FORM 20-F

Year ended December 31,

Average price of sale for barrel of Oil and for million cubic feet of Gas

Argentina

Oil (In U.S.$ per barrel of Oil)

Gas (In U.S.$ per thousand cubic feet)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 20-F

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

Commission File Number: 001-34429

PAMPA ENERGíA S.A.

(Exact name of registrant as specified in its charter)

Pampa Energy Inc.

(Translation of registrant’s name into English)

Argentina

(Jurisdiction of incorporation or organization)

Maipú 1

C1084ABA, City of Buenos Aires

Argentina

(Address of principal executive offices)

María Carolina Sigwald

Maipú 1

C1084ABA, City of Buenos Aires

Argentina

Tel.: + 54 11 4344 6000 / Fax: + 54 11 4344 6473

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange
on which registered

Common Stock

American Depositary Shares, each representing

25 shares of common stock, par value Ps.1.00 per share

PAM

New York Stock Exchange*

New York Stock Exchange

* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

1,359,606,137 outstanding shares of common stock, par value Ps.1.00 per share, excluding 3,914,243 treasury shares, as of December 31, 2025.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

☒ Yes

☐ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

☐ Yes

☒ No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

☒ Yes

☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

☒ Yes

☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☒	Accelerated Filer	☐
Non-Accelerated Filer	☐	Emerging Growth Company	☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (§ 15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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

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

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐

International Financial Reporting Standards as issued by the International Accounting Standards Board ☒

Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

☐ Item 17

☐ Item 18

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐ Yes

☒ No

TABLE OF CONTENTS

Item 1. Identity of Directors, Senior Management and Advisers	6
Item 2. Offer Statistics and Expected Timetable	6
Item 3. Key Information	6
Exchange Rates	6
Risk Factors	7
Item 4. Information on the Company	40
History and Development of the Company	40
Our Business	41
Organizational structure	45
Our Oil and Gas Business	46
Our Generation Business	56
Our Petrochemicals Business	61
Our Holding and Other Business	62
Quality, Health, Safety and Environment	69
Corporate Responsibility	70
Property, Plant and Equipment	72
Insurance	72
Patents and Trademarks	72
The Argentine Energy Sector	73
Oil & Gas Regulatory Framework	73
Electricity Regulatory Framework	87
Item 4A. Unresolved Staff Comments	112
Item 5. Operating and Financial Review and Prospects	112
Item 6. Directors, Senior Management and Employees	136
Item 7. Major Shareholders and Related Party Transactions	148
Item 8. Financial Information	150
Consolidated Financial Statements	150
Legal Proceedings	150
Dividends	153
Significant Changes	153
Item 9. The Offer and Listing	153
Trading History	153
The Argentine Securities Market	155
Item 10. Additional Information	160
Memorandum and Articles of Association	160
Material Contracts	167
Exchange Controls	167
Taxation	171
Documents on Display	179
Item 11. Quantitative and Qualitative Disclosures about Market Risk	180
Item 12. Description of Securities Other than Equity Securities	180
Item 13. Defaults, Dividend Arrearages and Delinquencies	182
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds	182
Item 15. Controls and Procedures	182

Item 16A. Audit Committee Financial Expert	183
Item 16B. Code of Ethics	183
Item 16C. Principal Accountant Fees and Services	183
Item 16D. Exemptions from the Listing Standards for Audit Committees	184
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers	184
Item 16F. Change in Registrant’s Certifying Accountant	184
Item 16G. Corporate Governance	184
Item 16H. Mine Safety Disclosure	189
Item 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.	189
Item 16J. Insider Trading Policies.	189
Item 16K. Cybersecurity.	189
Item 17. Financial Statements	191
Item 18. Financial Statements	191
Item 19. Exhibits	191

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PRESENTATION OF INFORMATION

This document comprises Pampa’s annual report on Form 20-F for the year ended December 31, 2025. This annual report was approved by our Board of Directors by resolution following its meeting held on April 8, 2026. In this annual report, we use the terms “we”, “us”, “our”, “registrant” and the “Company” to refer to Pampa and its subsidiaries.

Financial Information

This annual report contains our audited consolidated statements of financial position as of December 31, 2025 and 2024, and the related consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, and the notes thereto (the “Consolidated Financial Statements”).

Our Consolidated Financial Statements are set forth in Item 18 beginning on page F-1 of this annual report. Our Consolidated Financial Statements are prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board (the “IASB”). The Consolidated Financial Statements included in this annual report have been approved by resolution of the Board of Directors’ meeting of the Company held on March 2, 2026 and by the Shareholder’s meeting held on April 7, 2026.

The Consolidated Financial Statements have been audited by Price Waterhouse & Co. S.R.L., an independent registered public accounting firm in Buenos Aires, Argentina whose report is included in this annual report.

Consistent with Item 18 of Form 20-F, we provide the disclosure required under Accounting Standards Codification (“ASC”) 932 of the Financial Accounting Standards Board (the “FASB”) relating to extractive activities—Oil and Gas (formerly, FASB Statement of Financial Accounting Standards No. 69—Disclosures about Oil and Gas Producing Activities) (“ASC Topic 932”), as is required regardless of the basis of accounting on which we prepare our financial statements.

Functional and Presentation Currency

The information included in the Consolidated Financial Statements has been recorded in the functional currency of the Company, which is the currency of the primary economic environment in which the Company operates. The Company’s functional currency is U.S. Dollars, which is also the presentation currency.

The results and financial position of subsidiaries, joint ventures and associates that have a different functional currency have been translated into the Company’s functional currency and the results from the translation process have been recognized in “Other Comprehensive Income (loss)”. For more information, see Note 4.3 to our Consolidated Financial Statements.

Rounding

Certain figures included in this annual report (including percentage amounts) have been subject to rounding adjustments. Accordingly, certain totals may not precisely equal the sum of the numbers presented.

PRESENTATION OF INFORMATION CONCERNING RESERVES

The proved hydrocarbon reserves included in this report for the year ended December 31, 2025, are those that we have the right to extract and sell based on assignments granted to us by the respective governmental authorities.

The estimates of our remaining proved recoverable oil and gas reserve volumes for the five years ended December 31, 2025 included in this report have been calculated according to the technical definitions required by the U.S. Securities and Exchange Commission. GaffneyCline conducted reserves audits of our estimates of our proved reserves as of December 31, 2025. All reserves estimates involve some degree of uncertainty. For a description of the risks relating to reserves and reserves estimates, see “Item 3. Key Information -Risk Factors -Risk Relating to our Oil and Gas Business - Unless we replace our oil and gas reserves, such reserves and production will decline over time,” “Our estimated oil and gas reserves are based on assumptions that may prove inaccurate” and “We face significant competition in the acquisition of exploratory acreage and oil and natural gas reserves.”

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FORWARD-LOOKING STATEMENTS

This annual report contains estimates and forward-looking statements, principally in “Item 3. Key Information - Risk Factors,” “Item 4. Our Business” and “Item 5. Operating and Financial Review and Prospects.” Some of the matters discussed herein concerning our business operations and financial performance include estimates and forward-looking statements within the meaning of the U.S. Securities Act of 1933, as amended (the “Securities Act”) and the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends that affect or may affect our business and results of operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us.

Our estimates and forward-looking statements may be influenced by the following factors, among others:

general economic, business, social and political conditions in Argentina, and any possible changes and/or deterioration in such conditions, and other regions where we, our associates or joint ventures operate, such as the rate of economic growth, fluctuations in exchange rates of the Peso or high inflation rates and their impact on our costs;

government interventions, resulting in changes in the economy, taxes, tariffs, the regulatory framework or environmental matters, or in the delay or withholding of governmental approvals;

the policies of the current administration in Argentina, including its ability to foster economic growth, implement business-friendly policies and facilitate access to foreign capital by Argentine companies;

the failure of governmental authorities to approve proposed measures or transactions described in this annual report;

changes in the laws and regulations applicable to the energy sector in Argentina;

uncertainties relating to future government approvals or legal actions, such as provisional remedies, that could affect our tariffs;

the availability of financing at reasonable terms to Argentine companies, such as us;

export limitations to our production;

import restrictions on consumables that are key for the maintenance of our assets;

more severe restrictions on the ability to exchange Pesos into foreign currencies or to transfer funds abroad;

the effect of steep local currency depreciation or volatility on our Peso-denominated revenues;

international and regional geopolitical developments, including but not limited to armed conflicts, acts of terrorism or civil unrest;

changes in the price of hydrocarbons and their derivatives;

competition in the hydrocarbon sector and related industries;

changes in the price of electricity and other related services;

electricity shortages;

competition in the electricity sector, public utility services and related industries;

cybersecurity events, including potential cyberattacks;

climate change and severe weather events;

obsolescence of products manufactured in our petrochemical facilities;

the volume of crude oil, natural gas and derivatives we produce and sell;

our ability to renew certain concessions, acquire or be awarded new concessions;

the ability to develop and monetize conventional and unconventional reserves;

our ability to develop our expansion projects and to win awards for new potential projects;

changes to our reserves estimates;

tariff updates;

sanctions, trade restrictions or market disruptions;

changes to our capital expenditure plans; and

other risk factors discussed under “Item 3. Key Information - Risk Factors.”

The words “believe”, “may”, “will”, “aim”, “estimate”, “continue”, “anticipate”, “intend”, “expect” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and we undertake no obligation to update or to renew any estimates and/or forward-looking statements because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. Our future results may differ materially from those expressed in these estimates and forward-looking statements. In light of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this annual report might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to factors including, but not limited to, those mentioned above.

