Environmental expenses, adaptations and certifications CC.TT.	Adaptations to comply with the environmental impact statement of Central Atacama, investment in tanks for the accumulation of raw water and improvements, 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
	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
Enel Green Power Chile S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste.	In progress	90,712	—	90,712	—	-	90,712
	Environmental Sanitation	Contracts for vector control, deratization, disinfection.	In progress	75,483	—	75,483	—	-	75,483
	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
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	214,493	—	214,493	—	-	214,493
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	85,802	—	85,802	—	-	85,802
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	6,743	—	6,743	—	-	6,743
	Outsourced Services	Other services (contracts with third parties)	In progress	213,326	—	213,326	—	-	213,326
	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
Geotérmica del Norte S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste.	In progress	65,536	—	65,536	—	-	65,536
	Environmental Sanitation	Vector control contracts, rat extermination, disinfection.	In progress	12,865	—	12,865	—	-	12,865
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	3,780	—	3,780	—	-	3,780
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	290,803	—	290,803	—	-	290,803
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	5,294	—	5,294	—	-	5,294
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	947	—	947	—	-	947
	Permitting Framework Agreement	Management contract for environmental and sectoral permits	In progress	2,677	—	2,677	—	-	2,677
Parque Eolico Talinay Oriente S.A.	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
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	3,801	—	3,801	—	-	3,801
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	250	—	250	—	-	250
	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

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				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
	PEHUENCHE CENTRAL	Environmental Sanitation	In progress	3,528	—	3,528	5,334	12-31-2021	8,862
Pehuenche		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 replacement of species and grass in Enel substation enclosures. Maintenance tree planting of SSEE and removal of weeds, debris and garbage, exterior perimeter. The withdrawal and transfer was carried out.	Completed	340,704	—	340,704	—	12-31-2020	340,704
	RESPEL MANAGEMENT	Hazardous waste removal and treatment management	Completed	19,122	—	19,122	—	12-31-2020	19,122
	SEC STANDARDIZATION PROJECT (CAPEX)	Tree planting of SSEE and removal of weeds, rubble and garbage, exterior perimeter.	Completed	1,774,155	1,774,155	—	—	12-31-2020	1,774,155
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in the Metropolitan Park.	Completed	1,374	—	1,374	—	12-31-2020	1,374
	OIL ANALYSIS AT TD OF POWER (OPEX)	Consider chromatographic analysis, furans, and physical-chemical analysis.	Completed	32,096	—	32,096	—	12-31-2020	32,096
	ENVIRONMENTAL EXPENSES CC.CC.	The main expenses incurred are: Operation and maintenance, monitoring air quality and meteorological stations, Environmental audit monitoring network once a year, Annual CEMS Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements, SGI Works (NC objective, inspections, audits and supervision) ISO 14001, OHSAS certification, CEMS operation and maintenance service.	In progress	595,987	95,976	500,011	599,144	12-31-2021	1,195,131
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	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 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.	In progress	84,113	—	84,113	148,447	12-31-2021	232,560
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	46,957	—	46,957	104,448	12-31-2021	151,405
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	—	—	35,266	44,588	12-31-2021	44,588
	Rent/Vehicle Expenses	Vehicle rental for environmental trips (field 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 (Collision of Birds- 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
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	32,032	—	32,032	40,578	12-31-2021	72,610
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	8,066	—	8,066	31,591	12-31-2021	39,657
	Outsourced Services	Other services (contracts with third parties)	In progress	222,291	—	222,291	297,167	12-31-2021	519,458
	Environment Travel	Tickets - accommodation and viatics for site visit in facilities	In progress	56,820	—	56,820	85,150	12-31-2021	141,970
	Waste management	Contracts for the removal of hazardous and non-hazardous waste.	In progress	21,992	—	21,992	32,918	12-31-2021	54,910
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	6,500	—	6,500	14,319	12-31-2021	20,819
Geotérmica del Norte S.A.	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	313,280	—	313,280	339,170	12-31-2021	652,450
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	91	—	91	3,559	12-31-2021	3,650
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	4,816	—	4,816	1,324	12-31-2021	6,140
	Waste management	Contracts for the removal of hazardous and non-hazardous waste.	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, deratization, disinsection.	In progress	6,939	—	6,939	4,109	12-31-2021	11,048
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	76,595	—	76,595	—	12-31-2021	76,595
	Sewage Treatment Plant	Contract for removal 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.	In progress	39,521	—	39,521	31,508	12-31-2021	71,029
	Environmental Sanitation	Contracts for vector control, deratization, 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 sewage	In progress	—	—	—	24,435	12-31-2020	24,435
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	63,736	—	63,736	64,160	12-31-2021	127,896
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	16,663	—	16,663	28,702	12-31-2021	45,365
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	8,149	—	8,149	12,795	12-31-2021	20,944
		Total		14,046,722	5,768,806	8,313,182	3,966,677		18,013,399

