HISTORY AND DEVELOPMENT OF THE COMPANY Pampa is incorporated as a sociedad anónima under the laws of Argentina. Our principal executive offices are located at Maipú 1, City of Buenos Aires, Argentina (C1084ABA). Our telephone number is + 54 11 4344 6000. Our website address is www.pampa.com. None of the information available on our website or elsewhere is included or incorporated by reference into this annual report. Our authorized representative in the United States for our registration statement with the SEC is Puglisi Associates, located at 850 Library Avenue, Suite 204, Newark, Delaware 19711. We were incorporated on January 12, 1945 and registered before the Public Registry on February 21, 1945 for a duration lasting until June 30, 2044, under the name Frigorífico La Pampa S.A. In 2003, we suspended our former business activities, which were limited to the ownership and operation of a cold storage warehouse building. In 2005, the Company was acquired by its current principal shareholders to serve as a corporate vehicle for its investments in Argentina. Following such acquisition, we changed our corporate name to Pampa Holding S.A. We changed our corporate name again, to Pampa Energía S.A, in September 2008 and have operated under this name since then. As a result of several acquisitions made since 2006, we are currently one of the leading independent energy integrated companies in Argentina and, directly and/or through our subsidiaries and joint controlled companies, we participate in the electricity and gas value chains. In July 2016, we acquired from Petrobras all of the shares of Petrobras Participaciones S.L., which in turn owned, at such time, 67.2% of the shares of Petrobras Argentina (the “Acquisition”). Since the Acquisition, we started a corporate reorganization process and have merged certain subsidiaries into Pampa, including, among others, Petrobras Argentina, Petrolera Pampa, CTG, CTLL, CPB and certain assets of CISA by way of absorption, with Pampa as the surviving company. The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Capital Expenditures and Divestitures For a description of our capital expenditures, see “Item 5. Operating and Financial Review and Prospects - Liquidity and Capital Resources.” 40 Table of Contents OUR BUSINESS Overview We are one of Argentina’s largest energy companies, participating mainly in the crude oil, gas and power generation value chain: Note: As of December 31, 2025. Numbers are rounded, so they may not sum up. CTEB, Transener and TGS are affiliates, which under IFRS are not consolidated in the financial statements. 1) Average 2025 production. 2) It includes 1.1 kbbl of crude oil produced in El Tordillo and La Tapera-Puesto Quiroga, assigned in October 2025. 3) It includes 848 MW at CTEB, co-operated by Pampa. Oil and Gas. We are engaged in the oil and gas business through the exploration and exploitation of direct interests in blocks located in Argentina, with operations in 9 production blocks, 2 exploratory blocks and 470 productive wells. The Company is the fifth-largest gas producer with 9% of the country’s gas output and the third-largest shale gas producer with 10% market share. The segment includes our 20% equity interest in SESA and San Matías Pipeline S.A., both of which are engaged in the development of the FLNG Project (see “Recent Events – FLNG Project”). · As of December 31, 2025, our combined crude oil and natural gas proved reserves amounted to approximately 296 million boe, 54% of which were proved developed reserves. Natural gas accounted for approximately 81% of our combined proved reserves and liquid hydrocarbons for 19%; and · As of December 31, 2025, our combined oil and gas production in Argentina averaged 84.4 thousand boe per day. Crude oil accounted for approximately 11.7 thousand boe per day, while natural gas accounted for approximately 72.8 thousand boe per day. During 2025, 60% of our production came from Vaca Muerta formation, reaching 63% during the last quarter of 2025, consolidating our position as one of the main producers in the most relevant formation of Argentina. Our oil and gas business segment recorded U.S.$ 862 million in revenue and an operating profit of U.S.$ 91 million for the fiscal year ended December 31, 2025. For more information about our Oil and Gas Business, please see “Item 4. Our Oil and Gas Business.” Generation. Our generation installed capacity reached 5,472 MW as of December 31, 2025, representing approximately 12% of Argentina’s installed capacity. Our generation business segment recorded U.S.$ 792 million in revenue and an operating profit of U.S.$ 375 million for the fiscal year ended December 31, 2025. For more information about our Generation Business, please see “Item 4. Our Generation Business.” Petrochemicals. We are engaged in the petrochemicals business through two plants located in Argentina which produce styrene, styrene butadiene rubber and polystyrene, with a domestic market share of 86% and 98% (per Company estimates), respectively, as of December 31, 2025. Our petrochemicals business segment recorded U.S.$ 443 million in revenue and an operating loss of U.S.$ 31 million for the fiscal year ended December 31, 2025. 41 Table of Contents For more information about our Petrochemicals Business, please see “Item 4. Our Petrochemicals Business.” Holding and Other Business. We also hold other interests, including: · a 26.9% co-controlling interest in TGS, the country’s largest gas transportation company, owning and operating 9,248 km of gas pipelines, a natural gas liquids processing plant, General Cerri, with a production capacity of over 1 million tons/year, and a gathering pipeline and gas treatment plant located in Vaca Muerta, province of Neuquén, which provides unregulated midstream services; · a 26.3% co-controlling interest in Transener, Argentina’s leading high-voltage electric energy transmission company. Additionally, Transener holds a 100% interest in Transba. As of December 31, 2025, Transener’s operation and maintenance coverage reached approximately 22.4 thousand kilometers of high voltage transmission lines, representing approximately 86% of the high-voltage system in Argentina; · a 70% interest in Enecor S.A., an independent electricity transmission company that provides operation and maintenance services, by subcontracting Transener, for 21 km of 132 kV double-triad electricity lines, from the Paso de la Patria transforming station, in the Province of Corrientes. Such services are provided under a 95-year concession, which is due to expire in 2088; and · a 10.2% interest in VMOS related to the “Vaca Muerta Oil Sur Project” for the construction, development, and operation of an oil pipeline approximately 437 km in length, from Allen to Punta Colorada, in the Province of Río Negro. Pampa will have transportation, storage, and dispatch capacity of 50,000 barrels per day. · a 2.1% interest in Oldelval, a company engaged in the operation of main oil pipelines that connect the Neuquina Basin to the Bahía Blanca harbor. Our holding and other business segment recorded U.S.$ 24 million in revenue and an operating profit of U.S.$ 68 million for the fiscal year ended December 31, 2025. For more information about our Holdings and Others Business, please see “Item 4. Our Holdings and Others Business.” Relevant Events Oil and Gas Vaca Muerta Oil Sur Project In June 2025, the shareholder structure of VMOS S.A. was expanded with the incorporation of Tecpetrol S.A. as a Class A shareholder. We currently hold a 10.2% stake in VMOS, which may vary depending on an increase in any of the shareholders’ participation or the entry of additional shareholders into the project. VMOS is currently developing a large-scale pipeline that will streamline crude oil evacuation and exports from the Vaca Muerta formation, and specifically, for us, from the Rincón de Aranda block, will reduce logistics costs, open new markets for Argentine oil, increase foreign currency inflows, create employment opportunities and expand our firm transportation capacity. FLNG Project On January 15, 2025, we acquired an interest in a floating liquefied natural gas project in Argentina, including the stationing of the floating liquefied gas vessel “Hilli Episeyo” (“Hilli”) and the construction of all the required additional facilities in the San Matías Gulf, in the Province of Río Negro (the “FLNG Project”), together with Pan American Energy S.L., Golar FLNG Holding Company Limited, YPF and Harbour Energy. The vessel is expected to start operating in September 2027. The FLNG Project is being executed through SESA, whose shareholders are Pan American Energy S.L. (30%), YPF S.A. (through its subsidiary Sur Inversiones Energéticas S.A.U.) (25%), Pampa (20%), Wintershall DEA Argentina S.A. (15%), and Golar FLNG Sub Holding Company Limited (10%). SESA’s application to adhere to the RIGI, in accordance with Law 27,442, Regulatory Decree No. 749/24, and other regulations that may amend and/or complement them, to be considered a Strategic Long-Term Export Project was approved on April 29, 2025. 42 Table of Contents On May 2, 2025, the consortium satisfied all conditions required to move forward with development of the FLNG Project, including the final investment decision for Hilli and the approval of its application for enrollment under the RIGI. A second vessel, the “MKII” was included in the project. Both units are expected to provide a combined processing and export capacity of approximately 6 million tons per year of LNG (equivalent to 27 million m³/day of natural gas). The FLNG Project represents an estimated investment of approximately U.S.$ 7 billion over its 20-year operational horizon and is expected to position Argentina as a participant in the global LNG market. Operations of the Hilli and the MKII are expected to begin in late 2027 and 2028, respectively. To supply natural gas to both vessels, SESA entered into 20-year natural gas supply agreements with Pampa, Pan American Energy, YPF and Wintershall, each in proportion to its equity interest in SESA. The project also contemplates the construction of a dedicated gas pipeline from the Province of Neuquén to the San Matías Gulf to ensure year-round operation of both vessels to be developed by the company San Matias Pipeline S.A., where we also hold a 20% interest. The FLNG Project is strategic to monetizing our Vaca Muerta reserves, placing Argentina within the liquefied natural gas global market, and boosting foreign currency inflows, job creation, and the domestic supply chain. Extension of the RIGI, inclusion of hydrocarbon upstream activities and filing of the RDA Project On February 19, 2026, pursuant to DNU No. 105/26, the deadline to join the RIGI was extended until July 8, 2027, and the exploration and production of liquid and gaseous hydrocarbons in greenfield blocks was incorporated into the regime. These activities may only be included in new projects, as well as the construction of associated treatment, storage, and transportation infrastructure. In addition, a minimum investment amount was set at U.S.$ 600 million for onshore developments and U.S.$ 200 million for offshore projects. In cases where activities not subject to the RIGI coexist within the same hydrocarbon block, strict asset and corporate segregation must be ensured. Additionally, the traceability of RIGI production must be guaranteed through separate measurement systems and via a dedicated vehicle that exclusively holds the relevant assets, rights, and operations. Following such inclusion, on March 9, 2026, we (through our single-purpose project vehicle Pampa Energía S.A. - Sucursal Dedicada Proyecto RDA) submitted an application to adhere to the RIGI as a long-term strategic export project in connection with the exploration, drilling, completion, production, and development of new shale oil wells located in the Rincón de Aranda block, as well as the construction of related infrastructure, including processing facilities, oil pipelines, and gas pipelines (the “RDA Project”). The RDA Project contemplates the drilling and development of approximately 259 new wells, of which 154 are expected to be drilled in the southern portion and 105 in the northern portion of the block. Pursuant to DNU No. 105/26, the 54 wells currently operated by Pampa in the block are excluded from the scope of the RIGI application. Accordingly, only new wells drilled following the submission of the application are included. It should be noted that, prior to the enactment of DNU No. 105/26, the RDA Project contemplated the development of approximately 50% of the total surface of the Rincón de Aranda block, considering the reservoir quality and the associated geological complexity. The enactment of DNU No. 105/26 made it feasible to extend the development to the northern portion of the Rincón de Aranda block, allowing the development of 105 additional wells in such block. The total estimated investment for the RDA Project is approximately U.S.$ 4.5 billion. Sale of El Tordillo, La Tapera y Puesto Quiroga. On October 1, 2025, the Company transferred to Crown Point Energía S.A., in relation with the El Tordillo, La Tapera and Puesto Quiroga blocks: (i) its 35.6706% participation in the hydrocarbon exploitation concessions and hydrocarbon transportation concessions, and (ii) the Joint Venture Agreements for the exploration, exploitation and development of hydrocarbons. The amount of the transaction was U.S.$ 2 million. 43 Table of Contents Generation Hydroelectric concessions termination On June 4, 2024, we announced the beginning of a 12-month transition period for the concession held by HINISA, in which we hold a 52.04% stake. On June 11, 2024, we announced that the transition period was modified and reduced to 6 months. HINISA’s concessions, granted by the Province of Mendoza and the National Government for the use of water resources and electric power generation, were originally set to expire on June 1, 2024. The Province of Mendoza, through Decree No. 1,021 issued on May 27, 2024, and the National Energy Secretariat, via Resolution RESOL-2024-83-APN-SE#MEC and RESOL-2024-98-APN-SIYC#MEC, have both established a twelve-month transition period effective from June 1, 2024, during which HINISA will continue to manage the hydroelectric complex, with designated observers from the provincial government. The concessions for HINISA expired on November 30, 2024. On November 29, 2024, the SE extended the transition period for 6 months. The new expiration date is June 1, 2025. In the case of HIDISA, its concession expired on October 19, 2024. These concessions include one granted by the Province of Mendoza for the use of water assets and resources and another granted by the Argentine Federal Government for electricity generation. We hold 61% of HIDISA’s share capital. On October 18, 2024, the Province of Mendoza, through Decree No. 2,096/24, established a 12-month transition period, with the provincial Undersecretary of Energy and Mining appointed as supervisor. Similarly, the Secretariat for the Coordination of Energy and Mining of Argentina, through Resolution No. 1/24, established a transition period until June 1, 2025, and designated the national Subsecretariat of Electric Energy as the supervising authority. With respect to HINISA, the Province of Mendoza enacted Law No. 9,630 which was promulgated in May 2025 declaring an emergency for HINISA’s operation for a 14-month term from such promulgation due to the flood that occurred in January 2025, thereby extending the 12-month transition period provided in the concession agreement. The Province of Mendoza established a new corporation “Hidroelectricidad Mendocina” to become the future owner of the Nihuiles assets upon reversion. With respect to HIDISA, Law No. 9,630 authorized the continued use of water, while the National Government, pursuant to SE Resolution No. 398/25, proposed the continuation of HIDISA’s operation until June 30, 2026. HIDISA adhered to such an extension. In March 2025, the Province of Mendoza and the National Government agreed to jointly call for a tender for the operation of both hydroelectric assets. As of the date of this report, the tender has not been launched. Changes in the electricity regulatory framework In order to achieve the objectives set out in the Bases Law, in July 2025 Decree No. 450/25 was enacted amending Law No. 15,336 and approving a consolidated text of Law No. 24,065. In line with this, based on the guidelines for the readaptation of the WEM, on October 21, 2025, SE Resolution No. 400/25 approved the Rules for the Normalization and Progressive Adaptation of the WEM. For more information on such changes, see “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework.” 44 Table of Contents Organizational structure The following chart sets forth our corporate structure as of December 31, 2025. See “Exhibit 8.1. List of subsidiaries, Joint Ventures and Associates of Pampa Energía S.A.” We have no significant subsidiaries. 45 Table of Contents Our Oil and Gas Business Exploration and Production Our strategy is to develop profitable oil and gas reserves with social and environmental responsibility. In this segment, we are focused on three main objectives: (i) development and monetization of unconventional gas reserves; (ii) exploration for reserves replacement; and (iii) optimization of operations and existing infrastructure as leverage for new projects. As is usual in the oil and gas exploration and production business, we participate in exploration and production activities in conjunction with joint operation partners. Contractual arrangements among participants in a joint operation are usually governed by an operating agreement, which provides that costs, entitlements to production and liabilities are to be shared according to each party’s interest in the joint operation. One party to the joint operation is usually appointed as operator and is responsible for conducting the operations under the overall supervision and control of an operating committee that consists of representatives of each party to the joint operations. While operating agreements generally provide for liabilities to be borne by the participants according to their respective interest, licenses issued by the relevant governmental authority generally provide that participants in joint operations are jointly and severally liable for their obligations to the relevant governmental authority pursuant to the applicable license. In addition to their interest in field production, contractual operators are generally paid their indirect administrative expenses on a monthly basis by their partners in proportion to their participation in the relevant field. As of December 31, 2025: · our combined crude oil and natural gas proved reserves were 296 million boe, 54% of which were proved developed reserves. Natural gas accounted for approximately 81% of our combined proved reserves and liquid hydrocarbons for 19%; and · our combined oil and gas production in Argentina averaged 84.4 thousands of boe per day. Crude oil accounted for approximately 11.7 thousands of boe per day, while natural gas accounted for approximately 437 million standard cubic feet per day, or 72.8 thousands of boe per day based on a measure of conversion of 6,000 cubic feet of gas per barrel of oil equivalent. During 2025, according to the SE, gas gross production in Argentina increased by 2% (4.99 billion cubic feet per day on average), whereas oil gross production increased 13% at 794.5 thousand barrels per day (on average). For 2025, according to the SE, our consolidated oil and gas production accounted for approximately 1.2% and 9% of total oil production and gas production in Argentina, respectively. Key Information Relating to Oil and Gas As of December 31, 2025, we had interests in 11 areas, joint operations (UTEs) and agreements in Argentina: 9 oil and gas production areas and 2 exploration blocks located within exploration areas or pending authorization for production. As of December 31, 2025, we were directly the contractual operator of 7 of the 11 blocks in which we hold equity interest. Acreage As of December 31, 2025, our total production and exploration acreage, both gross and net, was as follows. The table includes the total production and exploration acreage by the Company, joint operations and associates. Acreage Production (1) Exploration (2) Gross(3) Net (4) Gross(3) Net (4) (in thousands of acres) Argentina 1,167 389 65 57 (1) Includes all areas in which we produce commercial quantities of oil and gas or areas in the development stage. (2) Includes all areas in which we are allowed to perform exploration activities but where commercial quantities of oil and gas are not produced, plus areas that are not in the development stage. (3) Does not include Río Limay Este area, which is in process of relinquishment. (4) Adjusted at our working interest ownership in the gross acreage. 46 Table of Contents Productive Wells As of December 31, 2025, our total gross and net productive wells were as follows. The table includes the total gross and net productive wells by the Company, joint operations and associates. Oil Gas Total (3) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Argentina 45 33 425 231 470 265 Note: All figures have been subject to rounding, so figures shown as totals may not add up. (1) Refers to the number of wells completed. (2) Refers to fractional ownership working interest in gross productive wells. (3) Includes Oil and Gas productive wells. Drilling Activities In 2025, we carried out investment plans aligned with our reserves replacement and production goals, as a means to achieve sustainable growth. A development well, for purposes of the following table, is one that justifies the installation of permanent equipment for the production of oil or gas. A well is deemed to be a dry well if it is determined to be incapable of commercial production. “Gross wells drilled” in the table below refers to the number of wells completed during each fiscal year, regardless of the spud date, and “net wells drilled” relates to our fractional ownership working interest in wells drilled. This table includes wells drilled by the Company, joint operations and associates (includes our discontinued operations). The following table sets forth the number of total wells we drilled in Argentina and the results for the relevant periods. Year ended December 31, 2025 2024 2023 Argentina Gross wells drilled: Production: Development wells: Oil 26 1 9 Gas 12 18 35 Dry wells - - - Total 38 19 44 Exploration: Discovery wells: Oil 2 - - Gas 1 - - Dry wells - - - Total 3 0 0 Net wells drilled: Production: Development wells: Oil 26 1 3 Gas 9 9 24 Dry wells - - - Total 35 10 27 Exploration: Discovery wells: Oil 1 - - Gas 1 - - Dry wells - - - Total 2 0 0 Note: All figures have been subject to rounding, so figures shown as totals may not add up. In 2025, our activity was focused on the development of our shale oil production in Rincón de Aranda, where 26 wells were drilled. Also, regarding oil, 1 exploratory net well was drilled in Rio Neuquén. As for gas, the core of the activity was concentrated in the Neuquén Basin, mainly in El Mangrullo and Sierra Chata, where 7 net wells were drilled in Sierra Chata, all of them being from shale reserves, Río Neuquén with net 2 wells drilled and Parva Negra with 1 exploratory well drilled. 47 Table of Contents Oil and Gas Production We transport our oil and gas production through several methods depending on the infrastructure available and the cost efficiency of the transportation system in a given location. We use the oil pipeline system and oil tankers to transport oil to our customers. Oil is customarily sold through contracts whereby producers are responsible for transporting produced oil from the field to a port for shipping, with all costs and risks associated with transportation borne by the producer. Gas, however, is sold at the delivery point of the gas pipeline system near the field and, therefore, the customer bears all transportation costs and risks associated therewith. Oil and gas transportation in Argentina operate in an “open access” non-discriminatory environment under which producers have equal and open access to the transportation infrastructure. We maintain limited storage capacity at each oil site and at the terminals from which oil is shipped. In the past, such capacity has been sufficient to store oil without reducing production during temporary unavailability of the pipeline systems, for example, due to maintenance requirements or temporary emergencies. During 2025, our production was concentrated in three basins: Neuquén, San Jorge and Noroeste. In Argentina, we own 446,000 net acres, and in the Neuquén basin — the most important basin in the country in terms of oil and gas production —we own approximately 315,000 net acres (representing 71% of our total acreage). Our most important fields in the Neuquén basin are Rincón de Aranda, El Mangrullo, Sierra Chata and Río Neuquén. As of December 31, 2025, we lifted hydrocarbons from 470 productive wells in Argentina. For the year 2025, our average daily production was 11,682 barrels of crude oil and 437 million cubic feet of natural gas. Gas production was maintained and Oil production increased 145% compared to our 2024 average. The following table sets forth our oil and gas production during 2025. Production figures represent our working interest in production (and are therefore net to the Company). In addition, the table includes our working interest in each field, operator and the expiration date of the concessions, in each case as of December 31, 2025. Although some of these concessions may be extended at their expiration, the expiration dates set forth below do not include any extensions not granted as of the date of this annual report. 2025 Production Production Blocks Location Basin Oil (1) Gas (2) Oil Equivalent (3) Operator Direct and Indirect Interest Expiration El Mangrullo Neuquén NQN 11 83,630 13,949 Pampa 100.00 % 2053 Sierra Chata Neuquén NQN 25 53,659 8,968 Pampa 45.55% 2053 Río Neuquén Neuquén/Río Negro NQN 300 16,867 3,112 YPF 33.07%(4)/31.42%(5) 2027/2051 Rincón del Mangrullo (6) Neuquén NQN 5 2,128 360 YPF 50.00% 2052 Río Limay Este (Ex Senillosa)(7) Neuquén NQN 0 0 0 Pampa 85.00% 2040 Aguaragüe Salta NOA 40 1,540 297 Tecpetrol 15.00% 2037 El Tordillo (8) Chubut CGSJ 393 297 442 Tecpetrol 35.67% 2027 La Tapera – Puesto Quiroga (8) Chubut CGSJ 15 0 15 Tecpetrol 35.67% 2027 Rincón de Aranda Neuquén NQN 3,448 807 3,582 Pampa 100.00% 2058 Veta Escondida Neuquén NQN 0 0 0 Pampa 55.00% 2027 Los Blancos Salta NOA 18 0 18 High Luck 50.00% 2045 Total 4,256 158,928 30,744 Note: All figures have been subject to rounding, so figures shown as totals may not add up (1) In thousands of boe. (2) Gas production represents only marketable production of natural gas excluding flared gas, injected gas and gas consumed in operations. In millions of cubic feet. (3) In thousands of boe. Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per barrel of oil equivalent. (4) Province of Neuquén. (5) Province of Río Negro. (6) Does not include Vaca Muerta formation. (7) In process of relinquishment. (8) the Company sold the area in October 2025. 48 Table of Contents The following table sets forth the production of oil and gas in Argentina for the relevant periods: Year ended December 31, 2025 2024 2023 Argentina Oil (1) Gas (2) Oil (1) Gas (2) Oil (1) Gas (2) Río Neuquén 300 16,867 293 19,720 297 20,071 El Mangrullo 11 83,630 17 96,179 25 78,128 Sierra Chata 25 53,659 83 40,505 21 29,004 Rincón de Aranda 3,448 807 329 0 0 0 Other blocks 472 3,965 1.020 4,426 1,420 5,449 Total 4,256 158,928 1,742 160,829 1,762 132,652 Note: All figures have been subject to rounding, so figures shown as totals may not add up. (1) Oil production includes other liquid hydrocarbons. Amounts in thousands of barrels. (2) Gas production represents only marketable production of natural gas excluding flared gas, injected gas and gas consumed in operations. Amounts in millions of cubic feet. Exploration Our strategy is focused on constantly searching for new exploration opportunities aligned with our growth targets. In Argentina, we own substantial acreage containing undeveloped unconventional reservoirs, including both tight and shale gas in the Neuquén basin. The following table lists our exploration blocks, joint operations and permits in Argentina as of December 31, 2025, the location and basin of each area, our net working interest and the expiration date for the exploration authorization. 2025 Production Blocks/UTE Location Basin Oil kbbl Gas mcf Total kboe Operator Interest Expiration Parva Negra Este Neuquén NQN 0 468 78 Pampa 85.00% 2025 Las Tacanas Norte Neuquén NQN - - - Pampa 90.00% 2027 Total Exploration Blocks 0 468 78 Total Production 4,256 159,396 30,822 Note: All figures have been subject to rounding, so figures shown as totals may not add up. As of December 31, 2025, we held interests in approximately 65,000 gross exploration acres in Argentina. Cost of Sales, Revenues and Price Cost of Sales, Royalties and Depreciation The following table sets forth our average cost of sales, royalties and depreciation cost in our oil and gas fields in each geographic area for the fiscal years ended December 31, 2025, 2024 and 2023. This table includes our net share of production, joint operations and associates. Year ended December 31, Argentina 2025 2024 2023 (in U.S.$ per barrel of oil equivalent) Production cost 7 6 7 Royalties 4 3 4 Depreciation 9 8 7 Total 20 17 18 Revenues The following table sets forth revenues for the oil and gas exploration and production business segment by geographic area for the fiscal years ended December 31, 2025, 2024 and 2023. Year ended December 31, 2025 2024 2023 Argentina (in millions of U.S.$) Oil 267 127 121 Gas 585 591 534 Others 10 12 11 Total 862 730 666 49 Table of Contents The following table sets forth the average sales price per barrel of oil and per million cubic feet of gas for each geographic area for the fiscal years ended December 31, 2025, 2024 and 2023. Year ended December 31, Average price of sale for barrel of Oil and for million cubic feet of Gas 2025 2024 2023 Argentina Oil (In U.S.$ per barrel of Oil) 63 73 69 Gas (In U.S.$ per thousand cubic feet) 4 4 4 Delivery commitments Natural Gas Created on November 16, 2020, Plan Gas.Ar seeks to promote Argentine natural gas production and manage the gas cost impact on the Priority Demand’s tariff through tendering long-term supply agreements (DNU No. 892/20). Initially, the term for onshore production was 4 years, with an additional 4 years for offshore production from January 2021. The term was extended until December 31, 2028, for the 70 million m3 per day base volume awarded under rounds 1 and 3 (DNU No. 730/22). Agreements are executed between producers (as sellers) and CAMMESA, gas distributors and ENARSA (as purchasers), with a 100% daily DoP and a 75% monthly ToP for CAMMESA and quarterly ToP for gas distributors and ENARSA. The awarded price is adjusted by the following factors: 0.82 in the summer period (October-April), and 1.25 (May-September) during the winter period for the base volume. CAMMESA and ENARSA, as purchasers, pay the awarded price, whereas gas distributors pay the price set forth in the effective tariff scheme, with the difference being offset by the Federal Government. Moreover, the Federal Government has set a compensation support guarantee system based on tax credit certificates, notwithstanding other applicable mechanisms. For more information about the different Plan Gas.Ar’s round tenders, please see “Item 4. The Argentine Energy Sector – Oil & Gas Regulatory Framework – Regulations Specifically Applicable to the Gas Market –Plan Gas.Ar.” Pampa participated and was awarded in all Plan Gas.Ar’s rounds in the Neuquina Basin. Each round’s conditions for Pampa are detailed below: Round Delivery Volume in million m3/day Price in U.S.$/MBTU Expiration 1 & 4.1 Annual flat 4.90(1) 3.60(2) December 2028 3 & 4.1 Annual flat 2.00 3.347(2) December 2028 4.2 Annual flat 4.80 3.485(2) December 2028 5.2 Northwest Monthly variable 13.5 – 70.5 thousand m3/day 6 – 9.8(4) December 2028 Note: 1) The total commitment from May 2021 is 7 million m3/day. Out of this, 4.9 are deliveries under Plan Gas.Ar and the balance is sold on the market. 2) 1.25 adjustment factor in the winter and 0.82 for the rest of the year. 3) It covers the months of May through September. 4) Prices start at U.S.$9.8/MBTU and drop to U.S.