Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
☐
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025
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)
(Translation of Registrant’s name into English)
CHILE
(Jurisdiction of incorporation or organization)
Roger de Flor 2725, Tower 2, Floor 19, Las Condes, Santiago, Chile
(Address of principal executive offices)
Isabela Klemes, phone: (56) 2 26309000, ir.enelchile@enel.com, Roger de Flor 2725, Tower 2, Floor 17, Las Condes, 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 *
*
US$ 1,000,000,000 4.875% Notes due June 12, 2028
ENIC28
_____________________
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: 69,166,557,219
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
Enel Chile’s Simplified Organizational Structure(1)
As of December 31, 2025
1
TABLE OF CONTENTS
Page
GLOSSARY
3
INTRODUCTION
6
PRESENTATION OF INFORMATION
7
FORWARD-LOOKING STATEMENTS
9
PART I
Item 1.
Identity of Directors, Senior Management and Advisers
10
Item 2.
Offer Statistics and Expected Timetable
Item 3.
Key Information
Item 4.
Information on the Company
23
Item 4A.
Unresolved Staff Comments
45
Item 5.
Operating and Financial Review and Prospects
Item 6.
Directors, Senior Management and Employees
77
Item 7.
Major Shareholders and Related-Party Transactions
85
Item 8.
Financial Information
87
Item 9.
The Offer and Listing
89
Item 10.
Additional Information
90
Item 11.
Quantitative and Qualitative Disclosures About Market Risk
106
Item 12.
Description of Securities Other Than Equity Securities
109
PART II
Item 13.
Defaults, Dividend Arrearages and Delinquencies
111
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
Item 15.
Controls and Procedures
Item 16.
Reserved
112
Item 16A.
Audit Committee Financial Expert
Item 16B.
Code of Ethics
Item 16C.
Principal Accountant Fees and Services
114
Item 16D.
Exemptions from the Listing Standards for Audit Committees
Item 16E.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
115
Item 16F.
Change in Registrant’s Certifying Accountant
Item 16G.
Corporate Governance
Item 16H.
Mine Safety Disclosure
116
Item 16I.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Item 16J.
Insider Trading Policies
Item 16K.
Cybersecurity
117
PART III
Item 17.
Financial Statements
120
Item 18.
Item 19.
Exhibits
2
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 ADSs 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
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.
EFI
Enel Finance International N.V.
A Dutch company operating as a financing company for the Enel Group, raising funds through bond issuances, loans, and other facilities, and in turn lending funds to companies in the Enel Group, and a subsidiary of Enel.
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, 2025, and our ultimate parent company.
Enel Américas
Enel Américas S.A.
An affiliated Chilean publicly held limited liability stock corporation headquartered in Chile, with subsidiaries engaged primarily in the generation, transmission, and distribution of electricity in Argentina, Brazil, Colombia, and Peru, controlled by Enel.
Enel Chile
Enel Chile S.A.
Our company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile. The registrant of this Report.
Enel Colina
Enel Colina S.A.
A subsidiary of Enel Distribución Chile engaged in electricity distribution in Chile, formerly known as Empresa Eléctrica de Colina Ltda.
Enel Distribución Chile
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 Generación Chile
Enel Generación Chile S.A.
A Chilean publicly held limited liability stock corporation engaged in electricity generation and a subsidiary of Enel Chile.
Enel Group
Enel S.p.A. and the companies that it directly and indirectly controls.
Enel X Chile
Enel X Chile S.p.A.
A Chilean company by shares 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 Accounting 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.
4
PMGD
Pequeños Medios de Generación Distribuida
A Chilean regime for distributed generation facilities.
OSM
Ordinary Shareholders’ Meeting
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 Generación Chile.
SAIDI
System Average Interruption Duration Index
Index of average duration of interruption in the power supply.
SAIFI
System Average Interruption Frequency Index
Index of average frequency of interruptions in the power supply.
SEF
Superintendence of Electricity and Fuels
A Chilean public agency, under the Ministry of Energy, that inspects and supervises compliance with the laws, standards, regulations, and technical norms applicable to the generation, transmission, and distribution of electric energy, as well as liquid fuels and gas.
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$39,727.96 as of December 31, 2025.
VAD
Valor Agregado de Distribución
Value-added from distribution of electricity.
5
As used in this Report on Form 20-F (“Report”), first-person personal pronouns such as “we,” “us,” or “our,” as well as “Enel Chile” or the “Company,” refer to Enel Chile S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries and jointly controlled companies and associates is expressed in terms of our economic interest as of December 31, 2025.
We are a Chilean publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile as a result of a corporate reorganization completed in 2016 by the former Enersis S.A., which separated its Chilean businesses from its non-Chilean businesses.
We are engaged in electricity generation and distribution businesses in Chile through our subsidiaries and affiliates. We own 93.55% of Enel Generación Chile S.A. (“Enel Generación Chile”), a Chilean electricity generation company with operations in Chile, 99.99% of Enel Green Power Chile S.A. (“EGP Chile”), a Chilean renewable electricity generation company, 99.09% of Enel Distribución Chile S.A. (“Enel Distribución Chile”), a Chilean electricity distribution company that operates in the Santiago Metropolitan Region, and 100% of Enel X Chile S.p.A, a Chilean company providing retail products, services, and technologies that promote electrification.
As of December 31, 2025, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, owns 64.93% of us and is our ultimate controlling shareholder.
In this Report, unless otherwise specified, references to “U.S. dollars” or “US$,” 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, 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, 2025, one UF was equivalent to Ch$39,727.96. The U.S. dollar equivalent of one UF was US$43.80 as of December 31, 2025, using the observed exchange rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2025, of Ch$907.13 per US$1.00. The U.S. dollar observed exchange rate (dólar observado) (the “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, 2025. 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 U.S dollars. Effective January 1, 2025, Enel Chile changed its functional and presentation currency from Chilean pesos to U.S. dollars because the U.S. dollar became the currency that most significantly influences the primary economic environment in which the Company operates. Balances as of December 31, 2024 and 2023 presented in U.S. dollars were translated using the Exchange Rate of Ch$996.46 per US$1.00 and Ch$877.12 per US$1.00, respectively. Amounts in the consolidated statements of comprehensive income and cash flows were translated using the average exchange rate for each period. See Note 3 of the Notes to our consolidated financial statements.
We have prepared our consolidated financial statements under International Financial Reporting Standards (“IFRS”) Accounting Standards, 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.
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, 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
Some figures included in this Report have been rounded for ease of presentation. Due to rounding, the sums in tables may not equal the sums of the entries.
8
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:
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, worldwide or regional health crises, epidemics and pandemics, and interventionist measures by authorities in Chile;
geopolitical events, financial or other crises, armed conflicts in other countries, and foreign exchange risks;
adverse litigation proceedings and labor disputes;
water supply, droughts, flooding, storms, and other weather-related conditions as a result of climate change effects;
changes in Chilean electricity, water, and environmental regulations, including climate regulations to limit greenhouse gas (GHG) emissions, 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;
disruptions in infrastructure and supply chains and fluctuations in market prices of energy and certain commodities;
interruption or failure of our information technology, control, and communications systems, cyberattacks, cybersecurity breaches, and uncertain risks related to artificial intelligence; 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.
Item 1. Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2. Offer Statistics and Expected Timetable
Item 3. Key Information
B. Capitalization and Indebtedness.
C. Reasons for the Offer and Use of Proceeds.
D.
Risk Factors.
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, and could be in the future, negatively affected by arid hydrological conditions, which have 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.
Hydrological conditions in Chile have often been subject to two weather phenomena dealing with ocean currents - El Niño and La Niña - that influence rainfall and may result in drought or flooding, depending on the region affected. In the past, La Niña has affected Chile’s hydrological conditions, leading to rainfall deficits, high temperatures, and higher energy prices in some years, while El Niño has led to unusually intense rains, flooding, and landslides in other years. For example, in 2025, La Niña brought drier conditions during the fall and winter months, resulting in below-average reservoir levels in Chile, which negatively affected our hydroelectric generation.
Our subsidiary Enel Generación Chile has entered into certain agreements with the Chilean government and local irrigators regarding water use for hydroelectric generation during low water levels. However, if droughts persist, we have faced, 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, electricity demand can increase significantly within a short period, affecting service and causing service outages that have resulted in, 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, heavy rainfall or snowfall may occur in a short period and be accompanied by windstorms and lightning. These events may damage our power distribution infrastructure, resulting in service outages. Depending on weather conditions, our distribution business results can vary significantly from year to year.
On August 1 and 2, 2024, the Santiago Metropolitan Region was severely hit by an extraordinary, devastating, and unpredictable storm with winds of up to 124 kilometers per hour, which felled more than 2,000 trees, 800 public service poles and large tree branches and destroyed significant portions of the above-ground electrical energy distribution network. The resulting damages were comparable only to those that occurred during the 2010 earthquake in Chile. The storm caused widespread electrical power outages throughout Enel Distribución Chile’s concession area. While Enel Distribución Chile deployed all available resources and adopted special measures to restore electricity supply to its customers in the shortest time possible under the particular circumstances, several portions of the concession area were without power for an extended period, in some cases for more than 15 days. As a result, the Chilean government initiated an investigation to determine whether the actions taken by Enel Distribución Chile met the concession requirements, considering thousands of customers experienced service outages for an extended period following the storm. Failure to meet the concession’s requirements could result in the revocation and termination of our public service concessions. As of the date of this Report, Enel Distribución Chile has not been legally notified of any administrative proceeding resulting from the Chilean government’s investigation aimed at declaring the termination of its public service concessions for the distribution of electrical energy.
In January 2025, the Chilean Superintendency of Electricity and Fuels (the “SEF”) fined Enel Distribución Chile approximately US$20 million for possible breaches relating to the extended power outages resulting from the August 2024 storm: failure to properly maintain its infrastructure; delay in restoring service; failure to provide information to the government in a timely manner; and failure to have an adequate system to receive customer complaints and outage reports. Enel Distribución Chile subsequently filed a motion requesting the SEF to reconsider the charges and reduce the fine, which remains pending a final court decision.
In February 2025, Enel Distribución Chile announced an agreement with the Chilean National Consumer Service (“SERNAC” in its Spanish acronym) to voluntarily compensate more than 800,000 customers whose service was affected by the August 2024 storm. The Chilean courts approved a total compensation of US$17.1 million, with payments beginning in September 2025.
In July 2025, the SEF fined Enel Distrución Chile approximately US$8.5 million for failure to comply with the Electro-Persons Law (Ley de Electrodependientes) during the August 2024 storm. Enel Distribución Chile subsequently filed motions requesting the SEF to reconsider the charges and reduce the fine, which are currently pending final resolutions.
Our operating expenses also increase during droughts when thermal power plants, which have higher operating costs relative to hydroelectric power plants, are dispatched more frequently to compensate for 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 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 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 to operate our thermal power 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.
11
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 or increasing 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 compensate for 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, 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, and contractual limitations.
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 could adversely affect our business, results of operations, and financial condition. In addition, the dividends paid by our subsidiaries in Chilean pesos are subject to depreciation in relation to the U.S. dollar, our functional and presentation currency, which may have a negative impact on our ability to pay dividends denominated in U.S. dollars to shareholders.
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 other 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 inherent risks to archaeological heritage sites. These factors may also lead to significant delays and cost overruns.
12
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 we fail to engage with our relevant stakeholders, we may face opposition, which could negatively affect our reputation, impact operations, or lead to litigation threats or actions.
Our reputation is the foundation of our relationship with key stakeholders and other constituencies. Any damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, possibly leading to the abandonment of projects and operations, which could cause our share prices to drop and hinder our ability to attract and retain valuable employees. Any of these outcomes could result in an impairment of our goodwill with stakeholders. If we do not effectively manage these sensitive issues, they could adversely affect our business, results of operations, and financial condition.
Our long-term electricity sales contracts are subject to fluctuations in the market prices of certain commodities, energy, and other factors.
We are exposed 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 could 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. Customers who switch must give 12 months’ notice of the change and remain in the new tariff regime for at least four years. In recent years, 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, under the unregulated tariff regime because regulated tariffs are currently higher than unregulated tariffs due to regulated tariffs being based on contracts tendered in the past at higher prices. Additionally, in November 2024 the Ministry of Energy published Exempt Resolution No. 58 lowering the minimum connected capacity requirement for customers to choose unregulated tariffs from 500 kW to 300 kW, which, combined with lower market prices, may reduce the number of customers who choose regulated tariffs. Customers switching to unregulated tariffs may also choose an alternative energy provider other than one of our generation subsidiaries, 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 because they are located far from demand centers. 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 pipeline projects.
On February 25, 2025, a blackout left much of Chile without power for several hours, affecting more than 98% of the population and prompting emergency measures and audits of the electrical system. The outage occurred after a transmission line between Vallenar and Coquimbo was disconnected, triggering a loss of synchrony and cascading supply failures across multiple regions. Recovery required coordination between the National Energy Commission (“CNE” in its Spanish acronym), generation companies, and local authorities and led to investigations and audits of system operators. An independent technical report commissioned by the CNE concluded that, had transmission facilities operated according
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to regulations and operational instructions, a total blackout should not have occurred, highlighting operational and coordination failures and the need to strengthen contingency protocols. The event sparked debate over grid resilience, transmission investment, and regulatory oversight and prompted authorities to announce measures to improve system security and restoration procedures. Prolonged and widespread outages due to transmission disruptions in the future may lead to increased operating costs and lower revenues for our generation and distribution businesses, negatively affecting our business, results of operations, and financial conditions.
The construction of new transmission lines may take longer than in the past, mainly because of higher 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 causing significant disruptions. Stoppages could force us to purchase electricity at spot market prices, which could be higher than the contracted fixed sale price to customers. We could also be forced to dispatch our natural gas power plants using LNG that is transported by barge and is more expensive than natural gas that is transported from Argentina through these pipelines, which, in turn, could increase our operating expenses. These scenarios could adversely affect our business, results of operations, and financial condition.
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. 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 failure to reach a collective bargaining agreement with any labor union or by an agreement 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 if we are unable to hire new employees to fill key positions, and 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.
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 also 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 depends on the physical interconnection of our facilities with the electricity network infrastructure and 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 operations technology systems (“OT Systems”), and other infrastructure, as well as the information processed on our digital assets, could be affected by cybersecurity incidents, including those caused by a compromise in our supply chain or human error. Cybersecurity incidents have evolved dramatically in recent years and have grown exponentially in terms of frequency, severity and sophistication, which have
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been accelerated by the widespread use of tools powered by artificial intelligence and techniques by malicious actors, which could enable faster and more automated, complex attacks.
Given the evolving threat landscape, 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 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.
In addition, 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 to strengthen our digital assets.
In such context, to address these challenges, we believe that it is necessary to adopt a systemic and proactive approach, providing for the definition of a clear and shared strategy, the identification and continuous assessment of risks, the implementation of adequate preventive measures and response to cyber incidents, the creation of a culture of cyber security, together with a close cooperation between public and private sectors to prevent cyber threats and to strengthen the protection and resilience of critical infrastructures.
Although the Enel Group has adopted a “Cyber Security Framework” to guide and manage cybersecurity processes and has created its own organizational model for implementing the Cyber Security Framework processes, we could still be subject to cyber attacks and other cyber security threats to our IT and OT Systems. In such circumstances, we and the Enel Group could be unable to continue to conduct our respective businesses effectively, prevent or respond promptly and appropriately, or mitigate the adverse effects of breakdowns or interruptions in our IT and OT Systems, with possible adverse effects on our reputation, financial condition, assets, business, and results of operations. For further details regarding our Cyber Security Framework, please refer to “Item 16K. Cybersecurity.”
The use of artificial intelligence (“AI”) technology creates uncertain risks for our business.
The Enel Group, including Enel Chile, evaluates opportunities to implement AI in all areas of our business to improve operational efficiency, optimize energy resource management, and develop new and increasingly sustainable solutions. The Enel Group has developed a structured governance framework for the adoption of AI initiatives within its processes. This approach, strongly inspired by the European AI Act, is applied to all Enel Group initiatives to manage risks, identify potential opportunities, and foster a culture of awareness about AI. Due to the rapid development of AI technologies and an uncertain regulatory landscape, successfully identifying and mitigating every associated risk will be crucial. The misuse of AI by our employees, contractors or third-party vendors, or unexpected AI behaviors and decision-making could compromise our IT Systems, operations, and confidential information, which may result in further security risks to our systems and other unpredictable outcomes.
We contract with third-party vendors that use AI in the products and services they provide, and we may not have full visibility into, awareness of, or control over, the underlying data, supply chain dependencies, model training practices, performance, security safeguards, or compliance posture of such AI-enabled tools. The use of third-party AI models, platforms, or cloud services introduces additional risks, including performance failures, service outages, and insufficient indemnities.
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The use of AI technologies may also expose us to claims that training data or model outputs infringe intellectual property rights or misappropriate trade secrets. If our use of the recommendations, content, or analyses that AI applications produce is, or is alleged to be, deficient, inaccurate, or in violation of applicable laws, we could be subjected to legal liability, brand or reputational harm, and operational interruptions.
AI also amplifies cybersecurity risks. Generative AI technology is enabling malicious actors to increase the speed, variation, and sophistication of their cyberattacks, including by modifying code almost instantaneously and deploying thousands of variations of social engineering messages. AI both expands the attack surface and arms adversaries with more sophisticated tools for attacks, escalating the scale and unpredictability of cyber threats. A successful cyberattack leveraging AI capabilities could severely disrupt our business operations, result in data security breaches, or otherwise have a material adverse effect on our business, financial condition, and results of operations.
The development, testing, and deployment of AI capabilities may require significant computational resources, specialized personnel, and additional investment, resulting in increased costs. We may not be able to recover these costs through our regulatory proceedings. Rapid advances in AI capabilities may also require modifications to our systems, adoption of enhanced governance processes, or implementation of new safeguards.
The regulatory landscape surrounding AI, including generative AI, is rapidly evolving and uncertain. Future laws, regulations, or industry standards relating to AI, including those addressing transparency, data usage, cybersecurity, accountability, or risk management, could materially affect how we design, procure, or use AI technologies and could increase compliance costs. The pace of AI innovation and regulation is unpredictable, and we cannot foresee all potential impacts of AI technologies or future laws and regulations, or their associated costs and consequences.
Conversely, any failure by the Enel Group to effectively and timely develop and implement AI technologies, or to attract and retain AI talent, could impair our ability to compete, particularly if competitors incorporate AI more quickly or more successfully to lower costs, improve customer experience, and accelerate innovation. Not advancing the understanding and use of AI may compromise our operational and financial progress. If we fail to keep pace with the rapid evolution of AI technologies in our industry and the segments we serve, our competitive position and business results could be negatively impacted. Any of these events could adversely affect our business, results of operations, financial condition, and reputation.
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 zero direct (Scope 1) 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 GHG 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 affect how we operate our electric generating units and lead to increased competition and regulation.
Our ability to successfully execute our strategic plan, including the transition of our generation facilities and achievement of our GHG 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 and similar matters may hinder our access to capital, as investors may decide to reallocate capital or not commit capital as a result of their assessment of our ESG practices.
We cannot guarantee that we will be able to achieve or maintain our announced ESG goals, practices, and commitments. Our failure or perceived failure to achieve our ESG goals, maintain practices aligned with stakeholder expectations for
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best practices, or comply with new ESG expectations could harm our reputation, adversely affect our ability to attract and retain customers and employees, and expose us to legal and regulatory proceedings and increased scrutiny from a range of stakeholders. Some stakeholders may disagree with our ESG-related goals and commitments, which may negatively affect our business and reputation and the prices of our securities.
Any of these situations could adversely affect our reputation, investment in our securities, or our access to capital markets and negatively impact our results of operations, financial condition, and liquidity.
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 acquisitions and review acquisition prospects to expand and improve 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:
inconsistencies in standards, controls, procedures and policies, business cultures, and compensation structures;
difficulties in integrating various business-specific operating procedures and systems, as well as our financial, accounting, information, and other systems;
complications in retaining key employees, customers, and suppliers;
unexpected transaction costs or failures in the assessed value or a proper projection of the potential benefits and synergies; and
diversion of our management’s attention from its 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.
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 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 CNE and financed by companies in the generation industry, including our subsidiaries Enel Generación Chile and, to a lesser extent, EGP Chile through accounts receivable generated by the differences between the contractual rates and the stabilized rates. The maximum amount of the stabilization fund of US$1.35 billion was reached ahead of schedule in January 2022.
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In July 2022, the Chilean Congress passed Law No. 21,472, which complements Law No. 21,185 by creating a new stabilization fund program and establishing a new transitory mechanism for stabilizing customers’ electricity prices under the regulated price system. The purpose of the mechanism is to limit the increase in electricity bills for regulated customers during 2022 and to allow such increases to occur gradually over the following 10 years. The accounts receivable balances are fully guaranteed by the Chilean government and must be repaid by no later than December 31, 2032. The maximum amount of the stabilization fund program established by Law No. 21,472 of US$ 1.8 billion was reached in February 2024.
In April 2024, Law No. 21,667 was enacted to prevent generation companies from continuing to accumulate debt due to stabilized prices under the regulated price system. Under this law, tariffs for regulated customers will be gradually adjusted to reflect the real costs of energy, and generation companies will be able to recover the balance of debt accumulated under the price stabilization mechanisms generated by Laws No. 21,185 and No. 21,472. Law No. 21,667 increased the stabilization fund established under Law No. 21,472 to US$5.5 billion, of which the US$3.7 billion increased amount has a 30% guarantee of the Chilean government. The increased maximum amount of the stabilization fund program established by Law No. 21,472 of US$5.5 billion was reached in April 2025. The accounts receivable balances must be repaid no later than December 31, 2035.
As a result of applying the laws mentioned above as of and for the year ended December 31, 2025, our current and non-current accounts receivables decreased, while financial income and financial costs increased. 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.
In March 2025, Law No. 21,735 was enacted, reforming the Chilean pension fund regime. Beginning in August 2025, employer contributions to employee pensions will increase gradually over a 9-year period from 1.5% to 8.5% of the employee’s monthly wages. Any increase in our labor costs could have an adverse effect on our business, results of operations, and financial condition.
In October 2025, the CNE announced that a methodological error had occurred in the calculation of electricity tariffs in Chile, which overestimated billing balances to customers, resulting in excessive charges during 2024 and 2025. In response, the CNE approved Exempt Resolution No. 715 and published the Definitive Technical Report for price setting for the first half of 2026, which incorporates the necessary methodological corrections and confirms the refund of the amounts overcharged to regulated customers through reduced regulated tariffs billed to customers during the first half of 2026. The correction will reduce regulated tariffs on average by approximately 2%.
Proposed changes to 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 Generación Chile 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
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31, 2040. In doing so, we became the first power 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.
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 energy 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:
are for an unlimited duration;
are absolute and unconditional property rights; and
are not subject to further challenge. Chilean generation companies must pay an annual license fee for unused water rights. New hydroelectric facilities are required to obtain water rights, and the conditions of such water rights may affect the design, timing, or profitability of a project.
Any revocation of or limitations on our current water rights, additional water rights, the duration of our water concessions, or an 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 regulations to limit GHG emissions.
Future climate change legislation and regulation, particularly measures aimed at reducing GHG emissions, could materially increase our operating costs. Compliance with new regulatory frameworks or international treaties may necessitate significant capital expenditures in advanced technologies and emission control systems. Any failure or delay in implementing such measures could impair our ability to adapt to climate change and result in additional expenses, including operating and maintenance costas, and taxes or fees on emissions. These developments could have a material adverse effect on our business, results of operations, and financial condition.
Material Risks Related to Chile and Other Global Risks
Fluctuations in the Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and other countries may affect our results of operations, financial condition, liquidity, and the value of our securities.
Due to all our operations being in Chile, our consolidated revenues may be affected by the performance of the Chilean economy. We are exposed to political volatility in Chile due to the challenges arising from changes in economic conditions, regulatory policies, and laws governing foreign trade, manufacturing, development, investments, and taxation.
In December 2025, José Antonio Kast was elected as Chile's next president and took office on March 11, 2026. President Kast is a veteran conservative politician who leads the Republican Party and is recognized for prioritizing public safety, enforcing stringent immigration measures, and advancing a business-friendly economic platform centered on limiting government involvement and curbing public expenditures.
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President Kast’s agenda marks a notable departure from the progressive policy direction of outgoing President Gabriel Boric’s administration. His election is broadly viewed as reflective of a wider shift toward the political right in Chile and across portions of Latin America.
Although the details of how his policies to be carried out remain uncertain, questions persist about how his proposed initiatives—especially efforts to strengthen immigration enforcement, scale back regulatory oversight, and pursue fiscal austerity—may reshape Chile’s political, economic, and regulatory landscape. Such policy changes could contribute to heightened social division, alterations to tax, labor, and environmental regulatory regimes, and reallocation of public spending priorities, any of which could have an adverse effect on our business, results of operations, and financial condition.
Ongoing developments in Chile, including revisions to immigration and security policies, adjustments to tax and regulatory structures, and domestic political reactions to shifts in government policy, may impact our ability to carry out our business plan and could adversely affect our growth, results of operations, and financial condition. Additional risks—such as civil unrest, political polarization, changes to exchange controls, and instability in Chilean financial and capital markets, driven by both domestic policy changes and global economic conditions—could also negatively impact our profitability and the value of our securities.
Political events or financial or other crises in any region worldwide can significantly impact Chile and may unfavorably affect our operations and liquidity.
Financial and political events in other parts of the world could diminish our ability to access liquidity through international basic financings or the capital markets in Chile and abroad. Reduced liquidity or ability to obtain new bank financings under the same historical terms and conditions that we have benefited from to date could negatively affect our capital expenditures, long-term investments and acquisitions, growth prospects, and dividend payout policy.
The current presidential administration in the United States has made a number of policy changes to trade, foreign relations, governmental regulation, immigration, and other matters that differ significantly from those of the prior administration, which could have material effects on the global political and economic landscape. In February 2026, the security situation in the Middle East escalated significantly with the commencement of a major military conflict involving the United States, Israel, and Iran. This escalation has led to the closure of the Strait of Hormuz, through which approximately 20% of the world's oil and liquefied natural gas (LNG) supply is shipped, resulting in extreme volatility in global energy prices. Supply disruptions, damage to energy infrastructure, increased shipping and insurance costs, and the rerouting of oil and gas cargos have further exacerbated global energy market instability. These developments have resulted in, and further instability in the Middle East or any other major oil-producing region could further exacerbate, higher fuel prices worldwide. Because our LNG supply contracts are indexed to international commodity benchmarks, including Henry Hub and Brent crude oil prices, disruptions to global energy markets could directly increase the cost of fuel for our thermal generation power plants, which represented approximately 22% of our total net installed capacity and 26.9% of our total electricity generation in 2025. Higher fuel costs have and could further increase the operating costs for our thermal generation power plants and unfavorably affect our results of operations and financial condition. In addition, the imposition of additional sanctions targeting Iran-linked maritime networks, and the potential for expanded trade restrictions, could further constrain global energy supply and increase compliance costs for market participants, with potential knock-on effects on our ability to procure fuel and other inputs on commercially reasonable terms.
We are unable to predict how governmental policy in the United States, China, and other trading partners, or the outbreak of a trade war, may continue to impact global economic conditions. If the scope or amount of the tariffs is further expanded or increased, global economic conditions could be impacted. If Chile experiences lower than expected economic growth or a recession, it is likely that consumer demand for electricity will decrease and that some of our customers may have difficulties paying their electric bills, possibly increasing our uncollectible accounts.
Any of these situations resulting from political events or financial or other crises could adversely affect our results of operations and financial condition.
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We may be subject to the effects of armed conflicts in other countries.
Global markets have been, and may continue to be, subjected to periods of economic uncertainty, volatility, and disruption due to armed conflicts around the world, including the current conflicts in Ukraine and the Middle East, such as between the United States and Israel and Iran. In February 2026, the security situation in the Middle East escalated significantly following the commencement of joint U.S.-Israel military operations against Iran and subsequent Iranian retaliation, leading to the closure of the Strait of Hormuz and broader regional instability. The intensity and duration of this conflict are difficult to predict, and the situation continues to evolve rapidly.
In addition to economic sanctions, such as those imposed on Russia and certain Russian citizens and enterprises, and any additional sanctions that may be imposed in connection with the Middle East conflict, armed conflicts could have a negative effect on the global economy and are highly uncertain and difficult to predict. President Trump has made several statements signaling a shift from the previous administration’s approach to U.S. foreign policy regarding Ukraine, NATO, Venezuela, Cuba and Iran, which could have material effects on the global political and economic landscapes. Although we do not have direct business transactions with suppliers, clients, or lenders from Russia, Ukraine, Venezuela, Cuba or Iran, 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, particularly oil and natural gas, which directly affect the operating costs of our thermal generation power plants; (iv) an increase in inflationary pressures in Chile, which could increase the rates charged to our customers; and (v) increased maritime shipping and insurance costs, and delays or rerouting of LNG cargos, which could disrupt the supply of fuel to the Quintero and Mejillones LNG terminals on which our thermal power plants depend.
Any escalation and expansion of these conflicts, including into a broader and more sustained regional conflict, could have a further negative impact on both global and regional conditions and may adversely affect our business, financial condition, results of operations, and liquidity. The extent and duration of the ongoing conflicts, resulting sanctions, and any related market disruptions are impossible to predict, but could be substantial, particularly if current or new sanctions continue for an extended period of time or if geopolitical tensions result in expanded military operations on a global scale.
Our operations and financial results could be adversely impacted by the effects of worldwide or regional health crises, epidemics or pandemics.
A global or regional health crisis, epidemic or pandemic, or a similar outbreak in a region where we or our key partners, customers, or suppliers operate, could disrupt our business. The extent of the disruption would depend on various factors, including but not limited to, the duration and severity of the outbreak, government-imposed restrictions on businesses and individuals, changes in demand for our products and services, supply chain disruptions, and the health and safety of our employees and the communities in which we operate.
The potential impact of any future health crisis, epidemic or pandemic, and the measures governments and businesses may take to control such outbreaks cannot be predicted and are beyond our control, and it is possible that any such future outbreak could adversely affect our business and results of operations.
Foreign exchange risks may unfavorably affect our results and the U.S. dollar value of dividends payable to ADS holders.
Until December 31, 2024, our functional and presentation currency was the Chilean peso, which has been subject to devaluations and appreciations against the U.S. dollar. Effective January 1, 2025, our functional and presentation currency is the U.S. dollar.
Because all our operations are in Chile, our operating subsidiaries generate revenues in Chilean pesos, and we pay our dividends in Chilean pesos. Although a substantial amount of our consolidated indebtedness and operating cash flows are 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. For information on the change to our functional and presentation currency, see “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,” and Note 3 of the
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Notes to our consolidated financial statements. 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, especially when measured in U.S. dollars.
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 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.
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 related to climate change, catastrophic accidents, natural disasters, 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.
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We are subject to financing risks, such as those associated with funding our new projects and capital expenditures or refinancing existing obligations.
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.
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 funds required to finish our projects in the pipeline or in execution. Likewise, we may be unable to refinance our debt or obtain such refinancing in terms acceptable to us. Without 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 fines, penalties, or 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 the eventual fines or penalties related to each litigation. 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.
Item 4. Information on the Company
We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile. Since April 2016, we have been registered in Santiago with the CMF. 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, 2025, 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:
Roger de Flor 2725, Torre 2, Piso 17
Las Condes, Santiago
Chile
Email:
ir.enelchile@enel.com
Telephone:
(56) 2 26309000
Website:
www.enel.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 became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. (“Chilectra”). In the 1990s, Enersis diversified into electricity generation through increasing equity stakes in Endesa Chile S.A. (“Endesa Chile”).
Enel Chile was created as part of the corporate reorganization process of Enersis that began in April 2015. At the time, Enersis controlled the generation, transmission, and distribution businesses in Chile as well as in Argentina, Brazil, Colombia, and Peru. In December 2015, Enersis’ shareholders approved the first phase of the reorganization plan, which created Enersis Chile as the only vehicle to control the Enel Group’s generation and distribution assets in Chile. Enersis was renamed Enersis Américas and became the vehicle to control all assets of the businesses in other countries in the region. Endesa Chile and Chilectra went through a similar division process to create Endesa Américas and Chilectra Américas.
In September 2016, during the second phase of the plan, Enersis Américas absorbed Endesa Américas and Chilectra Américas and was renamed Enel Américas through the merger.
In October 2016, Enersis Chile, Endesa Chile, and Chilectra changed their names to Enel Chile, Enel Generación Chile, and Enel Distribución Chile, respectively.
Since the merger, Enel Chile’s electricity generation business has been held through its subsidiary Enel Generación Chile, and until 2021 its distribution and transmission business had been operated through its subsidiary Enel Distribución Chile, which operates a 2,105 km2 concession area granted by the Chilean government, for an unlimited duration, to transmit and distribute electricity throughout 33 municipalities in the Santiago Metropolitan Region, including the areas serviced by Enel Colina. The concession area is regarded as a densely populated area in terms of tariff regulation, making the Company the largest electricity commercialization company in Chile.
In August 2017, a corporate reorganization of Enel Chile was proposed, which would involve the merger of Enel Green Power Latin America S.A. with and into Enel Chile and a public tender offer (“PTO”) for 100% of the shares of Enel Generación Chile. The merger was approved in December 2017.
On April 2, 2018, Enel Green Power Latin America merged with and into Enel Chile, and Enel Chile’s shareholding in Enel Generación Chile increased to 93.55%. This transaction added 1,189 MW of installed capacity in non-conventional renewable energy (NCRE), mainly wind and solar technology.
In September 2018, Enel Chile announced the creation of a new subsidiary named Enel X Chile to develop, implement, and sell products and services related to energy that involve innovation, cutting-edge technology, future trends, and ancillary services, but that are not an electricity distribution concession service or considered ancillary to electricity distribution, either regulated or not.
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In accordance with the Law No. 21,194 (the “Distribution Short Law”) approved in late 2019, establishing a “Sole Business” for electricity distribution companies in Chile, Enel Distribución Chile separated its operations into two separate and independent business lines: electricity distribution and electricity transmission. This new structure allowed Enel Distribución Chile to focus exclusively on the regulated electricity distribution business in its concession area and have the new company that resulted from the division, Enel Transmisión Chile, hold the assets and operation of the transmission business as of January 1, 2021.
On December 9, 2022, Enel Chile completed the sale of its entire 99.09% ownership interest in Enel Transmisión Chile to Sociedad Transmisora Metropolitana S.p.A., (a company controlled by Inversiones Saesa Ltda.). The transaction was carried out through a PTO that took place from November 7, 2022, to December 6, 2022.
On January 1, 2023, EGP Chile completed a spin-off of assets and liabilities associated with the solar plants Carrera Pinto, Pampa Solar Norte, Diego de Almagro, and Domeyko (416 MW of total net installed capacity), which were allocated to a new company called Arcadia Generación Solar S.A. (“Arcadia”). All shareholders of EGP Chile received a number of shares of Arcadia equal to the number of shares they held in EGP Chile. As a result, Enel Chile became the owner of 99.99% of Arcadia, which was subsequently sold to Sonnedix Chile Arcadia S.p.A. and Sonnedix Chile Arcadia Generación S.p.A. on October 24, 2023.
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. Our capital expenditures are financed by internally generated funds or direct financings. Our goal is to focus on investments that will provide long-term benefits. 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 cash flows are needed.
For the 2026-2028 period, we expect to make capital expenditures of US$1.8 billion in our subsidiaries, with a strong focus on renewables and digitalization to increase efficiency. Approximately 50% of the capital expenditures will be allocated to renewable energy projects to add 600 MW of installed capacity, mainly in battery storage, wind, and solar. Thermal investments will aim to maintain plant availability and improve efficiency. Additionally, US$400 million will be invested in our grids to improve quality, resilience, and operational effectiveness.
While our planned investments go beyond the 2026-2028 period, we report three years to align with Enel’s three-year industrial plan disclosed in February 2026. Please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further information.
The table below sets forth the cash flows used to purchase property, plant and equipment and intangible assets in 2025, 2024, and 2023.
Year ended December 31,
2025
2024
2023
(in millions of US$)
Cash flows used
499
765
789
Capital Expenditures in 2025, 2024, and 2023
In the last three years, our capital expenditures were principally related to the development of solar projects, PMGD projects, Los Cóndores hydroelectric power plant, wind farms, maintenance of our existing power plants, and projects to facilitate new client connections and optimize our distribution network through digitalization.
During 2025, our distribution business investments focused on facilitating new customer connections and building a more resilient grid through strengthening low- and medium-voltage networks, reinforcing service quality, enhancing emergency
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preparedness and planning, increasing the capacity of our substations, and automating our systems through the installation of remote control devices and smart meters for residential customers.
During 2025, our generation business investments focused primarily on developing battery energy storage systems (“BESS”) projects, PMGD plants, and maintaining and upgrading operating assets. Please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further details 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 execution will be financed with resources provided by external financing and internally generated funds.
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, 2025, we had 8,904 MW of net installed capacity and approximately 2.2 million distribution customers. Of our total net installed capacity, 78% corresponds to renewable energies and BESS, including 3,667 MW of hydroelectric power plants, 903 MW of wind farms, 2,083 MW of solar plants, 83 MW of geothermal capacity, and 203 MW from BESS. All our thermoelectric net installed capacity corresponds to gas/diesel power plants (1,965 MW). As of and for the year ended December 31, 2025, we had consolidated assets amounting to US$12.9 billion and operating revenues of US$4.7 billion.
We also participate in other activities that are not core businesses and represent approximately 1% of our 2025 revenues. We do not report them as a separate segment in this Report or in our consolidated financial statements.
The table below presents our revenues:
Revenues
Change 2025 vs. 2024
(in %)
Generation
3,283
2,950
3,901
11.3
Distribution
1,784
1,739
1,800
2.6
Non-electricity business and consolidation adjustments
(404)
(464)
(485)
(12.9)
Total revenues and other operating income
4,663
4,225
5,216
10.4
For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 28 of the Notes to our consolidated financial statements.
Electricity Generation Segment
In 2025, our consolidated electricity sales were 31,975 GWh, and our electricity production was 21,583 GWh, representing an 11.1% decrease and a 12.4% decrease, respectively, compared to 2024. Our total net installed capacity in 2025 was 8,904 MW, representing a 0.4% increase compared to 2024, due to PMGD projects that were connected to the grid in 2025.
For additional information on our historical capacity, see “Item 4. Information on the Company — D. Property, Plant and Equipment.”
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The following tables summarize the operating data relating to our electricity generation:
ELECTRICITY DATA
Number of generation facilities(1)
76
70
67
Net installed capacity (MW)(2)
8,904
8,869
8,478
Electricity generation (GWh)
21,583
24,639
24,122
Electricity sales (GWh)
31,975
35,974
32,847
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)
Sales
% of SalesVolume
% of Sales Volume
Regulated customers
10,616
33.2
13,895
38.6
11,848
36.1
Unregulated customers
19,370
60.6
19,500
54.2
19,024
57.9
Total contracted sales(1)
29,986
93.8
33,395
92.8
30,872
94.0
Electricity pool market sales
1,989
6.2
2,579
7.2
1,975
6.0
Total electricity sales
100.0
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 the National Electricity System (the “SEN” in its Spanish acronym) dispatches generation companies in excess of their contractual obligations and therefore must sell their surplus electricity in the pool market or when the generators’ electricity dispatched is less than their contractual commitments with customers. Therefore, they must purchase the deficit in the pool market. These purchase and sale transactions among electricity generation companies are typically made in the pool market at the spot price and do not require a contractual agreement.
The regulatory framework often requires that electricity distribution companies have contracts to support their commitments to small-volume customers. Chilean regulations also determine which customers can purchase energy directly in the electricity pool market.
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Tenders
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.
During 2025, Enel Generación Chile submitted bids in two supply tenders to address a short-term supply deficit for regulated customers: CNE Tender 2025/01 (4 years and 3.4 TWh per year) and CNE Tender 2025/02 (1 year and 1.5 TWh per year). Enel Generación Chile was awarded 100% of the energy in both tenders at an average price of US$64.5 per MWh for 2027-2030 (tender 2025/01) and US$98.7 per MWh for 2026 (tender 2025/02).
In May 2024, 3,600 GWh, divided into two parts of 1,500 GWh and 2,100 GWh starting in 2027 and 2028, respectively, were tendered to supply electricity to regulated customers for 20 years. Enel Generación Chile was awarded 100% of the energy tendered for an average price of US$56.68 per MWh. The tender includes an incentive for BESS projects lasting more than 4 hours or for generation projects with non-variable renewable energy, a discount corresponding to US$0.15 per MWh will be applied for each GWh of energy generated by such means in the respective Schedule Block A or C (non-solar), with a limit of US$15 per MWh in each block.
Energy purchases and transportation costs are the principal variable costs involved in the electricity generation business, in addition to the direct variable cost of generating hydroelectric or thermal electricity, such as fuel costs. Our thermal generation increases during relatively low rainfall periods, typically resulting in higher fuel costs. Under dry conditions, the electricity we have contractually agreed to provide may exceed the electricity we generate, requiring us to purchase electricity in the pool market at spot prices to satisfy our contractual obligations. The cost of these purchases at spot prices may, under certain circumstances, exceed the price at which we sell electricity under contracts and, therefore, may result in a loss. We attempt to minimize the effect of poor hydrological conditions on our operations in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. To determine the estimated production in a dry year, we consider the available statistical information concerning rainfall, mountain snow and ice, and when they are expected to melt, hydrological levels, and critical reservoirs’ capacity.
In addition to limiting contracted sales, we may adopt other strategies, including installing temporary thermal power, negotiating lower consumption levels with unregulated customers, negotiating with other water users, and pass-through cost clauses in contracts with customers. For further details about hydrological conditions and their effects on our business, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation and Transmission Business.”
Seasonality
While our core business is subject to weather patterns, only extreme events such as prolonged droughts, rather than seasonal weather variations, may adversely affect our generation capacity and materially affect our operating results and financial condition.
Our 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
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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, EGP Chile, Enel Generación Chile, and Pehuenche. As of December 31, 2025, we had 76 generation power plants in Chile with a total net installed capacity of 8,904 MW, representing 22% of the SEN’s installed capacity in 2025.
Enel Generación Chile owns 14 hydroelectric, six thermal, and two wind-powered power plants, with a total net installed capacity of 4,923 MW. EGP Chile owns 38 solar, nine wind-powered, two hydroelectric, and two geothermal power plants, as well as four BESS, with a total net installed capacity of 3,282 MW. Pehuenche owns three hydroelectric power plants, with a net installed capacity of 699 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.”
The following table sets forth the electricity generation by each of our generation companies:
ELECTRICITY GENERATION BY COMPANY (GWh)
13,577
15,111
15,391
EGP Chile(1)
5,703
6,325
6,012
2,302
3,203
2,719
Total
(1)
Includes all of EGP Chile’s subsidiaries.
It is common in the electricity industry to divide the business into hydroelectric, thermoelectric, and other generation types because each has significantly different variable costs. Thermoelectric generation requires fuel purchase, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers, which typically has immaterial variable costs. Our total hydroelectric generation (including mini-hydro) accounted for 47.9% of our total generation in 2025, reaching 10,339 GWh, a decrease of 24.5% compared to 2024, while our thermal generation accounted for 26.9% of our total generation in 2025, reaching 5,796 GWh, an increase of 18.3% compared to 2024. The SEN dispatched thermal generation power plants more regularly in 2025 to offset lower hydroelectric generation due to drier hydrological conditions compared to 2024.
The following table sets forth the electricity generation by type:
ELECTRICITY GENERATION BY TYPE (GWh)
%
Hydroelectric generation
10,288
47.7
13,636
55.3
12,158
50.4
Thermal generation
5,796
26.9
4,900
19.9
6,198
25.7
Solar generation – NCRE
3,274
15.2
3,627
14.7
3,546
Wind generation – NCRE
2,075
9.6
2,161
8.8
1,796
7.4
Geothermal generation – NCRE
98
0.5
261
1.1
374
1.5
Mini-hydro generation – NCRE
51
0.2
52
49
Total generation
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Water Resource Use Agreements
Water resource use agreements refer to a user’s right to utilize water from a particular source, such as a river, stream, pond, or groundwater. In times of favorable hydrological conditions, water agreements are generally not complicated or contentious. However, with poor hydrological conditions, water agreements protect our right to use water resources for hydroelectric generation. The following agreements allow us to use water more efficiently and avoid additional litigation with the local community and farmers.
We have three current agreements signed with the Chilean Hydraulic Works Directorate (“DOH” in its Spanish acronym). 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 Generación Chile 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 Generación Chile signed an agreement to operate and recover water resources from Laja Lake, complementing the 1958 agreement with DOH.
In August 2025, our subsidiary Pehuenche, Colbún S.A., and the Maule Lagoon Vigilance Board-First Section, renewed an agreement to optimize the use of water during drought periods. The agreement expires on August 31, 2035, and may be further renewed by agreement of the parties.
In October 2025, Enel Generación Chile signed an agreement with the Biobío River Basin Vigilance Board to ensure a minimum volume of water in the Ralco reservoir during the 2025/2026 irrigation season, along with making the generation of the Pangue power plant and its reservoir more flexible.