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40. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of December 31, 2022, 2021 and 2020, summarized financial information of the Company’s principal consolidated subsidiaries prepared under IFRS is as follows:


	12-31-2022
	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	517,448,832	1,503,735,962	2,021,184,794	707,079,953	629,125,828	684,979,013	2,021,184,794	1,390,067,039	(1,219,057,344)	171,009,695	80,618,603	13,031,895	(11,117,156)	1,914,739	20,211,987	22,126,726	(6,670,042)	15,456,684
Enel Generación Chile	Separate	1,616,083,142	2,654,629,663	4,270,712,805	899,409,125	1,202,746,824	2,168,556,856	4,270,712,805	3,666,453,365	(2,927,568,119)	738,885,246	593,454,679	525,197,060	(36,631,364)	635,647,512	(71,927,760)	563,719,752	147,458,665	711,178,417
Enel Distribución Chile	Separate	509,513,449	1,493,545,567	2,003,059,016	695,744,040	629,055,841	678,259,135	2,003,059,016	1,386,278,469	(1,217,064,139)	169,214,330	79,680,726	14,077,959	(11,098,303)	2,979,657	19,475,413	22,455,070	(6,665,575)	15,789,495
Empresa Eléctrica Pehuenche S.A.	Separate	153,652,579	156,567,496	310,220,075	97,367,848	38,214,373	174,637,854	310,220,075	272,441,946	(8,068,518)	264,373,428	256,448,537	248,835,473	5,859,222	254,694,695	(67,785,473)	186,909,222	—	186,909,222
Enel Transmision Chile S.A. (1)	Separate	—	—	—	—	—	—	—	96,056,284	(2,416,697)	93,639,588	79,237,171	70,500,241	(9,460,824)	61,039,418	(12,513,925)	48,525,493	55,652	48,581,145
Enel X Chile SPA	Separate	120,842,754	129,627,868	250,470,622	227,063,403	1,615,388	21,791,831	250,470,622	44,555,174	(19,227,050)	25,328,124	10,911,375	10,785,706	(9,297,839)	918,355	930,710	1,849,065	(72,940)	1,776,125
Geotermica del Norte S.A.	Separate	25,635,151	449,371,985	475,007,136	54,576,871	9,795,709	410,634,556	475,007,136	42,338,738	(2,085,161)	40,253,577	2,484,607	(16,314,492)	(1,906,202)	(18,220,694)	5,882,266	(12,338,428)	436,249	(11,902,178)
Parque Eolico Talinay Oriente S.A.	Separate	127,752,924	84,532,822	212,285,746	12,169,016	25,153,714	174,963,016	212,285,746	27,384,124	(1,255,906)	26,128,218	22,691,033	15,654,610	2,650,649	18,305,259	(5,114,251)	13,191,008	(228,602)	12,962,406
Enel Green Power Chile S.A	Separate	155,208,869	3,614,007,070	3,769,215,939	734,804,810	1,950,173,417	1,084,237,712	3,769,215,939	497,274,888	(247,339,411)	249,935,478	182,795,798	97,069,706	(59,481,555)	37,588,151	(11,322,450)	26,265,701	(2,216,269)	24,049,432
Grupo Enel Green Power	Consolidated	291,452,465	3,734,811,118	4,026,263,583	784,406,218	1,990,260,594	1,251,596,771	4,026,263,583	510,321,233	(198,979,315)	311,341,918	210,023,156	98,022,568	(54,359,950)	40,852,508	(11,617,745)	29,234,763	7,747,281	36,982,044
Grupo Enel Generación Chile	Consolidated	1,700,122,637	2,707,181,983	4,407,304,620	1,082,602,388	1,240,478,531	2,084,223,701	4,407,304,620	3,818,906,698	(2,818,054,885)	1,000,851,813	849,770,172	774,032,534	(30,772,142)	751,020,012	(139,713,234)	611,306,778	147,333,179	758,639,957


