Earnings release
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October 29, 2025 ENGIE ENERGÍA CHILE S.A. (“ECL”) is engaged in the generation, transmission and supply of electricity and the transportation of natural gas in Chile. ECL is the fourth largest electricity generation company in Chile and one of the largest electricity generation companies in the northern segment of the SEN national grid (formerly known as SING). As of September 30, 2025, ECL accounted for 8% of the SEN’s installed capacity. ECL primarily supplies electricity to large mining and industrial customers, and it also supplies electricity to distribution companies throughout Chile. ECL is currently 59.99% indirectly owned by the French company, ENGIE S.A. The remaining 40.01% of ECL’s shares are publicly traded on the Santiago stock exchange. For more information, please refer to www.engie.cl. ENGIE ENERGÍA CHILE REPORTED EBITDA OF US$ 159 MILLION AND NET INCOME OF US$ 23 MILLION IN THE THIRD QUARTER OF 2025. EBITDA REACHED US$521 MILLION IN THE FIRST NINE MONTHS OF 2025, A 23% INCREASE COMPARED TO THE SAME PERIOD OF 2024. THE THIRD QUARTER REFLECTED A GOOD OPERATING RESULT DUE TO THE AVAILABILITY OF OUR GENERATION PLANTS AND LOWER MARGINAL COSTS , ACCOMPANIED BY A DECREASE IN GENERATION COSTS EXPLAINED BY LOWER FUEL PRICES. STRONG OPERATING RESULTS HAVE CONTRIBUTED TO ONGOING RECOVERY IN LEVERAGE AND LIQUIDITY RATIOS THAT HAVE IN TURN ALLOWED THE COMPANY TO CONTINUE WITH ITS AMBITIOUS INVESTMENT PLANS AND DECARBONIZATION PROCESS. • Operating revenues amounted to US$500.6 million in the third quarter of 2025, a 12% increase compared to the third quarter of 2024, mainly due to increased revenue from energy and capacity sales. • EBITDA amounted to US$159 million in the third quarter of 2025, mainly due to the increase in the electricity margin. • Net Results amounted to US$ 23 million in the third quarter of 2025, primarily due to improved operating results. • The company maintains its FY2025 guidance range for EBITDA at US$ 650 – 700 million and its CAPEX range at US$ 900 – 975 million. The resulting ND/EBITDA ratio is 3.3x.1 1 For more details on guidance, see page 29. 3Q24 3Q25 Var % 9M24 9M25 Var% Total operating revenues 447.6 500.6 12% 1,381.1 1,598.2 16% Operating income 92.6 114.2 23% 314.6 403.0 28% EBITDA 129.5 159.0 23% 424.0 520.6 23% EBITDA margin 28.9% 31.8% 10% 30.7% 32.6% 6% Total non-operating results (22.7) (29.9) 32% (35.0) (65.0) 86% Net income attributed to controlling shareholders 50.5 23.0 -55% 201.0 208.5 4% Earnings per share (US$/share) 0.05 0.02 0.19 0.20 Total energy sales (GWh) 3,139 3,189 2% 9,424 9,594 2% Total net generation (GWh) 1,335 2,128 59% 3,918 5,350 37% Energy purchases on the spot market (GWh) 1,026 212 -79% 3,010 1,668 -45% Energy purchases - back up (GWh) 859 877 2% 2,645 2,709 2% Financial Highlights (in US$ millions)
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2 Contents HIGHLIGHTS ............................................................................................................................................................... 3 SUBSEQUENT EVENTS ............................................................................................................................. 3 THIRD QUARTER OF 2025 ....................................................................................................................... 3 SECOND QUARTER OF 2025 .................................................................................................................... 4 FIRST QUARTER OF 2025 ......................................................................................................................... 5 INDUSTRY OVERVIEW ........................................................................................................................................... 5 Marginal Costs............................................................................................................................................... 5 Fuel prices ...................................................................................................................................................... 6 Generation ....................................................................................................................................................... 6 Management’s Discussion and Analysis of Financial Results ....................................................................................... 8 Third quarter of 2025 compared to third quarter of 2024 and second quarter of 2025 .................................... 8 Operating Revenues .......................................................................................................................... 8 Operating Costs ................................................................................................................................. 9 Electricity Margin ........................................................................................................................... 10 Operating Results ............................................................................................................................ 11 Financial Results ............................................................................................................................. 11 9M2025 compared to 9M2024 ...................................................................................................................... 12 Operating Revenues ........................................................................................................................ 12 Operating Costs ............................................................................................................................... 13 Operating results ............................................................................................................................. 14 Financial Results ............................................................................................................................. 15 Liquidity and Capital Resources ................................................................................................................... 16 Cash Flow from Operating Activities ............................................................................................. 16 Cash Flow Used in Investing Activities .......................................................................................... 17 Cash Flow from Financing Activities ............................................................................................. 17 Contractual Obligations .................................................................................................................. 18 Dividend Policy ............................................................................................................................................. 20 Risk management policy ............................................................................................................................... 21 OWNERSHIP STRUCTURE AS OF SEPTEMBER 30, 2025 ................................................................................... 22 Number of shareholders: 1,723 .................................................................................................................................... 22 APPENDIX 1 .............................................................................................................................................................. 23 PHYSICAL DATA AND SUMMARIZED QUARTERLY FINANCIAL STATEMENTS ........................ 23 Physical Sales .................................................................................................................................. 23 Quarterly Income Statement ........................................................................................................... 24 Quarterly Balance Sheet .................................................................................................................. 25 Main Balance Sheet Variations ....................................................................................................... 25 APPENDIX 2 .............................................................................................................................................................. 27 Financial information ...................................................................................................................... 27 Financial Ratios .............................................................................................................................. 27 ENGIE Energía Chile’s guidance 2025 ....................................................................................................................... 29 CONFERENCE CALL 9M25 ..................................................................................................................................... 30
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3 HIGHLIGHTS SUBSEQUENT EVENTS • Preliminary technical tariff report : In Chile, the electricity pricing system seeks to reflect efficient costs, guarantee stability for regulated customers and balance short - and long -term signals. The auth ority sets the "average node price" every six months to establish the tariff that distributors charge final consumers for the concept of generation. In this context, the National Energy Commission issued Exempt Resolution No. 633, dated October 14, 2025, approving the Preliminary Technical Report (ITP) fo r the setting of the Average Node Price for the first half of 2026. Among others, this ITP report contemplates corrections or amendments, in accordance with the provisions of Article 17 of Exempt Resolution No. 379, in relation to the valuation that the authority made of the Billing Differences (“diferencias de facturación” ), specifically regarding a methodological error related to the inflation effect, when applying the variation of the CPI and, jointly, the current interest rate for non- adjustable operations in national currency, starting from the Supreme Decree No. 7T (2024) and the successive fixations of the Average Node Price referred to in Article 158 of the General Law of Electric Services (LGSE). The ITP was available for comments until October 24. Subsequently, in accordance with current regulations, the CNE will address the comments and publish the final report in November, which will serve as the basis for the Ministerial Decree that will set the prices applicable to regulated customers. Such decree shall be binding once published in the Official Gazette, and may go --before or after its publication-- through the “Toma de razón” or acknowledgment procedure by the Office of the Comptroller of the Republic. The ITP mentions figures that would preliminarily have a negative effect resulting from the correction in the interest rate for a value of CLP 25,828,322,770.74 for ENGIE Energía Chile and CLP 169,566,213.62 for Eólica Monte Redondo. • New US$400 million term loan facility: On October 15, 2025, Engie Energía Chile entered into a Green Senior Unsecured A/B Loan Facility with the Corporación Andina de Fomento ("CAF"), by virtue of which CAF made available to Engie a non -revolving financing facility for a total amount of US $ 400 million. The financing is structured in two tranches: (i) Tranche A, for an amount of US$250 million maturing in 2032, and (ii) Tranche B, in an amount of US$150 million maturing in 2029. The funds will be used to finance renewable energy and storage projects, which meet the eligibility criteria provided for in the Financing Agreement . • Total arbitration: On October 21, ENGIE and Total Energies agreed on the terms and conditions under which the latter will pay ENGIE the compensation determined by the arbitral tribunal plus interest. The amount was disclosed in the Material Fact submitted to the CMF on June 18, 2025. These terms & conditions, among others, stipulate that the outstanding amount owed will be primarily offset against the price of certain LNG c argoes during 2025 and 2026 under the existing SPA entered between the parties. If th e delivery of these LNG c argoes does not materialize, the amounts owed will be paid in cash together with applicable interest where warranted . THIRD QUARTER OF 2025 • BESS Tocopilla storage Project: The BESS Tocopilla project reached a key milestone with the energization of the last medium -voltage circuit on September 29. With this milestone, and the commissioning of the power transformer last August, the project’s energization was completed, representing a decisive step tow ard the start of its commercial operation. With an installed capacity of 116 MW and 660 MWh distributed in 240 batteries and 30 PCS, the asset will become Engie Chile’s largest project of its kind to be directly connected to the power grid. BESS Tocopilla is located on the land that previously housed the coal and fuel oil units of the Tocopilla Thermal Complex, representing a relevant driver for the country's energy transition. • ENGIE Chile’s first local bond issue. In an Essential Fact Notice issued on September 3, ENGIE Chile reported its first placement of green bonds in the national market for UF 3,000,000. The bond is a 20-year transaction, which makes it the longest-term bond issue in the company's history, with a coupon rate of 3.60% per annum and a placement rate of 3.57% per annum. This rate represents a spread of 1.02% over a benchmark bond of the Central Bank of Chile, which is the lowest recorded for a placement by an AA- issuer at that term in the last five