$6/MBTU in 2028. Once the Plan Gas.Ar commitments are fulfilled, the remaining natural gas will be allocated to industries, exports, CAMMESA’s monthly tenders and the spot market. Oil Regarding Oil deliveries, within the “Vaca Muerta Oil Sur Project”, we will hold a dispatch capacity of 50,000 barrels per day. For more information, see “Item 4. Our Business - Our Holding and Others Business – VMOS.” 50 Table of Contents Also, we have an agreement signed for 6,000 barrels per day in the “Proyecto Duplicar”, until the end of the Oldelval concession in 2037. For more information, see “Item 4. Our Business - Our Holding and Others Business – Oldelval.” Reserves We believe our estimates of remaining proved recoverable oil and gas reserve volumes to be reasonable. Pursuant to Rule 4-10 of Regulation S-X (Title 17 of the Code of Federal Regulations Part 210), proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that the project will commence within a reasonable time. The evaluation of our reserves covered the reserves located in areas operated and non-operated by the Company. The proved oil and natural gas reserves were estimated in accordance with Rule 4-10 of Regulation S-X and in accordance with the oil and gas reserves disclosure provisions of FASB Topic 932. GaffneyCline performed an independent audit of 99% of our estimated proved reserves as of December 31, 2025. We provided all information required during the course of the audit process to the satisfaction of GaffneyCline. See the Reserves Report by GaffneyCline, dated January 21, 2026, included as Exhibit 13.2 to this annual report. As of December 31, 2025, 2024 and 2023, 99%, 98%, and 99%, respectively, of our estimated proved oil equivalent reserves were audited by GaffneyCline. As of December 31, 2025, our liquid hydrocarbon and natural gas proved developed and undeveloped reserves totaled 295.8 million of oil equivalent barrels (boe), 57.0 million barrels of liquid hydrocarbons and 1,433.1 billion cubic feet, or 238.8 million boe, of natural gas, of which 1,407.2 billion cubic feet were estimated to be sales gas and 25.9 billion cubic feet were estimated to be consumed as fuel gas in operation (which are included in our total natural gas proved reserves). For variations of our reserves data, see Reserves Evolution below. Liquid hydrocarbons and natural gas accounted for 19% and 81%, respectively, of our total proved reserves as of December 31, 2025. As of December 31, 2025, proved developed reserves of crude oil equivalent represented 54% of our total proved reserves of crude oil equivalent and we had proved reserves equal to approximately ten years of production at 2025 volumes. The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas as of December 31, 2025, including joint operations and associates. Reserves as of December 31, 2025 Reserves Category Crude oil, condensate and natural gas liquids (millions of barrels) Natural Gas (billions cubic feet) Oil Equivalent (million boe) Proved Developed 24.0 814.2 159.7 Proved Undeveloped 33.0 618.9 136.1 Total proved reserves 57.0 1,433.1 295.8 Note: Totals may not exactly equal the sum of the individual entries because of rounding. The statements contained in this Item 4 regarding exploration and development projects and production estimates are forward-looking and subject to significant risks and uncertainties. Although we believe that these expectations reflected in these forward-looking statements are reasonable, we cannot guarantee that our actual levels of activity, production or performance will meet those expectations. See “Item 3. Key Information—Risk Factors.” 51 Table of Contents The following table sets forth the breakdown of our total proved reserves of liquid hydrocarbons and natural gas into proved developed and proved undeveloped reserves as of December 31, 2025, 2024 and 2023: 2025 2024 2023 Millions of boe (1) % of total proved reserves Millions of boe % of total proved reserves Millions of boe % of total proved reserves Proved developed reserves 159.7 54.0% 128.0 55.4% 128.4 64.5% Proved undeveloped reserves 136.1 46.0% 103.2 44.6% 70.6 35.5% Total Proved Reserves 295.8 100.0% 231.2 100.0% 199.0 100.0% Note: Totals may not exactly equal the sum of the individual entries because of rounding. During 2025, a total of forty-one “gross wells” were completed in the Rincón de Aranda, Sierra Chata, Río Neuquén blocks and Parva Negra Este exploration area. Fourteen wells from the Sierra Chata, Rincón de Aranda and Río Neuquén were changed from “proved undeveloped reserves” to “proved developed reserves”. Estimated reserves were subject to economic evaluation to determine their economic limits. Estimated reserves in Argentina are stated before royalties since royalties have the same impact as taxes on production and are not paid in kind and therefore are treated as operating costs. Reserves Evolution The table below sets forth total proved reserves and proved developed reserves of crude oil, condensate and natural gas liquids, and reserves of natural gas, at the dates indicated. This table includes our net share of the proved reserves of our joint operations and associates: Crude oil, condensate and natural gas liquids Natural gas Argentina Combined (in thousands of barrels) (in millions of cubic feet) (in million boe) (1) Total proved developed and undeveloped reserves as of December 31, 2023 11,586 1,124,245 199.0 Proved developed reserves as of December 31, 2023 7,592 724,775 128.4 Increase (decrease) originated in: Revisions of previous estimates -5 -10,011 -1.7 Improved recovery 253 56 0.3 Extensions and discoveries 9,167 321,665 62.8 Purchase of proved reserves 0 0 0.0 Sale of proved reserves -2,003 -365 -2.1 Year’s production -1,796 -151,417 -27.0 Total proved developed and undeveloped reserves as of December 31, 2024 17,201 1,284,172 231.2 Proved developed reserves as of December 31, 2024 4,409 741,634 128.0 Increase (decrease) originated in: Revisions of previous estimates 1,967 76,280 14.7 Improved recovery 0 0 0.0 Extensions and discoveries 43,106 221,718 80.1 Purchase of proved reserves 0 0 0.0 Sale of proved reserves -947 -700 -1.1 Year’s production -4,361 -148,363 -29.1 Total proved developed and undeveloped reserves as of December 31, 2025 56,967 1,433,107 295.8 Proved developed reserves as of December 31, 2025 23,994 814,199 159.7 (1) Gas converted to oil equivalent using a factor of 6,000 cubic feet of gas per barrel of oil equivalent. During 2025, previous estimates of our fields located in Argentina were subject to revisions representing an increase of 14.7 million boe mainly attributable to more than expected production performance in the Sierra Chata, El Mangrullo and Rincón de Aranda areas offsetting lower productivity in the Rio Neuquén area. Extension and discoveries increased by 80.1 million boe through drilling activities, in the Rincón de Aranda, Sierra Chata and Río Neuquén areas. Also, the sale of our interest in the El Tordillo area caused a reduction of 1.1 million barrels of oil equivalent in our reserves. 52 Table of Contents As of December 31, 2025, 54% of our “proved reserves” were developed, while 46% were undeveloped. Proved developed reserves were 159.7 million boe. During 2025, we invested U.S.$ 184 million in drilling, completion and facilities, to convert approximately 23.2 million boe of “proved undeveloped reserves” to “proved developed reserves”. Our “proved undeveloped reserves” were 136.1 million boe, all of which corresponded to wells offsetting existing “proved developed reserves” where the activity has been scheduled to target production levels in accordance with contracts and installed and future facilities. We plan to put approximately 94.7% of these “proved undeveloped reserves” into production through activities to be implemented over the next five years. The balance of 5.3% (7.2 million boe) will be developed over periods exceeding five years and are mainly located in gas fields where the activity has been scheduled to maintain production levels in accordance with contracts and installed facilities. The 32% increase (32.9 million boe) in our “proved undeveloped reserves” in 2025 compared to 2024 was mainly attributable to: (1) a decrease of 12.7 million boe by the conversion of “proved undeveloped reserves” to “proved developed reserves”, mainly through drilling, completion and workover activities performed in our production areas in the Neuquén basin, mainly in the El Mangrullo and Río Neuquén areas; (2) an increase of 44.2 million boe of “proved undeveloped reserves” by extensions and discoveries, through additional drilling activities, mainly in the El Mangrullo, Sierra Chata, Rincón de Aranda and Río Neuquén areas in the Neuquén basin; and (3) an increase of 1.2 million boe of “proved undeveloped reserves”, came from revisions of previous estimates mainly attributable to better performance than expected of proved undeveloped wells in the Rincón de Aranda and El Mangrullo areas. The activities described in items (1), (2) and (3) above resulted in a net increase of approximately 32.9 million boe in our “proved undeveloped reserves” in 2025 compared to 2024. Internal Control over Proved Reserves The reserves estimation process begins with an initial evaluation of our assets by geophysicists, geologists, and engineers. A Reserves Technical Officer (Jefe de Reservas) safeguards the integrity and objectivity of our reserves estimates by supervising and providing technical support to technical teams who are responsible for preparing the reserves estimates. Our technical teams have degrees in geophysics, geology, petroleum engineering and accounting, and are trained internally in reserves estimations seminars. The technical officer is responsible for consolidating and auditing the reserves estimation process in compliance with the SEC reserves guidelines. The technical officer primarily responsible for overseeing the preparation of our Reserves Report is a member of the Society of Petroleum Engineers, with over 30 years of experience in exploration and production activities. Our reserves estimates are approved by the Oil and Gas Exploration and Production Director. The reported hydrocarbon reserves were estimated based on professional, geological, and engineering judgment and on information available prior to December 31, 2025. Thus, they are subject to revisions, upward or downward, as a result of future operations or as additional information becomes available. The estimation of reserves is imprecise due to many unknown geologic and reservoir factors that can only be estimated through sampling techniques. Since reserves are therefore only estimates, they cannot be appraised for the purpose of verifying exactness. There are many uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including certain factors that are beyond our control. The reserves data set forth in this annual report solely represents estimates of our proved oil and gas reserves. Reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of reserves estimates stems from available data, engineering and geological interpretation and judgment of reserves and reservoir engineering. As a result, different engineers often obtain different estimates. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate, so the reserves estimates at a specific time are often different from the quantities of oil and gas that are ultimately recovered. Furthermore, estimates of future net revenues from our proved reserves and the present value thereof are based upon assumptions about future production levels, prices and costs that may prove to be incorrect over time. Estimates of future prices, costs and production volumes are subject to uncertainties and may prove to be incorrect over time. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Accordingly, we cannot provide assurances that any specified production levels will be reached or that any cash flow arising therefrom will be produced. The actual quantity of our reserves and future net cash flows therefrom may be materially different from the estimates set forth in this annual report. 53 Table of Contents We replace our reserves through the acquisition of producing fields, exploration, and by “proving up” reserves in existing fields. “Proving up” is the process by which additional reserves classified as “probable and possible reserves” in a producing field are accessed and reclassified as “proved reserves”. We prove up reserves with reservoir management techniques, such as appraisal wells, water flooding, and enhanced oil recovery projects. The reservoir management techniques currently used are appraisal wells, water injection, and the drilling of horizontal producing and injection wells. Technologies such as 3D seismic process, horizontal and step out wells, and reservoir numerical stimulation are also used. About the Independent Reserves Engineers Firm GaffneyCline has more than 50 years of excellence in energy consulting, with extensive experience in the world’s oil basins in estimating and auditing reserves and resources. GaffneyCline focuses solely on the petroleum and energy industry, and specializes in the provision of policy, strategy, technical and commercial assistance to governments, financial institutions, and national and international oil, gas and energy companies worldwide. The provision of Reserves and Resources assessments is a core component of GaffneyCline’s business. GaffneyCline is fully familiar with the SEC regulations regarding oil and gas reserves (Rule 4-10 (a) of Regulation S-X). GaffneyCline employs a combination of commercial and technical professionals in main offices in the United Kingdom, United States and Singapore, with supporting offices in Argentina, Australia and Brazil. This staff encompasses all upstream technical disciplines (geology, geophysics, petrophysics, reservoir engineering, drilling and completion and development planning / facilities engineering), with midstream and downstream engineering and economics, commercial, legal and business strategy professionals to complement its technical staff. The Reserves Report covered 99% of our estimated total “proved reserves”. In connection with the preparation of the Reserves Report, the Independent Reserves Engineers Firm prepared its own estimates of our proved reserves. In the process of the reserves evaluation, the Independent Reserves Engineers Firm did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of the Independent Reserves Engineers Firm that brought into question the validity or sufficiency of any such information or data, the Independent Reserves Engineers Firm did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. The Independent Reserves Engineers Firm independently audited reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition of SEC Regulation S-X Section 210.4-10(a) issued the Reserves Report based upon its evaluation. The Independent Reserves Engineers Firm’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us. The assumptions, data, methods and procedures used, were appropriate for the purpose served by such report, and the Independent Reserves Engineers Firm used all methods and procedures as it considered necessary under the circumstances to prepare such reports. Technology used in reserves estimation The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that the project will commence within five years. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. 54 Table of Contents There are various generally accepted methodologies for estimating reserves including volumetric, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using any of such deterministic methods. The particular method chosen should be based on the evaluator’s professional judgment as being the most appropriate, given the geological nature of the property, the extent of its operating history and the quality of available information. It may be appropriate to employ several methods in reaching an estimate for the property. Estimates must be prepared using all available information (open and cased hole logs, core analyses, geologic maps, seismic interpretation, production/injection data and pressure test analysis). Supporting data, such as working interest, royalties and operating costs, must be maintained and updated when such information changes materially. Our estimated “proved reserves” as of December 31, 2025, are based on estimates generated through the integration of available and appropriate data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments include information obtained directly from the subsurface via wellbore, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also include subsurface information obtained through indirect measurements, including high quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, geological outcrop information was also utilized. The tools used to interpret and integrate all this data included both proprietary and commercial software for reservoir modeling, simulation and data analysis. In some circumstances, where appropriate analog reservoir models are available, reservoir parameters from these analog models were used to increase the reliability of our reserves estimates. FLNG Project On January 15, 2025, we acquired an interest in the FLNG Project, together with Pan American Energy S.L., Golar FLNG Holding Company Limited, YPF and Harbour Energy. The vessel is expected to start operating in September 2027. Pampa’s share in the company that will undertake the FLNG Project, SESA, is 20%. SESA’s application to adhere to the RIGI, in accordance with Law 27,442, Regulatory Decree No. 749/24, and other regulations that may amend and/or complement them, to be considered a Strategic Long-Term Export Project was approved on April 29, 2025. On May 2, 2025, the consortium satisfied all conditions required to move forward with the development of the FLNG Project, including the final investment decision for Hilli and the approval of its application for enrollment under the RIGI. A second vessel, the “MKII”, was included in the project. Both units are expected to provide a combined processing and export capacity of approximately 6 million tons per year of LNG (equivalent to 27 million m³/day of natural gas). The FLNG Project represents an estimated investment of approximately U.S.$ 7 billion over its 20-year operational horizon and is expected to position Argentina as a participant in the global LNG market. Operations of the Hilli and the MKII are expected to begin in late 2027 and 2028, respectively. To supply natural gas to both vessels, SESA entered into 20-year natural gas supply agreements with Pampa, Pan American Energy, YPF and Wintershall, each in proportion to its equity participation in SESA. The project also contemplates the construction of a dedicated gas pipeline from the Province of Neuquén to the San Matías Gulf to ensure year-round operation of both vessels, to be developed by the company San Matias Pipeline S.A., where we also hold a 20% interest. The FLNG Project is strategic to monetizing our Vaca Muerta reserves, positioning Argentina within the liquefied natural gas global market, and boosting foreign currency inflows, job creation, and the domestic supply chain. 55 Table of Contents Our Generation Business Our power generation assets include: CTG, CTP, CTPP, CTLL, CTIW, CPB, CTGEBA, HPPL, EcoEnergía, PEPE II, PEPE III, PEPE IV, PEPE VI and PEA and interests in CTB, HINISA and HIDISA (the latter two are currently in a transition period to end their license agreement). Renewable Energy PEPE II PEPE II is located on Provincial Route No. 51, 18 km from the city of Bahía Blanca in the province of Buenos Aires. It was commissioned in May 2019 with an installed capacity of 53 MW, representing 0.1% of Argentina’s power. Its 14 Vestas V-136 wind turbines, each with a capacity of 3.8 MW, have a hub height of 120 meters and a net capacity factor P50 of 56%. The average annual generation since 2020 has been 197 GWh. PEPE III PEPE III is located in Coronel Rosales, along National Route No. 3, 45 km from Bahía Blanca. It is a twin park of PEPE II with a net capacity factor P50 of 63% and an average annual generation of 221 GWh since 2020. PEPE IV Adjacent to PEPE III, PEPE IV provides 81 MW, equivalent to 0.2% of the country’s capacity, through 18 Vestas V-150 wind turbines of 4.5 MW each, with a hub height of 105 meters and a net capacity factor P50 of 63%. Since 2023, the average annual generation has been 244 GWh. PEA PEA is located in the province of La Rioja, 90 km north of the provincial capital along Provincial Route No. 9. It was acquired by Pampa in December 2022. PEA has 38 Siemens Gamesa G-114 wind turbines of 2.625 MW each, with a hub height of 80 meters and a net capacity factor P50 of 43%. Its installed capacity is 100 MW, representing 0.2% of Argentina’s power. PEA was commissioned in March 2020 and sells its energy to CAMMESA under the RenovAr program (Round 1). The historical average annual generation since 2020 has been 284 GWh. PEPE VI PEPE VI was commercially commissioned in different stages commencing in July 2024 and was completed in November 2024. PEPE VI features 31 Vestas wind turbines of 4.5 MW each, with a total installed capacity of 139.5 MW, representing 0.3% of Argentina’s power. In 2025, it generated 583 GWh. Hydroelectric Generation Plants We hold interests in three hydroelectric generation plants Hidroeléctrica Diamante (through HIDISA), Hidroeléctrica Los Nihuiles (through HINISA) and HPPL (which we fully own). HIDISA (in transition period) We own 61% of the voting capital stock of HIDISA, a hydroelectric generation company, located in the Province of Mendoza. The Province of Mendoza, through EMESA, currently owns the remaining capital stock of HIDISA. HIDISA operates under a provincial concession for the hydroelectric use of water from the Diamante River, located in the department of San Rafael in the Province of Mendoza, and under a national concession for the generation, sale and bulk trading of electricity from Diamante’s hydroelectric system (the “Diamante System”). The Diamante System consists of three dams and three hydroelectric power generation plants (Agua del Toro, Los Reyunos and El Tigre). The Diamante System covers a total distance of approximately 55 km with a height differential between 873 m and 1,338 m. HIDISA has an installed capacity of 388 MW, which represents 0.9% of the installed capacity in Argentina. From 1990 to 2025, the average annual generation has been 528 GWh, with the highest level of generation (943 GWh) recorded in 2006 and the lowest level (303 GWh) recorded in 2022. Also, HIDISA owns 0.9% of the capital stock of TJSM and 0.8% of the capital stock of TMB. 56 Table of Contents HINISA (in transition period) We own 52.04% of the voting capital stock of HINISA, a hydroelectric generation company, located in the Province of Mendoza. The Province of Mendoza, through EMESA, currently holds the remaining capital stock of HINISA. HINISA operates under a provincial concession for the hydroelectric use of water from the Atuel River, located in the department of San Rafael in the Province of Mendoza (approximately 1,100 km southwest of Buenos Aires) and under a national concession for the generation, sale and bulk trading of electricity from the Los Nihuiles’ hydroelectric system (the “Nihuiles System”). The Nihuiles System consists of three dams and three hydroelectric power generation plants (Nihuil I, Nihuil II and Nihuil III), as well as a compensatory dam, which is used to manage the system’s water flow for irrigation purposes. The Nihuiles System covers a total distance of approximately 40 km with the grid’s height ranging from 754 m to 1,251 m. HINISA has an installed capacity of 265 MW, which represents 0.6% of the installed capacity in Argentina. From 1990 to 2025, the average annual generation was 767 GWh, with the highest level of generation (1,250 GWh) recorded in 2006 and the lowest level (283 GWh) recorded in 2025. HINISA also owns 1.6% of the capital stock of TJSM and 1.4% of the capital stock of TMB. Termination of concessions. The original term of the HINISA and HIDISA concession agreements was 30 years, starting from June 1, 1994 in the case of HINISA and October 19, 1994 in the case of HIDISA. Thus, the original concessions expired during 2024. However, under the relevant concession agreements both the national and provincial governments opted to extend the concession term for a one-year period as provided therein. Consequently, the reversion of the concession was postponed until June 1, 2025 in the case of HINISA. In the case of HIDISA, the SE extended the transition period until June 1, 2025, while the Province of Mendoza extended it until October 19, 2025. On March 8, 2025, the National Government and the Province of Mendoza signed an agreement to jointly carry out the public national and international bidding process for the concession of the Diamante and Nihuiles Hydroelectric Complexes as a single business unit. The bidding process will include the transfer of 51% of the shareholding package of the company that becomes the concessionaire and owner of the assets. However, as of the date of this report, the tender has not been launched. On May 26, 2025, by Law No. 6,930, the Province of Mendoza declared an emergency with respect to the Nihuiles System for a 14-month period and extended the term of the concession. The Company stated that such an extension requires an agreement with HINISA. However, the National Concession of HINISA expired on June 1, 2025, and, in the absence of a determination by the authorities, HINISA decided to continue operating to safeguard the concession assets, electricity supply, and the safety of people and facilities. Such continued operation does not imply that HINISA unilaterally accepts the extension or assumes new obligations or responsibilities, nor that it waives its rights under the Concession Agreements. On October 20, 2025, the SE proposed to extend HIDISA’s concession until June 2026, subject to HIDISA’s adherence to the conditions of the original contract and to new provisions, including the update of guarantees, waiver of claims against the State due to changes in the remuneration scheme, and payment of royalties to the Province of Mendoza (SE Resolution No. 398/25). Law No. 6,930 authorized HIDISA to continue with the use of water for the operation of the hydroelectric assets. On November 19, 2025, HIDISA confirmed its adherence to the proposed extension. HPPL In August 1999, we were awarded a 30-year concession for hydroelectric power generation at HPPL. The HPPL complex, located in the Comahue region, Province of Neuquén, has three electricity generating units. The dam is constructed of loose materials with a waterproof concrete side. The dam has a total length of 1,045 m, a total height of 54 m at the deepest point of the foundation, and a crest at 480.2 m above sea level. HPPL has an installed capacity of 285 MW, which represents 0.7% of Argentina’s installed capacity. From 2000 to 2025, HPPL’s average annual generation was 912 GWh, with a generation record high of 1,430 GWh in 2006, and a record low of 494 GWh in 2016. 57 Table of Contents Summary of HPPL concession HPPL’s concession was granted pursuant to the following terms and conditions: Term. 30 years, starting August 30, 1999. Royalty payments. According to the concession contract and applicable laws, we pay 12% for hydroelectric royalties and a 0.5% monthly fee to the Argentine Government for the use of the water resource. Such amounts are calculated based on the tariff rate applied to the electricity block sold. Contingency fund. We make quarterly payments to a foundation that owns and manages a contingency fund created to cover up to 80% of the difference between the aggregate amount of potential costs relating to any repair of the hydroelectric systems at any of the hydroelectric generation plants and U.S.$5 million, to the extent such costs are not covered by their respective insurance policies. Fines and Penalties. Under the HPPL concession agreement, we are subject to potential penalties and fines. They are calculated based on the aggregate gross amount invoiced during a 12-month period prior to the imposition of such penalties according to the following ranges: (i) from 0.1% to 1% in cases of breach of the terms of the agreement or regulations applicable to power generation, dam safety, water management, environmental protection, and non-compliance of instructions from the Organismo Regulador de Seguridad de Presas (ORSEP), CAMMESA, any of the regulatory authorities or the ENRE; (ii) from 0.02% to 0.2% in cases of delays or lack of payment of contributions to the contingency fund and insurance policies and for taking action without prior authorization of the respective regulatory authorities; (iii) from 0.01% to 0.1% in cases of failure to submit any requested information or failure to file mandatory reports; (iv) from 0.03% to 0.3% in cases of failure to keep routes and roads open to traffic and free from soil, air or water pollution, and delays in the fulfillment of mandatory work; and (v) from 1% to 10% in cases of any actions considered by the regulatory authorities as termination events under the concessions. If the fines imposed in a 12-month period exceed 20% of the gross amount invoiced for power sales, the granting authority would be entitled to terminate the relevant concession agreement. Performance guarantees. As security for the performance of the obligations under the HPPL concession, we have deposited Ps.2.0 million for the benefit of the relevant granting authority. Upon the expiration or termination of the concession agreement, in case there is no set-off by the granting authority in the event of a breach or any other event of non-compliance under the terms of the concession agreement, such amount will be released. Termination of concessions. HPPL’s concession agreements may be terminated upon the occurrence of any of the following events: (i) breach of material contractual and legal obligations, in which case we shall remain in charge of the concessions during a transitional period established by the granting authority, not exceeding 12 months, and shall indemnify the Argentine Government for any damages caused (the granting authorities may also apply the performance guarantee amounts toward the payment of any damages). A public bidding process would be called for the purpose of granting a new concession. After deducting all fines, interest and withholdings for prospective claims, the balance would be reimbursed to us as the only compensation for the transfer of the concessions; (ii) certain bankruptcy events, including any liquidation or winding-up proceedings, in which case the termination of the relevant concession shall be automatic; (iii) force majeure or certain actions by third parties that prevent compliance with the obligations under the concession agreement; or (iv) expiration of the term of the concession agreements. Thermal Generation plants CTGEBA CTGEBA is located in Marcos Paz, Province of Buenos Aires. The plant began operating in 1999 and has two CC, one with a 684 MW installed capacity, which consists of two gas turbines of 223 MW each and a 238 MW steam turbine, repowered in October 2020. The second CC consists of a gas turbine of 182 MW, known as Genelba Plus, which was commissioned in 2009 and repowered in June 2019, as well as a 188 MW gas turbine incorporated in 2019 under the expansion to CC process and steam turbine of 199 MW which was incorporated on July 2, 2020. Currently, the total installed capacity of the CTGEBA complex amounts to 1,253 MW, which represents 2.8% of Argentina’s installed capacity. From 2000 to 2025, CTGEBA’s historical average annual generation was 5,492 GWh, with a generation record high of 8,594 GWh in 2021, and a record low of 3,438 GWh in 2001. 58 Table of Contents CTEB CTEB is located in the City of Ensenada, Province of Buenos Aires, owned by CTB, a company that we jointly co-control with YPF. The plant began its operations in 2012 and consisted of (i) two open cycle gas turbines with an installed capacity of 569 MW; and (ii) a steam turbine that completed the combined cycle with a capacity of up to 279 MW, which entered commercial operations on February 22, 2023. Both (i) and (ii) had a total installed capacity of 848 MW, which represented 1.9% of the installed capacity in Argentina. During 2025, a repowering project was carried out on both (i) and (ii) which, combined with the major maintenance of the turbines, required an investment of U.S.