	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. (2)	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)

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	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)
Grupo Enel Green Power	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)

(1)See Note 2.4.1.v.

(2)See Note 2.4.1.iv.

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41. SUBSEQUENT EVENTS

On January 6, 2023, draw No. 2 of the EFI 290 credit line for US$100 million was repaid, leaving a debit balance owed of US$190 million (see Note 10.d.vi).

ii.

On January 13, 2023, draw No. 3 of the EFI 290 credit line for US$90 million was repaid. The new debit balance owed amounts to US$100 million (see Note 10.d.vi).

iii.

On January 30, 2023, draw No. 1 from the EFI 290 credit line for US$100 million was repaid. As of January 31, 2023, no amounts are owed and this credit line is 100% available (see Note 10.d.vi).

iv.

On February 1, 2023, our subsidiary Enel Generación Chile signed a sales contract for the Santa Rosa Complex with Territoria Santa Rosa SpA. In the same contract, Enel Chile and its subsidiaries Enel Generación Chile and Enel Distribución Chile sold movable assets to Territoria Apoquindo S.A.

The sales price for the property amounted to UF 864,947.84. Of this, UF 768,447.84 (equivalent to ThCh$27,119,224) was paid in cash upon execution of the contract. The remaining UF 96,500 will be paid within two years. The total price for the movable assets sold to Territoria Apoquindo S.A. amounted to Th$405,919, which was also paid in cash.

The agreement with Territoria Santa Rosa SpA establishes that the Group will continue to use the Santa Rosa Complex through a lease until the first half of 2024. From this date onwards, the Company will begin to use tower 2 of the MUT (Mercado Urbano Tobalaba) complex as its new corporate headquarters, which is owned by Territoria Apoquindo S.A. On February 1, 2023, Enel Chile also signed a 7-year lease agreement with Territoria Apoquindo S.A., which will be effective as of May 1, 2023.

On April 13, 2023, draw of the BBVA y MIZUHO credit line for US$90 million. The draw was made at a variable interest rate of Libor 6M plus a margin 0.90% and a maturity date of October 20, 2023.

vi.

On April 20, 2023, draw from the EFI credit line for US$50 million. The draw was made at Libor 3M + spread and with a maturity date of July 20, 2023 (see Note 10.ii).

vii.

On April 26, 2023, draw from the EFI credit line for US$290 million. The draw was made at Libor 3M + spread and with a maturity date of July 26, 2023 (see Note 41.iii).

Between January 1, 2023 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.