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4 years. With Scotiabank as financial advisor and placement agent, a total demand of UF 6.7 million was achieved, which represented an oversubscription of 2.3 times. • Transmission expansion works: With the enactment of the Energy Transmission Law No. 21,721 , a relevant regulatory change took place: the responsibility for tendering the transmission expansion works ceased to be in the hands of the National Electricity Coordinator and passed directly to the owners of the facilities in charge of carrying out the expansion. To implement this modification, the National Energy Commission (CNE) published Exempt Resolution No. 98 of 2025, which establishes the regulatory framework for the process. At the same time, the National Electricity Coordinator prepared the document "OA Te nders Procedure", which details the stages, deadlines and conditions of supervision, with special focus on the monitoring of free competition and the transparency of each phase. This new scheme implies that ENGIE, in its capacity as owner of transmission facilities, must conduct public and international bidding processes under a demanding framework, complying with strict requirements of transparency, safeguards of competence and permanent coordination with the authority. To start this new regime, ENGIE launched on Friday, September 26, the tender for the expansion works at the Roncacho Substation, marking the first process under this modality. In 2026, a new bidding process covering three additional expansion works in facilities owned by ENGIE, will take place, thus consolidating the progressive deployment of this new regulatory scheme. • Pampa Fidelia wind project: On July 23, 2025, the company announced the construction of a new wind generation project in the Antofagasta region, the Parque Eólico Pampa Fidelia project, which will have 51 wind turbines and an installed capacity of 306 MW. This initiative will be abl e to supply the equivalent of 300,000 homes in the country with 100% renewable energy once it enters commercial operation, which is expected to occur in the first half of 2027. The project will contribute to the reduction of 91 t housand tons of CO2 emissions per year. SECOND QUARTER OF 2025 • Arbitration: On June 18, by means of an Essential Fact, Engie Energía Chile informed that it was notified of the final judgment issued by the arbitral tribunal constituted before the International Chamber of Commerce (ICC) in the international arbitration initiated by ENGIE against its liquefied natural gas ("LNG") supplier, Total Energies Gas & Power Limited ("Total"), in relation to the breach of one of the LNG supply contracts entered into with Total (referred to as "Contract 1"), which meant the total non -delivery during 2023 and partial delivery during 2024, of the contractually committed LNG cargoes. "Contract 1" is subject to New York law and is effective until December 31, 2026. The arbitral tribunal's award ruled, inter alia, that Total breached its contractual obligation s to (i) supply ENGIE in 2023 with four LNG cargoes, and (ii) supply ENGIE in 2024 with one LNG cargo. Accordingly, the Tribunal ordered Total to pay compensation in the amount of approximately US$101,200,000, plus interest at the rate agreed by the parties to Contract 1, compounded on a monthly basis, mostly accrued since January 1, 2024 and which will continue to accrue on the amounts outstanding until the time of payment by Total. Approximately US$32,700,000 of the above stated amount was received during the first half of 2025. However, the arbitral ruling could be subject to a n appeal of strict law before the Paris Court of Appeal, in an attempt to annul the decision. • BESS Capricornio COD : On May 19, the National Electric Coordinator (“CEN”) authorized the commercial operation of the battery storage project, BESS Capricornio, located in the Antofagasta region. Through 96 battery containers, this project has 48 MW/264 MWh of installed capacity to capture and store solar energy generated by the Capricornio PV plant and to inject energy into the SEN grid for up to 5 hours a day. • Annual Shareholders’ Meeting : The company’s shareholders reached the following agreements at ENGIE Energía Chile S.A.’s Annual Ordinary Shareholders’ meeting, which took place on April 29, 2025: a) Dividends: To approve the board of director’s proposal to distribute a final dividend to shareholders on account of the net income reported in the fiscal year ending December 31, 2024. Pursuant to local laws, the dividend distribution corresponds to the minimum regu latory 30% of net income after absorbing accumulated losses. The total amount to be distributed is US$54,414,436.64, or US$0,0516604307 per
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5 share, payable on May 28, 2025 to those shareholders listed in the Shareholders Registry the fifth business day prior to the payment date. b) Local rating agencies: To maintain the stock -title local rating services provided by “Feller Rate Clasificadora de Riesgo” and “Fitch Chile Clasificadora de Riesgo Ltda.”. c) Auditors: To appoint EY Servicios Profesionales de Auditoría y Asesorías SpA as the Company’s external auditing firm. • Monetization of PEC-3 documents: On April 3, 2025, pursuant to an agreement reached with IDB Invest, the company sold documents of payment ("DDPs") issued by the Chilean Treasury for a total amount of US$112.4 million including interests of US$3.7 million, corresponding to the second and last sale of DDPs under the so- called PEC-3 Law. FIRST QUARTER OF 2025 • Parque Eólico Kallpa (ex -Lomas de Tal Tal) COD: The system coordinator (CEN), certified the start of commercial operations of the Kallpa wind farm, a relevant milestone in our ongoing decarbonization plan. This wind farm, located in Taltal in the Antofagasta region, represents ENGIE’s largest renewable energy generation asset in Chile, which added 344MW of renewable energy capacity into our portfolio. • BESS Tamaya COD: the National Electric Coordinator (“CEN”) authorized the commercial operation of the battery storage project, BESS Tamaya, located in the Antofagasta region. Through 152 battery containers, this project has 68 MW/418 MWh of installed capacity to capture and store solar energy generated by the Tamaya PV plant. INDUSTRY OVERVIEW The SING and SIC power grids operated independently until November 24, 2017, when the interconnection of both grids was perfected through EECL’s 50% -owned TEN project, giving birth to the SEN ( “Sistema Eléctrico Nacional”). Currently, the company’s generation assets are predominantly located in the northern segment of the SEN, in the area that used to be covered by the so -called SING Grid (“Sistema Interconectado del Norte Grande” ), which serves a major portion of the country’s mining industry. Given local conditions, the northern segment of the SEN used to be predominantly a thermoelectric system, with growing penetration of renewable sources, including wind, solar, geothermal, and storage systems, which allow to cope with the renewable energy generation intermittence, decoupling and curtailment. In 2018, EECL began its geographical diversification with the acquisition of renewable generation assets in other regions of the country and with the start of supply under PPAs awarded with distribution companies in the center -south region. Since then, and more significantly following its decarbonization announcements, the company has been embarked in an ambitious investment program including investing in new renewable generation, storage and transmission assets. In recent years, the accelerated installation of renewable energy projects in the country has exceeded the capacity of the transmission infrastructure, making it necessary to expand it to prevent renewable energy losses. Marginal Costs 2024 Real (Monthly Average per Node) Mes Crucero PAN DE AZUCARPolpaico Charrua P. Montt Jan 42 40 41 37 79 Feb 54 51 53 50 108 Mar 51 49 49 47 60 Abr 55 53 55 61 73 May 79 81 93 94 95 Jun 54 52 54 48 36 Jul 46 45 49 43 42 Aug 44 43 47 44 66 Sep 48 41 42 38 49 Oct 50 45 40 29 50 Nov 42 36 35 28 34 Dec 38 35 37 35 57 YTD 50 48 49 46 63 2025 (monthly average per nude) Mes Crucero PAN DE AZUCARPolpaico Charrua P. Montt Jan 41 39 42 40 128 Feb 74 65 68 66 163 Mar 53 63 65 64 73 Abr 77 82 94 93 99 May 56 55 63 61 56 Jun 68 68 110 108 105 Jul 60 63 89 88 104 Aug 35 37 45 44 50 Sep 36 36 40 39 35 Oct Nov Dec YTD 56 56 68 67 90
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6 Source: Coordinador Eléctrico Nacional In the first quarter of 2025, the average marginal cost of the system was 71 USD/MWh. In the northern zone, it was 57 USD/MWh, 59 USD/MWh in the center, and 122 USD/MWh in the southern region. In the second quarter of 2025, the system marginal cost averaged 80 USD/MWh: 67 USD/MWh in the north, 88 USD/MWh in the center and 87 USD/MWh in the south of the country. In the third quarter of 2025, the system marginal cost decreased to an average of 53 USD/MWh, with averages of 44 USD/MWh in the north, 58 USD/MWh in the center and 63 USD/MWh in the south of the country. In the first nine months of 2025 the average marginal cost of the system was 68 USD/MWh, an increase compared to the same period of 2024, when marginal energy costs averaged 55 USD/MWh. In January, marginal energy costs were relatively similar to those reported in January, 2024 ; however, February 2025 was affected by the massive black -out in the system in addition to a decrease in hydroelectric generation . The higher marginal costs reported thereafter were explained by lower availability of thermoelectric plants, lower hydroelectric generation and a recovery in demand. The second quarter was also affected by failures in some transmission lines that caused an increase in marginal costs, particularly in the center -south zone. In the third quarter, marginal costs return to lower levels as a reflection of improved efficiency in the system. Fuel prices As shown in the table above, when comparing fuel prices for the first nine months of 2025 to the same periods in 2024, we can observe an ongoing decline in coal and oil prices. The exception has been Henry Hub, which increased in the first quarter mainly due to an extremely cold winter in the U.S. , which caused an increase in gas demand for both electricity generation and climatization. The second quarter marks the start of spring and summer in the Northern Hemisphere. The increase in demand for electricity generation due to the use of air conditioning is normally less than the fall in the consumption of gas for heating , thereby generating lower demand . In the second and third quarters of 2025, LNG prices began to moderate, but they remained above the prices observed in 2024. Generation The following graphs provide a breakdown of generation in the SEN by fuel type and by company in the first nine months of 2024 and the first nine months of 2025: 2024 2025 % Variation 2024 2025 % Variation 2024 2025 % Variation 2024 2025 % Variation YoY YoY YoY YoY Jan 74.1 75.9 2% 80.2 79.6 -1% 3.17 4.19 32% 106.1 110.4 4% Feb 77.8 71.5 -8% 83.8 75.4 -10% 1.67 4.19 151% 95.8 99.4 4% March 81.3 68.1 -16% 85.4 72.5 -15% 1.49 4.12 176% 114.4 97.4 -15% April 85.7 62.2 -27% 90.1 66.1 -27% 1.51 3.25 115% 118.8 102.4 -14% May 80.0 62.4 -22% 81.4 64.7 -20% 2.19 3.12 42% 106.0 95.6 -10% June 79.8 69.3 -13% 82.2 72.2 -12% 2.54 3.10 22% 109.7 103.6 -5% July 81.2 68.5 -16% 83.9 71.2 -15% 2.06 3.20 55% 106.4 104.4 -2% August 76.7 64.7 -16% 80.4 67.7 -16% 2.00 2.91 46% 121.7 99.4 -18% September 70.3 63.6 -10% 74.1 68.0 -8% 2.26 3.02 34% 114.8 93.0 -19% October 71.7 75.3 2.06 119.9 November 70.0 74.4 2.15 121.9 December 70.9 74.1 3.09 112.3 (US$/Barrel) (US$/Barrel) (US$/MMBtu) (US$/Ton) International Fuel Prices Index WTI Brent Henry Hub European coal (API 2)