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GLOSSARY

Glossary of certain terms used in this Annual Report

Unless the context indicates otherwise, the following terms have the meanings shown below:

“A3”: A3 Mercados S.A. (former Mercado Abierto Electrónico S.A. – MAE)

“ADEERA”: Asociación de Distribuidores de Energía Eléctrica de la República Argentina;

“ADR”: American Depositary Receipt;

“ADS” or “ADSs”: American Depositary Shares;

“AGEERA”: Asociación de Generadores de Energía Eléctrica de la República Argentina;

“AGUERA”: Asociación Grandes Usuarios de Energía Eléctrica de la República Argentina;

“ANSES”: National Social Security Agency (Administración Nacional de la Seguridad Social);

“Anti-Money Laundering Law”: Law No. 25,246, subsequently amended by, among others, Laws No. 26,087, 26,119, 26,268, 26,683, 26,733, 26,734 and Decree No. 27/18;

“ARCA” Federal Tax and Customs Authority (Agencia de Recaudación y Control Aduanero, former Administración Federal de Ingresos Públicos -AFIP-);

“ATEERA”: Asociación de Transportistas de Energía Eléctrica de la República Argentina;

“Authorized Markets”: securities markets in Argentina that require authorization from the CNV to operate;

“Banco Nación”: Banco de la Nación Argentina;

“BASE”: Buenos Aires Stock Exchange;

“Bases Law”: Law No. 27,742 (Ley de Bases y Puntos de Partida para la Libertad de los Argentinos)

“bbl”: Barrel of crude oil;

“BCRA” or “Central Bank”: Central Bank of the Republic of Argentina (Banco Central de la República Argentina);

“Board of Directors”: the board of directors of Pampa Energía S.A.;

“boe”: Barrel of oil equivalent;

“ByMA”: Argentine stock exchange and markets (Bolsas y Mercados Argentinos S.A.);

“Caja de Valores”: Caja de Valores S.A.;

“CAMMESA”: Wholesale Electric Market Administration Company (Compañía Administradora del Mercado Eléctrico Mayorista Sociedad Anónima);

“CC”: Combined Cycle;

“CENCH”: unconventional hydrocarbon exploitation concession;

“CIESA” Compañía de Inversiones de Energía;

“CISA”: Comercializadora e Inversora S.A.;

“CITELEC” Compañía Inversora en Transmisión Eléctrica Citelec S.A.;

“CML”: Capital Markets Law No. 26,831, as amended by, among others, Law No. 27,440;

“CNG”: compressed natural gas;

“CNV”: Comisión Nacional de Valores;

“Corporate Criminal Liability Law”: Corporate Criminal Liability Law No. 27,401;

“CPB”: Central Piedra Buena S.A. or “Central Térmica Piedra Buena”;

“CPI”: Consumer Prices Index;

“CSJN”: Corte Suprema de Justicia de la Nación;

“CTB”: CT Barragán S.A.;

“CTEB”: Central Térmica Ensenada de Barragán;

“CTG”: Central Térmica Güemes;

“CTIW”: Central Térmica Ingeniero White;

“CTGEBA” or “Genelba”: Central Térmica Genelba;

“CTLL”: Central Térmica Loma La Lata S.A. or “Central Térmica Loma La Lata”;

“CTP”: Central Térmica Piquirenda;

“CTPP”: Central Térmica Parque Pilar;

“DNU”: Necessity and Urgency Decree (Decreto de Necesidad y Urgencia);

“DoP”: delivery or pay;

“Edenor”: Empresa Distribuidora y Comercializadora Norte S.A.;

“Edesur”: Empresa Distribuidora Sur S.A.;

“EMESA”: Empresa Mendocina de Energía Sociedad Anónima;

“ENARSA”: Energía Argentina S.A. (former Integración Energética Argentina S.A.);

“ENARGAS”: Ente Nacional Regulador del Gas or National Gas Regulatory Entity;

“Energy Plus” or “Energía Plus”: a program under SE Resolution No. 1,281/2006;

“Energy Secretariat” or “SE”: Secretariat of Energy (Secretaría de Energía);

“ENRE”: Ente Nacional Regulador de la Electricidad or Electricity Regulatory Entity;

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“Exchange Act”: United States Securities Exchange Act of 1934, as amended;

“FO or GO”: Fuel Oil or Gas Oil;

“FODER”: Fondo para el Desarrollo de Energía Renovables;

“FONINVEMEM”: Fund for Investments required to increase the Power Supply in the Electricity Wholesale Market (Fondo Para Inversiones Necesarias que Permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista);

“Foundation”: Fundación Pampa Energía S.A;

“GaffneyCline”: Gaffney, Cline & Associates;

“GDP”: Gross Domestic Product;

“GHG” Greenhouse gas;

“GO and FO”: natural gas or liquid fuels;

“GPM”: Perito Francisco Pascasio Moreno Pipeline (former Nestor Kirchner Pipeline);

“G&P”: Gas y Petróleo de Neuquén S.A.;

“GT”: gas turbine;

“GU”: Large Users (Grandes Usuarios);

“GUDI”: Major Distribution Users (Grandes Usuarios del Distribuidor);

“GUMA”: Major Large Users (Grandes Usuarios Mayores);

“GUME”: Minor Large Users (Grandes Usuarios Menores);

“GWh”: Gigawatt-Hour;

“HIDISA”: Hidroeléctrica Diamante S.A.;

“HINISA”: Hidroeléctrica Los Nihuiles S.A.;

“HMRT”: hours with a high thermal demand;

“HPPL”: Pichi Picún Leufú Hydroelectric Complex;

“Hydrocarbons Law”: Law No. 17,319 as amended by Law No. 27,007;

“IGJ”: City of Buenos Aires’s Public Registry of Commerce (Inspección General de Justicia);

“IMF”: International Monetary Fund;

“INDEC”: National Statistics and Census Institute (Instituto Nacional de Estadística y Censos);

“Independent Reserves Engineers Firm”: GaffneyCline;

“IPIM”: Wholesale Domestic Price Index (Índice de Precios Internos al por Mayor);

“J.P. Morgan”: JPMorgan Chase Bank, N.A;

“LGS”: Business Corporation Law;

“LNG”: liquefied natural gas;

“LPG”: liquefied petroleum gas;

“MAT”: Term Market (Mercado a Término);

“MATER”: Renewable Energy Term Market;

“MBTU”: millions of British Thermal Units (BTU);

“MDP”: Ministry of Productive Development (former SGE);

“ME&M”: Ministry of Energy and Mining;

“MLC”: Free Exchange Market (Mercado Libre de Cambios);

“MW”: Megawatt;

“MWh”: Megawatt-Hour

“National CPI”: a CPI which is based on a survey conducted by the INDEC and several provincial statistical offices in 39 urban areas including each of Argentina’s provinces;

“NYSE”: New York Stock Exchange;

“OCP Ltd.”: Oleoducto de Crudos Pesados Ltd.;

“OCP S.A.”: Oleoducto de Crudos Pesados Ecuador S.A.

“Official Gazette”: Official Gazette of Argentina (Boletín Oficial de la República Argentina);

“Oldelval”: Oleoductos del Valle S.A.;

“Pampa” or “the Company”: Pampa Energía S.A.;

“Pampa Bloque18”: Pampa Bloque18 S.A.S.;

“Pampa Group”: Pampa and its subsidiaries;

“PEA”: Parque Eólico Arauco II;

“PEB”: Pampa Energía Bolivia S.A.;

“PEMC”: Parque Eólico Ingeniero Mario Cebreiro;

“PEN”: National Executive Branch (Poder Ejecutivo Nacional);

“PEPE II”: Parque Eólico Pampa Energía II;

“PEPE III”: Parque Eólico Pampa Energía III;

“PEPE IV”: Parque Eólico Pampa Energía IV;

“PEPE VI”: Parque Eólico Pampa Energía VI;

“Pesos” or “Ps.”: Argentine Pesos;

“Petrobras”: Petroleo Brasileiro S.A.;

“Petrobras Argentina”: Petrobras Argentina S.A.;

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“Petrolera Pampa”: Petrolera Pampa S.A.;

“PGSM”: Puerto General San Martin;

“PIST”: Transportation System Entry Point or natural gas price at the wellhead (Punto de Ingreso al de Sistema de Transporte);

“Plan Gas.Ar”: the Plan to Promote Argentine Natural Gas Production;

“Polisur”: PBB Polisur S.A;

“PPA” or “PPAs”: relevant wholesale electricity supply agreements or power purchase agreements (Contratos de Abastecimiento Mayorista de Electricidad);

“PROCELAC”: Procuraduría de Criminalidad Económica y Lavado de Activos;

“Public Emergency Law”: Law No. 25,561 – the Public Emergency and Exchange Rate Regime Reform Law;

“QHSE”: Quality, Health, Safety and Environment;

“Refinor”: Refinería del Norte S.A.;

“RENPER”: National Registry of Renewable Source Electric Power Generation Projects (Registro de Proyectos de Generación de Energía Eléctrica de Fuente Renovable);

“Reserves Report”: the year-end reserves report by GaffneyCline;

“RTI”: Revisión Tarifaria Integral (Comprehensive Tariff Review);

“SACDE”: Sociedad Argentina de Construcción y Desarrollo Estratégico S.A.;

“SADI”: the Argentine Electricity Interconnected Grid (Sistema Argentino de Interconexión);

“SBR”: styrene butadiene rubber;

“SEC”: U.S. Securities and Exchange Commission;

“Securities Act”: U.S. Securities Act of 1933, as amended;

“SEE”: Subsecretariat of Electric Energy, former Secretariat of Electric Energy (Subsecretaría de Energía Eléctrica);

“SESA”: Southern Energy S.A.