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 Mejillones LNG Terminal in northern Chile and Quintero LNG Terminal in central Chile 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.
During 2025, Enel Chile, through its subsidiary Enel Generación Chile, used 1.79 billion cubic meters of natural gas for its generation and marketing needs, similar to the volume used in 2024. This volume consisted of 899 million cubic meters of LNG, a 21% decrease compared to 2024, and 891 million cubic meters of natural gas, a 34% increase compared to 2024.
The availability of natural gas from Argentina allowed us to have continuous supply throughout 2025. In 2025, Enel Generación Chile operated utilizing various supply agreements, delivering 836 million cubic meters of Argentine natural gas throughout central Chile, and 55 million cubic meters throughout northern Chile, which represented 50% of our total natural gas requirements in Chile (electricity plus supply to customers).
During 2025, we continued to actively manage the supply of LNG and Argentine natural gas in central Chile by optimizing the supply mix, allowing us to sell LNG at the Quintero LNG Terminal, as well as executing other trading actions. Through the Mejillones LNG Terminal in northern Chile, we supplied the Atacama and Taltal plants and industrial clients with more than 503 million cubic meters of LNG and Argentine natural gas.
In 2025, 128 million cubic meters of LNG were delivered by truck, an increase of 1.6% compared to 2024.
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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
During 2025, the electricity demand throughout the SEN decreased by 0.7% to 79,510 GWh from 80,091 GWh in 2024. Our electricity sales reached 31,975 GWh in 2025, 35,974 GWh in 2024, and 32,847 GWh in 2023, which represented a 40.2%, 44.9%, and 42.1% market share, respectively.
The following table sets forth the SEN’s electricity sales:
ELECTRICITY SALES IN THE SEN (GWh)
Total electricity sales (SEN)
79,510
80,091
77,953
Electricity Generation and Purchases
Our total generation amounted to 21,583 GWh in 2025, which represents a 12.4% decrease compared to 2024, mainly due to lower hydroelectric and solar generation. Energy purchases decreased by 8.3% in 2025, compared to 2024.
The following table sets forth our electricity generation and purchases:
ELECTRICITY GENERATION AND PURCHASES (GWh)
(GWh)
%of Volume
% of Volume
Electricity generation
67.5
68.5
73.4
Electricity purchases
10,393
32.5
11,335
31.5
8,725
26.6
31,976
Generation Customers
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 each customer’s needs, and the conditions are agreed upon by both parties, reflecting competitive market conditions.
For the year ended December 31, 2025, the following two customers individually accounted for 10% or more of the consolidated ordinary revenues of the generation segment: CGE (Compañía General de Electricidad S.A.) and Enel Distribución Chile.
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
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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 experience 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.
Electricity generation companies compete mainly on price, technical experience, and reliability. We have lower marginal production costs than companies whose installed capacity is primarily thermal because 41% of our installed capacity connected to the SEN is hydroelectric. Our installed thermal capacity benefits from access to gas from the Quintero LNG Terminal. However, during periods of extended droughts, we may be forced to buy more expensive electricity from thermal generators at spot prices to comply with our contractual obligations.
Electricity Distribution and Networks Segment
Our distribution and networks operations are conducted through Enel Distribución Chile, 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, 2025, we distributed electricity to approximately 2.2 million residential, commercial, industrial, and other customers, who are primarily municipalities, representing 35.1%, 15.8%, 4.7%, and 44.4%, respectively, of our total electricity sales of 14,534 GWh, a decrease of 1.9% compared to 2024.
The following table sets forth our principal operating data for each of the periods indicated:
14,534
14,810
14,356
Residential
5,096
5,820
5,730
Commercial
2,294
2,213
2,228
Industrial
690
675
410
Other customers(1)
6,454
6,103
5,989
Number of customers (thousands)
2,190
2,163
2,130
1,971
1,944
1,913
158
47
Energy purchased (GWh)(1)(2)
15,401
15,549
15,035
Total energy losses (%)(3)
6.6
5.8
5.3
SAIDI (minutes)(4)
167
150
121
SAIFI (times)
1.3
1.2
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Tariff Update Process
The tariff decree for the 2020-2024 period was issued in June 2024. The tariffs are retroactively effective from November 4, 2020, and will apply until the tariff decree for the 2024-2028 period is issued and the updated tariffs become effective. The 2024-2028 tariff update process is ongoing.
Distribution Customers
For the supply to regulated distribution customers, Enel Distribución Chile’s principal suppliers during 2025 were (in alphabetical order): Colbún S.A., Enel Generación Chile, Engie Energía Chile S.A., and GM Holdings.
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 affect our profitability since the cost of electricity purchased is passed on to end-users through tariffs that are set for multi-year periods. However, in the case of regulated customers, an increase in tariffs due to rate adjustments may not happen immediately, which could affect our profitability in the short term.
ELECTRICITY INDUSTRY STRUCTURE AND REGULATORY FRAMEWORK
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: the 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:
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Generators supply electricity to end customers using lines and substations that belong to transmission and distribution companies. The generation segment operates competitively, and generators may sell their energy to unregulated customers and other generation companies through contracts at freely negotiated prices. They may also sell to distribution companies to supply regulated customers through contracts governed by bids defined by the authorities.
Transmission
Transmission companies own lines and substations with a voltage higher than 23 kV flowing from generators’ production points to the centers of consumption or distribution, charging a regulated toll for the use of their installations. The transmission segment is a natural monopoly subject to special industry regulations, including antitrust legislation. Tariffs are regulated, and access must be open and guaranteed under non-discriminatory conditions.
Distribution 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. 21,194 (the “Distribution Short Law”), distribution companies may not enter into new electricity supply contracts with unregulated customers as of 2021.
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. However, customers with a connected capacity between 300 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 Short 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. 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.
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According to the Electricity Law, there are no restrictions on market concentration for generation and distribution activities. However, Chilean antitrust authorities have imposed specific measures to increase transparency associated with our subsidiaries and us through Resolution No. 667/2002 issued by the 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 Generación Chile, and Enel Distribución Chile 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.
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.
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 had a 10% target by 2024.
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.
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Responsible for Regulation and Supervisory Body
The CNE is the entity in charge of approving the annual transmission expansion plans, managing the indicative plan for the construction of new electricity generation facilities, calculating the rates of generation capacity, and proposing regulated tariffs to the Ministry of Energy for approval. The Superintendence of Electricity and Fuels (the “SEF”) 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
The CEN is a centralized dispatch center that coordinates the SEN’s operations with an approach that minimizes costs while monitoring the quality of the generation and transmission companies’ service. The 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.
The 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.
Remuneration for Generators
To reduce operating costs, the CEN applies an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any given 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 the CEN.
Transmission Tariffs
The remuneration of existing national and zonal transmission installations is determined by a tariff-setting process conducted every four years regulated by Law No. 20,936. This process determines the annual transmission value that considers efficient operation and maintenance costs, and a yearly valuation of investments based on a discount rate determined by the authorities every four years (minimum 7% after-tax) and the installations’ useful life.
The regulation currently in force states that transmission remuneration is the sum of tariff revenue and the usage charge revenue received for the transmission system, defined as $/kWh by the CNE. Revenues are calculated on a semi-annual basis. The tariff-setting process for the 2020-2023 period was concluded in February 2023 and has been effective retrospectively since January 1, 2020. In connection with the tariff-setting process for the 2024-2027 period, the CNE published the definitive technical report for the classification of transmission installations. The tariff-setting process for the 2024-2027 period is expected to be completed in 2026.
Distribution Tariffs
The Distribution Short 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.
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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 Short 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.
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.
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 accelerated 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.
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, 2025. 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 27 countries worldwide and a consolidated installed capacity of 92.8 GW, including BESS. Enel distributes electricity through a network of 1.9 million kilometers to 54 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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We consolidated the principal subsidiaries listed in the following table as of December 31, 2025. 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
ConsolidatedAssets
Consolidated Revenues and Other Operating Income
Electricity Generation
93.55%
4,569
3,181
99.99%
4,670
634
Electricity Distribution
99.09%
3,220
Enel X
100.00%
197
59
For more information about our consolidated subsidiaries, see Note 2.4 of the Notes to our consolidated financial statements.
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Our property, plant, and equipment is concentrated in electricity generation and distribution assets in Chile.
We conduct our generation business through EGP Chile, Enel Generación Chile, and their subsidiaries, which together own 76 power plants, all located in Chile, of which 38 are solar (2,083 MW of net installed capacity), 19 are hydroelectric (3,667 MW of net installed capacity), 11 are wind-powered (903 MW of net installed capacity), six are thermal (1,965 MW of net installed capacity), and two are geothermal (83 MW of net installed capacity), in addition to four BESS (203 MW of net installed capacity).
The following table identifies the power plants and BESS that we own that are connected to the grid, all located in Chile, at the end of each year, organized by company and technology:
Property, Plant, and Equipment of Generation Companies
Net Installed Capacity As of December 31,
Company
Power Plant Name
Power Plant Type(1)
(in MW)
Ralco
Reservoir
689
Pangue
466
El Toro
449
Rapel
377
375
Antuco
Run-of-the-river
320
Los Cóndores
153
—
Cipreses
Abanico
93
Sauzal
80
Isla
Palmucho
Los Molles
Sauzalito
Ojos de Agua
Total Hydroelectric
2,876
2,874
2,720
Atacama
Combined Cycle /Natural Gas+Diesel Oil
716
San Isidro 2(2)
380
San Isidro 1(2)
372
Quintero
Gas Turbine/Natural Gas
236
249
Taltal
Gas Turbine/Natural Gas+Diesel Oil
241
242
Tarapacá
Gas Turbine/Diesel Oil
Total Thermal
1,965
1,979
Canela 2
Wind
64
Canela 1
Total Wind
82
Total Enel Generación Chile
4,923
4,921
4,781
570
Curillinque
Loma Alta
40
Total Pehuenche
699
La Cabaña (1 & 2)
Battery Storage (BESS)
69
Don Humberto
El Manzano
Total Battery Storage (BESS)
203
Cerro Pabellón (1 & 3)
Geothermal
83
Total Geothermal
Pullinque
Pilmaiquén
41
39
92
Guanchoi
Solar
398
Campos del Sol
Las Salinas
205
Valle del Sol
163
Sol de Lila
161
Finis Terrae
160
Finis Terrae Ext
126
99
PMGD(3)
81
Azabache
61
Lalackama
60
Chañares
Lalackama 2
Finis Terrae 3
La Silla
Total Solar
2,083
2,050
1,970
Renaico 2
144
Sierra Gorda Este
La Cabaña
Talinay Oriente
Valle De Los Vientos
Renaico
88
Talinay Poniente
Los Buenos Aires
821
Total EGP Chile
3,282
3,249
3,000
Total Net Capacity Enel Chile
Property, Plant, and Equipment of Distribution Companies
We conduct our distribution business through Enel Distribución Chile 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 Distribución Chile.
Distribution Network – Concession area and Medium and Low Voltage Lines(1)
As of December 31, 2024
As of December 31, 2023
Concession Area (km2)
MV (km)
LV (km)
2,105
5,873
12,375
5,741
12,263
5,709
12,174
Transformers from Medium to Low Voltage for Distribution(1)
Number ofTransformers
Capacity (MVA)
22,664
5,540
22,607
5,411
22,628
5,364
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. 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 insurance companies to negotiate what we believe is the most commercially reasonable insurance coverage.
Project Investments
We continuously analyze potential growth opportunities, together with the profitability of our project portfolio. Industry technology allows for smaller, less environmentally impacting power plants that 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. Our project investments are ordinarily submitted for internal approvals in U.S. dollars but occasionally may be approved in another currency, such as euros.
Below we list our most material projects that reached commercial operation, added additional capacity, were in execution or in the pipeline during the fiscal year ended December 31, 2025. However, any decision related to execution will depend on commercial opportunities foreseen in the upcoming years, including future tenders for supplying the regulated market and the evolution of the regulatory framework (mainly associated with ancillary services). Budgeted amounts include connecting lines that could be owned by third parties and paid as tolls unless otherwise indicated. The financing for all our projects described below comes from internal and external sources.
Distribution and Networks Business Projects
In 2025, our subsidiary Enel Distribución Chile and its subsidiary Enel Colina invested a total of US$163.1 million in projects related to growth and customer connections and developing and maintaining our distribution network.
The most relevant investments in 2025 included the following:
Generation Business Projects
Projects that Reached Commercial Operation in 2025
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 153 MW run-of-the-river hydroelectric power plant, with two Pelton vertical water turbine units that will use water from the Maule Lagoon reservoir through a pressure tunnel. The construction of the power plant and the commissioning tests of equipment were successfully completed in December 2024. The power plant connects to the SEN at the Ancoa substation (220 kV) through an 87 km transmission line.
The total investment was approximately US$1.2 billion. The project was connected to the grid during the fourth quarter of 2024 and reached commercial operation during the first quarter of 2025.
Rapel Hydroelectric Repowering Project
The Rapel Hydroelectric Repowering project was 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 involved replacing two turbine runners (Unit 3 and Unit 4) installed in 1968 with an efficiency rate of less than 85%. The turbines runners have a new hydraulic design offering improved efficiency (>92%) and increase the net installed capacity by 2 MW (1 MW for each unit).
The total investment was approximately US$10 million. The project began in 2023 and was completed in 2025.
Projects that Reached Additional Capacity in 2025
PMGD Solar Projects
There are six PMGD projects in northern and central Chile that have an aggregate net installed capacity of 33 MW. The total investment was approximately US$35 million. Construction began in 2024, and all the projects were connected to the grid during 2025, adding 33 MW of net installed capacity. We expect all the PMGD projects to reach commercial operation in 2026.
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Projects in Execution
Azabache BESS Retrofit
The Azabache BESS Retrofit project is in the Antofagasta Region in northern Chile. It is a greenfield project, and the BESS will have a storage capacity of 94 MW. The project will be built at our Azabache-Valle de los Vientos hybrid power plant and will connect to the grid using the existing Valle de los Vientos substation.
The total approved investment is approximately US$87 million, of which approximately US$10 million had been incurred as of December 31, 2025. Construction on the project began during the second quarter of 2026, and we expect the project to reach commercial operation in 2027.
Las Salinas BESS Retrofit
The Las Salinas BESS Retrofit project is in the Antofagasta Region in northern Chile. It is a greenfield project, and the BESS will have a storage capacity of 206 MW. The project will be built at our Las Salinas solar power plant and will connect to the grid using the existing Las Salinas substation.
The total approved investment is approximately US$170 million, of which approximately US$26 million had been incurred as of December 31, 2025. Construction on the project began during the fourth quarter of 2025, and we expect the project to reach commercial operation in 2027.
Valle del Sol BESS Retrofit
The Valle del Sol BESS Retrofit project is in the Antofagasta Region in northern Chile. It is a greenfield project, and the BESS will have a storage capacity of 153 MW. The project will be built at our Valle del Sol solar power plant and will connect to the grid using the existing Valle del Sol substation.
The total approved investment is approximately US$126 million, of which approximately US$16 million had been incurred as of December 31, 2025. Construction on the project began during the first quarter of 2026, and we expect the project to reach commercial operation in 2027.
Pangue Hydroelectric Repowering Project
The Pangue Hydroelectric Repowering project is being carried out within our existing 466 MW power plant in the Bio-Bio Region in central Chile. Pangue is a reservoir hydroelectric power plant with two Francis vertical units that use water from the Bio-Bio reservoir.
The project involves replacing one rotor (Unit 1) with a modern design that will improve efficiency and reliability and require less maintenance. We expect the upgraded turbine to generate an additional 54 GWh of energy per year.
The total approved investment is approximately US$22 million, of which approximately US$16 million had been incurred as of December 31, 2025. Work at the project site began during the fourth quarter of 2025, and we expect the project to reach commercial operation in 2026.
San Isidro Emissions Reduction
The San Isidro power plant is a combined cycle plant located in the Valparaíso Region, in central Chile, and has a new environmental permit that allows it to extend its operational useful life until 2040. The emissions reduction project at Unit 2 will allow the power plant to comply with the new emissions limits approved by the environmental permit, which also
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allows for eliminating the environmental limit on installed capacity. When the project is completed, the power plant will have a gross installed capacity of 780 MW.
The project consists of installing a selective catalytic reduction (“SCR”) DeNOx system in Unit 2, operating with a < 25% ammonia solution injected into the flue gases upstream of the SCR blocks. The ammonia solution will be provided by trucks and stored in dedicated tanks inside a new building specially designed for this purpose. The project is expected to lower NOx flue gas emissions to 10 mg/Nm3 (with natural gas firing), complying with the new environmental permit.
The total approved investment is approximately US$30 million, of which approximately US$26 million had been incurred as of December 31, 2025. The project began in 2024, and we expect it to be completed in 2026.
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. A new environmental permit was approved in 2025, increasing the limit on the plant’s gross installed capacity to 780 MW from 740 MW. The project consists of upgrading the existing gas turbines to improve the efficiency of both units and increase gross installed capacity by 30 MW (15 MW for each unit), within the approved environmental permit.
The total approved investment is approximately US$26 million, of which approximately US$8 million had been incurred as of December 31, 2025. The project began in 2022, and Unit 2 reached additional capacity in 2023. We expect Unit 1 to reach additional capacity in 2026.
Projects in the Pipeline
We are currently evaluating the following projects and will decide whether to proceed 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.
Cerro Los Loros Wind Project and BESS
The Cerro Los Loros wind farm is in Ovalle in the Coquimbo Region in northern Chile. The project has a net installed capacity of 80 MW, including BESS storage capacity of 30 MW.
The total estimated investment is approximately US$110 million, of which approximately US$1 million had been incurred as of December 31, 2025.
Finis Terrae BESS Retrofit
The Finis Terrae BESS Retrofit project is in the Antofagasta Region in northern Chile. It is a greenfield project, and the BESS will have a storage capacity of 100 MW.
The total estimated investment is approximately US$95 million, none of which had been incurred as of December 31, 2025.
Sol de Lila BESS Retrofit
The Sol de Lila BESS Retrofit project is in the Antofagasta Region in northern Chile. It is a greenfield project, and the BESS will have a storage capacity of 150 MW.
The total estimated investment is approximately US$140 million, none of which had been incurred as of December 31, 2025.
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Major Encumbrances
As of December 31, 2025, 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, 2025 and 2024, and for the three years ended December 31, 2025, are derived from our audited consolidated financial statements included in this Report. Our consolidated financial statements were prepared in accordance with IFRS Accounting Standards (“IFRS”), as issued by the IASB.
The tables are expressed in millions, except for ratios, operating data, and data for shares and ADS. Unless otherwise indicated, and except for information derived from the financial statements as of and for the year ended December 31, 2025, which are prepared in U.S. dollars in accordance with IFRS, all amounts have been translated as described below.
Effective January 1, 2025, Enel Chile changed its functional and presentation currency from Chilean pesos to U.S. dollars because the U.S. dollar became the currency that most significantly influences the primary economic environment in which the Company operates. The comparative periods are required to be translated to the new presentation currency in accordance with IAS 21 “The Effects of Changes in Foreign Exchange Rates.” Balances as of December 31, 2024, and January 1, 2024 presented in U.S. dollars were translated using the Exchange Rate of Ch$996.46 and Ch$877.12 per US$1.00, respectively. Amounts in the consolidated statements of comprehensive income and cash flows were translated using the average exchange rate for each period. See Note 3 of the Notes to our consolidated financial statements.
The following tables set forth our selected consolidated financial data and operating data for the years indicated:
For the year ended December 31,
2024 (1)
2023 (1)
(in millions of US$, except per share or per ADS data)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income
5,215
Raw materials and consumables used
(2,780)
(3,079)
(3,567)
Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expense, by nature
(872)
(751)
(734)
Operating income (loss)(2)
1,011
395
914
Financial results(3)
(237)
(165)
(105)
Other gains
264
Share of profit (loss) of associates and joint ventures accounted for using the equity method
Income (loss) before income taxes
795
239
1,080
Income taxes
(210)
(37)
(270)
Net income
585
202
810
Net income attributable to the Parent Company
538
754
Net income attributable to non-controlling interests
56
Total basic and diluted earnings per average number of shares (US$ per share)
0.00777
0.00222
0.01090
Total basic and diluted earnings per average number of ADS (US$ per ADS)
0.38865
0.11115
0.54520
Cash dividends per share (US$ per share)
0.00445
0.00526
0.00716
Cash dividends per ADS (US$ per ADS)
0.22250
0.26300
0.35800
Weighted average number of shares of common stock (millions)
69,167
As of
December 31,
January 1,
Consolidated Statement of Financial Position Data
Total assets
12,904
12,765
13,492
Non-current liabilities
4,881
5,168
4,878
Equity attributable to the parent company
5,176
4,976
5,069
Equity attributable to non-controlling interests
369
359
Total equity
5,550
5,345
5,428
Capital stock(4)
3,896
5,964
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Exchange Rates
Fluctuations in the exchange rate between the U.S. dollar and the Chilean peso will affect the U.S. dollar equivalent of the price in Chilean pesos of our shares of common stock on the Chilean Stock Exchanges. Also, to the extent that part of our transactions is denominated in foreign currencies, fluctuations in the foreign currency exchange rate may significantly impact our earnings.
There are two currency markets in Chile, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal). The Formal Exchange Market consists of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market includes entities that are not expressly permitted to operate in the Formal Exchange Market, such as 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 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 Exchange Rate within the desired range.
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 2025, one determines the percentage change between the reciprocal of Ch$996.46, the value of one U.S. dollar as of December 31, 2024, or 0.0010036, and the reciprocal of Ch$907.13, the value of one U.S. dollar as of December 31, 2025, or 0.0011024. In this example, the percentage change between the two dates is 9.8%, representing the 2025 year-end appreciation of the Chilean peso against the 2024 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.
The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2021 through December 31, 2025, based on information published by the Central Bank of Chile.
Ch$ per US$(1)
Period End
Appreciation (Devaluation)
(in Ch$)
907.13
9.8
996.46
(12.0)
877.12
(2.4)
2022
855.86
(1.3)
2021
844.69
(15.8)
Source: Central Bank of Chile.
A. Operating Results
General
The following discussion should be read in conjunction with our audited consolidated financial statements and the notes thereto, included in Item 18 in this Report, and the selected financial data included above. Our audited consolidated financial statements as of December 31, 2025, and 2024, and for each year in the three-year period ended December 31, 2025, have been prepared in accordance with IFRS Accounting Standards, 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) actions adopted by governmental authorities in response to extraordinary events during the pandemic, and (v) changes in economic conditions may materially affect our financial results. We transact a significant portion of our business in U.S. dollars, while another part of our transactions is in Chilean pesos, which means that financial conditions are affected by variations in the exchange rate between the U.S. dollar and the Chilean peso. 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. This Law creates a Temporary Regulated Customer Tariff Stabilization Mechanism that states that the price to charge regulated customers for electricity from July 1, 2019, through December 31, 2020, is to be equal to the prices in force during the first half of 2019 (Decree 20T/2018). This stabilized price was named the “Stabilized Regulated Customer Price” (Precio Estabilizado para Clientes Regulados or “PEC” in its Spanish acronym). From January 1, 2021, until the stabilization mechanism is suspended, the prices will be those defined in the tariff-setting processes carried out every six months as established in Article 158 of the Electricity Law, but not to exceed the PEC adjusted for inflation using the Consumer Price Index as of January 1, 2021, as a baseline (adjusted PEC). The billing differences until 2023 were recorded as accounts receivable in favor of electricity generation companies, limited to a maximum of US$1,350 million, which was reached ahead of schedule in January 2022. The balance of these accounts receivable is to be recovered, at the latest, by December 31, 2027.
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 electricity distribution companies to end customers and the amount payable to electricity generation companies. The resources available for the MPC may not exceed US$1,800 million through a new instrument called a Payment Document in U.S. dollars that is indexed and transferable, with a maximum due date of December 2032 and State guarantee that is issued monthly by the General Treasury of the Republic to energy generating companies. The maximum amount of the stabilization fund program established by Law No. 21,472 of US$1,800 billion was reached in February 2024.
On March 14, 2023, Resolution No. 86 was published, and on August 9, 2023, Exempt Resolution No. 334 was published, which was amended by Exempt Resolution No. 379 of August 8, 2024, establishing, among other matters, certain provisions, procedures, deadlines, and conditions for the proper implementation of Law No. 21,472.
On April 30, 2024, Law No. 21,667 was published, which, among other things, establishes the following:
It allows generation companies not to accumulate more debt, since the tariffs for customers subject to price regulation will gradually take on the real costs of energy and power prices.
Generation companies will recover the balances generated by the Tariff Stabilization Law and Law No. 21,472, the PEC and MPC stabilization mechanisms, respectively.
The MPC fund limit is increased to US$5,500 million, of which the additional US$3,700 million will have a 30% government guarantee. These balances must be paid no later than by December 31, 2035.
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The most vulnerable customers will be protected through the creation of an electricity subsidy.
Furthermore, customers with monthly consumption exceeding 350 kWh will pay the real price of the energy and power as of the date of publication of the average node price decree for the first half of 2024 plus an additional charge (MPC charge) that will allow the accumulated debt from the PEC and MPC stabilization mechanisms to be extinguished. Customers with monthly consumption equal to or less than 350 kWh will pay the real price of energy and power as of the date of publication of the decree for the second half of 2024, and from the publication of the decree for first half of 2025 the MPC charge will be added.
The effects of the Tariff Stabilization Law as of December 31, 2025, and 2024 are described in Note 9a.1 of the Notes to our consolidated financial statements.
Effective January 1, 2025, Enel Chile changed its functional and presentation currency from Chilean pesos to U.S. dollars because the U.S. dollar became the currency that significantly influences the economic environment in which the Company operates.
The change to the functional currency was primarily driven by the fact that, effective January 1, 2025, Enel Generación Chile, a subsidiary of Enel Chile, also changed its functional currency from Chilean pesos to U.S. dollars. This change reflects a shift in the subsidiary’s main source of revenue, comes predominantly from agreements with unregulated customers. These unregulated customer agreements, due to their billing and collection cycles, give rise to significantly less exchange rate risk compared to agreements with regulated customers, whose extended collection periods result in greater exchange rate fluctuation exposure. The group of regulated customer agreements represented the Company's main source of revenue in 2024.
Accordingly, given the relevance of the Generation segment within the Group, the Company’s principal source of revenue—dividends from its subsidiaries—will be determined on a U.S.-dollar basis, consistent with the Company’s functional and presentation currency. For further information, see Note 3 of the Notes to our consolidated financial statements.
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, 2025, 2024, and 2023 was 8,904 MW, 8,869 MW, and 8,478 MW, respectively, of which 41.2, 41.3%, and 41.4% were hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”
Hydroelectric generation was 10,339 GWh, 13,688 GWh, and 12,208 GWh in 2025, 2024, and 2023, respectively. Our hydroelectric generation decreased in 2025 compared to 2024, mainly related to worse 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. The 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 remunerate 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 are almost always the least expensive generation technologies 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 during 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 higher 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 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.
Hydrologicalconditions
Expected effects on spot pricesand 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 our contracted energy sales, the energy deficit is covered by spot market purchases at lower prices.
Negative: if our generation is higher than our contracted energy sales, energy surpluses 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 for sale in the spot market.
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If factors other than those described above apply, the expected impact of hydrological conditions on operating results will differ from those shown above. For instance, in a dry year with lower commodity prices, spot prices may decrease, or in a wet year, if demand increases or generation plants are not available for technical or other reasons, the spot price may increase, altering the impact of hydrological conditions discussed in the table above.
Our electricity Distribution and Networks segment is conducted through Enel Distribución Chile in the Santiago Metropolitan Region, providing electricity to approximately 2.2 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, 2025, electricity sales were 14,534 GWh, representing a 1.9% decrease compared to 2024. For the year ended December 31, 2024, electricity sales were 14,810 GWh, representing a 3.2% increase compared to 2023.
Distribution and Networks segment 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 segment 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 5.9% for the 2023-2025 period, a level close to our concession’s distribution technical loss threshold. Reducing losses below this level requires additional investments to reduce illegal tapping that 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 on increasing our quality of service to enhance the effectiveness of our facilities, profitability of our business, and our capacity to satisfy our growing number of customers and their increasing demands.
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 process was concluded in 2024 and is retroactively effective from November 4, 2020, and will remain in effect until the tariff decree for the 2024-2028 period is issued and the updated tariffs become effective.
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.
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 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 SEF issued Circular No. 140129 to modify the instructions provided by SEF 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.
As a result of the application of these laws as of December 31, 2025, our current and non-current accounts receivable decreased compared to the previous year. Please see Note 9 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. We transact a significant portion of our business in U.S. dollars, which is the currency of the primary economic environment in which we operate and is our functional and presentation currency for financial reporting purposes, while another portion of our transactions is in Chilean pesos because most of our operations occur in Chile. Therefore, an increase or decrease in the exchange rate between the Chilean peso and the U.S. dollar affects our operating results, as well as our assets and liabilities, depending on the amounts denominated in Chilean peso. For additional information, see “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 other countries 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
Average
Year End
Chilean pesos per U.S. dollar
950.43
943.74
839.91
Source: Central Bank of Chile
2.
Analysis of Results of Operations for the Years Ended December 31, 2025 and 2024
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, 2025 and 2024:
Years ended December 31,
2024(1)
Change
Generation segment
Enel Generación Chile, EGP Chile, and subsidiaries
333
Distribution and networks segment
Enel Distribución Chile and subsidiary
438
Effective January 1, 2025, our functional currency is the U.S. dollar, which is accounted for prospectively from that date. We also changed the presentation currency to U.S. dollars in 2025. The change in presentation currency was accounted for as a change in accounting policy and applied retrospectively, as if the new presentation currency had always been the presentation currency in the consolidated financial statements. See Note 3 of the Notes to our consolidated financial statements.
Generation Segment: Revenues and other operating income
Revenues and other operating income from our Generation segment increased US$333 million, or 11.3%, in 2025 compared to 2024, driven by:
(i)
a US$215 million increase in energy sales, mainly due to:
a)
the impact in 2024 of the recognition at the end of 2024 of a US$657 million loss from the discontinuation of certain accounting cash flow hedges that were entered into to reduce the exchange rate risk of revenues directly linked to the U.S. dollar from our subsidiary Enel Generación Chile. The discontinuation of these hedges occurred because Enel Generación Chile changed its functional currency to the U.S. dollar effective as of January 1, 2025, thereby eliminating the exchange rate risk; and
b)
US$125 million in lower losses from exchange rate hedging revenue.
These effects were partially offset by:
c)
a US$373 million decrease due to lower physical volumes sales (-3,998 GWh), driven by lower physical sales to regulated customers (-3,279 GWh), lower spot market physical sales (-590 GWh), and lower physical sales to unregulated customers (-129 GWh); and
d)
a US$198 million decrease from a lower average sales price.
(ii)
a US$68 million increase in other sales, mainly from higher gas sales in 2025;
(iii)
a US$46 million increase in other operating income, mainly due to:
a US$50 million increase in revenue from insurance claims; and
US$6 million in higher income from the collection of a bank guarantee associated with a supplier contract termination agreement.
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US$12 million in lower additional revenue related to the improved commercial terms in transactions with energy and fuel suppliers recognized in 2024.
Distribution and Networks Segment: Revenues and other operating income
Revenues and other operating income from our Distribution and Networks segment increased US$45 million, or 2.6%, in 2025 compared to 2024, primarily driven by:
an US$18 million increase in other operating income, mainly due to:
US$15 million in higher insurance claims recoveries; and
US$4 million in higher income from recovery of unrecorded consumption.
a US$16 million increase in energy sales, primarily due to:
a)a US$28 million increase from recalculations of energy tariffs from previous years;
This was partially offset by:
a US$ 12 million negative foreign currency translation effect resulting from the devaluation of the Chilean peso against the U.S. dollar during the period between 2024 and 2025.
a US$13 million increase in revenue from other services, driven by higher revenue from customer power connection works and public lighting projects.
These increases were partially offset by:
(iv)
a US$2 million decrease in revenue from other services, such as antenna leasing, network connections, and connections relocations.
Total Raw materials and consumables used
The following table sets forth our total raw materials and consumables used for the years ended December 31, 2025 and 2024 by segment.
1,736
1,956
(220)
(11.2)
1,474
1,555
(81)
(5.2)
(430)
(432)
(0.5)
Total raw materials and consumables used
2,780
3,079
(299)
(9.7)
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Generation Segment: Raw materials and consumables used
Raw materials and consumables used in our generation segment decreased US$220 million, or 11.2%, in 2025 compared to 2024, mainly due to:
US$149 million in lower energy purchase costs, driven by lower physical purchase volumes (-942 GWh);
US$79 million in lower transportation costs, primarily due to:
a US$39 million decrease in regasification and gas transportation costs; and
US$34 million in lower toll expenses.
US$14 million in lower other variable procurement and services costs, primarily due to:
US$9 million of lower thermal emissions tax expense; and
US$6 million in lower cost of commodity hedging derivatives; net of a US$2 million increase in cost of sales in gas trading.
These decreases were partially offset by:
(iv) US$22 million of higher fuel consumption costs due to:
a US$35 million increase due to higher gas consumption.
US$11 million in lower commodity hedging costs; and
US$2 million in lower oil consumption.
Distribution and Networks Segment: Raw materials and consumables used
Raw materials and consumables used in our distribution and networks segment decreased by US$81 million, or 5.2% in 2025 compared to 2024, mainly due to:
a US$45 million decrease in energy purchases mainly due to:
US$35 million in lower physical purchase volumes of energy (-147 GWh); and
a US$10 million favorable foreign currency translation effect resulting from the devaluation of the Chilean peso against the U.S. dollar during the period between 2024 and 2025.
a US$26 million decrease in other procurement and services explained by:
a US$28 million decrease in fines imposed by the SEF; and
US$1 million in lower outage and service restoration costs.
US$3 million in higher value-added services costs.
a US$10 million decrease in transmission expenses due to lower transmission tolls.
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Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expenses.
Our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses, and other expenses are comprised of salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.
The following table sets forth our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expenses for the years ended December 31, 2025 and 2024, by segment:
591
516
75
14.5
228
198
43.2
Total employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expenses, by nature
872
751
16.1
Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased US$121 million, or 16.1%, in 2025 compared to 2024, mainly due to:
a US$74 million increase in depreciation and amortization, primarily related to the commissioning of new renewable energy plants;
a US$19 million increase in impairment losses on accounts receivable, mainly in the Distribution and Networks segment, driven by a higher-than-expected credit loss allowance related to residential customers;
a US$10 million increase in other expenses by nature in the Generation segment, including:
US$3 million in higher maintenance and repair services;
US$2 million in higher technical and administration services; and
US$2 million in higher outsourced services.
a US$9 million increase in other expenses by nature in the Distribution and Networks segment, primarily due to:
US$5 million in higher expenses related to the winter plan; and
US$3 million in higher operation and maintenance costs.
(v)
a US$7 million increase in personnel expenses in the Generation segment, mainly due to:
a US$5 million non-recurring expense for incentives associated with early retirement plans; and
US$2 million in higher employee collective bargaining agreement bonuses.
(vi)
an US$8 million decrease in personnel expenses in the Distribution and Networks segment, mainly due to:
US$6 million in lower expense for the payment of the employee collective bargaining agreement bonuses; and
US$5 million in higher capitalization of personnel costs for investment projects.
These effects were offset by:
US$4 million in non-recurring expense for incentives granted to employees participating in early retirement plans.
Consolidated Operating Income
The following table sets forth our operating income by reportable segment for the years ended December 31, 2025 and 2024:
956
479
477
99.6
(13)
94
n.a.
(26)
(71)
(63.4)
Total consolidated operating income
616
155.9
Operating margin(2)
21.7%
9.3%
(2)
Operating margin, a measure of efficiency, represents operating income as a percentage of revenues and other operating income. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses.
Our operating income in 2025 increased US$616 million, or 155.9%, compared to 2024 due to the following:
Generation Segment: Operating Income
Operating income totaled US$956 million for the year ended December 31, 2025, an increase of US$477 million, or 99.6%, compared to 2024, primarily due to an increase in revenues driven by (i) the discontinuation of hedges accounting for certain cash flow hedges that had been used to hedge the foreign-exchange risk on U.S. dollar-linked revenues at our subsidiary Enel Generación Chile that impacted 2024; (ii) higher gas sales in 2025; and (iii) higher insurance recoveries and lower raw materials and consumables used compared to 2024, mainly due to (i) lower energy purchase costs, driven by lower physical purchase volumes; and (ii) lower transportation costs.
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Distribution and Networks Segment: Operating Income
Operating income totaled US$81 million for the year ended December 31, 2025, an increase of US$94 million compared to 2024, primarily due to (i) higher insurance recoveries and (ii) higher energy sales explained by an increase in retroactive adjustments related to prior year sales contracts, partially offset by lower physical energy volumes sales and an unfavorable foreign currency translation effect resulting from the devaluation of the U.S. dollar against the Chilean peso and lower raw materials and consumables used compared to 2024, mainly due to lower energy purchase costs and other lower other procurement and services costs driven by a reduction in fines imposed by the SEF.
Consolidated Financial and Other Results
The following table sets forth our financial and other results for the years ended December 31, 2025 and 2024:
Financial results
Financial income
72
(11)
(13.3)
Financial costs
(330)
(247)
(83)
33.6
Gain from indexed assets and liabilities
(9)
(40.9)
Foreign currency exchange differences
(23)
(134.8)
Total financial results
(72)
43.6
Other results
Share of the profit of associates and joint ventures accounted for using the equity method
66.7
Total other results
133.3
Total consolidated financial and other results
(216)
(156)
(60)
38.5
Financial Results
Consolidated financial results was a loss of US$237 million, an increase of US$72 million for the year ended December 31, 2025, as compared to the loss of US$165 million in 2024, primarily attributable to:
an US$11 million decrease in financial income, mainly due to:
US$14 million in lower interest on accounts receivable from electric distribution companies, as a result of delays in issuing the corresponding tariff decrees;
US$10 million in lower income from temporary investments in fixed-income instruments;
US$2 million in lower interest income related to the application of the Tariff Stabilization Law; and
US$1 million in lower financial income from customer agreements.
These effects were partially offset by a US$19 million increase from a methodological adjustment by the CNE, related to the financial update procedure for accounts receivable pending billing from previous years. See Note
58
34, Footnote (3) regarding financial income from the methodological change of the CNE of the Notes to our consolidated financial statements.
an increase of US$83 million in financial costs, mainly due to:
US$83 million in lower capitalized interest, primarily in the generation segment, due to the “Los Cóndores” power plant entering into service in the first quarter of 2025; and
US$61 million in higher financial costs, due to the methodological adjustment by the CNE, related to the financial restatement of accounts receivable pending invoicing from prior years. See Note 34, Footnote (3) regarding financial cost from the methodological change of the CNE of the Notes to our consolidated financial statements.
US$36 million in lower financial costs with related parties, driven by lower outstanding indebtedness with Enel Finance International (“EFI”);
US$16 million in lower financial costs from supplier payment schedule optimization agreements; and
e)
US$11 million in lower financial costs related to losses from the sale of accounts receivable from finance leases in the first quarter of 2024 related to electric mobility projects.
a US$9 million decrease from gains from indexed assets and liabilities, mainly due to:
US$13 million in lower income from the indexation of trade receivables.
US$5 million in higher gains from the indexation of tax assets.
a US$31 million increase in gains from foreign currency exchange rate differences, mainly due to:
US$52 million in higher positive exchange rate differences on trade accounts receivable and accounts receivable from related parties; and
US$144 million in lower foreign exchange losses on net financial debt and derivative instruments.
US$165 million in higher foreign exchange losses on trade accounts payable and accounts payable to related parties.
These effects primarily reflect the change in functional and presentation currency of Enel Chile and Enel Generación Chile.
Other Results
Gain on disposal of assets increased by US$12 million in 2025, compared to 2024, primarily due to:
US$5 million in higher proceeds from sales of other property, plant and equipment; and
US$4 million in higher profit-sharing distributions from our associate GNL Chile S.A.
Consolidated Income Tax Expenses
The effective tax rate was 26.4% in 2025, compared to 15.4% in 2024.
Consolidated income tax expense totaled US$210 million in 2025, an increase of US$173 million compared to 2024, mainly due to:
a US$150 million increase in income tax expense attributable to higher profit in 2025; and
a US$23 million increase in tax expense resulting from the elimination of the tax price-level restatement at Enel Chile, Enel Generación Chile, and Empresa Eléctrica Pehuenche following the change in the functional and presentation currency to U.S. dollars from Chilean pesos, which was accounted for prospectively as of January 1, 2025.
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, 2025 and 2024:
Operating income
Financial and other results
Net income before taxes
556
232.6
Income tax (expenses)
(173)
467.6
Consolidated net income
383
189.6
385
251.6
(4.1)
Net income attributable to our parent company increased US$385 million in 2025 compared to 2024, mainly due to the effect caused to the discontinuation of certain accounting cash flow hedges that were entered into to reduce the exchange rate risk of revenues directly linked to the U.S. dollar from our subsidiary Enel Generación Chile. The discontinuation of these hedges occurred because Enel Generación Chile changed its functional currency to the U.S. dollar effective as of January 1, 2025, thereby eliminating the exchange rate risk.
3. Analysis of Results of Operations for the Years Ended December 31, 2024 and 2023
Effective January 1, 2025, our functional and presentation currency is the U.S. dollar, which was accounted for prospectively as of that date. The comparative figures for years and periods prior to January 1, 2025, presented in our Annual Report on Form 20-F previously filed with the SEC on April 30, 2024, were translated for our consolidated statements of comprehensive income using the average exchange rate for each period.
The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 2024 and 2023:
(951)
(24.4)
(61)
(3.4)
(4.3)
(991)
(19.0)
Revenues and other operating income from our generation segment decreased US$951 million, or 24.4%, in 2024 compared to 2023, due to:
a US$428 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency;
a US$254 million decrease in other sales, mainly due to lower gas sales in 2024;
a US$232 million decrease in energy sales, mainly due to:
a US$657 million losses from the discontinuation of certain accounting cash flow hedges that were entered into to reduce the exchange rate risk of revenues directly linked to the U.S. dollar from our subsidiary Enel Generación Chile. The discontinuation of these hedges occurred because Enel Generación Chile changed its functional currency to the U.S. dollar effective as of January 1, 2025, thereby eliminating the exchange rate risk; and
US$41 million in lower commodity hedging revenue.
a US$278 million increase in physical sales (+3,127 GWh), due to higher regulated customer sales (+2,047 GWh), spot market sales (+604 GWh), and unregulated customer sales (+476 GWh); and
US$188 million in a higher average sales price due to a positive exchange rate effect during the 2024 period.
a US$37 million decrease in other operating revenues, mainly due to:
US$29 million in lower additional revenue related to the improvement of commercial terms of transactions with energy and fuel suppliers in 2023; and
US$21 million in lower revenue from commodity hedges.
a US$9 million increase in revenue from insurance claims.
Revenues and other operating income from our Distribution and Networks segment decreased US$61 million, or 3.4%, in 2024 compared to 2023, primarily due to:
a US$197 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency;
a US$7 million decrease in revenue from other services, due to lower revenue from the construction of customer power connections and public lighting.
an increase of US$143 million in energy sales mainly due to:
US$109 million in a higher average sales price due to a positive exchange rate effect during the 2024 period; and
US$54 million increase in physical energy sales (+454GWh), primarily in the commercial and industrial customer segments.
an increase in provisions related to collective voluntary process agreements with the National Consumer Service (“SERNAC” in its Spanish acronym) for US$18 million, related to the weather events that occurred in May and August 2024.
The following table sets forth our total raw materials and consumables used for the years ended December 31, 2024 and 2023 by segment.
2,474
(518)
(20.9)
1,573
(18)
(1.1)
(480)
(10.0)
3,567
(488)
(13.7)
Raw materials and consumables used in our Generation segment decreased US$518 million, or 20.9%, in 2024 compared to 2023, mainly due to:
62
a US$214 million decrease in fuel consumption costs, mainly due to:
a US$123 million decrease in gas consumption costs due to lower thermal electricity generation and a lower average purchase price;
a US$79 million decrease in commodity hedging costs due to improved hydrological production during 2024; and
a US$12 million decrease in fuel-oil consumption costs primarily due to lower thermal electricity generation.
a US$92 million decrease in other variable procurement and services costs, primarily due to:
a US$71 million decrease in gas commercialization cost of sales;
a US$28 million decrease in commodity hedging costs; and
a US$5 million decrease in rental cost associated with the leasing of temporary fixtures.
US$12 million of higher thermal emission tax expense.
a US$30 million increase in transportation costs primarily due to US$48 million of higher regasification and gas transportation costs, partially offset by a decrease of US$17 million due to reduction in tolls; and
a US$30 million increase in energy purchases mainly due to higher physical energy purchases (+2,611 GWh: +2,356 GWh from other power generators and +255 GWh on the spot market).
Raw materials and consumables used in our Distribution and Networks segment decreased by US$18 million, or 1.1% in 2024 compared to 2023, mainly due to:
a US$170 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency.