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7 Source: Coordinador Eléctrico Nacional During the first nine months of 2025, peak electricity demand reached 12,397.5 MWh/h on February 4, 1.7% above the peak demand of 2024. Accumulated sales as of August 2025 reached 53,351.3 GWh, with a 3.3% decrease in regulated customer sales and a 2.0% increase in the unregulated client segment as compared to the same period of 2024. Regarding renewable energy, solar generation increased by 2.9%, while wind generation rose by 10.8% as compared to the same period of 2024. As of August 2025, the National Electricity System (SEN) reported total gross installed capacity of 38,303 MW, including 19,913.1 MW, or 52%, qualifying as non-conventional renewable energy capacity as defined by Law #20,257. In terms of hydraulic generation for the SEN, as of the end of August 2025, the estimated probability of exceedance for the April 2025-Mar 2026 hydrological year was 92.2% (dry year). Electricity production in the SEN grid, broken down by company, was as follows: Source: Coordinador Eléctrico Nacional Others 44% Enel 29% AES 7% Colbún 14% ENGIE 6% 9M24: Generation by company 64,401 GWh Others 43% Enel 27% AES 10% Colbún 12% ENGIE 9% 9M25: Generation by company 63,725 GWh
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8 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL RESULTS The following discussion is based on our unaudited consolidated financial statements for the nine-month periods ending September 30, 2025, and September 30, 2024. These financial statements have been prepared in U.S. dollars in accordance with IFRS and should be read in conjunction with the financial statements and the notes thereto published by the Comisión para el Mercado Financiero (www.cmfchile.cl). Third quarter of 2025 compared to third quarter of 2024 and second quarter of 2025 Operating Revenues Energy and capacity sales reached US$446.3 million in the third quarter of 2025, representing a 10% increase (US$39.9 million) compared to the same quarter of the previous year. When compared to the second quarter of 2025, energy and capacity sales climbed 2% (US$9.4 million). The 8% increase in regulated customer sales compared to the second quarter was explained by a 2% increase in physical sales, but more importantly, by a price increase provided for in the tariff decree applicable for the second half of the year. As compared to the third quarter of 2024, regulated sales increased 28% due to increases in demand (18%) and prices (8%). The decrease in energy and capacity sales to unregulated customers compared to the previous quarter was mainly explained by lower prices and provisions reported in the second quarter . D emand began to recover after preventive maintenance and equipment failures reported in the second quarter by some of our customers , namely Antucoya, Glencore, and Cap. The 12% drop in energy and capacity sales to unregulated customers , as compared to the third quarter of 2024, was explained by a decrease in physical sales, while the average realized tariff remained unchanged. Operating Revenues Amount % of total Amount % of total Amount % of total QoQ YoY Unregulated customers sales………………….. 192.5 47% 193.0 44% 170.2 38% -12% -12% Regulated customers sales……………………. 185.4 46% 220.2 50% 237.5 53% 8% 28% Spot market sales……………………………….. 28.5 7% 23.8 5% 38.6 9% 62% 35% Total revenues from energy and capacity sales 406.4 91% 436.9 75% 446.3 89% 2% 10% Gas sales………………………….. 13.4 3% 108.4 19% 21.5 4% -80% 60% Other operating revenue………………………. 27.8 6% 36.8 6% 32.8 7% -11% 18% Total operating revenues…………………. 447.6 100% 582.2 100% 500.6 100% -14% 12% Physical Data (in GWh) Sales of energy to unregulated customers (1)…… 1,773 56% 1,541 49% 1,573 49% 2% -11% Sales of energy regulated customers…… 1,366 44% 1,584 51% 1,616 51% 2% 18% Sales of energy to the spot market……………. - 0% - 0% - 0% - - Total energy sales…………………………. 3,139 100% 3,126 100% 3,189 100% 2% 2% Average monomic price unregulated customers(U.S.$/MWh)(2) 108.5 125.2 108.2 -14% 0% Average monomic price regulated customers (U.S.$/MWh)(3) 135.7 139.0 147.0 6% 8% Quarterly Information (In US$ millions) 3Q24 2Q25 3Q25 % Variation
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9 In monetary terms, sales to the spot market reported similar levels as those of the third quarter of 2024 and an increase compared to the previous quarter . This item includes payments for energy and capacity re settlements determined by the CEN, and in the third quarter it included US$13 million in provision reversals. In the third quarter of 2025 gas sales dropped as compared to the second quarter, which included the compensation resulting from the arbitration trial in relation to the breach of one of the LNG supply contracts entered into with our main LNG supplier. The most relevant items in the ‘O ther operating revenue’ account are sub -transmission tolls and regulatory transmission revenues, which starting 2018 include a single charge called “cargo único” , as well as port and maintenance services. Operating Costs Gross electricity generation increased 61%, compared to the third quarter of 2024, and 8% compared to the second quarter of 2025. Coal-based generation increased as our plants were more frequently dispatched according to merit order and also because IEM had repo rted a 20 -day maintenance outage in May . Likewise, g as generation increased due to better availability of our U-16 and CTM-3 CCGTs. The latter was out of service for 10 days in April. Generation with renewables increased 10% compared to the second quarter and 30% compared to the third quarter of 2024, mainly due to the contribution of the newly added Kallpa wind farm that reached COD in February 2025 and generated 201 GWh in 3Q25. Solar generation, however, decreased, but generation associated to our BESS projects, including the contribution of the new BESS Tamaya and BESS Capricornio, which achieved official COD in the second quarter, increased significantly, accounting for 5% of our net generation during the third quarter. ENGIE Chile’s renewable portfolio includes the following additions since 2021: (i) Kallpa wind farm (342 MW), which achieved COD in February 2025, (ii) Calama wind farm (151.2 MW) at the end of 2021, (iii) the Tamaya Operating Costs Amount % of total Amount % of total Amount % of total QoQ YoY Fuel and lubricants……………………………… (71.8) 20% (106.1) 25% (101.7) 26% -4% 42% Energy and capacity purchases on the spot market…………………………… (162.9) 46% (147.0) 35% (121.2) 31% -18% -26% Depreciation and amortization attributable to cost of goods sold……………………………. (36.0) 10% (40.9) 10% (43.6) 11% 7% 21% Other costs of goods sold……………………. (77.6) 22% (121.5) 29% (119.4) 31% -2% 54% Total cost of goods sold……………….. (348.3) 98% (415.4) 98% (386.0) 100% -7% 11% Selling, general and administrative expenses… (12.7) 4% (14.3) 3% (12.9) 3% -10% 1% Depreciation and amortization in selling, general and administrative expenses………… (0.9) 0% (0.9) 0% (1.2) 0% 33% 37% Other operating revenue/costs………………………. 7.0 -2% 8.6 -2% 13.6 -4% Total operating costs….………………. (354.9) 100% (422.0) 100% (386.4) 100% -8% 9% Physical Data (in GWh) Gross electricity generation Solar….............. 161 12% 108 5% 112 5% 4% -30% Wind…............. 185 13% 328 16% 371 17% 13% 101% Hydro………………………………. 57 4% 40 2% 41 2% 3% -28% Total Renewable……………………………… 403 476 524 10% 30% Coal…………………………………………. 432 31% 998 48% 1,022 46% 2% 136% Gas………...………………....……… 500 36% 504 24% 594 27% 18% 19% Diesel Oil and Fuel Oil……………………. 0 0% 2 0% 0 0% -100% -100% Total Thermal…………………………… 933 1,503 1,617 8% 73% Bess …................... 55 4% 88 4% 102 5% 16% 86% Total gross generation…………………. 1,391 100% 2,068 100% 2,243 100% 8% 61% Minus Own consumption……………….. (55) -4% (131) -6% (115) -5% -12% 107% Total net generation……………………. 1,335 41% 1,937 62% 2,128 66% 10% 59% Energy purchases on the spot market……….. 1,026 32% 369 12% 212 7% -42% -79% Energy purchases- bridge……….. 859 27% 828 26% 877 27% 6% 2% Total energy available for sale before transmission losses……………………… 3,220 100% 3,134 100% 3,218 100% 3% 0% Quarterly Information (In US$ millions) 3Q24 2Q25 3Q25 % Variation
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10 solar PV plant (114 MWac) which started commercial operations in January 2022, (iv) the Capricornio solar PV plant (88 MWac), with injections starting in April 2022, (v) the Coya PV plant (180 MWac), operational since August 2022, although it obtained its COD as of March 2023, and (vi) the San Pedro wind farms acquired in mid-December 2022. The fuel cost item showed a 42% increase compared to the same quarter of the previous year, mainly as a result of the 73% increase in thermal generation. Compared to the second quarter of 2025, despite an 8% increase in thermal generation, fuel costs dropped 4% due to lower fuel prices. The 'Cost of energy and capacity purchases in the spot market' item decreased compared to both the third quarter of 2024 and second quarter of 2025, mainly due to the decrease in spot purchase volumes. Energy purchases through back-up supply contracts with other generation companies reached 877 GWh in the third quarter, up from 828 GWh in the second quarter of 2025. Other direct operating costs include, among others, transmission tolls, plant personnel salaries, operating and maintenance costs, insurance premiums and cost of fuels sold. These costs increased from the same quarter of 2024 and remained relatively similar to those reported in the second quarter of 2025 . This included approximately US$30 million in provisions made in the context of the energy transition, with no effect on cash flow, such as spare -parts obsolescence, coal inventory, dismantling and environmental repair, and onerous contracts, among others. SG&A expenses decreased compared to the previous quarter, mainly due to higher legal, IT, and external personnel expenses reported in the second quarter. These expenses remained flat compared to the same quarter of 2024. The Other operating revenue/cost item includes water sales as well as recoveries, single transmission charges (“cargo único”), provisions and other miscellaneous income. EECL’s share in TEN’s net income, which amounted to US$1.4 million in the third quarter of 2025, is also included in this item. Electricity Margin 1Q24 2Q24 3Q24 1Q25 2Q25 3Q25 Electricity Margin Total revenues from energy and capacity sales……… 402.2 434.8 406.4 432.7 436.9 446.3 Fuel and lubricants………………….. (81.6) (83.2) (71.8) (67.2) (106.1) (101.7) Energy and capacity purchases on the spot market…… (157.6) (173.3) (162.9) (195.6) (147.0) (121.2) Gross Electricity Profit 163.0 178.4 171.6 170.0 183.9 223.4 Electricity Margin 41% 41% 42% 39% 42% 50% 2024 2025 Quarterly Information (In US$ millions) In the third quarter of 202 5, the electricity margin, or gross profit from the electricity generation business, increased by US$51.8 million as compared to the third quarter of 2024, with gross profit representing 50% of energy and capacity revenues, up from 42%. This was due to a 26% decrease in electricity purchase costs. Although fuel costs increased by 42% due to the increase in generation, fuel and electricity purchase costs taken together fell by US$11.8 million (5%), while revenues for energy and capacity sales increased by US$39.9 million (10%). Meanwhile, compared to the second quarter of 2025, there was a US$ 39.5 million increase in gross profit, and the gross margin increased from 42% to 50% since revenues from energy and capacity sales increased by US$9.4 million. Moreover, fuel costs decreased by US$4.4 million, while energy and capacity purchases dropped by US$25.8 million, mainly due to lower spot purchase volumes.