“SGE”: Former Government Secretariat of Energy (former Secretaría de Gobierno de Energía) (former Ministry of Energy (former ME&M));

“SHC”: Undersecretary of Hydrocarbons and Fuels (Subsecretaría de Recursos Hidrocarburíferos (former Secretaría de Recursos Hidrocarburíferos));

“Social Solidarity and Productive Reactivation Law”: Law No. 27,541;

“SRRYME”: Secretary of Renewable Resources and Electricity Market (Secretaría de Recursos Renovables y Mercado Eléctrico);

“ST”: steam turbine;

“TGS”: Transportadora de Gas del Sur S.A.;

“TJSM”: Termoeléctrica José de San Martín S.A.;

“TMB”: Termoeléctrica Manuel Belgrano S.A.;

“ToP”: take or pay;

“Transba”: Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires Transba S.A.;

“Transener”: Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.;

“UIF”: Financial Information Unit (Unidad de Información Financiera);

“U.S.”: United States of America;

“U.S.$ and/ or U.S. Dollars”: U.S. currency;

“UT” or “UTs”: joint operations (Unión Transitoria);

“VAR”: Vientos de Arauco Renovables S.A.U.;

“VAT”: Value Added Tax;

“VMOS”: VMOS S.A.

“WEM”: Wholesale Electricity Market;

“WEM Large Users”: WEM users with a capacity higher than 300 KW;

“YPF”: YPF S.A.

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Item 1.

Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.

Offer Statistics and Expected Timetable

Not applicable.

Item 3.

Key Information

EXCHANGE RATES

Exchange Rates

The following table sets forth the high, low, average and period-end exchange rates for the periods indicated, expressed in Pesos per U.S. Dollar and not adjusted for inflation. There can be no assurance that the Peso will not depreciate or appreciate again in the future. The Federal Reserve Bank of New York does not report a noon buying rate for Pesos.

	*Exchange rates⁽¹⁾*
	*(in Pesos per U.S. Dollars)*
	*High*	*Low*	*Average⁽²⁾*	*Period end*
Year ended December 31,
2021	102.720	84.700	95.161	102.720
2022	177.160	103.000	130.810	177.160
2023	808.450	178.150	295.295	808.450
2024	1,032.000	810.700	916.164	1,032.000
2025	1,492.000	1,032.500	1,245.024	1,455.000


Month
January 2026	1,475.000	1,429.500	1,448.952	1,447.000
February 2026	1,451.000	1,370.500	1,408.389	1,397.000
March 2026	1,416.000	1,368.000	1,395.950	1,382.000
April 2026⁽³⁾	1,394.000	1,387.500	1,391.750	1,387.500

Source: Banco Nación

(1)

Represents the average of exchange rates on the last day of each month during the period.

(2)

Average of the lowest and highest daily rates in the month.

(3)

Represents the average of the lowest and highest daily rates from April 1 through April 8, 2026.

Pursuant to Argentine law, in the case that we pay dividends, we are required to determine the amount in Pesos. Exchange rate fluctuations will affect the U.S. Dollar amounts received by holders of American Depositary Shares, on conversion by us or by the depositary of cash dividends on the shares represented by such ADSs. Fluctuations in the exchange rate between the Peso and the U.S. Dollar will affect the U.S. Dollar equivalent of the Peso price of our shares on the BASE and, as a result, can also affect the market price of our ADSs.

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RISK FACTORS

The following summarizes some, but not all, of the risks provided below. Please carefully consider all of the information discussed in this Item 3.D. “Risk Factors” in this annual report for a more thorough description of these and other risks:

Risks Related to Argentina

Our business, operational results and financial condition depend on economic and political conditions in Argentina, which remain vulnerable

The Argentine Government’s economic expectations may not materialize and the process of restoring confidence in the Argentine economy may take longer than anticipated

The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate

Recent political developments in Argentina could affect macroeconomic, regulatory and social conditions in the country

Exchange rate volatility may adversely affect the Argentine economy

Inflation could adversely affect the Argentine economy and our operational results

The interruption of the publication of Argentine economic indexes or changes in their calculation methodologies could affect the projections made by the Company

Argentina’s ability to obtain financing from international markets could be limited, which may impair its ability to implement reforms and foster economic growth

Argentine corporations may be restricted from making payments in foreign currencies or from importing certain products

Argentine public expenditure may generate negative consequences for the Argentine economy

Failure to adequately address actual and perceived risks of institutional deterioration and corruption may adversely affect Argentina’s economy and financial condition

Our operating costs could increase as a result of the promotion or adoption of certain measures by the Argentine Government as well as pressure from union sectors

External shocks and “contagion” effects could have an adverse effect on the Argentine economy

The Argentine economy and finances may be adversely affected by declines in international commodity prices or in the production levels of commodities

Any downgrade in Argentina’s and/or Pampa’s credit rating or rating outlook could adversely affect both the rating and the market price of the Company’s ADSs and shares

Risks Related to our Company

We operate a material portion of our business pursuant to public concessions granted by provincial and national governments, which may not be renewed, or may be revoked or terminated, and whose economic and other conditions may change

Our performance is largely dependent on recruiting and retaining key personnel

We employ a largely unionized labor force and could be subject to organized labor action, including work stoppages

We could be subject to accidents or other events that may not be covered by our insurance policies

We conduct a portion of our operations through joint ventures and co-controlled companies, and our failure to continue such joint ventures and co-controlled companies or to settle any potential material disagreements with our partners could have a material adverse effect on the success of these operations

Our derivative risk management activities could result in financial losses

We may not be able to effectively hedge our currency risk in full regarding a devaluation of the Argentine Peso

We are or could be involved in various legal proceedings which could result in unfavorable rulings against us

Cybersecurity events, including cyber-attacks, could adversely affect our business, financial condition, operational results and cash flows

Our operations could cause environmental risks and any change in environmental laws could increase our operating costs

We may be unable to collect payments of amounts due, or to collect them in a timely manner, from CAMMESA, ENARSA, the Argentine Government and other customers

Certain of our outstanding financial indebtedness includes bankruptcy, reorganization proceedings and expropriation events of default and we may be required to repay all of our outstanding debt upon the occurrence of any such events

Covenants in our indebtedness could adversely restrict our financial and operating flexibility

Natural disasters, pandemics, catastrophic events, terrorist attacks and operational failures could disrupt our assets and impair our ability to fulfill contractual commitments

Our activities may be adversely affected by events in other countries in which we do business

We continue evaluating investment projects to expand our activity, which could entail an increase in our indebtedness and additional costs

Climate change, energy transition and regulatory framework promoted for such purposes could affect our business, our results of operations and financial condition

Guarantees that we granted to third parties could be enforced

Risks Related to Our Business

Risks Related to our Oil and Gas Business

Oil and gas companies have been affected by certain measures taken by the Argentine Government and may be further affected by additional changes in their regulatory framework

Argentine oil and gas production concessions and exploration permits are subject to certain conditions and may not be renewed or could be revoked or their terms and economic conditions may be modified

Substantial or extended declines and volatility in the prices of crude oil, oil products and natural gas may have an adverse effect on our operational results and financial condition

Export duties and import regulations on our products negatively affected the profitability of our operations

Oil and gas prices and sale conditions could affect our level of capital expenditures

Limits on exports and imports of hydrocarbons and related oil products, including the imposition of export duties, other taxes and import regulations, have affected and may continue to affect our operational results

We conduct most of our oil and gas operations through joint arrangements (joint operations for accounting purposes) in which we may not always act as operators. Our inability to maintain or resolve disagreements with our partners within such joint agreements could materially affect the success of their operations

Our failure to comply with our investment commitments could negatively affect our operational results

Oil and gas activities are subject to significant economic, environmental and operational risks

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Our oil and gas activities are substantially dependent upon the availability of water and our ability to dispose of produced water gathered from drilling and production activities. Restrictions on our ability to obtain water or dispose of produced water may have a material adverse effect on our operations

Unless we replace our oil and gas reserves, such reserves and production will decline over time

Our estimated oil and gas reserves are based on assumptions that may prove inaccurate

We face significant competition in the acquisition of exploratory acreage and oil and natural gas reserves

We may incur significant costs and liabilities related to environmental, social, health and safety matters

Limitations on local pricing in Argentina may adversely affect our operational results

We are exposed to contractions in the crude oil and natural gas demand and to contractions in the demand for any of their by-products

Risks Related to Our Generation Business

· Government intervention in the electricity sector may have an impact on our business operations, financial condition and/or results of operations

We could be adversely affected by limited electricity transmission and distribution capacity or sudden increases or decreases in energy demand in the short or medium term

Our power generation plants may be subject to new regulations that require additional investments or adversely affect their dispatch

Measures encouraging renewable and nuclear energy generation projects may affect our generation sales

Our ability to generate electricity in our thermal generation plants depends on the availability and price of natural gas (and other fuels), and any disruption to our fuel supply or the regulatory framework governing its procurement could materially adversely affect our operational results

We may be subject to penalties under our energy supply agreements with CAMMESA and/or WEM Large Users

We may be subject to sanctions for breaches of applicable regulations or for failing to obtain the required permits and authorizations for our operating or new power generation units

Revenues from our renewable generation assets depend on meteorological and hydrological conditions, as well as on our ability to contract the energy produced and maintain applicable dispatch priorities

Operational difficulties could limit our ability to generate electricity, which could adversely affect our operational results

We may face extra costs due to the termination of the concession agreements for HINISA, HIDISA and/or HPPL

We could be exposed to third-party claims on real property where CPB is located that could result in the imposition of significant damages, for which we have not established a provision in our consolidated financial statements for potential losses

The national antitrust authorities could decide not to approve the acquisition of the CTEB

Our profits may be affected by the cancellation of the Energy Plus Program

Our energy projects may not perform as expected

We may face competition in the electricity sector and related industries

Risks arise for our business from technological changes in the energy market

Our suppliers may not be able to provide spare parts and/or upgrades to our generation units