This decrease was partially offset by:
a US$125 million increase in energy purchases mainly due to US$90 million in a higher average purchase price when expressed in U.S. dollars and a US$35 million increase in physical energy purchases (+514 GWh); and
a US$27 million increase in other procurement and services explained by:
a US$31 million increase in fines imposed by the SEF, including the US$20 million (280,000 UTM) fine related to the extraordinary, devastating, and unpredictable storm on August 1 and 2, 2024.
This increase was partially offset by:
US$3 million in lower costs related to disconnecting and reconnecting customers’ power supply; and
US$1 million in lower costs of value-added services.
63
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 sets forth our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense for the years ended December 31, 2024 and 2023, by segment:
494
4.5
189
4.8
(15)
(28.8)
735
2.2
Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased US$16 million, or 2.2%, in 2024 compared to 2023, mainly due to:
a US$38 million increase in depreciation and amortization expense in the generation segment primarily due to US$50 million of higher expenses in EGP Chile primarily related to the commissioning of new solar generation units and the increase in the exchange rate, partially compensated by US$18 million in lower expenses resulting from the sale of Arcadia in October 2023;
a US$29 million increase in impairment loss of property, plant and equipment primarily mainly explained by US$36 million higher expenses in the generation segment due to the impairment of the Las Salinas power plant expansion project recognized at year-end 2024. This was partly offset by US$7 million in lower property, plant and equipment impairment loss related to the gas-fired unit of Tarapacá power plant booked in 2023;
a US$26 million increase in other expenses mainly explained by;
a US$14 million increase in maintenance and repair costs related to the weather events during May and August of 2024;
an US$8 million increase in maintenance and repair services due to the commissioning of new solar and wind projects; and
a US$7 million increase in insurance premiums.
an US$8 million increase in accounts receivable impairment losses in the distribution and networks segment due to the lower credit rating of residential customers;
a US$4 million increase in depreciation and amortization expense in the distribution and networks segment primarily due to the commissioning of projects that were previously in the development stage; and
a US$3 million increase in depreciation of right-of-use assets related to the lease of the Group’s new corporate building.
All of the above were partially offset by:
(vii)
an US$81 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency;
(viii)
an US$11 million decrease in personnel expenses mainly due to:
a US$4 million decrease in expenses related to the Group’s digitalization strategy;
a US$2 million decrease in vacation provisions; and
a US$2 million increase in capitalization of personnel expenses related to investment projects.
a US$1 million increase in employee collective bargaining agreement bonuses and other employee benefits.
The following table sets forth our operating income by reportable segment for the years ended December 31, 2024 and 2023:
934
(455)
(48.7)
(50)
(135.1)
(57)
(14)
24.6
(519)
(56.8)
Operating margin(1)
17.5%
Our operating income in 2024 decreased compared to 2023 due to the following:
Operating income totaled US$479 million for the year ended December 31, 2024, a decrease of US$455 million, or 48.7%, compared to 2023, primarily due to:
(i) the discontinuation of certain accounting cash flow hedges that were entered into to reduce the exchange rate risk of revenues directly linked to the U.S. dollar from our subsidiary Enel Generación Chile. The discontinuation of these hedges occurred because Enel Generación Chile changed its functional currency to the U.S. dollar effective as of January 1, 2025, thereby eliminating the exchange rate risk; and (ii) lower gas sales in 2024.
The raw materials and consumables used totaled US$1,956 million as of December 31, 2024, a decrease of US$518 million, or 20.9%, compared to 2023, mainly due to lower gas consumption costs and commodity price hedging costs.
65
Operating income was a loss of US$13 million for the year ended December 31, 2024, a decrease of US$60 million, or 48.7%, compared to 2023, primarily due to:
(i) a decrease in revenues and other operating income driven by (a) a decrease due to the conversion of the variations in the 2024 results compared to 2023 due to the change in the functional and presentation currency, (b) lower revenue from the construction of power connections and public lighting and (c) greater provisions related to collective voluntary process agreements with SERNAC related to the weather events that occurred in May and August 2024; and
(ii) lower raw materials and consumables used compared to 2023, mainly due to a decrease due to the conversion of the variations in the 2024 results compared to 2023 due to the change in the functional and presentation currency.
The following table sets forth our financial and other results for the years ended December 31, 2024 and 2023:
(77)
(48.1)
(294)
(16.0)
(8)
(26.7)
(22)
57.1
28.6
(264)
271
(262)
(96.7)
166
(322)
(194.0)
Consolidated financial results was a loss, which increased by US$60 million for the year ended December 31, 2024, as compared to 2023, primarily attributable to:
a decrease of US$77 million in financial income, mainly due to:
US$46 million in lower interest income from accounts receivable with distribution companies, related to billings that have been accumulating since July 2022 due to the postponement of the issuance of the corresponding tariff decrees;
a US$16 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency; and
US$15 million in lower income on short-term fixed income investments.
66
a decrease of US$47 million in financial costs, mainly due to:
a US$32 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency;
a US$27 million decrease in interest expenses mainly related to losses from the sale of accounts receivable in 2023, specifically related to the Company’s financial leasing contracts related to electromobility projects;
US$11 million in lower interest income, mainly related to the implementation of the Tariff Stabilization Law for US$8 million; and
a US$5 million decrease in financial expenses resulting from amendments to the supplier payment schedule.
US$18 million in higher interest expenses on bonds and bank loans; and
f)
US$10 million in higher financial expenses with related parties resulting from a higher amount of debt owed to EFI.
a decrease of US$8 million from indexed assets and liabilities, mainly due to:
US$14 million in lower income from the indexation of recoverable taxes and other non-financial assets;
US$8 million in lower income from the indexation of trade accounts receivable; and
a US$4 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency.
a US$15 million increase in positive effects caused by IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of Enel Generación Chile located in Argentina; and
a US$3 million increase in income due to trade accounts payable indexation.
an increase of US$22 million in loss from foreign currency exchange rate differences, mainly due to:
US$182 million in higher negative exchange rate differences on related party trade accounts payable related to loans obtained from EFI;
US$167 million in higher negative exchange rate differences on financial debt and derivative instruments;
US$161 million in higher negative exchange rate differences on trade accounts payable, including a negative effect of US$99 million related to the tariff stabilization mechanisms established by the Tariff Stabilization Law, Law No. 21,472, and Law No. 21,667 that dollarized accumulated billings to regulated customers; and
a US$2 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency.
US$306 million in higher positive exchange rate differences on trade accounts receivable from related parties, primarily accounts receivable from EGP Chile;
US$145 million in higher positive exchange rate differences on trade accounts receivable related to the tariff stabilization mechanisms established by the Tariff Stabilization Law, Law No. 21,472, and Law No. 21,667;
g)
US$25 million in higher positive exchange rate differences on other financial assets; and
h)
US$14 million in higher positive exchange rate differences on cash and cash equivalents.
Gain on disposal of assets decreased US$264 million in 2024, compared to 2023, mainly due to the US$228 million gain on the of sale the Company’s 99.99% share ownership in Arcadia on October 24, 2023, offset by a US$29 million decrease due to the conversion of this sale, at the average exchange rate for each period, due to the change in functional and presentation currency. The sale price for this transaction was US$553 million. This was compared to 2024 in which there were no significant gains.
The effective tax rate was an income tax expense of 15.4% in 2024, compared to 25.0% in 2023.
Consolidated income tax expense totaled US$37 million in 2024, a decrease of US$233 million compared to 2023, mainly due to:
a US$136 million decrease in income tax expense due to the Company’s lower profit in 2024;
a US$65 million decrease in income tax expense due to the sale of Arcadia in October 2023; and
a US$37 million decrease due to the conversion of the variations in the 2024 results compared to 2023, at the average exchange rate for each period, due to the change in functional and presentation currency.
a US$5 million increase in income tax expense related to price level restatement.
The following table sets forth our consolidated net income before taxes, income tax expenses, and net income for the years ended December 31, 2024 and 2023:
(841)
(77.9)
233
(86.3)
(608)
(75.1)
(601)
(79.7)
(7)
(12.5)
68
Net income attributable to our Parent Company decreased US$601 million in 2024 compared to 2023, mainly due to the effect caused to the discontinuation of certain accounting cash flow hedges that were entered into to reduce the exchange rate risk of revenues directly linked to the U.S. dollar from our subsidiary Enel Generación Chile. The discontinuation of these hedges occurred because Enel Generación Chile changed its functional currency to the U.S. dollar effective as of January 1, 2025, thereby eliminating the exchange rate risk.
B. Liquidity and capital resources.
Our main assets are our consolidated Chilean subsidiaries, EGP Chile, Enel Distribución Chile, and Enel Generación Chile. The following discussion of cash sources and uses reflects the key drivers of our cash flow.
We receive cash inflows from our subsidiaries and related companies. Cash flows from our subsidiaries and associates 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, 2025, 2024, and 2023:
2023(1)
Net cash flows provided by operating activities
1,320
1,622
840
Net cash flows used in investing activities
(738)
(103)
Net cash flows used in financing activities
(771)
(1,095)
(1,112)
Net increase (decrease) in cash and cash equivalents before the effect of exchange rate changes
(211)
(375)
Effect of exchange rate changes on cash and cash equivalents
(46)
(6)
Cash and cash equivalents at the beginning of the period
642
1,023
Cash and cash equivalents at the end of the period
462
Net cash flows provided by operating activities were US$1,320 million for the year ended December 31, 2025, a decrease of US$302 million, or 18.6%, compared with the same period in 2024. The decrease was driven by:
US$148 million lower collections from sales of goods and services, principally in our Generation segment due to lower physical sales volumes (-3,998 GWh—including sales to regulated customers -3,279 GWh, spot market sales -590 GWh, and sales to unregulated customers -129 GWh) and a lower average sales price;
US$66 million in higher income tax payments;
US$55 million in higher payments to suppliers, primarily in our Generation segment due to higher fuel consumption costs, primarily from higher gas consumption;
US$27 million in higher other payments for operating activities;
US$12 million in lower collections from leasing and subsequent sale of those assets;
US$7 million in lower other collections for operating activities; and
US$4 million in other cash outflows.
These effects are partially offset by:
(viii) US$10 million in lower payments to employees; and
(ix) US$7 million in lower payments for manufacturing or acquiring assets held for lease to others and subsequent sales.
For the year ended December 31, 2024, net cash flows provided by operating activities were inflows amounting to US$1,622 million, representing an increase of 93.1%, or US$782 million, compared to the same period in 2023. The increase was in part the result of:
US$636 million from increased cash collections from the sale of goods and services principally from (a) our Generation segment due to higher energy sales of 2,047 GWh mainly in the spot market and to regulated customers; and (b) our Distribution and Networks segment due to higher physical energy sales of 454 GWh mainly in the industrial and residential customer segments;
US$136 million from decreased payments to suppliers mainly from our generation segment due to lower thermal electricity generation and a lower average purchase price. This was partially offset by an increase of 2,611 GWh in physical energy purchases; and
US$10 million from decreased income tax payments in 2024, mainly due to:
a US$280 million increase in Enel Chile’s income tax payments in 2023 due to the gain from the sale of Enel Transmisión Chile in December 2022; and
a US$51 million decrease in income tax payments due to the Company’s lower profit in 2024.
a US$119 million decrease from foreign currency exchange rate differences, due to the change in functional and presentation currency;
a US$90 million increase in Enel Generación Chile’s income tax payments;
a US$74 million increase in Enel Chile’s income tax payments due to the gain from the sale of Arcadia in 2023; and
a US$38 million increase in 2023 due to Enel Generación’s Chile income tax refund.
For further information regarding our operating results in 2025, 2024, and 2023, please see “— A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2025, and 2024” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2024, and 2023.”
Net cash flows used in investing activities were US$488 million for the year ended December 31, 2025, a decrease of US$250 million, or 33.9%, compared with the same period in 2024, primarily due to:
US$263 million in lower cash outflows for the purchase of property, plant and equipment;
US$4 million in lower purchases of intangible assets;
US$2 million in higher proceeds from the sale of property, plant and equipment; and
US$2 million in lower payments to acquire equity or debt instruments of other entities.
(v) US$10 million in lower interest received;
US$9 million in lower proceeds from futures, forward, options, and swap contracts; and
US$4 million in lower other investing cash inflows.
For the year ended December 31, 2024, net cash flows used in investing activities were outflows amounting to US$738 million, representing an increase of 616.5% or US$635 million, compared to the same period in 2023, mainly due to:
an increase of US$725 million in cash flows from the purchase of property, plant and equipment due to additional plants and equipment mainly for the Generation segment;
a US$104 million decrease from foreign currency exchange rate differences, due to the change in functional and presentation currency; and
an increase of US$41 million in cash flows from the purchase of intangibles assets due to an increase in intangible assets under development, primarily in the Generation segment, and greater investment in software.
These investing activities net cash flow outflows were partially offset by:
a US$22 million increase in interest received; and
US$4 million in higher cash received from future, forward, options, and swap contracts corresponding to financial derivatives.
For the year ended December 31, 2025, net cash flows used in financing activities were US$771 million, a decrease of US$324 million, or 29.6%, compared to US$1,095 million in 2024.
The aggregate cash payments associated with financing activities in 2025 were primarily due to:
71
US$351 million in dividend payments, of which US$198 million was paid to Enel, our controlling shareholder, and US$154 million to third parties;
US$190 million in loan principal payments by Enel Chile;
US$174 million in interest payments (US$134 million paid by Enel Chile and US$40 million paid by Enel Generación Chile);
aggregate outflows from financing activities in 2025 of US$161 million primarily from loan payments by Enel Chile to EFI;
US$47 million in bond principal payments by Enel Generación Chile; and
US$37 million in leasing liability payments and other cash outflows.
These financing activities were partially offset by:
aggregate inflows from financing activities from short-term loans in 2025 of US$190 million.
For the year ended December 31, 2024, net cash flows used in financing activities were US$1,095 million, a decrease of US$17 million, or 1.53%, compared to US$1,112 million in 2023.
The aggregate cash payments associated with financing activities in 2024 were primarily due to:
US$454 million in bond principal payments by Enel Generación Chile;
US$366 million in dividend payments, of which US$215 million was paid to Enel, our controlling shareholder, and US$151 million to third parties;
US$347 million in loan principal payments by Enel Chile;
aggregate outflows from financing activities in 2024 of US$147 million: inflows primarily from loans received from EFI, a related company, of US$1,157 million; and outflows primarily from loan payments by Enel Chile to EFI for US$1,304 million;
US$218 million of interest payments (US$2 million paid by EGP Chile; US$51 million paid by Enel Generación Chile; and US$164 million paid by Enel Chile); and
US$39 million in leasing liability payments and other cash outflows.
aggregate inflows from financing activities from short-term loans in 2024 of US$475 million.
For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — C. Risk Factors — We depend on distributions from our subsidiaries to meet our payment obligations.” Please see Notes 20 and 23 of the Notes to our consolidated financial statements for further details regarding the features and conditions of financial obligations and financial derivatives. These notes also refer to the material cash requirements of known contractual and other obligations.
Contractual Obligations
The table below sets forth our cash payment of contractual obligations as of December 31, 2025:
Payments Due by Period
Contractual Obligation
2026
2027-2028
2029-2030
After 2030
In millions of US$
Purchase obligations(1)
20,012
9,491
6,252
3,543
726
Yankee bonds
1,317
1,206
Interest expense
1,193
177
247
132
638
Accounts payable to related parties(2)
1,022
400
300
Bank debt
930
192
504
Lease obligations
Local bonds
100
Pension and post-retirement obligations(3)
Total contractual obligations
25,140
10,119
8,131
4,280
2,611
Includes Generation and Distribution business purchase obligations, comprised mainly of electricity purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of US$20,012 million, 50% corresponds primarily to fuel supply, maintenance of medium- and low-voltage lines, cable and utility poles, and electricity purchased for generation, and 48% corresponds to electricity purchased for distribution. The remaining 2% corresponds to miscellaneous services, such as LNG regasification and fuel transportation.
Represents loans payable to EFI.
(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.
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 Enel Chile level 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, as a holding company, we 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.”
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, 2025:
Aggregate Principal Amount
Issuer
Term
Maturity
Coupon
Issued
Outstanding
10 years
June 2028
4.875%
1,000
Enel Generación Chile(1)
30 years
February 2027
7.875%
230
206
Enel Generación Chile(2)
40 years
February 2037
7.325%
220
100 years
February 2097
8.125%
200
5.575%
(3)
1,650
73
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 (US$657 million as of December 31, 2025). As of December 31, 2025, and as of the date of this Report, there have been no issuances of bonds under this program.
Our subsidiary, Enel Generación Chile, 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 Generación Chile that are outstanding on December 31, 2025:
Coupon (inflation
adjusted rate)
(in millions of UF)
Enel Generación Chile Series M
21 years
December 2029
4.75%
10.00
3.64
159.3
Enel Generación Chile Series H
25 years
October 2028
6.20%
4.00
0.67
29.4
4.98%
(1)
14.00
4.31
188.7
For a complete description of local bonds issued by Enel Generación Chile, 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. The following table lists our U.S. dollar syndicated and bilateral revolving loans, which are governed by the laws of the State of New York and Chile, and the amounts outstanding as of December 31, 2025.
Borrower
Type
Lender
Maturity(1)
Facility Amount
Amount Drawn
Bilateral Revolving Loan
September 2030
290
Corporación Andina de Fomento (CAF)
December 2027
Syndicated Revolving Loan
DNB Bank ASA & Citibank N.A.
March 2027
The disbursement of the revolving loans is 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 allows us complete flexibility for a drawdown under any circumstances, including situations involving an MAE.
Additionally, we and our subsidiaries have also entered into uncommitted Chilean bank facilities for approximately US$118.5 million in the aggregate, none of which was drawn as of December 31, 2025. Unlike the committed lines described above, which are not subject to an MAE condition precedent to disbursements, these facilities are subject to a risk of not being disbursed because they are subject to an MAE condition precedent to disbursements. Our liquidity could be limited under such circumstances.
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As for our term loans, the detail of each transaction and the outstanding principal amount as of December 31, 2025, is described in the following table:
Issuance Date
Outstanding principal
Term Loan
March 2020
March 2030
December 2015
322
SDG-linked Term Loan
April 2021
April 2031
Citibank N.A. - London Branch
May 2024
December 2037
286
European Investment Bank
December 2022
244
Scotiabank Chile
December 2021
December 2026
December 2023
December 2038
101
July 2023
July 2038
October 2022
October 2037
1,952
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, 2025, 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 Generación Chile’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 liquidity and is 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 do not affect the payment of dividends or distributions to us as of the date of this Report. Certain credit facilities and investment agreements of our subsidiaries may restrict dividends or distributions in certain exceptional circumstances. For instance, one of Enel Generación Chile’s UF-denominated Chilean bonds limits intercompany loans that Enel Generación Chile and its subsidiaries can lend to related parties. The threshold for such aggregate restrictions 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 2026 through 2028 are expected to amount to US$1.8 billion related to renewables and digitalization to increase efficiency. Approximately 50% of the capital expenditures will be allocated to renewable energy to add 600 MW of installed capacity, mainly in battery storage, wind, and solar. Thermal investments will aim to maintain plant availability and improve efficiency. Additionally, US$400 million will be invested in our grids to improve quality, resilience, and operational effectiveness.
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 external financings.
C. Research and Development, Patents and Licenses, etc.
D. Trend Information.
Generation Segment
Enel Generación Chile expects that the percentage of revenue from contracts with unregulated customers will exceed revenue from contracts with regulated customers from 2025 onwards. This trend is expected to continue for at least the next 10 years. This forecast is supported by two material facts, firstly: some contracts expired in December 2024. These contracts were with regulated customers at prices that are significantly higher than the current ones. Secondly, new contracts with unregulated customers commenced in 2025, some of which include prices in U.S. dollars. As a result of these changes, the Company’s management is focusing on the unregulated market and is using the U.S. dollar as the Company’s functional and presentation currency effective as of January 1, 2025.
Supply Contracts
During 2025, Enel Generación Chile executed medium- and long-term supply contracts with unregulated customers for approximately 3 TWh, structurally complementing the Company’s very favorable contract curve obtained in prior years.
In addition, the trend in the Chilean electricity market characterized by a high volume of smaller customers who have the option to migrate to the regulated market but chose to remain as unregulated customers, in accordance with the rights granted under the electricity regulations has continued. This context was very favorably leveraged by Enel Chile through its subsidiary, Enel Generación Chile, which entered into supply contracts directly with a large number of smaller unregulated customers, reaching a total of 0.9 TWh, with average maturities of approximately four years.
Hydrology
2025 was preceded by wet hydrological conditions in 2023 and part of 2024, allowing the Laja and Maule reservoirs to recover water levels. This enabled the Company to begin 2025 with higher levels of stored water, partially offsetting the drier hydrological conditions that occurred during 2025.
During 2024, Pacific Ocean temperatures declined, shifting from El Niño conditions at the beginning of 2024 to La Niña conditions at the beginning of 2025, which remained throughout the year, fluctuating between neutral and La Niña conditions. In Chile, La Niña is associated with a decrease in precipitation, which largely explains the very dry hydrological condition observed in 2025.
Fuel Prices
During 2025, the prices of several fuels declined compared to 2024, resulting in lower supply costs for the SEN. In the case of coal, according to statistics published by the electricity authority, the average annual price decreased by approximately 10%, from US$128 per ton in 2024 to US$115 per ton in 2025. With respect to natural gas, although the international Henry Hub index reference increased on average by 56% (from USD 2.3 to USD 3.6 per MMBtu), imports of Argentine natural gas were carried out at lower prices, leading to reductions of more than 10% in the variable operating costs of thermal power plants. Finally, the price of Brent crude oil, which has a lower share in generation within the SEN, declined by 14.3%, from US$80.6 per barrel to US$69.1 per barrel. Taken together, these developments, along with increased renewable generation, helped Enel Chile to contain the rise in marginal costs compared to 2024.
Distribution and Networks Segment
In our distribution and networks segment, some customers who meet certain requirements are free to choose between regulated and unregulated tariffs. They must give 12 months’ notice of the change and remain in the new regime for at least 4 years. Additionally, the minimum connected capacity requirement for customers to choose unregulated tariffs is currently 300 kW, which, combined with lower market prices, may reduce the number of customers who choose regulated tariffs. Customers switching to unregulated tariffs may also choose an alternative energy provider other than one of our generation subsidiaries, which could adversely affect our business, results of operations, and financial condition.
VAD Reassessment
During 2025, the SEF requested information, through various official communications, to validate the VAD costs and prepare a recalculation during the first quarter of 2026. The Ministry of Energy’s Decree 5T will establish tariff formulas applicable to supplies subject to regulated prices, provided by distribution concession companies, for the period 2020-2024. This recalculation will have an impact on all customers of Enel Distribución Chile and will be applied once instructed by the Ministry of Energy.
Commercial Operations
During 2025, debt collection and regularization management continued to be marked by the challenges arising from tariff increases related to VAD and PEC. In terms of allocation of collection actions, more than 39 million actions were assigned during 2025, recovering a total of US$890 million, an increase of 9% compared to 2024. The collection strategy included intensifying actions by customer, actions by customer segment and debt age, highlighting disconnection notices and the offering of payment agreements. With respect to service disconnections, 572,000 disconnection actions were carried out, recovering US$78 million, an increase of 18.8% compared to 2024.
Digitalization Strategy
Enel Chile is carrying out a digital transformation process of its entire value chain, developing new business models and digitalizing processes, integrating systems, and adopting new technologies. These initiatives help accelerate the digitalization of network infrastructure through the innovation and development of a robust and resilient electricity system. We continue to add technology to get closer to our customers, connect with them, and anticipate and solve their needs by providing greater service reliability and quality while strengthening and digitalizing the physical network.
For information regarding our critical accounting estimates, see Note 2.3 of the Notes to our consolidated financial statements.
Item 6. Directors, Senior Management, and Employees
A.
Directors and Senior Management.
Directors
Our board of directors (the “Board”) 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 may elect a temporary director to fill the vacancy until the next OSM, at which time the entire Board will be elected for new three-year terms. Our executive officers are elected and hold office at the discretion of the Board.
Our current Board was elected at the OSM held on April 28, 2025, for a three-year term that ends in April 2028. As of December 31, 2025, the members of our Board were as follows.
Position
Age(1)
Current PositionHeld Since
Marcelo Castillo Agurto
Chairman
Gina Ocqueteau Tacchini
Director
María Teresa Vial Álamos
Pablo Cruz Olivos
Rodolfo Avogadro Di Vigliano
Salvatore Bernabei
2016
Valentina de Cesare
Set forth below are brief biographical descriptions of the members of our Board as of December 31, 2025.
Marcelo Castillo Agurto: Mr. Castillo is currently the director of institutional affairs & international governance for the Enel Group, Rest of the World area, which covers 26 countries in the Americas, Africa, Asia, and Oceania. Mr. Castillo has more than 15 years of experience teaching energy regulation and management at several colleges and business schools. In his 34 years with the Enel Group, he has held various positions, including duties in Africa, Asia, Italy, Latin America, the Middle East, Spain, and the United States. He joined the Enel Group’s commercial division in 1990, eventually becoming deputy director of Endesa Chile. He went on to work for Endesa Chile as deputy director of energy management, deputy commercial director, and head of analysis. In 2002, he served as deputy business director in the Endesa S.A.-Morgan Stanley joint venture for the European power and gas trading market and commerce, and he also became director and vice president of regulation for Latin America, a position he held for more than 11 years. In 2013, he assumed the role of head of international regulatory and antitrust affairs at Enel Grids, and a year later, he became head of business development, a post he held until October 2023. Mr. Castillo holds a degree in civil, industrial, and electrical engineering from Pontifícia Universidad Católica de Chile, and an MBA from Universidad de Navarra in Madrid, Spain.
Gina Ocqueteau Tacchini: Ms. Ocqueteau is currently the Chair of the board of directors of SQM, in addition to serving on various boards and advisory councils of business organizations, foundations, and entities linked to Chile’s productive development, innovation, and international projection. She is a Chilean executive with more than 30 years of experience in leadership, strategic management, and corporate governance, with a distinguished career in regulated companies, trade associations, foundations, and impact-driven ventures. Her expertise has primarily focused on risk management, occupational health and safety, sustainability, organizational culture, and human resource development, bringing a comprehensive, long-term perspective to strategic decision-making. For more than three decades, she developed her career at the Chilean Safety Association (ACHS), where she held various senior management positions, including General Manager, leading organizational transformation processes in complex and highly demanding operational environments. She has been recognized on several occasions as one of Chile’s “100 Leading Women,” a reflection of her sustained contribution to business, institutional, and social development. Ms. Ocqueteau holds a nursing degree from Universidad de Chile. She has also carried out postgraduate studies and executive programs in administration, marketing, productivity and corporate governance in Chile and other countries.
María Teresa Vial Álamos: Ms. Vial is the head of the Santiago Chamber of Commerce and director of Artikos S.p.A. She is also a member of the Directors’ Network for Climate Action at Chapter Zero Chile. She holds a law degree and a certificate in negotiation from Pontificia Universidad Católica de Chile. She also holds a master’s degree in business law and a certificate in construction from Universidad de Los Andes.
Pablo Cruz Olivos: Mr. Cruz currently serves as a director of numerous private companies and non-profit foundations. During his tenure at ExxonMobil, Mr. Cruz held executive, managerial, commercial, and operational roles in various countries throughout Latin America and the United States. He served as an executive and director at Empresas Relsa for more than 11 years, and subsequently at Arval Relsa. He has served as a consultant and advisor to companies in the energy sector in Latin America for the development of new businesses and asset acquisitions. Mr. Cruz holds a degree in civil engineering from Pontificia Universidad Católica de Chile and has certificate from the Executive Management Program (PADE) at Universidad de Los Andes.
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Rodolfo Avogadro Di Vigliano: Mr. Avogadro is currently head of Legal and Corporate Affairs, Rest of World Area for the Enel Group. Previously, he held key positions such as head of M&A and Group Significant Litigation of the Enel Group. He has also led the legal departments of Enel X and Enel Green Power in various regions, providing guidance in project development, daily operations, and extraordinary transactions in Europe, North Africa, the Middle East, and Latin America. He also served as chairman of the board of Enel Distribución Chile and as a member of the board of directors of international companies such as Slovenské Elektárne AS. Mr. Avogadro is a lawyer with dual qualifications, authorized to practice in Italy and England and Wales, and has more than 25 years of private practice and in-house experience. He has gained significant international exposure, having studied and worked for more than ten years in New York, London, and Madrid. Mr. Avogadro holds a law degree from the University of Milan and an LLM from New York University.
Salvatore Bernabei: Mr. Bernabei has served as the head of Enel Green Power and thermal generation since 2020. Since October 2020, Mr. Bernabei has served as president of the Res4Africa Foundation (Renewable Energy Solutions and Electrification for Africa). He joined the Enel Group in 1999 as logistics manager for Enel Distribuzione. He later served as supply chain manager for geothermal energy projects and a project manager for wind energy projects in Italy. He served in a variety of capacities at Enel Green Power, including manager for safety and environment in Iberia and Europe and engineering and construction manager for Iberia and Latin America. Additionally, during his tenure in Iberia, he served as director of renewables operations and maintenance. In 2013, he assumed the position of country manager for Chile and the Andean countries at Enel Green Power. Subsequently, he was appointed head of renewable energies for Latin America. He served as the global procurement director at the Enel Group from 2017 to 2020. Mr. Bernabei holds a degree in industrial engineering from Università degli Studi di Roma “Tor Vergata,” and an MBA from Politecnico di Milan.
Valentina de Cesare: Ms. de Cesare is currently the head of Project, Planning, Control, and Risk Management in the Engineering and Construction area of Enel Green Power. Ms. de Cesare began her career at Enel in 2010 as a civil specialist in the nuclear technical area and later served as a project engineer at the Mochovce Nuclear Power Plant. During her career with the Enel Group, she has held various positions in the generation division at Enel Green Power, such as project engineer and civil specialist in the hydroelectric power plant design unit; responsible for improvement projects and the preparation of reports in the area of Health, Safety, Environment and Quality; and subsequently, leader of the interdisciplinary program “Next Gen,” focused on the energy transition of the Group. From 2020 to 2025, she served as executive assistant to the CEO of the Enel Group. Since May 2025, she has served on the board of directors of Nuclitalia, a company dedicated to the study of next-generation nuclear technologies for Italy. She holds a degree in civil engineering and a master’s degree in structural engineering from the University of Rome “La Sapienza.”
Executive Officers
Set forth below are our executive officers as of December 31, 2025:
Year Joined Enel or Affiliate
Gianluca Palumbo
Chief Executive Officer
1996
Simone Conticelli
Chief Financial Officer
2006
Gaetano Manzulli(2)
People & Organization Officer
2010
Juan Diaz Valenzuela
Internal Audit Officer
Pedro Urzúa Frei
External Relations & Sustainability Officer
2012
Set forth below are brief biographical descriptions of our executive officers as of December 31, 2025.
Gianluca Palumbo: Mr. Palumbo has served as Enel Chile’s CEO since July 2025. He has more than 28 years of experience dedicated to transforming the global electricity industry. He joined the Enel Group in 1996 and has held several positions, including head of distribution operations in Italy, global manager of Grid Development, Planning, and Control, and CEO of EDESUR in Argentina. Mr. Palumbo holds a degree in electrical engineering from the University of Naples Federico II.
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Simone Conticelli: Mr. Conticelli has served as Enel Chile’s chief financial officer since October 2024. He joined the Enel Group in 2006, where he worked in Administration, Finance, and Control (“AFC”) as head of planning and control for Global Digital Solutions and the “Divisione Mercato Italia,” as well as in human resources as the Group’s head of organizational development. Before joining the Enel Group, he worked in the AFC for Fincantieri, a shipbuilding Company, and Value Partners, a strategic consulting firm. In 2019, he was the head of planning and industrial control for Global Power Generation Chile area, and subsequently CFO of Enel Generación Chile. In 2023, he was appointed CFO of Slovenske Elektrarne. He . Mr Conticelli holds a degree in nuclear physics from Università degli Studi di Roma “Tor Vergata,” and an MBA from LUISS Business School.
Gaetano Manzulli: Mr. Manzulli has served as the manager of People and Organization at Enel Chile since January 1, 2025. He joined the Enel Group in 2010 in Italy. He has been responsible for major projects for the Enel Group and has had a variety of work experiences in Italy and Latin America. He assumed the role of manger of People and Organization for Colombia, Panama, Guatemala, and Costa Rica in February 2024. He holds a master’s degree in electrical engineering from Politecnico di Bari.
Juan Díaz Valenzuela: Mr. Díaz has been internal audit and compliance manager for Enel Chile and its subsidiaries since February 2022. He joined the Enel Group in 2010. He has held various responsibilities in Internal Audit in Latin America across the different business lines of the Enel Group. Between 2019 and 2022, he served as audit and compliance manager for Enel Peru and its subsidiaries, where he successfully implemented the Anti-Bribery Management Systems and compliance with the local crime prevention 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.
Pedro Urzúa Frei: Mr. Urzúa has served as manager of external relations and sustainability at Enel Chile, which includes Institutional Relations, Communications, and Sustainability areas, since April 1, 2024. He served as chief of staff for the Ministries of Planning and Cooperation and Mining. From 2006 to 2012, he worked for the National Oil Company (ENAP), initially serving as communications director at ENAP Sipetrol and subsequently as corporate affairs director. In 2012, he became the director of the Fundación Acción RSE. In November 2012, he joined the Enel Group as institutional relations manager for Chile and the Andes at Enel Green Power, and later as institutional relations manager at Enel Chile. He is currently the director of the San Ignacio de Huinay Foundation, the Chilean Chapter of the World Energy Council (WEC), and the Chilean-Argentine Chamber of Commerce. Mr. Urzúa holds a degree in journalism from Universidad de Artes y Ciencias de la Comunicación (UNIACC).
B.
Compensation.
At the OSM held on April 28, 2025, our shareholders approved our Board’s compensation policy for 2025. 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 a 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 2025, the total compensation paid to each of our directors, including fees for attending Directors’ Committee meetings, was as follows:
FixedCompensation
Ordinary and Extraordinary Session
Directors’Committee (Fixed Compensation)
Ordinary and Extraordinary Session (Directors’ Committee)
Marcelo Castillo Agurto(1)
136
107
195
Rodolfo Avogadro Di Vigliano(1)
Salvatore Bernabei(1)
Valentina de Cesare(1)
Isabella Alessio(1)(2)
Pablo Cabrera Gaete(2)
108
We do not disclose any information about an individual executive officer’s compensation. Executive officers are eligible for variable compensation under short-term and long-term bonus plans.
Executive officers are eligible for variable compensation under an annual cash bonus plan. The annual bonus plan is paid to our executive officers for achieving company-wide objectives and for their contribution to our results and goals. The annual bonus plan provides a range of cash bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries.
Enel Chile has an ongoing long-term incentive (LTI) plan designed to reward executive officers and other eligible employees with cash bonus payments for the achievement of certain financial and strategic goals focusing on the creation of long-term shareholder value, as determined by the Company from year to year, for three-year performance periods. The performance goals determined in any given year may not apply uniformly to each executive officer and eligible employee. The Company may determine a differentiated set of goals for each participant depending on role, responsibilities, and strategic priorities.
The financial and strategic goals for the performance period for fiscal years 2025 to 2027 include relative total shareholder return, return on average capital employed, percentage of women managers and middle managers, earnings per share, system average interruption duration (SAIDI) of the Distribution business and Scope 1 CO2eq emissions intensity of the Generation business.
The LTI plan’s long-term bonus opportunity is based on a percentage of each participant’s base salary. The LTI plan awards vest at the conclusion of each three-year performance period, subject to achievement of threshold levels of performance and the participant’s continued employment, and will be cash-settled in subsequent years. For the 2025-2027 performance period, the long-term bonus, if earned, will be paid in two installments in 2028 and 2029, unless the participant elects a single payment in 2029.
For the year ended December 31, 2025, the aggregate gross compensation, paid and accrued, for all our executive officers, attributable to the fiscal year 2025, was US$1.5 million in fixed compensation, and US$429,000 in short-term and long-term variable compensation and benefits, including payments made under the annual bonus and LTI plan.
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 2025. There are no other amounts set aside or accrued to provide for pension, retirement, or similar benefits for our executive officers.
Incentive-Based Compensation Policy
In October 2022, the SEC adopted Rule 10D-1 under the Exchange Act, requiring national securities exchanges and national securities associations, such as NYSE, to require listed companies to adopt a written compensation recovery (clawback) policy providing for the recovery, in the event of a required accounting restatement, of incentive-based compensation received by the chief executive officer and certain other “executive officers” as defined in Rule 10D-1(d) under the Exchange Act. The amendment to NYSE’s listing rules became effective on October 2, 2023, and issuers like Enel Chile listed on NYSE were required to adopt SEC-compliant clawback policies by December 1, 2023.
On September 27, 2023, our Board adopted Enel Chile’s incentive-based compensation policy effective as of October 2, 2023, a copy of which is filed as Exhibit 97 to this Report. The incentive-based compensation policy complies with the requirements of Section 303A.14 of the NYSE listing rules implementing SEC Rule 10D-1.
Under our incentive-based compensation policy, in the event we are required to prepare an accounting restatement due to (i) material noncompliance with any financial reporting requirements under U.S. federal securities laws, including any required accounting restatement to correct an error in a previously issued financial statement that is material to such previously issued financial statement, or (ii) an error not material to a previously issued financial statement, but that would result in a material misstatement if the error were corrected in the current period financial statements or left uncorrected in the current period financial statements, we are entitled to recover or pay, as applicable, a portion or all of any incentive-based compensation provided to certain specified current or former executive officers (including the CEO, the CFO and the principal accounting officer), who, during a three-year period preceding the date on which an accounting restatement is required, received incentive compensation based on the erroneous financial data that exceeds or falls short of or is deficient with respect to, as applicable, the amount of incentive-based compensation the executive officer would have received based on the restatement. The Board (with a majority vote of the independent directors) administers our incentive-based compensation policy and has discretion, in accordance with the applicable laws, rules and regulations, to determine how to seek recovery under the policy and may forego recovery if it determines that recovery would be impracticable.
C. Board Practices.
Members of the Board do not have service contracts with us or with any of our subsidiaries that provide them with benefits upon the termination of their service. Our current Board was elected at the OSM held on April 28, 2025, for a three-year term. For information about the directors in office as of December 31, 2025, and the year they began their service on the Board, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management.”
Directors’ Committee (Audit Committee)
Set forth below are our members of the Directors’ Committee as of December 31, 2025:
Committee Member
Position in Committee
Chair
Member
Our Directors’ Committee performs the following functions:
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, 2025, 2024, and 2023.
Enel Distribución Chile(1)
553
588
526
559
573
Enel Chile(2)
408
436
474
229
347
97
Enel X Way Chile
Total Personnel(3)
1,792
2,077
The Chilean Labor Code entitles all employees in Chile who are fired for reasons other than misconduct to a severance indemnity payment. In most cases, contracted employees are entitled to a legal minimum severance indemnity payment of one month’s salary for each year (and every fraction thereof beyond six months) worked, subject to a maximum of 11 months’ salary.
Our employment contracts typically provide severance indemnity payments higher than those required by the Chilean Labor Code. In most cases, we respect seniority as the time that the employee first joined us or an affiliate. Therefore, employees hired by one of our Chilean affiliates or predecessor companies maintain their seniority in the company and are treated contractually as if we had hired them. Under such employment contracts, severance indemnity payments for most of our employees consist of one month’s salary for each full year worked (and every fraction thereof beyond six months),
subject to a maximum of 25 months. Under our collective bargaining agreements and other employment contracts not covered by such agreements, we are typically obligated to make severance indemnity payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and often exceed the amounts required under Chilean law.
Collective Bargaining
The Company offers employment terms to its employees through contracts and collective bargaining agreements reached through collective negotiation processes between the Company and unions, in line with current legislation. The main topics covered by the current collective agreements are benefits and working conditions linked to productivity bonuses, overtime, and welfare benefits related to health, education, food, vacations, among others.
For Enel Chile and its subsidiaries, collective negotiation is an instrument that is validated by both sides and facilitates collaborative efforts. It enhances the organization’s positive social impact and includes the promotion of best practices such as freedom of association and fair wages. Enel Chile’s employees have the right to associate collectively and can join one of the many unions at the Company and its subsidiaries.
The following table sets forth the collective bargaining agreements with our personnel as of December 31, 2025.
In Force
Union
From
To
Workers, Engineers, and Professional Staff (SIPEF)
December 2024
EGP Workers, Engineers, and Professional Staff
October 2023
September 2026
Professional/Technical Staff
January 2024
Professional Staff
July 2025
July 2028
Administrative Staff
January 2026
December 2028
Professional IT Staff
June 2026
Workers, Engineers, and Professional Staff (SINTEF)
Engineers and Professional Staff (SIEP)
Professional/Technical Staff (GAT)
Enel X Way
84
The following table sets forth the percentage of our personnel who were unionized (permanent and temporary employees) at Enel Chile and our subsidiaries as of December 31, 2025, 2024, and 2023.
91
E.
Share Ownership.
None of the directors or officers described in Item 6.A beneficially owns any of our shares or holds stock options as of March 31, 2026.
F. Disclosure of a Registrant’s Action to Recover Erroneously Awarded Compensation.
As of the date of this Report, we have not been required to prepare an accounting restatement for the fiscal years ended December 31, 2025, or 2024 that required recovery of erroneously awarded compensation pursuant to our incentive-based compensation policy.
Item 7. Major Shareholders and Related-Party Transactions
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, 2025, 5,788 shareholders of record held 69,166,557,219 shares of our outstanding common stock. Enel owned 44,334,165,151 common shares and 11,457,799 ADSs, equivalent to 572,889,950 shares, aggregating a 64.93% ownership interest in us. There were four record holders of our ADSs, as of such date.
It is not practicable for us to determine the number of our ADSs, or our common shares, beneficially owned in the United States. The depositary for our ADSs only registers the record holders, including the Depositary Trust Company and its nominees. As a result, we are not able to ascertain the domicile of the ultimate beneficial holders represented by the five ADS record holders in the United States, nor are we able to determine the domicile of any of our foreign shareholders who hold our common stock, either directly or indirectly.
As of December 31, 2025, Chilean private pension funds (“AFPs”) owned 9.9% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 20.4% of our shares. ADS holders owned 4.0% of our shares, and 5,672 minority shareholders held the remaining 0.8% of our shares.
The following table sets forth information concerning ownership of the common stock as of April 1, 2026, for the only stockholder known by us to own more than 5% of the outstanding shares of common stock:
Number of SharesOwned
Percentage of SharesOutstanding
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, 2025, 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 27 countries worldwide and a consolidated installed capacity of 92.8 GW, including BESS. Enel distributes electricity through a network of 1.9 million kilometers to 54 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.
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 contribute to the corporate interest and consider 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 non-interested 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. In 2024, CMF General Rule 501 came into effect, which provides for the inclusion of minimum information in Habituality Policies and sets specific requirements for transactions to be included in such policies, as well as requires semi-annual reports to the public of all transactions with related parties carried out during the respective period, whether or not under an exception. At its meeting held on July 24, 2024, our Board updated our related-party transaction policy. This policy is available on our website at www.enel.cl.
If a transaction is not in compliance with Article 147, this will not affect its validity. Still, the Company or its shareholders may demand compensation for damages from the individual associated with the infringement as provided by law.
The following are related-party financial transactions conducted between January 1, 2025, and March 31, 2026:
Maturity Date
Amount (millions)
Interest Rate
Outstanding Principal(1)
Contract Type
Jul-25
Jul-28
US$150
6.11%
CCM-LT(2)
Aug-25
Aug-28
US$175
6.02%
Feb-26
Feb-29
5.91%
Mar-26
Mar-29
5.90%
Feb-25
Feb-28(3)
Ch$250,000
7.73%
Ch$0
Mar-25
Mar-28
Ch$130,000
7.22%
Jun-25
Jun-28
Ch$28,000
6.89%
5.97%
Ch$10,000
6.76%
6.25%
Sep-25
Sep-28
6.72%
Oct-25
Oct-28
6.67%
86
Our internal procedure provides that all our subsidiaries’ cash inflows and outflows are managed through a centralized cash management mechanism. It is common practice in Chile to transfer surplus funds from one company to an affiliate that has a cash deficit. These transfers are executed through either short-term or long-term transactions. Under Chilean laws and regulations, such transactions must be conducted on an arms-length basis. All these transactions are subject to the supervision of our Directors’ Committee. As of April 1, 2026, the peso-denominated short-term transactions were priced at a variable rate equivalent to 6.12% annually when lending to subsidiaries and a variable rate equivalent to 4.48% annually when accepting deposits of cash surpluses from subsidiaries. The US$-denominated short-term transactions were priced at a variable rate equivalente to 5.97% when lending to subsidiaries and a variable rate equivalent to 4.31% when accepting deposits of cash surpluses from subsidiaries.
Under the centralized cash management mechanism, we granted short-term intercompany loans to and received cash transfers from our subsidiaries. As of March 31, 2026, the total outstanding balance of these loans and cash transfers, including interest, was US$503 million and US$721 million, respectively.
All these intercompany cash flows help meet our working capital needs and those of our subsidiaries.
We have various contractual relationships with EGP Chile, Enel Americas, Enel Distribución Chile, Enel Generación Chile, 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, to Enel Distribución Chile and its subsidiaries, to Enel Generación Chile and its subsidiaries, and to 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, 2025, there were other 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.