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11 Operating Results EBITDA Amount % of total Amount % of total Amount % of total QoQ YoY Total operating revenues……………………… 447.6 100% 582.2 100% 500.6 100% -14% 12% Total cost of goods sold…………………… (348.3) -78% (415.4) -71% (386.0) -77% -7% 11% Gross income…………………………. 99.2 22% 166.8 29% 114.7 23% -31% 16% Total selling, general and administrative expenses and other operating income/(costs). (6.6) -1% (6.6) -1% (0.5) 0% -93% -93% Operating income….………………. 92.6 21% 160.2 28% 114.2 23% -29% 23% Depreciation and amortization……...………… 36.8 8% 41.8 7% 44.8 9% 7% 22% EBITDA…………….….………………. 129.5 28.9% 202.0 34.7% 159.0 31.8% -21% 23% Quarterly Information (in US$ millions) 3Q24 2Q25 3Q25 % Variation Third quarter EBITDA reached US$159 million, a 23% increase compared to the third quarter of 2024 and a 21% decrease compared to the second quarter of 2025, when the company reported a compensation resulting from the arbitration with its main LNG supplier. Financial Results In the third quarter of 2025, finance income remained flat compared to the same quarter of 2024, and dropped by US$4.5 million compared to the second quarter of 2025, mainly because the company reported interest income of US$3.7 million in April 2025 relat ed to the second and last sale of documents of payment issued under the PEC -3 price stabilization mechanism. The slight increase in financial expenses, as compared to the second quarter of 2025, was mainly due to the issue of a local bond on September 3, while the US$6.7 million decrease in financial expenses compared to the third quarter of 2024 is primarily exp lained by lower interest rates and lower debt balances. Interest capitalized in investment projects remained flat in the three quarters under comparison (US$7.6 million in 3Q25, US$7.5 million in 2Q25 and US$7.4 million in 3Q24). Exchange rate differences resulted in a US$3.6 million loss in the third quarter, as opposed to the US$8.9 million profit reported in the second quarter, and the US$10.2 million profit in the third quarter of 2024. This is primarily explained by the effect of up and down movements in foreign-exchange rates on the value of certain assets, liabilities and cash flows denominated in currencies other than the US dollar, the company’s functional currency. These include some accounts receivable and payable, advanc es to suppliers, value-added tax credit and liabilities for onerous concessions on land and other assets recorded on the balance sheet under the IFRS16 norm. Non-operating results Amount % of total Amount % of total Amount % of total QoQ YoY Financial income………..……………………… 4.4 1% 8.7 1% 4.2 1% -52% -5% Financial expense………….………………… (37.3) -8% (29.0) -5% (30.6) -5% 6% -18% Foreign exchange translation, net…………… 10.2 2% 8.9 1% (3.6) -1% -141% -136% Other non-operating income/(expense) net… 0.0 0% (0.9) 0% 0.2 0% n.a. 1856% Total non-operating results……………. (22.7) -5% (12.4) -4% (29.9) -5% Income before tax……………………. ……… 70.0 15% 147.9 17% 84.2 14% -43% 20% Income tax……………………………………… (19.4) -4% (40.2) -5% (61.3) -10% 52% 215% Net income from continuing operations after taxes … 50.5 10% 107.7 13% 23.0 4% -79% -55% Net income to EECL's shareholders 50.5 10% 107.7 13% 23.0 4% -79% -55% Earnings per share…………………….. 47.97 102.20 21.81 Quarterly Information (In US$ millions) 3Q24 2Q25 3Q25 % Variation
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12 Net Earnings In the third quarter of 2025, net income after taxes reached US$23 million, a 55% decrease compared to the third quarter of 2024, despite the improvement in operating results. This was mainly due to an increase in deferred tax expenses explained by the merger of Central Termoeléctrica Andina (CTA) into EECL that generated a tax badwill and consequently the recognition of deferred taxes of approximately US$37 million. Net income after taxes fell more significantly compared to the US$107.7 million net income reported in the second quarter of 2025, when the company registered a compensation resulting from the Total arbitration. The lower net interest expense and foreign -exchange profits also contributed to the increase in the 2Q25 net result. In the third quarter of 2025, income taxes increased by US$21.1 million compared to the second quarter, mainly due to (a) the above explained increase in deferred taxes, (b) a reduction in assets for deferred taxes associated to cumulative tax losses, and (c) and increase in deferred tax liabilities explained by accelerated depreciation, slightly offset by a liability reduction arising from capitalized interest. 9M2025 compared to 9M2024 Operating Revenues In the first nine months of 2025, total revenues from energy and capacity sales reached US$ 1,316 million, a 6% (US$72.6 million) increase as compared to the first nine months of 2024, due to greater volume sales to regulated clients and a slight increase in average realized monomic prices in both the regulated and unregulated segments. The 16% increase in physical sales to regulated customers is partially explained by the expiration of energy supply contracts with other generators at the end of 2024, added to contracts with other generating companies that were suspended or had early termination due to problems in the execution of their generation projects. On the other hand, a 10% decrease was observed in physical sales to free customers. Physical sales to the spot market increased, although they were not material. The sales to the spot market item also includes payments for annual capacity and monthly energy reliquidations done by the CEN. The gas sales item had a greater contribution than in the previous period. In the first half of 2025, the company made gas sales to other operators, and it recognized the compensation for the arbitration ruling with the gas supplier Operating Revenues Amount % of total Amount % of total Amount % Unregulated customers sales………………….. 590.2 47% 537.5 41% -52.7 -9% Regulated customers sales……………………. 587.7 47% 695.5 53% 107.8 18% Spot market sales……………………………….. 65.5 5% 83.0 6% 17.5 27% Total revenues from energy and capacity sales…… 1,243.4 90% 1,316.0 82% 72.6 6% Gas sales………………………….. 27.5 2% 183.9 12% 156.5 569% Other operating revenue………………………. 110.2 8% 98.3 6% -11.9 -11% Total operating revenues…………………. 1,381.1 100% 1,598.2 100% 217.2 16% Physical Data (in GWh) Sales of energy to unregulated customers (1)…… 5,262 56% 4,740 49% -523 -10% Sales of energy regulated customers…… 4,139 44% 4,793 50% 654 16% Sales of energy to the spot market……………. 22 0% 62 1% 39 176% Total energy sales…………………………. 9,424 100% 9,594 100% 170 2% Average monomic price unregulated customers(U.S.$/MWh)(2) 112.1 113.4 1.2 1% Average monomic price regulated customers (U.S.$/MWh)(3) 142.0 145.1 3.1 2% For the 9-month period ended september 30 (US$ millions) 9M24 9M25 Variation
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13 for breach of contracts in previous years in an amount of US$101.2 million plus accrued interest, minus legal expenses. On October 20, 2025, ENGIE and T otal Energies agreed on the terms and conditions under which Total will pay for the compensation determined by the arbitration tribunal in the amount disclosed in the Essential Fact Notice published on June 18, 2025. The other operating revenue account includes sub -transmission tolls and as well as port and maintenance services. The decrease in this account is explained by a US$17.8 million insurance recovery in the first half of 2024 related to a past loss at the CTA plant. Operating Costs Gross electricity generation increased by 38% as compared to the first nine months of 2024. Coal generation increased due to lower availability of other plants in the system , lack of Argentine gas supply in the center of the system during a few days in the second quarter, and because our coal-fired plants, particularly IEM, CTA and CTH, were more frequently dispatched due to merit order. Gas-fired generation remained at similar levels as those of the first nine months of 2024. Renewable generation was higher, mainly due to the start-up of the Kallpa wind farm, while BESS's contribution to our generation matrix represented 5% of our gen eration in the first nine months of the year. Operating Costs Amount % of total Amount % of total Amount % Fuel and lubricants……………………………… (236.6) 22% (274.9) 23% 38.4 16% Energy and capacity purchases on the spot market… (493.8) 46% (463.8) 39% -30.0 -6% Depreciation and amortization attributable to cost of goods sold… (106.8) 10% (114.6) 10% 7.9 7% Other costs of goods sold……………………. (206.6) 19% (324.6) 27% 118.0 57% Total cost of goods sold……………….. (1,043.7) 98% (1,177.9) 99% 134.2 13% Selling, general and administrative expenses… (36.1) 3% (39.3) 3% 3.2 9% Depreciation and amortization in selling, general and administrative expenses… (2.7) 0% (3.0) 0% 0.3 13% Other operating revenue/costs………………………. 16.0 -1% 24.9 -2% 8.9 56% Total operating costs….………………. (1,066.5) 100% (1,195.3) 100% 128.8 12% Physical Data (in GWh) Gross electricity generation Solar….............. 493 12% 391 7% -102 -21% Wind…............. 475 12% 949 17% 475 100% Hydro………………………………. 118 3% 96 2% -22 -19% Total Renewable……………………………… 1,086 1,436 351 32% Coal…………………………………………. 1,455 35% 2,523 45% 1,068 73% Gas………...………………....……… 1,405 34% 1,405 25% 0 0% Diesel Oil and Fuel Oil……………………. 0 0% 16 0% 16 na Total Thermal…………………………… 2,860 3,944 1,084 38% Bess …................... 157 4% 285 5% 127 81% Total gross generation…………………. 4,102 100% 5,665 100% 1,563 38% Minus Own consumption……………….. (184) -4% (315) -6% -131 71% Total net generation……………………. 3,918 41% 5,350 55% 1,432 37% Energy purchases on the spot market……….. 3,010 31% 1,668 17% -1,342 -45% Energy purchases back up PPA…..……….. 2,645 28% 2,709 28% 64 2% Total energy available for sale before transmission losses……………………… 9,573 100% 9,727 100% 154 2% For the 9-month period ended september 30 (in US$ millions) 9M24 9M25 Variation
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14 In the first nine months of 2025, fuel costs increased 16% due to the increase in our own thermal generation, offset in part by the decrease in fuel prices. The item “Energy and capacity purchases on the spot market” decreased by US$30 million (6%) as compared to the first nine months of the previous year, mainly due to the combination of lower volumes of energy bought and lower realized prices when buying such energy. Depreciation expenses remained at similar levels in both periods. Other direct operating costs include, among others, transmission tolls, plant personnel salaries, operating and maintenance costs (third party services), insurance premiums and cost of fuels sold. The increase in this item as compared to the first nine months of 2024 is mainly explained by higher maintenance costs and higher provisions associated to the energy transition, which had no effects on cash flow. SG&A expenses increased by 9% compared to the first nine months of 2024 due to higher third party and advisory services. The other operating revenue/cost item includes water sales, recoveries, “cargo único”, other provisions, as well as EECL’s share in TEN’s net income, which amounted to US$4.4 million in the first nine months of 2025. Operating results EBITDA Amount % of total Amount % of total Amount % Total operating revenues……………………… 1,381.1 100% 1,598.2 100% 217.2 16% Total cost of goods sold…………………… (1,043.7) 76% (1,177.9) 74% 134.2 13% Gross income…………………………. 337.4 24% 420.4 26% 82.9 25% Total selling, general and administrative expenses and other operating income/(costs). (22.8) 2% (17.4) 1% -5.4 -24% Operating income….………………. 314.6 23% 403.0 25% 88.4 28% Depreciation and amortization……...………… 109.4 8% 117.6 7% 8.2 7% EBITDA…………….….………………. 424.0 30.7% 520.6 32.6% 96.5 23% For the 9-month period ended september 30 (in US$ millions) 9M24 9M25 Variation EBITDA for the first nine months of 2025 reached US$520.6 million, a 23%, or a US$96.5 million increase, compared to the same period of 202 4, mainly due to increase in operating revenue, which exceeded the increase in operating costs, as discussed in the above sections.