Our PPAs may not be renewed, or they could be unilaterally modified, terminated or otherwise affected by measures adopted by the Argentine Government related to the PPAs or the energy sector in general, or we may not be able to enter into new PPAs

The generation activity involves the handling of dangerous elements such as fuels that have an associated potential risk for premises and people

Risks Related to our Shares and ADSs

Restrictions on the movement of capital out of Argentina may impair the ability of holders of ADSs to receive dividends and distributions and the proceeds of any sale of the shares underlying the ADSs, which could affect the market value of the ADSs

ADS holders’ ability to receive cash dividends may be limited

Under Argentine law, shareholder rights may be fewer or less well-defined than in other jurisdictions

Holders of ADSs may be unable to exercise voting rights with respect to the common shares underlying the ADSs at our shareholders’ meetings

Our shareholders may be subject to liability for certain votes of their securities

Provisions of our bylaws and of Argentine securities laws could deter takeover attempts and have an adverse impact on the price of our shares and the ADSs

There can be no assurance that we will not be a passive foreign investment company, or PFIC, for U.S. federal income tax purposes for any taxable year, which could subject U.S. holders of our shares or ADSs to adverse U.S. federal income tax consequences

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Risks Related to Argentina

Overview

We are a stock corporation (sociedad anónima) incorporated under the laws of the Republic of Argentina; most of our revenues are earned in Argentina and most of our operations, facilities and customers are located in Argentina. Our financial condition and operational results depend to a significant extent on macroeconomic, regulatory, political and financial conditions prevailing in Argentina, including, among others, growth rates, inflation rates, currency exchange rates, interest rates and taxes. Our business is subject to the effects of other local, regional and international events and conditions that may impact Argentina in any manner. For example, a slowdown in economic growth or economic recession could lead to a decreased demand for electricity in the service areas in which we operate or a decline in the purchasing power of our customers, which, in turn, could lead to a higher delinquency rate from our customers or increased energy losses due to illegal use of our services. Actions of the Argentine Government concerning the economy, including measures with respect to inflation, interest rates, price controls (including tariffs and other compensation of utility companies), foreign exchange controls and taxes, have had and may in the future have a material adverse effect on private sector entities, including us. Our activities are highly regulated and subject to uncertainties due to political and economic factors, changes in legislation, expropriations, termination and modification of contractual rights, revocation of permits and consents, the need to obtain permits from regulatory authorities, foreign currency restrictions, price controls, currency fluctuations and increases in royalties, among others.

We cannot assure you that the Argentine Government will not adopt policies that could adversely affect the Argentine economy or our business, financial condition or operational results. In addition, we cannot assure you that future economic, regulatory, social and political developments in Argentina will not impair our business, financial condition or operational results, or cause the market value of our ADSs and common shares to decline.

Our business, operational results and financial condition depend on economic and political conditions in Argentina, which remain vulnerable

Most of our operations, facilities and customers are located in Argentina, and most of our revenues are earned in Argentina. Hence, our financial condition and operational results depend to a significant extent on macroeconomic, regulatory, political and financial conditions prevailing in Argentina.

The Argentine economy has experienced significant volatility in recent decades, characterized by periods of low or negative growth, high levels of inflation and currency devaluation. Sustainable economic growth in Argentina depends on a variety of factors including the international demand for Argentine exports, the stability and competitiveness of the Peso against foreign currencies, confidence among consumers and foreign and domestic investors, a stable rate of inflation, national employment levels and the circumstances of Argentina’s regional trade partners.

Following periods of economic volatility, Argentina’s GDP grew 4.6% in 2025, after showing signs of stabilization. The IMF expects Argentina’s economy to grow by 4.0% in 2026, supported by domestic demand, improved access to credit, declining inflation, and continued deregulation. However, we cannot guarantee that this estimate will be met.

The current Argentine administration faces significant macroeconomic challenges, such as continuing to reduce the inflation rate or maintaining it at low levels, sustaining a fiscal surplus, accumulating reserves, supporting the Peso, further eliminating exchange controls, refinancing debt owed to private creditors, and improving the competitiveness of the economy. Since taking office, the current administration has implemented a large number of measures aimed at deregulating the Argentine economy and limiting government intervention in the private sector, including trade liberalization through reduced tariff barriers, labor market modernization, easing of foreign exchange restrictions, and product market deregulation across key sectors such as oil, gas, mining, and electricity. However, there can be no assurance that these measures will be sustained or will achieve their intended objectives. As has occurred with previous reform efforts, these measures may be modified, delayed, reversed, or challenged, including through legislative action or judicial proceedings, which could adversely affect economic stability and growth.

The Argentine macroeconomic environment remains vulnerable, despite recent stabilization efforts. Although inflation has decelerated during 2025, declining from an accumulated rate of 117.8% during 2024 to an accumulated rate of 31.5% during 2025, elevated inflation levels continue to undermine confidence in the Argentine economy. Trade imbalances present further risks, as import volumes rose 30.5% year-over-year to approximately U.S.$ 75.8 billion in 2025, which may strain foreign exchange reserves and the Argentine trade balance.

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Social and labor market conditions present additional challenges. During the second semester of 2025, poverty and extreme poverty reached 28.2% and 6.3%, respectively; unemployment reached 7.5%; and the informal employment rate reached 43.0%. Protests, such as those observed in recent years, or strikes, such as the general strike of February 19, 2026, may negatively affect the stability of the political, social and economic environment and could negatively impact global financial market confidence in the Argentine economy.

The Argentine Government’s economic expectations may not materialize and the process of restoring confidence in the Argentine economy may take longer than anticipated

Argentina’s economy may be adversely affected if political and social pressures prevent the Argentine Government from implementing policies designed to control inflation, generate growth and enhance consumer and investor confidence, or if such policies once implemented fail to achieve their intended objectives. These events could materially affect our financial condition and operational results or cause the market value of our ADSs and our common shares to decline. Also, the Argentine economy could be affected by a regional or global crisis. See “External shocks and “contagion” effects could have an adverse effect on the Argentine economy”.

We cannot assure you that a decline in economic growth will not adversely affect our business, financial condition or operational results and cause the market value of our ADSs and our common shares to decline.

The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate

The Argentine Government has historically exercised significant influence over the economy, and we operate in a highly regulated environment. In the recent past, the Argentine Government has directly intervened in the economy, including through the implementation of expropriation and nationalization measures, price controls and exchange controls. Since we operate in a context in which the governing law and applicable regulations change frequently, in part as the result of changes in government administrations, it is difficult to predict if and how our activities will be affected by such changes.

Javier Milei was elected President of Argentina and took office in 2023. Once in office, President Milei announced various “shock” measures and policies designed to reform the Argentine Government and economy. Such measures included DNU No. 70/23, which initiated a comprehensive series of amendments in economic, labor, foreign trade, energy and legal policy areas, often with the goal of repealing relevant regulations. Additionally, significant adjustments were implemented in the Argentine Civil and Commercial Code, mainly focused on foreign currency obligations, as well as easing of regulation of contracts and restrictions to judicial authority in contractual intervention. Although the Argentine Senate voted to reject DNU No. 70/23 on March 14, 2024, and transmitted the measure to the Chamber of Deputies, the decree remains in effect, as the lower chamber had not, as of the date of this report, acted to reject it. The decree is also the subject of ongoing judicial challenges, including court orders suspending certain labor-related provisions. We cannot predict the ultimate outcome of these proceedings or the extent to which they may affect the decree’s scope, implementation, or continued effectiveness.

Concurrently with DNU No. 70/23, President Javier Milei submitted an “Omnibus Law” bill to Congress aimed at deregulating the economy, modernizing the state, easing labor laws, and privatizing state-owned companies. A revised version of the bill with a more limited scope was approved on June 27, 2024, enacting Law No. 27,742, known as the “Bases Law” (Ley Bases), which was implemented through extensive regulatory action during 2025. Its labor modernization provisions have been in effect since July 9, 2024. The Bases Law also established the Large Investment Incentive Regime (Régimen de Incentivo para Grandes Inversiones, or “RIGI”), which provides significant tax, customs, and regulatory incentives for qualifying investments and aims to develop investments in strategic sectors such as oil and gas, mining, renewable energies, and other strategic sectors. On February 19, 2026, the deadline to join the RIGI was extended until July 8, 2027, and new projects related to the production of liquid and gaseous hydrocarbons in greenfield blocks were incorporated into the regime. There can be no assurance that these reforms and incentives will remain in force, be fully implemented as intended, or have a positive effect on our business, financial condition, or operational results.

The current administration has also enacted Law No. 27,802, published in the Official Gazette on March 6, 2026, which substantially amends employment rules in the country, including a new mandatory employer contribution to a Labor Assistance Fund with a corresponding reduction in employers’ social security contributions, measures to simplify the rules and formalities for the registration of employment relationships, amendments to vacation policies, the possibility to agree, under certain circumstances and subject to specific conditions, to a compensatory system for overtime work, the unification of criteria regarding the calculation of certain severance payments and the updating of amounts claimed in labor judicial proceedings, and the regulation of additional aspects related to collective bargaining agreements and the right to strike. On March 30, 2026, a court ruling was issued in the context of a legal action filed against such reform, pursuant to which a preliminary injunction was granted suspending the application of certain provisions thereof. As a result, the effectiveness and/or implementation of certain aspects of the labor reform may be limited pending a final decision. As of the date of this annual report, the ultimate scope and impact of such ruling remain uncertain. We cannot assure you that Law No. 27,802 will remain in force in its current form or will not be subject to further judicial challenge, modification, or repeal.