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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:


	12-31-2022
ASSETS	U.F.	Chilean Peso	U.S. dollar	Euro	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	32,892	745,956,809	128,804,370	176,894	242,734	875,213,699
Other current financial assets	—	2,856,333	657,001	16,882	—	3,530,216
Other current non-financial assets	3,065,209	161,803,844	26,263,120	502,775	1,005,404	192,640,352
Trade and other current receivables	4,374,199	1,463,980,203	41,156,861	2,092	—	1,509,513,355
Current accounts receivable from related parties	—	3,741,016	20,048,882	232,478,706	—	256,268,604
Inventories	136,717	65,749,377	9,292,286	2,737,713	-	77,916,093
Current tax assets	-	112,755,098	7,803,269	-	-	120,558,367
Non-current assets or groups of assets for disposal classified as held for sale	—	28,333,006	268,627	—	—	28,601,633
TOTAL CURRENT ASSETS	7,609,017	2,585,175,686	234,294,416	235,915,062	1,248,138	3,064,242,319

NON-CURRENT ASSETS
Other non-current financial assets	1,458,904	58,368,736	-	—	—	59,827,640
Other non-current non-financial assets	70,036	78,178,092	28,213	—	—	78,276,341
Trade and other non-current receivables	20,988,425	114,670,586	554,563,222	—	925,412	691,147,645
Non-current accounts receivable from related parties	—	—	-	—	—	-
Investments accounted for using the equity method	—	4,960,303	12,404,147	—	388,328	17,752,778
Intangible assets other than goodwill	—	109,744,724	81,674,736	—	21,803	191,441,263
Goodwill	—	849,345,650	34,267,779	—	—	883,613,429
Property, plant and equipment	—	3,212,229,418	3,345,829,232	—	14,295,344	6,572,353,994
Investment property	—	7,348,262	—	—	—	7,348,262
Right-of-use asset	208,921,326	17,988,526	-	6,788,580	—	233,698,432
Deferred tax assets	—	42,524,495	23,353,134	—	—	65,877,629
TOTAL NON CURRENT ASSETS	231,438,691	4,495,358,792	4,052,120,463	6,788,580	15,630,887	8,801,337,413
TOTAL ASSETS	239,047,708	7,080,534,478	4,286,414,879	242,703,642	16,879,025	11,865,579,732


	12-31-2021
ASSETS	U.F.	Chilean Peso	U.S. dollar	Euro	Argentine Peso	Total
	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

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	12-31-2022
LIABILITIES	U.F.	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Argentine Peso	Other Currency	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	40,274,963	83	28,244,737	—	—	—	—	68,519,783
Current lease liability	11,041,842	100,658	6,429,038	1,449,098	—	—	—	19,020,636
Trade and other current payables	27,565,082	1,336,917,391	371,476,401	7,596,123	—	324,415	13,497	1,743,892,909
Current accounts payable to related parties	—	234,496,436	448,393,609	263,608,529	-	—	—	946,498,574
Other current provisions	—	22,760,982	-	—	—	141,024	-	22,902,006
Current tax liabilities	—	327,612,098	6,724,272	—	—	—	—	334,336,370
Other current non-financial liabilities	—	28,318,088	4,499,888	486,941	—	16,685	-	33,321,602
TOTAL CURRENT LIABILITIES	78,881,887	1,950,205,736	865,767,945	273,140,691	-	482,124	13,497	3,168,491,880

NON-CURRENT LIABILITIES
Other non-current financial liabilities	225,557,282	—	1,958,245,974	—	—	—	—	2,183,803,256
Non-current lease liability	208,182,319	996,108	1,027,260	6,459,232	—	—	—	216,664,919
Trade and other non-current payables	—	27,660	308,281,202	—	—	—	—	308,308,862
Non-current accounts receivable to related parties	—	—	1,147,096,713	—	—	—	—	1,147,096,713
Other long-term provisions	—	164,276,876	25,193,367	—	—	—	—	189,470,243
Deferred tax liabilities	—	36,601,749	162,414,745	—	—	—	—	199,016,494
Non-current provisions for employee benefits	—	62,699,415	-	—	—	—	—	62,699,415
Other non-current non-financial liabilities	—	1,088,647	—	—	—	—	—	1,088,647
TOTAL NON-CURRENT LIABILITIES	433,739,601	265,690,455	3,602,259,261	6,459,232	—	—	—	4,308,148,549
TOTAL LIABILITIES	512,621,488	2,215,896,191	4,468,027,206	279,599,923	-	482,124	13,497	7,476,640,429


	12-31-2021
LIABILITIES	U.F.	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Argentine Peso	Other Currency	Total
	ThCh$	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

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APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012

This appendix forms an integral part of these consolidated financial statements.