Item 8. 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, 2025, 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 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 also informs the dividend policy for the current fiscal year. Additionally, our Board generally establishes an interim dividend for the current fiscal year, payable in January of the following year and deducted from the final dividend payable in May of the next year. The Board can freely establish an interim dividend provided there are no accumulated losses.
For dividends accrued in the fiscal year 2025, on November 28, 2025, the Board agreed to distribute an interim dividend of US$0.000762962580788 per share of common stock on January 23, 2026, equal to 15% of consolidated net income as of September 30, 2025. At the OSM held on April 28, 2026, our shareholders approved a final dividend, after deducting the interim dividend paid in January 2026, of US$0.003123519916077 per share of common stock for the year 2025, equivalent to a payout of 50% of annual net income for the fiscal year 2025.
For dividends relating to the fiscal year 2026, our Board presented at the OSM held on April 28, 2026, the following proposed dividend policy:
An interim dividend, accrued in the fiscal year 2026 and amounting to 15% of consolidated net income as of September 30, 2026, to be paid in January 2027.
A final dividend payout of 50% of annual net income for the fiscal year 2026, to be paid in May 2027, from which the interim dividend to be paid in January 2027 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’s right to change the amount and timing of the dividends under prevailing circumstances at the time of the payment. Dividends on the common stock will continue to be paid in Chilean pesos in 2026 notwithstanding the change in our functional and presentation currency to the U.S. dollar.
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 paid in each year by us in U.S. dollars per common share and U.S. dollars per ADS. For additional information, see Note 27.2 of the Notes to our consolidated financial statements.
Dividends Distributed(1)
Year
US$ per Share
US$ per ADS(2)
0.22
(4)
0.26
0.36
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.”
Significant Changes
Effective January 1, 2025, Enel Chile changed its functional and presentation currency from Chilean pesos to U.S. dollars because the U.S. dollar became the currency that most significantly influences the primary economic environment in which the Company operates. Balances as of December 31, 2024, and 2023 presented in U.S. dollars were translated using the Exchange Rate of Ch$996.46 per US$1.00 and Ch$877.12 per US$1.00, respectively. Amounts in the consolidated statements of comprehensive income and cash flows were translated using the average exchange rate for each period. See Note 3 of the Notes to our consolidated financial statements.
Item 9. The Offer and Listing
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.”
Plan of Distribution.
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, 2025, the SSE and ESE accounted for 92.9% and 7.1% of our total equity traded in Chile, respectively.
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, as 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 Dow Jones Sustainability Index, FTSE4 Good, LSEG ESG Index, and MSCI Sustainability Indices, among others.
The following table contains information regarding the number of total traded shares of common stock and the corresponding percentage traded per market during 2025:
Market
Number of CommonShares Traded
Percentage of Shares Traded
Chile(1)
19,358,691,064
69.4%
United States (One ADS = 50 shares of common stock)(2)
8,531,480,250
30.6%
27,890,171,314
100.0%
Includes SSE and ESE.
Includes the NYSE and over-the-counter trading.
Selling Shareholders.
Dilution.
F.
Expenses of the Issue.
Item 10. Additional Information
Share Capital.
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.
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 US$219,000 or Ch$199 million as of December 31, 2025) do not have the option to bring the procedure to the courts.
The CMF regulates the Chilean securities markets under the Securities Market Law (Law No. 18,045) and the Chilean Corporations Law. These two laws state the disclosure requirements, restrictions on insider trading, and price manipulation, and protect minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges, and brokers, and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Corporations Law and the Securities Market Law, both as amended, state rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors’ committees, independent directors, stock options, and derivative actions.
Public Register
We are a publicly held limited liability stock corporation incorporated under the laws of Chile. We were incorporated by public deed issued on January 8, 2016, by the Santiago Notary Public, Mr. Iván Torrealba A., and registered on January 19, 2016, in the Commercial Register (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago) on pages 4288 No. 2570. Our registry in the Securities Registry of the CMF was approved by the CMF on April 13, 2016. 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:
The majority shareholders of a publicly held limited liability stock corporation must inform the CMF and the Chilean Stock Exchanges if such acquisitions are entered into to acquire control of the company or make a passive financial investment instead.
Under Article 54 of the Securities Market Law and General Rule No. 104 enacted by the CMF, unless the tender offer regulation applies, any person who directly or indirectly intends to take control of a publicly held limited liability stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held limited liability stock corporation has been provided.
Corporate Objectives and Purposes
Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transformation, and/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 consists of seven members elected by shareholders at an OSM for a three-year term, at the end of which each member 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 that one of those individuals is 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 cumulative 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 and be included in the board meetings, as set forth by the Chilean Corporations Law.
Our bylaws do not contain provisions relating to:
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:
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 subscribed
shares on or before the payment date, 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, 2025, the Company’s subscribed and fully paid capital totaled US$3.9 billion consisting of 69,166,557,219 shares.
Preemptive Rights and Increases of Share Capital
Except for capital increases needed to carry out a merger, Chilean regulation requires Chilean publicly held limited liability stock corporations to grant shareholders preemptive rights to purchase a sufficient number of shares, or any other securities convertible into shares or that confer future rights over shares, to maintain their existing ownership percentage of such company whenever such company issues new shares, or any other securities convertible into shares or that confer future rights over shares.
Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders for 30 days. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares should be offered at least once to the shareholders pro-rata to the shares held registered in their name at midnight on the fifth business day before the date of the start of the preemptive rights period. The preemptive rights offering and the beginning of the 30 days for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper that should be used for notifications of shareholders’ meetings. During such 30 days, and for an additional period of at least 30 days immediately following the initial 30-day period, publicly held limited liability stock corporations are not permitted to offer any unsubscribed shares to third parties under more favorable terms than those provided to their shareholders. At the end of the second 30-day period, a Chilean publicly held limited liability stock corporation is authorized to sell unsubscribed shares to third parties on any terms, provided they are sold on one of the Chilean Stock Exchanges.
Shareholders’ Meetings and Voting Rights
An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April 28, 2026. An ESM may be called by the Board when deemed appropriate. An ESM or 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. The 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 of the board or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it
and to continue it within the same day and place, with no new constitution of the meeting or qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.
Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can occur at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented. This second meeting must take place within 45 days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting unless a qualified majority is required.
Regardless of the quorum present, a vote of at least a two-thirds majority of the outstanding shares with voting rights is required to adopt any of the following actions:
●
a transformation of the company into a form other than a publicly held limited liability stock corporation under the Chilean Corporations Law, a merger or split-up of the company;
an amendment to the term of duration or early dissolution of the company;
a change in the company’s domicile;
a decrease 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 that 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 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’ 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.enel.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.
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
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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 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 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 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 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 must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire Board 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 re-election for the following period. Our shareholders have never rejected the financial statements presented by the Board.
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 outstanding shares of stock. The preceding restriction does not apply to the Depositary as record owner of shares represented by ADSs, but it does apply to each beneficial ADS holder. Additionally, our bylaws currently prohibit any
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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 ADSs must first withdraw the shares represented by their ADSs under the Deposit Agreement’s terms. In case of a bankruptcy proceeding, the withdrawal right from an adopted resolution is suspended until the existing debt has been paid.
“Dissenting” shareholders are defined as those at a shareholders’ meeting who vote against a resolution that results in the withdrawal right or who, if absent from such meeting, state in writing their opposition to the respective resolution within the 30 days following the shareholders’ meeting. Shareholders who are present or represented at the meeting and who abstain from exercising their voting rights shall not be considered dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company.
The price paid to a dissenting shareholder of a publicly held limited liability stock corporation whose shares are quoted and actively traded on one of the Chilean Stock Exchanges is the weighted average of the sales prices for the shares as reported on the Chilean Stock Exchanges on which the shares are quoted for the 60 trading days between the ninetieth and the thirtieth trading day before the shareholders’ meeting giving rise to the withdrawal right. If the CMF determines that the shares are not actively traded on a stock exchange, the price paid to the dissenting shareholder shall be the book value. Book value for this purpose must be equal to the company’s equity attributable to the parent company, divided by the total number of subscribed shares, whether entirely or partially paid. To make this calculation, the latest consolidated statement of financial position is used, as adjusted to reflect inflation up to the date of the shareholders meeting which gave rise to the withdrawal right.
Article 126 of the Chilean Corporations Regulation (Reglamento de Sociedades Anónimas) establishes that in cases where the right to withdraw arises, the company is obliged to inform the shareholders of this situation, the value per share that will be paid to shareholders exercising their right to withdraw, and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted, giving rise to the right of withdrawal, before its voting. A special communication should be given to the shareholders with rights within two days following the date on which the rights to withdraw arise. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its website, plus a written communication addressed to the shareholders with rights at the address they have registered with 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:
Investments by AFPs
The Pension Fund System Law permits AFPs to invest their funds in companies subject to Title XII of such law, and these companies are subject to greater restrictions than other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP investments. We are and have been subject to Title XII provisions and are approved by the Risk Classification Committee.
Companies subject to Title XII provisions are required to have bylaws that:
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.
Material Contracts.
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.
Chapter XIV of the Compendium
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 types 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.
The Compendium and International Bond Issuances
Chilean issuers may offer bonds internationally, subject to the reporting requirements outlined in Chapter XIV of the Compendium.
E. Taxation.
Chilean Tax Considerations
The following discussion summarizes Chilean material income and withholding tax consequences to Foreign Holders arising from the ownership and disposition of shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own, or dispose of shares or ADSs, if any, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs.
The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes, and how Chilean taxes are imposed and collected may be amended only by another law. The Chilean tax authorities also enact rulings and regulations of either general or specific application and interpret the Chilean Income Tax Law provisions. Chilean tax may not be assessed retroactively against taxpayers who act in good faith, relying on such rulings, regulations, and interpretations, but Chilean tax authorities may change their rulings, regulations, and interpretations in the future. The discussion that follows is also based, in part, on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreements will be fulfilled under its terms. In 2010, the United States and Chile signed an income tax treaty that was ratified by both countries on December 19, 2023, and came into effect on January 1, 2024.
For the purposes of the treaty, the expression “resident of a contracting country” means any person who, under the laws of that country, is subject to tax therein by reason of his domicile, residence, citizenship, place of management, place of incorporation, or any other criterion of an analogous nature.
As used in this Report, the term “foreign holder” means either:
Taxation of Cash Dividends and Property Distributions
Cash dividends paid concerning the shares or ADSs held by a Foreign Holder will be subject to Chilean withholding tax, which is withheld and paid by the company. The amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax (“CIT”), paid by the issuer), and then subtracting as a credit 65% of such Chilean CIT paid by the issuer, if the country of residence 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 2025, 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, 2021 (even if not yet in effect), the CIT is entirely creditable against the 35% withholding tax. The Chile-U.S. tax treaty was ratified by both countries on December 19, 2023, and came into effect on January 1, 2024. In the case of treaties signed before January 1, 2021, 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. As of January 1, 2024, the Chile-U.S. tax treaty is in effect, and 100% of the CIT may be applied as a credit against withholding tax of U.S. holders without distinction of the date of payment.
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 2025 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 TaxTreaty Resident
Amount Non-TaxTreaty Resident
Company taxable income (based on Line 1 = 100)
Chilean corporate income tax: 27% x Line 1
Net distributable income: Line 1 - Line 2
Dividend distributed (50% of net distributable income): 50% of Line 3
36.50
Withholding tax: 35% of (the sum of Line 4 and 50% of Line 2)
17.50
Credit for 50% of Chilean corporate income tax: 50% of Line 2
13.50
CIT partial restitution (Line 6 x 35%)(1)
4.73
Net withholding tax: Line 5 - Line 6 + Line 7
8.73
Net dividend received: Line 4 - Line 8
32.50
27.78
Effective dividend withholding rate: Line 8 / Line 4
10.96
23.90
However, for purposes of the foregoing, the tax authority has not clarified whether the taxpayer’s 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 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 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.
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 2025, and a 35% Chilean withholding tax, the former being creditable against the latter.
The date of acquisition of the ADSs is the date of purchase of the shares for which the ADSs are exchanged.
Taxation of Share Rights and ADS Rights
For Chilean tax purposes and to the extent we issue any share rights or ADS rights, the receipt of share rights or ADS rights by a Foreign Holder of shares or ADSs under a rights offering is a nontaxable event. Also, there are no Chilean income tax consequences to Foreign Holders upon the exercise or the expiration of the share rights or the ADS rights.
Any gain on the sale, exchange, or transfer of any ADS rights by a Foreign Holder is not subject to taxes in Chile.
Any gain on the sale, exchange, or transfer of the share rights by a Foreign Holder is subject to a 35% Chilean withholding tax.
Other Chilean Taxes
There is no gift, inheritance, or succession tax applicable to Foreign Holders’ ownership, transfer, or disposition of ADSs. However, such taxes will generally apply to the transfer at death or by a gift of the shares by a Foreign Holder. There is no Chilean stamp, issue, registration, or similar taxes or duties payable by holders of shares or ADSs.
Material U.S. Federal Income Tax Considerations
This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary, and proposed Treasury regulations, all as of the date of this Report. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined to ensure that the tax treatment of ADSs will be identical to the tax treatment of the underlying shares.
The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADSs. However, it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities. 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:
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:
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
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administrative guidance interpreting provisions thereof. U.S. Holders should consult their own tax advisors concerning their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S., and other tax laws and the possibility of changes in tax laws, including the effects of any future administrative guidance interpreting provisions thereof.
Taxation of Distributions
The following discussion of cash dividends and other distributions is subject to the discussion below under “—Passive Foreign Investment Company Rules.” Distributions received by a U.S. Holder on shares or ADSs, including the amount of any Chilean taxes withheld, other than certain pro-rata distributions of shares to all shareholders, will constitute foreign-source income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. The amount of dividend income paid in Chilean pesos that a U.S. Holder will be required to include in income will equal the U.S. dollar value of the distributed Chilean peso, calculated by reference to the exchange rate in effect on the date the payment is received, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder generally will 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 either (i) the ADSs are readily tradable on an established securities market in the United States or (ii) we are eligible for benefits of a comprehensive tax treaty with the United States, which the U.S. Treasury determines is satisfactory for this purpose, which includes an exchange of information program, and, in each case, (A) we were not, in the year before the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”) and (B) the holder thereof has satisfied certain holding period and other 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 may also be eligible for benefits of the tax treaty between the United States and Chile (the “Chile-U.S. Tax Treaty”) and the U.S. Secretary of the Treasury has determined that the Chile-U.S. Tax Treaty is satisfactory for purposes of the qualified dividend income definition. We do not believe that we were a PFIC for U.S. federal income tax purposes with respect to our 2025 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 2026 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. Further, no assurances can be provided that we are or will be eligible for the benefits under the Chile-U.S. Tax Treaty, or that the Chile-U.S. Tax Treaty will continue to satisfy the requirements of the qualified dividend income definition.
Based on existing guidance, it is not entirely clear whether dividends received with respect to our shares will be treated as qualified dividends because our shares 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.
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The amount of a dividend generally will be treated as foreign-source dividend income to a U.S. Holder for foreign tax credit purposes. As discussed in more detail below under “—Foreign Tax Credits,” it is not free from doubt whether Chilean withholding taxes imposed on distributions on shares or ADSs will be treated as income taxes eligible for a foreign tax credit for U.S. federal income tax purposes. If a Chilean withholding tax is treated as an eligible foreign income tax, subject to generally applicable limitations, you may claim a credit against your U.S. federal income tax liability for the eligible Chilean taxes withheld from distributions on shares or ADSs. If the dividends are taxed as qualified dividend income (as discussed above), special rules will apply in determining the amount of the dividend taken into account to calculate the foreign tax credit limitation. The rules relating to foreign tax credits are complex. U.S. Holders are urged to consult their own tax advisors regarding the treatment of Chilean withholding taxes imposed on distributions on shares or ADSs.
Sale or Other Disposition of Shares or ADSs
If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss, and will be a long-term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.
In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not ADSs). See “— Chilean Tax Considerations — Taxation of Shares and ADSs.” If a Chilean tax is imposed on the sale or disposition of shares, a beneficial owner who 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. Pursuant to the Chile-U.S. Tax Treaty, the Chilean dividend withholding taxes and Chilean capital gains tax will be 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 2025 taxable year and do not anticipate being a PFIC for our 2026 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.
F.Dividends and Paying Agents.
G.Statement by Experts.
H.Documents on Display.
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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 at www.sec.gov and on our website at www.enel.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 segment, we are exposed to market risks from the price volatility of some commodities, mainly through fuel purchases and sales for the electricity generation process and energy purchase-sale transactions carried out in local markets.
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, 2025, we held the following hedges:
As of December 31, 2024, we held the following hedges:
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, 2025, 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
2027
2028
2029
2030
Thereafter
FairValue(1)
Fixed Rate
Ch$/UF(2)
Weighted average interest rate
US$
181
1,035
779
2,869
2,897
3.2%
5.9%
5.1%
5.3%
3.6%
4.5%
4.7%
Other currencies(2)
4.8%
Total fixed rate
183
401
1,036
439
783
2,878
2,906
Variable Rate
262
545
557
4.6%
4.9%
3.4%
4.1%
174
5.8%
Total variable rate
253
429
981
993
5.4%
5.0%
5.2%
4.3%
1,128
1,212
3,859
3,899
As of December 31, 2024, 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.
180
399
1,034
1,192
3,002
2,948
2.9%
162
1,195
3,009
2,955
3.0%
207
483
501
4.2%
191
6.7%
6.5%
6.6%
919
937
6.3%
224
411
1,116
1,593
3,929
3,892
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, 2025 and 2024, 87% and 89%, respectively, of our total outstanding debt had fixed interest rates, and 13% and 11%, 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, 2025, 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:
Variable to fixed rates
Fixed to variable rates
As of December 31, 2024, 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:
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.
Until December 31, 2024, our functional and presentation currency was the Chilean peso, which has been subject to devaluations and appreciations against the U.S. dollar. Effective January 1, 2025, our functional and presentation currency is the U.S. dollar. For information on the change to our functional and presentation currency, see Note 3 of the Notes to our consolidated financial statements.
As of December 31, 2025, 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:
(in millions of US$)(2)
UF to US$
143
171
US$ to Ch$/UF
Ch$ to US$
As of December 31, 2024, 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:
178
237
Please refer to Note 22 of the Notes to our consolidated financial statements for further detail.
Effective January 1, 2025, our functional and presentation currency is the U.S. dollar. For further information on the change to our functional and presentation currency, see Note 3 of the Notes to our consolidated financial statements.
(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
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
(5) Distribution of securities other than ADSs or rights to purchase additional ADSs (i.e., a spin-off of shares)
(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 2025
The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2025, the Depositary reimbursed us for expenses related primarily to investor relations activities for approximately US$1.1 million (after the deduction of applicable U.S. taxes).
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Item 13. Defaults, Dividend Arrearages and Delinquencies
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
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, 2025.
There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error, and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.
Based upon our evaluation, the chief executive officer and the chief financial officer concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to our management, including the chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.
(b)Management’s Annual Report on Internal Control Over Financial Reporting
As required by Section 404 of the Sarbanes-Oxley Act of 2002, our management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule13a-15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.
Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.
Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2025. 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, 2025, 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, 2025. Their attestation report appears on page F-4 of this Report.
(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, 2025, 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
The Directors’ Committee performs the Audit Committee’s functions.
Under Chilean law, we are not required to appoint a financial expert. As of April 28, 2026, our Board has decided that our corporate governance system, including the Directors’ Committee’s ability to consult internal and external experts, satisfies the function provided by a financial expert on the Directors’ Committee and, therefore, has decided not to appoint a financial expert, as such term is defined under Item 407 of Regulation S-K.
Item 16B. Code of Ethics
Our standards of ethical conduct are governed using the following corporate rulings or policies approved by our Board: (i) the Manual for the Management of Information of Interest to the Market (the “Manual”); (ii) the Human Rights Policy; (iii) the Politically Exposed Person Policy; (iv) the Code of Ethics; (v) the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”); (vi) the Penal Risk Prevention Model; (vii) the Enel Global Compliance Program on Corporate Criminal Liability (the “Enel Global Compliance Program”); (viii) the Internal Control and Risk Management System; (ix) 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 (x) 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. Please refer to “Item 16J. Insider Trading Policies” for further information.
The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into our corporate policies, and the Politically Exposed Person Policy includes procedures for regulating the commercial and contractual relationships between Politically Exposed People and us. 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, with emphasis on 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 Chile classifies risk monitored in its Risk Catalogue into 6 macro-categories: Financial, Strategic, Governance and 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 Risk Control and Management Policy also follows the standards and best practices established in the ISO 31000:2018 (G31000), and part of its team is already 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 30, issued by CMF as amended from time to time, establishes the 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.enel.cl) and is sent to the stock exchanges.
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 our employees’ work environment and quality of life. The Company is committed to creating an inclusive work environment where employees can develop their potential and maximize their contribution.
In 2018, the Board approved a policy dealing with environmental and biodiversity issues. ESG criteria are integrated into our business model. The Board periodically receives reports from management to identify and assess all risks associated with ESG and climate change issues, including compliance with its policies.
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A copy of these documents is available on our webpage at www.enel.cl, as well as upon request, free of charge, via email at: ir.enelchile@enel.com.
In the fiscal year 2024, our Board updated the Manual and the Penal Risk Prevention Model to reflect the most recent Chilean regulation applicable to the Company. 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 2025.
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 Ltda. (“KPMG”) and its respective affiliates by type of service for the periods indicated.
Services Rendered
Audit fees
1.30
1.11
Audit-related fees
0.07
0.06
Tax fees
All other fees
1.37
1.17
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 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
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In the fiscal year 2025, 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
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 Norm 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 link, interest or economic, professional, credit or commercial dependency, 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, principal officer or advisor 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 up to the second degree of consanguinity or affinity 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 (US$66 million or Ch$60 billion as of December 31, 2025) 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 also comply with, the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. Since our incorporation on March 1, 2016, we have complied with the independence and the functional requirement of Rule 303A.06.
Under our bylaws, all Directors’ Committee members must satisfy the requirements of independence of 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 Directors’ Committee’s functions and duties.
Item 16H. Mine Safety Disclosure
Item 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Item 16J. Insider Trading Policies
In order to guarantee compliance with the guidelines contained in Law No. 18,045 on the Securities Market and General Norm Regulation No. 270 of the CMF, our Board approved the Manual in 2016. It was updated in 2023 and includes our insider trading policy and procedure (the “Insider Trading Policy”), 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, including with respect to our securities. The Insider Trading Policy is reasonably designated to promote compliance with applicable insider trading laws, rules and regulations and NYSE listing standards and contributes to the transparency and protection of investors. A copy of the Manual is filed as Exhibit 11 to this Report. The principles reflected in the Manual are transparency, good faith, prioritization of general interests before personal ones, and care of and diligence in the use of information and the actions carried out in the markets.
The Manual sets forth the internal policies and rules regarding the information that will be made available to investors and implements systems aimed at guaranteeing that such information is communicated to the market in a timely manner. The Manual reflects our belief that timely and efficient information provided either with respect to securities transactions carried out by persons holding positions of directors, managers, administrators, chief executives, or employees, as well as entities controlled directly by them or through third parties, with respect to information of interest or essential information related to the Company’s progress contributes to the formation of a transparent market.
The Manual regulates the following:
Item 16K. Cybersecurity
Governance
Since September 2016, Enel has operated a Cyber Security unit committed to guaranteeing governance, direction, and control of cybersecurity topics. The head of the Cyber Security unit, who is also Enel’s chief information security officer (“CISO”), reports directly to the head of Security function and to the head of global information and communication technology (“ICT”), the Enel Group’s chief information officer (“CIO”), as part of Global Service function.
At the Enel Group’s executive management level, the Cyber Security Committee addresses and approves the Group cybersecurity strategy and periodically conducts oversight of strategy implementation (at least annually). The committee is chaired by the Enel Group’s CEO and made up of his/her front-line officers, including the head of the Cyber Security unit.
A separate Cyber Risks Operating Committee meets quarterly to define criteria to set priorities for risk analysis and acceptance according to Enel Group risk posture, in addition to sharing best practices and lessons learned. The committee consists of the head of the Cyber Security unit and Cybersecurity Risk “Reference Persons” (i.e., cybersecurity focal points for business areas and holding function—one focal point for each business area and holding function of the Enel Group). These Risk “Reference Persons” report to the head of the Cyber Security unit.
Additionally, cybersecurity risks and strategic initiatives are periodically discussed in depth by the Enel Group’s main executive and supervisory boards, such as the Risk Control Committee. Moreover, cyber risk is defined within the Enel Group Risk Catalogue as a risk related to digital technology.
Mr. Yuri Rassega joined Enel in 2001, and after holding several positions within the ICT and Audit functions, he was appointed CISO and head of the Cyber Security unit for the Enel Group in June 2016. Mr. Rassega oversees all information technology (“IT”), operational technology (“OT”), and Internet of things (“IoT”) processes for Cyber Security Risk Management, Governance, Engineering, Assurance, and Operations areas, including the Enel Group’s Cyber Emergency Readiness Team (“CERT”) and Digital Identity Management.
Before joining Enel, Mr. Rassega served in roles with various responsibilities in the ICT industry, including the development of systems in the finance sector, telecommunications, internet service providers (ISPs), enterprise resource planning (ERP), supervisory control and data acquisition (SCADA) systems, automation control systems (ACS), and industrial control systems (ICS) solutions for several clients. His experience has developed through a wide range of roles, from software development and electronic design to consultancy, entrepreneurial roles, and senior management positions. He is a member of expert working groups sponsored by EU authorities and forums, such as the G7 and G20, the World Economic Forum (with 5 publications), and the International Council on Large Electric Systems (CIGRE). He also delivers seminars and lectures on cybersecurity-related topics at Italian universities.
Mr. Rassega is a founding partner and chairperson of AssoCISO (National Chief Information Security Officer Association) in Italy. He has participated as a speaker, panel chair, and member of the advisory board at dozens of international conferences in Europe, North America, Middle East, and Asia on cybersecurity, digital transformation, and wireless communications technologies. Mr. Rassega has also designed digital fraud detection tools and methods that are patented in Europe, the USA, and Latin America. Furthermore, Mr. Rassega has been appointed to the Technical and Scientific Committee of the Italian ACN (“Agenzia per la Cybersicurezza Nazionale” - National Cybersecurity Agency), a statutory body with advisory and consultative responsibilities and a guarantor role toward third parties.
Cybersecurity Risk Management and Strategy
Cybersecurity Framework
In order to mitigate cyber risks across all digital environments of the Group (IT, OT, IoT), Enel adopted the Cyber Security Framework ( the “CS Framework”) in 2017 to guide and manage cybersecurity processes. It has been integrated into each company throughout the entire organization, including Enel Chile. The CS 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.
The CS Framework is structured around eight core processes and is fully applicable to the complexity of the IT, OT, and IoT environment. It clearly defines roles and responsibilities, actively involving business areas and stakeholders throughout the organization, and establishes a solid basis for the full integration of technologies, core processes and people. The CS Framework focuses on and is driven by a “risk-based” approach and a “cybersecurity by design” principle.
The “risk-based” approach places risk assessment as a prerequisite for the Group’s strategic decisions. The estimation of cybersecurity risk factors (impacts, threats, vulnerabilities) is critical to assess the Group’s level of cyber risk and to identify appropriate treatment actions to mitigate it. The “cybersecurity by design” principle ensures that cybersecurity requirements are considered throughout the entire lifecycle of systems and services.
The CS Framework provides the overall coverage of the following areas:
Cyber Security Risk Assessment: aims to identify, analyze, and evaluate cybersecurity risks, in line with the Group’s risk posture.
Cyber Security Strategy: aims to guide cybersecurity strategy, define cybersecurity objectives and priorities, address cybersecurity initiatives, and coordinate investment activities on cybersecurity topics for the Company. It guarantees oversight of international cybersecurity standards and regulations and ensures cybersecurity policy definitions, in accordance with regulatory compliance and Enel Group organizational documents. It also ensures managerial reporting and continuous monitoring of ongoing cybersecurity initiatives.
Cyber Security Engineering, Design, and Implementation: aims to ensure the adoption of cybersecurity principles throughout the entire lifecycle of IT/OT/IoT solutions and infrastructures.
Cyber Security Risk Treatment: aims to define and implement the most appropriate risk treatment actions to face cybersecurity risks.
Cyber Security Assurance: aims to analyze, verify, and test the effectiveness of the implemented risk response measures, detecting vulnerabilities, and assessing cybersecurity controls, ensuring the monitoring of remediation plans.
Cyber Emergency Readiness: aims to monitor, track, and report risk exposures and handle cybersecurity incidents that could occur.
Identity Management and Access Control: aims to manage the full lifecycle of digital identities used within the Company and perform security controls on access privileges to highlight possible risks and security improvements, triggering the necessary remediation processes.
Cyber Security Awareness and Training: aims to drive and run our Cyber Security Awareness and Training initiatives to focus attention on critical cybersecurity topics, working on behaviors and human factors.
In accordance with the CS Framework, Enel applies a Cyber Security Business Impact Analysis and Risk Assessment methodology (“Cyber Risk Management Procedure”), applicable to the entire Group. 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 aims to define the controls necessary to achieve the desired level of risk mitigation.
The Cyber Security unit is engaged in monitoring the relevant cyber security regulatory and legislative framework, analyzing regulatory obligations, and guiding the implementation of necessary technological, organizational, and procedural adjustments to ensure compliance of Group companies subject to the applicable regulations. For example, in 2025, a compliance program aligned with Law No. 21,663 (“Ley Marco sobre la Ciberseguridad e Infraestructura Crítica
118
de la Información”), which applies to operators of essential services and of vital importance, was implemented for Group companies in Chile. In addition, the Cyber Security unit supports the Group in achieving and maintaining ISO 27001 certifications, obtained in 2025 for the distribution business in Chile.
As part of the Cyber Security unit, Enel’s CERT is a global unit that is active 24 hours a day, whose mission is to protect Enel’s employees and assets (instrumental to our business that could be compromised by cyber threats) by promoting a proactive approach based on “incident readiness” rather than “incident response”. The CERT operates with threat intelligence, incident response, and information sharing processes, and exchanges information within a network of accredited international partners.
The Threat Intelligence service helps Enel’s CERT detect and protect privileged information to avoid, mitigate, or manage a potential cyber incident. The Cyber Incident Response process outlines the responsibilities for implementing corrective actions to put in place when an incident occurs. During the execution of response activities, depending on the type and impact of a cyber incident, all internal stakeholders and required actors support Enel’s CERT to respond to an incident in the shortest time possible, relying on procedures, knowledgeable people, technical resources, and connections to external partners. Depending on the incident typology and related classification of risk level, the Cyber Incident Response process can activate all the procedures defined for incidents and critical events management (e.g., Policy for Data Breach management, Policy for IT Service Continuity Management) to facilitate an efficient and quick response, minimizing impacts on people, services, and assets. Induction sessions are periodically held to inform Enel’s Board about cybersecurity risks and the occurrence of any cybersecurity incidents.
Additionally, Enel’s CERT conducts periodic “cyber exercises” aimed at simulating a cybersecurity incident to increase the ability of response, readiness, incident management, and training of all relevant parties. The exercises involve both technical and business reference structures, and a final report is provided detailing the results of the cyber exercise. These simulations are performed worldwide, including by Enel Chile, to generate awareness and address any need for technical and/or organizational improvements. In 2025, among cyber exercises that involved the Chilean perimeter, Enel Chile participated in “SENEx | 1,” a cyber exercise organized by Chilean institutional authorities.
If 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 low impact levels and are considered “day-by-day” instances because they do not significantly impact the Group’s systems. Enel’s CERT manages these incidents, which are generally blocked automatically or semi-automatically by the Group’s systems, thereby preventing and/or reducing the potential impact of a cyberattack. Incidents classified at medium, high, or critical impact levels of the Enel Cyber Impact Matrix may impact the Group and are managed by Enel’s CERT in conjunction with relevant stakeholders, depending on incident typology, business area, and geographic boundaries.
For the year ended December 31, 2025, based on the Enel Cyber Impact Matrix classification, there were no potentially critical impact cybersecurity incidents.
119
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
By-laws (Estatutos) of Enel Chile S.A. effective July 4, 2025.
2.1
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934.
8.1
List of Subsidiaries as of December 31, 2025.
Manual for the Management of Information of Interest to the Market, including the Insider Trading Policies, filed as Exhibit 11 to Enel Chile’s Annual Report on Form 20-F for the year ended December 31, 2024, is incorporated herein by reference.
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.
Incentive-based Compensation Policy, filed as Exhibit 97 to Enel Chile’s Annual Report on Form 20-F for the year ended December 31, 2023, is incorporated herein by reference.
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
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.
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.
By:
/s/ Gianluca Palumbo
Name:
Title:
Date: April 28, 2026
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, 2025, 2024, and 2023
F-1 – F-5
Consolidated Financial Statements:
Consolidated Statements of Financial Position
F-6
Consolidated Statements of Comprehensive Income
F-8
Consolidated Statements of Changes in Equity
F-10
Consolidated Statements of Cash Flows
F-11
Notes to the Consolidated Financial Statements
F-12
Ch$Chilean pesos
US$U.S. dollars
UF“Unidades de Fomento” – A Chilean inflation-indexed, Chilean peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
UTM“Unidad Tributaria Mensual” –Chilean inflation-indexed monthly tax unit used to define fines, among other purposes.
UTA“Unidad Tributaria Annual” – Chilean inflation-indexed annual tax unit. One UTA equals 12 UTM.
ThCh$Thousands of Chilean pesos
ThUS$Thousands of U.S. dollars
EUREuro
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, 2025 and 2024, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years then ended, 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, 2025 and 2024, and its financial performance and its cash flows for each of the years then ended, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
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, 2025, 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 March 5, 2026 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 Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Unbilled Revenue
As discussed in Notes 4q and Appendix 2.2 to the consolidated financial statements, revenue from sales to customers includes estimates of energy provided and not billed as of December 31, 2025, amounting to MUS$383.539, related to the distribution and generation entities in Chile. These estimates are made based on the quantity of energy consumed by customers during the period, at the prices stipulated in the electricity tariffs in accordance with the current regulation or, if applicable, contractual arrangements with customers.
We identified the revenue recognition of energy provided and not invoiced as a critical audit matter due to the auditor judgment required to assess the complexity of the non-standardized determination of energy consumed by customers and the calculation of price formulas established in the contracts and regulations. In addition, auditor judgment was required to assess the adequacy of the nature and extent of the audit evidence obtained.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the unbilled revenue process for the generation and distribution entities. This included controls related to:
We compared the amount of unbilled revenue at the end of the year versus the actual amount billed in January 2026 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 revenue to customers based on current contracts and decrees issued by the local regulator. We extracted a sample from the sales ledger to January 2026, to obtain evidence about the accuracy of the relevant data elements associated to billed amount to customers. We evaluated the reconciliation of the sales ledger to the actual sales report as of year-end. In addition, we evaluated the sufficiency of audit evidence obtained by assessing the results of procedures performed, including the appropriateness of such evidence.
F-2
Changes in functional and presentation currency
As discussed in Note 3 to the consolidated financial statements, as of January 1, 2025, the Company and its subsidiary, Enel Generación Chile, changed its functional and presentation currency from Chilean pesos to United States dollars as a result of changes in events and conditions relevant to their business operations. The change in functional currency was accounted for prospectively from the date of the change. The change in presentation currency was accounted for as a change in accounting policy and applied retrospectively, as if the new presentation currency had always been the presentation currency in the consolidated financial statements. As a result of the translation of comparative information into a new presentation currency, the Company included a third statement of financial position as of January 1, 2024.
We identified the evaluation of the accounting for the change in functional and presentation currency as a critical audit matter. Evaluating the Company’s application of the accounting for the change in functional and presentation currency required a higher degree of complex auditor judgment to determine the nature and extent of audit effort required to address the matter.
The following are the primary procedures we performed to address this critical audit matter. We applied auditor judgment to determine the nature and extent of procedures to be performed over the Company’s application of the accounting for the change in functional and presentation currency. We evaluated the design and tested the operating effectiveness of certain internal controls related to the financial reporting process. This included controls related to the Company’s application of the accounting for the change in functional and presentation currency. We evaluated the exchange rates used by management for the change in functional and presentation currency by comparing such exchange rates to third party information. We tested the accuracy of the financial position at January 1, 2025 for the prospective change in functional currency. We tested the accuracy of the translation of all periods presented in the consolidated financial statements to the new presentation currency. We evaluated the Company’s disclosures in the consolidated financial statements, including the presentation of comparative figures for the years and periods prior to January 1, 2025 with the new presentation currency.
/s/ KPMG
KPMG Auditores Consultores Ltda.
We have served as the Company’s auditor since 2020.
Santiago, Chile
April 28, 2026
KPMG Auditores Consultores SPA, a Chilean limited liability partnership 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-3
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, 2025, 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, 2025, 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, 2025 and 2024, 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, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated April 28, 2025 expressed an unqualified opinion on those consolidated financial statements.
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
KPMG Auditores Consultores Ltda, a Chilean limited liability partnership 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-4
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.
.
F-5
ENEL CHILE S.A. AND SUBSIDIARIES
As of December 31, 2025, December 31, 2024, and January 1, 2024
(Thousands of U.S. dollars - ThUS$)
Note
12-31-2025
12-31-2024 (Restated) (*)
01-01-2024 (Restated) (*)
ThUS$
ASSETS
CURRENT ASSETS
Cash and cash equivalents
461,924
384,761
642,206
Other current financial assets
982
19,588
77,226
Other current non-financial assets
8.a
172,555
153,708
114,576
Trade and other receivables, current
1,386,241
1,495,258
1,652,333
Current receivables due from related parties
61,811
42,935
57,317
Inventories
68,121
65,400
66,994
Current tax assets
87,453
80,506
92,479
TOTAL CURRENT ASSETS
[Subtotal]
2,239,087
2,242,156
2,703,131
NON-CURRENT ASSETS
Other non-current financial assets
24,070
13,228
Other non-current non-financial assets
14,486
149,126
271,792
Trade and other non-current receivables
1,105,384
1,163,370
1,030,279
Investments accounted for using the equity method
46,468
32,820
28,906
Intangible assets other than goodwill
292,790
294,391
222,329
Goodwill
902,193
892,402
1,008,374
Property, plant and equipment
7,763,436
7,579,693
7,809,860
Investment property
7,930
7,201
8,369
Right-of-use assets
379,863
273,579
306,745
Deferred tax assets
19.b
127,952
125,685
88,551
TOTAL NON-CURRENT ASSETS
10,664,572
10,522,930
10,788,433
TOTAL ASSETS
12,903,659
12,765,086
13,491,564
(*) See Note 3.