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Additionally, President Javier Milei has implemented substantial reforms affecting the energy sector, including deregulation measures, liberalization of energy prices, and elimination of certain export controls and currency restrictions. While these policies are generally intended to attract foreign investment and stimulate development of unconventional resources such as the Vaca Muerta shale formation, the rapid pace of regulatory change creates uncertainty regarding the long-term stability of our operating environment. The full implementation and durability of these reforms remain subject to political and economic factors that could impact our operations.

On April 8, 2026, an amendment to Law No. 26,639, which governs the Regime of Minimum Budgets for the Preservation of Glaciers and the Periglacial Environment, was approved by Congress. Such amendment narrows the scope of protected zones to permit productive activities and modify the regulatory framework applicable to hydrocarbon production in certain previously restricted periglacial areas.

We cannot assure you that the reforms spearheaded by President Milei will be sustained in the long term. Argentine courts have suspended certain articles of DNU No. 70/23, particularly those related to labor matters, including subcontractor liability and the calculation of salaries, severance payments, and social security contributions. More broadly, companies operating in Argentina face risks including strikes, social unrest, mandatory amendment of existing contracts, and changes in taxation policies, including tax increases and retroactive tax claims. We cannot guarantee that the Argentine Government’s economic, regulatory, social, and political framework, or the policies or measures it adopts or may adopt, will not adversely affect the market value of our ADSs, our business, our financial condition, or our results of operations.

Recent political developments in Argentina could affect macroeconomic, regulatory and social conditions in the country

On October 26, 2025, Argentina held national midterm legislative elections to renew 127 of the 257 seats in the Chamber of Deputies and 24 of the 72 seats in the Senate. President Javier Milei’s party, La Libertad Avanza, obtained approximately 40.7% of the national vote for the Chamber of Deputies and approximately 42.0% for the Senate, while the principal opposition coalition, Fuerza Patria, obtained approximately 31.7% and 28.4%, respectively. Following the elections, President Milei implemented a cabinet reshuffle affecting the Foreign Affairs, Interior, Security, and Defense ministries.

In the immediate aftermath of the elections, Argentine financial markets reacted positively, with the Peso appreciating against the U.S. Dollar, Argentine sovereign bonds rising, and equity indices recording significant gains, reflecting improved investor confidence in the continuity of the administration’s economic reform agenda. However, there can be no assurance that these conditions will be sustained. Political or social opposition to the Argentine Government’s reform measures, adverse external developments or delays in the implementation of structural policies could reverse these trends and generate volatility in Argentine financial markets, adversely affecting access to international financing, the value of the Argentine Peso and the overall stability of the Argentine economy.

Argentina is scheduled to hold presidential and legislative elections in 2027, which could result in a change in administration and further shifts in the direction of economic and regulatory policy. We cannot assure you whether such changes will occur or, if they occur, estimate their timing or potential effects on our operations and financial condition.

Exchange rate volatility may adversely affect the Argentine economy

The Argentine Peso has been subject to significant devaluation against the U.S. Dollar in the past and may be subject to fluctuations in the future. According to the exchange rate information published by the Banco de la Nación Argentina, the Argentine Peso has depreciated 28.9%, 27.7% and 356.3% in 2025, 2024 and 2023, respectively. The Peso experienced sharp volatility during 2025, first in April when certain foreign exchange controls were lifted and the exchange rate regime was converted to a managed float system. Later, the Peso came under renewed pressure in the run-up to the 2025 midterm legislative elections.

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We cannot predict whether and to what extent the value of the Peso could depreciate or appreciate against the U.S. Dollar and the way in which any such fluctuations could affect our business. The value of the Peso compared to other currencies is dependent, in addition to other factors, on the level of international reserves maintained by the BCRA, which have also shown significant fluctuations in recent years. As of April 8, 2026, the international reserves of the BCRA totaled U.S.$ 44,750 million, reflecting recent purchases made by the BCRA in the exchange market in order to increase such reserves.

Fluctuations in the value of the Peso may also adversely affect the Argentine economy, the prices of our products, our financial condition and operational results. The devaluation of the Argentine Peso may have a negative impact on the ability of certain Argentine businesses to service their foreign currency-denominated debt, lead to high inflation, significantly reduce real wages, jeopardize the stability of businesses whose success depends on domestic market demand, including public utilities and the financial industry, and adversely affect the Argentine Government’s ability to honor its foreign debt obligations.

On the other hand, a significant appreciation of the Argentine Peso against the U.S. Dollar could also present risks for the Argentine economy, including a reduction in exports as a consequence of diminished external competitiveness, a trend that is currently affecting both export volumes and values. Any such increase could also have a negative effect on economic growth and employment, reduce the Argentine public sector’s revenues from tax collection in real terms and have a material adverse effect on our business, our operational results and our ability to repay our debt within the respective maturity dates and may affect the market value of our ADSs, as a result of the overall effects of the weakening of the Argentine economy.

Inflation could adversely affect the Argentine economy and our operational results

Historically, inflation has materially undermined the Argentine economy and the Argentine Government’s ability to create conditions that allow growth. In recent years, Argentina has confronted inflationary pressures, evidenced by significantly higher fuel, energy and food prices, among other factors.

When the current administration took office, it applied certain measures (see “The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate”) relating to the deregulation of prices for food supplies, health insurances, communications, transport, gasoline and electricity and gas tariffs, which generated additional inflationary pressure at first. However, according to data published by the INDEC, during 2024 and 2025 there was a significant deceleration of year-on-year inflation with respect to previous years. The National CPI variation was 31.5% during 2025, 117.8% during 2024, and 211.4% during 2023, continuing a multi-year deceleration trend. Notwithstanding this deceleration, inflation remains elevated.

During 2026, CPI rates for January and February were 2.9% and 2.9%, respectively. For 2026, the IMF projects an annual inflation rate of 16.4%, while private analysts surveyed in the March 2026 Market Expectations Survey (Relevamiento de Expectativas del Mercado – REM) forecast an annual inflation rate of approximately 26%. As of the date of this annual report, the Argentine Government appears to have achieved a degree of stabilization in the value of the Argentine Peso through various fiscal consolidation measures, including reductions in public expenditure and constraints on monetary financing of the fiscal deficit. Notwithstanding this progress, inflation in Argentina remains elevated by international standards, and the economy continues to operate in a transitional stabilization phase.

Any reversal or stalling of this disinflation trend could affect Argentina’s foreign competitiveness, negatively impact employment and the level of economic activity and undermine confidence in Argentina’s banking system, which may further limit the availability of domestic and international credit to businesses. These risks are compounded by the structure of Argentine sovereign debt, a portion of which continues to be adjusted by the “CER” (the Reference Stabilization Coefficient), a currency index that is strongly correlated with inflation. Therefore, any significant increase in inflation would drive a corresponding increase in Argentina’s external debt, either in whole or in part, as appropriate and, consequently, in Argentina’s financial obligations, which could exacerbate the stress on the Argentine economy. An inflationary environment could undermine our operational results, adversely affect our ability to finance the working capital needs of our businesses on favorable terms and our operational results and cause the market value of our ADSs and our common shares to decline.

There is uncertainty regarding the effectiveness of the policies implemented by the Argentine Government to control, maintain and further reduce inflation and the potential impact of those policies in the future. Argentina’s economic history demonstrates that periods of relative stability have frequently been followed by renewed inflationary episodes triggered by political transitions, external shocks, fiscal imbalances, or changes in monetary policy. We cannot assure that the inflation rate will not increase in the future or that measures taken or to be taken by the Argentine Government to control inflation will be effective in the long term. High inflation may adversely affect the Argentine economy, which in turn may have a negative impact on our financial condition and operational results.

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The interruption of the publication of Argentine economic indexes or changes in their calculation methodologies could affect the projections made by the Company

The INDEC is Argentina’s main official agency responsible for collecting, producing, and publishing nationwide statistical data, including the CPI. Historically, there have been concerns regarding the accuracy and independence of the INDEC statistics, and such concerns have periodically resurfaced.

In 2014, the INDEC established the CPI, which reflects a broad measurement of consumer prices, considering price information from the 24 provinces of the country, divided into six regions. Faced with the credibility of the CPI, as well as other indices published by the INDEC, being called into question, the Argentine Government declared a state of administrative emergency for the national statistical system and the INDEC on January 8, 2016, based on the determination that the INDEC had failed to produce reliable statistical information, particularly with respect to CPI, GDP, inflation and foreign trade data, as well as with poverty and unemployment rates. The INDEC temporarily suspended the publication of certain statistical data until the reorganization of its technical and administrative structure to recover its ability to produce reliable statistical information. In 2017, the INDEC began publishing a National CPI, which is based on a survey conducted by the INDEC and several provincial statistical offices in 39 urban areas including each of Argentina’s provinces.

In February 2026, the head of the INDEC resigned amid disagreements with the Ministry of Economy regarding the timing and criteria for implementing a new CPI calculation methodology. Although the agency has not recently faced significant public controversy over the accuracy of its data, the resignation reflected technical and policy disagreements over the methodological update. Future methodological or institutional changes could still give rise to challenges or undermine confidence in official statistics.

Any future required correction or restatement of the INDEC indexes could result in decreased confidence in Argentina’s economy, which, in turn, could have an adverse effect on our ability to access international capital markets to finance our operations and growth, and which could, in turn, adversely affect our operational results and financial condition and cause the market value of our ADSs and our common shares to decline.