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15 Financial Results Financial income reported a US$48 million decrease compared to the first nine months of 2024, mainly due to US$50 million interest income accrued on accounts receivable from distribution companies, which was accounted for in June 2024, pursuant to a tariff decree that recognized the effect of delays in the publication of past tariff decrees. Excluding this effect, finance income increased by almost US$2 million. In the first nine months of 2025, the company received US$3.73 million in interest on the sale o f PEC-3 documents of payment issued by the Chilean Treasury, while in the same period of 2024, interests received on the sale of PEC-2 documents of payment amounted to US$1.5 million. The US$9.9 million decrease in financial expense in the first nine months of 2025, as compared to the first nine months of 2024, reflects a US$3 million decrease in interest accrued on financial debt balances, which fell by US$156 million, and a US$3.1 mil lion increase in capitalized interest. The average coupon rate of the company’s financial debt decreased from 5.6% as of September 30, 2024, to 5.4% as of September 30, 2025. Exchange rate gains of US$10.5 million in the first nine months of 2025 compare favorably to a US$0.9 million foreign-exchange profit in the first nine months of 2024, mainly due to exchange -rate volatility, with a local currency appreciation tendency in the first nine months of 2024, as opposed to the Chilean peso depreciation observed in the first nine months of 2025. Fluctuations in exchange rates affect the value of certain assets and liabilities denominated in currencies other than the US dollar (accounts receivable, advances to suppliers, value-added tax credit, accounts payable and provisions). Among the asset accounts denominated in currencies other than the US dollar, we can highlight value added tax credit (US$185 million as of September 30, 2025), which has increased due to the company’s active investment program in renewable generation and transmission projects. The main liabilities denominated in currencies other than the US dollar are the liabilities for onerous concessions on land recorded on the balance sheet under the IFRS16 norm and the local bond issued on September 3 for an equivalent amount of US$122 million. Net Earnings In the first nine months of 2025, net income after taxes reached US$208.5 million, a US$7.4 million increase compared to the first nine months of 2024, mainly due to better operating results (US$ 96.5 million increase in EBITDA) and foreign-exchange gains (+US$9.6 million). This was partially offset by (i) a US$38 million increase in net financial expenses due to interest income generated on accounts receivable from regulated clients accounted for in 2024, and (ii) a US$50.9 million increase in the income ta x provision. The latter was primarily explained by an increase in deferred tax liabilities. Non-operating results Amount % of total Amount % of total Amount % Financial income………..……………………… 65.4 7% 17.4 1% -48.0 -73% Financial expense………….………………… (102.0) -11% (92.2) -8% 9.9 -10% Foreign exchange translation, net…………… 0.9 0% 10.5 1% 9.6 1046% Other non-operating income/(expense) net… 0.6 0% (0.7) 0% -1.4 -215% Total non-operating results……………. (35.0) -4% (65.0) -5% Income before tax……………………. ……… 279.6 31% 338.0 28% 58.4 21% Income tax……………………………………… (78.6) -9% (129.5) -11% -50.9 65% Net income from continuing operations after taxes 201.0 22% 208.5 17% 7.4 4% Net income to EECL's shareholders 201.0 208.5 7.4 4% Earnings per share…………………….. 190.8 197.9 For the 9-month period ended september (in US$ millions) 9M24 9M25 Variation
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16 Liquidity and Capital Resources As of September 30, 2025, EECL reported consolidated cash balances of US$252.8 million, while its nominal financial debt2 amounted to US$2,279.4 million, including US$96 million of debt maturing within one year. During 2024 and the first nine months of 2025, the company raised cash proceeds from several financings in addition to the sale of documents of payment issued by the Chilean Treasury pursuant to the price stabilization laws to regulated clients (“PEC-2” and “PEC-3”). These resources allowed the company to finance capital expenditures, repay debt and increase its cash balance. The main financings during 2024 were (1) a 10-year, US$500 million, 144 -A/RegS bond issued on April 17, 2024, and (2) a CHF 190 million (US$225 million) green fixed-rate bond due in September 2029. Additionally, during 2024, the company sold documents of payment issued by the Chilean Treasury purs uant to the PEC-2 program structured by IDB Invest. Proceeds from these sales totaled US$58.8 million including interest. In October 2024, the company received US$356 million from the first sale of documents of payment issued under the PEC-3 program. On April 3, 2025, it received US$112.4 million from the second and last sale of PEC -3 documents of payment. Finally, on September 4, 2025, the company completed its first bond issue on the local market for a nominal value of UF 3 million, equivalent to appr oximately US$122 million as of September 30, 2025. On January 29, 2025, the company repaid the US$136 million remaining balance of a US$350 million 144 -A bond and repaid a US$50 million loan with BCI, with the consequential decrease in current debt and liquidity strengthe ning. Cash Flow Statement Cash Flow from Operating Activities The cash flow statement for the first nine months of 2025 shows cash flows from operating activities amounting to US$ 509 million. This figure is the result of the following movements. Cash flows from regular operations represented a net cash inflow of US$5 23.8 million. The following items must be subtracted from such figure: (i) interest payments of US$80.2 million (US$102.6 million effectively paid minus US$22.5 million included in CAPEX), (ii) income tax payments for a total of US$11.5 million, and (iii) payments of insurance premiums of US$35.6 million. Finally, an amount of US$112.4 million, received on the second and last sale of documents of payment in the context of the PEC -3 law, must be added to reach the US$509 million reported in the cash flow statement. Cash flow from operating activities in the first nine months of 2025 was significantly higher than the US$143.3 million reported in the first nine months of 2024. In 2024, cash flows from regular operations would have represented a net cash inflow of US$32 7.8 million, mainly due to a more balanced commercial position, lower fuel purchases and the drop in marginal energy costs and coal prices. However, these cash inflows could only partially materialize due to lower collections from regulated customers as a result of the price stabilization law, which resulted in a US$112.5 million build -up in accounts receivable. Therefore, net cash flows provided by operating activities amounted to US$215.3 million. The following items must be added to such figure: (i) US$5 8.8 million of cash proceeds from the sale of DDPs under the PEC -2 law and (ii) US$17.8 million in insurance compensations on past losses at the CTA plants. The following amounts should then be deducted to reach the US$143.3 million recorded in (1) Nominal amounts differ from the debt amounts recorded in the Financial Statements, which also include deferred financial expenses and mark-to-market valuations on derivative transactions. The above amount excludes the financial leases related to the long-term tolling agreement with TEN and transactions qualified as financial leases under IFRS 16. Cash Flow 2024 2025 Net cash flows provided by operating activities 143.3 509.0 Net cash flows used in investing activities (416.7) (593.7) Net cash flows provided by financing activities 321.3 (162.9) Change in cash 47.9 (247.6) For the 9-month period ended september (in US$ millions)
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17 the cash flow statement: (i) interest payments for US$97.8 million (US$117.2 million effectively paid minus US$19.4 million included in CAPEX), (ii) income tax and green tax payments for a total of US$30.5 million, and (iii) insurance premiums of US$20.3 million. Cash Flow Used in Investing Activities In the first nine months of 2025, net cash flows used in investment activities reached US$ 593.7 million, mainly due to capital expenditures of US$604.4 million, including the BESS Tamaya and BESS Capricornio energy storage projects, the Kallpa (ex -Lomas de Taltal), Pampa Fidelia and Pemuco wind farms, and the PV and BESS Libélula hybrid project as well as investments in transmission and major maintenance of generation and transmission assets, as detailed in the chart below. Other investing cash flows included US$13.2 million in financial income. In the first nine months of 2024, cash flows related to investment activities resulted in a net cash outflow of US$416.7 million, mainly due to capital expenditures of US$418.2 million, including the BESS Coya, BESS Tamaya and BESS Capricornio energy stora ge projects, the Kallpa wind farm and investments in transmission and major maintenance of generation and transmission, as detailed in the chart below. Other investing cash flows included a US$9.6 million cash outflow related to compensation of derivative products offset by US$11.2 million in financial income. Capital Expenditures Our capital expenditures in the first nine months of 2024 and the first nine months of 2025 amounted to US$418.2 million and US$604.4 million, respectively, as shown in the following table. The capital expenditure amounts included in the table above include VAT payments as well as capitalized interest. In the first nine months of 2024 the latter amounted to US$19.4 million, whereas in the first nine months of 2025 capitalized interest was US$22.5 million. Cash Flow from Financing Activities In the first nine months of 2025, cash flows related to financing activities represented a net cash outflow of US$162.9 million, including the placement of the company’s first green bond in the local market (US$122 million), which was offset by the following uses of funds: (i) the repayment of the US$135.5 million balance of a 144 -A bond with maturity on January 29, 2025, (ii) the repayment of a US$50 million loan with BCI, (iii) the payment of installments under the IFC/DEG loan (US$42.2 million), (iv) the payment of the first installment of the IDB Invest loan (US$1.1 million), (v) payments under financial leases (US$2.6 million), and (vi) dividend payments (US$53.7 million). In the first nine months of 2024, cash flows related to financing activities represented a net cash inflow of US$321.3 million, including (i) a 144 -A/RegS bond issue for US$500 million and (ii) the issue of a 5 -year bond in the Swiss market for a dollar-equivalent amount of US$225.1 million, partially offset by the following uses of funds: CAPEX 2024 2025 Substation………………… 31.3 30.0 Overhaul power plants & equipment maintenance and refurbishing………………… 16.0 27.3 Overhaul equipment & transmission lines 5.3 7.5 PV Power Plant…………… 14.7 114.0 Wind farm…………….. 174.5 245.5 Bess…............................................................ 166.2 165.0 Others…………………………………………… 10.2 15.0 Total capital expenditures………………………. 418.2 604.4 For the 9-month period ended september (in US$ millions)