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Financial Position, Classified (continued)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Other current financial liabilities
322,082
84,003
701,175
Current lease liabilities
41,518
26,982
27,520
Trade and other payables, current
1,533,475
1,535,871
1,669,660
Current payables to related parties
371,919
299,362
527,383
Other current provisions
30,702
51,534
28,676
Current tax liabilities
110,030
189,742
182,537
Other current non-financial liabilities
8.b
63,610
63,964
48,380
TOTAL CURRENT LIABILITIES
2,473,336
2,251,458
3,185,331
NON-CURRENT LIABILITIES
Other non-current financial liabilities
2,170,328
2,382,396
2,171,325
Non-current lease liabilities
368,679
268,670
278,097
Trade and other payables non-current
985,569
969,504
678,966
Non-current payables to related parties
861,531
1,019,514
1,179,760
Other long-term provisions
214,175
216,031
241,245
Deferred tax liabilities
200,452
208,635
196,681
Non-current provisions for employee benefits
64,058
65,831
71,621
Other non-current non-financial liabilities
16,024
37,745
60,676
TOTAL NON-CURRENT LIABILITIES
4,880,816
5,168,326
4,878,371
TOTAL LIABILITIES
7,354,152
7,419,784
8,063,702
EQUITY
Share and paid-in capital
27.1
3,895,895
5,964,284
Retained earnings
3,011,147
3,781,518
3,855,606
Other reserves
27.5
(1,731,173)
(4,769,387)
(4,750,937)
Equity attributable to shareholders of Enel Chile
5,175,869
4,976,415
5,068,953
Non-controlling interests
27.6
373,638
368,887
358,909
TOTAL EQUITY
5,549,507
5,345,302
5,427,862
TOTAL LIABILITIES AND EQUITY
F-7
Consolidated Statements of Comprehensive Income, by Nature
For the years ended December 31, 2025, 2024, and 2023
(Restated) (*)
STATEMENTS OF PROFIT (LOSS)
Revenue
4,509,547
4,137,511
5,075,058
Other operating income
153,183
87,314
140,080
4,662,730
4,224,825
5,215,138
(2,780,380)
(3,078,782)
(3,566,556)
Contribution Margin
1,882,350
1,146,043
1,648,582
Other work performed by the entity and capitalized
16.b.2
42,339
43,161
47,183
Employee benefits expense
(175,561)
(173,710)
(205,722)
Depreciation and amortization expense
31.a
(387,430)
(313,083)
(301,699)
Impairment (loss) reversal recognized in profit or loss
31.b
(35,458)
(36,242)
(8,363)
Impairment (loss) impairment gain and reversal of impairment loss determined in accordance with IFRS 9
(38,658)
(19,529)
(12,827)
Other expenses, by nature
(276,243)
(251,341)
(253,056)
Operating Income
1,011,339
395,299
914,098
Other gains (losses)
5,801
(310)
264,136
71,744
82,949
159,843
(330,272)
(246,450)
(294,160)
Share of profit of associates and joint ventures accounted for using the equity method
14,967
8,916
6,788
8,023
(23,027)
(1,020)
Gains or losses from indexed assets and liabilities
13,356
22,066
30,105
Profit (loss) before taxes
794,958
239,443
1,079,790
Income tax expense
19.a
(210,059)
(37,011)
(270,163)
PROFIT (LOSS)
584,899
202,432
809,627
Profit (loss) attributable to
Profit (loss) attributable to owners of the parent
537,629
153,763
754,195
Profit (loss) attributable to non-controlling interests
47,270
48,669
55,432
Profit (loss)
Basic earnings per share
Basic earnings (losses) per share
US$ / Share
Weighted average number of outstanding shares
thousands
69,166,557
Diluted earnings per share
Diluted earnings (losses) per share
Consolidated Statements of Comprehensive Income, by Nature (continued)
2024(Restated) (*)
2023(Restated) (*)
STATEMENTS OF COMPREHENSIVE INCOME
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
(357)
(3,233)
(32)
Other comprehensive loss that will not be reclassified subsequently to profit or loss
Gains (losses) from foreign currency translation differences
76,187
(497,393)
(111,354)
Share of other comprehensive income from associates and joint ventures accounted for using the equity method
Gains (losses) on cash flow hedges
(12,689)
(119,893)
(322,163)
Adjustments from reclassification of cash flow hedges, transferred to profit or loss
232
763,185
97,605
Other comprehensive income (loss) that will be reclassified subsequently to profit or loss
63,730
145,899
(335,896)
Total components of other comprehensive income (loss) before taxes
63,373
142,666
(335,928)
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
873
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Income tax expense (benefit) related to cash flow hedge
4,989
(175,880)
60,631
Income tax expense (benefit) related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Total other comprehensive (loss) income
68,458
(32,341)
(275,288)
TOTAL COMPREHENSIVE INCOME
653,357
170,091
534,339
Comprehensive income (loss) attributable to:
Owners of Enel Chile
605,445
129,743
493,412
47,912
40,348
40,927
F-9
Changes in Other Reserves
Share and Paid-inCapital (1)
TranslationReserve (2)
Reserve forCash FlowHedges
Reserve forDefined BenefitPlans
Reserve forGains and Losseson measuringFinancial Assetat Fair Value through OtherComprehensiveIncome
Other Comprehensive Income
Other MiscellaneousReserves
Total OtherReserves (3)
Retained Earnings
Equityattributable toowners ofthe parentto Shareholdersof Enel Chile
Non-ControllingInterests (4)
Total Equity
Consolidated Statement of Changes in Equity
Opening balance as of January 1, 2023 (Restated) (5)
(591,742)
(459,844)
(1,051,582)
(3,423,044)
(4,474,626)
3,319,546
4,809,203
342,436
5,151,639
Changes in equity
Comprehensive income
Other comprehensive income (loss)
(104,393)
(156,405)
(260,799)
(260,783)
(14,505)
(218,134)
(24,988)
(243,122)
Increase (decrease) from other changes
(23,818)
(23,817)
8,289
(15,528)
(15,529)
534
(14,995)
Total changes in equity
(128,211)
(284,616)
8,305
(276,311)
536,060
259,750
16,473
276,223
Closing balance as of December 31, 2023 (Restated) (5)
(719,953)
(616,249)
(1,336,198)
(3,414,739)
Opening balance as of January 1, 2024 (Restated) (5)
(476,513)
454,837
(2,344)
(24,020)
(8,321)
(225,506)
(36,639)
(262,145)
2,344
3,226
5,570
6,268
9,494
(21,675)
(18,450)
(74,087)
(92,537)
9,977
(82,560)
Closing balance as of December 31, 2024 (Restated) (5)
(1,196,466)
(161,411)
(1,357,873)
(3,411,514)
OtherMiscellaneousReserves
Opening balance as of January 1, 2025 (Restated) (5)
Increase (decrease) due to changes in accounting policies (6)
(2,068,389)
1,651,564
166,141
1,817,703
1,150,658
2,968,361
(899,972)
Opening balance restated after adjustment
455,098
4,730
459,830
(2,260,856)
(1,801,026)
2,881,546
75,223
(7,145)
67,816
(407,766)
(43,284)
(451,050)
1,775
2,037
123
1,898
68,078
69,853
129,601
199,454
4,751
204,205
Closing balance as of December 31, 2025
530,321
(2,415)
527,908
(2,259,081)
(1) See Note 27.1
(2) See Note 27.3
(3) See Note 27.5
(4) See Note 27.6
(5) See Note 3
(6) Represents adjustment for change in functional currency, see Note 3
Consolidated Statements of Cash Flows, Direct Method
Statements of Cash Flows - Direct Method
Cash flows from (used in) operating activities
Types of collection from operating activities
Collections from the sale of goods and services
6,725,625
6,873,268
7,008,302
Collections from leasing and subsequent sale of such assets
16,838
28,971
53,014
Other collections from operating activities
6,326
13,608
2,158
Types of payment in cash from operating activities
Payments to suppliers for goods and services
(4,833,436)
(4,778,565)
(5,522,146)
Payments to and on behalf of employees
(145,982)
(155,906)
(174,412)
Payments to manufacture or acquire assets held to lease to others and subsequently held for sale
(6,704)
Other payments for operating activities
6.c)
(167,510)
(140,468)
(165,747)
Income taxes paid
(272,166)
(206,205)
(351,226)
Other cash outflows, net
(10,017)
(5,829)
(9,778)
Net cash flows from operating activities
1,319,678
1,622,170
840,165
Cash flows from (used in) investing activities
Cash flows from the loss of control of subsidiaries or other businesses
6.d)
619,217
Cash flows used to obtain the control of subsidiaries or other businesses
(76)
Other cash payments to acquire equity or debt instruments of other entities
(2,348)
(1,750)
Other collections from the sale of shares in joint ventures
6.e)
35,316
Proceeds from the sale of property, plant and equipment
2,285
40,456
Purchases of property, plant and equipment
(462,284)
(724,780)
(758,168)
Acquisition of intangible assets
(36,824)
(40,637)
(30,517)
Payments for future, forward, option and swap contracts
(5,675)
(4,742)
(64,689)
Collections from future, forward, option and swap contracts
1,274
9,136
16,324
Dividends received
1,001
Interest received
12,322
22,013
41,179
Other cash inflows
3,762
Net cash flows (used in) investing activities
(487,901)
(737,596)
(102,675)
Cash flows from (used in) financing activities
Proceeds from long-term loans
6.f)
190,000
475,021
296,125
Proceeds from short-term loans
326
Loans from related companies
1,157,361
914,006
Payments of loans
(237,115)
(800,468)
(100,919)
Payments on borrowings and lease liabilities
(36,535)
(18,956)
(21,929)
Payments of loans to related entities
(161,092)
(1,304,231)
(1,494,223)
Dividends paid
(351,451)
(365,644)
(478,139)
Interest paid
(174,336)
(217,723)
(229,992)
Other outflows of cash, net
(366)
(20,147)
2,441
Net cash flows (used in) financing activities
(770,895)
(1,094,787)
(1,112,304)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate movements
60,882
(210,213)
(374,814)
16,281
(47,232)
(5,593)
Net increase (decrease) in cash and cash equivalents
77,163
(257,445)
(380,407)
Cash and cash equivalents at beginning of year
1,022,613
Cash and cash equivalents at end of year
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Contents
1. GENERAL INFORMATION
F-15
2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS
F-16
2.1 Accounting principles
2.2 New accounting pronouncements
2.3 Responsibility for the information, judgments and estimates provided
F-20
2.4 Subsidiaries
F-21
2.5 Investment in associates
F-22
2.6 Joint arrangements
F-23
2.7 Basis of consolidation and business combinations
2.8 Functional currency
F-25
2.9 Conversion of financial statements denominated in foreign currency
3. CHANGE OF FUNCTIONAL CURRENCY AND PRESENTATION CURRENCY
F-26
4. ACCOUNTING POLICIES
F-31
a) Property, plant and equipment
b) Investment property
F-32
c) Goodwill
F-33
d) Intangible assets other than goodwill
d.1) Research and development expenses
d.2) Other intangible assets
e) Impairment of non-financial assets
F-34
f) Leases
F-36
f.1) Lessee
f.2) Lessor
F-37
g) Financial instruments
g.1) Financial assets other than derivatives
g.2) Cash and cash equivalents
F-38
g.3) Impairment of financial assets
g.4) Financial liabilities other than derivatives
F-40
g.5) Derivative financial instruments and hedge accounting
g.6) Derecognition of financial assets and liabilities
F-41
g.7) Offsetting of financial assets and financial liabilities
F-42
g.8) Financial guarantee contracts
h) Fair value measurent
i) Investments accounted for using the equity method
F-43
j) Inventories
F-44
k) Non-current assets (or disposal group of assets) held for sale or held for distribution to owners and discontinued operations
l)Treasury shares
F-45
m) Provisions
m.1) Provisions for post-employment benefits and similar obligations
n) Translation of foreign currency balances
F-46
o) Classification of balances as current and non-current
p) Income taxes
q) Revenue and expense recognition
F-47
r) Earnings per share
F-49
s) Dividends
t) Share issuance costs
u) Statement of cash flows
F-50
5. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS
F-51
5.1 General Overview and Industry Structure
5.2 Regulatory framework
F-53
5.2.1 Main regulatory authorities
5.2.2 Remuneration and tariffs
F-54
5.2.3 Environmental regulations
F-55
5.2.4 Regulatory matters
6. CASH AND CASH EQUIVALENTS
F-57
7. OTHER FINANCIAL ASSETS
F-60
8. OTHER NON-FINANCIAL ASSETS AND LIABILITIES
9. TRADE AND OTHER RECEIVABLES
F-61
10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES
F-66
10.1 Balances and transactions with related parties
a) Receivables from related parties
b) Payables to related parties
F-67
c) Significant transactions and effects on profit or loss
F-68
d) Undiscounted contractual cash flows
e) Significant transactions
10.2 Board of Directors and key management personnel
F-69
10.3 Compensation of key management personnel
F-73
10.4 Incentive plans for key management personnel
10.5 Compensation plans linked to share price
F-74
11. INVENTORY
F-75
12. CURRENT TAX ASSETS AND LIABILITIES
13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD
F-76
13.1. Investments accounted for using the equity method
13.2. Additional financial information on investments in associates
F-77
13.3. Joint ventures
F-78
14. INTANGIBLE ASSETS OTHER THAN GOODWILL
F-79
15. GOODWILL
F-81
16. PROPERTY, PLANT AND EQUIPMENT
F-83
17. INVESTMENT PROPERTY
F-87
18. RIGHT-OF-USE-ASSETS
F-88
19. INCOME TAX AND DEFERRED TAXES
F-89
a) Income taxes
b) Deferred taxes
F-90
20. OTHER FINANCIAL LIABILITIES
F-92
20.1 Interest-bearing borrowings
20.2 Unsecured liabilities
F-94
20.3 Hedged debt
F-96
20.4 Other information
20.5 Future Undiscounted debt flows
F-97
21. LEASE LIABILITIES
21.1 Individualization of Lease Liabilities
F-98
21.2 Undiscounted debt cash flows
F-100
22. RISK MANAGEMENT POLICY
F-101
22.1 Interest rate risk
22.2 Exchange rate risk
F-102
22.3 Commodities risk
22.4 Liquidity risk
F-103
22.5 Credit risk
22.6 Risk measurement
F-104
23. FINANCIAL INSTRUMENTS
F-105
23.1 Financial instruments, classified by type and category
23.2 Derivative instruments
F-106
23.3 Fair value hierarchy
F-109
24. CURRENT AND NON-CURRENT PAYABLES
F-110
25. PROVISIONS
F-111
26. POST-EMPLOYMENT BENEFIT OBLIGATIONS
F-112
26.1 General information
26.2 Details, movements and presentation in financial statements
26.3 Other disclosures
F-113
27. EQUITY
F-114
27.1 Subscribed and paid capital and number of shares
27.2 Dividends
27.3 Foreign currency translation reserves
F-13
27.4 Restrictions on subsidiaries transferring funds to the parent
27.5 Other reserves
F-115
27.6 Non-controlling Interests
F-116
28. REVENUE AND OTHER OPERATING INCOME
F-117
29. RAW MATERIALS AND CONSUMABLES USED
F-118
30. EMPLOYEE BENEFITS EXPENSE
31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSS OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9
F-119
32. OTHER EXPENSES, BY NATURE
33. OTHER GAINS (LOSSES)
F-120
34. FINANCIAL RESULTS
F-121
35. INFORMATION BY SEGMENT
F-123
35.1 Basis of segmentation
35.2 Generation and distribution
F-124
36. GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS
F-126
36.1 Direct guarantees
36.2 Indirect guarantees
36.3 Litigation and arbitration proceedings
36.4 Financial restrictions
F-129
37. HEADCOUNT
F-132
38. SANCTIONS
39. ENVIRONMENT
F-134
40. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED
F-137
41. SUBSEQUENT EVENTS
F-138
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY
F-139
APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012
F-141
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES
F-143
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY, POWER AND TOLL
F-146
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS
F-147
F-14
FOR THE YEAR ENDED DECEMBER 31, 2025
(In thousands of U.S. dollars – ThUS$)
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 Roger de Flor 2725, Tower 2, Floor 17, Las Condes, 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, 2025, the Group had 1,792 employees. During 2025, the Group averaged a total of 1,852 employees. For more information regarding the distribution of the Company’s employees, by category and geographic location, see Note 36.
The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy of any kind or form, whether in Chile or abroad, either directly or through other companies. It is also engaged in telecommunications activities, and it provides engineering consulting services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing, its investments in subsidiaries and associates which generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:
BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS
2.1. Accounting principles
The consolidated financial statements of Enel Chile as of December 31, 2025, approved by its Board of Directors at its meeting held on April 28, 2026, have been prepared in accordance with the accounting standards of International Financial Reporting Standards (IFRS Accounting Standards), 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, 2025, December 31, 2024, and January 1, 2024 and the results of operations, changes in equity, and cash flows for the years ended December 31, 2025, 2024, and 2023 and the related notes.
These consolidated financial statements have been prepared undergoing concern assumptions on a historical cost basis, except when, in accordance with IFRS Accounting Standards, 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
Amendments and Improvements
Mandatory application for annual periods beginning on or after:
Amendments to IAS 21: Lack of Exchangeability
January 1, 2025
Amendments to IAS 21: “Lack of Exchangeability”
On August 15, 2023, the IASB issued amendments to IAS 21 “The Effects of Changes in Foreign Exchange Rates” to respond to commentary from stakeholders and concerns on the diversity in practice when accounting for the lack of exchangeability between currencies.
These amendments establish criteria that will allow entities to apply a consistent approach to assess whether or not a currency is exchangeable into another and, when it is not, determining the exchange rate to be used and the disclosures to be provided. The amendment establishes that a currency is exchangeable into another at the measurement date when an entity can exchange that currency into another currency within a timeframe that includes a normal administrative delay and through an exchange market or mechanism in which an exchange transaction would create enforceable rights or obligations.
These amendments are effective for annual periods beginning on or after January 1, 2025.
The adoption of these amendments did not have any impact on the Group's consolidated financial statements at the initial application date.
As of the date of issuance of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB:
Standards, amendments and improvements
Amendments to IFRS 9 and IFRS 7: Classification and Measurement of Financial Instruments
January 1, 2026
Annual Improvements to IFRS Accounting Standards (Volume 11):
- IFRS 1 First-time Adoption of IFRS
- IFRS 7 Financial Instruments: Disclosures
- IFRS 9 Financial Instruments
- IFRS 10 Consolidated Financial Statements
- IAS 7 Statement of Cash Flows
Amendments to IFRS 9 and IFRS 7: Contracts Referencing Nature-dependent Electricity
IFRS 18: Presentation and Disclosure in Financial Statements
January 1, 2027
IFRS 19: Subsidiaries without Public Accountability: Disclosures
Amendments to IAS 21: Translation to a Hyperinflationary Presentation Currency
Amendments to IFRS 9 and IFRS 7 “Classification and Measurement of Financial Instruments”
On May 30, 2024, the IASB issued limited scope amendments to the requirements for the classification and measurement of financial instruments in IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures. These amendments are a response to the comments of the “Post-implementation review” of the 2022 Accounting Standards and clarify the requirements in areas where the stakeholders have expressed concerns or where new issues have arisen from the issuance of IFRS 9.
These amendments address the following issues:
The IASB also changed the disclosure requirements related to investments in equity instruments designated at fair value through other comprehensive income and added disclosure requirements for financial instruments with contingent features that are not directly related to the risks and basic costs of loans.
These amendments are applicable retrospectively for annual periods beginning on or after January 1, 2026 and early adoption is permitted.
Management has conducted an assessment of the estimated impacts of these amendments and concluded that their adoption will not generate significant effects on the Group’s consolidated financial statements at the initial application date.
F-17
Annual Improvement to IFRS Accounting Standards (Volume 11)
On July 18, 2024, the IASB issued limited amendments to IFRS Accounting Standards and the accompanying guide as part of its regular Standards maintenance process. Annual improvements are limited to changes that clarify the wording of an IFRS Accounting Standard or correct relatively minor undesired consequences or conflicts between the requirements in IFRS Accounting Standards.
These amendments include clarifications, simplifications, corrections and changes destined to improve the consistency of the following IFRS Accounting Standards:
These amendments are effective for annual periods beginning on or after January 1, 2026 and early adoption is permitted.
Management has conducted an assessment of the estimated impacts of this amendment and concluded that its adoption will not generate effects on the Group’s consolidated financial statements at its initial application date.
Amendments to IFRS 9 and IFRS 7 “Contracts referencing nature-dependent electricity”
On December 18, 2024, the IASB issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures. These amendments are intended to help companies better report financial effects of nature-dependent electricity contracts in their financial statements, which are often structured as power purchase agreements.
Nature-dependent electricity contracts help companies secure their electricity supply from sources, such as wind and solar power. The amount of electricity generated under these agreements can vary depending on uncontrollable factors, such as weather conditions. Current accounting requirements may not adequately reflect how these contracts affect a company’s performance.
The amendments relate to own use requirements and hedge accounting requirements, together with related disclosures.
F-18
IFRS 18 “Presentation and Disclosure in Financial Statements”
On April 9, 2024, the IASB issued IFRS 18 Presentation and Disclosure in Financial Statements for the purpose of improving the transparency and comparability of information on the financial performance of companies, allowing better investing decisions. The new standard supersedes IAS 1 “Presentation of Financial Statements”.
IFRS 18 introduces three sets of new requirements to improve an entity’s reporting of its financial performance and provide investors with a better basis to analyze and compare companies:
The new standard is applicable for annual periods beginning on or after January 1, 2027 and early adoption is permitted.
Management is assessing the potential impact of the adoption of IFRS 18 on the Group’s consolidated financial statements.
IFRS 19 “Subsidiaries without Public Accountability - Disclosures”
On May 9, 2024, the IASB issued IFRS 19 Subsidiaries without Public Accountability: Disclosures, whose objective is to allow eligible subsidiaries to opt for using IFRS Accounting Standards with reduced disclosures. The new Standard seeks to reduce the cost of preparation of the financial statements of subsidiaries, while maintaining the usefulness of the information for its users.
Subsidiaries are eligible to apply IFRS 19 if they have no public accountability and their Parent applies IFRS Accounting Standards in its consolidated financial statements. A subsidiary has no public accountability if it does not have shares or debt that is traded in a stock exchange, and it does not act in a fiduciary capacity for the assets of a broad group of outsiders. Entities that choose to apply IFRS 19 must still apply the recognition, measurement and presentation requirements of other IFRS Accounting Standards.
An entity can elect to apply IFRS 19 for annual periods beginning on or after January 1, 2027 and early adoption is permitted.
Management has determined that IFRS 19 is not applicable to the consolidated financial statements of the Group because Enel Chile does not meet the eligibility criteria.
F-19
Amendment to IAS 21 “Translation to a Hyperinflationary Presentation Currency”
On November 13, 2025, the IASB issued amendments to IAS 21 “The Effects of Changes in Foreign Exchange Rates”, to clarify certain situations regarding the translation of financial statements of hyperinflationary economies.
These amendments establish translation criteria for financial statements of entities whose functional currency is that of a non-hyperinflationary economy into a presentation currency of a hyperinflationary economy. They also clarify the translation method for entities with presentation currencies that cease to be of a hyperinflationary economy and whose functional currency is that of a non-hyperinflationary economy. Lastly, they establish a different approach when an entity’s functional currency and presentation currency are the currency of a hyperinflationary economy, and the entity translates the results and financial position of a foreign operation whose functional currency is that of a non-hyperinflationary economy.
These amendments will be effective for annual periods beginning on January 1, 2027 and early application is permitted.
Management has performed an assessment of the estimated impacts of this amendment and concluded that its adoption will not have effects on the Group’s consolidated financial statements at the date of its initial application.
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 information included in the consolidated financial statements is selected based on a materiality analysis conducted in accordance with the requirements set out in IAS 1 “Presentation of Financial Statements” and IFRS Practice Statement No. 2 “Making Materiality Judgements” and based on investor expectations.
The most significant areas where material judgment has been required are:
-The identification of Cash Generating Units (CGU) for impairment testing (see Note 4.e).
-The hierarchy of information used to measure assets and liabilities at fair value (see Note 4.h).
-Application of the revenue recognition model in accordance with IFRS 15 (see Note 4.q).
-Determination of the functional currency of Enel Chile and each of its subsidiaries, including the application of the accounting for the change in functional and presentation currency (see Note 3).
Accounting estimates generally refer to:
-
The valuations performed to determine the existence of impairment losses in non-financial assets and goodwill (see Note 4.e).
The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 4.m.1 and 26).
The useful lives of property, plant and equipment and intangible assets (see Notes 4.a and 4.d).
The assumptions used to calculate the fair value of financial instruments (see Notes 4.h and 23).
The energy supplied to customer whose meters have not yet been read.
Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, that allow for estimation of electricity system settlements that occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recognized in the financial statements (see Appendix 2.2).
The interpretation of new normative related to the regulation of the Electric Sector, whose final economic effects will be determined by the resolutions of the relevant agencies (see Notes 5 and 9).
The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 4.m).
Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 4.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 4.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 4.g.3).
In the measurement of lease liabilities, determination of the lease term of contracts with renewal options, as well as the rates to be used to discount lease payments (see Note 4.f.1).
Estimates and judgements by Management have been made based on the best information available at the date of issuance of these consolidated financial statements, and are based on past experiences and other factors considered reasonable given the circumstances. Accordingly, actual results may differ from these estimates. Estimates and assumptions are periodically reviewed and the effects of any changes are reflected in results if they only involve that period. If the review involves both the current period and the future period, the change is recognized in the period in which the review is conducted and in the related future periods.
2.4.Subsidiaries
Subsidiaries are defined as those entities controlled, directly or indirectly by Enel Chile. Control is exercised if and only if the following conditions are met: Enel Chile 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.
Ownership as of 12-31-2025
Ownership as of 12-31-2024
Ownership as of 01-01-2024
Taxpayer ID No.
Country
Currency
Direct
Indirect
96.800.570-7
Chilean peso
96.783.910-8
91.081.000-6
U.S. dollar
96.504.980-0
92.65%
77.047.280-6
Sociedad Agrícola de Cameros Ltda.
57.50%
76.924.079-9
76.412.562-2
96.971.330-6
Geotérmica del Norte S.A.
84.59%
76.126.507-5
Parque Talinay Oriente S.A.
60.91%
77.741.548-4
Enel Mobility Chile SpA
77.569.067-4
Enel X Way Chile S.p.A. (i)
62.46%
2.4.1Changes in the scope of consolidation
No changes occurred.
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 4.i.
The detail of the companies that qualify as associates is the following:
76.418.940-K
GNL Chile S.A.
33.33%
76.364.085-K
Energía Marina S.p.A.
25.00%
Enel X Way Chile S.p.A.(i)
49.00%
i.
On August 1, 2024, Enel Chile participated in a capital increase in Enel X Way Chile S.p.A., which was fully contributed on August 23, 2024. As a result of this capital increase, Enel Chile´s ownership interest in Enel X Way Chile S.p.A. increased from 49% to 62.46%, thereby gaining control of the company and resulting in Enel X Way Chile S.p.A. becoming a subsidiary.
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:
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:
77.110.358-8
HIF H2 SpA.
50.00%
Currently, Enel Chile is not involved in any joint arrangement that qualifies as a joint operation.
2.7. Basis of consolidation and business combinations
The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations of intra-group transactions have been made.
The comprehensive income from subsidiaries is included in the consolidated statement of comprehensive income from the date when the 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:
For each business combination, IFRS Accounting Standards allow valuation of the non-controlling interests in the acquiree on the date of acquisition: i) at fair value; or ii) for the proportional ownership of the identifiable net assets of the acquiree, with the latter being the methodology that the Group has systematically applied to its business combinations.
If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained about events and circumstances that existed on the acquisition date, but which were unknown to Management at that time. Comparative information for prior periods presented in the financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting.
For business combinations achieved in stages, the Parent Company measures at fair value the participation previously held in the equity of the acquiree on the date of acquisition and the resulting gain or loss, if any, is recognized in profit or loss of the period.
Non-controlling interests in equity and in the comprehensive income of the consolidated subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Profit (loss) attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.
3.
Balances and transactions between consolidated companies have been fully eliminated on consolidation.
4.
Changes in the ownership interests in subsidiaries that do not result in the Group obtaining or losing control are recognized as equity transactions. The carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in equity attributable to shareholders of the Parent Company.
F-24
5.
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 U.S. dollar (US$). The functional currency has been determined, considering the economic environment in which the Company operates. (See Note 3).
This conclusion is based on the fact that the US$ is the currency that fundamentally influences the Company’s financing activities, capital issuances and cash and cash equivalents. Due to the above, the US$ reflects the underlying transactions, events and conditions that are relevant to Enel Chile S.A.
Any information presented in US$ has been rounded to the closest thousand (ThUS$) or million (MUS$), 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 US$, and do not operate in hyperinflationary economies, is carried out as follows:
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 in 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 the Argentine branch owned by Enel Generación Chile S.A., a subsidiary of Enel Chile, have been restated retrospectively, applying the general price index at historical cost, 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 2023
211.41%
From January to December 2024
117.76%
From January to December 2025
31.55%
The effects of the application of this standard on these consolidated financial statements are detailed in Note 34.
Exchange rates
The exchange rates used for the translation of the financial statements of the different subsidiaries with a functional currency other than the Group's functional currency are recorded at the following values (foreign currency against the US$):
As of December 31,
Close
Argentine peso
1,455.00
1,250.90
1,032.00
915.43
808.45
294.68
Effective January 1, 2025, Enel Chile changed its functional currency from Chilean pesos (Ch$) to United States dollars (US$), because the U.S. dollar became the currency that significantly influences the economic environment in which the Company operates.
This change in functional currency was substantially generated by the fact that, effective January 1, 2025, Enel Generación Chile, a subsidiary of Enel Chile, also changed its functional currency from Chilean pesos to U.S. dollars. This was mainly because as of January 1, 2025, the main source of revenue of this subsidiary is from the group of unregulated customer agreements that, considering the billing and collection cycles, give rise to a substantially lower exposure to exchange rate fluctuations compared with the group of regulated customers, which require considerably more time to complete the collection process. The group of regulated customer agreements represented Enel Generación Chile's main source of revenue in 2024.
Thus, considering the relevance of the Generation segment for the Group, the main source of revenue of Enel Chile, that is, the dividends from its subsidiaries, will be determined in United States dollars (US$).
The change in functional currency was accounted for prospectively as of January 1, 2025, by translating all items in the consolidated statement of financial position from Chilean pesos to U.S. dollars using the exchange rate of Ch$996.46 per US$1.00 effective on that date.
Effective January 1, 2025, Enel Chile also changed the presentation currency of its consolidated financial statements to U.S. dollar. This change in presentation currency was accounted for as a change in accounting policy and was applied retrospectively, as if the U.S. dollar had always been the presentation currency in the consolidated financial statements.
Additionally, in accordance with the guidelines established in International Accounting Standard No. 1 “Presentation of Financial Statements”, the consolidated statement of financial position as of January 1, 2024, has been presented for comparative purposes, because during 2024 the Chilean peso depreciated by 13.5% against the U.S. dollar, a change that materially affects the translation of balance sheet items into U.S. dollars from the beginning to the end of the 2024 fiscal year.
Accordingly, all comparative figures for years and periods prior to January 1, 2025, have been translated into the new presentation currency in accordance with IAS 21, “The Effects of Changes in Foreign Exchange Rates”. The consolidated statements of comprehensive income and cash flows were translated to U.S dollars using the average exchange rate for each period, while the consolidated statements of financial position as of December 31, 2024, and January 1, 2024, were translated to U.S. dollars using the closing exchange rates of Ch$996.46 per US$1.00 and Ch$877.12 per US$1.00, respectively. Issued capital, retained earnings, and other reserves within equity were translated using the historical exchange rates applicable at the dates of the respective equity transactions, and all resulting foreign currency translation differences have been recognized in equity within the foreign currency translation reserve.
Enel Chile’s change to a new functional currency was formally approved at the Extraordinary Shareholders’ Meeting held on April 28, 2025. To facilitate this change, permanent article five of the Company’s bylaws was amended denominating Enel Chile’s capital in U.S. dollars.
F-27
Statement of Financial Position as of December 31, 2024, and January 1, 2024:
As of 12-31-2024
As of 01-01-2024
As Reported
Restated
Th$
383,399,319
563,291,290
19,518,512
67,736,634
153,163,381
100,497,325
1,489,965,233
1,449,294,549
42,783,336
50,274,125
65,168,573
58,761,879
80,220,499
81,115,457
2,234,218,853
2,370,971,259
4,646,303
11,602,385
148,597,823
238,393,864
1,159,251,669
903,678,141
32,703,763
25,353,785
293,348,456
195,009,500
889,242,912
884,464,658
Property, plant, and equipment
7,552,861,067
6,850,184,820
7,175,892
7,340,561
272,610,975
269,052,555
125,239,871
77,669,508
10,485,678,731
9,462,749,777
12,719,897,584
11,833,721,036
83,705,578
615,014,915
26,886,119
24,138,193
1,530,434,532
1,464,491,965
298,301,928
462,578,466
51,351,795
25,152,710
189,070,151
160,107,212
63,737,298
42,434,883
2,243,487,401
2,793,918,344
2,373,962,103
1,904,512,941
267,718,931
243,924,027
966,072,117
595,534,857
1,015,904,873
1,034,791,219
215,266,701
211,600,686
207,896,524
172,512,663
65,598,156
62,820,044
37,611,263
53,219,983
Total non-current liabilities
5,150,030,668
4,278,916,420
7,393,518,069
7,072,834,764
3,882,103,470
2,871,345,789
2,917,851,065
(1,794,650,838)
(2,353,874,617)
4,958,798,421
4,446,079,918
367,581,094
314,806,354
5,326,379,515
4,760,886,272
TOTAL EQUITY AND LIABILITIES
F-28
Statement of Comprehensive Income for the years ended December 31, 2024 and December 31, 2023:
3,904,732,890
4,262,591,097
82,402,403
117,654,896
3,987,135,293
4,380,245,993
(2,905,568,914)
(2,995,585,459)
1,081,566,379
1,384,660,534
40,732,541
39,629,466
Employee benefits expenses
(163,937,134)
(172,787,800)
(295,468,978)
(253,399,784)
(34,203,486)
(7,023,888)
Impairment losses (gains on impairment and reversal of impairment losses) determined in accordance with IFRS 9 on financial assets
(18,429,856)
(10,773,445)
Other expenses by nature
(237,200,190)
(212,543,865)
373,059,276
767,761,218
(291,724)
221,846,937
78,282,443
134,253,836
(232,584,262)
(247,067,556)
Share of profits (losses) of associates and joint ventures accounted for using the equity method
8,413,675
5,702,088
Foreign currency exchange gains (losses)
(21,732,058)
(856,350)
20,824,185
25,285,703
Profit (loss) before tax
225,971,535
906,925,876
(34,928,564)
(226,912,485)
191,042,971
680,013,391
145,112,153
633,455,775
45,930,818
46,557,616
Basic earnings (loss) per share
2.10
9.16
Weighted average number of ordinary shares outstanding
Diluted earnings (loss) per share
F-29
Statements of Cash Flows for the years ended December 31, 2024 and December 31, 2023:
6,486,575,452
5,886,342,023
27,340,625
44,527,326
12,842,555
1,812,296
Types of payment cash from operating activities
(4,509,721,561)
(4,638,105,198)
(147,134,962)
(146,490,612)
(6,326,670)
(132,565,162)
(139,212,339)
(194,603,727)
(294,998,284)
(5,500,674)
(8,212,967)
1,530,905,876
705,662,245
520,086,080
(63,727)
(2,216,167)
(1,470,000)
29,662,554
33,979,203
(684,003,978)
(636,792,401)
Proceeds from the sale of intangible assets
(38,350,319)
(25,631,385)
(4,475,539)
(54,333,349)
8,622,118
13,710,904
27,540
20,774,572
34,586,244
3,549,909
(696,099,404)
(86,238,337)
448,296,220
248,718,361
273,777
1,092,247,399
767,682,700
(755,433,698)
(84,762,889)
(17,889,151)
(18,418,666)
(1,230,854,131)
(1,255,012,700)
(345,072,557)
(401,593,903)
(205,473,569)
(193,172,908)
(19,013,832)
2,050,585
(1,033,193,319)
(934,235,643)
Net decrease in cash and cash equivalents before effect of exchange rate movements
(198,386,847)
(314,811,735)
18,494,876
2,889,326
Net decrease in cash and cash equivalents
(179,891,971)
(311,922,409)
875,213,699
F-30
The main material accounting policies used in preparing the accompanying consolidated financial statements are the following:
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:
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 4.f.1.
The following are the main categories of property, plant and equipment with their related estimated useful lives:
Classes of property, plant and equipment
Years of estimated useful life
Buildings
10 – 60
Plant and equipment
6 – 65
IT equipment
3 – 15
Fixtures and fittings
2 – 35
Motor vehicles
5 – 10
In addition, for further information, the following is a more detailed breakdown of the class of plant and equipment:
Class of plant and equipment
Generating plant and equipment
Hydroelectric plants
Civil engineering works
10 – 65
Electromechanical equipment
10 – 45
Combined cycle power plants
10 – 25
Renewable
10 – 50
Wind Power Plants
Solar Power Plants
Geothermal Power Plants
10 – 40
Distribution plant and equipment
Low- and medium-voltage network
Measuring and remote control equipment
Primary substations
6 – 25
Natural gas transportation plant and equipment
Gas pipelines
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 or retirement of items of property, plant and equipment, 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” includes land and buildings that are kept for the purpose of obtaining gains from future sales or lease arrangements.
Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses experienced. Investment property, excluding land, is depreciated by distributing the cost of the several elements that comprise it on a straight-line basis over the years of useful life.
An investment property is derecognized on disposal, or when no future economic benefits are expected from use or disposal.
Gains or losses arising from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the statement of comprehensive income and determined as the difference between the sales amount and the net carrying amount of the asset.
The fair value of investment property is disclosed in Note 17.
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 U.S. dollars 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 4.e).
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, 2025, December 31, 2024, and January 1, 2024, intangible assets with indefinite useful lives amounted to ThUS$9,355, ThUS$7,281, and ThUS$7,507 respectively, mainly related to easements and water rights.
An intangible asset is derecognized when it is sold or otherwise disposed of, or when no future economic benefits are expected from its use, sale or other disposal.
Gains or losses arising from sales of intangible assets are recognized in profit or loss for the period and determined as the difference between the amount of the sale and the carrying amount of the asset.
The criteria for recognizing impairment losses on these assets and, if applicable, recoveries of impairment losses recorded in prior periods are explained in letter e) of this Note below.
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.
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.
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. As of December 31, 2025, the rates used to extrapolate the projections were between 2.3% and 3.0% (between 2.3% and 3.0% as of December 31, 2024 and between 2.3% and 3.3% as of December 31, 2023).
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 as of December 31, 2025 ranged from 7.8% to 9.4%, as of December 31, 2024 ranged from 8.6% to 10.9%, and as of December 31, 2023 ranged from 8.2% to 11.0%.
The Company’s approach to allocate value to each key assumption used to project cash flows, considers:
Past experience has demonstrated the reliability of the Company's forecasts, which allows it to base key assumptions on historical information. During 2025, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2024 were not significant and cash flows generated in 2025 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.
F-35
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.
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.
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 consists 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 re-measurement of the lease liability, less accumulated depreciation and accumulated impairment losses. A right-of-use asset is depreciated on the same terms as other similar depreciable assets, as long as there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If no such certainty exists, the leased assets are depreciated over the shorter of the useful lives of the assets and their lease term. The same criteria detailed in Note 4.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.
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 are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.
The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method (see Notes 4.i and 13) and non-current assets and disposal groups held for sale or distribution to owners (see Note 4.k), into three categories:
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, receivables 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.
This category includes the financial assets that meet the following conditions: (i) they are classified in a business model, the purpose of which is to maintain the financial assets both to collect the contractual cash flows and to sell them, and (ii) the contractual conditions meet the SPPI criterion.
These financial assets are recognized in the consolidated statement of financial position at fair value when this can be determined reliably. For the holdings in unlisted companies or companies with low liquidity, it is usually not possible to determine the fair value reliably, therefore, when this occurs, such holdings are valued at their acquisition cost or for a lower amount if there is evidence of their impairment.
Changes in fair value, net of their tax effect, are recorded in the consolidated statement of comprehensive income: Other comprehensive income, until the disposal of these financial assets, when 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.
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.
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.
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:
In general, the measurement of expected credit losses for financial assets other than trade receivables, contractual assets or lease receivables, are performed separately.
For trade accounts receivable, contractual assets and lease receivables, the Group applies two types of evaluations of expected credit losses:
To measure the expected credit losses collectively, the Group considers the following assumptions:
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 receivables, 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.
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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.
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 4.g.1).
Lease liabilities are initially measured at the present value of future lease payments, determined in accordance with the criteria described in Note 4.f.1.
In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability is measured at its fair value for the portion of the hedged risk.
In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 23, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and floating interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that debt issued at floating interest rate, i.e., each coupon is established at the beginning of each period based on the benchmark interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.
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”.
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:
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 long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Accordingly, the purpose of fuel purchase agreements is to use them to generate electricity, electricity purchase contracts for use in sales to end-customers, and electricity sale contracts for sale of the Group’s own products.
The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the host contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the statement of comprehensive income.
Financial assets are derecognized when:
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 4.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 recognition of the current conditions of an existing financial liability (or a part thereof), is recorded as a cancellation of the original financial liability, and a recognition of a new financial liability.
The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position only when:
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.
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 fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the entity, namely, the market that maximizes the amount that would be received to sell the asset or minimizes the amount that would be paid to transfer the liability.
In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there is sufficient data to perform the measurement where it maximizes the use of relevant observable data and minimizes the use of unobservable data.
Given the hierarchy explained below, data used in the valuation techniques, assets and liabilities measured at fair value can be classified at the following levels:
The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:
Financial assets and financial liabilities measured at fair value are shown in Note 23.3.
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 the related provision is recognized.
The financial statements of associates or joint ventures are prepared for the same reporting period as the Group. When necessary, adjustments are made to align the accounting policies with those of the Group.
Goodwill from the associate or joint venture is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when there are indicators of impairment.
Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using the equity method of accounting”.
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, 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:
For the above classifications, the assets must be available for immediate sale or distribution in their present condition and their sale or distribution must be highly probable. For a transaction to be considered highly probable, management must be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification.
Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan can be made or that the plan will be cancelled. The probability of shareholders’ approval (if required in the jurisdiction) should be considered as part of the assessment of whether the sale or distribution is highly probable.
The assets or disposal groups classified as held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.
Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.
Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution, less any depreciation, amortization or revaluation that would have been recognized had they had not been 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:
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 are presented as a deduction to 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 are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.
The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal costs expected to be incurred in resolving a legal claim are included in measuring of the provision.
Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.
A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.
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”.
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.
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.
Obligations maturing in less than twelve months, but for which the Company has the substantial right to defer settlement for at least 12 months at the end of the reporting period, are classified as non-current liabilities.
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:
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 records, 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 is recognized when (or as) the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which the Group is expected to be entitled for said transfer of control, excluding the amounts collected on behalf of third parties.
The Group analyzes and takes into consideration all the relevant facts and circumstances for revenue recognition, applying the five-step model established by IFRS 15: 1) Identifying the contract with a customer; 2) Identifying the performance obligations; 3) Determining the transaction price; 4) Allocating the transaction price; and 5) Recognizing revenue.
The following are the criteria for revenue recognition by type of good or service provided by the Group:
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).
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 from revenue those gross inflows of economic benefits received when it acts as agent or commission agent on behalf of third parties, recording as revenues only the payment or commission to which it expects to be entitled.
Because the Group mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the disclosure practical expedient provided in IFRS 15, through which it is not required to disclose the aggregate amount of the transaction price allocated to the performance obligations not met (or not met partially) at the end of the reporting period.
In addition, the Group evaluates the existence of incremental costs of obtaining a contract with a customer and costs directly related to the fulfillment of a contract with a customer. These costs are recognized as an intangible asset if their recovery is expected to be 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 amortization period of the asset that would have 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, 2025, December 31, 2024, and January 1, 2024 incremental costs of obtaining a contract capitalized by the Group primarily relate to commissions paid to sales agents (see Note 14).
Interest income (expense) are recorded considering the effective interest rate applicable to the principal pending amortization during the related accrual period.
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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, if any.
Diluted earnings per share is calculated by dividing profit attributable to shareholders of the Parent 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.
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's 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 “Payables due to related parties, current”, 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.
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 that occurs immediately after the date on which the disbursements were incurred.
Share issuance and placement expenses directly related to a probable future transaction are recorded as prepaid expenses in the statement of financial position. These expenses are recorded in equity upon issuance and placement of the shares, or in profit or loss when the condition changes and the transaction is no longer expected to occur.
The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined using the direct method. It uses the following definitions and related meanings:
5.1. General Overview and Industry Structure
The Chilean electricity market is comprised of four main types of local participants: generators, transmission companies, distribution companies, and large customers. The industry’s three core business segments—generation, transmission, and distribution—are required to function in a coordinated and interconnected manner to ensure that electricity is delivered to end customers efficiently, at the lowest possible cost, and in compliance with the quality and safety standards set by regulatory authorities.
Chile’s electricity sector is organized into three primary grids: the National Electric System (SEN, in its Spanish acronym), which stretches from Arica in the north to Chiloé in southern Chile, as well as two smaller isolated grids (Aysén and Magallanes).
Generators supply electricity to end customers using lines and substations owned by transmission and distribution companies. The Company’s Generation Segment operates on a competitive basis, and generators may sell their energy to unregulated customers and to other generation companies through contracts at freely negotiated prices. They may also sell to distribution companies to supply regulated customers through contracts governed by bidding processes defined by the authorities.
Transmission companies own lines and substations with a voltage higher than 23 kV that run from generators’ production points to consumption or distribution centers, charging a regulated toll for the use of their facilities. 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 on a non-discriminatory basis.
Distribution companies supply electricity to end customers using electrical infrastructure below 23 kV. The Company’s Distribution and Networks Segment is also a natural monopoly subject to special industry regulations, including antitrust legislation. The distribution network is open access and distribution tariffs are regulated. Distribution companies must supply electricity to regulated customers within their concession area at regulated prices. Pursuant to Law No. 21,194 (“Distribution Tariffs Law”), distribution companies may not enter into new electricity supply contracts with unregulated customers.
Hydroelectric generation requires a concession granted by the authorities to operate for an indefinite period; however, other types of electricity generation technologies do not require concessions. Chile’s Ministry of Energy grants distribution concessions for indefinite periods and the right to use public areas for the construction of distribution lines. Distribution companies must supply electricity to all customers requesting service within their concession area. A concession may be declared forfeited if service quality does not meet the specific minimum standards established by the regulator.
Customers are classified according to their demand as regulated or unregulated. Regulated customers are those with connected capacity of up to 5,000 kW. Unregulated customers are those with connected capacity of more than 5,000 kW. Customers with connected capacity between 300 kW and 5,000 kW may choose to be regulated or unregulated, subject to the respective pricing regime, but must remain in the selected category for at least four years.
Limits on integration and concentration
Antitrust legislation set forth in Decree Law (DFL, in its Spanish acronym) 211 (as amended in 2016 by Law No. 20,945) and the rules applicable to the electricity industry set forth in DFL 4 (“Electricity Law”) and Law No. 20,018 (General Electricity Services Law) have established criteria to prevent economic concentration and abusive market practices in Chile. Companies may participate in different market segments (generation, distribution and transmission) to the extent that they are duly separated, both from an accounting and corporate standpoint. Companies must also comply with the conditions established in Resolution No. 667/2002 and the Distribution Tariffs Law, which are discussed below.
The transmission sector is subject to the most significant restrictions, mainly due to its open access requirements. The Electricity Law establishes that companies that own the National Transmission System (STN, in its Spanish acronym) may not carry out activities in the Company’s Generation or Distribution segments. STN owners must be limited liability corporations. Individual holdings in the STN by companies that operate in another segment of electricity customers or unregulated customers may not exceed, directly or indirectly, 8% of the total investment value of the STN. In addition, the aggregate participation of all such agents in the STN may not exceed 40% of the total investment value.
According to the Electricity Law, there are no market concentration restrictions for Generation and Distribution activities. However, Chilean antitrust authorities have imposed specific measures to increase transparency related to the Company and its subsidiaries through Resolution No. 667/2002 issued by the Competition Tribunal.
Resolution No. 667/2002 provides that Enel Chile must keep its generation and distribution segments separate and manage them as independent business units. Enel Chile, Enel Generación and Enel Distribución are registered with the CMF and must remain subject to its regulatory authority and comply with the regulations applicable to listed corporations, even if any of these companies loses such designation. Members of the Boards of Directors of Enel Chile and its subsidiaries must be elected from different and independent groups, and the external auditors of the companies must be different for local statutory purposes.
Generation companies may sell to distribution companies, unregulated end customers or other generation companies through contracts. Generation companies meet their contracted sales requirements with dispatched electricity, either 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 National Energy Coordinator, which is based on the lowest production cost of the last kWh dispatched.
Customers subject to the unregulated pricing regime may negotiate their electricity supply with any supplier; however, they must pay a regulated toll to use the transmission and distribution network. Regulated customers with residential generation units may sell their surplus to their distribution company under certain conditions (net billing regulation). Since November 2018, Law No. 21,118 allows regulated customers with installed residential generation capacity of up to 300 kW to sell their surplus, both on an aggregated and individual basis.
Water rights
Companies in Chile must pay an annual fee for unused water rights. License fees already paid can be recovered through monthly tax credits, as from the project start date associated with the water rights. The maximum license fees that can be recovered are those paid during the eight years prior to the start date.
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5.2. Regulatory framework
Since its inception, private sector companies have developed the Chilean electricity industry; however, a nationalization process was carried out by the government between 1970 and 1973. During the 1980s, the Electricity Law reorganized the sector, allowing renewed private sector participation. Currently, the industry is governed by the General Electricity Services Law, contained in DFL No. 4/20.018 of 2006 of the Ministry of Economy, Development and Reconstruction, and its subsequent amendments.
Non-Conventional Renewable Energy (ERNC, in its Spanish acronym) has been promoted in Chile since 2008. ERNC refers to wind, solar, geothermal, biomass, ocean (tidal movement, waves, currents and ocean thermal gradient) and small hydroelectric plants with a capacity below 20 MW. Law No. 20,698 (2013) established a mandatory 20% share of ERNC sources as a percentage of total contracted electricity sales for 2025, but it was extended for contracts signed between 2007 and 2013, which have a 10% target for 2024.
5.2.1.Main regulatory authorities
Responsible for setting policy
The Ministry of Energy is the leading regulatory authority in the Chilean energy industry. It enacts and coordinates plans, regulations, policies and standards for the proper functioning of the sector and the development of the industry in Chile.
Responsible for regulation and supervisory body
The National Energy Commission (CNE, in its Spanish acronym) is the entity responsible for approving annual transmission expansion plans, preparing technical regulations, managing the indicative plan for the construction of new electricity generation facilities and proposing regulated tariffs to the Ministry of Energy for approval. The Superintendence of Electricity and Fuels inspects and oversees compliance with the laws, regulations, rules and technical standards applicable to electricity generation, transmission and distribution, as well as liquid fuels and gas, and reports to the Ministry of Energy.