$ 30 million and enhanced CTEB’s installed capacity by an additional 34 MW, which would be elevated to 888 MW. From 2013 to 2025, the average annual generation amounted to 1,910 GWh, with a generation record high of 4,741 GWh in 2024, and a record low of 255 GWh in 2020. Pampa operated the power plant until December 31, 2023 and, as of January 2024, Pampa and YPFL jointly operate CTEB under a shared operation scheme. CTLL CTLL is located in the Province of Neuquén. The plant was built in 1994 and consists of three gas turbines with an installed capacity of 375 MW, a 180 MW Siemens steam turbine installed in 2011 for its closing to CC and repowered in January 2018, a 105 MW General Electric aeroderivative gas turbine installed in May 2016, the incorporation in August 2017 of a 105 MW General Electric gas turbine and 15 MW from MAN gas engines in August 2021. CTLL has a privileged location due to its proximity to one of the largest gas fields in Latin America, also named Loma de la Lata. CTLL has an installed capacity of approximately 780 MW, representing approximately 1.8% of Argentina’s installed capacity. From 1997 to 2025, CTLL’s average annual generation was 2,539 GWh, with a generation record high of 5,103 GWh in 2022, and a record low of 272 GWh in 2002. During 2025, a major maintenance overhaul was performed on the CC plant’s TG01 unit. The tasks included upgrading the generator and transformer protections, as well as a complete replacement of the excitation system. A major inspection was conducted, featuring a turbine rotor replacement to extend its service life. The generator maintenance involved electrical measurements and preventive work on the Instrumentation and Control systems. Additionally, casing alignment and transformer bushing replacements were carried out, ensuring the unit’s operational reliability and efficiency. CPB CPB is a thermal generation plant located in Ingeniero White, Bahía Blanca, Province of Buenos Aires, approximately 600 kilometers away from the City of Buenos Aires. CPB is an open-cycle thermal generation plant that consists of two identical conventional units (Unit 29 and Unit 30) with an installed capacity of 310 MW each. CPB can be powered either by natural gas or by oil No.6 (though it was originally designed and partially equipped to burn coal as well). The plant currently stores up to 60,000 m3 of fuel oil in two separate storage tanks and owns, operates and maintains a 22-kilometer natural gas pipeline that is connected to the main pipeline of TGS. CPB has an installed capacity of 620 MW, which represents 1.4% of Argentina’s installed capacity. From 1997 to 2025, CPB’s average annual generation was 1,744 GWh, with a generation record high of 3,434 GWh in 2011, and a record low of 189 GWh in 2002. CTG CTG is located in the northwestern region of Argentina, in the City of General Güemes, Province of Salta. Privatized in 1992, it has a total installed capacity of 361 MW, comprised of (i) 261 MW from steam generation units and (ii) 100 MW from a gas combustion turbine, which accounts for 0.8% of Argentina’s installed capacity. From 1993 to 2025, its average annual generation was 1,486 GWh, with a generation record high of 1,903 GWh in 1996, and a record low of 225 GWh in 2022 and 2023. CTIW CTIW is located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires, and consists of six high-efficiency Wärtsilä engines. Liquid fuel supply is made using CPB’s discharge and storage facilities, and natural gas is also supplied from this power plant internal facilities. The plant has a total power installed capacity of 100 MW, which accounts for 0.2% of Argentina’s installed capacity. The annual average energy generation from 2018 to 2025 was 221 GWh, with a generation record high of 312 GWh in 2019, and a record low of 134 GWh in 2025. 59 Table of Contents CTPP CTPP is located in the Pilar Industrial Complex, in the district of Pilar, Province of Buenos Aires. Construction began in October 2016, and the plant was commissioned on August 29, 2017. The plant is made up of six cutting-edge Wärtsilä engines. Natural gas is supplied through a gas pipeline owned by Transportadora de Gas del Norte S.A. and the energy is evacuated through an output field of a 132kv double-bar cable, together with all the necessary auxiliary equipment, in the Pilar Substation No. 158 owned by Edenor (“Pilar Substation”), located at the Pilar Industrial Complex. The power plant has storage tanks for fuel oil which may be used as alternative fuel. CTPP has a total power capacity of 100 MW, which accounts for 0.2% of Argentina’s installed capacity. The annual average energy generation from 2018 to 2025 was 213 GWh, with a generation record high of 321 GWh in 2022, and a record low of 139 GWh in 2025. CTP CTP is located in the northwestern region of Argentina, in a location known as Piquirenda, District of Aguaray, Department of General San Martín, in the Province of Salta. Its construction started in early 2008 and was completed in 2010. CTP has a 30 MW thermal electricity generation plant including ten Jenbacher (model JGS 620) gas-powered motor-generators, which accounts for 0.1% of Argentina’s installed capacity. From 2011 to 2025, its average annual generation was 96 GWh, with a generation record high of 156 GWh in 2017, and a record low of 52 GWh in 2022. ECOENERGÍA EcoEnergía is a co-generation power plant located at TGS’ General Cerri complex in Bahía Blanca, in the Province of Buenos Aires. The plant was commissioned in 2011 and consists of a steam turbine. EcoEnergia has a power capacity of 14 MW, which accounts for 0.03% of Argentina’s installed capacity. From 2012 to 2025, EcoEnergía’s average annual generation amounted to 81 GWh, with a generation record high of 108 GWh in 2018, and a record low of 54 GWh in 2025. The following chart depicts our generation assets and our respective shares of the Argentine power generation market as of and for the years ended December 31, 2025, 2024 and 2023. Our generation operations derive revenues from the sale of electricity in the spot market and under term contracts, including Energía Plus contracts and WEM Supply Agreements. Summary of Electricity Generation Assets Wind Hydroelectric Subtotal Hydro + Wind PEMC (1) PEPE II PEPE III PEPE IV PEA PEPE VI (2) HINISA HIDISA HPPL Installed Capacity (MW) - 53 53 81 100 140 265 388 285 1,365 Market Share - 0.1% 0.1% 0.2% 0.2% 0.3% 0.6% 0.9% 0.7% 3.1% Net Generation 2025 (GWh) - 206 241 361 322 583 283 520 558 3,074 Market Share - 0.1% 0.2% 0.3% 0.2% 0.4% 0.2% 0.4% 0.4% 2.2% Sales 2025 (GWh) - 215 241 361 322 583 283 520 558 3,083 Net Generation 2024 (GWh) - 188 202 341 343 197 857 616 890 3,633 Variation Net Generation 2025-2024 - 10% 20% 6% (6)% - (67)% (16)% (37)% (15)% Sales 2024 (GWh) - 201 202 341 343 195 857 616 890 3,643 Net Generation 2023 (GWh) 193 209 204 274 326 - 543 361 1,060 3,170 Variation Net Generation 2024-2023 (100)% (10)% (1)% 24% 5% - 58% 71% (16)% 15% Sales 2023 (GWh) 193 213 217 274 326 - 543 361 1,060 3,187 In U.S.$/MWh Avg. Price 2025 - 89 63 63 79 63 21 28 20 49 Avg. Price 2024 - 81 64 64 82 64 13 21 13 35 Avg. Gross Margin 2025 - 48 54 54 56 55 3 17 7 35 Avg. Gross Margin 2024 - 49 57 57 64 59 5 10 5 24 Sources: Pampa Energía S.A. and CAMMESA. Note: Gross margin before amortization and depreciation. All figures have been subject to rounding, so figures shown as totals may not add up. (1) Divested in July 2023. (2) Gradual commissioning: 45 MW (Jul-24), 36 MW (Aug-24), 13.5 MW (Sep-24), 18 MW (Oct-24), 27 MW (Nov-24). 60 Table of Contents Summary of Electricity Generation Assets Thermal CTLL CTG CTP CPB CTPP CTIW CTGEBA ECO-ENERGÍA CTEB(1) Subtotal Total Installed Capacity (MW) 780 361 30 620 100 100 1,254 14 848 4,107 5,472 Market Share 1.8% 0.8% 0.07% 1.4% 0.2% 0.2% 2.8% 0.03% 1.9% 9.3% 12% Net Generation 2025 (GWh) 4,326 261 53 514 139 134 8,144 54 4,325 17,950 21,024 Market Share 3.1% 0.2% 0.04% 0.4% 0.1% 0.1% 5.8% 0.04% 3.1% 12.7% 14.8% Sales 2025 (GWh) 4,244 448 53 514 139 134 8,566 123 4,321 18,542 21,625 Net Generation 2024 (GWh) 4,754 303 59 262 192 145 7,584 70 4,741 18,111 31,743 Variation Net Generation 2025-2024 (9)% (14)% (9)% 96% (27)% (8)% 7% (23)% (9)% (1)% (3)% Sales 2024 (GWh) 4,705 625 59 262 192 145 8,043 150 4,733 18,914 22,557 Net Generation 2023 (GWh) 4,512 225 75 606 274 265 7,548 68 4,236 17,809 20,979 Variation Net Generation 2024-2023 5% 34% (22)% (57)% (30)% (45)% 0% 4% 12% 2% 4% Sales 2023 (GWh) 4,470 547 75 606 274 265 8,224 146 4,236 18,842 22,029 In U.S.$/MWh Avg. Price 2025 32 88 62 92 - - 39 39 36 42 43 Avg. Price 2024 20 54 30 124 - - 38 36 30 36 36 Avg. Gross Margin 2025 18 38 23 46 - - 20 14 26 24 26 Avg. Gross Margin 2024 17 21 3 24 - 142 19 10 24 22 23 Sources: Pampa Energía S.A. and CAMMESA. Note: Gross margin before amortization and depreciation. All figures have been subject to rounding, so figures shown as totals may not add up.(1) We hold an interest of 50% in CTB. Our Petrochemicals Business The petrochemicals segment is vertically integrated into our gas operations, allowing us to maximize the value chain and consolidate our position in the styrenics market. Our products include octane bases for gasoline, benzene, aromatic solvents, hexane and other hydrogenated paraffinic solvents, propellants for the cosmetic industry, styrene monomer, rubber and polystyrene for markets in Argentina and abroad. The performance of this segment is influenced by global supply and demand. Pampa is the only Argentine producer of styrene monomer, polystyrene and elastomers, and the only integrated manufacturer transforming oil and gas into plastics. As part of the integration strategy, we use our benzene production to obtain styrene, which in turn is used in the production of polystyrene and SBR. 61 Table of Contents The petrochemicals division has the following assets: · an integrated petrochemicals complex at PGSM, located in the Province of Santa Fe, with an annual production capacity of 50,000 tons of gases (LPG), which are used as raw material and propellants, 160,000 tons of styrene, 55,000 tons of SBR, 180,000 tons of ethylbenzene and 31,000 tons of ethylene. At the same site, we operate a reforming plant with a production capacity of 155,000 tons of aromatics, 290,000 tons of gasoline and refined products; and · a polystyrene plant located in the City of Zárate, Province of Buenos Aires, with a production capacity of 65,000 tons of polystyrene. The following table sets forth main indicators of sales by major product for the petrochemical division in Argentina for the fiscal year ended December 31, 2025, 2024 and 2023: 2025 2024 2023 Technical Information Sales (in thousand ton): Styrene (incl. propylene) & Polystyrene 84 88 111 SBR 41 45 43 Reforming & Others 335 336 250 Regarding styrene, 2025 continued to be marked by demand contraction and increased competition from imports. In the domestic market, SBR and styrene volumes decreased by 25% and 9% year-on-year, respectively, while polystyrene remained flat. The sales decrease was offset by the 67% year-on-year growth in styrene exports to Brazil. A 63% and 5% drop in polystyrene and SBR exports were recorded, respectively. Regarding propylene, sales volumes declined by 54% to 3 kton due to lower ethylene plant throughput and increased propane-propylene recirculation. Regarding Reforming, 2025 sales remained flat, driven by increases of 11% in solvents and 185% in aromatics, partially offset by decreases of 5% in octane bases, 3% in gasoline and 28% in propellant. 382 kton of raw gasoline were processed, 6% more than in 2024, including 68 kton of imports. Our Holding and Other Business Our holding and other business segment is comprised, among other holdings, of our direct and indirect interest in TGS and Transener. Our Interest in TGS TGS is Argentina’s main gas transportation company and operates the largest pipeline system in Latin America. It is also a leading company in producing and commercializing NGL, conducting this business from the General Cerri Complex located in Bahía Blanca, Province of Buenos Aires. TGS provides comprehensive natural gas solutions, including transportation to the main pipeline via the Vaca Muerta gathering pipeline, treatment at the Tratayén plant, and injection into the main gas pipeline. It also provides telecommunications solutions through its controlled company, Telcosur. As of December 31, 2025, Pampa holds a 26.9% interest in TGS. Description of TGS’ Business Segments Regulated Segment: Gas Transportation Revenues in this segment come mainly from firm transportation contracts, which guarantee the reservation of pipeline capacity through payment regardless of actual use, and, to a lesser extent, from interruptible services subject to availability. In addition, TGS operates and maintains gas transportation assets expanded by the Federal Government and held under trusts created for such purposes. For this service, TGS receives the Charge for Access and Use, set by ENARGAS as the regulatory entity. 62 Table of Contents In 2025, revenues from this segment amounted to U.S.$ 485 million, representing 41% of TGS’s total revenues, and grew 13% compared to 2024, driven by tariff updates and the five-year tariff review approval since May 2025. 80% of regulated revenues come from firm transportation contracts (compared to 84% in 2024), with a weighted average life of approximately 11 years and an average contracted firm capacity of 89.3 million m3 per day. In 2025, 71 new contracts were executed for interruptible transportation and 57 for exchange and displacement services. In 2025, the average daily gas injection into the system operated by TGS was 86.4 million m3 per day flat compared to 2024, including contributions from the Austral, Golfo San Jorge and Neuquina Basins, and the gas fed into the GPM in Salliqueló, which averaged 16.1 million m3 per day, 39% more than in 2024. Non-Regulated Segment: Production and Marketing of Gas Liquids In 2025, revenues from this segment amounted to U.S.$ 454 million, 16% lower than those recorded in 2024, mainly due to the climate event at the Cerri Complex in March 2025 and lower international reference prices. On March 7, 2025, an extraordinary flood affected the Cerri Complex, fully interrupting NGL production and partially disrupting natural gas transportation, while damaging the infrastructure of the city of Bahía Blanca. Given the asset’s strategic nature, gas transportation was fully and reliably restored by March 24, with no material impact on business revenues. The liquids segment remained shut down until mid-April 2025, resuming operations gradually and reaching normal production levels in early May. TGS submitted the relevant documentation to the insurance companies to recover damages incurred. Liquids production and commercialization activities are carried out at the Cerri Complex, located close to the City of Bahía Blanca and supplied by all of TGS’s main gas pipelines. Ethane, propane, butane and natural gasoline are recovered at this complex. TGS sells liquids in both domestic and foreign markets. In the domestic market, propane and butane are sold to reseller companies. These products and natural gasoline are sold at international reference prices in the foreign market. Moreover, ethane is sold to Polisur at a price agreed between the parties. In 2025, the total volume sold amounted to 1,077 ktons, although there was a temporary interruption at the Cerri Complex. The prompt restoration of operations and the plant’s resilience allowed the liquids segment to maintain stable operating performance. Richer gas from Vaca Muerta and the offshore Fénix field partially offset reduced gas availability from the Austral Basin and maintained process efficiency. Fifty-nine percent of volumes sold were destined to the domestic market, with 83% of prices denominated in U.S.$. While TGS continued to participate in government programs such as the Household Gas Bottles Program, sales prices converged toward export-parity levels. Ethane sales totaled 334,596 tons in 2025, an increase compared to the 309,894 tons sold in 2024, despite the impact of the flooding event. The dispatch of Liquefied Petroleum Gas was carried out from the Galván Plant, totaling 303,106 tons, compared to 331,751 tons in 2024. This distribution channel primarily supplies domestic demand and neighboring countries, while enhancing operating margins and expanding the customer base. Natural Gas Liquids exports recorded U.S.$ 201 million in revenues, representing 44% of segment sales and 41% of commercialized volumes. For natural gasoline, exports in 2025 were made under a two-year contract with Trafigura, priced at international benchmarks minus a discount. In addition, TGS entered into a new contract with ATMI TotalEnergies (a subsidiary of TotalEnergies) from March 2026 to February 2028, improving the prevailing commercial terms. Non-Regulated TGS’s Segment: Midstream and Other Services The midstream segment is not subject to ENARGAS regulation. The midstream segment includes gas collection, treatment, and compression services, with a focus on Vaca Muerta, and INTEGRA’s services, including the operation and maintenance of third-party facilities, such as gas pipelines and plants. It also includes telecommunications, provided by the subsidiary Telcosur. 63 Table of Contents In 2025, the segment’s revenues were U.S.$ 244 million, 21% of TGS’s total, an 18% increase compared to 2024, mainly due to increased natural gas volumes transported and conditioned in Vaca Muerta, in line with the growth from non-conventional production. Since 2018, TGS has focused on being a leading provider of integrated services and a key player in the country’s energy development, having invested more than U.S.$ 700 million in midstream infrastructure, a 183-kilometer gas pipeline network crossing multiple hydrocarbon blocks, and a gas conditioning plant in Tratayén that allows entry into the regulated transportation systems. During 2024 and part of 2025, TGS expanded the Tratayén plant’s capacity from 5.4 to 28 million m3 per day, with an approximate U.S.$ 350 million investment. Works consisted of installing two plants, each with a capacity of 6.6 million m3 per day, inaugurated in November 2024 and February 2025, respectively. This expansion enabled TGS to support production growth and capture higher processing volumes. Likewise, in 2025, TGS continued with engineering and economic-financial feasibility studies to expand the Tratayén plant. The project contemplates expanding processing capacity, adding NGL extraction, constructing a multiproduct pipeline to evacuate NGL, and developing new fractionation, storage, and dispatch facilities in Bahía Blanca. This project aims to anticipate the growing infrastructure demand driven by rising gas production. In telecommunications, Telcosur renewed and entered into new agreements with strategic customers in 2025, securing new accounts in key segments, thereby strengthening its presence and diversifying its revenue streams. TGS INTEGRA is the business unit that brings together all support services offered by TGS to the energy market, from third-party pipelines and plants’ operation and maintenance to the execution of minor works and pipeline repair works, scraper passage assistance, meter calibration, hydrocarbon sample analysis, turbines and compressors’ overhaul, among others. In 2025, hot-tap, integrity, engineering and operation, and maintenance services for the GPM were awarded. In addition, TGS INTEGRA installed a metering station on the Juana Azurduy Integration Gas Pipeline, a key piece of infrastructure to enable natural gas exports from Argentina to Bolivia and the region. Our Interest in Transener Transener is the leading company in Argentina’s utility service of high voltage electric energy transmission. It holds a concession over 15,456 km of transmission lines and 61 transforming stations, directly operating 86% of the country’s high-voltage lines. In turn, its controlled subsidiary Transba is in charge of the concession of 6,989 km of transmission lines and 116 transforming stations, the Main Distribution Transmission System of the Province of Buenos Aires. Transener also generates additional revenues from, among others, the operation and maintenance of lines and services provided to third parties. As of the date of this report, Pampa holds a 26.3% stake in Transener. The remaining capital stock is currently held by ENARSA and minority public shareholders as Transener’s Class B common shares are listed on the BASE. In July 2025, the Argentine government, through the Ministry of Economy, formally launched a national and international public tender process for the sale of the equity interest held by ENARSA in CITELEC. The process was initiated pursuant to the Ministry of Economy Resolution No. 1050/25 within the framework established by the Bases Law and Decree No. 286/25, which authorized the privatization of ENARSA through the divestiture of its business units. The process is being coordinated by the Agency for the Transformation of Public Enterprises, acting as the temporary executing authority. The award date is set to be on April 14, 2026. Transener was privatized in July 1993, when CITELEC was awarded the Argentine Government’s controlling stake in Transener. On August 5, 1997, Transener acquired 90% of Transba’s capital stock, when the Province of Buenos Aires privatized the company’s capital stock. 64 Table of Contents Operation and Maintenance The extra high voltage power transmission grid, operated and maintained by Transener, faces increasing demands year after year. On February 10, 2025, demand reached a new all-time high of 30,257 MW, exceeding by 2% the peak recorded in 2024. Despite the high demands, at the end of 2025, 0.42 failures per 100 km of line were recorded, a service quality consistent with accepted international parameters for companies operating and maintaining extra high voltage transmission systems. Annual revenues generated by this segment amounted to U.S.$ 362 million, representing 92% of Transener’s total revenues, a 24% increase when compared to 2024, explained by tariff normalization after the five-year tariff review approval in May 2025. On December 23, 2025, ENRE Resolution 811/25 approved the assignment of the rights and obligations under the COM Agreement for the Choele Choel – Puerto Madryn Interconnection from INTESAR to Transener, establishing remuneration for operation and maintenance per the applicable hourly rates. Business Development Annual revenues generated by this segment amounted to U.S.$ 32 million, representing 8% of Transener’s total revenues, a 15% decrease compared to 2024. Engineering services, works and maintenance Transener prioritizes projects that leverage its competitive advantages, with a growing focus on renewable energy and mining. In 2025, in addition to providing engineering consultancy for transforming stations in new wind farms, Transener expanded its services to include grid access, feasibility and electrical studies, basic engineering, and preparation of technical specifications for budget works. Since the beginning, Transener has been committed to operating, maintaining and providing specialized transmission services to private customers, either for exclusive use or linked to utilities, such as independent carriers. Its activities include transformer and bushing replacement, oil analysis, specialized diagnostics, fiber-optic repair, electric and magnetic field measurements, implementation of automated systems, and maintenance of lines and transformer stations, among other services. Transener has maintained a fair and transparent remuneration policy, with most contracts being continually renewed, reflecting the quality of the service and its customers’ satisfaction. Communications In 2025, Transener continued to offer infrastructure services to communication companies, including assigning dark fiber in its grid and renting space in microwave stations and their antenna-supporting structures. The increasing demand for these services has supported revenue growth, reflecting higher service volumes and stronger commercial conditions. Transener continues to provide specialized support for WEM agents’ operational communications and data transmission. VMOS On December 13, 2024, we confirmed our participation in the “Vaca Muerta Oil Sur Project” as shareholder of VMOS along with YPF, Vista Energy Argentina S.A.U., and Pan American Sur S.A., Pluspetrol S.A., Tecpetrol S.A., Shell Argentina S.A. and Chevron Argentina S.R.L. as Class A shareholders and Gas y Petróleo del Neuquén S.A. as Class B shareholder. We currently hold a 10.2% stake in VMOS, which may vary depending on the entry of other shareholders into the Project. VMOS is developing an investment project consisting of the construction, development, and operation of a pipeline approximately 437 km in length, running from Allen to Punta Colorada in the Province of Río Negro. The project will include a loading and unloading terminal with interconnected monobuoys, a tank farm, and ancillary facilities associated with these assets to export crude oil and liquids via very large crude carriers, known as VLCCs. The project will demand an estimated investment of U.S.$3 billion, funded through shareholders’ contributions and external financing. Pampa has secured a take-or-pay transportation contract for 50 kbpd, including storage and dispatch capacity. On November 15, 2024, VMOS submitted an application to join the RIGI, in accordance with the Bases Law and Regulatory Decree No. 749/24, as amended or supplemented from time to time, to be considered a Strategic Long-Term Export Project. Such application was approved on March 20, 2025 by the Ministry of Economy’s Resolution Nº 302/25. 65 Table of Contents VMOS will streamline crude oil evacuation and exports from the Vaca Muerta formation, and specifically, for us, from the Rincón de Aranda block, reduce logistics costs, open new markets for Argentine oil, increase foreign currency inflows, create employment opportunities and expand our firm transportation capacity. Oldelval As of December 31, 2025, Pampa holds a 2.1% direct interest in Oldelval, a company engaged in the operation of main oil pipelines that connect the Neuquina Basin to the Bahía Blanca harbor. The pipeline includes the system from the Comahue area to Allen, and the Allen-Puerto Rosales oil pipeline, easing oil exports and supplying the Plaza Huincul and Luján de Cuyo distilleries along the way. In 2025, the total transported volume averaged 70,644 m3, equivalent to 162.2 million bbl per day on an annualized basis, a 27% increase compared to 2024, mainly explained by the commissioning of Duplicar, a new 525-kilometer oil pipeline that passes through Río Negro, La Pampa and Buenos Aires, and a new terminal station in Puerto Rosales. The project increased oil transport capacity by 50,000 m3 per day and demanded a total investment of U.S.$ 1.4 million. The works ended on March 15, 2025, and Pampa holds 6,302 bpd of transport capacity. Transportation from Allen to Puerto Rosales reached 66,139 m3 per day on average. Refineries located in Neuquén and Mendoza received an average of 1,071 m3 per day and 3,434 m3, respectively. As of the end of 2025, the transportation capacity was 86,000 m3 without drag-reducing agents and 98,000 m3 per day with their use for the entire transportation system, consolidating its position as a critical infrastructure for the growth Vaca Muerta’s production. Enecor Pampa holds a 70% interest in Enecor, an independent power transportation company which provides operation and maintenance services, by subcontracting Transener, for 21 km of 132 kV double-triad electricity lines from the Paso de la Patria transforming station, in the Province of Corrientes. It is under a 95-year concession, which expires in 2088. Refinor We held a 28.5% interest in Refinor, whose other shareholders were YPF (50%) and Pluspetrol S.A. (21.5%). Refinor is engaged in crude oil refining, natural gas processing, product transportation, marketing and sales. On September 15, 2022, Pampa and Pluspetrol S.A. entered into an agreement with Hidrocarburos del Norte S.A. in order to sell their interest in Refinor that represented 50% of the outstanding capital stock and voting power of such company, and 100% of its Class A shares. The purchase price for the shares owned by us was U.S.$ 5.7 million, and the buyer paid 30% of such price at closing, and the remaining 70% balance was to be paid 12 months after closing. On December 22, 2023, we signed an amendment to the original agreement regarding the payment of the pending balance. On October 28, 2025, Hidrocarburos del Norte S.A. transferred all its shares in Refinor to YPF for a price of U.S.$ 25 million. In accordance with the purchase and sale agreement, in the event of a sale of the acquired interest to a third party, Hidrocarburos del Norte S.A. was required to apply any amount received for such transaction to immediately cancel in a single payment the amount due. Accordingly, in November 2025, the pending balance of U.S.$ 0.6 million was paid to Pampa. 66 Table of Contents Ecuador Oleoducto de Crudos Pesados In 2001, the Ecuadorian government signed with OCP S.A., OCP Ltd. and its shareholders an agreement for the “Construction and Operation of the Heavy Crude Oil Pipeline and Hydrocarbons Transportation Public Service” (the “Construction and Operation Agreement”) granting the rights to build and operate for a 20-year term a 503 km-long pipeline that runs from the northeastern region of Ecuador to the Balao distribution terminal on the Pacific Ocean coast. OCP S.A. operates the main private oil pipeline in Ecuador. The oil pipeline has a transportation capacity of approximately 450,000 barrels per day. The construction of the oil pipeline was completed and began its operations in 2003. On August 30, 2024, we acquired 36% of OCP Ltd., in which we already held 64% of the capital, for a price of U.S.$ 23 million, thereby increasing our indirect stake to 100%. As a result, we indirectly gained control of 100% of OCP S.A. The expiration of the pipeline concession was initially scheduled for January 20, 2024. However, successive extensions of the concession term were granted by the Ministry of Energy and Mines of Ecuador during 2024 —which extended the term first until July 31, 2024, then until August 19, 2024 and lastly until November 30, 2024, and on that date, all shares of OCP S.A. were transferred and delivered to the Ecuadorian State at no cost, along with the titles and rights to the pipeline’s assets, all in accordance with the pipeline concession contract. In compliance with the provisions of the Construction and Operation Agreement, OCP Ltd. arranged for OCP S.A. to provide to the Ministry of Energy and Mines of Ecuador with an Operational Guarantee and an Environmental Guarantee, each for the sum of U.S.$ 50,000,000, which would remain in force during the operational period until the ninetieth day following the expiration or termination of the Construction and Operation Agreement subject, among other conditions, to the non-existence of claims under such guarantees. Accordingly, on March 1, 2025 such guarantees should have been considered extinguished in accordance with their terms, as 90 days had elapsed since the termination of the Concession and the Construction and Operation Agreement. Notwithstanding the above, Citibank Ecuador had unjustifiably stated that OCP S.A. did not comply with certain formalities required for the guarantees to expire 90 days after the termination of the Construction and Operation Contract. On April 11, 2025, OCP Ltd. initiated an arbitration proceeding before the International Centre for Settlement of Investment Disputes in order to obtain the effective release of the Environmental and Operational Guarantees and to be compensated for the damages and losses caused by the lack of such release; and alternatively, to receive from the Ecuadorian State an amount equal to the Environmental and Operational Guarantees in addition to all damages and losses caused by Ecuadorian State actions, plus interest. On October 28, 2025, the Ecuadorian State instructed Citibank Ecuador to proceed with the guarantees release, which became no longer valid as of that day under the terms of the contract. On November 3, 2025, Citibank NY proceeded with the release of the guaranteed deposits funds. On November 14, 2025, OCP Ltd requested the discontinuance of the arbitration before the Arbitral Tribunal, and on December 15, 2025, the Ecuador State consented thereto. On January 23, 2026, the Arbitral Tribunal issued the order taking note of the discontinuance and, as a result, the arbitration proceedings were terminated. Incentive Regime for Large Investments The Bases Law and Decree No. 749/24 creates and regulates the RIGI, which establishes a specific promotion and incentive framework for certain investments made by Project Holding Vehicles (“VPU”) that meet the stipulated requirements. One of the main objectives of this regime is to encourage both domestic and foreign “Large Investments” in the country, strengthen competitiveness and economic sector development, increase exports, foster job creation, and ensure a predictable and stable environment for investors. 67 Table of Contents The RIGI is designed for projects in sectors such as forestry industry, tourism, infrastructure, mining, technology, steel industry, energy, oil, and gas, provided they comply with the regime’s requirements. VPUs have a two-year period from the effective date of the Bases Law to adhere to the regime. On February 19, 2026, pursuant to DNU No. 105/26, the deadline to join the RIGI was extended until July 8, 2027, and the exploration and production of liquid and gaseous hydrocarbons in greenfield blocks was incorporated into the regime. These activities may only be included in new projects, as well as the construction of associated treatment, storage, and transportation infrastructure. In addition, a minimum investment amount was set at U.S.$ 600 million for onshore developments and U.S.$ 200 million for offshore projects. Requirements for a “Large Investment” under RIGI To qualify as a “Large Investment” under RIGI, a project must meet the following conditions: - Minimum Investment Amount: The project must meet a minimum investment threshold in eligible assets, varying by sector but ranging from U.S.$ 200 million to U.S.$ 900 million. - Investment Execution Timeline: Within the first two years after the approval of the investment plan, the project must execute at least 40% of the minimum investment amount, with a variable percentage allocated for each of those years. - Long-Term Nature: A project is considered long-term if the present value of its expected cash flow, relative to planned capital investments during the first three years, does not exceed 30%. Special Regime for “Strategic Long-Term Export Projects” The RIGI also includes a specific framework for “Strategic Long-Term Export Projects”, aimed at positioning Argentina as a long-term supplier in international markets where it currently holds little presence. These projects require a minimum investment of U.S.