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18 (i) US$165 million bank debt payments (US$30 million with Banco Santander, US$35 million with BCI, and US$100 million with Scotiabank), (ii) the repayment of the first installment of the IFC/Deg loan (US$21.1 million), and (iii) the early redemption of US$214.5 million of the US$350 million 144-A/RegS bond maturing in January 2025. Contractual Obligations The following table sets forth the maturity profile of our debt obligations as of September 30, 2025. Notes: a. The tolling contract signed with TEN for the use of dedicated transmission assets is considered a financial leasing operation and is accounted for under accounts payable to related companies. b. According to the IFRS16 Leasing rules, leasing obligations for land and vehicle rentals were accounted for as financial debt. As of September 30, 2025, the company’s consolidated debt totaled US$2,277.9 million (US$2,457.0 million including IFRS 16 financial leases, accrued interest and deferred financing costs). Short-term debt maturities amounted to US$ 149.8 million, including accrued interest, deferred costs , the current portion of financial leases and mark-to-market of interest-rate swaps. Short-term bank debt amounted to US$96 million, including (i) a US$50 million loan with Banco Estado maturing in January 2026, and (ii) the current portion of long-term debt. The latter included two principal installments of the IFC and DEG loans, each f or an amount of US$21.1 million, payable on January 15, 2026 and July 15, 2026, and the two principal installments of the IDB loan totaling US$3.9 million payable on December 15, 2025 and June 15, 2026. All loans are denominated in US dollars. The Banco Estado loan is documented with a promissory note in Chilean pesos plus a cro ss-currency swap, which turns the company’s obligation into a fixed -rate, US-dollar denominated loan. The IFC/DEG and the IDB financings accrue variable rates, except for a US$15 million tranche of the IDB financing which is at fixed rates. To mitigate its exposure to interest-rate fluctuations, the company took an interest -rate swap with Banco de Chile to fix the floating SOFR base rate over a notional amount equivalent to 60% of the IFC/DEG loan and a similar interest -rate swap with Banco de Chile to fix the floating SOFR base rate over a notional amount equivalent to 50% of the floating-rate portion of the IDB loan. Medium and long-term bank debt reached US$834.8 million as of September 30, 2025 (US$250 million with Scotiabank, US$170 million with a group of banks led by Banco Santander, US$120.1 million with IDB Invest, and US$294.7 million with IFC and DEG). These loans are described in the following paragraphs. On December 23, 2020, the Company and IDB Invest signed a financing agreement under which IDB Invest committed to extend a US$125 million loan to ENGIE Energía Chile. The financing includes a US$74 million senior loan from IDB Invest, a US$15 million mixed financing provided by the Clean Technology Fund (CTF), and a US$36 million loan from the China Fund for Co-financing in Latin America and the Caribbean (China Fund). The transaction, with a tenor of up to 12 years, was used to finance the construction, op eration, and maintenance of the Calama wind farm. This financing solution was designed to promote the acceleration of decarbonization activities by monetizing the actual displacement of CO2 emissions achieved through the anticipated decommissioning of coal -based plants whose generation is being replaced with the renewable power output of the Calama wind farm. In the absence of a carbon market, the financial structure provides for a minimum price for the avoided emissions to be paid through the reduction in the financial cost of the CTF loan. In case a carbon market is developed during the life of the loan, CTF Total < 1 year 1 - 3 years 3 - 5 years More than 5 years Bank debt…………………………………….………......... 930.7 96.0 523.5 150.8 160.6 Bonds (144 A/Reg S Notes+Swiss Bond+Local Bond)……………………..1,347.1 - - 725.1 622.0 Financial lease - Tolling Agreement TEN…………........... 48.4 2.2 5.1 6.1 35.0 Financial lease - IFRS 16…………………………. 91.5 4.0 9.9 4.6 73.1 Deferred financing cost………………………….. (25.2) - (10.9) (6.2) (8.2) Accrued interest………………………………….. 32.4 32.4 - - - Mark-to-market swaps………………………………….. 32.0 15.2 15.4 1.2 0.2 Total 2,457.0 149.8 542.9 881.6 882.7 Contractual Obligations as of 09/30/25 Payments Due by Period (in US$ millions)
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19 and Engie will share any positive difference between the market price and the minimum price set at the beginning of the financing. On August 27, 2021, the company drew the full amount available under these facilities. As of September 30, 2025, the loan reported a remaining average life of 4.3 years. The financing has tranches at variable interest rates for an initial amount of US$110 million, and their base-rate was switched from 6-month LIBOR to daily compounded SOFR beginning December 15, 2023. The compan y signed an interest-rate swap with Banco de Chile to fix the base rate of 50% of the loan balance, through which the base rate was fixed at 4.15% p.a. over a notional amount of US$55 million. On July 26, 2022, the company signed a US$250 million, 5 -year bullet green financing facility with Scotiabank. The first loan under this facility, for an amount of US$150 million, was booked on July 28, 2022, and the remaining US$100 million was disbursed on September 7, 2022. The loan accrues variable interest, using the SOFR benchmark rate. To hedge against interest -rate risk, the company took interest -rate swaps with Banco de Chile for a notional amount equivalent to 70% of the facility, fixing the SOFR rate at 2.872% p.a. On December 15, 2022, the company signed a 5-year loan agreement for a total committed amount of US$170 million with Banco Santander. On that date, the first US$77 million was disbursed to pay for the purchase of shares of the San Pedro wind farms in Chilo é. The remaining US$93 million portion was disbursed on February 15, 2023. The loan accrues interest at a variable rate based on 6-month Term SOFR plus a margin. To hedge against interest rate risk, the company took interest rate swap derivatives with Banc o Santander for a notional amount equivalent to 70% of the loan principal. Through this swap, the SOFR rate was fixed at an average rate of 3.493% p.a. for such portion of the loan. This loan was syndicated, which meant that Santander assigned tranches, ea ch amounting to US$34 million, to Société Générale, Rabobank, Banco Estado and Intesa San Paolo. At the end of June 2023, the International Finance Corporation (IFC), member of the World Bank Group, announced the closing of a green and sustainability-linked loan for ENGIE Energía Chile S.A. This financing, together with a parallel loan extended by the German bank DEG, member of the KfW development bank group, reached a total committed amount of US$400 million out to 10 years. The purpose of the loan is to finance and re -leverage investments in renewable projects and in the installation of energy storage systems (Battery Energy Storage System - BESS). The financing includes US$200 million provided directly by the IFC; US$114.5 million by investors under a co-financing portfolio managed by IFC; US$35.5 million by the ILX Fund, an investor focused on the O DS within IFC’s B-Loan framework; and a US$50 million parallel loan granted by DEG. This financing is to be repaid in 19 virtually equal semiannual installments beginning on July 15, 2024 and ending on July 15, 2033. On July 28, 2023, the company made the first US$200 million disbursement under this financing, and the remaining US$200 million was disbursed on December 19, 2023. The company took an interest-rate swap with Banco de Chile covering 60% of the notional amount of the debt at all times. Therefore, the annual base interest rate, over an initial notional amount of US$240 million, was fixed at 3.815%. As of September 30, 2025, EECL held two bonds under the 144A/RegS format, following the full repayment of the US$135.5 million balance remaining after a liability management involving a US$350 million bond issued in 2014. Of the two remaining bonds, the fi rst one, amounting to US$500 million, was issued on January 28, 2020 to fully refinance US$400 million notes originally due in January 2021. This bond has a 3.4% coupon rate and is due on January 28, 2030. On April 17, 2024, the company placed a new 6.375%, 10-year 144 A/Reg S Green bond for US$500 million to partially refinance the US$350 million bond maturing on January 29, 2025 and to finance renewable projects. The maturity date of this US$500 million bond is April 17, 2034. On August 29, 2024, the company priced a CHF 190 million, 5 -year green bond in the Swiss market and closed a CHF-USD cross-currency swap with BNP Paribas to convert the obligation to US dollars at an annual fixed rate of 5.427%. The bond proceeds, in an am ount of US$225.1 million, were received on September 26, 2024. The bond is payable in a single principal installment on September 26, 2029. On September 3, 2025, EECL completed its first green -bond issue on the local market in an amount of UF 3,000,000 out to 20 years, with principal payable in a single installment at maturity in September 2045. The interest rate placement was 3.57%, while the bond coupon rate is 3.60%. Leasing obligations include a long -term tolling agreement signed with TEN for the use of dedicated transmission assets connecting EECL’s plants in Mejillones with the national grid at the Los Changos substation. The tolling agreement is out to 20 years at which time EECL will take ownership of the asset. The agreement has a present