System operator
The National Electric Coordinator (CEN, in its Spanish acronym) is a centralized dispatch center that coordinates the operations of the SEN with an approach that preserves service security in the power system, ensures the most economical operation for the set of facilities in the electric system, and enables open access to all transmission systems, while monitoring service quality of generation and transmission companies. The CEN calculates market balances, which include both energy injections and withdrawals, determines transfers between generation companies and calculates the hourly marginal cost, the price at which energy transfers are carried out in the spot market. However, the CEN does not calculate generation capacity charges. The CNE calculates such prices.
The CEN schedules the energy production of each generation company considering its marginal costs, the maximum capacity that a generator can supply to the system at certain peak hours, statistical information, accounting for maintenance downtime and drought conditions for hydroelectric plants.
5.2.2.Remuneration and tariffs
Remuneration of generators
To reduce operating costs, the CEN applies an efficiency criterion under which, generally, the lowest-cost available producer is required to meet demand at any 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 hourly marginal cost is the price at which generators trade energy in the spot market, using both their injections (sales) and withdrawals (purchases) to balance their contracted customers’ sales with their production determined by the CEN.
Transmission tariffs
Remuneration of existing national and zonal transmission facilities is determined through a tariff-setting process carried out every four years, regulated by Law No. 20,936. This process determines the annual transmission value, which considers efficient operation and maintenance costs and an annual valuation of investments based on a discount rate determined by the authorities every four years (minimum 7% after taxes) and the useful life of the facilities.
Current regulations establish that transmission remuneration is the sum of tariff revenues and revenues from use charges received by the transmission system, defined as $/kWh by the CNE. Revenues are calculated semi-annually. The tariff-setting process for the 2020-2023 period concluded in February 2023 and had retroactive effects as from January 1, 2020. With respect to the tariff-setting process for the 2024-2027 period, the CNE published the final technical report for the classification of transmission facilities and is currently developing the valuation studies and defining the use charges associated with the different categories of transmission systems. The new tariffs are expected to enter into force once those studies are completed and the respective tariff decrees are processed, in accordance with the timelines established in current regulations.
Distribution tariffs
The Distribution Tariffs Law established new limits on investment returns 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, a public service charge and the value added of electricity distribution (VAD, in its Spanish acronym), allowing distribution companies to recover their investment and operating costs, including a legally mandatory return on investment. The transmission charge reflects the price paid for the transmission and transformation of electricity. The law also prohibits distribution companies from operating in other sectors or industries as from 2021.
The VAD is based on the so-called “efficient model company” within a typical distribution area (ATD, in its Spanish acronym). The CNE determines the VAD for each ATD. Using the resulting VAD, preliminary tariffs are tested to ensure an aggregate industry rate of return between 6% and 8%. However, the Distribution Tariffs 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 actual 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 a higher return for distribution companies that are more efficient than the model company.
Electricity regulations establish tariff equalization mechanisms for electricity services. Law No. 20,928 establishes that the maximum tariff that distribution companies may charge residential customers must not exceed the national average tariff by more than 10%. Differences arising from the application of this mechanism are progressively absorbed by the remaining customers subject to regulated prices, below the above-mentioned average, except for those residential users whose average monthly energy consumption in the previous calendar year is less than or equal to 200 kWh.
The process to set the distribution value added for 2020-2024 concluded in July 2024 and is effective retroactively, as from November 4, 2020. The process to set the distribution value added for 2024-2028 is currently ongoing, with the tariffs set for 2020-2024 remaining in force.
5.2.3.Environmental regulations
Chile has numerous laws, regulations, decrees and municipal ordinances that address environmental considerations. These include regulations related to waste disposal (including the discharge of liquid industrial waste), 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 various regulations, including the Environmental Impact Assessment System Regulation issued in 1997 and amended in 2001. This law establishes a general regulatory framework for the right to live in an environment free from pollution, environmental protection, preservation of nature and conservation of environmental heritage. This law requires companies to conduct an environmental impact study and submit a declaration for future generation or transmission projects.
On September 10, 2014, Law No. 20,780 was enacted, which included fees for the emission of Particulate Matter (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 plant is located, resulting in 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 entered into force in 2018, and the amount due was calculated based on the previous year’s emissions. All thermal power plants of Enel Generación Chile have established methodologies to measure emissions and pay the related taxes in line with the requirements of the Chilean Superintendence of the Environment.
On June 13, 2022, Law No. 21,455 (Framework Law on Climate Change) was enacted. This law establishes that Chile will be carbon neutral and climate resilient by 2050, which could be brought forward if circumstances allow. To address climate change, the law establishes specific actions for 17 executive departments, as well as powers and obligations at the regional and local levels. It also establishes the Long-Term Climate Strategy, a roadmap detailing how the country will meet its commitments through specific actions over a 30-year period, and requires the preparation of sectoral mitigation and adaptation plans with specific measures and actions to meet these objectives. On December 13, 2024, the Ministry of Energy published the Energy Climate Change Mitigation and Adaptation Plan, which contains 15 key actions, with 13 specific measures set out under 3 main pillars (mitigation, adaptation, and integration and means of implementation).
5.2.4.Regulatory matters
2019 – 2025 Laws
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 CNE’s Exempt Resolution No. 72/2020 and its amendments. It should be noted that the fund limit was reached in January 2022.
On August 2, 2022, the Ministry of Energy published Law No. 21,472 (the “CPM Law”), which creates a tariff stabilization fund and establishes a new mechanism for transitory stabilization of electricity prices for customers subject to price regulation. Through this law, a Transitory Customer Protection Mechanism (“CPM”) was established to stabilize energy prices for the National Electric System and medium-sized systems complementary to those established in Law No. 21,185, for customers subject to price regulation provided by concessionaire companies of public distribution services regulated by the General Electricity Services Law. The objective of the CPM is to pay the differences that arise between the billing of distribution companies to end customers for the energy and power component, and the amount payable for the electric supply to generation companies. The resources accounted for in the operation of the CPM shall not exceed US$1.8 billion, and its validity shall extend until the balances originated by the application of this law are extinguished. As of 2023, the CNE will make a semiannually forecast of the total payment of the remaining final balance for a date no later than December 31, 2032. Exempt Resolution No. 86 was published on March 14, 2023, and Exempt Resolution No. 334 (as amended by Exempt Resolution No. 379 of August 8, 2024) was published on August 9, 2023. The Exempt Resolutions established, among other matters, certain provisions, procedures, deadlines and conditions for the proper implementation of the CPM Law.
Because of the application of the price stabilization mechanism established under the CPM Law and the Exempt Resolutions, the General Treasury, as delegated by the Ministry of Finance and on behalf of the Tariff Stabilization Fund (“FET” in its Spanish acronym), will issue transferable credit titles payable to the order (the “Payment Documents”), which will allow their holder to collect the restitution of certain amounts owed as a result of the application of the CPM Law and such energy price stabilization mechanism, and the interest recognized in the aforementioned Payment Documents, on the dates established.
On April 30, 2024, Law No. 21,667 was published, which establishes, among other aspects, four significant items:
Furthermore, customers recording monthly consumption exceeding 350 kWh will pay the actual price of energy and capacity starting from the publication of the average node price decree for the first half of 2024, plus an additional charge (CPM charge) that will allow the extinguishment of the accumulated debt from the PEC and CPM stabilization mechanisms. Customers recording monthly consumption of 350 kWh or less will pay the actual price of energy and capacity starting from the publication of the decree for the second half of 2024, and from the decree for the first half of 2025, the CPM charge will be added.
F-56
As of January 01,
Cash balances
213
Bank balances
381,655
223,580
156,248
Time deposits
80,056
364,825
Other fixed-income instruments
161,115
120,936
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 on cash and cash equivalents.
Other payments from operating activities
103,917
247,383
512,221
357,864
137,191
129,815
Euro
149
For further detail of the Statement of Cash Flows see below:
VAT tax debit
(99,438)
(77,993)
(98,620)
Insurance premiums
(42,418)
(33,559)
(30,813)
Tax on emissions
(11,362)
(15,578)
(24,655)
Other
(14,292)
(13,338)
(11,659)
Cash received from the sale of Arcadia Generación Solar S.A.
621,355
Cash and cash equivalents outflow related to Arcadia Generación Solar S.A. exiting the Group
(2,138)
As of December 31, 2023, the cash amount represents the proceeds from the sale of its 50% interest in the joint venture Sociedad de Inversiones K Cuatro SpA, completed in December 2022 by the Company’s subsidiary Enel X Chile. On June 30, 2023, Enel X Chile received a payment of ThUS$17,647, representing 50% of the total sale consideration. The remaining 50%, amounting to ThUS$17,669, was received on December 22, 2023.
F-58
Short-term loans
Long-term loans
Lease liabilities
Assets held to cover liabilities arising from financing activities
Opening balance as of January 1, 2025
236,199
3,401,910
295,652
(8,614)
3,925,147
73,160
263,160
Used
(281,733)
(190,000)
(508,268)
(174,159)
(177)
Total cash flows from financing activities
(455,892)
(36,712)
(419,444)
Movements that do not represent cash flows
Movements in fair value
62,092
5,826
14,231
82,149
Foreign currency translation differences
3,517
(1,706)
46,594
(24,676)
23,729
Financial costs (1)
173,238
5,669
24,871
(347)
203,431
New leases
88,035
Other Movements
469,764
(379,840)
(8,243)
(72,738)
8,943
488,918
3,031,859
410,197
(18,984)
3,911,990
Detail by category
Payables due to related parties (see Note 10.1. b)
167,101
1,028,632
Interest-bearing loans (See Note 20.1)
259,461
2,161,366
2,420,827
Cash flow hedges (See Note 23.2.a)
62,356
8,962
52,334
Lease liabilities (See Note 21)
Assets held to hedge liabilities arising from financing activities
Opening balance as of January 1, 2024
827,492
3,348,867
305,617
(62,960)
4,419,016
1,632,383
65,282
1,697,665
(1,052,502)
(1,137,625)
(2,209,083)
(214,929)
(2,794)
(1,267,431)
494,758
(21,750)
(729,141)
6,590
(5,036)
(25)
138
1,667
3,756
2,674
(23,809)
(8,277)
(25,656)
213,830
7,746
11,990
(2,797)
230,769
43,905
451,962
(447,099)
(20,276)
(15,413)
Closing balance as of December 31, 2024
167,097
1,186,611
61,447
2,377,162
2,438,609
7,655
5,234
4,275
Opening balance as of January 1, 2023
566,603
3,891,875
275,379
(66,355)
4,667,502
400,014
810,443
13,082
1,223,539
(1,010,370)
(595,413)
(1,627,712)
(218,901)
(11,091)
(829,257)
215,030
(33,020)
(634,165)
Sales of subsidiaries
46,378
(44,273)
(12,762)
(10,657)
11,028
97,377
4,221
5,493
118,119
217,065
5,631
11,535
(2,418)
231,813
56,201
815,675
(816,773)
(8,699)
(9,797)
Closing balance as of December 31, 2023
Payables due to related parties (See Note 10.1. b)
167,112
1,346,872
618,183
2,163,402
2,781,585
42,197
5,705
(15,058)
(1) Relates to accrual of interest.
F-59
The detail of other financial assets as of December 31, 2025, December 31, 2024, and January 1, 2024, is as follows:
Current
Non-current
12-31-2024
01-01-2024
Financial assets at fair value through profit or loss
2,328
Financial assets at fair value through other comprehensive income
128
146
2,335
2,652
Financial assets measured at amortized cost
648
10,846
10,891
2,714
Hedging derivatives
8,614
66,137
19,021
10,576
Non-hedging derivatives
The detail of other non-financial assets as of December 31, 2025, December 31, 2024, and January 1, 2024 is as follows:
Value-added tax fiscal credit and other taxes
101,937
77,666
47,545
3,123
120,348
238,868
Prepaid expenses
62,901
71,499
63,491
Water right credits
18,285
16,440
Spare-parts with a consumption schedule of more than 12 months
8,311
7,468
9,576
Guarantee deposits
2,420
1,779
4,507
7,717
4,543
3,540
632
1,246
2,401
The detail of other non-financial liabilities as of December 31, 2025, December 31, 2024, and January 1, 2024 is as follows:
32,269
32,026
22,416
Deferred revenue from energy sales (1)
13,983
17,092
15,428
15,103
36,593
59,613
Deferred revenue from transfer of networks
5,822
7,105
2,226
Deferred revenue from retail businesses
6,850
5,468
Deferred revenue from other services
7,028
279
1,681
Deferred revenue from connections
476
Deferred revenue from lighting services
3,827
125
548
Reimbursable financial contributions
217
168
137
577
774
1,063
Trade and Other Receivables, Gross
Trade and other receivables, gross
1,516,309
1,591,329
1,740,630
1,109,665
1,166,226
1,045,158
Trade receivables, gross
1,347,672
1,507,914
1,627,724
994,594
1,068,931
883,872
Accounts receivable due from finance leases, gross
21,604
18,462
23,663
110,250
92,446
157,293
Other receivables, gross
147,033
64,953
89,243
4,821
4,849
3,993
Trade and Other Receivables, Net
Trade and other receivables, net
Trade receivables, net
1,232,090
1,424,706
1,552,619
992,830
1,067,198
870,102
Accounts receivable due from finance leases, net
21,075
18,297
23,503
107,733
91,323
156,184
Other receivables, net (1)
133,076
52,255
76,211
Receivables from employees
16,323
14,962
15,845
3,107
2,430
Advances to suppliers and creditors
17,154
16,590
44,858
519
Insurance receivables (i)
70,986
2,001
Other receivables for - deposits in transit and other
21,698
14,755
11,017
6,915
3,947
4,491
1,714
574
975
(i) This corresponds to accounts receivable from insurance companies which, given the progress of the settlement process, are considered virtually certain. As of December 31, 2025, it includes ThUS$ 55,553 from the Generation segment, mainly related to claims arising from prior-year events at the Atacama, Abanico, Quintero and Guanchoi power plants, and ThUS$ 15,433 from the Distribution segment, related to non-recurring events that resulted in service interruptions to end users. (See Note 28).
a.1) Variance in gross trade accounts receivable:
a.1.i) As of December 31, 2025, current trade accounts receivable decreased by ThUS$160,242 in comparison to as of December 2024, explained mainly by the sale of accounts receivable in the amount ThUS$235,181 (see section a.2. of this sales detail note). The above was partially offset by: (i) an increase of ThUS$54,652 in accounts receivable from the application of the regulated customers rate stabilization mechanism, of which ThUS$176,495 correspond to transfers from the non‑current portion, an amount that is reduced by collections for the period amounting to ThUS$ 121,842; and (ii) an increase of ThUS$47,448 for U.S. dollar translation of accounts receivable from the regulated customers of Enel Distribución Chile denominated in Chilean pesos.
a.1.ii) Conversely, non‑current trade accounts receivable decreased by ThUS$74,337 compared to 2024 year‑end. This is mainly explained by: (i) a decrease of ThUS$176,495 in accounts receivable arising from the application of regulated customer rate stabilization mechanisms due to transfers to the short‑term, and (ii) a decrease of ThUS$7,339 related to lower agreements with regulated customers. These effects were partially offset by: (i) an increase of ThUS$101,971 resulting from the U.S. dollar translation of trade receivables denominated in Chilean pesos from Enel Distribución Chile, and (ii) an increase of ThUS$18,875 due to the application of the laws that establish rate stabilization mechanisms for regulated customers.
The rate stabilization mechanisms were established by Laws No. 21,185, 21,472 and 21,667 (for further information, see Note 5.2.4 subparagraphs i, ii and iii).
As an effect of the application of the aforementioned laws, and after eliminating transactions between related companies, the accounting effects recorded by the Group are summarized as follows:
The aforementioned trade and non-trade concepts, while included in the model to determine impairment losses (see Note 4.g.3), have no significant impact as of December 31, 2025, December 31, 2024, and January 1,2024, 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 trade receivables
F-62
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.
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 August 14, 2023, Enel Generación Chile S.A. and Enel Green Power Chile S.A. entered into an agreement with the IDB Invest as the buyer. Under this agreement, they agreed to sell, assign, and transfer to the buyer certain Treasury Payment Documents related to Law No. 21,472, for an approximate amount of up to US$606 million for Enel Generación Chile S.A. and US$34.8 million for Enel Green Power Chile S.A.
Detail of sales and disposals:
On May 12, 2023, Enel Generación Chile and Enel Green Power Chile sold and assigned Balances to Chile Electricity PEC SpA with a nominal value of approximately US$48 million and US$3 million, respectively.
On August 30, 2023, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Payment Documents to IDB Invest with a nominal value of approximately US$294.8 million and US$17.2 million, respectively.
On October 30, 2023, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Payment Documents to IDB Invest with a nominal value of approximately US$ 15.9 million and US$1.03 million, respectively.
On December 28, 2023, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Payment Documents to IDB Invest with a nominal value of approximately US$14.7 million and US$0.95 million, respectively.
On January 17, 2024, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Notes to IDB Invest with a nominal value of approximately US$14.2 million and US$0.9 million, respectively.
On May 31, 2024, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Notes to IDB Invest with a nominal value of approximately US$50.8 million and US$3.6 million, respectively.
F-63
On August 9, 2024, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Notes to IDB Invest with a nominal value of approximately US$12.7 million and US$1.0 million, respectively.
On October 24, 2024, Enel Generación Chile and Enel Green Power Chile sold and assigned Treasury Payment Documents to IDB Invest with a nominal value of approximately US$592.5 million and US$21.4 million, respectively.
On April 3, 2025, Enel Generación Chile sold and assigned Treasury Payment Documents to IDB Invest with a nominal value of approximately US$ 235.2 million.
As a result of the sales and transfers of balances performed during the year ended December 31, 2025 and 2024, Enel Generación Chile and Enel Green Power Chile did not recognize financial costs (ThUS$8,585 and ThUS$532 as of December 31, 2023, respectively).
In addition, during the year 2025, Enel Generación Chile and Enel Green Power Chile conducted sales of short‑term receivables, other than those originating from the application of Laws No. 21,185, No. 21,472 and No. 21,667, for a nominal value of ThUS$1,608,266 and ThUS$68,978, respectively (ThUS$1,588,768 and ThUS$54,681, respectively, as of December 31, 2024, and ThUS$1,524,061 and ThUS$48,122, respectively, as of December 31, 2023), recognizing a financial cost of ThUS$7,365 and ThUS$261 (ThUS$9,630 and ThUS$496, respectively, as of December 31, 2024, and ThUS$14,001 and ThUS$479, respectively, as of December 31, 2023).
The financial cost implications as previously outlined for the Distribution and Generation segments, for the period ended December 31, 2025 total ThUS$20,544 (ThUS$20,973 and ThUS$36,280 as of December 31, 2024 and 2023, respectively). (See Note 34 (6)).
a.3) Other
There are no restrictions on the disposal of these types of receivables in a significant amount.
The Group has one customer in the Generation segment, Compañía General de Electricidad S.A., whose sales represent 10% or more of its revenue for the periods ended December 31, 2025, 2024 and 2023.
For amounts, terms and conditions related to receivables due from related parties, refer to Note 10.1.
As of December 31, 2025, December 31, 2024, and January 1, 2024 future collections on financial lease receivables are the following:
Gross
Interest
Present value
Less than one year
25,159
3,555
21,476
3,014
29,520
5,857
From one to two years
16,694
1,704
14,990
14,972
1,446
13,526
17,291
2,013
15,278
From two to three years
14,428
1,321
13,107
12,804
1,076
11,728
14,874
13,428
From three to four years
12,083
986
11,097
10,575
792
9,783
12,697
945
11,752
From four to five years
9,682
729
8,953
9,030
550
8,480
10,242
313
9,929
More than five years
69,580
7,477
62,103
55,475
6,546
48,929
124,750
17,844
106,906
147,626
15,772
131,854
124,332
13,424
110,908
209,374
28,418
180,956
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.
F-64
In addition, as of December 31, 2025, financial income from lease debtors reached ThUS$2,677 (ThUS$2,218 and ThUS$3,703 as of December 31, 2024 and 2023, respectively).
Trade receivables due and unpaid but for which no impairment losses have been recorded
Less than three months
55,509
46,100
45,108
Between three and six months
14,046
13,473
16,143
Between six and twelve months
14,556
7,086
20,740
More than twelve months
68,480
86,747
202,567
152,591
153,406
284,558
Current and
Trade receivables due and unpaid, with impairment losses
Balance as of January 1, 2024
103,176
Increases (decreases) for the period
19,529
Amounts written off
(10,998)
Increases (decreases) in foreign currency translation differences
(12,780)
Balance as of December 31, 2024
98,927
Increases (decreases) for the period (1)
38,658
(15,367)
Increases (decreases) in foreign currency translation difference
12,131
Balance as of December 31, 2025
134,349
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 segment, the process normally considers at least one year of proceedings. In the Company’s Distribution segment, 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 4.g.3 and 22.5).
F-65
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, which may be short-term and/or long-term, and are prepayable. For short-term transactions, the interest rate applied is variable and reflects market conditions. To reflect these market conditions, short-term interest rates are periodically reviewed through an update procedure approved by the Boards of Directors of the respective companies. Long-term operations can be for 1 year with a variable interest rate or 3 years with a fixed rate, with rates quoted in the market at the time of allocation to reflect market conditions.
The balances of receivables and payable as of December 31, 2025, December 31, 2024, and January 1, 2024, are as follows:
Relationship
Transaction Description
Foreign
Empresa Distribuidora Sur S.A.
Argentina
Common Immediate Parent
Other Services
276
250
282
IT Services
1,929
1,881
1,904
Enel Generacion El Chocón S.A.
Engineering Services
Enel Brasil S.A.
Brazil
572
1,804
2,227
2,120
94.271.000-3
CLP
2,697
909
875
404
Administrative Services
5,928
2,971
1,293
Enel Distribución Sao Paulo S.A.
Enel X Way Chile SpA
Associated
Technical Services
1,584
595
Advance for Gas Purchase
26,675
19,742
4,547
Enel Colombia S.A. ESP.
Colombia
2,271
2,360
1,651
Endesa España
Spain
EUR
Endesa Generación
Sale of Materials
1,916
Enel North America Inc
United States
248
234
256
Enel Global Services S.r.l.
Italy
Enel Global Trading S.p.A.
971
527
561
Commodity derivatives
5,051
2,128
27,063
Enel Green Power Spa
2,062
697
702
2,040
2,063
2,085
950
767
Enel Grids S.r.L
685
601
640
Enel Innovation Hubs Srl
127
Enel Italia SrL.
1,783
1,536
1,640
Enel Produzione
337
298
317
Parent
1,377
1,171
1,163
Enel X S.R.L.
Enel Green Power Morocco
Morocco
946
701
662
Chinango S.A.C.
Peru
Enel Distribución Perú S.A.
Enel Generación Perú S.A.
3,760
Enel Generación Piura S.A.
817
652
EGP Magdalena Solar SA de CV
Mexico
368
Energetica Monzon S.A.C.
916
Enel Argentina S.A.
Enel Trading Argentina S.R.L.
Enel X Brasil Gerenciamento de Energia Ltda
827
426
667
3,995
2,551
Gas Purchase
21,477
17,474
14,945
833
964
196
Coal purchase
594
Enel Green Power España SL
933
1,278
814
Enel Iberia SRL
260
674
Enel Green Power North America Inc
517
515
251
Enel Finance International NV (*)
Netherlands
Loan payable
Cesi S.p.A.
130
Enel X Advisory Services S.r.L.
186
508
2,250
3,077
8,862
240
272
614
Commodity Derivatives
1,358
34,106
1,642
1,467
5,797
733
Enel Green Power Italia
1,065
711
745
7,617
9,032
35,697
13,701
14,176
19,048
3,757
7,136
1,825
8,757
641
9,744
2,133
19,026
3,785
2,541
9,569
Enel Italia S.p.A
698
815
3,211
2,067
2,189
129
2,155
1,490
1,677
104,286
40,341
140,285
3,946
4,625
7,137
3,413
2,495
3,334
746
1,258
4,098
Financial Guarantee Service
2,367
1,362
335
268
496
8,413
Consorzio DAP
13,631
16,677
Gridspertise s.r.l.
1,501
1,854
(*) See items d) and e) below.
The significant transactions with related companies that are not consolidated are as follows:
For the years ended December 31,
Endesa Generación, S.A.U.
Sale of PPE
Enel Colombia S.A.S.
(3,218)
Provision of administration services and others
5,671
7,088
9,949
Gas consumption
(350,813)
(237,183)
(255,778)
Gas Sales
7,292
7,844
(6,153)
(5,783)
(6,360)
(2,584)
(2,399)
(4,904)
(3,274)
(3,899)
(3,582)
(3,217)
(4,147)
(3,540)
(3,870)
(4,721)
Financial expenses
(4,021)
(1,088)
Enel Global Trading SpA.
(19,796)
186,283
97,152
20,370
(1,540)
(1,538)
(1,759)
Enel Finance International NV
(35,605)
(67,172)
(67,361)
Enel Green Power SpA
(11,721)
(12,636)
(15,209)
(4,165)
Gridspertise S.r.L.
Purchase of materials
(1,672)
(385)
(3,415)
The transactions detailed in the preceding table include all transactions that exceed ThUS$2,000, by counterparty and nature of the transactions.
The estimates of undiscounted cash flows for loans payable as of December 31, 2025, December 31, 2024, and January 1, 2024:
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
Total Non-Current
2.93%
7,484
182,799
190,283
185,677
21,198
21,139
410,323
301,934
940,271
Nominal interest rate
2.91%
8,620
186,269
194,889
21,140
712,257
1,130,555
2.89%
9,826
189,625
199,451
194,737
190,131
185,525
21,045
733,055
1,324,493
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, 2025, was composed of the following people:
During the Ordinary Board Meeting on April 28, 2025, Mr. Marcelo Castillo Agurto was appointed Chairman of the Board, and Mrs. Josefa Rodríguez Benavente was designated Secretary of the Board. Subsequently, on November 27, 2025, the Board designated Mrs. Natalia Fernández Sepúlveda as the new Secretary of the Board, a role she assumed effective immediately on that date.
The Directors’ Committee was established during the April 28, 2025 Board Meeting and operates under Law No. 18,046 on Corporations, as well as the Sarbanes-Oxley Act of 2022. The Committee is composed of Mrs. María Teresa Vial Álamos, Mr. Pablo Cruz Olivos, and Mrs. Gina Ocqueteau Tacchini. According to Circular No. 1,956 issued by the CMF, both Mr. Pablo Cruz Olivos and Mrs. Gina Ocqueteau Tacchini are classified as independent directors under Chilean law.
During a session held on April 28, 2025, the Company's Directors' Committee appointed Mrs. María Teresa Vial Álamos as Chair and Ms. Josefa Rodríguez Benavente as Secretary of the Committee. Later, on November 27, 2025, Mrs. Natalia Fernández Sepúlveda was elected to serve as the new Secretary, a role she assumed effective immediately on that date.
There are no outstanding balances receivable and payable between the Company and its Directors and Group Management.
There are no transactions other than remuneration between the Company and its Directors and Group Management.
No guarantees have been given to the 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 S.A.
F-70
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:
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.
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:
F-71
The following table show details of the compensation paid to the members of the Board of Directors of the Company for the years ended December 31, 2025, 2024 and 2023:
December 31, 2025
Taxpayer ID No
Name
Period in position
Enel Chile Board
Board of subsidiaries
Directors' Committee
9.973.492-2
January - December 2025
8.431.507-9
April - December 2025
4.774.797-K
Pablo Cabrera Gaete
January - April 2025
12.627.794-6
10.434.628-6
Isabella Alessio
Valentina De Cesare
TOTAL
147
December 31, 2024
4.975.992-4
Herman Chadwick Piñera
January - April 2024
4.461.192-9
Fernan Gazmuri Plaza
5.545.086-2
Luis Gonzalo Palacios Vasquez
January - December 2024
Maria Teresa Vial Alamos
April - December 2024
Marcelo Castillo Agurto (1)
Monica Girardi
January - September 2024
520
141
December 31, 2023
January - December 2023
311
155
776
F-72
Enel Chile’s key management personnel during 2025 was comprised of the following people:
Key Management Personnel
Gianluca Palumbo (1)
27.101.372-8
Giuseppe Turchiarelli (1)
Administration, Finance and Control Officer
Gaetano Manzulli (2)
Human Resources and Organization Manager
6.973.465-0
Domingo Valdés Prieto (3)
General Counsel and Secretary to the Board
8.664.305-7
Nicolás Lustig Falcón (3)
16.261.687-0
Juan Francisco Díaz Valenzuela
11.625.161-2
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 cash bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.
The LTI plan’s long-term bonus opportunity is based on a percentage of each participants’ base salary. The LTI plan awards vest at the conclusion of each three-year performance period, subject to achievement of threshold levels of performance and the participant’s continued employment, and will be cash-settled in subsequent years.
For expatriate executives, the salary, annual bonus plan, and long-term incentives are subject to recharge agreements, so this cost has been borne by Enel Chile.
Compensation received by key management personnel are as follows:
Remuneration
1,528
1,988
2,924
Short-term benefits for employees
350
394
Other long-term benefits
434
470
1,957
2,816
3,805
No guarantees have been given to key Management personnel.
There are no payment plans granted to the Directors or key Management personnel based on the share price of the Enel Chile common stock.
11. INVENTORIES
The detail of inventories as of December 31, 2025, December 31, 2024, and January 1, 2024 is as follows:
Supplies for Production
13,592
11,901
15,797
Gas
5,128
1,860
2,112
Oil
8,464
10,041
13,685
Supplies for projects and spare parts
44,260
41,663
42,290
Electrical materials
10,269
11,836
8,907
There are no Inventories pledged as Debt Compliance Guarantees.
For the years ended December 31, 2025, 2024 and 2023, raw materials and supplies recognized as fuel costs amount to ThUS$376,602, ThUS$354,616 and ThUS$638,512, respectively. See Note 29.
For the years ended December 31, 2025, 2024 and 2023, no impairment losses have been recognized on inventories.
Tax Receivables
Advance income tax payments
19,255
12,446
15,413
Credit for absorbed tax profits
67,461
76,640
Tax credit for training expenses
737
599
Income tax
The detail of the Group’s investees accounted for using the equity method and the movements for the years ended December 31, 2025, December 31, 2024, and January 1, 2024:
Share of
Balance as of
Profit
currency
comprehensive
increase
Negative
Taxpayer ID
01-01-2025
Additions
(loss)
declared
translation
income
(decrease)
equity
No.
Associates and Joint Ventures
Percentage
Associate
32,183
14,197
(1,001)
45,443
76.014.570-K
Argentine Peso
0.0793%
523
(153)
514
Energías Marina SpA
Chilean Peso
(91)
77.374.847-0
HIF H2 SpA (1)
Joint venture
315
845
(679)
481
(146)
(487)
1-1-2024
22,424
9,724
323
(43)
(85)
328
(350)
(20)
(370)
370
Enel X Way Chile S.p.A. (2)
6,092
(473)
(5,619)
(5,291)
32,450
Financial information as of December 31, 2025, December 31, 2024, and January 1, 2024, of the main companies in which the Group exercises significant influence is detailed below:
Direct / Indirect
Current Assets
Non-current Assets
Current Liabilities
Non-current Liabilities
Profit (Loss)
Total comprehensive Income
Investments with Significant Influence
Ownership %
197,983
1,753,973
331,173
1,484,454
1,211,588
42,592
175,289
1,857,881
299,801
1,636,819
1,108,238
29,171
10,250
39,421
As of January 01, 2024
165,109
2,025,663
286,937
1,836,562
1,240,782
23,889
2,059
25,948
Enel X Way Chile S.p.A.
17,063
3,869
8,088
412
10,813
(2,675)
(2,642)
None of the Company’s associates have issued price quotations.
The detail of the Group’s statements of financial position and statements of income of joint ventures as of December 31, 2025, December 31, 2024, and January 1, 2024, are as follows:
HIF H2 SpA
50.0%
Total current assets
Total non-current assets
1,107
Total current liabilities
730
Revenue from ordinary activities
1,691
Other fixed operating expenses
(699)
(17)
Comprehensive income (Loss)
There are no significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.
The balances of this caption as of December 31, 2025, December 31, 2024, and January 1, 2024, are presented below:
Classes of Intangible Assets, Gross
Intangible Assets, Gross
522,036
478,196
406,992
Development Costs
9,907
10,596
Easements and water rights
20,332
18,638
15,362
83,211
83,400
82,356
Patents, registered trademarks and other rights
4,462
2,172
1,932
Software licenses
258,858
200,930
183,000
Intangible assets in development
133,499
149,996
113,067
Other Identifiable Intangible Assets
11,069
11,084
10,939
Contract costs
1,380
336
Classes of Intangible Assets, Amortization and Impairment
Accumulated Amortization and Impairment, Total
(229,246)
(183,805)
(184,663)
(2,660)
(907)
(5,820)
(5,788)
(5,871)
(25,586)
(23,074)
(20,559)
(2,287)
(1,214)
(1,178)
(189,722)
(149,418)
(153,746)
(2,868)
(2,876)
(3,238)
(303)
(528)
Classes of Intangible Assets, Net
Intangible Assets, Net
7,247
9,689
14,512
12,850
57,625
60,326
61,797
2,175
958
69,136
51,512
29,254
8,201
8,208
7,701
852
265
As of December 31, 2025, December 31, 2024, and January 1, 2024, the detail and movements of intangible assets other than goodwill were as follows:
Patents, Registered Trademarks and Other Rights
ComputerSoftware
Contract Costs
Intangible Assets,Net
Movements in Intangible Assets
Movements in identifiable intangible assets
Increases other than from business combinations
27,660
Increase (decrease) from foreign currency translation differences
301
3,925
3,442
7,723
Amortization (1)
(2,598)
(2,469)
(783)
(29,207)
(35,576)
Increases (decreases) from transfers and other Movements
(709)
1,344
2,505
1,882
42,845
(47,867)
Increases (decreases) from transfers
Argentina Hyperinflation Effect
Increase (decrease)
865
(2,737)
(1,409)
Total Movements in identifiable intangible assets
(2,442)
1,662
(2,701)
1,217
17,624
(16,497)
(457)
(1,601)
Computer Software
9,492
113,066
8,221
95,509
103,831
(553)
(107)
(4,918)
(9,992)
259
(65)
(15,305)
(908)
(187)
(19,465)
(491)
(23,537)
38,425
(40,322)
1,143
10,617
3,911
806
(256)
(5)
(8,265)
258
7,066
3,358
(1,471)
204
22,258
36,930
507
587
72,062
As of December 31, 2025, the additions of intangible assets under development mainly come from the Distribution segment, corresponding to investments in software amounting to ThUS$15,507, and from the Generation segment, corresponding to investments in software and the internal development of Renewable Projects amounting to ThUS$12,153. As of December 31, 2024, the additions of intangible assets under development mainly come from EGP Chile for ThUS$81,737, corresponding to the internal development of Renewable Projects (Greenfield projects).
No impairment losses have been recognized as of December 31, 2025, December 31, 2024, and January 1, 2024. 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, 2025 (see Note 4.e).
F-80
The following table sets forth goodwill by cash-generating unit or group of cash-generating units and changes as of December 31, 2025, December 31, 2024, and January 1, 2024:
Cash Generating Unit
Opening Balance01-01-2024
Foreign Currency Translation
Closing Balance12-31-2024
Closing Balance 12-31-2025
2,554
(306)
2,248
2,485
103,136
(12,352)
90,784
9,554
100,338
Generación Chile
862,645
(103,314)
759,331
Enel Green Power Chile
29,030
Geotérmica del Norte
Parque Eólico Talinay Oriente
10,900
(115,972)
9,791
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, 2025, December 31, 2024, and January 1, 2024 (see Note 4.e).
The origin of the goodwill is detailed below:
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.
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 Chilectra S.A. (currently Enel Distribución Chile S.A.), reaching 99.09% ownership.
On May 11, 1999, Enersis S.A. (currently Enel Américas S.A.) acquired an additional 35% ownership interest in Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) achieving 60% ownership of the generation company, through a public tender offer in the Santiago Stock Exchange and the purchase of shares in the United States (30% and 5%, respectively).
On October 1, 2019, GasAtacama Chile S.A. merged with Enel Generación Chile S.A., with the latter being the legal surviving company. The resulting goodwill was recognized in Enel Generación Chile S.A.
3.1.GasAtacama Chile S.A. (formerly Inversiones GasAtacama Holding Limitada)
On April 22, 2014, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired 50% ownership interest in GasAtacama Chile S.A. (formerly Inversiones GasAtacama Holding Limitada), previously held by Southern Cross Latin América Private Equity Fund III L.P.
3.2.GasAtacama Chile S.A. (formerly Empresa Eléctrica Pangue S.A.)
On July 12, 2002, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired 2.51% of the shares of Empresa Eléctrica Pangue S.A., upon exercise of the sale option by the minority shareholder International Finance Corporation (IFC).
On May 2, 2012, Empresa Eléctrica Pangue S.A. merged with Compañía Eléctrica San Isidro S.A., with the latter being the legal surviving company.
3.3. GasAtacama Chile S.A. (formerly Compañía Eléctrica San Isidro S.A.)
On August 11, 2005, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired an ownership interest in Inversiones Lo Venecia Ltda., whose sole asset was a 25% interest in San Isidro S.A.
On September 1, 2013, Compañía Eléctrica San Isidro S.A. merged with Endesa Eco S.A., with the latter being the legal surviving company.
On November 1, 2013, Endesa Eco S.A. merged with Compañía Eléctrica Tarapacá S.A. (“Celta”), 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.
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, Panguipulli 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.
F-82
The following table sets forth the property, plant and equipment as of December 31, 2025, December 31, 2024, and January 1, 2024:
Classes of Property, Plant and Equipment, Gross
Property, Plant and Equipment, Gross
13,550,600
12,970,260
13,490,829
Construction in progress
920,872
2,287,718
2,818,207
Land
64,146
75,630
79,841
1,686,758
1,008,015
935,434
Generation plant and equipment
8,917,115
8,065,315
8,009,282
Network infrastructure
1,615,594
1,353,318
1,462,818
168,104
156,176
161,218
Other property, plant, and equipment
178,011
24,088
24,029
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment
Total Accumulated Depreciation and Impairment in Property, Plant and Equipment
(5,787,164)
(5,390,567)
(5,680,969)
(227,462)
(223,852)
(217,616)
Generation Plant and equipment
(4,745,188)
(4,500,446)
(4,752,506)
(677,403)
(546,371)
(585,676)
(105,556)
(95,994)
(101,486)
(31,555)
(23,904)
(23,685)
Classes of Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
1,459,296
784,163
717,818
4,171,927
3,564,869
3,256,776
938,191
806,947
877,142
62,548
60,182
59,732
146,456
184
344
The composition and movements of the property, plant and equipment accounts during the years ended December 31, 2025 and 2024 are as follows:
Generation Plant and Equipment
Fixtures and Fittings
Other property, plant and equipment
Movements in 2025
Balance as of January 1, 2025
441,569
3,089
444,728
Increases (decreases) from foreign currency translation differences
23,054
187
929
351
75,936
2,487
102,944
Depreciation (1)
(39,557)
(217,481)
(43,707)
(9,707)
(7,278)
(317,730)
Impairment losses recognized in income for the year (2)
Increases (decreases) from transfers and other movements
(1,788,939)
(3,885)
686,919
856,308
96,183
10,053
143,361
Increases (decreases) from transfers from construction in progress
Disposals and removals from service
(4,203)
(63)
(6,331)
(388)
(10,994)
Removals
Other increases (decreases)
(7,790)
(3,648)
26,810
(26,479)
131
(893)
10,189
(1,680)
Argentine hyperinflationary economy
718
620
435
1,933
Total movements
(1,366,846)
(11,484)
675,133
607,058
131,244
2,366
146,272
183,743
Movements in 2024
553,872
11,733
3,531
569,136
(216,066)
(8,744)
(7,324)
(143,742)
(100,873)
(7,454)
(484,201)
(10,346)
(214,814)
(30,732)
(8,731)
(162)
(264,785)
(828,714)
85,508
659,414
62,980
15,109
(773)
(1,016)
(606)
(2,417)
(3,630)
(1,326)
(1,730)
(4,978)
(4,495)
1,267
(14,892)
1,064
1,496
270
3,234
(530,489)
(4,211)
66,345
308,093
(70,195)
450
(160)
(230,167)
Additional information on property, plant and equipment, net
The main additions to property, plant, and equipment are related to investments in the Company’s networks and operating plants and new projects under construction. These investments totaled ThUS$920,872, ThUS$2,287,718 and ThUS$2,818,207 as of December 31, 2025, December 31, 2024, and January 1, 2024, 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 ThUS$258,563, ThUS$178,058 and ThUS$192,736 as of December 31, 2025, December 31, 2024, and January 1, 2024, respectively.
F-84
In the Generation segment, investments include works towards the new capacity program. This includes:
During the year 2025, the Don Humberto, Don Humberto BESS, El Manzano BESS, La Cabaña BESS and Rihue BESS plants came into operation, accumulating a carrying amount of ThUS$253,117 and having an installed capacity of 0.28 GW.
In accordance with the accounting criteria described in Note 4.a), only those investments made in the Generation projects described above qualify as assets eligible for capitalized interest. Together, these projects represent accumulated cash disbursements of ThUS$8,033, ThUS$1,695,109 and ThUS$2,075,956 as of December 31, 2025, December 31, 2024 and January 1, 2024, respectively.
b.1) Capitalized financial expenses in work-in-progress
The capitalized cost for financial expenses amounted to ThUS$7,009 as of December 31, 2025 (ThUS$90,350 and ThUS$96,971 as of December 31, 2024 and 2023, respectively) (see Note 34). The average financing rate ranged between 4.84% and 6.92% as of December 31, 2025 (between 5.49% and 6.6% as of December 31, 2024, and between 5.29% and 6.08% as of December 31, 2023).
b.2) Capitalized personnel expenses in work-in-progress
The capitalized cost for personnel expenses directly related to constructions in progress amounted to ThUS$42,339, ThUS$43,161 and ThUS$47,183 as of December 31, 2025, 2024 and 2023, respectively.
Additionally, the Group has civil liability insurance to cover third-party claims up to a limit of €450 million (ThUS$528,503) 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 (ThUS$23,489). The premiums associated with these policies are recorded proportionally to each company in the caption prepaid expense.
F-85
In 2025, the development of PMGD solar projects in the industry experienced a slowdown, primarily due to changes in remuneration schemes impacting the profitability of such initiatives. As a result, the alternative uses for certain assets connected to the Las Salinas expansion project were no longer considered feasible by the Group. Consequently, the Company recognized an additional impairment loss totaling ThUS$34,660.
F-86
Composition and movements of investment properties during the periods ended December 31, 2025, December 31, 2024, and January 1, 2024, have been as follows:
Investment Properties, Gross
Accumulated Depreciation and Impairment
Investment Properties, Net
Investment Property, Net, Cost Model
8,790
(421)
Owner-occupied real property transfers
(384)
210
(174)
(1,032)
(994)
7,374
Depreciation expense (*)
752
734
8,126
(196)
(*) See Note 31.a).
During the periods ended December 31, 2025, December 31, 2024, and January 1, 2024, no real estate property has been sold.
As of December 31, 2025, December 31, 2024, and January 1, 2024, the fair value of the investment amounted to ThUS$10,911, ThUS$9,182, and ThUS$10,151, respectively. This value was determined based on independent appraisals.
The inputs 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, 2025
Level 1
Level 2
Level 3
Investment properties
10,911
See Note 4.h.
The revenue and expenses derived from investment properties for the years ended December 31, 2025, 2024 and 2023, are as follows:
Income and expense from investment properties
Income derived from rental income from investment properties
122
Direct operating expenses from investment properties that generate rental income
(12)
(24)
As of December 31, 2025, December 31, 2024, and January 1, 2024, there are no contracts for repairs, maintenance, acquisition, construction or development that represent future obligations for the Group.
The Group has obtained 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.
Right-of-use assets as of December 31, 2025, December 31, 2024, and January 1, 2024, are detailed as follows:
Buildings, Net
Other plants and equipment
Right-of-use assets, Net
241,477
21,942
10,160
New asset contracts, right-of-use
68,929
16,495
Increases (decreases) from foreign currency translation differences, net
43,367
2,872
904
47,143
(14,899)
(5,429)
(13,791)
(34,119)
Retirements
(5,510)
10,735
102,622
3,608
106,284
344,099
21,996
13,768
259,589
27,977
19,179
43,286
512
(19,153)
(846)
(1,766)
(21,765)
(11,780)
(5,621)
(7,360)
(24,761)
(30,465)
(80)
(30,545)
(18,112)
(6,035)
(9,019)
(33,166)
As of December 31, 2025, the main right-of-use assets and lease liabilities primarily arise from land lease contracts for the development of non-conventional renewable energy projects within the EGP Chile Group, in projects such as El Manzano, Guanshoi, Sector Miraje, and Llanos de Chulo, with remaining durations ranging from 25 to 60 years, which accrue interest at an annual rate in the range of 2.42% to 2.93%.