$ 2 billion, which may be executed in U.S.$ 1 billion stages. While they receive special benefits, they must also meet the general requirements of the RIGI. Tax, Customs, and Foreign Exchange Incentives Projects qualifying under the RIGI will benefit from a range of tax, customs, and foreign exchange incentives, including: - A reduced corporate income tax rate of 25% for VPUs. - The ability for VPUs to pay VAT (including withholdings) on purchases, construction of fixed assets, or infrastructure investments to suppliers or ARCA (formerly AFIP) using Tax Credit Certificates. - The option to fully offset the Tax on Bank Debits and Credits against corporate income tax. - Exemption from export duties starting three years after the project adherence. - Partial and progressive exemption from the requirement to settle foreign currency earnings from exports in the local exchange market: (i) in the first two years, 20% of their foreign currency earnings; (ii) in the third year, the percentage increases to 40%; and (iii) by the fourth year onwards, it reaches 100% of their foreign currency earnings. Current Project Applications by Pampa and its affiliates under RIGI As mentioned, the Vaca Muerta Oil Sur Project, the FLNG Project and the RDA Project have applied for RIGI under the Strategic Long-Term Export Projects category. Vaca Muerta Oil Sur Project RIGI’s application was approved on March 20, 2025 by the Ministry of Economy’s Resolution Nº 302/25. As for the FLNG Project RIGI’s application was approved on April 29, 2025 by the Ministry of Economy’s Resolution Nº 559/25. As of the date of this report, the approval by the relevant authorities for the RDA Project RIGI’s application is pending. 68 Table of Contents Quality, Health, Safety and Environment We are committed to developing our businesses with the highest quality, safety, environmental and labor health standards for personal welfare, environmental care and energy efficiency. We want to meet current needs without compromising future generations, pursuing sustainable development. Our QHSE Policy incorporates essential principles for health and safety, environmental protection, efficient use of energy and natural resources, and our operations’ reliability. This approach includes ten management principles serving as a guide for agile and effective implementation. In 2025, we continued working on the Cultural Evolution Program in QHSE, complementing local initiatives and reinforcing operational excellence. The program had 9 initiatives, achieving more than 90% progress. We conducted an internal engagement survey that showed 98% favorability in health, safety, and environmental matters, exceeding 87% recorded in 2023. These results reflect the importance that Pampa places on the well-being of its people, environmental management, and sustainability. Management quality We further our management quality using ISO standards and the Argentine national quality prize model, seeking continuous improvement. We apply methodologies such as the operational risk management matrix (RMM), the QHSE performance cycle, certified management systems administration and daily management quality. We apply the RMM to reduce the risks inherent in our operations, in cycles. In 2025, we conducted the third cycle, increasing requirements and achieving a 30% reduction in major risks compared to 2023. Major risks associated with preventive management decreased from 13.2% to 9.8%. We maintained ISO 9001 (quality management), 14001 (environmental management) and 45001 (occupational health and safety) certifications in all businesses and ISO 55001 (asset management) in all power plants. During 2025, we expanded the ISO 9001 and ISO 45001 certifications to the PEPEs and conducted the external audit of 2024 emissions management at CTLL following ISO 14064-1 (Greenhouse Gases), receiving a positive recommendation. Finally, since 2013, outstanding improvement practices at Pampa have been selected to participate in the annual national meeting of the Argentine Society for Continuous Improvement (Sociedad Argentina Pro-Mejoramiento Continuo, SAMECO) to share our experiences and knowledge. In the 2025 annual meeting, we presented the work: “Electrical Safety Program” by E&P and “Cooling Tower Failure Detection” by CTEB. Health and Safety In 2025, we consolidated and expanded our strategic safety and health actions, strengthening the preventive culture and continuous improvement. Regarding management and digitalization, we implemented digital work permits that unify permit management, safe task analysis, and risk certificates, enhancing operational safety and day-to-day processes. For 2026, an offline version is planned that will integrate a single tool across the entire Company. We developed the Preventive Behavior Observations (OPC) dashboard in Power BI, enabling the analysis and identification of recorded OPCs and events that require a specific approach. In addition, we completed the communication campaign for the Golden Rules to reduce the risk of serious and/or fatal accidents. In 2026, theoretical and practical training will be further strengthened. In industrial hygiene, together with the Occupational Risk Insurance provider (ART), we assessed noise as a risk agent and implemented a Hearing Conservation Program to prevent noise-induced hearing loss. We continued with the Surveillance System for Carcinogenic Substances and Compounds established by the Superintendency of Occupational Risks. Environment We have been members of the United Nations Global Compact since 2019. We have participated again in the “Connecting Companies with the Sustainable Development Goals” program, organized by the Consejo Empresario Argentino para el Desarrollo Sostenible (“CEADS”) and Ernst & Young Argentina. We presented several initiatives contributing to Sustainable Development Goals (“SDG”) 3, 6, 7, 12, and 15. 69 Table of Contents In 2025, we conducted CO2-emission-reduction studies on venting and carbon capture in our reservoirs, as well as leak detection using infrared cameras for rapid maintenance. In addition, under the ISO 14064-1 requirements, we began developing a carbon-neutrality strategy and continued work on the scope 3 emissions inventory, including emissions from waste generated by our operations, business travel, and employee commuting. We also completed a current and potential water risk assessment at each of our assets and developed the biodiversity baseline for CTB, CTIW, CTEB, CTGEBA and CTPP. Throughout the year, we conducted periodic drills to ensure a rapid and effective response to emergencies, aligned all sites with the corporate standard for contingency and operations management, carried out on-site risk assessments, and continued training in the incident command system. Occupational Health Our health management prioritizes risk reduction and our teammates’ overall well-being. Regarding well-being and health promotion, we implemented preventive programs that included 1,180 immunizations, 20 bromatological assessments of cafeterias, over 900 hours of training in first aid and CPR, and nutrition consulting and training. Within the framework of the Alcohol, Drugs, and Psychoactive Substances Policy, we conducted 9,195 tests, with 117 cases detected among contractors, reinforcing a prevention culture. In addition, we carried out good manufacturing practice audits, microbiological evaluations of food products, and supplier oversight, ensuring food safety and quality across the Company. Corporate Responsibility Social investment is part of a strategic model for building relationships with our stakeholders, led jointly with the Foundation. With a solid commitment to society, we implement programs and actions geared toward improving individuals’ quality of life, strengthening education and enhancing the capabilities of the institutions in the communities where we operate. We have framed our social investment strategy on three axes: • Education: as a basis for growth and personal autonomy, essential for professional training; • Employability: a driver for the development of individuals and communities; and • Social inclusion: allows us to bring opportunities and resources to individuals and groups under vulnerable situations, promoting equal opportunities. Education Over 60% of the social investment budget was distributed to education-related initiatives. We supported educational pathways to promote completion of technical secondary education and facilitate the transition to university and tertiary studies. Scholarship recipients receive not only financial support, but also mentoring, training, field visits, and opportunities to engage with formal work environments, enabling them to broaden their professional outlook. In 2025, we supported 904 students, including 715 in the last three years of technical secondary schools and 189 at university and tertiary levels. As of December 2025, 254 secondary school students and 40 university students had graduated, mainly in fields related to our businesses, such as engineering. In addition, we launched a graduates’ network through the Conexión Joven project in partnership with Empujar, which supported 133 young people in their first exposure to the work environment and enabled 22 to continue and graduate from a second stage of intensive training with on-site practical experience. In terms of teacher training, we seek to strengthen educational quality and encourage the adoption of new teaching methodologies. In 2025, we implemented six initiatives addressing topics such as energy, professional practice programs, 3D design, and emotional management. A total of 891 teachers and school leaders from 269 schools in Neuquén, Mendoza, Salta, La Rioja, Santa Fe, and Buenos Aires participated. Labor placement training In 2025, more than 1,900 high school, college and university students took part in professionalizing practices, first-job workshops and training programs that strengthened their technical and personal skills, thus promoting their employability. A total of 730 professional training placements and workplace exposure experiences were carried out for students in the final years of technical and general secondary schools. Of these, 20% were carried out at Pampa’s assets, where 145 students from 23 schools completed nearly 15,000 hours of theoretical and practical training. 70 Table of Contents In coordination with strategic partners, we conducted 585 professionalizing practices in different environments, together with institutions such as UTN at San Rafael and Neuquén, UFLO, Siemens Foundation, 500RPM, and MSI. At the university and college levels, supervised professional internships and traineeships were facilitated for 3 scholarship students from Salta and Buenos Aires. We also promoted meetings with companies in collaboration with AcercaRSE, participation in sector-specific fairs alongside IAPG, and technical and interpersonal skills workshops delivered by professionals from Pampa and its subsidiaries. In addition, we implemented the Centro Pescar program for 56 students, which combined full-stack web development training with J.P. Morgan and Fundación Pescar, and technical support training delivered by Pampa’s IT team and Novatium, with the support of the L’Oréal and Karuna Foundations. In 2025, we offered vocational training courses with strategic partners. In Bahía Blanca, 69 people graduated from Buen Trabajo program, in partnership with Dow, Viterra, UTN Bahía Blanca, and the local municipality. In La Rioja, over 50 people completed two electrical training courses in alliance with Fundación VOZ, UNLaR, and the Municipality of Aimogasta. In Piedra del Águila, 26 people completed programs in water, gas, and sewage services, with Fundación Potenciar and the local municipality. To promote labor inclusion of people with disabilities, we granted scholarships to students from Fundación Baccigalupo to train as sports assistants. We continued providing supplies to the Accervil Protected Workshop, which employs people with motor disabilities, as well as to the Alamesa project, promoting inclusion through gastronomy. Social and community inclusion We continued developing productive activities with social and environmental impact through the Responsible Inclusive Purchasing Program. In 2025, we held the second business round and trade fairs in Salta, Mendoza, Santa Fe, Neuquén, and Buenos Aires, with direct impact on 130 people. We supported Poteco, a campaign promoting the circular economy through plastic recycling for tiles to schools and sports clubs. Regarding community partnerships, we strengthened our work with the Guaraní community of Piquirenda de Fátima in Salta through gender-focused workshops for children, teenagers, and families. With Fundación Solar Inti, we expanded the eco-efficient cookstoves project, reaching 86 families. Vocational training courses, health and nutrition talks, entrepreneurship spaces, productive fairs, and nutritional, social, and psychological aid were delivered with Pata Pila. We participated in public-private coordination initiatives, such as the Public-Private Laboratory of the Group of Foundations and Companies (GDFE) and Red Bahía in Bahía Blanca. In Neuquén, we developed processes to strengthen the social ecosystem and community planning. Professional volunteering is a central pillar of our social impact strategy. We had 10 active volunteer committees, with 119 employees who defined action plans with local partners. In 2025, 25 initiatives were promoted, with over 1,500 participations and 11,000 hours volunteered. Professional volunteering is one of the key focus areas to make our employees’ technical skills and expertise available to the community. Through initiatives in health, safety, employability, and education, we promote capacity, collaboration, and transparency development, and strengthen community trust. In 2025, volunteers from Buenos Aires, Mendoza, Salta, Santa Fe, La Rioja, and Neuquén participated. We conducted solidarity campaigns: a blood donation campaign; the “Empezamos con Todo” campaign to deliver school supplies to students; and the “Nos Juntamos Contra el Frío” campaign to provide warm clothing and food to schools, community kitchens, and senior centers. During Children’s Month, we organized recreational activities, and through the Christmas Eve in Solidarity initiative, 281 employees contributed over 600 hours to assemble 1,300 food boxes, which were distributed to 36 neighboring organizations. Finally, we developed social and community initiatives and projects focused on tangible improvements in the communities where we operate, including renovations in schools in Neuquén and Ingeniero White; supporting a rural-based family enterprise in Neuquén; the “Tejiendo Lazos” community initiative, to produce warm clothing year-round; and TEA Project to provide practical tools for educators. 71 Table of Contents Capital Expenditures For a discussion of our capital expenditures, see “Item 5. Operating and Financial Review and Prospects. Capital Expenditures”. Seasonality See “Item 5. Operating and Financial Review and Prospects-Factors Affecting Our Results of Operations-Electricity Demand and Supply”. Property, Plant and Equipment Most of our property is located in Argentina, mainly consisting of oil and gas assets that allow us to explore and exploit oil and gas reserves (mainly wells and drilling equipment), power plants (thermal plants, hydroelectric complexes and wind farms) and corporate office buildings. Insurance In our oil and gas business, we carry full insurance, including business interruption and general liability insurance. As of December 31, 2025, the total oil and gas assets covered under these insurance policies are valued at U.S.$1,333 million. In our generation business, we carry full insurance for each of our generation assets, including business interruption and general liability insurance. As of December 31, 2025, the total generation assets covered under these policies are valued at U.S.$7,327 million. In our petrochemical business and distribution business, we also carry full insurance, including business interruption and general liability insurance. As of December 31, 2025, the total assets covered under insurance policies are valued at U.S.$1,267 million. Patents and Trademarks None of our commercial activities are conducted under licenses granted by third parties. 72 Table of Contents THE ARGENTINE ENERGY SECTOR OIL & GAS REGULATORY FRAMEWORK The Argentine Hydrocarbons Law In 2014, Law No. 27,007 amended the Hydrocarbons Law No. 17,319, introducing new drilling techniques in the industry and changes to terms and extensions of exploration permits and exploitation concessions, levies and royalty rates, concepts for on- and off-shore unconventional exploration and exploitation, and a promotion regime pursuant to Decree No. 929/13, among others. Later, the Bases Law introduced substantial amendments to Hydrocarbons Law No. 17,319, with the following main objectives: maximization of revenues from the exploitation of hydrocarbon resources, free export (subject to the non-objection of the enforcement authority), hydrocarbon processing activities, among others. Unconventional Hydrocarbons Exploitation The Law conferred legal status to the concept of “Unconventional Hydrocarbon Exploitation Concession” (“CENCH”) created by Decree No. 929/13. The term unconventional hydrocarbon exploitation is defined as the extraction of liquid and/or gaseous hydrocarbons by unconventional stimulation techniques applied in reservoirs situated in geological formations of schist rock or slate (shale gas or shale oil), tight sandstone (tight sands, tight gas, tight oil), coal bed methane and/or deposits characterized, in general, by the presence of low permeability rocks. Holders of exploration permits and/or hydrocarbon exploitation concessions will be entitled to request a CENCH to the enforcement authority pursuant to the following terms: · The exploitation concessionaire may request, within its block, the subdivision of the existing block into new unconventional hydrocarbon exploitation blocks and the granting of a CENCH. Such request will be based on the development of a pilot plan aiming at the commercial exploitation of the discovered reservoir pursuant to acceptable technical and economic criteria and may only be made until December 31, 2028. After this date, no further applications for conversion will be accepted. · Holders of a CENCH that are also holders of a preexisting and adjacent exploitation concession may request the unification of both blocks as a single CENCH, provided they duly demonstrate the geological continuity of these blocks. Such request should be based on the development of a pilot plan. Terms for Exploitation Concessions and Permits The terms for the exploration permits will be established in each tender issued by the enforcement authority according to the exploration’s purpose (conventional or unconventional): i. Conventional exploration: the basic term is divided into two periods of up to three years each, plus an optional extension of up to five years. In this way, the maximum extension for exploration permits is reduced from fourteen to eleven years; ii. Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years, that is, up to a maximum of 13 years; and iii. On and off-shore exploration: the basic term is divided into two periods of three years each, plus an optional extension of one year each. Upon the expiration of the first period of the basic term, the permit holder will decide whether to continue exploring the block or to transfer it back in whole to the Government. The whole originally-granted block may be kept provided the obligations arising from the permit have been appropriately met. Upon the expiration of the basic term, the holder of the exploration permit will revert the whole block, unless it exercises its right to extend the period, in which case the reversion will be limited to 50% of the remaining block. Exploitation concessions will be granted for the following terms, which will be computed as of the granting resolution’s date: i. Conventional exploitation concession: 25 years; 73 Table of Contents ii. Unconventional exploitation concession: 35 years; and iii. Continental shelf and off-shore exploitation concession: 30 years. Exploitation concessions granted prior to the entry into force of the Bases Law will continue to be governed, until their expiration, by the conditions established by the existing legal framework. At the end of the term of the exploitation concessions, they may not be awarded without a new bidding procedure. For new concessions, the granting authority will be able to set different terms, up to a maximum of 10 years, on the basis of well-founded and motivated reasons justifying the deviation from the terms laid down. The possibility of requesting an extension of the 10-year period is removed. Awarding of Areas Law No. 17,319 (amended by Law No. 27,007 and the Bases Law) proposes drafting of a standard bid form that will be jointly prepared by the SE and the provincial authorities. The model bidding documents will include the conditions and warranties to be met by the bid, as well as the minimum necessary investments to be made by the successful bidder. Likewise, the model bidding documents will establish mechanisms for adjusting the royalties deemed appropriate, which may take into account, among other variables, the total investments made, the revenues generated and the operating costs incurred. The evaluation of bids will take into account the total value of the project, including the royalties offered, the investments committed and the associated production, as specified in the respective bid documents. Bidders will compete on the royalty value based on a fifteen percent (15%) base value that will apply to the Project in each of its phases. The royalty to be offered will be identified as fifteen percent (15%) + “X”. The term “X” is defined as a percentage (%) at the sole discretion of the Bidder, which may be negative. · Levies and Royalties - Levy Law No. 17,319 (amended by laws No 27,007 and the Bases Law) set the levy values per km2 or fraction to be paid annually and in advance by the permit holder, based on the average price of a barrel of oil, adjusted annually to the Brent price: a) Basic Term: 1st period: the equivalent in Argentine Pesos of zero point fifty (0.50) barrels of oil per square kilometer. 2nd Period: the equivalent in Argentine Pesos of two (2) barrels of oil per square kilometer. b) Extension: the equivalent in Argentine Pesos of fifteen (15) barrels of oil per square kilometer. Royalties Royalties are defined as the only revenue the jurisdictions holding title to the hydrocarbons will collect, in their capacity as grantors, and are set at a percentage determined in the bidding process. For contracts in force at the time of enactment of the Bases Law, the royalty will continue to be the one agreed with the PEN or the Provincial Executive Branch, as the case may be, which were established between 12% and 15%. The PEN or the Provincial Executive Branch, may reduce royalties by up to 5%, taking into account the productivity, conditions and location of the wells. 74 Table of Contents - Transportation Authorization The Bases Law substitutes transport concessions set forth in Law No. 17,319 by transport authorizations granted and extended for the same term granted for the originating exploitation concession. After these terms expire, the facilities will be transferred back to the Federal or Provincial Government, as applicable, by law and without any charges or encumbrances. Transport concessions granted prior to the entry into force of the Bases Law shall be subject to the terms and conditions given at the time they were granted. - Processing permits The Bases Law includes hydrocarbon processing activities within the framework of Law No. 17,319. This allows the PEN or the Provincial Executive Branch to grant permits for the processing of hydrocarbons and their derivatives, the construction and operation of conditioning plants, hydrocarbon separation plants, natural gas liquefaction plants and other necessary facilities and ancillary equipment, without these necessarily being linked to an exploitation concession. Operators of hydrocarbon processing projects and/or facilities may request an authorization from the authority to transport hydrocarbons and/or their derivatives to their industrialization facilities and from such facilities to the centers and/or facilities for further industrialization or commercialization processes. Such authorizations shall not be subject to any time limit. Pursuant to Decree No. 1,057/24, published on November 29, 2024, it will not be mandatory for operators of hydrocarbon processing projects and/or facilities authorized prior to the Bases Law to apply for the conversion of the authorizations and/or permits granted under the new scheme of such law. - Authorizations for underground storage of natural gas The Bases Law incorporates into Law No. 17,319 the possibility for the PEN to grant authorizations for the underground storage of natural gas in natural reservoirs of depleted hydrocarbons to any party that: (i) meets the requirements of technical experience and financial capacity; (ii) has the consent of the holder of the exploration permit and/or the exploitation concession in whose area the natural reservoir to be used for storage is located; and (iii) undertakes to build, at its own cost and risk, the necessary facilities to carry out the storage activity. Such authorizations shall not be limited in time. Likewise, the holder of an underground gas storage authorization may apply for an authorization to transport hydrocarbons to their storage facilities and from there to the transport system, which shall also not be subject to a time limit. The granting of these authorizations is not subject to the payment of operating bonuses and no similar payments may be imposed for the granting of these authorizations through provincial regulations. Furthermore, the stored natural gas will only pay royalties at the time of its first commercialization. - Export / Import of hydrocarbons The Bases Law, within the framework of Law No. 17,319, establishes that the international trade of hydrocarbons shall be free and subject to the no objection of the Secretary of Energy. Licensees, concessionaires, refiners and/or traders will be able to freely export hydrocarbons and/or their derivatives under conditions to be regulated. However, the objection by the Secretary of Energy, which can only be exercised within 30 administrative working days of the exercise of the right to export, may be based on technical or economic reasons relating to the security of supply. Decree No. 1,057/24, which regulates the Bases Law, establishes that the Secretary of Energy shall make the corresponding adjustments to all other regulations related to hydrocarbons and/or their derivatives, in particular to Resolutions of the former Secretary of Hydrocarbon Resources No. 241/17, SE No. 360/21, SE No. 175/23 and all other regulations related to the export of hydrocarbons and/or their derivatives. Regarding the export of liquid hydrocarbons, producers have been informed by the Note of the Subsecretary of Liquid Fuels NO-2024.135497092-APN-SSCL#MEC of December 10, 2024, that until the regulations on hydrocarbon exports are adapted, the authorization procedure provided for before the entry into force of the Bases Law will continue to apply. 75 Table of Contents - Uniform Legislation Law No. 27,007 provides for two types of non-binding commitments between the Federal Government and the provinces regarding tax and environmental issues: i. Environmental Legislation: Provides that the Federal Government and the provinces will seek to establish a uniform environmental legislation primarily aiming to apply the best environmental management practices to hydrocarbon exploration, exploitation and/or transportation with the purpose of furthering the development of the activity while properly protecting the environment. ii. Tax System: Provides that the Federal Government and the provinces will seek to adopt a uniform fiscal treatment encouraging the development of hydrocarbon activities in their corresponding territories in adherence with the following guidelines: · The gross receipts tax rate applicable to the extraction of hydrocarbons will not exceed 3%; · The freezing of the current stamp tax rate and the commitment not to charge with it any financial contracts executed in order to structure investment projects, guarantee and/or warrant investments; · The commitment by the provinces and its municipalities not to impose new taxes —or increase the existing ones— on permit and concession holders, except for service compensation rates, improvement contributions and general tax increases; and · The Bases Law empowers the PEN to elaborate, with the agreement of the provinces, a harmonized environmental legislation in order to comply with Law No. 27,007. Restrictions on the Reservation of Blocks to National or Provincial Government-Controlled Companies The amendment to the Hydrocarbons Law restricts the Federal Government and the provinces from reserving new blocks in the future in favor of public or mixed-capital companies or entities, irrespective of their legal form. However, contracts entered by local companies for the exploration and development of reserved blocks before this amendment are safeguarded. Regarding blocks that have already been reserved in favor of public companies and that have not yet been awarded under joint venture agreements with third parties, associative schemes may be used, in which case the participation of such companies during the development stage will be proportional to their investments. Thus, the “carry” system during the blocks’ development or exploitation stage has been eliminated. Such system has not been prohibited for the exploration stage. Conventional and Unconventional Hydrocarbon Investment Promotion Regime On July 11, 2013, the PEN issued Decree No. 929/13, which created the Investment Promotion Regime for the Exploitation of Hydrocarbons —both conventional and unconventional— to encourage investments and the concept of unconventional exploitation concession. Law No. 27,007 extended the benefits of the Promotion Regime to hydrocarbon projects involving a minimum U.S.$250 million foreign currency direct investment, assessed at the time the hydrocarbon exploitation investment project is presented, to be invested during its first three years. Before the amendment, the Promotion Regime benefits reached investment projects denominated in foreign currency for a minimum of U.S.$1,000 million amount during a term of five years. Holders of exploration permits and/or hydrocarbon exploitation concessions, and/or third parties associated and registered with the National Registry of Hydrocarbon Investments submitting this kind of project will enjoy, beginning in the third year of execution, the right to freely sell abroad 20% and 60% of the liquid and gaseous hydrocarbon production in the case of conventional and unconventional exploitation projects and offshore projects, respectively, with a 0% export duty, if applicable. Moreover, they will have free availability of 100% of the foreign currency derived from the exportation of these hydrocarbons, provided the applicable projects have involved a minimum of U.S.$250 million of foreign currency entering into the Argentine financial market. 