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20 value of US$48.4 million and is payable in monthly installments totaling approximately US$7 million per year until 2037. As of September 30, 2025 the company reported leasing obligations related to land use concessions, vehicles, and other assets for a total amount of US$91.5 million, which qualified as financial debt under the IFRS 16 accounting norm. The stability and predictability of our cash flows are also exposed to interest rate risk, principally with respect to the portion of our indebtedness that bears interest at floating rates. We seek to maintain a significant portion of our long-term debt at fixed rates to minimize interest -rate exposure. As of September 30, 2025, 86.2% of our financial debt was either at fixed rates or hedged through interest rate derivatives, while 13.8% (US$54.5 million of the IDB Invest financing, US$75 million of the Sco tiabank loan, US$51 million of the Santander loan, and US$134.7 million of the IFC/DEG financing) was at floating rates. Dividend Policy EECL's dividend policy, approved at the Ordinary Shareholders' Meeting held on Tuesday, April 29, 2025, consists of distributing, during the course of each financial year, at least the minimum mandatory dividend in accordance with the law and the bylaws. Likewise, to the extent that the situation of the company's business so permits and always taking into consideration the Company's development projects and plans, the distribution of provisional or definitive dividends in excess of the mandatory minimum dividend may be agreed. The dividend paid against 2024 net income was proposed by our Board and subsequently approved at the Annual Ordinary Shareholders’ Meeting held on April 29, 2025. According to local laws, as a minimum, dividend distributions must equal 30% of the period’s liquid net profit. However, if the company reports accumulated losses (US$46.9 million in this case), the annual profit must be first used to absorb such losses. Average interest rate 2025 2026 2027 2028 Thereafter Grand Total Variable Rate (US$) 6.7908% p.a. 0.8 2.5 4.4 8.2 38.7 54.5 (US$) 5.6497% p.a. - - 75.0 - - 75.0 (US$) 6.7945% p.a. - - 51.0 - - 51.0 (US$) 7.0910% p.a. - 16.8 16.8 16.8 84.2 134.7 Total Variable Rate 0.8 19.3 147.2 25.0 122.9 315.2 Fixed Rate (US$) 6.4000% p.a. - 50.0 - - - 50.0 (US$) 4.1724% p.a. - - 175.0 - - 175.0 (US$) 1.0000% p.a. - - - - 15.0 15.0 (US$) 6.0430% p.a. - - 119.0 - - 119.0 (US$) 6.5783% p.a. 0.8 2.5 4.4 8.2 38.7 54.5 (US$) 6.5313% p.a. - 25.3 25.3 25.3 126.3 202.1 (US$) 3.4000% p.a. - - - - 500.0 500.0 (US$) 6.3750% p.a. - - - - 500.0 500.0 (US$-eq) 5.4272% p.a. - - - - 225.1 225.1 (US$-eq) 5.9200% p.a. - - - - 123.5 123.5 Total Fixed Rate 0.8 77.7 323.6 33.4 1,528.6 1,964.2 TOTAL 1.6 97.0 470.8 58.4 1,651.5 2,279.4 As of September 30, 2025 Contractual maturity date (in US$ millions)
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21 Pursuant to the above, the company’s shareholders agreed to the distribution of a final US$54.4 million dividend on account of 2024 net earnings, corresponding to a US$0.0516604307 per -share dividend, which was paid on May 28, 2025. The record of dividends paid since 2010 is shown in the following table: Amount (in US$ millions) May 4, 2010 Final (on account of 2009 net income) 77.7 0.07370 May 4, 2010 Additional (on account of 2009 net income) 1.9 0.00180 May 5, 2011 Final (on account of 2010 net income) 100.1 0.09505 Aug 25, 2011 Provisional (on account of 2011 net income) 25.0 0.02373 May 16, 2012 Final (on account of 2011 net income) 64.3 0.06104 May 16, 2013 Final (on account of 2013 net income) 56.2 0.05333 May 23, 2014 Final (on account of 2013 net income) 39.6 0.03758 Sept 30, 2014 Provisional (on account of 2014 net income) 7.0 0.00665 May 27, 2015 Final (on account of 2014 net income) 19.7 0.01869 Oct 23, 2015 Provisional (on account of 2015 net income) 13.5 0.01280 Jan 22, 2016 Provisional (on account of 2015 net income) 8.0 0.00760 May 26, 2016 Final (on account of 2015 net income) 6.8 0.00641 May 26, 2016 Provisional (on account of 2016 net income) 63.6 0.06038 May 18, 2017 Final (on account of 2016 net income) 12.8 0.01220 May 22, 2018 Final (on account of 2017 net income) 30.4 0.02888 Oct 25,2018 Provisional (on account of 2018 net income) 26.0 0.02468 May 24, 2019 Final (on account of 2018 net income) 22.1 0.02102 June 21, 2019 Provisional (on account of 2019 net income) 50.0 0.04747 Dec 13, 2019 Provisional (on account of 2019 net income) 40.0 0.03798 Nov 30, 2020 Provisional (on account of 2020 net income) 66.6 0.06323 May 20, 2021 Final (on account of 2020 net income) 51.1 0.04847 Aug 26, 2021 Provisional (on account of 2021 net income) 41.5 0.03940 May 28, 2025 Final (on account of 2024 net income) 54.4 0.05166 Cash Dividends paid by Engie Energía Chile S.A. Payment Date Dividend Type US$ per share Risk management policy For details of our risk management policies, please refer to the Notes to ENGIE Energía Chile’s consolidated Financial Statements that can be found in the following link. https://engie-energia.cl/inversionistas/ A more exhaustive discussion of the risks facing our company can be found in the Risk Management section of the Annual Report available on our website.
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22 OWNERSHIP STRUCTURE AS OF SEPTEMBER 30, 2025 NUMBER OF SHAREHOLDERS: 1,717 TOTAL NUMBER OF SHARES: 1,053,309,776 59.99% 15.13% 16.57% 7.90% 0.40% ENGIE Chilean pension funds Chilean Inst. Inv. Foreign Inst. inv. Others
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23 APPENDIX 1 PHYSICAL DATA AND SUMMARIZED QUARTERLY FINANCIAL STATEMENTS Physical Sales 1Q24 2Q24 3Q24 9M24 1Q25 2Q25 3Q25 9M25 Physical Sales Sales of energy to unregulated customers. 1,745 1,744 1,773 5,262 1,626 1,541 1,573 4,740 Sales of energy to regulated customers 1,374 1,399 1,366 4,139 1,593 1,584 1,616 4,793 Sales of energy to the spot market……… 22 - - 22 62 - - 62 Total energy sales…………………………. 3,142 3,143 3,139 9,424 3,280 3,126 3,189 9,594 Gross electricity generation Solar…..... 198 134 161 493 171 108 112 391 Wind…...... 128 162 185 475 250 328 371 949 Hydro………………………………. 17 44 57 118 15 40 41 96 Total Renewable……………………………… 343 339 403 1,085 436 476 524 1,436 Coal…………………………………………. 495 527 432 1,455 503 998 1,022 2,523 Gas………...………………....……… 413 492 500 1,405 307 504 594 1,405 Diesel Oil and Fuel Oil……………………. 0 - 0 0 14 2 - 16 Total Thermal…………………………… 908 1,019 933 2,860 824 1,503 1,617 3,944 Bess …................... 51 51 55 157 94 88 102 285 Total gross generation…………………. 1,303 1,409 1,391 4,102 1,354 2,068 2,243 5,665 Minus Own consumption……………….. (63) (66) (55) (184) (69) (131) (115) (315) Total net generation……………………. 1,240 1,343 1,335 3,918 1,285 1,937 2,128 5,350 Energy purchases on the spot market……….. 935 1,049 1,026 3,010 1,087 369 212 1,668 Energy purchases back up PPA 986 799 859 2,645 1,003 828 877 2,709 Total energy available for sale before transmission losses……………………… 3,161 3,192 3,220 9,573 3,375 3,134 3,218 9,727 Physical Sales (in GWh) 20252024
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24 Quarterly Income Statement IFRS Operating Revenues 1Q24 2Q24 3Q24 9M24 1Q25 2Q25 3Q25 9M25 Regulated customers sales……………………… 190.6 211.7 185.4 587.7 237.8 220.2 237.5 695.5 Unregulated customers sales………………….. 194.4 203.3 192.5 590.2 174.3 193.0 170.2 537.5 Spot market sales……………………………….. 17.3 19.7 28.5 65.5 20.7 23.8 38.6 83.0 Total revenues from energy and capacity sales………………… 402.2 434.8 406.4 1,243.4 432.7 436.9 446.3 1,316.0 Gas sales………………………….. 7.2 6.9 13.4 27.5 54.0 108.4 21.5 183.9 Other operating revenue………………………. 33.3 49.2 27.8 110.2 28.7 36.8 32.8 98.3 Total operating revenues…………………. 442.7 490.8 447.6 1,381.1 515.4 582.2 500.6 1,598.2 Operating Costs Fuel and lubricants……………………………… (81.6) (83.2) (71.8) (236.6) (67.2) (106.1) (101.7) (274.9) Energy and capacity purchases on the spot (157.6) (173.3) (162.9) (493.8) (195.6) (147.0) (121.2) (463.8) Depreciation and amortization attributable to cost of goods sold.. (34.1) (36.7) (36.0) (106.8) (30.1) (40.9) (43.6) (114.6) Other costs of goods sold……………………. (59.8) (69.2) (77.6) (206.6) (83.7) (121.5) (119.4) (324.6) Total cost of goods sold……………….. (333.1) (362.3) (348.3) (1,043.7) (376.5) (415.4) (386.0) ####### Selling, general and administrative expenses… (10.6) (12.9) (12.7) (36.1) (12.1) (14.3) (12.9) (39.3) Depreciation and amortization in selling, general and administrative expenses… (0.9) (0.9) (0.9) (2.7) (0.9) (0.9) (1.2) (3.0) Other revenues………...………………………. 5.1 3.9 7.0 16.0 2.6 8.6 13.6 24.9 Total operating costs….………………. (339.4) (372.1) (354.9) (1,066.5) (386.8) (422.0) (386.4) ####### Operating income….………………. 103.3 118.7 92.6 314.6 128.6 160.2 114.2 403.0 EBITDA…………….….………………. 138.3 156.3 129.5 424.0 159.5 202.0 159.0 520.6 Financial income………..……………………… 4.1 57.0 4.4 65.4 4.6 8.7 4.2 17.4 Financial expense………….………………… (33.7) (31.0) (37.3) (102.0) (32.5) (29.0) (30.6) (92.2) Foreign exchange translation, net…………… (10.3) 1.0 10.2 0.9 5.2 8.9 (3.6) 10.5 Other non-operating income/(expense) net……………………… - 0.6 0.0 0.6 - (0.9) 0.2 (0.7) Total non-operating results…………… (39.9) 27.6 (22.7) (35.0) (22.7) (12.4) (29.9) (65.0) Income before tax……………………..……… 63.4 146.3 70.0 279.6 105.9 147.9 84.2 338.0 Income tax……………………………………… (17.3) (41.8) (19.4) (78.6) (28.0) (40.2) (61.3) (129.5) Net income attributed to controlling shareholders………………. 46.1 104.4 50.5 201.0 77.8 107.7 23.0 208.5 Net income to EECL's shareholders……. 46.1 104.4 50.5 201.0 77.8 107.7 23.0 208.5 Earnings per share…………………….. (US$/share) 0.04 0.10 0.05 0.19 0.07 0.10 0.02 0.20 Quarterly Income Statement (in US$ millions)
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25 Quarterly Balance Sheet Main Balance Sheet Variations The main balance-sheet variations between December 31, 2024, and September 30, 2025, were the following: Cash and cash equivalent: Cash balances decreased by US$245.9 million from US$498.6 million reported as of December 31, 2024, resulting in a new balance of US$252.8 million as of September 30, 2025. In the first nine months of 2025, cash sources included (i) cash flow from operating activities (US$524 million), (ii) US$112.4 million from the monetization of documents of payment related to the PEC -3 law, and (iii) part of the cash balance reported at year-end 2024. Finally, the company issued a 20 -year local bond in an amount of UF 3 million, and received cash resources for the equivalent to US$122 million on September 4. These resources were mainly used to finance (i) CAPEX of US$582 million, (ii) dividend payments of US$53.7 million, (iii) the payment of the US$135.5 million balance of a 144-A bond, (iv) the payment of a US$50 million loan with BCI, as well as principal debt payments of US$42.1 million under the IFC/DEG loan and US$1.1 million under the IDB Invest loan, (v) income tax payments of US$11.5 million, (vi) insurance premiums of US$36 million, and (vii) interest payments of US$102 million. 2024 2025 December September Current Assets Cash and cash equivalents 498.6 252.8 Accounts receivable 220.6 223.9 Recoverable taxes 8.7 8.1 Current inventories 124.6 80.9 Other non financial assets 227.9 223.9 Total current assets 1,080.5 880.4 Non-Current Assets Property, plant and equipment, net 2,969.2 3,473.5 Other non-current assets 671.0 559.4 TOTAL ASSETS 4,720.8 4,913.2 Current Liabilities Financial debt 291.7 147.6 Other current liabilities 358.2 303.8 Total current liabilities 649.9 451.4 Long-Term Liabilities Financial debt 2,287.5 2,307.2 Other long-term liabilities 218.6 379.1 Total long-term liabilities 2,506.1 2,686.3 Shareholders' equity 1,564.8 1,775.6 Equity 1,564.8 1,775.6 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 4,720.8 4,913.2 Quarterly Balance Sheet (in U.S.$ millions)