Argentina’s ability to obtain financing from international markets could be limited, which may impair its ability to implement reforms and foster economic growth

Argentina has historically faced difficulties in accessing capital markets due to its history of debt restructuring and creditor litigation. Since the 2001 crisis, the country has undergone multiple restructurings, including debt swaps in 2005, 2010 and 2020, as well as agreements with the IMF in 2018, 2022 and 2025. These processes have allowed refinancing commitments but have affected investors’ confidence and macroeconomic stability. Argentina also remains subject to numerous arbitration and litigation proceedings before ICSID, UNCITRAL tribunals, and U.S. and foreign courts, arising from emergency economic measures and sovereign debt defaults. Adverse outcomes in these proceedings could result in significant monetary awards and enforcement actions, further limiting Argentina’s financial resources and access to international financing. Despite credit rating upgrades in 2025 following fiscal improvements, Argentina’s debt sustainability remains uncertain as continued multilateral financing depends on meeting fiscal and reserve accumulation targets the country has previously failed to achieve. See “Any downgrade in Argentina’s and/or Pampa’s credit rating or rating outlook could adversely affect both the rating and the market price of the Company’s ADSs and shares.”

The country has resorted to international organizations such as the IMF and the Paris Club to obtain financing, with successive revisions and disbursements conditioned on the fulfillment of fiscal and monetary goals. In this context, the current administration has continued with debt negotiations and payments. On April 8, 2025, the IMF and the Argentine Government reached a staff-level agreement on a comprehensive economic program that could be supported by a 48-month arrangement under the Extended Fund Facility (EFF) totaling U.S.$ 20 billion. The IMF’s Executive Board approved the arrangement on April 11, 2025, with an immediate disbursement of U.S.$ 12 billion. The first review, completed in July 2025, resulted in an additional disbursement of approximately U.S.$ 2 billion, though the IMF noted that net international reserves targets had been missed in mid-June 2025, with a waiver granted in August 2025.

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Alongside the IMF’s support, Argentina secured other significant bilateral and multilateral financing arrangements in 2025, including agreements reached between the BCRA and the People’s Bank of China in April 2025, as well as financing from the Inter-American Development Bank and the World Bank. Additionally, the BCRA entered into a U.S.$ 2 billion repurchase agreement with international private banks to bolster foreign currency reserves. In October 2025, the Argentine Government and the U.S. Treasury announced a U.S.$ 20 billion currency swap line financed through the Treasury Department’s Exchange Stabilization Fund (ESF).

Despite these financing arrangements, Argentina’s debt sustainability remains uncertain. The country must service over U.S.$ 45 billion in foreign debt obligations over the next three years, including more than U.S.$ 15 billion owed to the IMF. Continued access to IMF disbursements and other multilateral financing depends on Argentina’s ability to meet fiscal, monetary, and reserve accumulation targets, which the country has previously failed to achieve. Such a failure, or a deterioration in access to foreign investment and financing could hinder sustainable growth, aggravate fiscal problems and increase inflation. The difficulty in sustaining growth with price stability could lead to a new episode of economic instability, affecting both public finances and the private sector.

For private sector actors, such as us, this scenario represents higher financing costs, restrictions on access to credit and risks derived from macroeconomic volatility. Uncertainty about the Government’s ability to implement effective policies casts doubt on the stability of the business environment, affecting the private sectors’ planning and growth perspectives.

Argentine corporations may be restricted from making payments in foreign currencies or from importing certain products

Exchange controls could adversely affect our financial condition or results of operations and our ability to meet our foreign currency obligations and execute our financing plans.

Despite the substantial liberalization of restrictions on accessing the foreign exchange market for individuals, certain restrictions remain in effect for corporations in Argentina. See “Item 10. Additional Information - Exchange Controls”. These restrictions affect corporations’ ability to access the MLC to acquire foreign currency to transfer funds to other countries, service debt, make payments outside Argentina and other operations which require, in some cases, prior approval by the Central Bank. These restrictions may affect our operations and expansion projects, which require the import of equipment, services and other goods for which payment may be restricted. The Argentine Government may reimpose or create further restrictions on the access to the MLC. In such a case, our ability to make payments outside Argentina and to comply with our foreign currency obligations may be adversely affected. We cannot predict what the impact of future changes to exchange control policies would be on the Argentine economy or on our financial position.

During 2025, the Argentine Government replaced its crawling peg exchange rate regime with a floating band, under which the Peso moves freely within a range that widens monthly. It has also pursued policies aimed at currency competition, permitting transactions in Pesos, U.S. Dollars, or other currencies. The Government could further modify the exchange rate regime by creating multiple exchange rates for different types of transactions, substantially modifying the applicable exchange rate at which we acquire currency to service our outstanding foreign currency-denominated liabilities or even dollarize the economy, as Milei expressed during his presidential campaign. We cannot predict what the impact of such policy would be on the Argentine economy and our financial position if they were adopted.

Additional volatility, appreciation or depreciation of the Peso against the U.S. Dollar or reduction of the Central Bank’s reserves because of currency intervention could adversely affect the Argentine economy and our ability to service our debt obligations and could affect the value of our ADSs and our common shares. We cannot assure you that the official exchange rate will not fluctuate significantly in the future. Despite the current administration’s intention to further eliminate restrictions, there can be no assurances regarding future modifications to exchange controls or whether they will be eliminated for the short or long term. In the future, the Argentine Government may introduce new exchange controls and/or strengthen the existing ones, create restrictions on transfers to other countries, restrictions on capital movement or other measures in response to an eventual capital flight, further inflation or a significant depreciation in the Peso, measures that could, in turn, affect our ability to access the international capital markets.

We cannot predict whether, and to what extent, the value of the Argentine Peso may depreciate or appreciate against the U.S. Dollar or other foreign currencies, and how these uncertainties will affect our businesses. Existing and future measures may negatively affect Argentina’s international competitiveness, discourage foreign investments and lending by foreign investors or increasing foreign capital outflow, which could have an adverse effect on economic activity in Argentina, and which in turn could adversely affect our business and results of operations. We cannot predict how these conditions will affect our ability to meet our liabilities denominated in currencies other than the Argentine Peso. Any limitations or restrictions on transferring funds abroad imposed by the Government could undermine our ability to access international capital markets, pay dividends on our ADSs or make payments (of principal or interest) under our outstanding indebtedness in U.S. Dollars, as well as to comply with any other obligation denominated in foreign currency, to import certain products or goods that we use as inputs or affect in other ways our business and our operational results, or cause the market value of our ADSs and our common shares to decline.

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Argentine public expenditure may generate negative consequences for the Argentine economy

Public expenditure has significantly increased throughout the last decades in Argentina. In the past, the Argentine Government adopted several measures to finance its high public expenditure, including, among others, using the resources of the Central Bank and the ANSES to fund its financial needs, and implementing an expansionary monetary policy that increased inflation levels.

The current administration has implemented a significant fiscal consolidation program aimed at eliminating the fiscal deficit through reductions in public spending. Measures taken to achieve this have included (i) devaluing the Argentine Peso by 54% against the U.S. Dollar; (ii) suspending public works; (iii) reducing subsidies for energy and transportation services; (iv) halting official advertising; (v) reducing the number of ministries and secretariats; and (vi) reducing the size of the public sector workforce.

As a result of the measures taken by the current administration, in December 2025, primary expenditure in the National Public Sector fell by 0.2% year-over-year in real terms. Moreover, according to statistical information published by the Ministry of Economy, as of December 2025, Argentina achieved a primary surplus of Ps. 11,769,219 million, thus closing 2025 with a surplus of 1.4% of GDP and registering a financial surplus. On December 27, 2025, the Argentine Senate passed the 2026 budget by a vote of 46 to 25, marking the first budget approved by Congress since President Milei took office. The 2026 budget projects a primary surplus equivalent to 1.2% of GDP.

We cannot predict how the measures that the Argentine Government has applied and may continue to apply will impact the Argentine economy and, in turn, our business, our financial condition and the result of our operations. Moreover, we cannot be certain that the fiscal surplus generated by President Milei’s spending cuts will be sustained or that spending cuts will not lead to political and social upheaval. Opposition to the current administration’s austerity measures could result in a return to prior levels of public spending.

A new fiscal deficit may generate further complications for the Argentine Government’s ability to access the financial markets in the long term, and, at the same time, further limit Argentine corporations’ access to those markets. See “Argentina’s ability to obtain financing from international markets could be limited, which may impair its ability to implement reforms and foster economic growth”.

Failure to adequately address actual and perceived risks of institutional deterioration and corruption may adversely affect Argentina’s economy and financial condition

A lack of a solid and transparent institutional framework for contracts with the Argentine Government and its agencies and corruption allegations have affected and continue to affect Argentina. Argentina ranked 104 of 182 countries in the Transparency International’s 2025 Corruption Perceptions Index. Ongoing investigations and allegations of corruption involving high-ranking government officials may create political instability and adversely affect Argentina’s economy and investment climate.

As of the date of this annual report, there are various ongoing investigations into allegations of money laundering and corruption being conducted by the Office of the Argentine Federal Prosecutor, which have negatively impacted the Argentine economy and political environment. Depending on the results of these investigations and how long it takes to finalize them, companies involved may be subject to, among other consequences, a decrease in their credit ratings, having claims filed against them by investors in their equity and debt securities, and may further experience restrictions on their access to financing through the capital markets, all of which will likely decrease their income. Additionally, if criminal cases against companies move forward, they may be restricted from rendering services or may face new restrictions due to their customers’ internal policies and procedures. These adverse effects could restrict these companies’ ability to conduct their operating activities and to fulfill their financial obligations. Consequently, the number of suppliers available for our operations may be reduced which could in turn have an adverse effect on our commercial activities and results of operations.