The present value of future payments derived from those contracts is detailed as follows:
Present Value
59,191
17,673
37,703
10,721
37,626
10,106
35,077
15,685
19,392
22,497
11,119
11,378
20,700
9,834
10,866
32,926
15,022
17,904
21,754
10,243
11,511
20,082
9,080
11,002
31,741
14,346
17,395
21,602
9,805
11,797
19,861
8,938
10,923
27,654
14,075
13,579
21,614
9,409
12,205
19,963
8,544
11,419
503,665
203,256
300,409
377,696
155,917
221,779
380,168
146,281
233,887
690,254
280,057
502,866
207,214
498,400
192,783
The consolidated income statement for the years ended December 31, 2025, 2024 and 2023 includes expenses of ThUS$8,635, ThUS$7,111 and ThUS$6,500, respectively, of which ThUS$8,480 correspond to payments for short‑term leases in 2025 (ThUS$6,875 in 2024 and ThUS$6,246 in 2023) and ThUS$155 relate to leases with variable payment clauses in 2025 (ThUS$236 in 2024 and ThUS$254 in 2023), which are exempt from the application of IFRS 16 (see Note 4.f).
As of December 31, 2025 and 2024, the future payments arising from these contracts are as follows:
3,422
1,232
The following are the components of income tax recorded in the consolidated statements of comprehensive income for the years ended December 31, 2025, 2024 and 2023, are presented below:
Current Income Tax and Adjustments to Current Income Tax for Previous Periods
(Expense) / Current income tax
(204,976)
(245,240)
(194,805)
Adjustments to current tax from the previous period
(3,475)
(2,978)
(6,934)
(Expense) / Current tax (expenses) / benefit (related to cash flow hedges) (1)
(4,989)
175,880
(60,631)
Current tax expense, net
(213,440)
(72,338)
(262,370)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences
3,381
35,327
(7,793)
Total deferred tax benefit / (expense)
Income tax (expense) /benefit
The following table shows the reconciliation of the tax rate for the years ended December 31, 2025, 2024 and 2023:
Tax
Reconciliation of Tax Expense
Rate
Accounting profit before tax
Total tax expense using statutory rate
(27.00)%
(214,639)
(64,649)
(291,543)
Tax effect of rates applied in other countries
0.05%
406
2.87%
6,882
(0.48)%
(5,192)
Tax effect of tax-exempt revenue and other positive effects impacting the effective rate
0.75%
1.99%
4,776
0.39%
4,160
Tax effect of non-deductible expenses for determining taxable profit (loss)
(0.76)%
(6,071)
(5.55)%
(13,288)
(1.22)%
(13,221)
Tax effect of adjustments to income taxes in previous periods
(0.44)%
(1.24)%
(0.64)%
Price level restatement for tax purposes (investments and equity)
0.98%
7,792
13.47%
32,246
3.94%
42,567
Total adjustments to tax expense using statutory rate
0.58%
4,580
11.54%
27,638
1.98%
21,380
(26.42)%
(15.46)%
(25.02)%
The main temporary differences are described below:
The origin of and changes in deferred tax assets and liabilities as of December 31, 2025, December 31, 2024, and January 1, 2024, are as follows:
Assets
Liabilities
Deferred Tax Assets/(Liabilities)
Depreciation
34,872
(276,870)
35,259
37,600
(315,274)
Obligations for post-employment benefits
6,719
(1,067)
7,444
(1,167)
7,491
(992)
Tax loss
62,074
85,834
93,274
Provisions
118,585
(651)
108,166
(1,026)
129,004
Decommissioning provision
53,930
54,639
67,135
Provision for civil contingencies
457
5,543
454
Provision for doubtful trade accounts
16,406
(644)
9,051
(1,022)
6,423
Provision of Human Resources accounts
11,399
12,706
14,146
Provision of services rendered by foreign companies
12,107
11,308
26,465
Other Provisions
24,286
14,919
(4)
14,381
Other Deferred Taxes
137,515
(153,677)
102,212
(144,384)
116,975
(175,457)
Capitalization of expenses for issuance of financial debt
(9,955)
(12,274)
(15,838)
Leasing Net effect
132,528
(132,912)
96,091
(100,540)
112,224
(128,804)
Tax negative goodwill
(4,493)
(6,562)
(8,632)
Price-level Adjustment – Argentina
(1,957)
(24,619)
(22,097)
Other deferred taxes
4,987
(4,360)
6,121
(389)
(86)
Deferred tax assets/(liabilities) before compensation
359,765
(432,265)
338,915
(421,865)
384,344
(492,474)
Compensation deferred taxes assets/liabilities
(231,813)
(213,230)
213,230
(295,793)
295,793
Deferred tax assets/(liabilities) after compensation
(200,452)
(208,635)
(196,681)
Movements
Recognized in other in comprehensive income
Net balance as of January 1, 2025
Recognized in profit or loss
Recognized in others in comprehensive income
Incorporation of subsidiaries to the scope of consolidation
Foreign currency exchange difference
Net balance as of December 31, 2025
(240,029)
(2,575)
886
(280)
(241,998)
6,277
(728)
5,652
(25,724)
1,964
107,140
5,980
4,814
117,934
Decommissioning Provision
(815)
(5,098)
8,029
7,627
15,762
(1,563)
778
Other provisions
14,915
4,313
24,279
(42,172)
26,428
(418)
(16,162)
2,325
(4,449)
4,412
22,710
(48)
5,732
(5,096)
627
Deferred tax assets/(liabilities)
(82,950)
7,253
(72,500)
Net balance at January 1, 2024
Incorporation of subsidiaries to the scope of consolidation (i)
Net balance as of December 31, 2024
(277,674)
33,224
4,398
6,499
(380)
(715)
(5,447)
1,592
(3,585)
128,251
(8,672)
299
(12,738)
(5,828)
(6,668)
5,431
(342)
5,672
3,197
(840)
(1,611)
(12,683)
(2,474)
14,379
1,357
(803)
(58,480)
16,603
586
(260)
(621)
1,760
(16,579)
10,134
1,996
1,519
551
(22,096)
(3,961)
4,665
1,131
(650)
(108,130)
35,328
2,500
(12,900)
(1)On August 1, 2024, Enel Chile subscribed a capital increase in Enel X Way Chile S.p.A., which was fully contributed on August 23, 2024. Through capital increase, Enel Chile increased its interest in Enel X Way Chile S.p.A. from 49% to 62.46%, resulting in it becoming a subsidiary entity (see Note 2.4.1 iii)
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, 2025, December 31, 2024, and January 1, 2024, the Group has accounted for all deferred tax assets associated with its tax losses (See Note 4.p).
Regarding temporary differences related to investments in consolidated entities and certain joint ventures, the Group has not recognized deferred tax liabilities associated with undistributed earnings, since the control position exercised by the Group over such consolidated entities allows managing the timing of the reversal of those differences, and it is considered probable that they will not reverse in the foreseeable future. The total amount of these taxable temporary differences for which no deferred tax liabilities have been recognized amounts to ThUS$1,318,288 as of December 31, 2025 (ThUS$1,192,004 and ThUS$1,191,145 as of December 31, 2024 and January 1, 2024, respectively). In addition, no deferred tax assets have been recognized in relation to deductible temporary differences associated with investments in consolidated entities and certain joint ventures for which reversal is not expected in the foreseeable future or for which taxable profits are not expected to be available for their utilization. As of December 31, 2025, such deductible temporary differences amount to ThUS$1,165,367 (ThUS$1,175,636 and ThUS$1,522,513 as of December 31, 2024 and January 1, 2024).
The Group’s companies are potentially subject to income tax audits by the tax authorities where 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 2022 to 2024.
Because of 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.
For the years ended December 31, 2025, 2024 and 2023, the current and deferred tax effects of the components of other comprehensive income attributable to owners of the Group and non-controlling interests are detailed below:
Deferred Income Tax Effects on the Components of Other Comprehensive Income
Amount BeforeTax
Income TaxExpense (Benefit)
Amount AfterTax
Cash flow hedge
(12,457)
(7,468)
643,292
467,412
(224,558)
(163,927)
Actuarial gains(losses) on defined-benefit pension plans
(261)
(2,360)
Income tax related to components of other income and expenses with a charge or credit in equity
5,085
(175,007)
60,640
The following table shows the reconciliation of deferred tax movements between balance sheet and income taxes in other comprehensive income as of December 31, 2025, 2024 and 2023:
Deferred taxes of components of other comprehensive income
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations
Income tax of movements in cash flow hedge transactions
Total income tax relating to components of other comprehensive income
F-91
20. OTHER FINANCIAL LIABILITIES.
The balance of other financial liabilities as of December 31, 2025, December 31, 2024, and January 1, 2024, is as follows:
Other financial liabilities
Interest-bearing borrowings
Hedging derivatives (*)
62,621
22,542
82,991
7,923
Non-hedging derivatives (**)
(*) See Note 23.2.a
(**) See Note 23.2.b
The detail of current and non-current interest-bearing borrowings as of December 31, 2025, December 31, 2024, and January 1, 2024, are as follows:
Secured bank loans
46,345
4,026
3,090
721,022
764,242
494,000
Unsecured bank loans
150,624
694
151,071
150,000
Unsecured obligations with the public
62,492
56,727
464,022
1,440,344
1,462,920
1,519,402
Bank borrowings by currency and contractual maturity as of December 31, 2025, December 31, 2024, and January 1, 2024, is as follows:
EffectiveInterest
Nominal Interest
Unsecured / Secured
Less than 90 days
More than 90 days
Oneto two years
Twotothreeyears
Threetofouryears
Fourtofiveyears
Morethanfiveyears
TotalNon-Current
5.25%
4.74%
Yes
793
45,552
55,968
57,540
59,188
60,917
487,409
No
5.27%
150,615
150,618
802
196,167
196,969
Effective Interest
928
3,098
42,455
549,091
932
3,788
4,720
192,455
914,242
4.89%
24,500
37,109
37,731
394,660
6.51%
150,735
153,825
154,161
174,500
644,000
Fair value measurement and hierarchy
The fair value of current and non-current bank borrowings as of December 31, 2025 is ThUS$921,001 (ThUS$906,146 and ThUS$775,549 as of December 31, 2024 and January 1, 2024, respectively). The borrowings have been categorized as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 4.h).
TaxpayerID
FinancialInstitution
EffectiveInterestRate
NominalInterestRate
TypeofAmortization
Secured
Lessthan90daysThUS$
Morethan90daysThUS$
TotalCurrentThUS$
OnetotwoyearsThUS$
TwotothreeyearsThUS$
ThreetofouryearsThUS$
FourtofiveyearsThUS$
MorethanfiveyearsThUS$
Total Non-CurrentThUS$
97.018.000-1
Banco Scotiabank (Overdraft facility)
Upon expiration
76.536.353-5
Luxembourg
Annual
21,719
32,135
33,707
35,355
37,084
337,099
475,380
CitiBank N.A. London Branch
USA
4.46%
Biannual
23,833
24,626
150,310
245,642
CAF_VE (Commitment fee)
Venezuela
0.50%
18,621
33,706
374,183
5.15%
23,834
174,908
270,242
DNB Bank ASA (Commitment fee)
Norway
0.30%
97.036.000-k
Banco Santander
5.71%
49,963
6.86%
772
Banco Bilbao Vizcaya Argentaria S.A. NY Branch
6.37%
318
75,000
75,318
Mizuho Bank LTD.
25,000
SMBC (Commitment fee)
0.32%
(1)See Note 35.2
F-93
The detail of unsecured liabilities by currency and maturity as of December 31, 2025, December 31, 2024, and January 1, 2024, are as follows:
Lessthan90days
Morethan90days
TotalCurrent
Onetotwoyears
5.98%
5.59%
10,283
2,573
12,856
205,753
992,043
104,867
1,302,663
5.20%
4.97%
49,636
48,923
49,270
39,488
137,681
52,209
254,676
1,041,313
5.58%
10,284
12,857
205,643
989,130
104,839
1,299,612
5.21%
43,870
43,067
42,622
34,552
163,308
46,443
248,710
1,031,752
5.67%
405,818
416,102
205,495
986,360
103,947
1,295,802
5.22%
47,920
46,855
45,686
37,349
223,600
453,738
252,350
1,032,046
141,296
Financial Institution
TotalNon-CurrentThUS$
BNY Mellon - First Issuance S-1
8.00%
7.87%
6,755
BNY Mellon - First Issuance S-2
8.80%
7.33%
2,160
69,849
BNY Mellon - First Issuance S-3
8.68%
8.13%
1,368
35,018
97.036.000-K
Banco Santander -317 Serie-H (1)
7.17%
9,489
9,109
9,456
18,565
Banco Santander 522 Serie-M (1)
4.85%
40,147
39,814
119,116
BNY Mellon - Single
5.24%
4.88%
6,756
69,823
35,016
8,456
8,019
7,573
23,611
35,414
35,048
35,049
139,697
BNY Mellon - First issuance S-1
BNY Mellon - First issuance S-2
69,667
BNY Mellon - First issuance S-3
34,280
BNY Mellon - Single 24296
4.67%
4.25%
403,244
9,313
8,724
7,556
33,730
38,608
38,131
38,130
189,870
(1)Related to liabilities associated with covenants (See Note 35.4. Financial Restrictions, item 2. Financial Covenants), which amount to ThUS$137,681 as of December 31, 2025, ThUS$163,308 as of December 31, 2024, and ThUS$223,600, as of January 1, 2024.
As of December 31, 2025, December 31, 2024, and January 1, 2024, there were no secured bonds.
F-95
The fair value of the current and non-current secured and unsecured liabilities as of December 31, 2025 was ThUS$1,589,519 (ThUS$1,592,018 and ThUS$2,067,396 as of December 31, 2024, and January 1, 2024, respectively). These liabilities have been categorized as Level 2 (see Note 4.h). It is important to note that these financial liabilities are measured at amortized cost (see Note 4.g.4).
As of December 31, 2025, ThUS$0 (ThUS$0 and ThUS$1,294,000 as of December 31, 2024, and January 1, 2024, respectively) of the Group's debt in U.S. dollars was related to hedging a portion of the revenues of the subsidiary Enel Generación Chile, which were directly linked to the evolution of the U.S. dollar (see Note 4.g.5).
The movement as of December 31, 2025, December 31, 2024, and January 1, 2024, in the cash flow hedge reserves, net of tax and minority interests, due to the exchange rate differences of this debt has been as follows:
Balance in hedging reserves (income hedge) at the beginning of the year net
(389,604)
(366,510)
Foreign currency translation differences recorded in equity, net
(43,577)
(79,818)
Allocation of foreign currency exchange differences to profit or loss, net (i)
433,181
56,724
Balance in hedging reserves (income hedge) at the end of the year net
As of the 2024 year‑end, and considering the change in the functional currency of Enel Generación Chile effective January 1, 2025, these accounting hedges lost their effectiveness and, therefore, due to the change in the risk management objective, they were prospectively discontinued. As of December 31, 2024, the cumulative amount in the corresponding cash flow hedging reserves, where financial liabilities were defined as hedging instruments, amounted to ThUS$552,615, before taxes and minority interests (See Notes 23.2(a) and 28.1).
As of December 31, 2025, the Group has unconditional long-term credit lines available amounting to ThUS$690,000 (ThUS$690,000 and ThUS$540,000 as of December 31, 2024 and January 1, 2024, respectively), of which ThUS$340,000 are available with related parties (ThUS$340,000 and ThUS$490,000 as of December 31, 2024, and, January 1, 2024, respectively) and ThUS$350,000 are available with third parties (ThUS$350,000 and ThUS$50,000 as of December 31, 2024 and January 1, 2024, respectively).
20.5 Future undiscounted debt flows.
The following tables are the estimates of undiscounted flows by type of financial debt:
Non-Current
TotalNon-current
5.00%
227,446
239,198
93,100
91,944
90,588
89,320
611,234
976,186
12,487
38,155
50,642
242,064
94,898
93,579
92,052
706,237
1,228,830
4,935
168,771
173,706
37,142
204,934
57,679
57,572
530,592
887,919
11,758
239,204
24,826
49,625
74,451
265,335
1,030,818
8,586
363,414
1,676,739
21,060
53,391
371,999
1,751,189
22,859
456,802
479,661
380,586
1,825,641
2,347
55,372
57,719
55,230
54,814
41,206
151,250
2,607
50,396
53,003
50,811
48,619
48,253
36,274
183,957
3,462
56,624
60,086
57,664
55,279
52,894
52,496
39,464
257,797
27,173
104,997
132,170
320,565
1,085,632
49,792
1,827,989
23,667
103,787
127,454
125,262
313,954
1,079,071
44,860
1,935,146
26,321
513,426
539,747
132,115
129,730
318,229
1,083,314
420,050
2,083,438
As of December 31, 2025, December 31, 2024 and January 1, 2024, the balance of lease liabilities is as follows:
Lease liability
12-31-2025ThUS$
12-31-2024ThUS$
01-01-2024ThUS$
21.1. Individualization of Lease Liabilities
Maturiry
Taxpayer IDNumber
Less than90 daysThUS$
Morethan 90daysThUS$
One totwoyearsThUS$
Two tothreeyearsThUS$
Three tofouryearsThUS$
Four tofiveyearsThUS$
Morethan fiveyearsThUS$
10.579.624-2
Marcelo Alberto Amar Basulto
2.06%
Monthly
91.004.000-6
Productos Fernandez S.A.
2.09%
472
61.216.000-7
Empresa de Ferrocarriles del Estado
0.10%
78.086.990-9
Inversiones San Isidro
2.86%
77.088.295-8
Consultoria y transpor.
4.15%
81.591.800-2
Cuerpo de bomberos Quillota
76.409.056-k
Ald Automotive LTDA
3.92%
348
500
1,239
96.775.780-2
Compañía de Leasing Tattersall SA
345
478
291
1,175
70.015.730-K
Mutual de Seguros de Chile
1.91%
76.596.523-3
Capital Investi
61.219.000-3
Empresa de Transporte de Pasajeros Metro S.A.
5.99%
1,130
99.530.420-1
Inmobiliaria Nialem S.A.
0.40%
201
254
800
76.013.489-9
Inversiones Don Issa Ltda.
1.87%
78.844.390-0
Poliplast
5.36%
96.643.660-3
Inmobiliaria El Roble S.A.
0.79%
76.085.228-7
Rentas Fonsaso
5.37%
378
226
ALD Automovile Ltda.
5.16%
343
633
Compañía de Leasing Tattersall S.A.
159
221
222
593
77.744.291-0
Morillo Energy Rent SPA
6.10%
643
1,283
433
77.030.540-3
Lureye Arriendos SPA
6.78%
1,639
1,101
2,740
1,668
61.402.000-8
Ministerio de Bienes Nacionales
5.01%
329
363
1,284
2,634
3.29%
4,236
16,960
21,196
5,816
5,976
6,166
6,381
210,938
235,277
76.364.150-3
Inversiones Interover Sur S.A.
3.83%
182
216
1,287
76.400.311-K
Fundo Los Buenos Aires SpA
2.54%
124
1,185
1,688
5.704.494-2
Pablo Rioseco y Otros
4.94%
10.249.202-1
Juan Rioseco y Otra
3.91%
77.378.630-5
Agricola Santa Amalia
4.40%
287
402
319
77.894.990-3
Orafti Chile S.A.
78.201.750-0
Sociedad Agricola Parant
99.576.780-5
Sucesión Aguilera Parada
4.47%
278
1,119
1,447
9.433.580-7
Macarena Rioseco
76.170.091-K
Multicenter SpA
5.95%
625
1,056
76.064.627-K
Forestal Danco
5.92%
2,012
96.629.120-6
Agrícola Esmeralda S.A.
5.30%
1,049
8,712
8,990
76.238.102-8
Crucero Este Uno SpA
2.96%
938
1,103
Inversiones e Inmobiliaria Itraque S.A.
3.70%
453
288
308
79.771.340-6
Agrícola el Tapial Ltda.
849
5.121.031-K
Sergio Jose Retamal Iglesias
5.72%
2,722
2,946
6.372.943-4
Francisco Javier Ovalle Irarrazaval
665
134
907
1,451
79.745.330-7
Soc. Agricola Ancona Ltda.
0.07%
142
686
18,711
21,103
84.810.200-2
Huertos Carmen Sociedad Agricola Lt
7,150
8,064
77.412.950-2
Inverko S A
5.70%
7.256.021-3
Alicia Veronica Freire Hermosilla
2,048
96.637.810-7
Bosques Cautín S.A.
5.75%
145
154
173
7,269
7,905
2.32%
175
179
5,515
6,239
6.968.166-2
Luis Fernando Topali Galvan
2.62%
152
3,215
3,697
77.663.046-2
Inversiones CBO y Compañía
1,852
6.329.938-3
Maria Ines Beltran Navarro
3.62%
579
1,273
1,407
7.840.909-6
Juan Jose Gajardo Esparza
1.85%
164
1,412
76.416.292-7
Agricola La Campana Ltda.
1.38%
1,268
79.755.040-K
Inmobiliaria Silfran Ltda.
4.30%
911
992
8.287.566-2
Audolia Alveal & Otros
6.38%
209
4.503.432-1
Carmen Pinochet (Inosca)
135
140
10.879.279-5
Javier Saavedra Duhart
11.583.044-9
Eduardo Saavedra Duhart
76.690.982-5
Palpana Campos SpA
10.379.851-5
Nicolás Sánchez Lecares
1.43%
1,409
1,675
5.80%
382
414
5.018.840-K
Monica de la Cruz Fuster Lopez
475
5.823.948-8
Maria Edifilia Mondaca Galaz
589
677
79.909.880-6
Agricola y Ganadera San Raimundo
2.50%
280
294
302
8,976
10,139
ALD Automotive Ltda.
446
549
456
970
Parque Eólico Talinay Oriente S.A.
76.248.317-3
Agricola Alto Talinay
4.61%
503
576
2,721
4,876
76.203.473-5
Territoria Apoquindo S:A
4.17%
1,166
3,735
4,901
5,197
5,521
5,757
2,792
19,267
96.839.400-2
Inversiones San Jorge
4.34%
157
12,657
28,861
592
942
76.164.095-K
Inmobiliaria Mixto Renta Spa
7.10%
76.378.333-2
Inmobiliaria Fernandez
7.13%
5.29%
738
263
304
1,395
2,528
3.13%
3,724
13,412
17,136
4,510
4,655
5,103
5,250
184,018
203,536
1,444
1,138
1,569
303
211
630
841
77.423.282-6
Sociedad Agrícola La Cruz
4.29%
305
5,769
6,377
7.872.865-5
Paulina Camus Bories
3.35%
460
Agricola Esmeralda
578
6,895
7,131
724
895
84.810.200-8
Huertos Carmen Sociedad Agrícola Limitada
3.61%
Inversiones E Inmobiliaria Itraque S.A.
Agricola El Tapial Ltda.
3,024
Francisco Javier Ovalle Irarrazabal
927
1,014
Inverko S.A.
750
874
Soc. Aagricola Ancona Ltda.
7,398
8,176
Huertos Carmen Soc. Agricola Lt.
76.769.393-1
Rentas Coquimbo SpA
7.74%
991
325
340
356
2,183
3,515
1,115
3,152
4,267
4,360
4,575
4,860
5,068
20,940
7,996
18,986
F-99
193
312
618
99.527.200-8
Rentaequipos Tramaca S.A.
0.83%
165
96.565.580-8
Compañía de Leasing Tattersall S A.
76.253.641-2
Bcycle Latam S.P.A
6.24%
862
1,272
Compañia de Leasing Tattersall S. A.
1.41%
188
199
76.203.089-6
Rentas Inmobiliarias Amanecer S.A.
2.84%
3.78%
3.03%
3,251
14,219
17,470
3,818
4,618
4,532
4,686
198,702
216,356
5.02%
753
266
293
1,769
2,915
3.750.131-K
Federico Rioseco Garcia
215
3.750.132-8
Juan Rioseco Garcia
4.595.479-K
Adriana Castro Parra
391
491
285
1,343
1,644
76.259.106-5
Inmobiliaria Terra Australis Tres S.A.
6.39%
1,406
1,671
79.938.160-5
Soc. Serv. Com. Multiservice F.L.
2.94%
906
1,257
Fortestal Danco
2.42%
172
2,319
2,510
8,083
8,339
3.56%
762
1,113
3,261
3,452
316
330
346
361
2,038
3,391
1,183
3,294
4,477
4,550
4,744
4,978
5,288
7,760
27,320
7,440
20,080
10,867
10,999
11,420
233,888
21.2. Undiscounted debt cash flows.
The following tables are the estimates of undiscounted cash flows:
1,147
1,188
1,277
1,265
1,252
30,987
36,019
321
339
334
6,929
8,241
1,007
1,094
2,015
2,009
1,299
1,254
1,208
4,537
9,461
796
1,448
843
784
3,702
7,015
419
392
379
1,986
3,582
3.51%
10,361
31,821
42,182
30,278
28,033
25,939
20,381
534,550
639,181
7,799
20,713
28,512
21,300
20,273
19,420
18,937
431,020
510,950
7,563
25,633
33,196
25,055
24,067
23,279
22,765
505,577
600,743
2,296
1,744
4,041
2,108
2,340
13,991
35,428
49,419
34,962
30,559
28,407
22,791
570,283
687,001
8,645
21,636
30,281
22,483
21,455
20,568
20,049
441,651
526,206
8,319
26,323
34,642
25,743
24,707
23,895
23,359
508,657
606,361
The Group companies follow the guidelines of the Risk Management Control System (SCGR, in its Spanish acronym) 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 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 areas, acting as the first line of defense, Risk Control and Compliance units, acting as the second line of defense, and Internal Audit, acting 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.
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 period ended January 01,
Fixed interest rate
87%
89%
88%
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.
Exchange rate risks involve basically the following transactions:
In order to minimize foreign currency risk, the Group’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between cash flows in currencies other than the functional currency in its assets and liabilities. 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 2024, the respective Boards of Directors of Enel Chile, Enel Generación Chile, and Empresa Eléctrica Pehuenche agreed to change the functional currency of these companies from Chilean pesos to U.S. dollars, effective January 1, 2025, due to the fact that the U.S. dollar has become the currency that significantly influences the economic environment in which each of them operates (see Note 3).
The Group has a risk exposure to price fluctuations in certain commodities, basically due to:
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, 2025, the Company’s hedge position was concentrated in Henry Hub gas and coal. In Henry Hub gas, active hedges amounted to 30 Tbtu corresponding to purchase positions, and 9 Tbtu to sales positions. In coal, liquidation obligations were recorded for 27 kTon associated with sales contracts. As of that same date, there were no active Brent oil hedges.
As of December 31, 2024, active Brent hedges to be liquidated totaled 45 kBbl associated with purchases. Regarding gas, no active hedges to be liquidated were recorded at the 2024 year‑end, neither in Henry Hub Swaps nor in Henry Hub Futures. With respect to coal hedging, as of December 31, 2024, liquidation obligations were recorded for a total of 10.7 kTon corresponding to sales contracts.
Depending on the Group’s permanently updated operating conditions, these hedges may be modified, or include other commodities.
As a result of the mitigation strategies implemented, the Group was able to minimize the effects of the volatility of commodity prices on the profit or loss on the results for the year ended December 31, 2025.
The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.
The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives see Notes 20, 21 and 23.
Despite the negative working capital existing at the end of 2025, the Company is able to address this situation and mitigate the risk through the policy and actions described herein.
As of December 31, 2025, the Group had liquidity of ThUS$461,924 in cash and cash equivalents and ThUS$690,000 in unconditionally available long-term credit lines. As of December 31, 2024, the Group had a liquidity of ThUS$384,761 in cash and cash equivalents and ThUS$690,000 in unconditionally available long-term credit lines; and as of January 1, 2024, the Group had liquidity of ThUS$642,206 in cash and cash equivalents and ThUS$540,000 in unconditionally available long-term credit lines.
The Group closely monitors its credit risk.
Trade receivables:
Regarding the credit risk of the Company’s 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.
In relation to the credit risk corresponding to the receivables stemming from distribution commercial activity, this risk is historically very limited given that the short-term billing to customers does not individually accumulate very significant amounts before the supply suspension for non-payment can occur, in accordance with the related regulation. Additionally, tracking and control measures exist for all the Company’s segments: Corporate, Public Administration, and Residential, with exclusive commercial executives assigned for dealing with Corporate and Public Administration customers, with the aim of mitigating any activity that results in risk of payment default by the customer.
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).
Foreign exchange risk
For the purpose of monitoring this risk and limiting the volatility of the Statement of Financial Position, the Group prepares a prospective measurement, based on a Monte Carlo monthly simulation of foreign exchange fluctuation of accounting account mismatches, in a period of 3 months with 95% reliability. Based on the Company’s estimated exposure, considering the current hedges, payment flows and mitigation actions, the estimated impact of exchange rate fluctuations for the next quarter would amount to approximately MUS$26.
Considering that effective as of January 1, 2025 Enel Chile and its subsidiaries Enel Generación Chile and Empresa Eléctrica Pehuenche adopted the U.S. dollar as their functional currency, the foreign exchange risk measurement described above has been determined considering this circumstance.
Interest rate risk
The exposure associated with interest rate variance is measured as the finance cost sensitivity. The sensitivity analysis on the monthly finance cost shows that a variance of 25 basis points in the reference interest rate, SOFR, would have the following effects:
With respect to lease instruments denominated in Unidades de Fomento (UF), these are classified as variable‑rate instruments, since their value is indexed to inflation. However, such instruments do not exhibit sensitivity to changes in market interest rates (for example, the real TAB rate). Consequently, they are not included in the sensitivity analysis presented in this Note.
Due to the Company’s effective control over its exposure to variable rates, its risk is considered to be limited. To reduce this exposure even further, the Company continuously monitors market scenarios and seeks a balance between fixed and variable rate financing.
23.1 Financial instruments classified by type and category
Financial derivatives for hedging
Equity instruments
Trade and other receivables
1,382,738
Accounts receivable from related parties
Derivative instruments
896
Other financial assets
1,445,197
1,024
Total Non-current
1,108,098
2,553,295
3,359
19,227
1,493,300
1,547,081
2,329
2,710,451
4,420
1,649,263
3,070
10,890
1,717,470
3,216
2,747,749
5,868
76,713
Financial liabilities at fair value through profit or loss
Financial liabilities measured at amortized cost
Financial liabilities at fair value through other comprehensive income
Interest-bearing loans
Trade and other payables
1,526,225
Accounts payable to related parties
6,355
2,199,123
4,377,145
6,576,268
71,583
1,535,137
1,922,928
4,634,850
6,557,778
27,776
1,652,038
17,622
2,825,124
4,300,225
7,125,349
90,914
The carrying value of trade receivables and payables approximates their fair value.
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:
As of December 31, 2025, December 31, 2024, and January 1, 2024, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:
Interest rate hedge:
3,130
1,226
Exchange rate hedge:
62,552
8,539
2,104
64,911
Additionally, supplementary details of the associated instruments and underlying assets are presented:
Description of Instruments covered
Finance debt
18,984
53,550
9,410
Investments in property, plant & equipment
816
681
Operating income (i)
255
14,608
10,521
905
39,016
2,218
1,250
1,097
(i) As of the 2024 year‑end, and considering the change in the functional currency of Enel Generación Chile effective January 1, 2025, the accounting hedges associated with a portion of that subsidiary’s income, which were directly linked to the U.S. dollar valuation, lost their effectiveness and, therefore, due to the change in the risk management objective, they were prospectively discontinued. As of December 31, 2024, the cumulative amount in the cash flow hedging reserves, where financial derivatives were defined as the hedging instrument, amounted to ThUS$104,519, before taxes and minority interests (see Notes 20.3 and 28.1).
Hedging derivative instruments and their corresponding hedged instruments, as of December 31, 2025, December 31, 2024, and January 1, 2024 are shown in the following table:
Fair value of
Type of
Nature
hedged item
hedge
of hedged
of
instrument
risk
item
Risk Hedged
SWAP
Exchange rate
Unsecured obligations (bonds)
Cash flow
18,720
(1,220)
13,831
Interest rate
Loans with related parties
(3,055)
Bank loans
(9,031)
FORWARD
(62,023)
(235)
(14,608)
(29,808)
(279)
396
As of December 31, 2025, December 31, 2024, and January 1, 2024, 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.
F-107
As of December 31, 2025, December 31, 2024, and January 1, 2024, liabilities were recognized in the financial statement as a result of derivative financial operations that are recognized at fair value through profit or loss. The amounts are detailed below:
CurrentAssets
CurrentLiabilities
Non-CurrentAssets
Non-CurrentLiabilities
Non-hedging derivative instrument
These derivative instruments corresponded to forward contracts entered into by the Group, aimed at hedging the exchange rate risk related to obligations arising from civil works contracts linked to the construction of the Los Cóndores plant. Although these hedges had an economic rationale, they did not qualify as accounting hedges because they did not strictly meet the requirements established in IFRS 9 “Financial Instruments”.
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, 2025, December 31, 2024, and January 1, 2024:
Notional Amount
Fair value
Less than 1 year
1-2 years
2-3 years
3-4 years
4-5 years
More than 5 years
Financial derivatives
286,000
(43,325)
753,662
45,924
46,153
35,644
881,383
Derivatives not designated for hedge accounting
(52,356)
1,167,383
(16,107)
228,126
178,217
406,343
2,236
(19,176)
230,362
694,579
50,000
(15,429)
1,699,097
215,415
1,914,512
4,227
(14,151)
1,753,324
1,968,739
The notional amount of the contracts entered into does not represent the risk assumed by the Group, as this amount only relates to the basis on which the derivative settlement calculations are made.
F-108
Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 4.h.
The following table presents financial assets and liabilities measured at fair value as of December 31, 2025, December 31, 2024, and January 1, 2024:
Fair Value Measured at End of Reporting Period Using:
Financial Instruments Measured at Fair Value
Financial Assets:
Financial derivatives designated as cash flow hedges
Derivatives of commodities designated as non-hedging of cash flow at fair value through profit or loss
Derivatives of commodities designated as cash flow hedges at fair value through other comprehensive income
Equity instruments at fair value through other comprehensive income
2,463
25,193
22,858
Financial derivatives not designated for hedge accounting
78,833
8,613
2,464
13,035
10,700
732
28,524
76,712
3,071
2,797
82,633
79,981
90915
0
108,538
24. TRADE AND OTHER PAYABLES
As of December 31, 2025, December 31, 2024, and January 1, 2024, the details of trade and other payables, current are as follows:
Trade payables
Energy suppliers (1)
691,786
591,498
337,996
985,379
968,952
678,432
Fuel and gas suppliers
133,292
189,894
291,369
Payables for goods and services
442,352
490,938
411,234
331
Payables for assets acquisition
136,431
178,475
469,613
Subtotal
1,403,861
1,450,805
1,510,212
985,568
969,141
678,952
Other Payables
Dividends payable to third parties
71,187
35,807
91,962
Payables to employees
38,963
42,650
52,717
Other payables
19,464
6,609
14,769
129,614
85,066
159,448
Subtotal other current payables
(1)The non-current portion shows delays in payments for energy purchases of ThUS$985,379 as of December 31, 2025, US$968,952 as of December 31, 2024 and US$678,432 as of January 1, 2024, generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Laws No. 21,185, No. 21,472, and No. 21,667 (see Note 9.a.1.ii).
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, 2025, December 31, 2024, and January 1, 2024, are presented in Appendix 3.
Provision for legal proceedings (1)
1,221
1,826
1,307
42,578
39,448
11,939
Decommissioning or restoration (2)
28,082
22,351
171,329
175,745
227,668
Other provisions (3)
1,399
21,626
5,018
838
1,638
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.
LegalProceedings
Decommissioning orRestoration
Environmental Issues and Other Provisions
Movements in Provisions
41,274
203,827
22,464
267,565
Increase (decrease) in existing provisions
11,240
7,154
(191)
18,203
Provisions used (1)
(5,068)
(20,910)
(20,656)
(46,634)
Reversal of unused provision (2)
(7,508)
(800)
(8,308)
Increase from adjustment to time value of money (3)
9,278
3,861
850
4,773
Total movements in provisions
2,525
(4,416)
(20,797)
(22,688)
43,799
199,411
244,877
13,246
250,019
6,656
269,921
Increase (decrease) in existing provisions (4)
40,390
(8,570)
18,580
50,400
Reversal of unused provision
(1,244)
(24,475)
(25,719)
11,526
(8,429)
(919)
(9,348)
Decreases due to classification as held for sale (5)
(2,689)
(24,673)
(1,853)
(29,215)
28,028
(46,192)
15,808
(2,356)
26. POST-EMPLOYMENT BENEFIT OBLIGATIONS.
Enel Chile S.A. and certain subsidiaries granted various post-employment benefits to either all or certain active or retired employees. These benefits are calculated and recognized in the financial statements according to the criteria described in Note 3.m.1, and include primarily the following:
Defined benefit plans:
26.2 Details, changes and presentation in financial statements
Employee severance indemnities
41,169
44,396
49,451
Complementary Pension
16,405
15,736
16,199
Health Plans
2,963
2,717
Energy Supply Plans
3,521
3,092
3,254
Total post-employment obligations, net
Cost of current defined benefit plan service
(1,608)
(1,748)
(1,731)
Defined benefit plan interest cost (1)
(3,548)
(3,686)
(3,785)
Expenses recognized in Profit or Loss
(5,156)
(5,434)
(5,516)
Gains (losses) from remeasurement of defined benefit plans
Total expense recognized in the Statement of Comprehensive Income
(5,513)
(8,667)
(5,548)
(1) See Note 34.
Current service cost
1,748
Interest cost
3,686
Actuarial (gains) losses from changes in financial assumptions
1,270
Actuarial (gains) losses from changes in experience adjustments
1,963
(8,967)
Contributions paid
(5,817)
Transfer of employees
327
1,608
3,548
(1,302)
1,659
6,818
(14,080)
As of December 31, 2025, December 31, 2024, and January 1, 2024, the following assumptions were used in the actuarial calculation of defined benefit plans:
Discount rates used
5.33%
5.10%
5.31%
Expected rate of salary increases
4.00%
3.80%
Turnover rate
8.57%
8.74%
6.80%
Mortality tables
CB-H-2020 and RV-M-2020
CB-H-2014 and RV-M-2015
As of December 31, 2025, the sensitivity of the actuarial liability for post‑employment benefits to variations of 100 basis points in the discount rate implies a decrease of ThUS$5,250 (ThUS$5,259 and ThUS$4,292 as of December 31, 2024 and January 1, 2024, respectively) in the event of an increase in the rate, and an increase of ThUS$6,109 (ThUS$6,034 and ThUS$4,551 as of December 31, 2024 and January 1, 2024, respectively) in the event of a decrease in the rate.
According to the available estimate, the disbursements foreseen to cover the defined benefit plans for 2026 amount to ThUS$6,886.
Enel Chile´s obligations have a weighted average length of 20.24 years, and the outflows of benefits for the next 10 years are expected to be as follows:
Years
6,886
6,619
6,748
6,738
6,958
6 to 10
32,604
27.1.Subscribed and paid capital and number of shares
The capital of Enel Chile as of December 31, 2025, amounts to ThUS$3,895,895 represented by 69,166,557,219 authorized, fully subscribed and paid single series shares without par value. One share that remained unissued from the Company’s 2018 merger with Enel Green Power Latin America was cancelled by the shareholders at the Extraordinary Shareholders’ Meeting held on April 28, 2025. The capital of Enel Chile as of December 31, 2024 and January 1, 2024, amounts to ThUS$5,964,284 represented by 69,166,557,220 authorized, fully subscribed and paid single series shares. All the shares issued by Enel Chile are subscribed and paid and admitted for trading in the Bolsa de Comercio de Santiago de Chile, Bolsa Electrónica de Chile and the New York Stock Exchange (NYSE).
Dividend No.
Type ofDividend
Agreement date
Payment Date
Total Amount ThUS$
USD perShare
Charged to Fiscal
Interim dividend
11-25-2022
01-27-2023
29,532
0.00043
Final dividend
04-26-2023
05-26-2023
465,321
0.00673
11-23-2023
01-26-2024
47,462
0.00069
04-29-2024
05-29-2024
316,094
0.00457
11-15-2024
01-24-2025
63,358
0.00092
04-28-2025
05-23-2025
10,417
0.00015
Eventual
233,947
0.00338
11-27-2025
01-23-2026
52,771
0.00076
The details of the translation differences by company attributable to owners of the Group of the consolidated statement of financial position as of December 31, 2025, 2024 and 2023, are as follows:
12-31-2023
2,080
1,222
3,160
5,033
5,934
2,738
Grupo Enel Distribución Chile
75,894
Grupo Enel Green Power Chile
447,314
584,492
451,309
Translation difference due to change in presentation currency (1)
(1,788,114)
(1,177,160)
The 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, 2025, December 31, 2024, and January 1, 2024, the Company’s interest in the net restricted assets of Enel Generación Chile was ThUS$715,051.
Other reserves for the years ended December 31, 2025, 2024 and 2023, are as follows:
2025 Changes
Detail of other reserves
1,726,787
Cash flow hedges
158,996
Other miscellaneous reserves
1,152,433
3,038,214
2024 Changes
454,838
3,225
01-01-2023
2023 Changes
The main items and their effects are the following:
Other Miscellaneous Reserves
Company restructuring reserve ("Division") (i)
(535,955)
(770,084)
Reserve for transition to IFRS (ii)
(458,846)
(659,398)
Reserve for subsidiaries transactions (iii)
12,547
18,031
Reserves for Tender Offer of Enel Generation “Reorganization of Renewable Assets” (iv)
(913,672)
(1,420,440)
Reserves “Reorganization of Renewable Assets” (v)
(408,802)
(635,544)
Argentine hyperinflation (vi)
31,142
37,116
33,287
Other miscellaneous reserves (vii)
14,505
18,805
19,409
The details of the main non-controlling interests as of and for the periods ended December 31, 2025, 2024 and 2023, are as follows:
Non-controlling Interests
Equity
Companies
0.91%
6,867
7,246
349
(246)
6.45%
170,696
176,448
172,405
34,858
33,566
38,850
7.35%
11,302
12,212
13,400
10,323
12,606
12,925
42.50%
2,477
2,437
(35)
(176)
15.41%
78,624
77,365
75,747
1,643
39.09%
99,717
89,688
87,478
2,825
2,222
3,103
37.54%
3,739
4,626
(1,296)
(1,109)
Others
The details of revenue from ordinary activities and other income for the years ended December 31, 2025, 2024 and 2023, are as follows:
Energy sales
4,077,628
3,793,137
4,394,471
2,399,790
2,128,784
2,682,030
671,980
1,159,986
994,824
Unregulated customers (1)
1,567,800
816,289
1,546,916
Spot market sales
160,010
152,509
140,289
1,677,838
1,664,353
1,712,441
917,596
892,052
884,019
Business
464,768
479,893
518,448
124,015
129,234
142,881
Other consumers (2)
171,459
163,174
167,093
Other sales
367,086
286,712
607,854
Gas sales
305,126
237,090
552,319
Sales of goods and services
61,960
49,622
55,535
Revenue from other services
64,833
57,662
72,733
Tolls and transmission
3,652
2,891
1,069
Metering equipment leases
4,242
3,832
4,161
Services and Business Advisories provided (Public lighting, connections and electrical advisories)
49,954
36,188
48,214
Other services
6,985
14,751
19,289
Total Revenues
Revenue from modification of contracts with suppliers (3)
12,064
45,632
Regasification service
40,176
38,475
37,849
Reversal of contingency provisions
Income from sanctions to users
3,273
5,416
Commodity derivative income
6,702
3,467
27,347
Compensation from delayed suppliers
1,005
Income from insurance claims (4)
90,606
15,651
7,232
15,699
13,379
15,859
Total other income
During the last quarter of 2024, Enel Generación Chile completed an update of the analysis on the determination of its functional currency, concluding that it should be changed from Chilean pesos to U.S. dollars, effective January 1, 2025. This conclusion was mainly due to the fact that, beginning in 2025, the subsidiary’s main source of revenue is from the group of unregulated customer agreements that, considering the billing and collection cycles, give rise to a substantially lower exposure to exchange rate fluctuations compared with the group of regulated customers, which require considerably more time to complete the collection process.
Up to then, the Company had maintained certain transactions defined as cash flow hedges, which hedged the exchange rate risk of a portion of Enel Generación Chile's revenues directly linked to the evolution of the U.S. dollar, which were managed by obtaining financing in the latter currency and through derivative contracts (see Notes 4.g.5, 4.n, 20.3, 22.2 and 23.2).
Considering the change of functional currency contemplated for Enel Generación Chile, the accounting hedges described above lost their effectiveness and, therefore, due to the change in the risk management objective, they were discontinued prospectively. At December 31, 2024, the amount accumulated in cash flow hedge reserves, related to income directly linked to the evolution of the U.S. dollar, amounted to ThUS$657,134, before taxes and minority interests. This amount was fully recognized as lower revenue for the year 2024.
The detail of the item raw materials and consumables used for the years ended December 31, 2025, 2024 and 2023, are as follows:
Energy purchases
(1,833,017)
(2,029,524)
(2,125,564)
Fuel consumption
(376,602)
(354,616)
(638,512)
(372,069)
(348,647)
(618,508)
(4,533)
(5,969)
(20,004)
Energy transmission cost
(280,917)
(377,457)
(382,888)
Gas sales costs
(189,137)
(186,643)
(289,783)
Other variable supplies and services
(100,707)
(130,542)
(129,809)
The details of employee expenses for the years ended December 31, 2025, 2024 and 2023 are as follows:
Employee Benefits Expense
Wages and salaries
(144,872)
(153,511)
(174,809)
Post-employment benefit obligations expense
Social security and other contributions
(15,136)
(15,335)
(17,944)
Other employee expenses (*)
(13,945)
(3,116)
(11,238)
Total Employee Benefits Expenses
(*) The increase compared to the previous period corresponds to an early retirement incentive plan for employees, amounting to ThUS$13,309. In addition, for 2023, an amount of ThUS$4,405 was included for restructuring expenses and provisions.