Portfolio stratification

-Trade and other receivables by maturity:


	As of December 31, 2022
	Current Portfolio	1 - 30 days past due	31 - 60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	Total Current	Total Non- Current
Trade and Other Receivables	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	1,063,126,893	165,196,456	20,742,604	13,545,981	19,943,245	20,455,008	20,258,067	12,059,092	10,660,914	91,914,939	1,437,903,199	529,584,066
Impairment provision	(13,839,714)	(582,502)	(1,202,377)	(1,820,576)	(2,309,882)	(2,940,313)	(2,441,799)	(2,756,571)	(3,164,816)	(34,271,448)	(65,329,998)	(10,767,122)
Accounts receivable for leasing, gross	21,037,785	—	—	—	—	—	—	—	—	—	21,037,785	170,338,861
Impairment provision	(262,097)	—	—	—	—	—	—	—	—	—	(262,097)	(1,415,859)
Other receivables, gross	116,120,154	—	—	—	—	—	—	—	—	11,474,680	127,594,834	3,407,699
Impairment provision	—	—	—	—	—	—	—	—	—	(11,430,368)	(11,430,368)	—
Total	1,186,183,021	164,613,954	19,540,227	11,725,405	17,633,363	17,514,695	17,816,268	9,302,521	7,496,098	57,687,803	1,509,513,355	691,147,645

	As of December 31, 2021
	Current Portfolio	1 - 30 days past due	31 - 60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	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

-By type of portfolio:


	December 31, 2022						December 31, 2021
	Portfolio with no renegotiated terms		Portfolio with renegotiated terms		Total Gross Portfolio		Portfolio with no renegotiated terms		Portfolio with renegotiated terms		Total Gross Portfolio
		Gross		Gross		Gross		Gross		Gross		Gross
	Number of	Amount	Number of	Amount	Number of	Amount	Number of	Amount	Number of	Amount	Number of	Amount
	clients	ThCh$	clients	ThCh$	clients	ThCh$	clients	ThCh$	clients	ThCh$	clients	ThCh$
Up-to-date	1,978,750	1,049,380,978	83,186	543,329,981	2,061,936	1,592,710,959	2,230,792	527,654,070	26,165	361,525,567	2,256,957	889,179,637
1 to 30 days	40,186	161,637,984	1,428	3,558,472	41,614	165,196,456	102,883	73,364,730	6,645	1,106,430	109,528	74,471,160
31 to 60 days	30,621	19,108,793	1,588	1,633,811	32,209	20,742,604	43,856	21,393,764	4,206	1,057,015	48,062	22,450,779
61 to 90 days	29,542	12,388,582	1,765	1,157,399	31,307	13,545,981	8,738	8,935,098	1,030	707,160	9,768	9,642,258
91 to 120 days	44,792	19,164,002	1,411	779,243	46,203	19,943,245	21,811	8,855,902	3,267	311,117	25,078	9,167,019
121 to 150 days	32,952	19,978,533	1,584	476,475	34,536	20,455,008	12,729	12,958,406	2,739	763,841	15,468	13,722,247
151 to 180 days	15,522	19,875,975	970	382,092	16,492	20,258,067	12,155	11,029,547	3,938	618,886	16,093	11,648,433
181 to 210 days	12,464	11,764,028	903	295,064	13,367	12,059,092	6,683	7,587,824	2,759	920,198	9,442	8,508,022
211 to 250 days	32,553	10,467,899	1,430	193,015	33,983	10,660,914	7,367	10,185,568	1,353	524,385	8,720	10,709,953
More than 251 days	735,816	88,792,498	75,189	3,122,441	811,005	91,914,939	484,362	85,302,461	23,839	2,737,738	508,201	88,040,199
Total	2,953,198	1,412,559,272	169,454	554,927,993	3,122,652	1,967,487,265	2,931,376	767,267,370	75,941	370,272,337	3,007,317	1,137,539,707