76 Table of Contents During periods in which the national production of hydrocarbons is insufficient to meet domestic needs pursuant to Section 6 of the Hydrocarbons Law, those covered by the Promotion Regime will have, beginning in the third year following the execution of their respective investment projects, the right to obtain a price which shall not be lower than the reference export price (without computing the incidence of any applicable withholdings) from the exportable liquid and gaseous hydrocarbon percentage produced under such projects. According to these investment projects, Law No. 27,007 provides for two contributions payable to the producing provinces, where the investment project is developed: (i) 2.5% of the investment amount paid by the project holder, destined to corporate social responsibility projects; and (ii) an amount determined by the Hydrocarbon Investments Committee paid by the Federal Government, based on the size and scope of the investment project, destined to infrastructure projects. Regime for access to foreign currency for hydrocarbon exports By means of SE Resolution No. 808/23 (as amended by Resolution No. 827/23) issued on October 3, 2023, hydrocarbon exporters became eligible to settle 25% of their sales to the foreign market at the CCL exchange rate, while the remaining 75% continued to be settled in the MULC, at the official exchange rate. The objective of this scheme was to incentivize oil and gas exports and bolster the reserves of the BCRA. Furthermore, through the mentioned resolution, different tariff positions such as crude oil, petroleum oils, and gas were incorporated, in an extraordinary and transitory manner, into the Export Increase Program (PIE) established by Decree No. 576/22, reinstated by Decree No. 443/23, and extended by Decree No. 492/23. The settlements of export operations of goods, with export settlements dates between October 2, 2023 and October 20, 2023, inclusive, are covered by the referred program, provided that the effective export date of such goods is no later than November 30, 2023. Subsequently, on October 23, 2023, Decree No. 549/23 came into effect, allowing hydrocarbon exporters to settle 30% of their sales to the foreign market at the CCL exchange rate, while the remaining 70% continued to be settled at the official exchange rate. To qualify for the scheme, exports must be settled by November 17, 2023. Regulations Specifically Applicable to the Gas Market Plan Gas.Ar According to Decree No. 892/20, on November 16, 2020, the Plan Gas.Ar program was created to promote Argentine natural gas production, reduce and replace LNG and liquid fuels imports, provide supply chain predictability, and manage the impact of the cost of gas on the tariff of the priority demand. The on-shore production term is four years, with an additional four years for offshore production, beginning in January 2021. Beneficiaries of the Unconventional Plan Gas.Ar opting to participate in this program should first file their waiver. Tender methodology and purchasing conditions The SE instrumented a tender between producers as sellers, and CAMMESA, gas distributors and ENARSA (in the case of Patagonia, Malargüe and the Puna), as purchasers, for a total base volume of 70 million m3/day (67% for the Neuquina Basin), extendable for the winter period (May – September), with 100% daily DoP and 75% monthly ToP condition for CAMMESA and quarterly for gas distributors and ENARSA. The maximum base price for the Neuquina Basin to tender was U.S.$3.7/MBTU. Moreover, the awarded price will be adjusted by a 0.82 factor for the non-winter period, 1.25 for the winter period, and 1.30 for the additional volume during winter. The producer commits a minimum production per basin and per month beginning in January 2021 equivalent to the base injection (average between May and July 2020), and a maximum production lower than or equal to 70% of the production committed for the May – July 2021 period in the case of onshore production, and May - July 2020 for offshore production. Additionally, producers must submit an investment plan to maintain the committed production and a national added-value commitment providing the development of direct local, regional and national suppliers. 77 Table of Contents If the injection in the months of June, July and/or August is lower than that committed, the producer may offset the shortfall with: (i) own production from another basin or acquired from another signatory producer, as long as there is available transportation capacity; (ii) imports on its own account; (iii) a payment equivalent to 2 times the shortfall volume at the tendered price with a 1.25 adjustment factor. Moreover, participating producers may export on a firm basis, with a preferential order for those tendering lower prices, up to the aggregate volume of 11 million m3/day (64% Neuquina Basin) during the non-winter period, extendable to the winter period, provided there is an oversupply in a specific basin. Regarding the price payable, purchasers CAMMESA and ENARSA will make the payment at the price awarded under the Plan Gas.Ar call for tenders, whereas gas producers will be paid the amount established in the tariff scheme in force, and the difference in the awarded price will be compensated by the Argentine Government. According to the concession, this compensation will be subject to withholding according to the province and/or the Argentine Government’s royalties rate. As long as the producer submits the production’s affidavit within 30 days after the closing of the injection month, they will receive a provisional payment of 85% of the compensation net of royalties within the following 30 days, and the adjusted payment for the balance within 60 days as of the presentation of the affidavit certified by independent auditors, considering Banco Nación’s selling exchange rate on the last business day of the injection month. Upon adherence to the agreement assignments as provided in SE Resolution No. 606/25, the provisional monthly compensation percentage increases from 85% to 90%. Additionally, according to the Plan Gas.Ar framework, the Argentine Government created a guarantee system to secure compensation, notwithstanding other mechanisms, based on the recognition of fiscal credits, in accordance with the applicable legislation and as regulated by the enforcement authority and/or ARCA. Such mechanism was regulated by SE Resolution No. 125/21, which instrumented electronic certifications in foreign currency that producers may directly apply to fulfill fiscal liabilities in the Plan Gas.Ar default by the Argentine Government. Moreover, the SE will be empowered to make the awardees’ guarantee enforceable before the ARCA. The ARCA instruments said system on March 4, 2021. Finally, the BCRA should establish appropriate mechanisms to facilitate access to the MLC, as long as the funds have been admitted by the MLC and subsequently to the coming into effect of the DNU, and destined to the financing of projects under the Plan Gas.Ar. Tender award On December 15 and 29, 2020, the SE awarded 67.4 million m3/day of natural gas (55% of which was destined to power plants) at an average annual base price of U.S.$3.5/MBTU, as well as an additional volume of 3.6 million m3/day during the winter period at a price of U.S.$4.7/MBTU. Pampa was awarded a base volume of 4.9 million m3/day at U.S.$3.6/MBTU and an additional volume of 1.0 million m3/day during the winter period at a price of U.S.$4.7/MBTU. Moreover, Pampa was one of the three producers tendering additional volume during the winter period, being awarded 1 million m3/day for U.S.$4.68/MBTU. Out of the 4.9 million m3/day of the base tender, 56% will be destined to power plants and the balance to gas distributors or ENARSA. In contrast, the additional winter volume will be destined to gas distributors or ENARSA. Hence, Pampa achieved the highest growth in tendered production, with the winter peak injection 20% higher than average output between May and July 2020, with an approximate investment of U.S.$250 million during the four years of the Plan Gas.Ar. This winter volume is critical to support the highly seasonal gas demand, reduce gas imports and alternative fuels consumption, and moderate foreign currency reserves. On February 22, 2021, pursuant to SE Resolution No. 129/21, a second round to award additional winter gas volumes at Neuquina and Austral Basins was called, with a daily DoP between 75% and 100% for 2021 and 100% for 2022-2024, and 75% monthly ToP. The maximum bidding price was equivalent to the awarded price on the first round. Through SE Resolution No. 169/21, a total average volume of 3.3 million m3/day at U.S.$4.7/MBTU, is to be delivered as of June 2021. Pampa participated in said round, being awarded 0.8 million m3/day at U.S.$4.7/MBTU. Additionally, the awarded companies will have to enter into a contract with ENARSA. 78 Table of Contents On October 19, 2021, through SE Resolution No. 984/21, the third round to award a total amount of 6 million m3/day of natural gas corresponding was launched, 3 million m3/day at maximum price of U.S.$3.66/MBTU for the Neuquina Basin, 2 million m3/day at maximum price of U.S.$3.52/MBTU for the Austral Basin and 1 million m3/day at maximum price of U.S.$3.577/MBTU for the Northwest Basin. This round was valid from May 1, 2022, to December 31, 2024. On November 12, 2021, the SE awarded a total of 3 million m3/day, corresponding to the Neuquén Basin at U.S.$3.43/MBTU and the volumes of the Northwest and Austral Basins were declared void. Pampa was awarded a volume of 2 million m3/day at U.S.$3.347/MBTU. Additionally, the awarded companies are required to execute the contracts with ENARSA for the period of May to September and with CAMMESA for the period of October to April. Assurance Plan On November 3, 2022, Decree No. 730/22 (hereinafter, “Decree 730”) was published. Pursuant to such decree, the Plan Gas.Ar was modified and replaced by the “Plan to Assure and Reinforce the Federal Production of Hydrocarbons, Domestic Supply, Exports, Import Substitution and Transportation System Expansion for all Argentine Hydrocarbon Basins 2023-2028” (hereinafter, “Assurance Plan”). The main goals of the Assurance Plan are (i) to strengthen a flat basis of 70 MM m3/d corresponding to the volumes awarded in the Plan Gas.Ar rounds 1 and 3, excluding winter peaks and (ii) to make up a demand for incremental volumes that can be evacuated by using the new transportation capacity to be available upon the construction of GPM (Transport.Ar Program, Resolution No. 67/22). Decree 730 establishes a new effective period up to December 31, 2028. Methodology and Conditions The National Executive Power established that contracts are to be awarded by means of a bidding process to be invited by the SE. On November 14, 2022, SE Resolution No. 770/22 was published, launching, within the framework of the Assurance Plan, bidding rounds No. 4 (for Neuquen basin) and No. 5 (for Golfo San Jorge and Austral basins). As regards Neuquen basin, Round No. 4 had the following goals: (i) Round 4.1: extension of the commitments assumed within the framework of Rounds 1 and 3 of the Plan Gas.Ar for another 4 years, from January 1, 2025, to December 31, 2028, with the same volumes and prices equal to or lower than the ones awarded in due course. In the event that an awarded producer did not exercise the option to extend, the Energy Secretariat offered the bidders requesting the extension the option to complete the volume; and (ii) Round 4.2: award of incremental volumes: a. July Flat Gas: 11 MM m3/d from 7/1/23 to 12/31/28, b. January Flat Gas: 3 MM m3/d from 1/1/24 to 12/31/28, c. Peak Gas 2024: 7MM m3/d from 5/1 to 9/30, from 2024 to 2028, and d. Peak Gas 2025: 7MM m3/d from 5/1 to 9/30, from 2025 to 2028. As regards the price, bidders had to offer a price lower than or equal to the following: Flat Gas: U$S 4/MMBTU and for Peak Gas: U$S 6,9/MMBTU, to which an adjustment factor of 1.3 had to be applied. Bidding Rounds On December 22, 2022, a total volume of 66.4 million m3/day at U.S.$3.6/MBTU was awarded for Round 4.1 pursuant to SE Resolution No. 860 and, for Round 4.2, a total volume of 14 million m3/day at U.S.$3.3/MBTU was awarded for July and January Peak Gas and a total volume of 14 million m3/day at U.S.$3.9/MBTU in wintertime was awarded for Peak Gas 2024 and Peak Gas 2025. Pampa was awarded the extension of volume and price of previous rounds with 4.8 million m3/day corresponding to July Flat Gas at a price of U.S.$3.485/MBTU. On September 27, 2023, under round 5, Pampa was awarded with respect to the Northwest basin, volumes from 13.5 million to 70.5 million m3/day at prices that decrease from U.S.$9.8/MBTU to U.S.$6.0/MBTU. 79 Table of Contents Natural Gas for the Residential and CNG Segment - Natural Gas Price within the PIST In December 2017, the extension period set forth by Law No. 27,200 to the public emergency declared in 2002 terminated. Therefore, Law No. 24,076 was reinstated, which provides that the price of natural gas supply should be determined by the free interaction of supply and demand. In mid-February 2019, a call for tenders was launched for the supply of natural gas to distribution companies on a firm basis to ToP and DoP up to 70% of the maximum daily volume and for a term of 12 months starting April 2019. For the Noroeste Basin, 9.4 and 3.8 million m3 per day were assigned for the winter (April- September 2019) and summer (October 2019-April 2020), respectively, at an average tender price of U.S.$4.35/MBTU. For the rest of basins, 36.1 and 14.4 million m3 per day were assigned for the winter and the summer, respectively, at an average tender price of U.S.$4.62/MBTU. Pampa participated and was awarded in this tender. Producers billed to distribution companies in Pesos considering Banco Nación’s average exchange rate for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the exchange rate stipulated in the agreements (ENARGAS Resolution No. 72/19). However, the exchange rate update which should have been implemented on October 1, 2019, applicable to the October 2019 - April 2020 summer seasonal period, was deferred on several occasions. These agreements expired on March 31, 2020. Given the devaluation of the Ps. and the tariff freeze (Social Solidarity and Productive Reactivation Law), beginning in April 2020 pricing agreements started to be based on the range recognized by ENARGAS in the tariff schemes. In December 2020 the tender under the Plan Gas.Ar was conducted, agreeing on the supply to gas distributors and power plants for the 2021-2024 period for a total of 67.4 million m3/day, 35% of which will be destined to distributors. The average tendered annual base price was U.S.$3.5/MBTU, and an additional winter volume of 3.6 million m3/day was awarded at an average annual base price of U.S.$4.7/MBTU to be exclusively destined to the Priority Demand. Pampa participated and was awarded in this tender. Further, Decree No. 1053/18 provided that the Federal Government would bear the difference between the price of gas purchased by distributors and that recognized in final tariffs between April 2018 and March 2019. As of the date of this annual report, Pampa has collected the first installment of Ps. 41 million. However, on December 14, 2020 Law No. 27,591 was published, which abrogated this Decree. Pampa is evaluating the courses of action to take. It is worth highlighting that beginning in 2021 and pursuant to SE Resolution No. 354/20, the reference price at the PIST was set for natural gas production out of the Plan Gas.Ar, at U.S.$2.30/MBTU in the summer (October – April) and U.S.$3.50/MBTU in the winter (May – September) for the Neuquina Basin. On August 2, 2022, SE issued Resolution No. 610/22 by means of which the new reference price at PIST was set for natural gas to be applied to natural gas public service users in accordance with the provisions of Decree No. 332/22. In the case of ENARSA, it has to pay 100% of the price awarded in the Plan Gas.Ar. In February, June and August 2022 public hearings were held to consider the portion of natural gas PIST price that the National State assumes at its own expense within the framework of the Plan Gas.Ar. It is worth mentioning that, through SE Resolution No. 610/22, a gradual increase of the PIST price at which distributors are to pay non-subsidized residential consumptions was established, while distributors are to pay the subsidized price for the remaining subsidized consumers. On January 10, 2023, SE Resolution No. 6/23 was published. Pursuant to such resolution, natural gas PIST prices for contracts executed within the framework of Plan Gas.Ar and the Assurance Plan were adapted to the different types of users. On April 27, 2023, ENARGAS Resolution No. 186/23 to 196/23 were published. Pursuant to these resolutions, natural gas PIST prices for contracts executed within the framework of the Plan Gas.Ar and the Assurance Plan were adapted to the different types of users. 80 Table of Contents On March 27, 2024, SE Resolution No. 41/24 was published, establishing the prices in the PIST to be transferred to end users in relation to the agreements concluded within the framework of the Plan Gas.Ar (Decree No. 892/20 and amendments). These are defined for the following periods: (i) between April 1, 2024 and April 30, 2024; (ii) from May 1, 2024 to September 30, 2024; and (iii) from October 1, 2024 to December 31, 2024. Likewise, it established the obligation by ENARSA, the producing and distributing companies, and/or sub-distributors of natural gas with agreements from the Plan Gas.Ar to, within 5 consecutive days from the publication of this resolution (i.e., until April 1, 2024) or the next business day (i.e., until April 3, 2024), adjust said instruments and submit them to the Secretary of Energy and the ENARGAS. Finally, it instructs ENARGAS to: (i) issue tariff tables reflecting monthly variations in the exchange rate of prices to be transferred to tariffs; and (ii) take the necessary measures to ensure that invoices issued by public service providers for the distribution and sub-distribution of gas through networks nationwide reflect PIST gas prices. By Resolutions No. 93/24, No. 191/24, No. 232/24, No. 284/24, No. 602/24 and Resolution SCEyM No. 18/24, as well as Resolutions SE No. 25/25 and No. 139/25, the SE established the PIST price to be transferred to end users, in relation to the agreements concluded within the framework of the Plan Gas.Ar, for gas consumption from June, September, October and November 2024 and from January and April 2025 respectively and on the effective date of the tariff charts published by ENARGAS. Throughout 2025, the SE issued monthly resolutions setting out the PIST price updates to be transferred to end users in relation to the agreements concluded within the framework of the Plan Gas.Ar for gas consumption from January to December 2025, as well as the effective date of the tariff charts published by ENARGAS. It should be noted that the update in the PIST values increases the amount to be charged by us directly to the distributors, reducing the price compensation payable by the National State under the Plan Gas.Ar. - Gas subsidy compensation On March 6, 2025, ENARGAS Resolution No. 125/25 was published in the Official Gazette, repealing ENARGAS Resolutions No. 273/18 and N°399/24 and restructuring the subsidy’s compensation system for natural gas distribution companies, effective as of February 1, 2025. By this new system, compensations will be received directly by the producers and must be deducted from the invoices issued by them to the distribution companies. · Natural Gas for Power Generation From December 30, 2019, the fuel supply for power plants was again centralized in CAMMESA (except for generators under Energía Plus and SEE Resolution No. 287/17 contracts). Since then, CAMMESA has launched successive calls for tenders to cover its monthly consumption. Moreover, from 2021, most gas supplies to CAMMESA are channeled through the Plan Gas. Plan for the volumes committed under this program over a term of 4 years. Generators covered by Energía Plus and SEE Resolution No. 287/17 contracts have the option to assign the natural gas operation and transportation to CAMMESA. Pampa acceded to this scheme. It is worth mentioning that from mid-July 2021, CAMMESA launched, on average, fortnightly calls for the Plan Gas.Ar awardees to offer surplus volumes on an interruptible basis, with a maximum price equivalent to that awarded in the first round. In 2021, an average of 25.2 million m3/day were awarded at U.S.$3.4/MBTU (U.S.$4.4/MBTU until September and U.S.$2.9/MBTU onwards). After the closing of 2021, an average of 22.1 million m3/day was awarded at U.S.$2.9/MBTU. · Withdrawal of volumes from the Plan Gas.Ar SE Resolution No. 501/25 established additional guidelines for the withdrawal of volumes committed under the Plan Gas.Ar contracts between producers and CAMMESA and/or ENARSA, within the framework of SE Resolution No. 400/25. 81 Table of Contents In accordance with the regulations, on December 12, 2025, we requested CAMMESA to transfer up to 4,900,000 m³/day to it under the Plan Gas.Ar agreements. On December 30, 2025, CAMMESA approved the transfer of the contractual position requested by us in our capacity as owners of thermal generation units in the WEM, within the framework of the provisions of Article 2 of SE Resolution No. 501/25. · Assignment of contracts with ENARSA At the end of December 2025, SE Resolution No. 606/25 was issued, establishing adjustments to the Plan Gas.Ar for producers who adhere to it. Such producers must accept the assignment of their contracts to distributors and CAMMESA. The adhesion procedure will be carried out by submitting a note, within 30 business days of notification of the Resolution. Partial and/or conditional adhesion will not be accepted. Distributors will have to adhere within the same period. The terms and procedures for these assignments must be determined by ENARSA within 30 business days of the publication of the above-mentioned Resolution. Such period was extended to 45 days by SE Resolution No. 36/26 and for additional 180 days by SE Resolution 54/26. As of the date of this report, such determination is still pending. In addition, the following benefits are provided for adherents: (i) an increase in the provisional payment to 90% (Plan Gas.Ar compensation paid by the state), which will be based on the affidavit submitted by each producer (rather than on 85%); (ii) a reduction in the injection commitment, as the division by 0.7 of the production curve will no longer apply; and (iii) the elimination of the quarterly reporting regime on the progress of the investment plan. ENARGAS will supervise the process of assignment and allocation of volumes. · Natural Gas Export On April 27, 2021, a new procedure to authorize natural gas exports was implemented (SE Resolution No. 360/21). New permissions contemplate exports on a firm and preferential basis for Plan Gas.Ar’s awardees and set a minimum sales price equivalent to the off-peak price awarded in round 1. The Company, as an awardee under Plan Gas.Ar, may make firm exports during the summer period, extendable to the winter period when there is an oversupply in a specific basin and with the prior approval of the applicable authority. In February 2023, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 2.2 million m3/day for the May 2023 – June 2023 period. Subsequently, in June 2023, permits were granted to export gas to Chile on a firm basis for a maximum volume of 0.86 million m3/day from July to September 2023. In August 2023, additional permits were granted on a firm basis for 1.452 million m3/day for the October 2023 - April 2024 period. In December 2023, permits were granted to export gas to Chile on a firm basis for 0.6 million m3/day for the period from May 2024 to September 2024. It is worth highlighting that a natural gas export duty has been in effect since May 2020. PEN Executive Order No. 488/20, issued on May 19, 2020, established an export duty exemption if the international Brent price was equal to or below U.S.$ 45/bbl. The rate would rise gradually in line with the international reference price until reaching 8%, the cap to be recognized when Brent equals or exceeds U.S.$ 60/bbl. In 2021, the rate remained at 8%, except for January (3.1%) and February (5.7%). On November 17, 2022, SR Resolution No. 774 (SE Resolution No. 774/22) was published in lieu of SE Resolution No. 360/21. The new procedure defines three exportation areas with different summer limits: Neuquén basin 9 MM m3/day (Oct/23 – Apr/24), Austral basin 2 MM m3/day (Oct/23 – Apr/24) and Noroeste and other basins, not subject to volume limits. Volume limits will be allocated as follows: (i) 45% as a function of the awarded producer’s share in the total volume of the basin; and (ii) 55% among those generating the largest weighted price reduction per volume within the basin incremental volume. 82 Table of Contents A minimum price reference is established, which must be higher than or equal to the maximum between the Brent price percentage to be determined by the SE and the average awarded price adjusted by seasonal index. For the period May-June 2023, the minimum price is equivalent to U.S.$7.73/MBTU. Additionally, a firm volume of 3MM m3/day of exports will be authorized for Neuquén basin for the period May-June 2023 to be distributed among producers awarded in Round 4.2 “July Flat Gas” bid. Discounting volumes from Plan Gas.Ar and/or Assurance Plan contracts with CAMMESA and/or ENARSA is also allowed. With the enactment of the Bases Law, the free commercialization of hydrocarbons is established and the procedure of non-objection by the Secretary of Energy is introduced. Meanwhile, Decree No. 1,057/24 establishes that the SE shall adapt, among other regulations related to the export of hydrocarbons, SE Resolution No. 360/21. This regulation has not yet been issued. - Export of LNG Through the Bases Law (amending Law No. 24,076), a special export regime for liquefied natural gas (LNG) was established for those who produce, process, refine, trade, store and/or fraction hydrocarbons and/or their derivatives, subject non-objection of the SE. Moreover, on April 4, 2025, the SE approved the procedure for the export of LNG by means of its Resolution No. 145/25. The SE may raise objections within 120 administrative working days from the submission of the export notification by the interested party. If the Secretary of Energy does not raise any objection within the aforementioned period, a free export of LNG license is granted. The LNG export authorizations granted will be final with respect to the LNG volumes authorized for a period of up to 30 years, from the start-up of the liquefaction plant (on land or floating) or its extensions. In addition, the law provides that within six months of its entry into force, the Secretary of Energy shall carry out a study with a view to issuing a “Declaration of Gas Resource Availability” in the long term. Such declaration shall take into account the sufficiency of the country’s gas resources, projected over time, and the supply of natural gas from other sources to regularly satisfy domestic demand and, at the same time, supply on a firm and uninterrupted basis the LNG export projects that are expected to be developed and implemented during the same period of analysis. Decree No. 1057/24 defines the aspects to be included in this declaration. The ES must update this study at least every five years, or whenever a new LNG export application justifies it due to its size, longer duration and higher investment amounts. Among the grounds for objection, the ES may object to the export, in whole or in part, on the basis of the lack of availability of natural gas in Argentina, according to the Declaration of Availability of Gas Resources. Program for Access to Foreign Currency for Oil and Gas Incremental Production On May 28, 2022, Decree No. 277/22 was published in the Official Gazette, which provided that the SE will be able to enter into pluriannual contracts to cover natural gas demand (for a minimum of three years) by means of future auctions within the framework of the Plan Gas.Ar. Furthermore, Programs for Access to Foreign Currency for Oil Incremental Production (“RADPIP”) and Gas Incremental Production (“RADPIGN”), as well as the Program for Promotion of Employment, Work and Development of Regional and National Suppliers (“RPEPNIH”), were created. The beneficiaries of these programs will have access to the MLC to pay the principal and interest of trade or financial liabilities abroad, including liabilities to non-resident related companies and distribution of earnings and dividend corresponding to financial statements closed and audited and/or repatriation of investments of nonresidents. This benefit can be transferred to direct suppliers. Both for RADPIP and RADPIGN, access to MLC up to the mentioned amounts will not be subject to the Central Bank prior agreement, should the exchange regulations require so. In the case of natural gas, the benefit will be measured according to the Benefited Incremental Injection Volume (“VIIB”) valued at the weighted average export price over the last 12 months, net of export duties. This price cannot be lower than the weighted average price of base gas volumes awarded throughout the year, nor higher than twice the same value. VIIB will be equivalent to 30% of the incremental gas injection of the beneficiary with respect to their baseline. 83 Table of Contents In the case of oil, the benefit will be measured according to the Benefited Incremental Production Volume (“VPIB”) valued at the average Brent price over the last 12 months, net of export duties and subject to oil quality reductions. VPIB will be equivalent to 20% of the quarterly incremental oil production of the beneficiary with respect to their baseline. In both cases, the baseline will be the total production/injection of 2021 and the benefit percentage can be increased according to the assumptions set forth in the Decree. As regards RPEPNIH, supplier development plans will be controlled to ensure regional and national integration. A contracting scheme granting a preferential status to suppliers of goods and/or services of regional and national origin is also considered. On August 12, 2022, Decree No. 484/22 regulating DNU No. 277 was published. Furthermore, on January 16, 2023, SE Resolution 13/23 was published in the Official Gazette to regulate the steps to enroll in and obtain the benefit of access to foreign currency created by DNU No. 277. To date, Pampa has been granted certificates of access to the RADPIGN and RPEPNIH benefits corresponding to the third and fourth quarters of 2022 and the first quarter of 2023. The certificates requested for the second, third, and fourth quarters of 2023 and all four quarters of 2024 are still pending to be granted. Regulations Specifically Applicable to the Crude Oil Market · Crude Oil Commercialization in the Domestic Market As of the date of this annual report, there is no reference price for trading crude oil in the domestic market. However, considering the fuel price netback at the pump, local refiners are accepting prices below export parity. Since December 2023, the new management of YPF is trying to normalize gasoline and diesel prices in their pumps, leading to convergence of local oil price to export parity. · Liquid Hydrocarbons Export Duty Decree No. 488/20, issued on May 19, 2020, provided for an export duty exemption as long as the international Brent price was equal to or below U.S.$45/bbl, rising gradually as the international reference price increased until reaching 8%, the cap to be recognized when the reference price equals or exceeds U.S.$ 60/bbl. As of the date of this annual report, the rate amounts to 8%. On January 29, 2026, Decree No. 59/26 was published, establishing new export duties for conventional crude oil ranging from 0% (when the Brent crude oil price is equal to or below U.S.$ 65/bbl) to 8% (when the Brent crude oil price is equal to or above U.S.$ 80/bbl) and repealing the rate established in Decree No. 488/20 for this type of crude oil. The regulation came into effect on February 20, 2026, through SE Resolution No. 42/2026. Through the Bases Law, it was stipulated that the PEN may not interfere in or set the domestic market prices for any segment of the hydrocarbon production chain. Midstream - Transport Licenses The Bases Law amended Law No. 24,076 to provide that, at least 18 months prior to the expiry of a license, ENARGAS, at the request of the respective supplier, shall carry out an evaluation of the service provided by the supplier with a view to proposing to the National Executive Power the renewal of the license to provide public natural gas transport and distribution services for an additional period of twenty (20) years. 84 Table of Contents · Regulations Specifically Applicable to the LPG Business - Household Gas Bottles’ Program and Propane for Grids Agreement The program for the supply of butane for gas bottles at subsidized prices, created by Decree No. 470/15 and encompassed under the Household Gas Bottles’ Program (Secretary of Hydrocarbon Resources Resolution No. 56/17, as amended), is currently in force, and provides for the supply of a defined quota of LPG to fractionation companies, under a maximum reference price, to benefit low-income residential users. The sales price for butane and propane sold under the Household Gas Bottles’ Program was determined by the SRH, which established production and trade quotas for bottled LPG for low-income users (DNU No. 470/15, as amended). On January 22, 2025, the SE ordered the elimination of subsidies and set the export parity price as the maximum sale price (Res. No. 15/25). On July 3, 2025, further progress was made toward liberalizing the producer sale price, while maintaining the obligation to supply the domestic market (DNU No. 446/25). With respect to the Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids, on September 22, 2025, TGS signed a new Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids. The agreement establishes the compensation calculated as the difference between the sale price and the export parity published monthly by the SE. The Federal Government will pay the compensation through tax credit certificates, which are only applicable to the cancellation of hydrocarbon export duties. The agreement was in force from January 1 to December 31, 2025, and experienced significant delays in collections. However, on December 26, the SE requested that producers continue supplying under the same terms until a new agreement is executed. - Natural Gas Import Financing Charges Regarding ENARGAS Resolutions I-1,982/11 and I-1,991/11, which at the time provided for an approximate 700% increase in the natural gas import financing charge (created by Decree No. 2,067/08), on March 26, 2019, TGS was served notice of the first instance ruling upholding its claim for unconstitutionality and nullity of the above-mentioned provisions. The Federal Government appealed this ruling on March 29, 2019; the appeal was granted on April 3, 2019 and has not been resolved as of the date hereof. On December 1, 2020, the Court hearing the case resolved, taking into consideration the ruling and in view of the reasons alleged by TGS, to extend the validity of the granted injunction for a term of six months in such ordinary proceeding and/or until a final and conclusive ruling is issued. - Export Duty As for hydrocarbon exports, beginning in September 2018 there was an export duty of Ps. 4 per exported U.S.