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The Argentine Government has announced several measures aimed at strengthening Argentina’s institutions and reducing corruption. These measures include creating a special prosecutor’s office in charge of investigations involving national and provincial officials related to illicit enrichment and asset increases, plea bargains in exchange for cooperation with the judiciary in corruption investigations, greater access to public information, the seizure of assets from officials prosecuted for corruption, expanded powers for the Anti-Corruption Office, and the enactment of a new public ethics law, among others. However, the effectiveness and independence of these mechanisms have come under scrutiny. During 2025, a special investigative task unit established to investigate allegations of corruption was dissolved by presidential decree after only three months. The Anti-Corruption Office cleared senior government officials of wrongdoing in matters that remain subject to ongoing judicial and congressional investigations, and a congressional commission accused Executive Branch officials of systematically obstructing its inquiries. We cannot guarantee that existing anti-corruption measures will be effectively implemented or that they will achieve the desired result.

We cannot estimate the impact that the new measures could have on the Argentine economy. Similarly, it is not possible to predict the duration of corruption investigations, nor which companies might be involved or how far-reaching the effects of these investigations might be, particularly in the energy sector, or if there will be any other future investigations in this or other industry, which may negatively impact the Argentine economy. In turn, the decrease in investor confidence resulting from any of these, among other issues, could have a significant adverse effect on the growth of the Argentine economy, which could, in turn, harm our business, financial condition and operational results and affect the trading price of our common shares and ADSs.

Our operating costs could increase as a result of the promotion or adoption of certain measures by the Argentine Government as well as pressure from union sectors

We are subject to substantial and evolving risks associated with labor regulations, wage inflation, and collective bargaining activities in Argentina, any of which could increase our operating costs, disrupt our operations, and adversely affect our financial performance and results of operations. In the past, the National Government promoted and adopted laws and collective labor agreements that imposed on private sector employers the obligation to maintain certain salary levels and provide additional benefits to their employees. In addition, employers have come under strong pressure from employees and unions to grant wage increases and other benefits.

The current Argentine administration has pursued a series of labor-market reforms. DNU No. 70/23 and the Bases Law enacted measures aimed at easing existing labor regulations, reducing mandatory employer contributions, and introducing greater flexibility in employment contracts. However, these measures have been subject to judicial challenges and partial suspensions, and their scope, enforceability and ultimate validity remain uncertain. If key provisions are struck down or narrowed, we may be subject to the reinstatement of prior, more burdensome regulatory requirements. Moreover, Law No. 27,802 was enacted, modifying certain aspects of labor law. However, following the court ruling issued on March 30, 2026, which granted a preliminary injunction suspending the application of certain provisions of the recent labor reform, the scope and implementation of such changes may be limited pending further judicial review and a final decision on the merits (see “The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate”).

Notwithstanding the measures implemented by the current administration (see “The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate”) aimed at reducing the involvement of the government in the private sector, we cannot assure that such measures will achieve their intended purpose, that such measures will not be reversed or limited in any way in the future or that new measures that could increase minimum wages, mandatory benefits, severance obligations, or other employer-borne labor costs will not be enacted. Any salary increase and/or any other labor cost could result in higher costs and adversely affect the results of the Company’s operations. See “We employ a largely unionized labor force and could be subject to organized labor action, including work stoppages”.

External shocks and “contagion” effects could have an adverse effect on the Argentine economy

Although economic conditions vary from country to country, investors’ perceptions of events occurring in certain countries have in the past substantially affected, and may continue to substantially affect, capital flows into and investments in securities of issuers from other countries, including Argentina.

The effects of a global or regional financial crisis and related turmoil in the global financial system may have a negative impact on our business, capacity to access credit and international capital markets, financial condition and operational results, which is likely to be more severe on an emerging market economy, such as Argentina. There can be no assurance that the Argentine financial system and securities markets will not be adversely affected by policies that may be adopted by foreign governments or the Argentine Government in the future. Argentina can also be adversely affected by negative economic or financial events that take place in other countries, subsequently affecting our operations and financial condition, including our ability to repay our debt at its maturity date.

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This occurred on numerous occasions, such as in 2008, when the global economic crisis resulted in a sharp economic decline in Argentina’s economic activity throughout 2009, accompanied by inflationary pressures, depreciation of the Peso and a drop in consumer and investor confidence. In 2020, a new global financial crisis began as a result of Covid-19. Similarly, in 2022, another crisis was triggered because of the military invasion of Ukraine by the Russian Federation, which had a strong impact on the world’s main stock exchanges and on the economic and trade relations of many countries. Economic slowdowns, especially in Argentina’s major trading partners such as Brazil, led to declines in the Argentine economy in the past.

The administration of U.S. President Donald Trump has introduced significant changes in trade and regulatory policies, including tariffs, trade restrictions, and enforcement measures that could affect cross-border commerce and foreign business operations. In April 2025, President Trump signed a series of executive orders imposing various reciprocal tariffs, and other governments have imposed and may continue to impose retaliatory tariffs, trade restrictions or other trade barriers. On February 20, 2026, the U.S. Supreme Court ruled that these reciprocal tariffs, which were imposed under the International Emergency Economic Powers Act (“IEEPA”), are unconstitutional. The effect on global economic growth and trade of these measures, as well as the full implications of this ruling, remains uncertain, and could disrupt global trade flows, and increase operational costs for companies reliant on international supply chains.

The United States and Argentina agreed to a Framework for an Agreement on Reciprocal Trade and Investment in November 2025, under which certain Argentine exports were exempted from reciprocal tariffs. Following the U.S. Supreme Court’s ruling of February 20, 2026, the IEEPA-based reciprocal tariffs on Argentine imports were invalidated and subsequently terminated, although other trade measures remain in place and additional measures have been announced. Steel and aluminum continue to be subject to a 50% tariff rate. U.S. trade policy has been characterized by significant volatility and uncertainty, with tariff rates and covered products changing frequently and with limited advance notice. Tariffs may be reimposed under alternative legal authorities, further increased, expanded to additional products, or modified at any time. There can be no assurance that current trade arrangements will continue or that future changes to U.S. trade policy will not adversely affect Argentina’s economy or our operations. Any such changes, or retaliatory measures by other countries, could increase our costs for imported materials and equipment, disrupt our supply chains, and adversely affect our business, results of operations, and financial condition.

On January 3, 2026, the United States conducted a military operation in Venezuela resulting in the capture of Nicolás Maduro and his spouse on drug trafficking-related charges, with the Venezuelan Supreme Court subsequently designating Vice President Delcy Rodríguez as acting president. Further escalation of the situation in Venezuela could lead to significant market and other disruptions, which could have a material adverse effect on Latin America and global energy prices, thereby impacting our business, financial position, results of operations and cash flows.

At the same time, the war between Ukraine and Russia has had a significant economic impact worldwide, causing high volatility in the prices of primary commodities. Any further escalation of the conflict could lead to increased volatility in global oil and gas prices. Destabilization of global oil and gas prices could reduce the price of oil and natural gas and adversely affect our profitability. Increases in oil and gas prices may not persist and could be followed by price decreases based on factors beyond our control, including geopolitical events.

In this sense, in Argentina, the natural gas supply may be affected, with negative effects on the energy generation, especially for industries. The shortage of natural gas may adversely affect our generation dispatch assets. While we do not have any material business or financial ties to Russia or Ukraine as part of our own business, the impact of higher energy prices and higher prices for certain goods and services resulting in higher inflation and disruptions to financial markets across the globe may impact our business in the future. Further escalation of such armed conflict could lead to supply disruptions and higher energy costs, among others, which could adversely affect our results of operations.

The ongoing conflict between Israel, Hamas, and Hezbollah, together with broader hostilities across the Middle East, has contributed to world economic instability and uncertainty in global financial markets, adversely affecting our operations. The United Nations has reinstated sanctions against Iran in connection with its nuclear program, and the United States has intensified its pressure campaign through targeted sanctions against entities linked to the financing of Hamas and Hezbollah. President Javier Milei has also expressed a pro-Israeli position, and the Argentine Government has included Hamas in the list of terrorist organizations.

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On February 28, 2026, the United States and Israel commenced large-scale airstrikes against Iran, targeting military, governmental, and nuclear-related infrastructure, resulting in the death of Iran’s Supreme Leader, Ayatollah Ali Khamenei. Iran responded with widespread missile and drone attacks against Israel, U.S. military bases, and several Gulf states, causing substantial disruption to airspace, energy infrastructure, and civilian life across the Middle East, with significant casualties, displacement, and market volatility. The war in Iran has materially heightened uncertainty in international markets and has led to sustained volatility in global energy prices. On April 7, 2026, the United States and Iran entered into a two-week ceasefire agreement, which led to a sharp decline in oil prices. There can be no assurance the ceasefire will be extended or result in a lasting resolution of hostilities. Given the strategic importance of the region to global oil supply, any resumption or escalation of hostilities or a prolonged conflict in the region could have a material impact on our business, financial condition, and results of operations.

There can be no assurance that the Argentine financial system and securities markets will not be adversely affected by policies that may be adopted by foreign governments or the Argentine Government in the future, or by events in the economies of developed countries or in other emerging markets.

Finally, international investors’ perceptions of events occurring in one market may generate a “contagion” effect by which an entire region or class of investment is disfavored by international investors. Argentina could be adversely affected by negative economic or financial developments in other emerging and developed countries, which in turn may have a material adverse effect on the Argentine economy and, indirectly, on our business, financial condition and results of operations, and the market value of our ADSs and common shares.

The effects of an economic crisis on our customers and on us cannot be predicted. Weak global and local economic conditions could lead to reduced demand or lower prices for energy, hydrocarbons and related oil products and petrochemicals, which could have a negative effect on our revenues. Economic factors such as unemployment, inflation and the unavailability of credit could also have a material adverse effect on the demand for energy and, therefore, on our business, financial condition and operational results. The financial and economic situation in Argentina or in other countries, such as Brazil, may also have a negative impact on us and third parties with whom we do, or may do, business.