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Portfolio in default and in legal collection process


	As of December 31,
	2022		2021
	Number of	Amount	Number of	Amount
Portfolio in Default and in Legal Collection Process	clients	ThCh$	Clients	ThCh$
Notes receivable in default	1,856	255,178	1,864	255,977
Notes receivable in legal collection process (*)	755	3,304,750	1,368	5,608,066
Total	2,611	3,559,928	3,232	5,864,043

(*)	Legal collections are included in the portfolio past due.

Allowances and write-offs


	As of December 31,
	12-31-2022	12-31-2021
	ThCh$	ThCh$
Provisions and Write-offs
Allowance for portfolio with no renegotiated terms	13,738,391	10,188,647
Allowance for portfolio with renegotiated terms	8,893,362	8,576,528
Recoveries of the period	74,833	—
Total	22,706,586	18,765,175

Number and value of transactions


	12-31-2022		12-31-2021
	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	26,010	33,861	24,625	83,672
Amount of the transactions	5,303,963	22,706,586	3,840,423	18,765,175

F-147

Table of Contents

APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:

This appendix forms an integral part of these consolidated financial statements.

Portfolio stratification

Trade receivables detailed by aging:


	12-31-2022
Trade receivables	Up-to-date Portfolio	1-30 days past due	31-60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	More than 365 days past due	Total Current	Total Non- Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, Generation and Transmission	654,985,092	143,536,076	8,891,588	5,258,816	12,773,438	13,785,800	15,520,362	8,046,533	6,266,126	745,668	16,622,321	886,431,820	45,059,200
- Large customers	650,526,145	143,493,478	8,872,845	5,125,060	12,752,139	13,778,132	15,518,658	8,044,829	6,264,422	421,075	16,219,836	881,016,619	45,059,200
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—	—
- Others	4,458,947	42,598	18,743	133,756	21,299	7,668	1,704	1,704	1,704	324,593	402,485	5,415,201	—
Allowance for impairment	(121,270)	—	—	—	—	—	—	—	—	(2,556)	(5,104,847)	(5,228,673)	(105,869)
Unbilled services	640,741,166	—	—	—	—	—	—	—	—	—	—	640,741,166	1,858,103
Billed services	14,243,926	143,536,076	8,891,588	5,258,816	12,773,438	13,785,800	15,520,362	8,046,533	6,266,126	745,668	16,622,321	245,690,654	43,201,097