$ for propane, butane and LPG, with a maximum 12% rate (Decrees No. 793/18 and 865/18). The Social Solidarity and Productive Reactivation Law provided that, effective as of December 23, 2019, this rate may not exceed 8% of the taxable value or the Free on Board (“FOB”) price. However, until its regulation, Decrees No. 793/18 and 865/18 continued to apply. Decree No. 488/20, issued on May 19, 2020, provided for an export duty exemption as long as the international Brent price was equal to or below U.S.$45/bbl, rising gradually as the reference price increased up to 8%, the cap to be recognized when the Brent equaled or exceeded U.S.$ 60/bbl. On January 29, 2026, Decree No. 59/26 was published, establishing new export duties for conventional crude oil ranging from 0% (when the Brent crude oil price is equal to or below U.S.$ 65/bbl) to 8% (when the Brent crude oil price is equal to or above U.S.$ 80/bbl) and repealing the rate established in Decree No. 488/20 for this type of crude oil. The regulation came into effect on February 20, 2026, through SE Resolution No. 42/2026. 85 Table of Contents · Regulations Specifically Applicable to Crude Oil Transportation In November 2022, the SE launched the tariff update process. In 2023 and 2024, Oldelval submitted the requested information, and in July 2024, SE conducted its audit. As a result, the new maximum tariff scheme entered into force on June 12, 2025, applicable for the 2025–2029 five-year period (SE Resolution No. 256/25). Separately, on September 14, 2022, the SE granted the concession extension and its Medanito–Puesto Hernández expansion through November 14, 2037. In 2022, Oldelval tendered firm transportation capacity on the Allen–Puerto Rosales pipeline, within the framework of the Duplicar Project, for more than 314 kbpd, through contracts effective until the end of the concession. Construction of the Duplicar Project was completed in March 2025, with Pampa being awarded 6 kbpd of transportation capacity. · Oil Storage and Evacuation Related to the tender invited by Oldelval, Oiltanking Ebytem called for bids to increase oil delivery capacity to up to 50,000 m3/day and storage capacity to up to 300,000 m3. These expansions will be solely designed for oil exportation. 86 Table of Contents ELECTRICITY REGULATORY FRAMEWORK Overview Until 1990, virtually all of the electricity supply in Argentina was controlled by the public sector. In 1991, the Argentine Government undertook the privatization of state-owned electricity generation, transmission and distribution companies. In January 1992, the Argentine Congress enacted Law No. 24,065 (the “Regulatory Framework Law”), which established guidelines for the restructuring and privatization of the electricity sector. The ultimate goals of the privatization process was to reduce electricity tariffs and improve the quality of the electricity supply service through competition. The Regulatory Framework Law, which continues to provide the framework for regulation of the electricity sector, distinguished between the generation, transmission and distribution of electricity as separate businesses and made each subject to its own regulatory framework. The Public Emergency Law combined with the devaluation of the Peso and high rates of inflation had a severe effect on public utilities in Argentina. Because public utilities were no longer able to increase tariffs, inflation led to decreases in their revenues in real terms and a deterioration of their operating performance and financial condition. Most public utilities had also incurred large amounts of foreign currency indebtedness under the Convertibility Law Nº 23,928 regime and, following the devaluation of the Peso, the debt service burden of these companies increased sharply, which led many of them to suspend payments on their foreign currency debt in 2002. This situation caused many Argentine electricity generators, transmission companies and distributors to defer making further investments in their networks. As a result, Argentine electricity market participants, particularly generators, operated at near full capacity, which led to insufficient supply to meet a growing national energy demand. To address the above-mentioned electricity crisis, the Argentine Government has repeatedly intervened in and modified the rules of the WEM, creating a huge structural deficit in the operation of the WEM. In that sense, and to increase the electric power supply, the Argentine Government established several programs (FONINVEMEM projects, Energy Plus Program, among others), which evidenced a decision by the Argentine Government to take a more active role in promoting energy investments in Argentina. The Argentine Government additionally continued to implement various measures in order to regulate the operation of the WEM and of the intervening agents. In December 2015 and 2019, the state of emergency with respect to the national electricity system was declared. The state of emergency allowed the Argentine Government to take actions designed to guarantee the supply of electricity in Argentina such as instructing the ME&M to elaborate and implement, with the cooperation of all federal public entities, a coordinated program to guarantee the quality and security of the electricity system and rationalize public entities’ consumption of energy. The Argentine Government continued its intervention in the energy sector and measures allowing its return to normal are still pending. On December 16, 2023, Decree No. 55/23 declared the emergency of the national energy sector until December 31, 2024, comprising energy generation, transmission, distribution and the transmission and distribution of natural gas. The decree instructed the SE to take the necessary measures in order to: (i) define new mechanisms to set up competitive and free prices in the energy sector; and (ii) guarantee that energy and natural gas transport and distribution utilities can have the necessary incomes to provide adequate services and investments. 87 Table of Contents The abovementioned decree ordered the intervention of ENRE and ENARGAS and the execution of new procedures for the election of the members of their boards. SE Resolution No. 1/23 and ME Resolution No. 5/23 appointed the new controllers for the ENRE and ENARGAS, respectively. Moreover, Decree No. 55/23 defined new administrative procedures for the determination of new energy and natural gas tariffs schemes. Following the decree, both ENARGAS and SE issued resolutions calling for public hearings for the analysis of the new tariffs and subsidies schemes. On December 20, 2023, the PEN issued Urgency and Necessity Decree No. 70/23, declaring once again a state of public emergency with respect to economic, financial, fiscal, administrative, pension, tariff, health and social matters until December 31, 2025. Among other measures, the Decree empowered the SE to (i) redetermine the electricity and natural gas subsidy structures on the basis of the end users’ household income, (ii) calculate the cost of basic consumption on the basis of the rates at each supply point, and (iii) define mechanisms in connection with the allocation of subsidies and their collection by users. The Decree also introduces a series of amendments to different laws, such as amendments to Law No. 19,550 and Law No. 23,696, establishing that state-owned companies shall be subject to state supervision, and providing that the national state shall not be granted any public law prerogatives or advantages with respect to companies in which the national state is a shareholder. In addition, the Decree introduces amendments and repeals a number of existing laws, such as (i) Law No. 27,545, which established certain rules for the display of products on store shelves, (ii) Law No. 20,680, which granted the Secretary of Commerce the ability to impose severe regulations and penalties relating to supply and distribution of goods, and (iii) Law No. 27,221, which set forth new rules applicable to real estate lease agreements executed for touristic purposes. Decree No. 70/23 became effective on December 29, 2023. The Decree is subject to review by the National Congress and could be left without effect in case both chambers of congress decide to reject it. As of the date of this report, Decree No. 70/23 had been rejected by the Senate, and review by the House of Representatives (Cámara de Diputados) is still pending. In addition, it is currently the subject of several challenges in Argentine courts. In this respect, it is not possible to predict whether Decree No. 70/23 will remain in force in the future, or whether the current administration will issue new decrees or regulations that could impact our business. Recently, the Government held public hearings to establish new tariffs for energy transport and distribution, natural gas price and natural gas transport and distribution. Upon its conclusion the Government issued the relevant resolutions which increased the natural gas price and the abovementioned tariffs, cutting off a significant portion of subsidies. Decree No. 1023/24 extended the emergency and its associated actions until July 9, 2025. Also, Bases Law i) provides for the unification of ENRE and ENARGAS into a single regulatory structure; and ii) authorizes the PEN, during the period of the declared emergency, to adapt the regulatory framework for electricity, according to Laws Nos 15.336 and 24.065, in order to: - promote the opening of international trade in electricity; - ensure free marketing and maximum competition in the sector, guaranteeing final consumers a free choice of supplier; - promote the economic dispatch of energy transactions based on remuneration in the hourly economic cost of the system, taking into account the hourly marginal cost of the system and the energy not supplied; - adjust energy system tariffs based on the real cost of supply in order to cover investment needs and ensure the continued provision and regulation of public services; - explicitly differentiate the funds to be paid by the end user, with the explicit obligation of the distributor to act as a collection or withholding agent for the amounts to be collected for energy, transport and taxes corresponding to the WEM and the Treasury, as appropriate; and - ensure the development of electricity transmission infrastructure through open, transparent, efficient and competitive mechanisms. On January 28, 2025, SE Resolution No. 21/25 was published, establishing several modifications to the current regulation of the dispatch and operation of the WEM Term Market, as mentioned in the previous sections. Many of the aspects introduced by the resolution require future development regulations and/or clarifications for their application. The Resolution exempts generators, self-generators and co-generators of conventional thermal, hydroelectric and nuclear sources that enters into commercial operations as of January 1, 2025 from the suspension of contracting in the MAT. 88 Table of Contents Regarding the Energy Plus market, it restricted the renewal and/or submission of new contracts until October 31, 2025. Existing Energy Plus contracts will remain in force until they are terminated. Once the contracts are terminated, the Energy Plus Market will cease to exist and the generation units authorized under this regime will be remunerated under the new market rules. In relation with the dispatch and allocation of natural gas for generation, it repealed, with effect as of February 1, 2025, the dispatch regime established by SE Resolution No. 354/20, which settled a dispatch priority to generators in order to comply with the obligations (TOP and residual) of ENARSA’s supply contract with Bolivia and CAMMESA’s and ENARSA natural gas contracts under the Plan Gas.Ar. On the other hand, as of March 1, 2025, it authorizes the recognition of fuel costs in accordance with reference prices and the values declared and accepted in the declaration of production costs, plus freight, natural gas transport and distribution costs, and taxes and duties. CAMMESA will continue to centralize the management of fuels for those units under CAMMESA’s PPAs (e.g. Resolutions No. 220/07, No. 21/17 and No.287/17). Generators remunerated under the Spot Market will be able to manage their own fuel supply, leaving CAMMESA as supplier of last resort. Finally, it establishes new values for the cost of energy not supplied, setting a maximum of U.S.$ 1,500/MWh as of February 1, 2025, with the following steps; (i) up to 5% 350 U.S.$/MWh; (ii) up to 10% U.S.$ 750/MWh; and (iii) more than 10% U.S.$ 1,500/MWh. Regarding the ability of generators to supply their own fuel, on April 4, 2025, note NO-2025-35216647-APN-SE#MEC was issued, establishing additional guidelines to note NO-2025-16900682-APN-SE#MEC for the gas dispatch priority scheme for thermal generation in the WEM. The new directives state that offers from generators opting to manage their own fuel supply will be considered firm, and in case of non-compliance, they will be penalized with a Deliver or Pay equivalent to 70% of the reference price for the unavailable volume. A new reference price applicable to different scenarios was set, equivalent to 90% of the weighted average representative price per basin for natural gas at the PIST, using the prices from Round 4.2 for the Neuquina Basin and Round 4.1 for the Austral Basin. For the Northern Basin, prices from the Neuquina Basin will be used. Additionally, the reference price for natural gas originating from neighboring countries was modified. Reference prices for liquid fuels are determined for each generator based on international indicators, including a premium to cover associated financial and logistical costs. Regarding the payment for liquid fuels and natural gas from neighboring countries, the exchange rate corresponding to the business day prior to the transaction due date will be recognized, linked to the consumption recognized in the respective economic transaction. On January 28, 2025, the SE sent to CAMMESA Note NO-2025-09628437-APN-SE#MEC, in which it made several reflections on the current state of the WEM and instructed CAMMESA to draft certain briefs proposing new regulatory measures based on the Guidelines included in such note. The Guidelines were sent to AGEERA, ADEERA, ATEERA and AGUERA for them to comment on their content. As of the date of this annual report, all the associations have sent their comments to the SE. The Guidelines set several changes in the structure of the WEM and the compensation schemes for power generation. Based on CAMMESA’s briefs, the SE issued transitional rules for the adaptation of the WEM. On October 21, 2025, the SE published Resolution No. 400/25 which approved the “Rules for Normalization of WEM” and its “Progressive Adaptation”. The Rules for the Normalization of the WEM aim to ensure operational continuity and system growth by introducing a price signaling mechanism for demand and a remuneration scheme for spot sales based on marginal costs and enabled energy and capacity contracts through the Term Market. 89 Table of Contents This framework requires thermal generators to progressively manage their own fuel procurement, recovering associated costs through the Spot Market or Term Market. Given the constraints of the Plan Gas.Ar (in force until 2028) and limitations in gas transportation, transitional rules were established for access to fuels, while CAMMESA remains as the supplier of last resort. The scheme also enables generators to declare Variable Production Costs (CVP) to foster competitive dispatch and cost recovery. Additionally, adjustments to the pricing structure seek to value installed capacity and encourage new investments. For distributor users unable to manage their own supply, costs will be stabilized via existing supply contracts and state-managed generation. These rules will be complemented by additional instruments to ensure progressive adaptation and competitive mechanisms for energy, capacity, and ancillary services within the WEM. Regarding the changes in remuneration schemes. See “Item 4. The Argentine Energy Sector - Electricity Prices”. The Seasonal Demand of WEM Distributors includes residential and non-residential users, excluding Large Users (GUDI), and will be primarily supplied through “Assigned Generation,” which comprises existing WEM supply contracts (renewable and thermal), national hydroelectric generation, nuclear generation, and opportunistic imports. Residential demand will have priority in the use of this generation, while for the coverage of non-residential demand, distributors must complement their supply through the Spot Market or Term Market contracts. Associated costs will be passed through via stabilized seasonal prices. To ensure supply, distributors must cover at least 75% of their seasonal demand through contracts, complementing Assigned Generation with agreements in the Term Market. CAMMESA will assess short- and medium-term reserve requirements to guarantee the incorporation of additional capacity in the WEM. SE Resolution No. 501/25, complemented the normalization process of the WEM by enabling producers under the Plan Gas.Ar to partially or fully transfer contracted volumes under contracts executed with CAMMESA to generators. These transferred volumes are considered self-managed gas for dispatch purposes, allowing generators to declare their Variable Production Cost (CVP) for dispatch competition. The resolution also sets limits for CVP declarations, maintains operational obligations under the Plan Gas.Ar, and confirms that remuneration for these volumes will follow the Spot Market pricing scheme. This measure reinforces the transition toward decentralized fuel management and competitive mechanisms introduced by SE Resolution No. 400/25. Regulatory Authorities As of the date of this annual report, the principal regulatory authorities responsible for the Argentine electricity market are: (1) the Ministry of Economy, which assumed responsibility over the SE; (2) the ENRE; and (3) CAMMESA. The ENRE is an autonomous agency created by the Regulatory Framework Law. The ENRE has a variety of regulatory and jurisdictional powers, including, among others: · enforcement of the Regulatory Framework Law and related regulations; · control of the delivery of electric services and enforcement of the terms of concessions; · adoption of rules applicable to generators, transmitters, distributors, electricity users and other related parties concerning safety, technical procedures, measurement and billing of electricity consumption, interruption and reconnection of supplies, third-party access to real estate used in the electricity industry and quality of services offered; · prevention of anticompetitive, monopolistic and discriminatory conduct between participants in the electricity industry; · imposition of penalties for violations of concessions or other related regulations; and · arbitration of conflicts between electricity sector participants. Until the ENRE intervention pursuant to Decree No. 277/20, the ENRE was managed by a five-member board of directors appointed by the Argentine Government. Two of these members were nominated by the Federal Council on Electricity (Consejo Federal de la Energía Eléctrica) (the “CFEE”). The CFEE is funded with a percentage of revenues collected by CAMMESA for each MWh sold in the market. Sixty percent of the funds received by the CFEE are reserved for the Fondo Subsidiario para Compensaciones Regionales de Tarifas a Usuarios Finales (regional tariff subsidy fund for end users), from which the CFEE makes distributions to provinces that have met certain specified tariff provisions. The remaining forty percent are used for investments related to the development of electrical services in the interior of Argentina. 90 Table of Contents Since March 16, 2020, the Executive Branch has successively ordered the intervention of the ENRE. As indicated on the previous chapter, Decree No. 55/23 ordered a new intervention on the ENRE and ENARGAS, cancelled the procedures for the election of the members of their boards and instructed the commencement of new procedures. The Bases Law ordered that the ENRE and the ENARGAS will merge into a single new Regulatory Authority for the energy and the natural gas industries. In that way Decree No. 452/25, published on July 4, 2025, established the National Regulatory Agency for Gas and Electricity through the unification of ENRE and ENARGAS. This new agency, which must be fully operational within 180 calendar days from the publication of the Decree, will have a Board of Directors comprising a president, a vice president, and three board members, to be appointed by a public selection process. On October 9, 2025, SE Resolution No. 388/25 started the appointment of the Agency’s board members; and SE Resolution No. 479/25 published in November 2025 established the Selection Committee for the members of the board of the Agency. As of the date of this report, the new Agency has not been effectively implemented. The creation of the WEM made it necessary to create an entity in charge of the management of the WEM and the dispatch of electricity into the National Interconnection System (the “SIN”). The duties were entrusted to CAMMESA, a private company created for this purpose. CAMMESA is in charge of: · the dispatch of electricity into the SIN, maximizing the SIN’s safety and the quality of electricity supplied and minimizing wholesale prices in the spot market; · planning energy capacity needs and optimizing energy use in accordance with the rules set forth from time to time by the SE; · monitoring the operation of the term market and administering the technical dispatch of electricity under agreements entered into in that market; · acting as agent of the various WEM agents and carrying out the duties entrusted to it in connection with the electricity industry, including billing and collecting payments for transactions between WEM agents (upon enactment of SE Resolution No. 95/13, this was limited to the contracts then in force and, thereafter, to those contracts executed under Energy Plus Program); · purchasing and/or selling power from abroad or to other countries by performing the relevant import/export transactions; · purchasing and administering of fuels for the WEM generators under certain emergency conditions; and · providing consulting and other related services. Five groups of entities each hold 20% of the capital stock of CAMMESA. The five groups are the Argentine Government, the associations that represent: (i) the generation companies (AGEERA), (ii) the transmission companies (ATEERA), (iii) the distribution companies (ADEERA) and (iv) the large users (AGUEERA). CAMMESA is managed by a board formed by representatives of its shareholders. The board of CAMMESA is composed of ten regular and ten alternate directors. Each of the associations that represent generation companies, transmission companies, distribution companies and large users are entitled to appoint two regular and two alternate directors of CAMMESA. The other directors of CAMMESA are under the SE, who is the board chairman and an independent member, who acts as vice chairman. The decisions adopted by the board of directors require the affirmative vote of the board’s chairman. CAMMESA’s operating costs are financed through mandatory contributions by the WEM agents. 91 Table of Contents Key Participants Generators Generators are companies with electricity generating plants that sell output either partially or wholly through the SIN. Generators are subjected to the scheduling and dispatch rules set out in the regulations and managed by CAMMESA. Privately owned generators may also enter into direct contracts with distributors or large users. However, this possibility was suspended by SE Resolution No. 95/13, which in this respect, remains in effect except for the Energy Plus Program, renewable energy supply contracts and, upon SE Resolution No. 21/25, for generator whose entry into commercial operations takes place as of January 1, 2025. Transmitters Transmission companies hold a concession to transmit electric energy from the bulk supply point to electricity distributors. The transmission activity in Argentina is subdivided into two systems: the High Voltage Transmission System (“STEEAT”), which operates at 500 kV and transports electricity between regions, and the regional distribution system (“STEEDT”) which operates at 132/220 kV and connects generators, distributors and large users within the same region. Transener is the only company in charge of the STEEAT, and six regional companies operate within the STEEDT (Transcomahue, EPEN, Transnoa, Transnea, Transpa, Transba and Distrocuyo). In addition to these companies, there are also independent transmission companies that operate under a technical license provided by the STEEAT or STEEDT companies. Transmission and distribution services are carried out through concessions. These concessions are re-distributed periodically based on a re-bidding process. Transmission companies are responsible for the operation and maintenance of their networks, but not for the expansion of the system. The transmission concessions operate under the technical, safety and reliability standards established by the ENRE. Penalties are applied whenever a transmission concessionaire fails to meet these criteria, particularly those regarding outages and grid downtime. Generators can only build lines to connect to the grid, or directly to customers. Users pay for new transmission capacity undertaken by them or on their behalf. A public hearing process for these projects is conducted by the ENRE, which issues a “Certificate of Public Convenience and Necessity.” Transmission or distribution networks connected to an integrated system must provide open access to third parties under a regulated toll system unless there is a capacity constraint. Distributors Distributors are companies holding a concession to distribute electricity to consumers. Distributors are required to supply any and all demand of electricity in their exclusive areas of concession, at prices (tariffs) and conditions set forth in regulations. Penalties for non-supply are included in the concession’s agreements. The three distribution companies (Edenor, Edesur and Empresa Distribuidora La Plata S.A. (“Edelap”)) divested from Servicios Eléctricos del Gran Buenos Aires (“SEGBA”), represent more than 41% of the electricity market in Argentina. Only a few distribution companies (i.e., Empresa Provincial de Energía de Córdoba, Empresa de Energía de Santa Fe and Energía de Misiones) remain in the hands of the provincial governments and cooperatives. Edelap has been transferred to the jurisdiction of the Province of Buenos Aires. Concessions were issued for distribution and retail sale, with specific terms for the concessionaire stated in the contract. The concession periods are divided into “management periods” that allow the concessionaire to give up the concession at certain intervals. Large users The WEM classifies large users of energy into three categories: (1) GUMAs, (2) GUMEs and, (3) Grandes Usuarios Particulares (Major Particular Users or “GUPAs”). 92 Table of Contents Each of these categories of users has different requirements with respect to purchases of their energy demand. For example, GUMAs are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while GUMEs and GUPAs are required to purchase all of their demand through supply contracts. Energy Traders Energy Traders act as “participants” of the WEM. They can execute contracts in the Term Market with generators, resell energy to large users and distributors or act as intermediaries between such parties. With the deregulation scheme implemented by SE Resolution No. 400/25, energy traders are expected to have a significant role in Term Market transactions. Limits and restrictions To preserve competition in the electricity market, participants in the electricity sector are subject to vertical and horizontal restrictions, depending on the market segment in which they operate. Vertical restrictions The vertical restrictions apply to companies that intend to participate simultaneously in different sub-sectors of the electricity market. These vertical restrictions were imposed by Law No. 24,065, and apply differently according to each sub-sector as follows: Generators · Under Section 31 of Law No. 24,065, neither a generation company nor any of its controlled companies or its controlling company, can be the owner or a majority shareholder of a transmitter company or the controlling entity of a transmitter company; and · Under Section 9 of Decree No. 1,398/92, since a distribution company cannot own generation units, a holder of generation units cannot own distributions concessions. However, the shareholders of the electricity generator may own an entity that holds distribution units, either by themselves or through any other entity created with the purpose of owning or controlling distribution units. Transmitters · Under Section 31 of Law No. 24,065, neither a transmission company nor any of its controlled companies or its controlling entity, can be the owner or majority shareholder or the controlling company of a generation company; · Under Section 31 of Law No. 24,065, neither a transmission company nor any of its controlled companies nor its controlling company, can be the owner or majority shareholder or the controlling company of a distribution company; and · Under Section 30 of Law No. 24,065, transmission companies cannot buy or sell electric energy. Distributors · Under Section 31 of Law No. 24,065, neither a distribution company, nor any of its controlled companies or its controlling company, can be the owner or majority shareholder or the controlling company of a transmission company; and · Under Section 9 of Decree No. 1,398/92, a distribution company cannot own generation units. However, the shareholders of the electricity distributor may own generation units, either by themselves or through any other entity created with the purpose of owning or controlling generation units. 