(351,854)
(289,546)
(279,522)
Amortization
(22,177)
Distribution and Transmission
Information on Impairment Losses by Reportable Segment
Property, plant and equipment (1)
Total Reversal of impairment losses (impairment losses) recognized in profit or loss
Impairment gain and reversals from impairment losses (impairment losses) in accordance with IFRS 9 (2)
(630)
(37,053)
(18,907)
(11,988)
(1,735)
(947)
(1)See Note 16 c) item iv).
(2)See Note 9.d).
Other miscellaneous operating expense for the years ended December 31, 2025, 2024 and 2023, are as follows:
Professional, outsourced and other services
(109,793)
(92,059)
(106,420)
Repairs and maintenance
(63,929)
(65,418)
(60,673)
(31,108)
(31,434)
(26,419)
Environmental expenses
(15,311)
(10,772)
(5,222)
Administrative expenses
(11,815)
(12,071)
(10,960)
Taxes and charges
(6,599)
(6,232)
(6,490)
Leases and rental costs
(8,635)
(7,111)
(6,500)
Marketing, public relations and advertising
(2,558)
(2,940)
(3,593)
Travel expenses
(1,235)
(2,449)
(3,438)
Indemnities and fines
(1,801)
(769)
(135)
Other supplies and services
(13,262)
(17,669)
(19,955)
Write‑off of property, plant and equipment
(10,197)
(3,251)
The details of the item ‘Other gains (losses)’ for the years ended December 31, 2025, 2024 and 2023 are as follows:
Gain on sale of investment in Arcadia Generación Solar S.A. (1)
(558)
256,716
Profit on sale of corporate building (2)
1,142
Sale of Huasco Power Station (3)
4,535
Proceeds (losses) from sales of other property, plant and equipment
5,541
(444)
Gain on sale of Transmisora Eléctrica de Quillota Ltda. (5)
2,187
Gain (loss) on sale of other investments
(1)On July 12, 2023, Enel Chile signed an agreement for the sale of its subsidiary Arcadia Generación Solar S.A. to the international renewable energy company Sonnedix.
On October 24, 2023, the transfer of 99.99% of the shares held in this company was completed, and as from that date it ceased to be a subsidiary of Enel Chile and to be consolidated. The sale price for this transaction was ThUS$556,223.
(2)On February 1, 2023, the sale of the Group’s Corporate Building was completed, which included the sale of movable property, resulting in a gain of ThUS$1,142.
(3)Corresponds to the sale of the Huasco plant carried out by the Company’s subsidiary Enel Generación Chile, from which a gain of ThUS$4,535 was obtained.
(4)Additional gain related to the sale of Transmisora Eléctrica de Quillota Ltda., completed in December 2021, arising from the price adjustment process established in the purchase and sale agreement.
Finance income and costs for the years ended December 31, 2025, 2024 and 2023, are as follows:
Finance Income
Income from deposits and other financial instruments
12,452
22,162
41,199
Interests charged to customers in energy accounts and billing
23,742
23,568
27,232
Finance income per Law No.21,185 (1)
4,338
7,273
Finance income from contracts with electrical distribution companies (2)
6,119
20,346
74,654
Financial income from methodological change of the CNE (3)
18,630
Other finance income
6,463
10,264
9,485
Total finance income
Finance Costs
(51,354)
(53,693)
(37,882)
Bonds payable to the public not guaranteed
(84,007)
(92,822)
(106,152)
(24,871)
(11,990)
(11,535)
Valuation of financial derivatives for cash flow hedging
(4,192)
2,424
Financial cost by Law No.21,185 (1)
(2,949)
(3,631)
(4,005)
Financial cost from methodological change of the CNE (3)
Financial update of provisions (4)
(9,278)
(11,526)
(15,165)
Post-employment benefit obligations (5)
Debt formalization expenses and other associated expenses
(5,669)
(7,746)
(5,631)
Capitalized borrowing costs
7,009
90,350
96,971
Financial cost related companies
(35,450)
(71,193)
(68,699)
Assignment of rights and sale of accounts receivable to customers (6)
(20,544)
(20,973)
(36,280)
Trade agreements with customers
(12,283)
(28,618)
(35,225)
Interest taxes remitted abroad
(4,778)
(6,745)
(9,428)
(5,292)
Other (7)
(17,685)
(26,974)
(54,476)
Gains or loss from indexed assets and liabilities, net (*)
Foreign currency exchange differences (**)
Total finance costs
(308,893)
(247,411)
(265,075)
(237,149)
(164,462)
(105,232)
The origins of the effects on financial results for the application of adjustment units and foreign exchange gains (losses) are as follows:
Gains (losses) from Indexed Assets and Liabilities (*)
Other non-financial assets
4,939
2,042
Trade and other receivables (1)
4,414
16,983
28,598
Current tax assets and liabilities
6,081
1,238
19,054
Other financial liabilities (Financial Debt and Derivative Instruments)
612
(396)
1,433
(1,526)
(1,669)
(654)
Other non-financial liabilities
Subtotal result after adjustment
13,369
21,732
46,346
148
3,233
2,866
Deferred tax liability
(10,684)
(1,897)
(4,094)
(8,860)
Other service provisions
(697)
Personal expenses
284
405
(137)
(548)
Subtotal Hyperinflation result (2)
(16,241)
Gains from indexed assets and liabilities net
4,245
(10,943)
6,847
(20,942)
(8,423)
(2,186)
(1,987)
Trade and other receivables (3)
68,063
201,568
64,118
154,750
9,947
(95)
1,197
(79,282)
(223,012)
(63,576)
Trade and other payables (3)
(54,297)
(157,201)
5,789
Accounts payables from related entities
(90,398)
146,963
25,777
(562)
(453)
Total Foreign currency Exchange differences
F-122
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 or 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 its 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.
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: EBITDA1, Total Capex2, Profit for the Year, Total Energy Generation3, 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 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.
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 acquisition of Property, plant and equipment and Intangible assets other than goodwill.
3 Corresponds to electrical energy generated in power plant units, by technology, eliminating self-consumption in a given period.
4 Corresponds to the amount of electricity distributed, free of any losses, in a given period.
35.2 Financial information by business line
Distribution and Networks
Holdings and eliminations
Line of Business
1,927,828
2,111,719
2,187,325
850,303
672,130
611,474
(539,044)
(541,693)
(95,668)
269,980
267,233
242,639
2,827
2,707
3,353
189,117
114,821
396,214
418
19,018
74,189
546
115,156
110,148
72,019
6,073
5,152
5,480
51,326
38,408
37,077
515,295
805,172
1,040,646
830,126
655,629
564,228
40,820
34,457
47,459
950,875
844,719
686,554
3,395
28,448
(894,716)
(805,179)
(657,685)
57,840
53,553
58,075
4,407
4,884
6,527
5,874
6,963
2,392
18,264
11,876
13,203
1,129
68,060
68,291
77,115
7,257,546
7,367,340
7,722,881
2,355,246
2,221,487
2,108,249
1,051,780
934,103
957,303
21,357
2,713
11,982
146,694
265,723
653
1,562
8,409
5,102
1,019,819
1,095,383
915,069
82,467
59,578
110,108
Non-current receivables due from related parties
78,426
175,547
(78,426)
(175,547)
22,814
205,682
207,673
124,718
78,347
74,851
88,010
8,761
11,867
9,601
35,958
35,936
39,479
863,750
854,218
966,341
6,548,093
6,566,259
6,752,536
1,196,541
998,692
1,055,102
18,802
14,742
349,835
249,284
286,500
8,905
2,790
21,123
22,397
17,455
35,073
39,504
37,234
46,729
46,636
40,217
46,150
39,545
11,100
9,185,374
9,479,059
9,910,206
3,205,549
2,893,617
2,719,723
512,736
392,410
861,635
2,073,165
1,722,904
2,355,023
925,598
778,406
656,695
(525,427)
(249,852)
173,613
60,454
76,710
543,344
1,098
261,628
7,293
156,733
30,810
21,745
21,379
5,646
866
1,477
5,062
4,371
4,664
796,325
966,711
1,142,500
633,215
497,070
337,153
103,935
72,090
190,007
Current Payable to related parties
1,081,485
470,540
524,982
261,286
243,484
302,235
(970,852)
(414,662)
(299,834)
29,321
30,389
25,162
17,120
1,381
4,025
3,308
42,569
122,281
71,199
111,338
32,201
34,528
26,457
25,451
19,866
14,526
5,958
9,570
7,397
3,090,766
3,779,514
3,702,578
1,511,192
1,441,982
1,266,059
278,858
(53,170)
(90,266)
448,301
475,894
540,965
1,722,027
1,906,502
1,630,360
343,462
246,373
248,413
5,941
1,340
2,208
19,276
20,957
27,476
Trade and other payables, non-current
190
552
1,884,273
2,605,647
2,392,910
452,541
408,597
550,651
(1,475,283)
(1,994,730)
(1,763,801)
172,976
179,418
233,752
40,976
36,613
7,493
223
206,695
214,551
203,195
(6,243)
(5,916)
(6,514)
19,766
20,486
23,527
25,778
25,706
26,212
18,514
19,639
21,882
4,021,443
3,976,641
3,852,605
768,759
673,229
796,969
759,305
695,432
778,288
Equity attributable to owners of the parent
1,154,003
1,152,839
1,226,860
196,954
178,199
202,445
2,544,938
4,633,246
4,534,979
2,567,894
2,509,467
2,511,029
872,340
763,531
899,445
(429,087)
508,521
445,132
Share premiums
85,815
97,491
274
(86,118)
(86,090)
(97,803)
213,731
228,520
17,225
(300,838)
(268,775)
(305,233)
(1,270,428)
(4,360,245)
(4,104,020)
Total Liabilities and Equity
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.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
3,282,803
2,950,373
3,900,878
1,783,853
1,739,261
1,799,739
(403,926)
(464,809)
(485,479)
Revenues from third parties
2,833,116
2,511,643
3,417,919
1,760,920
1,718,112
1,778,895
68,694
(4,930)
18,323
5,215,137
Revenues from intersegment transactions
449,687
438,730
482,959
22,933
21,149
20,844
(472,620)
(459,879)
(503,803)
RAW MATERIALS AND CONSUMABLES USED
(1,735,744)
(1,955,854)
(2,473,683)
(1,474,167)
(1,554,570)
(1,573,017)
429,531
431,642
480,144
(885,135)
(1,034,326)
(1,128,875)
(1,389,122)
(1,433,695)
(1,470,448)
441,240
438,497
473,758
(2,125,565)
Transportation expenses
(258,576)
(337,673)
(345,814)
(47,988)
(58,191)
(62,071)
25,647
18,407
24,997
Other miscellaneous supplies and services
(215,431)
(229,239)
(360,482)
(37,057)
(62,684)
(40,498)
(37,356)
(25,262)
(18,611)
(289,844)
(317,185)
(419,591)
CONTRIBUTION MARGIN
1,547,059
994,519
1,427,195
309,686
184,691
226,722
25,605
(33,167)
(5,335)
20,035
23,740
30,367
18,303
13,620
4,001
3,404
(83,540)
(79,801)
(102,855)
(41,029)
(44,758)
(45,004)
(50,992)
(49,151)
(57,863)
(182,993)
(172,688)
(174,120)
(98,445)
(89,479)
(85,144)
5,195
10,826
6,208
GROSS OPERATING INCOME
1,300,561
765,770
1,180,587
188,515
64,074
109,986
(16,191)
(65,691)
(53,586)
1,472,885
764,153
1,236,987
(309,042)
(250,057)
(238,676)
(70,157)
(58,114)
(60,692)
(8,231)
(4,912)
(2,331)
Impairment losses (reversal of impairment losses) recognized in profit or loss
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9.
OPERATING INCOME
956,191
478,841
933,656
81,305
(12,947)
37,306
(26,157)
(70,595)
(56,864)
FINANCIAL RESULT
(206,477)
(130,877)
(27,999)
(36,266)
(24,753)
(26,677)
5,594
(8,832)
(50,556)
47,287
50,711
106,704
62,639
35,130
41,872
(38,182)
(2,892)
11,267
2,151
3,508
10,299
18,891
36,916
22,161
41,200
Other financial income
45,136
47,530
105,928
62,637
35,041
38,364
(48,481)
(21,783)
(25,649)
59,292
60,788
118,643
(273,286)
(170,687)
(176,012)
(98,885)
(58,135)
(66,600)
41,899
(17,628)
(51,548)
(16)
(51,350)
(37,850)
(37,881)
Secured and unsecured obligations
(35,257)
(43,423)
(57,704)
(48,750)
(49,398)
(48,449)
(92,821)
(106,153)
(238,025)
(127,264)
(118,292)
(66,585)
141,999
85,463
34,751
(194,911)
(99,936)
(150,126)
Income from indexation units
11,373
18,005
23,080
455
798
6,190
3,263
835
Foreign exchange profits (losses)
8,149
(28,906)
18,229
(475)
(2,546)
(8,139)
8,425
(11,110)
Positive
312,142
325,908
150,917
99,249
146,127
55,758
112,911
392,871
291,713
524,302
864,906
498,388
(303,993)
(354,814)
(132,688)
(99,724)
(148,673)
(63,897)
(112,562)
(384,446)
(302,823)
(516,279)
(887,933)
(499,408)
9,389
8,100
(1,312)
9,865
(1,084)
255,355
Gain (loss) from other investments
256,720
258,903
Gain (loss) from the sale of assets
7,682
(1,365)
5,233
770,482
357,601
923,622
45,039
(37,700)
9,545
(20,563)
(80,458)
146,623
(208,494)
(62,329)
(227,892)
(4,766)
10,695
7,127
3,201
14,623
561,988
295,272
695,730
40,273
(27,005)
16,672
(17,362)
(65,835)
97,225
STATEMENT OF CASH FLOWS
Net cash flows from (used in) operating activities
1,290,222
1,628,242
1,120,335
110,097
62,041
114,358
(80,641)
(68,113)
(394,528)
Net cash flows from (used in) investing activities
(410,540)
(874,695)
(702,268)
(133,217)
(72,867)
(118,014)
55,856
209,966
717,607
Net cash flows from (used in) financing activities
(878,156)
(705,201)
(185,557)
22,964
11,057
84,297
(400,643)
(937,016)
F-125
36.1. Direct guarantees
As of December 31, 2025, Enel Chile has future energy purchase commitments amounting to ThUS$16,433,707 (ThUS$16,124,880 and ThUS$12,355,119 as of December 31, 2024 and January 1, 2024, respectively).
36.2. Indirect guarantees
Debtor
Guarantee
Outstanding balance as of
Contract
Creditor of Guarantee
Guarantor
Type of Guarantee
Enel Energy Efficiency & Renewables FL (LATAM) C & D
Enel S.p.A. (*)
99,431
Up to USD 286M Facility Agreement
286,793
286,928
386,224
386,359
(*) Corresponds to a guarantee for 20% of the debt. The credit includes another guarantee with SACE (Italian Export Credit Agency) for the remaining 80%.
36.3 Litigation and Arbitration
In connection with to the litigation described above, the Group has set up provisions in the sum of ThUS$1,269 as of December 31, 2025 (see Note 25). There are other litigations that also have associated provisions but are not described in this note as individually they represent immaterial amounts. Management considers that the provisions recorded adequately cover the litigation risks and therefore does not expect that these provisions will result in additional liabilities to 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.
F-127
Other litigation of relevance is reported below:
In relation to the legal proceedings commenced by certain operators of the Northern Chile Grid (SING) (year 2017), including AES Gener SA, Eléctrica Angamos SA and Engie Energía Chile SA, against GasAtacama Chile (currently Enel Generación Chile), on October 17, 2023, a first instance judgment was issued in which the plaintiffs' claims were partially upheld. Enel Generación Chile S.A. filed the corresponding procedural appeals before the Court of Appeals of Santiago. On February 4, 2026, The Court of Appeals of Santiago dismissed the claims filed by the plaintiffs. The verdict is yet to be finalized. A very minor risk of adverse judgment is estimated.
In December 2016, a tort action was brought by Compañía Minera Arbiodo Limitada and Ingenieros y Asesores Limitada against Parque Eólico Taltal S.A. (currently Enel Green Power Chile S.A.), the National Geology and Mining Service and the Chilean Treasury, for the alleged liability in the potential economic losses caused by the failure to carry out a mining project of interest to the plaintiffs. In December 2023, the claim was accepted, only insofar as the National Geology and Mining Service and Enel Green Power Chile S.A. were ordered to pay jointly and severally to the plaintiffs the amount of ThCh$346,067,011 (ThUS$383,847) as consequential damages. The defendants filed procedural appeals before the Court of Appeals of Santiago, which are pending resolution. A very minor risk of adverse judgment is estimated.
F-128
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.
Some of the financial debt contracts contain cross default clauses.
Financial restrictions
Instrument type with restriction
Credit with a financial institution
Uncommitted line of credit
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 held by Enel Generación Chile, for any amount past due.
Any financial debt held by Enel Chile or its significant subsidiaries, 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.
Creditor
DNB Bank ASA (Administrative Agent)
Corporación Andina de Fomento, Citibank, European Investment Bank and Scotiabank Chile
BCI, Scotiabank Chile
Bank of New York Mellon (Bondholder Representative)
Registration Number
ISIN: US29278DAA37
Name of financial indicator or ratio
Cross default
Measurement frequency
Quarterly
Calculation mechanism or definition of the indicator or ratio
Debt past due higher than US$150 million of principal individually.
Debt past due
Restriction that must be fulfilled (Range, Value and Unit of measure)
Not having individual debts past due higher than US$150 million.
Not have individual debts past due.
Indicator or ratio determined by the company
There are no outstanding debts for an individual amount higher than US$150 million
There are no outstanding debts for an individual amount higher than US$150 million.
Compliance YES/NO
Accounts used in the calculation of the indicator or ratio
Series H and M Bonds
Any financial debt held by Enel Generación Chile or its Chilean subsidiaries, for any amount in default, and that the principal amount of the debt giving rise to the cross default exceeds US$30 million in an individual debt.
Any financial debt held by Enel Generación Chile, for any amount in default, and that the principal amount of the debt giving rise to the cross default exceeds US$50 million in an individual debt.
Any financial debt held by Enel Generación Chile, for any amount in arrears.
Any financial debt held by Enel Distribución Chile, for any amount in arrears.
Bank of New York Mellon (Bondholders' Representative)
Banco Santander Chile (Bondholders' Representative)
Banco Santander Chile and Scotiabank Chile
ISIN: US29244TAC53; US29244TAB7; US29244TAA9
CMF Securities Registry Registration No. 317 for Series H and No. 522 for Series M
Debt in arrears greater than US$30 million principal amount on an individual basis.
Debt in arrears greater than US$50 million principal amount on an individual basis.
Not to have individual debts in arrears in excess of US$30 million.
Not to have individual debts in arrears in excess of US$50 million.
There are no individual debts in arrears exceeding US$30 million.
There are no individual debts in arrears exceeding US$50 million.
F-130
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.
Series H Bonds
A ratio between Financial Obligations and Total Capitalization must be maintained of less than or equal to 0.64.
Maintain Minimum Equity of Ch$761,661 million (ThUS$764,367), a limit that is updated at the end of each fiscal year, as established in the contract.
Maintain a Financial Expense Coverage ratio of greater than or equal to 1.85.
Maintain a Net Active Position with Related Companies not exceeding the equivalent amount in Chilean pesos, legal tender, of US$500 million, according to the exchange rate observed on the date of its calculation.
Registration with the CMF Securities Registry No. 317 for Series H and No. 522 for Series M
Registration with the Securities Registry with CMF No. 317
Consolidated Indebtedness Level
Equity Attributable to the Parent
Financial Expense Coverage rate
Net Active Position with Related Companies
Financial Obligations related 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 Receivables due from Related Parties of Current and Non1Current Assets and ii) the sum of Payables due to Related Parties, 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.
Maintain Minimum Equity of Ch$761,661 million (ThUS$839,638), a limit that is updated at the end of each fiscal year, as established in the contract.
0.15
Ch$2,516,179 million (ThUS$2,773,780)
7.90
US$160.11 million
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, 2025, 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. Additionally, Management is not aware of any facts or circumstances indicating that the Company may have difficulties in meeting these covenants during or after the reporting period.
F-131
Enel Chile’s personnel, as of December 31, 2025, and December 31, 2024, is as follows:
1,772
1,832
1,951
1,985
Argentina (1)
2,006
The following Group companies have received sanctions from administrative authorities:
In relation to the sanctions described above, the Group has established provisions for ThUS$33,862 as of December 31, 2025 (see Note 25). There are other sanctions that also have associated provisions but are not described in this note since they individually represent immaterial amounts. The management of the Company considers that the provisions recorded are adequate to cover the risks resulting from sanctions, and therefore do not expect additional liabilities other than those already specified.
F-133
Environmental expenses as of December 31, 2025, 2024 and 2023, are as follows:
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 power plant
Waste Management
In progress
Environmental Sanitation
Vegetation control in MT/BT
Pruning of trees near the media network and low voltage.
9,066
528
12-31-2026
9,594
12,898
Environmental improvements
Urban tree planting project (Q2)
Waste recovery initiative (Q4)
Asbestos storage facility project (Q2)
Environmental space at the CEO center (Q2)
Environmental expenditures combined-cycle power plant
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.
39,765
38,754
11,711
Environmental expenditures Thermal Power Plants (TP)
Studies, monitoring, laboratory analyses, and collection and final disposal of solid waste at thermoelectric power plants (C.T.)
4,217
2,633
2,560
Environmental expenditures Hydroelectric Power Plants (HP)
Waste management
Contracts for the removal of hazardous and non-hazardous waste
442
Water analysis
Monitoring and analysis of drinking water and sewage
Sewage treatment plant
Wastewater treatment
Contract – Legal Requirements
Environmental and sectorial permit management contract.
Outsourced services
Other services (contracts with third parties)
463
Domestic waste removal
Household waste collection contract (municipal collection fee)
Bird collision monitoring services contracts
Bird collision monitoring contracts
Environmental sanitation
Contracts for vector control, deratization, disinfection.
Campaigns and studies
Environmental monitoring contracts (avian collision, flora and fauna, archaeology, etc.)
631
56,917
43,075
15,311
560
57,477
29,499
Environmental materials
SEF STANDARDIZATION PROJECT (CAPEX)
Underground Networks Interaction Project between Enel and Metrogas
649
Improvements environmental impact
Urban tree planting project (2T)
Waste recovery initiative (4T)
Asbestos Storage Project (2T)
MA Space in the CEO (2T)
Environmental expenses, and certifications, Coal Power Plants (CP)
The main expenses incurred are: Investments, improvements and work performed 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.
10,135
7,596
2,539
1,576
Environmental expenses, adaptations and certifications, Thermal Power Plants (TP)
Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (TP)
1,612
1,162
948
Environmental expenses, Hydroelectric Power Plants (HP)
Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (HP)
Contracts for vector control, deratization, disinfection
Campaigns and Studies
Contracts for Environmental Monitoring ( Flora and Fauna- Archeology, others)
Buy environmental materials (containers, spill kit, others)
Household waste removal
Household / domestic waste removal contract (payment of municipal retreat)
Environmental Travel
Tickets - accommodation and travel allowance for site visits to facilities
Legal requirements contract
Rent/vehicle expenses
Vehicle rental for environmental trips (field visits / Plants)
Bird collision monitoring contract
Bird Collision Monitoring Contract
Contracts for removal of hazardous and non-hazardous waste
Contracts for Environmental Monitoring (Birds Collision - Flora and Fauna - Archeology, others)
388
Permitting framework agreement
Management contract for environmental and sectoral permits
Household / domestic waste removal contract
18,817
8,046
10,772
11,693
30,510
F-135
Materials Environment
Improvements in the MT network
Replacement underground transformers by Technical Standard (PCB)
275
700
1,442
2,142
879
2,132
428
Contract for removal and cleaning of pits and sewage
Legal requirement contract
Wildlife monitoring
Contracts for Environmental Monitoring (Wildlife)
Archaeological monitoring
Monitoring of archaeological sites
Noise monitoring
Monitoring and analysis of potable water and wastewater
Purchase of environmental materials (containers, anti-leak kits, others)
Parque Eolico Talinay Oriente S.A.
Contracts for Environmental Monitoring (Birds - Flora and Fauna - Archaeology, etc.)
6,905
1,717
5,222
2,656
9,561
F-136
As of December 31, 2025, December 31, 2024, and January 1, 2024, summarized financial information of the Company’s principal consolidated subsidiaries prepared under IFRS is as follows.
Financial
Statements
Total Assets
Non-Current Liabilities
Total Equity and
Raw Materials andConsumables Used
ContributionMargin
Operating
Income
IncomebeforeTaxes
Total Comprehensive Income
Consolidated
851,097
2,368,902
3,219,999
929,500
1,517,263
773,236
1,783,852
309,685
188,514
81,304
45,038
40,272
69,304
109,576
Separate
1,542,591
2,891,709
4,434,300
1,009,538
617,732
2,807,030
3,034,642
(2,195,782)
838,860
693,327
614,983
(73,163)
690,170
(149,909)
540,261
(4,809)
535,452
833,283
2,352,063
3,185,346
898,357
1,516,723
770,266
1,773,201
(1,469,388)
303,813
184,166
79,229
(36,641)
42,588
(4,252)
38,336
69,768
108,104
90,860
155,618
246,478
60,025
32,722
153,731
210,418
(7,206)
203,212
193,823
186,918
5,424
192,342
(51,932)
140,410
91,590
105,395
196,985
100,111
119,398
(22,524)
59,316
(39,404)
19,912
(3,161)
(9,305)
(12,466)
(10,403)
(1,642)
(12,045)
11,904
2,258
14,162
4,113
9,960
9,026
(7,881)
1,145
(2,703)
(3,149)
(3,083)
(369)
(3,452)
1,068
(2,384)
Enel Mobility Chile SPA
2,440
10,769
13,209
15,843
(2,634)
(824)
1,253
(234)
(660)
(762)
(1,423)
(1,393)
(184)
(1,577)
75,839
467,903
543,742
41,493
6,373
495,876
60,400
(22,750)
37,650
29,089
(1,217)
1,619
(112)
180,456
81,373
261,829
11,194
24,417
226,218
16,613
15,087
11,686
10,013
(2,786)
7,227
Enel Green Power Chile S.A
163,463
4,217,308
4,380,771
971,399
2,404,016
1,005,356
626,251
(158,969)
467,282
372,722
153,653
(147,663)
(3,988)
1,807
3,808
389,146
4,281,131
4,670,277
993,473
2,440,443
1,236,361
633,961
(118,202)
515,759
413,498
154,291
(138,750)
16,295
(6,653)
9,642
1,813
11,455
Grupo Enel Generación Chile
1,592,111
2,976,415
4,568,526
1,133,121
650,323
2,785,082
3,181,163
(2,142,404)
1,038,759
887,065
801,902
(67,740)
754,176
(201,841)
552,335
(9,947)
542,388
FinancialStatements
Total Equity andLiabilities
Gross Operating Income
2,221,489
2,893,619
778,405
1,441,983
673,231
(1,554,569)
184,692
(2,866)
(29,871)
1,764,103
2,938,084
4,702,187
1,098,514
856,968
2,746,706
4,702,188
3,138,498
(2,479,170)
659,328
528,678
468,214
(29,584)
592,180
(87,156)
505,024
192,858
697,882
661,598
2,208,684
2,870,282
767,459
1,441,947
660,876
1,734,339
(1,549,787)
184,552
64,290
(11,656)
(25,088)
(36,744)
10,256
(26,488)
(2,861)
(29,349)
93,036
159,190
252,226
51,691
34,431
166,103
252,225
263,976
(17,342)
246,634
237,890
230,568
4,024
234,591
(63,136)
171,455
71,274
79,846
151,120
73,655
87,923
(10,458)
50,196
(27,485)
22,711
3,156
2,173
(15,124)
(12,950)
3,727
(9,223)
(9,204)
16,996
2,553
19,549
6,808
12,321
19,548
3,257
(2,803)
(1,388)
(1,598)
(1,442)
(1,512)
(2,954)
(29)
(2,983)
2,371
8,214
10,585
11,641
(1,055)
10,586
(578)
(1,105)
(595)
(2,108)
(99)
(2,207)
52,868
487,326
540,194
38,797
6,774
494,623
56,327
(16,266)
40,061
34,291
7,557
13,353
(2,431)
10,922
62,851
73,773
168,231
85,808
254,039
10,610
24,863
218,566
14,064
(1,396)
12,668
8,552
7,224
7,696
(2,012)
5,684
27,709
33,393
165,051
4,256,851
4,421,902
572,650
2,849,648
999,604
650,689
(184,237)
466,452
374,370
192,525
(120,097)
72,428
(20,652)
51,776
124,986
176,762
356,366
4,345,940
4,702,306
592,274
2,887,505
1,222,526
4,702,305
653,462
(137,811)
515,651
417,214
197,929
(105,316)
92,322
(24,862)
67,460
148,999
216,459
1,811,614
3,013,024
4,824,638
1,186,433
891,182
2,747,025
4,824,640
3,263,370
(2,360,563)
902,807
766,426
698,781
(25,561)
683,149
(150,292)
532,857
196,569
729,426
2,108,250
2,719,724
656,696
(1,573,018)
226,721
37,305
9,544
16,671
21,739
1,869,472
3,297,128
5,166,600
1,428,818
997,226
2,740,555
5,166,599
3,683,387
(2,967,532)
715,855
571,286
501,550
52,028
742,681
(132,204)
610,477
(106,587)
503,890
600,902
2,095,499
2,696,401
644,659
1,266,028
785,713
2,696,400
1,794,317
(1,571,309)
223,008
107,848
33,975
(25,711)
7,180
7,523
14,703
5,067
19,770
103,951
177,114
281,065
57,442
41,362
182,261
259,215
(9,309)
249,906
239,865
231,817
8,169
239,986
(64,186)
175,800
Arcadia Generación Solar S.A. (1)
51,307
(1,082)
50,225
36,340
16,530
680
17,209
(7,112)
10,097
10,052
20,149
94,784
124,696
219,480
121,797
99,660
(1,977)
55,325
(21,532)
33,793
16,137
14,704
(50,900)
(36,196)
10,083
(26,113)
(26,150)
23,623
512,912
536,535
42,240
11,751
482,544
54,608
(13,771)
40,837
31,892
5,229
(1,120)
4,110
(1,440)
2,670
12,349
15,019
157,552
90,561
248,113
8,934
26,805
212,374
16,688
(1,454)
15,234
11,260
3,219
11,508
(3,569)
7,939
5,532
13,471
147,576
4,218,441
4,366,017
802,831
2,617,765
945,420
4,366,016
634,753
(248,647)
386,106
290,103
176,086
(97,546)
78,540
(19,185)
59,355
25,492
84,847
303,073
4,339,862
4,642,935
828,326
2,662,412
1,152,196
4,642,934
638,354
(201,932)
436,422
333,255
183,760
(88,875)
94,950
(24,390)
70,560
30,218
100,778
1,919,559
3,363,969
5,283,528
1,559,789
1,038,190
2,685,549
3,807,867
(2,845,584)
962,283
810,992
733,367
60,197
811,463
(196,390)
615,073
(106,030)
509,043
Between January 1, 2026 and the date of issuance of these consolidated financial statements, we are not aware of any other financial or events that could significantly affect the financial position and results presented in this document.
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:
U.F.
158,496
13,411
38,372
902,353
445,444
9,277
34,835
17,699
11,187
56,824
74,242
13,211
38,416
1,260,248
921,795
18,612
5,813
8,231
109,245
994,007
270,788
21,842
862,154
40,039
4,400,043
3,349,469
13,924
Right-of-use asset
374,282
1,044
111,514
16,438
TOTAL NON CURRENT ASSETS
2,574
6,165,869
4,476,994
14,598
40,990
7,426,117
5,398,789
23,149
14,614
9,317
10,271
128,287
23,915
5,462
954,194
535,601
4,449
27,651
10,835
38,347
26,209
69,338
10,156
1,012
5,500
1,451,315
770,994
11,785
2,562
143,174
5,875
28,110
63,276
1,071,984
32,706
113,845
180,368
852,363
3,717,998
3,846,970
14,725
221,144
31,916
7,813
119,682
6,003
249,331
5,086,824
5,164,059
14,903
254,831
6,538,139
5,935,053
19,598
17,465
65,191
12,013
3,483
78,926
31,080
676
6,108
1,418,293
227,871
6,088
36,909
14,320
715
14,547
45,853
5,712
84,116
8,361
10,347
2,179,382
491,902
20,908
2,096
11,132
271,667
35,053
402,769
592,457
28,839
127,927
94,265
968,335
3,919,024
3,877,034
13,802
248,011
37,498
13,539
7,697
62,693
25,858
285,251
5,838,253
4,643,293
13,939
295,598
8,017,635
5,135,195
28,605
14,531
LIABILITIES
Brazilian Real
49,641
272,441
Current lease liability
34,966
100,224
1,100,200
319,112
13,371
568
Current payable to related parties
104,291
190,873
76,755
30,599
105,077
4,953
63,451
184,831
1,407,659
789,150
91,128
137,682
2,032,646
Non-current lease liability
328,537
35,169
205,893
8,282
154,621
45,831
466,219
442,936
3,969,028
651,050
1,850,595
4,758,178
93,761
40,133
24,952
1,729
81,184
964,131
472,537
17,809
186,626
72,395
51,052
482
185,451
4,291
54,498
9,466
150,006
1,295,473
713,836
91,933
253,417
9,210
6,043
180,798
35,233
183,012
25,623
467,386
4,441,480
403,423
1,762,859
5,155,316
97,976
653,255
25,253
407
1,746
10,603
1,259,837
387,462
11,487
7,652
184,012
335,707
28,622
177,578
4,959
37,688
9,011
1,672
83,776
1,511,491
1,239,124
350,612
223,599
1,947,726
269,417
1,104
1,271
6,305
332,979
345,987
201,369
39,876
35,566
70,607
493,016
702,301
3,676,749
576,792
2,213,792
4,915,873
356,917
F-140
-Trade and other receivables by maturity:
CurrentPortfolio
1 - 30 dayspast due
31 - 60 dayspast due
61 - 90 dayspast due
91 - 120 dayspast due
121 - 150 dayspast due
151 - 180 dayspast due
181 - 210 dayspast due
211 - 250 dayspast due
More than251 days past due
Trade and Other Receivables
1,083,880
37,856
14,688
9,943
10,941
6,485
6,716
5,123
6,926
165,114
Allowance for impairment
(4,788)
(944)
(2,748)
(3,285)
(3,204)
(3,418)
(3,474)
(3,288)
(4,487)
(85,946)
(115,582)
(1,764)
Lease receivables, gross
(529)
(2,517)
13,957
(13,957)
1,233,243
36,912
11,940
6,658
7,737
3,067
3,242
1,835
2,439
79,168
1,279,539
30,614
11,893
7,651
5,539
8,255
5,522
4,029
3,336
151,536
(8,239)
(544)
(1,708)
(1,807)
(1,695)
(1,955)
(2,191)
(2,864)
(2,498)
(59,706)
(83,207)
(1,733)
(1,123)
52,254
12,699
(12,699)
1,341,851
30,070
10,185
5,844
3,844
6,300
3,331
1,165
91,830
1,291,426
23,601
15,037
9,868
7,966
7,991
7,075
6,191
7,245
251,324
(23,364)
(426)
(1,729)
(1,857)
(2,327)
(2,705)
(3,685)
(3,487)
(34,281)
(75,105)
(13,770)
76,160
13,083
(13,032)
1,367,725
23,175
13,793
8,139
6,109
5,664
4,370
2,506
3,758
217,094
-By type of portfolio:
January 01, 2024
Portfolio with no renegotiated terms
Portfolio with renegotiated terms
Total Gross Portfolio
Number of
Amount
customers
Up-to-date
1,432,920
1,044,899
135,777
1,033,575
1,568,697
2,078,474
1,425,035
1,247,526
157,411
1,100,944
1,582,446
2,348,470
1,452,955
1,229,582
38,745
945,716
1,491,700
2,175,298
1 to 30 days
70,242
36,808
131,722
1,048
201,964
30,443
29,639
4,343
34,786
16,209
22,089
1,025
1,512
17,234
31 to 60 days
47,323
14,261
36,087
427
83,410
1,920
11,421
32,830
14,210
1,425
34,255
61 to 90 days
10,626
9,595
9,716
20,342
7,272
42,021
9,368
43,750
91 to 120 days
4,564
10,679
5,252
9,816
24,411
5,257
4,834
29,245
34,200
7,582
1,502
384
35,702
121 to 150 days
3,262
7,826
35,598
7,463
43,061
32,473
7,674
33,719
151 to 180 days
2,093
6,498
218
5,648
5,313
6,783
856
292
181 to 210 days
1,921
4,914
2,665
4,586
29,006
35,332
608
5,960
953
231
1,561
211 to 250 days
1,430
6,691
3,044
235
4,474
39,502
6,062
45,564
1,617
6,924
917
2,534
More than 251 days
268,570
160,015
54,401
5,099
322,971
290,284
147,844
123,928
3,692
414,212
469,681
248,499
152,571
622,252
1,842,951
1,300,612
386,783
1,041,654
2,229,734
2,342,266
1,877,344
1,469,273
310,723
1,107,572
2,188,067
2,576,845
2,082,881
1,558,671
200,969
952,925
2,283,850
2,511,596
Portfolio in Default and in Legal Collection Process
clients
Notes receivable in default
Notes receivable in legal collection process (*)
3,753
7,107
(*)Legal collections are included in the portfolio past due.
Allowance for portfolio with no renegotiated terms
30,514
Allowance for portfolio with renegotiated terms
6,273
4,516
Recoveries for the period
36,787
18,146
Total detail by type of transaction
Total detail by type of operation
Number and Amount of Transactions
Last Quarter
Year-to-date
Allowance for impairment and recoveries:
Number of Transactions
13,639
29,515
4,950
139,703
Amount of transactions
9,763
3,188
F-142
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:
Trade receivables
Currentbalances portfolio
1-30 days past due
31-60 days past due
More than 251days past due
More than 365days past due
Trade receivables, Generation and Transmission
374,402
5,129
3,213
3,460
5,691
45,917
438,345
- Large customers
- Institutional customers
- Other
(168)
(117)
(119)
(207)
(2,823)
(4,221)
Unbilled services
329,784
Billed services
44,618
108,561
Trade receivables, Distribution
709,478
32,727
11,475
9,916
7,481
6,459
6,263
5,110
6,912
16,322
97,184
909,327
994,592
- Mass-market customers
636,909
21,869
8,040
7,124
5,567
5,898
5,174
3,958
5,423
14,517
78,538
793,017
994,231
60,215
6,978
2,065
1,543
1,313
823
1,050
9,910
85,238
12,354
3,880
1,370
1,249
977
755
8,736
31,072
(776)
(2,631)
(3,284)
(3,085)
(3,471)
(11,524)
(71,392)
(111,361)
(1,761)
317,537
980,585
391,941
591,790
14,007
Total trade receivables, gross
143,101
Total Allowance for impairment
(11,731)
(74,215)
Total trade receivables, net
1,079,092
10,282
68,886
715,609
5,465
3,347
309
464
67,881
794,242
6,022
(1,941)
(10)
(2,114)
(4,380)
685,200
30,409
109,042
563,931
25,151
11,343
7,240
5,525
4,907
5,213
3,973
3,200
12,830
70,359
713,672
1,062,909
520,590
19,095
8,385
6,206
4,811
4,591
4,936
2,904
9,225
55,506
639,935
1,062,511
29,879
3,504
4,864
44,118
13,462
2,552
1,552
269
194
9,989
29,619
(6,298)
(379)
(1,693)
(1,794)
(1,848)
(2,182)
(2,863)
(2,494)
(8,203)
(49,379)
(78,828)
(1,726)
490,243
963,605
73,688
25,150
223,429
18,374
1,279,540
30,616
11,892
5,538
8,254
4,030
13,294
138,240
(2,865)
(8,213)
(51,493)
(83,208)
1,271,301
30,072
10,184
5,845
3,843
6,299
5,081
Thousands of U.S. dollars - ThUS$
847,772
1,468
498
1,712
9,152
119,440
981,557
2,548
847,525
118,981
980,851
459
706
(93)
(2,181)
(5,864)
831,240
16,532
150,317
443,654
22,133
14,565
9,646
7,166
7,492
6,171
5,533
13,980
108,752
646,167
881,324
403,889
15,513
9,886
6,074
6,031
4,851
11,541
85,590
561,958
875,471
23,779
2,026
530
365
547
9,008
41,157
4,008
15,986
2,709
2,653
1,244
562
1,096
811
1,157
788
1,892
14,154
43,052
1,845
(19,795)
(420)
(1,242)
(1,728)
(1,854)
(2,325)
(3,684)
(3,480)
(8,565)
(23,443)
(69,241)
(13,764)
377,593
848,767
66,061
14,564
7,167
108,751
268,574
32,558
9,869
7,990
23,132
228,192
(8,658)
(25,624)
1,268,062
8,140
5,663
2,507
14,474
202,568
Because not all of the Company’s commercial databases in the 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:
F-144
Type of Portfolio
Current balances Portfolio
Total current
Total non-current
GENERATION AND TRANSMISSION
51,608
DISTRIBUTION
675,557
31,679
11,048
9,568
7,219
6,226
6,045
6,677
108,407
867,327
604,695
20,846
7,621
6,777
5,305
5,666
4,956
3,750
5,188
88,344
753,148
59,498
6,954
2,058
10,960
84,490
11,364
3,879
1,369
1,248
267
976
9,103
29,689
33,921
42,000
32,213
4,710
39,867
749
990
389
1,384
Total gross portfolio
1 - 30 days
past due
31 - 60 days
61 - 90 days
91 - 120 days
121 - 150 days
151 - 180 days
181 - 210 days
211 - 250 days
More than 251
days past due
68,345
525,063
24,175
10,871
6,860
5,243
4,699
5,004
3,776
2,987
79,498
668,176
832
483,715
18,158
7,928
5,859
4,552
4,395
4,727
3,489
2,691
61,381
596,895
29,300
3,472
1,392
423
8,198
43,477
12,048
2,545
1,551
9,919
27,804
38,868
208
3,691
45,496
1,062,077
36,875
458
3,350
43,041
1,061,679
1,414
1,815
151,534
847,771
471
799
1,711
128,592
981,553
847,524
128,133
980,847
378,148
20,620
13,738
9,146
6,782
7,177
5,940
119,907
573,454
343,665
14,498
9,230
7,238
5,694
5,719
5,901
4,621
4,335
94,688
495,589
966
22,285
3,897
2,014
664
362
9,555
39,628
12,198
2,225
2,494
1,156
15,664
38,237
65,507
1,513
828
72,717
880,208
60,224
1,015
656
289
2,443
66,368
874,505
1,494
1,532
3,858
3,789
484
4,817
F-145
APPENDIX 2.2 ESTIMATES OF SALES AND PURCHASES OF ENERGY, POWER AND TOLL
Energy and
Capacity
Tolls
STATEMENT OF FINANCIAL POSITION
774,922
105,604
1,297,546
107,853
1,230,244
65,761
Trade and other receivables, non-current
911,224
855,454
1,106,548
Total Estimated Assets
1,686,146
2,153,000
2,336,792
288,862
32,024
209,649
29,271
113,298
25,279
892,767
795,436
651,931
Total Estimated Liabilities
1,181,629
1,005,085
765,229
STATEMENT OF INCOME
383,539
1,053,990
113,878
223,241
31,538
327,620
30,906
APPENDIX 3 DETAIL OF DUE DATES OF PAYMENTS TO SUPPLIERS
Goods
Services
Suppliers with Payments Up-to-Date
Up to 30 days
128,121
833,083
438,638
1,399,842
207,663
775,730
345,939
1,329,332
125,405
837,978
254,724
1,218,107
Between 31 and 60 days
246
6,125
1,961
8,110
10,194
8,090
31,274
49,558
Between 61 and 90 days
2,137
819
3,773
42,625
12,825
57,913
113,363
19,878
19,050
203,548
242,476
Between 91 and 120 days
Between 121 and 365 days
More than 365 days
678,621
130,483
833,947
1,424,999
2,389,429
256,413
788,579
1,374,954
2,419,946
155,477
865,520
1,168,167
2,189,164
Average payment period for accounts up-to-date
Suppliers Details
Suppliers for energy purchase
263,650
1,413,515
1,677,165
259,192
1,301,258
1,560,450
223,901
792,527
1,016,428
Suppliers for the purchase of fuels and gas
5,347
437,005
151,445
339,493
61,315
350,250
411,565
Payables for the purchase of assets
125,136
11,484
136,620
104,968
73,696
178,664
94,162
375,640
469,802