Trade receivables, Distribution	408,141,801	21,660,380	11,851,016	8,287,165	7,169,807	6,669,208	4,737,705	4,012,559	4,394,788	8,884,006	65,662,944	551,471,379	484,524,866
- Mass-market customers	366,272,977	18,467,498	8,246,806	5,884,359	5,064,562	4,915,647	3,712,699	3,057,882	3,318,993	6,753,036	44,500,915	470,195,374	451,150,735
- Large customers	36,208,465	834,666	1,075,417	510,124	488,532	547,488	199,112	429,147	318,026	678,559	6,609,561	47,899,097	7,855,802
- Institutional customers	5,660,359	2,358,216	2,528,793	1,892,682	1,616,713	1,206,073	825,894	525,530	757,769	1,452,411	14,552,468	33,376,908	25,518,329
Allowance for impairment	(13,718,444)	(582,502)	(1,202,377)	(1,820,576)	(2,309,882)	(2,940,313)	(2,441,799)	(2,756,571)	(3,164,816)	(6,244,946)	(22,919,099)	(60,101,325)	(10,661,253)
Unbilled services	332,260,920	—	—	—	—	—	—	—	—	—	—	332,260,920	447,746,461
Billed services	75,880,881	21,660,380	11,851,016	8,287,165	7,169,807	6,669,208	4,737,705	4,012,559	4,394,788	8,884,006	65,662,944	219,210,459	36,778,403
Total trade receivables, gross	1,063,126,893	165,196,456	20,742,604	13,545,981	19,943,245	20,455,008	20,258,067	12,059,092	10,660,914	9,629,674	82,285,265	1,437,903,199	529,584,066
Total Allowance for impairment	(13,839,714)	(582,502)	(1,202,377)	(1,820,576)	(2,309,882)	(2,940,313)	(2,441,799)	(2,756,571)	(3,164,816)	(6,247,502)	(28,023,946)	(65,329,998)	(10,767,122)
Total trade receivables, net	1,049,287,179	164,613,954	19,540,227	11,725,405	17,633,363	17,514,695	17,816,268	9,302,521	7,496,098	3,382,172	54,261,319	1,372,573,201	518,816,944


	12-31-2021
Trade receivables	Up-to-date Portfolio	1 - 30 days past due	31 - 60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	More than 365 days past due	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 customers	—	—	—	—	—	—	—	—	—	—	—	—	—
- 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 customers	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

Because 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

F-148

Table of Contents

By type of portfolio:


	12-31-2022
Type of Portfolio	Up-to-date portfolio	1 - 30 days past due	31 - 60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	Total current	Total non-current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Portfolio with no renegotiated terms	654,985,092	143,536,076	8,891,588	5,258,816	12,773,438	13,785,800	15,520,362	8,046,533	6,266,126	17,367,989	886,431,820	45,059,200
- Large customers	650,526,145	143,493,478	8,872,845	5,125,060	12,752,139	13,778,132	15,518,658	8,044,829	6,264,422	16,640,911	881,016,619	45,059,200
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Other	4,458,947	42,598	18,743	133,756	21,299	7,668	1,704	1,704	1,704	727,078	5,415,201	—
Portfolio with renegotiated terms	—	—	—	—	—	—	—	—	—	—	—	—
- Large customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Portfolio with no renegotiated terms	348,967,768	18,101,908	10,217,205	7,129,766	6,390,564	6,192,733	4,355,613	3,717,495	4,201,773	71,424,509	480,699,334	368,918
- Mass-market customers	311,820,388	14,959,951	6,613,958	4,729,193	4,285,454	4,439,308	3,330,743	2,762,818	3,102,394	48,799,268	404,843,475	63,972
- Large customers	35,302,143	787,279	1,075,417	508,243	488,532	547,488	199,112	429,147	341,610	7,288,119	46,967,090	304,946
- Institutional customers	1,845,237	2,354,678	2,527,830	1,892,330	1,616,578	1,205,937	825,758	525,530	757,769	15,337,122	28,888,769	—
Portfolio with renegotiated terms	59,174,033	3,558,472	1,633,811	1,157,399	779,243	476,475	382,092	295,064	193,015	3,122,441	70,772,045	484,155,948
- Mass-market customers	54,452,589	3,507,547	1,632,848	1,155,166	779,107	476,339	381,956	295,064	193,015	2,454,684	65,328,315	451,086,763
- Large customers	906,322	47,387	—	1,881	—	—	—	—	—	—	955,590	7,550,856
- Institutional customers	3,815,122	3,538	963	352	136	136	136	—	—	667,757	4,488,140	25,518,329
Total gross portfolio	1,063,126,893	165,196,456	20,742,604	13,545,981	19,943,245	20,455,008	20,258,067	12,059,092	10,660,914	91,914,939	1,437,903,199	529,584,066