93 Table of Contents Definition of control The term “control” referred to in Section 31 of Law No. 24,065 (which establishes the vertical restrictions), is not defined in the Regulatory Framework. Section 33 of the LGS states that “companies are considered as controlled by others when the holding company, either directly or through another company: (1) holds an interest, under any circumstance, that grants the necessary votes to control the corporate will in board meetings or ordinary shareholders’ meetings; or (2) exercises a dominant influence as a consequence of holding shares, quotas or equity interest or due to special linkage between the companies.” We cannot assure you, however, that the electricity regulators will apply this standard of control in implementing the restrictions described above. The regulatory framework outlined above prohibits the concurrent ownership or control of (1) generation and transmission companies, and (2) distribution and transmission companies. Although we are a fully integrated electricity company engaged in the generation, transmission and distribution of electricity in Argentina, we are in compliance with these legal restrictions, as we do not hold a controlling interest, either directly or indirectly, in Transener. Horizontal restrictions In addition to the vertical restrictions described above, distribution and transmission companies are subject to horizontal restrictions, as described below. Transmitters · According to Section 32 of Law No. 24,065, two or more transmission companies can merge or be part of the same economic group only if they obtain an express approval from the ENRE. Such approval is also necessary when a transmission company intends to acquire shares of another electricity transmission company; · Pursuant to the concession agreements that govern the services rendered by private companies operating transmission lines above 132Kw and below 140Kw, the service is rendered by the concessionaire on an exclusive basis over certain areas indicated in the concession agreement; and · Pursuant to the concession agreements that govern the services rendered by the private company operating the high-tension transmission services equal to or higher than 220Kw, the company must render the service on an exclusive basis and is entitled to render the service throughout the entire country, without territorial limitations. Distributors · Two or more distribution companies can merge or be part of the same economic group only if they obtain an express approval from the ENRE. Such approval is necessary when a distribution company intends to acquire shares of another electricity transmission or distribution company; and · Pursuant to the concession agreements that govern the services rendered by private companies operating distribution networks, the service is rendered by the concessionaire on an exclusive basis over certain areas indicated in the concession agreement. GENERATION Electricity Prices Spot prices The emergency regulations enacted after the Argentine crisis in 2001 had a significant impact on energy prices. Among the measures implemented pursuant to the emergency regulations were the pesification of prices in the WEM, known as the spot market, and the requirement that all spot prices be calculated based on the price of natural gas, even in circumstances where alternative fuel such as diesel is purchased to meet demand due to the lack of supply of natural gas. 94 Table of Contents Prior to the crisis, energy prices in the spot market were set by CAMMESA, which determined the price charged by generators for energy sold in the spot market of the WEM on an hourly basis. The spot price reflected supply and demand in the WEM at any given time, which CAMMESA determined using different supply and demand scenarios that dispatched the optimum amount of available supply, taking into account the restrictions of the transmission grid, in such a way as to meet demand requirements while seeking to minimize the production cost and the cost associated with reducing risk of system failure. The spot price set by CAMMESA compensated generators according to the cost of the next unit to be dispatched as measured at the Ezeiza 500 kV substation, which is the system’s load center and is in close proximity to the City of Buenos Aires. Dispatch order was determined by plant efficiency and the marginal cost of providing energy. In determining the spot price, CAMMESA also would consider the different costs incurred by generators outside the province of Buenos Aires. In addition to energy payments for actual output at the prevailing spot market prices, generators would receive compensation for capacity placed at the disposal of the spot market, including stand-by capacity, additional stand-by capacity (for system capacity shortages) and ancillary services (such as frequency regulation and voltage control). In October 2019, through SRRYM Resolution No. 38/19, the spot price at the WEM was established at 720 Ps./MWh. In May 2021, the spot price at the WEM was raised to 930 Ps./MWh (SE Resolution No. 748/21). Throughout 2025, the maximum spot price in the WEM was progressively updated as follows: SE Resolution No. 27/25 set the price at 12,469 Ps./MWh as from February; SE Resolution No. 143/25 raised it to 12,948 Ps./MWh as from April; SE Resolution No. 227/25 increased it to 13,300 Ps./MWh as from June; SE Resolution No. 280/25 updated it to 13,433 Ps./MWh as from July; SE Resolution No. 331/25 raised it to 13,487 Ps./MWh as from August; SE Resolution No. 356/25 adjusted it to 13,554 Ps./MWh as from September; SE Resolution No. 381/25 increased 13.622 Ps./MWh as from October; SE Resolution No. 483/25 established a unique spot price in the WEM of 14,000 Ps./MWh as from November 1; SE Resolution No. 602/25 increased the spot price to 14,381 Ps./MWh as from December; and SE Resolution No. 34/26 set the spot price at 14,669 Ps./MWh as from January 2026. With respect to the remuneration for legacy generation capacity, the remuneration scheme established by SEE Resolution No. 19/17 remained in force until February 28, 2019. From March 1, 2019 to January 31, 2020 SRRYME Resolution No. 1/19 was in effect, and, beginning on February 1, 2020, SE Resolution No. 31/20 came in effect. As of February 2021, SE Resolution No. 440/21 increased the values defined in SE Resolution No. 31/20 by 29%. It also repealed the automatic adjustment mechanism included in SE Resolution No. 31/20. On April 21, 2022, the remuneration scheme was modified by SE Resolution No. 238/22 that established a 30% increase in remuneration retroactive to February 2022 and a new 10% increase to be applied beginning in June 2022. It also eliminated the use factor used to calculate generators remuneration and the temporary energy export’s remuneration. On December 12, 2022, the remuneration scheme was modified by SE Resolution No. 826/22, which established a 20% increase in remuneration retroactive to September 2022 and a new 10% increase to be applied as of December 2022. It also established a 25% increase to be applied as of February 1, 2023, and a 28% increase to be applied as of August 2023. Regarding remuneration of thermal generation, the differential remuneration for motor-generator technology with a capacity of less than 42MW was eliminated. In addition, the remuneration scheme during peak thermal demand hours (both for thermal and hydroelectric generation) was replaced by a differentiated remuneration scheme during peak hours. The new scheme recognizes a remuneration equivalent to two times the value corresponding to the current price for energy generated, applicable from 18:00 to 23:00 every day during December, January, February, June, July and August, and one times such value for the same hours of the day for March, April, May, September, October and November. SE Resolutions No. 9/24 and No. 99/24 updated the remuneration values for spot generation, establishing an increase of 73.9% and 25%, respectively, for the economic transactions from February 2024 to June 2024. In addition, SE Resolutions No. 193/24, No. 233/24 and No. 285/24 and SCEyM Resolution 20/24 established further increases of 3%, 5%, 2.7% and 6% for the economic transactions of August, September, October and November 2024, respectively. Subsequently, Resolution 387/24 established a 5% increase from December 2024 and Resolution 603/24 a 4% increase for January 2025. Thereafter, Resolution 27/25 established a 4% increase for February 2025 and Resolutions 113/25 and 143/25 provided a further 1.5% increase for March and April, respectively. In turn, SE Resolutions No. 227/25, No. 280/25, No. 331/25, No. 356/25 and No. 381/25 established further increases of 1.5%, 1%, 0.4%, 0.5% and 0.5% for the economic transactions corresponding to June, July, August, September and October 2025, respectively. 95 Table of Contents SE Resolution No. 483/25 introduced significant changes to the remuneration scheme for generators not covered by the new remuneration scheme set forth in the Rules of the Normalization of the WEM set forth in SE Resolution No. 400/25 (see “Item 4. The Argentine Energy Sector – Term Market - Current Remuneration Scheme for the Spot Market”). Considering these modifications, SE Resolution No. 483/25 established a 3.5% increase for thermal generation and an increase ranging from 12% to 20% for hydroelectric generation for economic transactions corresponding to November. Then, SE Resolution No. 602/25 established an increase of 2% for the economic transactions corresponding to December 2025. Finally, SE Resolution No. 34/26 established a 2% increase applicable to all economic transactions corresponding to January 2026, except for Renewable HI units with installed capacity (P) ≤ 50 MW, to which a 20% increase was applied. SE Resolution No. 34/24 modified the payment terms under the Spot Market and gave energy transporters a priority to collect their revenues over energy generators. Consequently, if CAMMESA does not have enough funds to pay for both energy transporters and generators, transporters shall have priority to collect their revenues over generators. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework.”. Power plants dispatch Upon the Plan Gas.Ar entering into force, SE Resolution No. 354/20 changed the dispatch of thermal power plants, establishing five categories according to the source of the natural gas supply. This scheme modified the previous cost-based dispatch. It also defined a “unified dispatch” by CAMMESA taking into account the following categories: (1) generators whose natural gas supply comes from the supply contract that ENARSA has in force with Bolivia up to the “take or pay” volumes; (2) generators whose natural gas supply is assigned by CAMMESA from the natural gas contracts executed under the Plan Gas.Ar regime up to the “take or pay” volumes; (3) generators whose natural gas supply is assigned by CAMMESA from the natural gas contracts executed under the Plan Gas.Ar regime in excess of the “take or pay” volumes and up to the maximum daily volume; (4) generators whose natural gas supply is assigned by CAMMESA from LNG contracts or other firm contracts executed by CAMMESA; and (5) generators whose natural gas supply comes from contracts with natural gas producers not assigned to CAMMESA, spot natural gas supply or other. Within each category the dispatch shall follow the production costs declared by each generator. The generators excluded from the centralized fuel supply by CAMMESA (i.e., power plants under the Energy Plus Program or with PPAs under SEE Resolution No. 287/17) may operatively assign the volumes and transport capacity that they have contracted. If they proceed with such an assignment, they will qualify in the third category, and if they do not execute the assignment, they will qualify in the fifth category. On January 28, 2025, SE Resolution No. 21/25 repealed SE Resolution No. 354/20. Following such decision the SE issued note NO- 025-16900682-APN-SE#MEC in which it instructed CAMMESA on the new conditions for the generators dispatch considering CAMMESA’s obligations under its Plan Gas.Ar contracts. According to note SE NO-025-16900682-APN-SE-MEC, once priority dispatch volumes treated as zero-cost generation have been satisfied, generators that have opted to supply their own fuel can participate in dispatch based on the ascending order of declared Variable Production Costs (CVP). Such participation occurs alongside units using natural gas supplied by CAMMESA and remains subject to applicable priority dispatch rules. On April 4, 2025, the SE issued note NO-2025-35216647-APN-SE#MEC, establishing additional guidelines to the ones contained in Note NO-2025-16900682-APN-SE#MEC for the gas dispatch priority scheme for thermal generation in the WEM. The new directives state that offers from generators opting to manage their own fuel supply will be considered firm, and in case of non-compliance, they will be penalized with a Deliver or Pay equivalent to 70% of the reference price for the unavailable volume. A new reference price applicable to different scenarios was set, equivalent to 90% of the weighted average representative price per basin for natural gas at the PIST, using the prices from Round 4.2 for the Neuquina Basin and Round 4.1 for the Austral Basin. For the Northern Basin, prices from the Neuquina Basin will be used. Additionally, the reference price for natural gas originating from neighboring countries was modified. 96 Table of Contents Reference prices for liquid fuels are determined for each generator based on international indicators, including a premium to cover associated financial and logistical costs. Regarding the payment for liquid fuels and natural gas from neighboring countries, the exchange rate corresponding to the business day prior to the transaction due date will be recognized, linked to the consumption recognized in the respective economic transaction. On October 21, 2025, SE Resolution No. 400/25 established a transition towards competitive and decentralized fuel management for thermal generators. Natural gas for power generation is dispatched with priority given to firm supply contracts under the Plan Gas.Ar scheme (in force until the end of 2028). During the transition, generators may source natural gas through centralized agreements with CAMMESA or manage their own supply, with full decentralization required from January 1, 2029. Alternative fuels (such as fuel oil, gas oil, coal, or LNG) must be managed directly by generators. Generators with self-managed fuel can freely declare their variable production cost (CVP) for dispatch, within reference price bands. Those without self-management remain under regulated costs and do not access the competitive margin scheme. CAMMESA continues as supplier of last resort for generators without self-managed fuel, but the remuneration for capacity without own fuel management is progressively reduced until it is eliminated in 2028. Dispatch is based on the CVP declared by each generator (or reference prices as indicated above), with reference values published by CAMMESA, and the marginal cost for dispatch is gradually adjusted to reflect both operated and next-unit costs. Seasonal prices The emergency regulations also made significant changes to the seasonal prices charged to distributors in the WEM, including the implementation of a cap (which varies depending on the category of user) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators. See “Item 5. Operating and Financial Review and Prospects - Electricity prices and tariffs.” Prior to implementation of the emergency regulations, seasonal prices were regulated by CAMMESA as follows: · prices charged by CAMMESA to distributors changed only twice per year (in summer and winter), with interim quarterly revisions in case of significant changes in the spot energy price, despite prices charged by generators in the WEM fluctuating constantly; · prices were determined by CAMMESA based on the average cost of providing one MWh of additional energy (its marginal cost), as well as the costs associated with the failure of the system and several other factors; and · CAMMESA would use seasonal database and optimization models in determining the seasonal prices and would consider both anticipated energy supplies and demand as follows: (i) in determining supply, CAMMESA would consider energy supplies provided by generators based on their expected availability, committed imports of electricity and the availability declared by generators; and (ii) in determining demand, CAMMESA included the requirements of distributors and large users purchasing in the WEM as well as committed exports. On January 25, 2016, the ME&M issued Resolution No.6/16, approving the seasonal WEM prices for each category of users for the period from February 2016 through April 2016. Such resolution readjusted the seasonal prices set forth in the regulatory framework. Energy prices in the spot market had been set by CAMMESA, which determined the price charged by generators for energy sold in the spot market of the WEM on an hourly basis. The WEM prices resulted in the elimination of most energy subsidies and a substantial increase in electricity rates for individuals. Resolution No. 6/16 introduced different prices according to the customers’ categories. Such resolution also contemplated a social tariff for residential customers who comply with certain consumption requirements, which includes a full exemption for monthly consumptions below or equal to 150 kWh and preferential tariffs for customers who exceed such consumption level but achieve a monthly consumption lower than that of the same period in the immediately preceding year. This resolution also established tariff benefits addressed to residential customers for reducing their consumption. SEE Resolution No. 41/16 approved the winter seasonal prices in line with the prices included in SEE Resolution No. 6/16. During the Macri administration, the SGE issued various resolutions by means of which increased the portion of the generation cost to be paid by end users. However, there is still a portion of the generation costs, of approximately 40% for the quarter Feb/20 - Apr/20 according to CAMMESA’s estimations, that it is not transferred to the end users and it is covered by the Argentine Government. This situation led to a delay in CAMMESA’s payments to generators, which together with delayed payments from distributors have a negative impact on generators’ operations. 97 Table of Contents Moreover, SEE Resolution No. 20/17 allowed Provinces to collect the royalties to be paid by hydroelectric generators in kind in order to compensate for the debt of provincial distributors. During 2022, the Province of Neuquén applied for this scheme and obtained the corresponding authorizations (SE Resolution No. 769/22). SEE Resolution No. 1085/17 established a new scheme for the distribution of the energy transport cost to the final user and generators. Moreover, SRRYME, through Resolutions No. 2/19 and No.7/19, defined the methodology for such distribution and its inclusion in the seasonal price. Even though the latest resolutions defining the seasonal prices increased the energy transport costs, as of the date of this annual report, seasonal prices approved by the SE do not cover all sector costs. During 2021, the SE approved both winter and summer seasonal prices through different resolutions (SE Resolutions No. 408/21; No. 748/21; No. 1029/21 and No. 40/22). The main changes included the division of each distributor’s users into different categories to fix the reference prices to be applied to such users. For example, different reference prices were set to GUDIs which are health and education public institutions; general consumers (non-residential), residential users, and GUDIs whose activity is crypto mining. The SE defined un-subsidized prices and required distributors (mainly Edenor and Edesur) to calculate the subsidy for each invoice and include such amount in the respective invoice. Even though the SE approved higher prices than those applicable to residential end users, such prices do not cover the production cost. According to CAMMESA estimates, on average seasonal prices cover around 40% of the cost of production. During 2022 and 2023, the SE took several measures to reduce energy subsidies and transfer a higher proportion of the cost or energy production to the users. To that end, the SE established a new segmentation scheme. On February 5, 2024, SE Resolution No. 7/24 approved the summer seasonal reprogramming (February – April 2024) and established a new segmentation of distributors’ demand with only two categories: (i) “residential” (level 2 and 3 up to a consumption of 400 kWh per month); and (ii) “the rest”. The POTREF for the “The Rest” category was increased by 3,252.61%. The PEE prices for the former categories included in the “The Rest” segment were increased by 117% to 186%. Additionally, new unsubsidized POTREF ($2,682,088/MW-month) and PEE prices were sanctioned ($46,018/MWh; $44,401/MWh and $43,473/MWh depending on the hour of the day). On May 28, 2024, the National Government published Decree No. 465/24 in the Official Gazette, which ordered the restructuring of national jurisdiction energy subsidy regimes to ensure a gradual, orderly, and predictable transition to a scheme that allows users to bear the real costs of energy, promote energy efficiency, and ensure vulnerable residential users have access to essential consumption of electricity, natural gas, and bottled natural gas. To this end, a transition period of 6 months (extendable for an equal period) was established, depending on the evolution of the general economic situation and the dynamics of the energy sector. Additionally, it amended Decree No. 332/22, which had established the demand segmentation scheme considering the economic capacity of users (Level 1 (high income), Level 2 (low income), and Level 3 (middle income)). It also empowers the SE to: i) establish subsidized consumption limits for electricity and gas in all residential categories, considering criteria such as the area and time of year; ii) apply energy tariff discounts for users of different levels during a transition period; iii) charge consumption that exceeds subsidized limits at wholesale prices set by the Secretary of Energy, with possible gradual bonuses for Level 2 users; and iv) regularly review subsidized consumption limits and discounts, promoting efficient consumption habits, among others. 98 Table of Contents During this transition period, the evolution of all variables at play will be monitored, information cross-checks will be conducted, and the re-registration and updating of the ESAR (Energy Subsidy Access Registry) will be promoted to ensure that users are in the corresponding segment according to their income level. SE Resolution No. 90/24 applied caps on subsidized consumption volumes in all residential categories and segments, and discounts or bonuses on the Seasonal Price to be passed on to end users will be applied, establishing that excess consumption amounts be paid at wholesale electricity prices. Later, SE Resolution No. 19/24, established that on the final summer seasonal period starting on November 1, 2024 until April 30, 2025, the supply costs will be charged from distributors to large demand and level 1 users. On January 30, 2025, SE Resolution No. 26/25, established that the final summer seasonal period starting on November 1, 2024, until April 30, 2025, and, according to the information provided by CAMMESA, only Wholesale Large Users would pay for the actual energy cost of the new seasonal price and distributor’s demand has subsidized prices. On April 4, 2025, SE Resolution No. 171/25, established reference prices for the winter seasonal period starting on May 1, 2025 and ending on October 31, 2025. SE Resolutions No. 226/25, No. 331/25 and No. 334/25 modified the reference prices during such seasonal period and updated the surcharges of the National Electric Power Fund (FNEE). SE Resolution No. 434/25 established the final summer seasonal period for the period from November 1, 2025, to April 30, 2026, and approved un-subsidized reference prices. SE Resolutions No. 488/25 No. 604/25 No. 434/25, No. 488/25, No. 604/25 and No. 22/26 updated the reference and un-subsidized prices during the summer seasonal period. Following the publication of SE Resolution No. 400/25, seasonal prices were redefined to incorporate the new supply scheme. These prices are calculated based on the costs associated with Assigned Generation —including existing WEM supply agreements, hydroelectric generation owned by the National Government, nuclear generation, and any necessary imports— and, when coverage is insufficient, Spot market costs. The resolution also introduced segmentation of seasonal demand into two categories: Residential, with priority access to Assigned Generation and prices reflecting its average costs, and Non-Residential, which will be supplied with Assigned Generation and, when necessary, through Spot purchases or Term Market (MAT) contracts. Differences between the Stabilized Price and actual costs will be adjusted quarterly, and prices will be calculated by hourly bands (peak, off-peak, and valley), deducting capacity charges proportionally paid by distributors. Recently, Decree No. 934/25 unified the national energy subsidies and established the Targeted Energy Subsidy Scheme (SEF) for electricity and natural gas, among others. It also eliminated the segmentation by income levels and established a single category. Term market Generators may also enter into agreements in the term market to supply energy and capacity to distributors and large users. Term agreements typically stipulate a price based on the spot price plus a margin. Prices in the term market have sometimes been lower than the seasonal price that distributors are required to pay in the spot market. However, as a result of the emergency regulations, prices in the term market are currently higher than seasonal prices, particularly with respect to residential tariffs, making it unattractive to distributors to purchase energy under term contracts while prices remain at their current levels. The term market was suspended by SE Resolution No. 95/13 except for the Energy Plus Program, renewable energy supply contracts (MATER) and generators that entered into commercial operation as of January 1st, 2025 (as per SE Resolution No. 21/25). SE Resolution No. 400/25 enables contracting in the Term Market, differentiating between the Energy Term Market (MATE) and the Capacity Term Market (MAT Potencia), and establishes eligibility criteria for generators’ participation. In MATE, existing generation prior to January 1, 2025 can contract up to 100% of its monthly energy with distributors to cover unmet Seasonal Demand and up to 20% with large users (GUDI/GUMA/GUMES/GUPAS). Generators whose entry into commercial operation is after January 1, 2025 and generators with new firm natural gas transport contracts have no limitations and can contract all their capacity and energy with distributors and/or large users. 99 Table of Contents Provincially owned or managed hydroelectric power plants are authorized to contract without restrictions with distributors for their GUDIs and, from January 1, 2030, without limits with any Spot demand. Renewable generation maintains the MATER regime. In the Capacity Term Market there are no limitations on generators contracting with distributors and large users. Coverage under these contracts is assessed hourly in HRP. Coverage varies according to the power generation source used. Thermal generators’ coverage is 100%, while hydroelectric generators’ coverage is 70%. BESS projects may contract provided they comply with four hours of guaranteed energy charge. Renewable generators cannot offer capacity contracts. Remuneration Scheme for Generation Not Covered by Contracts Period, in Ps./MW-HMRT First 25 HMRT hours Second 25 HMRT hours Summer (December - February) and Winter (June - August) 45,000 22,500 Other (March - May and September - November) 7,500 - Current Remuneration Scheme for the Spot Market. Remuneration scheme for generators not covered by SE Resolution No. 400/25 On May 21, 2021, SE Resolution No. 440/21 was published in the Official Gazette increasing the remuneration scheme under SE Resolution No. 31/20 by an average of 29%. The resolution was retroactive as of February 2021 and rendered the update factor ineffective. The resolution also established that generators could apply this remuneration increase, provided they waived and/or dismissed all administrative and/or judicial claims filed due to the non-application of the automatic adjustment formula set by SE Resolution No. 31/20. Pampa adhered to this scheme. The remuneration scheme approved in SE Resolution No. 440/21 was modified on April 21, 2022, by SE Resolution No. 238/22. The latter established a 30% increase in remuneration as of February 2022 and a new 10% increase to be applied from June 2022 onwards. The remuneration scheme was modified on December 12, 2022, by SE Resolution No. 826/22, which established a 20% increase in remuneration as of September 2022 and a new 10% increase to be applied as of December 2022. It also established a 25% increase as of February 1, 2023, and a 28% increase as of August 2023. It also eliminated the use factor used to calculate generators’ remuneration and the temporary energy export remuneration. In September 2023, SE Resolution No.750/23 established a 23% increase in the remuneration as of September 2023. In October 2023, SE Resolution No. 869/23 updated the value of remuneration for spot generation with a 28% increase for November 2023. Finally, SE Resolution No. 9/24 approved a 74% increase as of February 2024. However, the latter resolution indicated in its whereas clause that the increase was a transitional measure until the SE establishes the necessary measures to comply with the provisions of Decrees 55/24 and 70/24 to allow a free market between WEM participants. The SE issued further resolutions during 2024 and 2025 updating the remuneration values for the economic transactions of those periods. Recently, SE Resolution No. 483/25 introduced significant changes to the remuneration scheme for such generators, consistent with the Rules of the Normalization of the WEM set forth in Resolution SE No. 400/25. This new scheme applies to generators that are not committed under power or energy availability contracts in the WEM, nor authorized to participate in the Spot Market regulated by SE Resolution No. 400/25. 100 Table of Contents It includes: (i) thermal units managed by ENARSA, the General San Martín and General Belgrano power plants, and combined-cycle units under agreements pursuant to SE Resolution No. 59/23; and (ii) hydroelectric power plants under national concessions, as well as the binational Salto Grande plant; but does not apply to privatized hydroelectric complexes (Alicurá, El Chocón–Arroyito, Cerros Colorados, Piedra del Águila), which remain subject to the regime established in SE Resolution No. 331/25 until further measures are implemented. Under this framework, capacity remuneration is calculated based on the monthly Real Power Availability (DRP) and guaranteed price by technology, removing the Base provision. For hydroelectric plants, availability is determined regardless of reservoir levels, and in the case of pumped-storage plants, both turbine operation and pumping availability are considered. In addition, the remuneration scheme has been streamlined by reducing distinctions based on technology and scale. Considering these modifications, SE Resolution No. 483/25 established a 3.5% increase for thermal generation and an increase ranging from 12% to 20% for hydroelectric generation for economic transactions for November. Finally, SE Resolution No. 602/25 established an increase of 2% for the economic transactions corresponding to December 2025. Finally, SE Resolution No. 34/26 established an increase of 2% for the economic transactions corresponding to January 2026. Remuneration to Generators Achieved (GA) consists of payments for monthly available capacity and energy, with energy understood as the sum of three components: i) based on the Energy Generated and the type of fuel, ii) the Energy Operated, and iii) the energy actually generated during peak hours. Remuneration for capacity availability is linked to the average Real Power Availability (RPA) for the month, valued at the Guaranteed Power Price (PrecPotDIGO). Remuneration for Capacity Availability. Remuneration for capacity availability is determined based on the Actual Power Availability (DRP) of each generation unit and the Guaranteed Power Price (PrecPotDIGO) corresponding to it, according to its technology, scale and monthly period. The Actual Power Availability (DRP) is the average monthly availability corresponding to month “m” of each generating machine “g”, that shall be calculated by taking the hourly values of available power recorded in that month. Thermal Power Generators The prices for the Available Power, in $/MW-month, for thermal generators under SE Resolution No. 438/25, are as follows: Thermal / Period PrecPotDIGO ($/MW-Month) Nov-25 Dec-25 Summer (Dec. Feb.) 7,256,568 7,401,699 Winter (Jun. – Aug.) 7,256,568 7,401,699 Others (Mar. – May & Sep. Nov.) 5,442,428 5,551,277 Hydrological Generators The prices for the Available Power, in $/MW-month, for hydrological generators under SE Resolution No. 438/25, are as follows: Hydrological – Technology / Scale PrecPotDIGO ($/MW-Month) Nov-25 Dec-25 Large HI > 300 MW 1,995,562 2.035.473 Medium HI > 120 MW & ≤ 300 MW 2,904,971 2,963,070 Small HI > 50 MW & ≤ 120 MW 4,206,418 4,290,546 Renewable HI ≤ 50 MW 7,288,122 8,745,746 Large HB pumping units with power P > 300 MW 1,995,562 2,035,473 101 Table of Contents Remuneration for Energy Generated Thermal Generators - Price of Energy Generated. For conventional thermal generation, the following shall be recognized as the maximum, by type of fuel consumed by the generating unit “g”, the variable non-fuel costs [CostoOYMxComb] indicated in the following table for the energy delivered each hour: Fuel Nov. - 25 Dec. - 25 Natural gas 4,842 4,939 FO or GO 8,473 8,642 Biofuels in general 12,095 12,337 Mineral coal 14,514 14,804 Hydrological Generators - Price of the Energy Generated. The price per unit of energy generated shall be recognized hourly as follows: Nov. - 25 Dec. - 25 National Hydraulics and Pumping 4,232 4,317 Binational Salto Grande 6,960 7,099 Remuneration for Energy Operated Generators will receive monthly remuneration for the Energy Operated, represented by the integration of hourly power during the period, valued at: Nov. - 25 Dec. - 25 Thermal 1,684 1,718 Hidrologycal National 1,684 1,718 Hydraulics and Pumping 1,684 1,718 Salto Grande 0 0 102 Table of Contents Remuneration scheme for generator covered by SE Resolution No. 400/25 All generation not committed under contracts or not allocated to supply the Seasonal Demand of WEM Distributors (DEDMEM) is considered Spot Generation, meaning energy available for commercialization in the Spot Market under the dispatch and remuneration rules established by the resolution. Remuneration of Thermal Generation Energy Thermal generation operating in the Spot Market is dispatched and therefore remunerated based on the declared Variable Production Cost (CVP) and an Adapted Marginal Rent (RMA), calculated as: Hourly Price = CVP + [(CMgh × FP – CVP) × FRA], where CMgh is the hourly marginal cost, FP the loss factor, and FRA a progressive factor: Year FRA 2025 0.15 2026 0.15 2027 0.25 2028 onwards 0.35 For new generation units, those that entered commercial operations as of January 1, 2025, and thermal units with firm natural gas transport, the Adapted Rent Factor (FRA) is set at 1. If a generator does not have its own fuel supply, its FRA will be zero, and the CVP will be based on reference values. Generators using CAMMESA’s “GN Agreement” apply an additional correction factor (FRC) to the Adapted Marginal Rent (RMA): Year FRC 2025 0.8 2026 0.8 2027 0.6 2028 onwards 0.5 For existing generation units, those that entered commercial operations prior to January 1, 2025, the resulting Adapted Marginal Rent (RMA) values will have the following minimums at the plant level —RMIN in U.S.