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26 Accounts receivable: The US$94 million increase is mainly explained by a US$76.5 million provision on the remaining amount to be collected in connection with the Total arbitration and payment of an invoice from a relevant client with a few days of delay for administrative re asons. This, together with a US$2.1 million decrease in the provision for uncollectible accounts, was offset by decreases in the following items: (i) accounts receivable related to other services ( -US$3.2 million), (ii) accounts receivab le from related companies ( -US$0.3 million), and (iii) other accounts receivable (-US$2.7 million), mainly explained by a decrease in accounts due from personnel as a result of the payment of collective bargaining bonuses. Current inventories: The US$43.7 million decrease in this item is mainly explained by a US$39.5 million decrease in coal and limestone inventory due to the drop in prices and the reduction in purchase volumes explained by the decarbonization process, which was partially offset by a US$3.7 million increase in LNG inventory and a US$1.9 million increase in diesel oil inventory. The inventory decrease also included a US$10 million impairment of the spare-parts inventory and a US$1.1 million increase in the inventory obsolescence provision. Recoverable taxes : The US$0.6 million decrease in this item is mainly explained by a US$0.1 million increase in recoverable taxes from previous periods, a US$0.3 million increase in monthly provisional tax payments and a US$0.9 million decrease in tax credit on personnel training expenses. Other current assets : The US$4 million decrease in this item is mainly explained by drops in (i) the VAT fiscal credit account ( -US$6.1 million), which reached a balance of US$184.8 million including FX differences, (ii) the mark-to-market of swap contracts (-US$5.2 million), and (iii) advances to suppliers including their associated FX difference (-US$1.1 million). These drops were partially offset by an US$8.4 million increase in prepaid expenses. Property, plant and equipment, net : The US$504.2 million increase in PP&E is explained by additions of generation and transmission assets which reached commercial operation during the first nine months of 2025 (US$627.7 million including BESS Tamaya (US$118.8 million), Wind Kallpa (US$481. 7 million) and BESS Capricornio (US$73.9 million)), and a US$70.8 million increase in the value of installations, basically transmission assets considering write-offs and impairments. The gross value of administrative buildings decreased by US$4 million, mainly due to depreciation, while works in progress reported a net decrease of US$191.4 million due to the reclassification to fixed assets of the assets that began commercial operations. Depreciation and amortization costs for the period amounted to US$114.6 million. Other non-current assets: The US$112.9 million decrease in this item resulted from (i) the end of the account receivable related to price stabilization laws explained by the full payment of the amount provisioned at year-end 2024 (US$90.9 million); (ii) the decrease in projects under development explained by the completion of those projects and their inclusion in the PP&E account ( -US$19.2 million); (iii) the lower proportional equity value of TEN ( -US$3.3 million) due to reserves related to hedging deriva tives; (iv) the amortization of intangible assets ( -US$5.7 million); and (v) the depreciation of assets by right of use associated with the IFRS 16 norm ( -US$2.5 million). Increases in this account included (i) a higher market value of financial derivative s (+US$11.1 million) and (ii) a higher value of rights of way (+US$2.3 million). Financial debt – current: This item reported a US$ 144.1 million decrease due to the net effect of (i) the payment of the US$135.5 million balance of the 144 -A/RegS bond with maturity on January 29, 2025, (ii) the repayment of a US$50 million loan with BCI, and (iii) the payment of the first principal installment of the IDB Invest loan for US$1.1 million. These payments were partially offset by the transfer from the long to the short term of (i) a US$50 million loan with Banco Estado maturing January 2026 and (ii) a US$2.2 million installment of the IDB Invest loan. The difference is explained by variations in accrued interest (-US$10.8 million), the mark-to-market of financial derivatives (+US$1.2 million), and deferred financing costs (-US$0.9 million). Other current liabilities: The US$54.5 million net decrease in this group of items is explained by decreases in the following accounts: (i) accounts payable to suppliers (-US$5.6 million); (ii) the dividend payment provision for (a) minority shareholders ( -US$21.8 million) and the controlling shareholder ( -US$32.6 million) due to the May dividend payment; (iii) the provision for employee benefits ( -US$7.7 million) and (iv) VAT retained to third parties (-US$1.5 million). All this was partially offset by a U S$12.8 million net increase in several provisions and a US$1.5 million net increase in accounts due to related companies.
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27 Long-term financial debt: The US$19.7 million increase in this account is mainly explained by (i) the local bond placement (+US$122 million -eq.) and (ii) a US$2.9 million increase in deferred financing costs, offset by the transfer from non-current to current debt of (i) the loan with Banco Estado (-US$50 million maturing in January 2026); (ii) the January and July 2026 installments of the IFC/DEG loan ( -US$42.1 million); (iii) the June 2026 installment of the IDB Invest loan (-US$2.2 million), and (iv) the US$1.7 million installments of the tolling agreement with TEN for the use of dedicated transmission assets and other IFRS 16 leases. Additionally, the mark -to-market of financial derivatives caused a US$8.2 million decrease in long-term financial debt. Other long-term liabilities: The US$160.5 million increase in other long-term liabilities, is mainly explained by (i) a US$127.7 million increase in the provision for deferred tax liabilities, and (ii) a US$26.5 million increase in other provisions , including the plant dismantling and site restoration provision as well as provisions on onerous contracts related to port facilities. Shareholders’ equity: The US$210.8 million increase in shareholders’ equity is explained by the US$208.5 million net profit reported in the first nine months of 2025 plus US$2.3 million corresponding to the variation in the reserve for merger of subsidiaries. APPENDIX 2 Financial information Financial Ratios 3Q24 4Q24 1Q25 2Q25 3Q25 EBITDA* 129.5 91.8 159.5 202.0 159.0 Net income attributed to the controller 50.5 27.3 77.8 107.7 23.0 Interest expense 37.3 28.9 32.5 29.0 30.6 * Operating income + Depreciation and Amortization for the period Sep/25 LTM EBITDA 612.3 LTM Net income attributed to the controller 235.7 LTM Interest expense 121.1 Financial debt 2,454.8 Current 147.6 Long-Term 2,307.2 Cash and cash equivalents 252.8 Net financial debt 2,202.0
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28 As of September 30, 2025, the current ratio and the quick ratio were 1.95x and 1.77x, respectively. Both indicators were higher than those reported at year-end 2024. The debt-to-equity ratio was 1.77 times as of September 30, 2025, below the level reported at year-end 2024, due to the increase in networth resulting from the net profit reported in the first nine months of 2025. The interest coverage ratio, measured by EBITDA -to-interest expense (including financial leasing interest expenses), for the last twelve months ended September 30, 202 5 was 5.06x, which represents an improvement compared to year-end 2024 due to the EBITDA recovery. Gross financial debt -to-EBITDA reached 4.01x including financial leases. The Net debt -to-EBITDA ratio was 3.60x. Excluding financial leases, these ratios would be 3.78x and 3.37x, respectively. These ratios represent an ongoing improvement since their 2022 peak. Return on equity and Return on assets were 1 3.3% and 4.8%, respectively. These figures remain positive after the profits reported in the last quarters. Dec/24 Sep/25 Var. Current ratio (times) 1.66 1.95 17% (current assets / current liabilities) Quick ratio (times) 1.47 1.77 20% ((current assets - inventory) / current liabilities) Working capital MMUS$ 430.6 429.0 0% (current assets – current liabilities) Leverage (times) 2.02 1.77 -13% ((current liabilities + long-term liabilities) / networth) Interest coverage * (times) 3.94 5.06 28% ((EBITDA / interest expense)) Financial debt –to- LTM EBITDA* (times) 5.00 4.01 -20% Net financial debt – to - LTM EBITDA* (times) 4.09 3.60 -12% Return on equity* % 14.6% 13.3% -9% (LTM net income attributed to the controller / net worth attributed to the controller) Return on assets* % 4.8% 4.8% 0% (LTM net income attributed to the controller / total assets) *LTM = Last twelve months FINANCIAL RATIOS
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29 ENGIE ENERGÍA CHILE’S GUIDANCE 2025 ENGIE Energía Chile maintains its guidance for 2025 as follows: Drivers and assumptions • Stable fuel costs • LNG + Argentine gas sourcing • Renewable generation increase • New storage projects • Last PEC receivables monetization • Strong initial cash position • LNG arbitration proceeds • Availability of generation assets In US$ millions EBITDA CAPEX ND/EBITDA FY2025 650 - 700 900 - 975 3.3x The details of the 2025 guidance will be presented during the Conference Call.
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30 CONFERENCE CALL 9M25 ENGIE Energía Chile is pleased to inform you that it will conduct a conference call to review its results as of and for the nine-month period ending September 30, 2025, on Thursday November 13, 2025 at 10:00 (EST) – 12:00 (Chile) hosted by: Juan Villavicencio, CEO Engie Energía Chile S.A. Vincent Sorel, CFO Engie Energía Chile S.A. To join the conference, please use the following link: Please connect approximately 10 minutes prior to the scheduled starting time. A replay of the call will be available in our web site: https://www.engie.cl/inversionistas/