	12-31-2021
Type of Portfolio	Current Portfolio	1 - 30 days past due	31 - 60 days past due	61 - 90 days past due	91 - 120 days past due	121 - 150 days past due	151 - 180 days past due	181 - 210 days past due	211 - 250 days past due	More than 251 days past due	Total Current	Total Non- Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Portfolio with no renegotiated terms	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 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	14,964,404	316,708,886	98,464,396
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- 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	—
Portfolio with renegotiated terms	—	—	—	—	—	—	—	—	—	—	—	—
- Large customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Portfolio with no renegotiated terms	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 customers	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 customers	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 customers	(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	—
Portfolio with renegotiated terms	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 customers	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 Customers	716,411	44,195	23,701	17,999	—	16,533	251	251	—	—	819,341	359,355
- Institutional Customers	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

F-149

Table of Contents

APPENDIX 2.2 ESTIMATES OF SALES AND PURCHASES OF ENERGY, POWER AND TOLL

This appendix forms an integral part of these consolidated financial statements.


	12-31-2022		12-31-2021
	Energy and		Energy and
	Capacity	Tolls	Capacity	Tolls
	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF FINANCIAL POSITION
Trade and other receivables, current	771,542,899	44,081,383	302,100,766	11,112,332
Trade and other receivables, non-current	441,133,414	-	389,606,316	-
Total Estimated Assets	1,212,676,313	44,081,383	691,707,082	11,112,332
Trade and other payables, current	116,540,839	23,547,980	106,108,407	5,855,074
Trade and other payables, non-current	288,973,001	-	157,402,765	-
Total Estimated Liabilities	405,513,840	23,547,980	263,511,172	5,855,074


	12-31-2022		12-31-2021
	Energy and		Energy and
	power	Tolls	power	Tolls
	ThCh$	ThCh$	ThCh$	ThCh$
INCOME STATEMENT
Energy Sales	812,406,845	38,856,793	466,620,691	11,112,332
Energy Purchases	248,111,074	23,547,980	151,312,313	5,855,074

F-150

Table of Contents

APPENDIX 3 DETAIL OF DUE DATES OF PAYMENTS TO SUPPLIERS

This appendix forms an integral part of these consolidated financial statements.


	12-31-2022				12-31-2021
	Goods	Services	Others	Total	Goods	Services	Others	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Suppliers with Payments Up-to-Date
Up to 30 days	165,444,247	749,444,690	545,460,293	1,460,349,230	84,896,490	342,566,432	320,708,771	748,171,693
Between 31 and 60 days	5,776,032	193,190	41,334,530	47,303,752	3,032,565	1,403,461	45,157,514	49,593,540
Between 61 and 90 days	9,877,476	538,317	20,753,733	31,169,526	14,137,065	30,231	102,236,202	116,403,498
Between 91 and 120 days	—	—	—	—	—	—	—	—
Between 121 and 365 days	—	—	—	—	—	—	—	—
More than 365 days	—	487	308,175,025	308,175,512	—	487	179,311,985	179,312,472
Total	181,097,755	750,176,684	915,723,581	1,846,998,020	102,066,120	344,000,611	647,414,472	1,093,481,203


	12-31-2022				12-31-2021
	Goods	Services	Others	Total	Goods	Services	Others	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Suppliers Details
Suppliers for energy purchase	—	228,033,131	584,217,799	812,250,930	—	94,049,964	319,420,457	413,470,421
Suppliers for the purchase of fuels and gas	—	236,836,190	—	236,836,190	—	86,288,004	—	86,288,004
Accounts payable for goods and services	68,929,751	285,307,363	—	354,237,114	29,508,717	163,662,643	—	193,171,360
Accounts payable for the purchase of assets	112,168,004	—	331,505,782	443,673,786	72,557,403	—	327,994,015	400,551,418
Total	181,097,755	750,176,684	915,723,581	1,846,998,020	102,066,120	344,000,611	647,414,472	1,093,481,203

F-151

(in millions of Ch$)

Cash flows used