$/MWh— evaluated hourly based on the unit’s declared CVP. RMIN CVP < 60u$s/MWh RMIN CVP >= 60u$s/MWh 2 7 For new generation units, those that entered commercial operations as of January 1, 2025, the Adapted Marginal Rent (RMA) will have no minimum or maximum limits, and the Adapted Rent Factor (FRA) will be set at 1. When these generators manage their natural gas supply through CAMMESA’s “GN Agreement,” the RMA calculation will apply the correction factor (FRC) indicated in the resolution. Thermal generation dispatched for operational reasons or local restrictions will only be recognized at its declared Variable Production Cost (CVP) and recovered through Spot Market prices. Monthly remuneration is determined based on actual generation and hourly prices. Fuel declarations for own gas or alternative fuels are binding; if a generator fails to provide the committed volume when dispatched, a Deliver-or-Pay penalty of 70% of the declared value applies, with exceptions for deviations up to 20% or justified causes beyond the generator’s control. 103 Table of Contents Remuneration of Renewable Energy and Self-Generators Remuneration for renewable generation in the Spot Market follows a scheme similar to thermal generation, with CVP equal to zero. For renewable units with commercial operation before December 31, 2024, Adapted Rent Factors (FRA) evolve annually as for existing thermal generation, and the Adapted Marginal Rent (RMA) has a minimum of U.S.$ 32/MWh. Renewable generation starting from January 1, 2025, applies FRA = 1 with no minimum or maximum limits for RMA. Biomass, biogas, or BRS-based renewable units may request dispatch under thermal generation conditions. Industrial self-generators offering surplus energy are treated as CVP = 0 with FRA evolution similar to thermal generation, while self-generators and co-generators offering firm capacity must declare CVP and receive the same treatment as thermal generators. Remuneration of hydroelectric generators This remuneration follows a scheme similar to thermal generation remuneration, with CVP equal to zero. For existing hydro units (before January 1, 2025), Adapted Rent Factors (FRA) evolve annually as for thermal generation, and the Adapted Marginal Rent (RMA) has a minimum of U.S.$ 22/MWh. New hydro generation (from January 1, 2025) applies FRA = 1 with no minimum or maximum limits for RMA. Pumped-storage plants follow the same conditions for hydro generation, with remuneration based on pumping demand cost and adapted marginal rent, applying FRA evolution and a minimum RMA of U.S.$ 22/MWh. Remuneration of Energy Storage Energy storage plants operating in the Spot Market earn revenue through price arbitrage between charging and discharging. Both charging cost and discharge remuneration are calculated as CMgh × FP, where CMgh is the hourly marginal cost and FP the loss factor. Dispatch for charging and discharging is coordinated with CAMMESA in weekly or daily scheduling, and storage units may also participate in the Term Market as demand (charging) and as generation (discharging). Remuneration of Thermal Generation Capacity During Hours of Capacity Remuneration (HRP), thermal generators are eligible for capacity payments (Potencia Puesta a Disposición – PPAD) provided they declare fuel self-management. A unit is considered available if it reports fuel management and equipment availability in all scheduling stages. Alternative fuel availability is monitored under the current SCOMB scheme. For units capable of operating with both natural gas and alternative fuels, if fuel management is declared only for natural gas, capacity will be remunerated as “with fuel management” for summer and mid-season months, and as “without fuel management” for winter months. Capacity remuneration applies during Hours of Capacity Remuneration (HRP), about 90 hours per week, when the unit is available. The hourly price for Potencia Puesta a Disposición (PPAD) is set at U.S.$ 12/MW, adjusted by seasonal and fuel-type multipliers (KP): Year PPAD KP – Capacity Multiplier THERM. NG THERM. NG+ALT November 25 onwards 12 U.S.$. /MW Win/Sum: 1.1 Rest: 0.9 Win/Sum: 1.5 Rest: 1 During the transition, units without fuel self-management receive reduced payments when not dispatched: Until Dec 2026: 80% of PPAD; Until Dec 2027: 40% of PPAD; and From Jan 2028: only when dispatched. Existing reliability commitments under SE Resolutions No. 59/23 and No. 294/24 remain in force. 104 Table of Contents Remuneration of Hydro, Renewable, and Storage Capacity During Hours of Capacity Remuneration (HRP), these technologies shall receive payments for Potencia Puesta a Disposición (PPAD) at a base price of U.S.$ 12/MW, applying technology-specific multipliers (KP): Year PPAD KP – Capacity Multiplier HYDRO RENEWABLE STORAGE November 25 onwards 12 U.S.$./ MW 0.5 0 Win/Sum: 1.1 Rest: 0.9 The capacity to be remunerated for hydro plants corresponds to their available installed capacity. Pumped-storage plants follow the same rules as conventional hydro generation. Storage plants receive capacity payments based on available capacity and validated storage hours (HAV). For each HRP, the recognized capacity is the actual available storage capacity, up to the commercially enabled limit. The application factor for PPAD pricing depends on HAV: i) HAV ≥ 4 hours: factor = 1; ii) HAV between 1 and 4 hours: factor = HAV ÷ 4 and iii) HAV < 1 hour: factor = 0. Differential Remuneration for Conventional Energy SE Resolution No. 1,281/06: Energy Plus Program In September 2006, the SEE issued Resolution No. 1281/06 in an effort to respond to the sustained increase in energy demand following Argentina’s economic recovery after the crisis. This resolution sought to create incentives for energy generation plants in order to meet increasing energy needs. The resolution’s principal objective is to ensure that energy available in the market is used primarily to service residential users and industrial and commercial users whose energy demand is equal to or below 300 kW and who do not have access to other viable energy alternatives. To achieve this, the resolution provided that: · large users in the wholesale electricity market and large customers of distribution companies (in both cases above 300 kilowatts) will be authorized to secure energy supply up to their “base demand” (equal to their demand in 2005) by entering term contracts; and · large users in the wholesale electricity market and large customers of distribution companies (in both cases above 300 kilowatts) must satisfy any consumption in excess of their base demand with energy from the Energía Plus system at prices that had to be approved by the ME&M. The Energía Plus system consists of the supply of additional energy generation from new generation and/or generating agents, co-generators or auto-generators that are not agents of the electricity market or who as of the date of the resolution were not part of the WEM. 105 Table of Contents The resolution also established the price large users were required to pay for excess demand, if not previously contracted under Energía Plus, a price closer to the marginal cost of operations. This marginal cost is equal to the generation cost of the last generation unit transmitted to supply the incremental demand for electricity at any given time. The SEE established certain temporary price caps to be paid by large users for any excess demand (as of the date of this annual report, Ps.1200 for GUMEs and GUMAs and Ps.0 per MWh for GUDIs). On January 28, 2025, the SE issued Resolution 21/25 which changed the regulations of the dispatch and operation of the Term Market (MAT) of the Wholesale Electricity Market (WEM). Regarding the Energy Plus market, it established October 31, 2025 as a deadline for the execution of new contracts or the renewal of supply agreements under Energy Plus Contracts. Consequently, as of November 2025, we were unable to execute new contracts upon the termination of those in force at such date. Our revenues could be affected if we cannot contract the capacity and energy under the new regulatory schemes. WEM Supply Agreements under SE Resolution No. 220/07 Aiming to modify the market conditions to encourage new investments and increase the generation supply, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into “WEM Supply Commitment Agreements” with WEM Generating Agents for the energy produced with new generation equipment. These are long-term U.S. Dollar-denominated PPAs, and the price payable by CAMMESA should compensate the investment made by the agent at a rate of return to be accepted by the SE. CTLL, CTP and CTEB have entered into agreements with CAMMESA under this Resolution, which account for a gross power capacity of 856 MW. Within the framework of these regulations, during 2021 the PPAs of CTP (30 MW) and CTLL’s TV01 (180 MW) completed the 10-year contractual term. Moreover, on April 2022, the PPA that remunerated CTEB’s gas turbines ended. As of such dates, the units have been remunerated under the spot scheme described above. Therefore, as of the date of this annual report, only part of CTLL’s TG04 gas turbine capacity (79 MW) and CTEB’s vapor turbine, are remunerated under this scheme. WEM Supply Agreements under SEE Resolution No. 21/16 As a result of the state of emergency in the national electricity sector declared by Decree No. 134/15, on March 22, 2016 the SEE issued Resolution No. 21/16 launching a call for bids for new thermal power generation capacity with the commitment to making it available through the WEM for the summer 2016/2017, winter 2017, and summer 2017/2018 periods. Awarded bidders entered PPAs for a fixed price (in U.S.$/MW-month) and a variable price excluding fuels (in U.S.$/MWh) with CAMMESA, which acted on behalf of distributors and WEM’s GU. We were awarded the installation of GT05 in CTLL for 105 MW and the construction of CTIW for a 100 MW capacity, both of which have been in service since August and December 2017, respectively. Furthermore, we acquired and developed CTPP for a 100 MW capacity, which was commissioned for service in August 2017. SEE Resolution No. 287/17: Co-generation and CC Projects On May 10, 2017, the SEE issued Resolution No. 287/17 launching a call for bids for co-generation projects and the closing to CC over existing equipment. The projects should have low specific consumption (lower than 1,680 kcal/kWh operating on natural gas and 1,820 kcal/kWh operating with alternative liquid fuels), and the new capacity should not increase electricity transmission needs beyond the existing capacity; otherwise, the cost of the necessary extensions would be borne by the bidder. Awarded projects were remunerated under a PPA for a term of 15 years. The remuneration is made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if offered), less penalties and fuel surpluses. Power capacity surpluses would be remunerated as legacy capacity. Within this framework, in September 2017, the SEE issued Resolution No. 820/17 awarding only three co-generation projects for a 506 MW power capacity, and, in October 2017, pursuant to Resolution No. 926/17, it awarded projects for a total 1,304 MW power capacity, where Pampa was awarded with Genelba 106 Table of Contents Plus’ closing to CC for a 383 MW capacity. Commercial operations at open cycle started in June 2019, and its commissioning at closed cycle started in July 2020. Thereafter, SRRYME Resolution No. 25/19 authorized awardees of projects under SEE Resolution No. 287/17 to submit a new scheduled commissioning date, which will operate as the new committed commissioning date under the PPAs, with a limit of 180 days beginning on the originally committed commissioning date. However, Pampa ratified Genelba Plus CC’s commercial commissioning date. As described above, SE Resolution No. 354/20 allows generators with PPAs under SEE Resolution 287/17 to assign the operation of the natural gas volumes and transport capacity of their contracts for the supply of the power plants with contracts under the latter resolution. The Company proceeded with such assignment, and an amendment to the PPA must therefore be executed. Even though the SE Resolution No. 21/25 repealed the SE Resolution No. 354/20, CAMMESA will continue to provide the natural gas necessary for the operation of Genelba Plus combined cycle. SEE Resolution No. 59/23: Remuneration for combined cycles On February 7, 2023, the SE issued Resolution No. 59/23, which established a regime pursuant to which the owners of combined cycle plants may adhere to and sign an Availability and Efficiency Improvement Agreement (Availability Agreement) with CAMMESA. The Availability Agreement contemplates an availability commitment of 85% of the net capacity for a maximum term of 5 years. In consideration for such availability commitment the generator shall collect U.S.$ 2,000/MW-months and the dollarization of energy prices (U.S.$3.5/MWh for natural gas and U.S.$6.1/MWh for FO and GO). It also provides for a 35% reduction in the remuneration to be received by the power plant for the power offered DIGO under SE Resolution No. 826/22 scheme in the months of December, January, February, June, July and August and 15% in the remaining months of the year. The agent interested in joining the program must submit its application within 90 calendar days to CAMMESA. The SE, through note NO-2023-28679610-APN-SE#MEC, instructed CAMMESA with certain changes in the application criteria: i. It allowed CAMMESA to contract the supply of capacity and energy from combined cycles not committed in other contracts. Combined cycles associated with industrial or commercial demand are excluded. ii. It established, regarding energy remuneration, that in hours when the generation unit is dispatched outside CAMMESA’s optimal dispatch for operational reasons not attributable to forced generation due to transportation, voltage control, or security requirements, the remuneration will be equal to 60% of the net installed power, regardless of the energy delivered by the generation unit. iii. It corrected the dates to be used for the adjustment in the applicable exchange rate, and therefore, the exchange rate at the closing of the business day prior to the expiration of the transaction will be used. iv. The generator may request the termination of the contract if the complementary remuneration derived from SE Resolution No. 826/22 or amendments thereto does not reflect the variation of the generation costs. The termination will depend on the analysis and acceptance of the SE. Within the framework of this resolution, in April 2023, Pampa executed two PPAs for GENELBA and CTLL combined cycles. Additionally, CTB also executed a PPA for its combined cycle. Following the publication of SE Resolution No. 400/25 in November 2025, Pampa requested to adhere to the new Spot Market framework under the established conditions and prices. In this context, Pampa suspended the PPAs relating to the combined cycles of CTGEBA, CTLL and CTB. Consequently, the obligations arising from adherence to SE Resolution No. 59/23 will remain suspended as long as the conditions established in SE Resolution No. 400/25 remain unchanged. 107 Table of Contents Contingency and Forecast Plan for Energy Supply in Critical Months The SE, through Resolution No. 294/24, established a “Contingency and Forecast Plan for Critical Months of 2024/2026” with the aim of avoiding, reducing or mitigating the critical energy supply condition for the critical days of the following years. The plan identifies different measures for the different segments of the industry. Regarding electricity generation, it includes an additional remuneration based on the available capacity and generation to promote the availability of thermal generation in the critical months and hours between December 2024 to March 2026. This scheme may be extended by the Undersecretariat of Electrical Energy for a further 12 months term, subject to the filling of a maintenance program for each generating unit. The remuneration scheme provides (i) a capacity remuneration of U.S.$ 2,000/MW-month, adjusted by a criticality factor that takes into account the node where the generating unit is located and the actual availability of the unit during the most critical hours, and 50% of this remuneration for the capacity in excess of the committed capacity; and (ii) a generated energy remuneration , which varies between U.S.$ 3.4/MWh and U.S.$ 10.5/MWh, depending on the fuel used and the generation technology. On the other hand, it instructed CAMMESA to implement an exceptional dispatch procedure that will allow the strategic use of generation units to reduce the risk of supply restrictions during peak hours. Such a procedure may include the possibility of reserving the dispatch of the remaining operating hours of those units that are nearing the end of their useful life, in order to allow their use during periods of maximum demand. Within the framework of these regulations, on November 20, 2024, Pampa adhered to such scheme for the relevant units of CPB, CTG, CT Piquirenda, CTLL, CTGEBA and Ecoenergía, effective from 1 December 2024 until 31 March 2026. On May 26, 2025, CPB submitted a formal request for a 12-months extension of the complementary remuneration scheme, applicable to CPB’s generating units BBLATV20 and BBLATV30. This request was approved on December 4, 2025, by the SE through Note No. NO-2025-114019713-APN-SSEE#MEC. In addition, in December 2025, requests were submitted to extend the remuneration scheme for 12 months for the following assets: CTP, CTLL, CTGEBA, ECOENERGIA and CTG. Such requests were approved on January 21, 2026, by the SE through Notes No. NO-2026-05311855-APN-SSEE#MEC; NO-2026-05311697-APN-SSEE#MEC; NO-2026-05310868-APN-SSEE#MEC; NO-2026-05311127-APN-SSEE#MEC and NO-2026-05311398-APN-SSEE#MEC, respectively. SE Resolution No. 976/23: New charges for GUDIs On December 2, 2023, the SEE issued Resolution No. 976/23, which stipulated that starting February 2024, CAMMESA must invoice the Distributor Agents and/or service providers of the WEM and the MEMSTDF for new charges: the “GUDIs Stabilized Charge” and the “GUDIs Complementary Power Adjustment”. This information must be published in the monthly DTE so that each WEM and/or MEMSTDF Provider can directly transfer the “GUDIs Stabilized Charge” and the “GUDIs Complementary Power Adjustment” to their clients’ invoices. On March 27, 2024, by ENRE Resolution No. 197/24, the ENRE authorized EDENOR and EDESUR to include such charges in the invoices of its relevant clients. Differential Remuneration for Renewable Energy Measures for the Promotion of Renewable Energy Projects In October 2015, Law No. 27,191 (regulated by Decree No. 531/16) was passed, which amends Law No. 26,190 on the promotion of renewable sources of energy. Among others, it provided that by December 31, 2025, 20% of the total demand for energy in Argentina should be covered with renewable sources of energy. To achieve such objective, WEM’s GU and CAMMESA should cover 8% of their demand with such sources by December 31, 2017, the percentage rising every two years until the objective is met. The agreements entered into with GU and GUDI may not have an average price exceeding U.S.$113/MWh. 108 Table of Contents Additionally, the law provides for several incentives to encourage the construction of renewable energy projects, including tax benefits (advance VAT return, accelerated depreciation on the income tax return, import duty exemptions, etc.) and the creation of the FODER, which is destined, among other objectives, to the granting of loans, capital contributions, etc., for the financing of these projects. RenovAr Program ME&M Resolution No. 71/16 issued in May 2016 launched the RenovAr (Round 1) Program’s open call for tenders. In October 2016 and pursuant to Resolution No. 213/16, the ME&M awarded 29 projects for a total 1,142 MW (97% of which were wind and solar energy projects). Additionally, in October 2016 ME&M Resolution No. 252/16 was issued launching the RenovAr (Round 1.5) Program’s call for tenders, and the following month ME&M Resolution No. 281/16 was issued, whereby 30 projects for a total 1,281.5 MW (100% which use wind and solar energy projects) were awarded. Furthermore, in August 2017 ME&M Resolution No. 275/17 was issued launching the RenovAr (Round 2) Program’s call for tenders, and in December 2017 ME&M Resolutions No. 473/17 and 488/17 were issued, whereby 88 projects for a total 2,043 MW (89% of them wind and solar energy projects) were awarded. Finally, in November 2018, SGE Resolution No. 100/18 launched the RenovAr MiniRen (Round 3) Program’s call for tenders for smaller-scope renewable projects (between 0.5 and 10 MW) contemplating its connection to the facilities of the distribution company corresponding to the location, with a maximum 400 MW facility, of which 350 MW are wind and solar energy projects. SSEERR Resolution No. 91/19 awarded projects for a total capacity of 246MW under RenovAr round 3. In all projects under the RenovAr rounds, any and all reductions of greenhouse-gas emissions resulting from the power capacity installed throughout the national territory, including that resulting from any other project accounted for to reach the WEM’s renewable power capacity goals set in Law No. 27,191, will be recognized by the Argentine Government towards the fulfillment of the contribution goal under the United Nations Framework Convention on Climate Change and the Paris Agreement. During 2021, several changes were introduced to the RenovAr Program by the SE Resolution No. 742/21 that modified the penalties scheme. Under such modifications the penalties for breach of supply commitments may be cancelled in installments. Additionally, an extra term was granted to the projects that experienced a delay in the entry into commercial operations committed date. Depending on the term granted to the project the term of the PPA with CAMMESA and the penalties to be paid during such extra term vary. Moreover, in order to increase transport capacity, SE Resolution No. 1260/21 approved a scheme that allowed the owners of the projects that did not meet the entry into commercial operations committed date to terminate their commitments with CAMMESA by means of payment of a penalty (equivalent to U.S.$ 17,500/MW for wind and solar projects and U.S.$ 12,500/MW for other technologies) and the fulfillment of other conditions. Alternatively, the owners of such projects could: (i) request an extension of the entry into commercial operations committed date in which case the term and price of the relevant PPA would be reduced; or (ii) reduce the project capacity (RenovAr 3 projects are not eligible for this option). In each case, the owner of the project must present a waiver to file any and all claims against the SE, CAMMESA, etc., for damages derived from the chosen alternative. On March 20, 2023, SE Resolution No. 165/23 (“Resolution 165”) amended Article 1 of SE Resolution No. 285/18 (previously amended by SE Resolution No. 742/21), in connection with the applicable monthly payment cap of penalties foreseen under the power purchase agreements from renewable sources executed under the RenovAr Program Rounds 1, 1.5, 2 and 3 and Resolution No. 202/16. On April 25, 2023, SE Resolution No. 284/23 established a new scheme allowing for RenovAr Rounds 2 and 3 projects with delays, to terminate the PPA executed with CAMMESA upon the payment of a termination fee equal to U.S.$ 35,000/MW and a waiver (i) of any claims against the Federal Government, the SE and CAMMESA and (ii) any tax benefit obtained but not applied to the project. 109 Table of Contents In November 2023, SE Resolution No. 883/23 was approved, which established a compensation mechanism for penalties under the Renewable PPAs provided that the amounts to be compensated are invested in new renewable generation capacity. The owners of the projects that request the compensation will have a term of 36 months for the installation of the new renewable power and the new capacity will be remunerated by one of the following options: (i) 100% of the energy generated to be remunerated at a price equal to U.S.$ 20/MWh for a 60-month term; (ii) 20% of the energy generated to be remunerated at a price equal to U.S.$ 20/MWh for a 120-month term and the remaining 80% to be sold either in the MAT, self-consumption, reserved to compensate future penalties or at the spot market; or (iii) 20% of the energy generated to be remunerated at a price equal to U.S.$ 20/MWh for a 180-month term and the remaining 80% to be sold either in the MAT, self-consumption, reserved to compensate future penalties or at the spot market. As of today, PEA is the only asset with a PPA under the RenovAr regime. MATER ME&M Resolution No. 281/17 issued on August 18, 2017 regulated the MATER regime, which set the conditions for WEM GU and GUDI to meet their demand supply obligation from renewable sources through the individual purchase within the MATER or through self-generation from renewable sources. Furthermore, this Resolution regulates the conditions applicable to renewable power generation projects. Specifically, it created the RENPER, where such projects will be registered. Projects destined to supply the MATER may not be committed under other remuneration mechanisms (e.g., the RenovAr program). Surplus energy exceeding commitments with CAMMESA are remunerated until 10% of the generation at the minimum price for the technology covered by the RenovAr Program, and the balance, at the remuneration value for that type of technology set in SEE Resolution No. 19/17. Furthermore, agreements executed under the MATER regime will be administered and managed in accordance with the WEM procedures. The contractual terms term, allocation priorities, prices and other conditions, notwithstanding the maximum price set forth in Section 9 of Law No. 27,191, may be freely agreed between the parties, although the committed electricity volumes will be limited by the power from renewable sources produced by the generator or supplied by other generators or suppliers with which it has purchase agreements in place. We registered the PEPE II, III, IV and VI projects with the RENPER. We also requested the corresponding priority dispatch which was subsequently granted. However, it is worth highlighting that SE Resolution No. 14/22, issued in January 2022, modified the tie-breaking criteria when there is more than one project requesting dispatch priority and the relevant corridor does not have enough transport capacity. The new scheme replaced the original criteria (term, use factor and draw), and instead requires a multiplying factor to be applied on the amounts to be paid to reserve such dispatch priority as established in SE Resolution No. 551/21. SE Resolution No. 551/21 replaced the guarantee grant to reserve dispatch priority for a scheme in which payments are made according to the extension of time and the completion of the work. During the committed term a U.S.$500/MW quarterly payment applies. In case of an extension for an additional 180 calendar days with work completed by least 60% the payments will continue to be quarterly and for a U.S.$500/MW amount. If the work is completed by less than 60% the payments will be monthly. For an extra extension of 360 calendar days the payments will raise to U.S.$1500/MW monthly. In May 2023, SE Resolution 360/23 introduced reforms to the regime for granting Dispatch Priority, with key highlights including: (i) projects of the GENREN Program can participate in the MATER Regime once their contracts are finalized; (ii) the assignment of dispatch priority to joint projects of incremental demand with new renewable generation as from 10MW is allowed; (iii) projects with partial qualification will pay a dispatch priority charge only for the difference between the assigned and qualified power as long as the qualified power is greater than 50% of the assigned power; (iv) possibility of granting Dispatch Priority called “Referential type A” in corridors without full availability in all hours of the year; and (v) projects with enabled power above their dispatch priority may adhere to the regime to be included in the allocation for the difference. 110 Table of Contents Under these regulations, the following projects are remunerated: PEPE II, III (53.2 MW each), IV (81 MW) and PEPE VI (140 MW). The energy produced is marketed through PPAs in U.S.$-linked contracts with private parties, with a weighted average term of approximately 5 years. The energy not commercialized under PPAs with Large User will be sold to the Spot Market under SE Resolution No. 400/25. In addition to its own generation, Pampa commercializes renewable energy generated by third parties, with the volume in 2025 averaging 10.9 GWh, contributing to the margin in the MATER segment. WEM Agents payments to CAMMESA SRRYME Resolution No. 29/19 relaxed the charges and interest rates applicable to WEM agent in default with CAMMESA. i. Punitive charges: to those WEM agents with no outstanding balance against CAMMESA in the last three months, the charge for default will be equal to 1% of the debt for each day with a cap. ii. Default Interests rates: If the WEM agent have duly paid the last three payments to CAMMESA prior to the month in default, no punitive charges shall apply and the interest rate shall be equal to that fixed by Banco de la Nación Argentina for its 30-day discount operations, provided that the payment is made within 15 days from its due date. iii. Compensation: in the case of delays not exceeding 5 days in a certain month, compensations without the application of compensatory interest are allowed by advancing the payment of the following invoice by 2 days per day of delay. iv. Charges reduction extension: SRRYME Resolution No. 29/19 extended the 50% reduction in the charges applicable to WEM agents with outstanding debt against CAMMESA until April 30, 2020. SE Resolution No. 148/20 extended the application of SRRYME Resolution No. 29/19 until December 31, 2020. Additionally, on April 8, 2020, the SE instructed CAMMESA to implement an extraordinary payment mechanism for WEM agents affected by the Covid-19 related quarantine. According to such mechanisms, WEM agents may partially cancel their energy supply according to the impact on their sales and postpone the payment of the remaining balance for a period between 15 days to 6 months. Such amounts shall not accrue charges nor interest. This mechanism applies to the energy supplies due from April 1, 2020 to 60 days after the abrogation of the Covid-19 isolation. During 2020, there was no adjustment to the prices set forth in SE Resolution No. 31/20. Moreover, Law No. 27,591 and SE Resolution No. 40/20 defined a scheme according to which the Argentine Government will cover up to 66% of the distributors’ debt to CAMMESA. The remaining amounts will be cancelled in 60 monthly installments with a 6-months grace period and a reduced interest rate (50% of the WEM’s interest rate). In order to apply for such scheme, the distributor, together with its relevant regulatory body, shall execute an agreement with the SE in which, among other obligations, it shall guarantee a scheme that allows the distributor to regularly pay the amounts due to CAMMESA in 2021 and provide adequate guarantees (e.g., assignment of the amounts owed to the distributor by its clients). In case the distributor has no debt, or if it is “reasonable”, then credits will be recognized. Such credits might be designated for infrastructure investments or widening the distribution network, among other examples. These distributors shall regularly pay the amounts due to CAMMESA. The credits to be recognized under both schemes will be funded by loans from the Unified Fund to the Stabilization Fund, but given that such fund is deficient, it is expected to be covered by transfers from the Argentine Government. However, these schemes tend to regularize the energy sector cash flow. On March 13, 2025, by means of DNU No. 186/25 a special regime to allow electricity distributors to regularize their accumulated debt by November 30, 2024 was established. The plan also provides a special credit regime for those distributors that, by December 31, 2023, do not have any unregulated debt with CAMMESA and who have cancelled all transactions for 2024, under the conditions established by the regulations. Regulations to this DNU is yet to be issued. 111 Table of Contents