The Argentine economy and finances may be adversely affected by declines in international commodity prices or in the production levels of commodities

The commodities market is characterized by its volatility. Commodities exports contribute significantly to the revenues of the Argentine Government. Consequently, the condition of the Argentine economy remains relatively dependent on the price of its exports, particularly soybeans and other agricultural products.

Argentina suffered severe droughts during the 2018 and 2023 growing seasons that caused significant economic headwinds for Argentina. The 2025 season has again faced climate volatility, with drought and extreme heat in late December 2024 and January 2025 affecting key growing regions, particularly in northeastern Argentina. Additionally, record soybean production in Brazil and other South American producers has contributed to downward pressure on global commodity prices, potentially affecting Argentina’s export revenues.

A sustained decrease in the international price of the main commodities exported by Argentina, or any future climate event or condition may have an adverse effect on the agricultural sector. This would negatively impact the revenues of the Argentine Government and its capacity to comply with the payments of its public debt, eventually generating recessive or inflationary pressures, thus affecting our business, financial situation and the results of our operations.

Any downgrade in Argentina’s and/or Pampa’s credit rating or rating outlook could adversely affect both the rating and the market price of the Company’s ADSs and shares

Argentina’s long-term debt denominated in foreign currency, as of the date of this report, is rated “Caa1” by Moody’s, “CCC+” by S&P and “CCC+” by Fitch.

Pampa and its subsidiaries are also assigned credit ratings, which are based on information provided by Pampa or obtained by risk rating agencies from independent sources. These ratings are also influenced by the credit ratings of Argentine Government bonds and general opinions related to the Argentine financial system considered as a whole. During 2025, major credit rating agencies upgraded both Argentina’s sovereign ratings, reflecting the country’s improved fiscal discipline and macroeconomic stabilization. However, the agencies continue to note Argentina’s external vulnerabilities and foreign currency constraints.

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Along with these sovereign upgrades, Pampa’s ratings also improved. In February 2025, S&P upgraded Pampa’s debt rating to “B-” from “CCC” as a result of improved sovereign-related constraints and credit conditions and later, in August 2025, upgraded Pampa’s stand-alone rating from “b+” to “bb-”.

On March 3, 2026, Fitch also upgraded Pampa’s Long-Term Foreign and Local Currency Issuer Default Ratings from “B-” to “B” and its senior unsecured notes from “B” to “B+” with a Recovery Rating of “RR3”.

Notwithstanding these developments, the Company cannot guarantee that Pampa’s ratings or Argentina’s rating outlook will remain stable. A downgrade, suspension or withdrawal of Pampa’s credit ratings could give rise to the following consequences, among others: (i) an increase in financing costs and other difficulties related to fundraising; (ii) the need to provide additional guarantee in relation to financial market operations; and (iii) the termination or cancellation of existing agreements.

Risks Related to our Company

We conduct a material part of our businesses pursuant to public concessions granted by provincial and national governments in Argentina to Pampa and other companies in which we hold interests. These concessions contain several requirements regarding the operation of those businesses and compliance with laws and regulations. Compliance with our obligations under our concessions is, in certain cases, secured by a pledge of our shares in the concessionaires in favor of the governments.

Accordingly, upon the occurrence of specified events of default under these concessions, the governments would be entitled to foreclose on their pledge of the concessionaire and sell our shares in that concessionaire to a third party. Such sales would have a severe negative impact on our ability to operate a material portion of our business, and as a result, our operational results would be materially adversely affected.

Moreover, our concessions also generally provide for termination in the case of insolvency or bankruptcy of the concessionaire. If any of our concessions are terminated or if any government forecloses its pledge over the shares we own in any of our concessionaire companies, or if, upon termination, such concessions are not renewed or extended or are only renewed or extended subject to further economic or other conditions, such companies may not be able to continue to operate as a going concern or their operational and financial condition may be adversely affected by such new requirements. In turn, our consolidated operational results would be materially adversely affected and the market value of our shares and ADSs could decline.

Our performance is largely dependent on recruiting and retaining key personnel

Our current and future performance and the operation of our business are dependent upon the contributions of our senior management and our skilled team of engineers and other employees. We depend on our ability to attract, train, motivate and retain key management and specialized personnel with the necessary skills and experience. There is no guarantee that we will be successful in retaining and attracting key personnel and the replacement of any key personnel who were to leave could be difficult and time-consuming. The loss of the experience and services of key personnel or the inability to recruit suitable replacements and additional staff could have a material adverse effect on our business, financial condition and operational results.

We employ a largely unionized labor force and could be subject to organized labor action, including work stoppages

The sectors in which we operate are generally unionized across the country. As of December 31, 2025, 50.73% of our workforce was represented by unions under collective bargaining agreements. Although our relations with trade unions have been historically stable, we cannot be sure that we will not experience work stoppages or disruptions in the future, which could have material adverse effects on our business and revenues. A primary reason for this is that our collective bargaining agreements are negotiated on an annual basis. As such, we are unable to guarantee the continuity of current terms and conditions in subsequent collective bargaining agreements, nor that we will not be subject to strikes or work stoppages before or during the negotiation process.

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If we are unable to negotiate salary agreements or are subject to strikes or work stoppages, our operations, financial condition and the market value of our shares and ADSs could be materially affected in an adverse way.

We could be subject to accidents or other events that may not be covered by our insurance policies

We carry insurance policies that are consistent with industry standards in each of our different business segments. Although we believe our insurance coverage is commensurate with international standards, no assurance can be given of the existence or sufficiency of risk coverage for any particular risk or loss both in our ongoing businesses or in the construction stages of our ongoing or future projects. If an accident or other event occurs that is not covered by our current insurance policies in any of our business segments or projects, we may experience material losses or have to disburse significant amounts from our own funds, which may have a material adverse effect on our net profits and our overall financial condition and the market value of our shares and ADSs.

We conduct a portion of our operations through joint ventures and co-controlled companies and, as a result, the continuation of such joint ventures and co-controlled companies is vital to our continued success. In the event that any of our partners were to decide to terminate its relationship with us in any such joint venture or co-controlled companies or sell its interest in such joint venture, we may not be able to replace our partner or obtain the necessary financing to purchase our partner’s interest. Furthermore, in certain cases such as Transener and TGS, we cannot hold a controlling interest due to applicable Argentine regulations. As a result, the failure to continue some of our joint ventures or co-controlled companies or to resolve any potential disagreement with our partners or to find new partners could adversely affect our ability to conduct the business that is the subject of such joint venture or co-controlled company, which would in turn negatively affect our financial condition and operational results and the market value of our shares and ADSs.

Our derivative risk management activities could result in financial losses

We may enter derivative financial instruments such as foreign exchange, interest rate and commodity hedges, among others, to mitigate market risks of certain present or future assets to whose prices we are exposed.

Although we would only execute non-speculative trades, we might be exposed to adverse fluctuations in the price of the assets underlying the derivative contracts, such contracts might fail to provide perfect hedging for the nature of the risks or our counterparties might fail to perform their obligations, any of which could result in financial losses and adversely affect our business, financial condition and results of operations.

We may not be able to effectively hedge our currency risk in full regarding a devaluation of the Argentine Peso

Although a significant portion of our revenue in the spot market for power generation is denominated in U.S. Dollars, our revenues are mainly collected in Argentine Pesos at an exchange rate that is fixed at the end of each month. As a result, we are exposed to exchange rate fluctuations between the rate-fixing date and the actual receipt of revenue. Furthermore, a significant portion of our existing financial indebtedness is denominated in U.S. Dollars. If we are not able to effectively hedge all or a significant portion of our currency risk exposure, a devaluation of the Argentine Peso may have a material adverse effect on our financial condition and results of operations.

We are or could be involved in various legal proceedings which could result in unfavorable rulings against us

Our business may expose us to litigation relating to labor, environmental, health and safety matters, regulatory, tax and administrative proceedings, governmental investigations, tort claims, and contract disputes, among other matters.

We are or could be party to several legal proceedings, some of which have been pending for several years. We cannot be certain that these claims will be resolved in our favor and responding to the demands of litigation may divert our management’s time and attention and our financial resources. In the context of these proceedings, we may be required to pay fines or monetary damages, and we may also be subject to complementary sanctions or injunctions affecting our ability to continue our operations. While we may contest these matters vigorously and make insurance claims when appropriate, litigation and other proceedings are inherently costly and unpredictable, making it difficult to accurately estimate the outcome of actual or potential litigation or proceedings. See “Item 8. Legal Proceedings”.

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Cybersecurity events, including cyber-attacks, could adversely affect our business, financial condition, operational results and cash flows

We rely extensively on internet-based data processing, communication, public cloud services and information exchange platforms. The increasing sophistication and frequency of cyber-attacks, combined with our growing dependence on internet-connected equipment and systems, have heightened our exposure to potential cybersecurity incidents. In recent years, cyber-threats and cyber-attacks targeting critical infrastructure in the energy sector have become more sophisticated, frequent, coordinated and costly, and could be and have been targeted at our operations or information technology systems.

These cyber-threats and cyber-attacks may include computer intrusions, fraud, phishing, identity theft and other disruptions that compromise the security of information stored within or transmitted through our computer systems and network infrastructure. The integrity of our information technology and operational systems could also be compromised as a result of the negligence or misconduct of our employees. If such integrity were to be materially compromised, this could lead to operational disruptions, fraud, property damage, theft of customer information, significant revenue losses, response and remediation costs, financial loss, increased regulatory scrutiny, litigation, and reputational damage. Additionally, our facilities, which maintain partial connectivity to manufacturer systems for maintenance and operational control, could be adversely affected by attacks targeting third party systems.

Despite encountering various cybersecurity threats during 2025, none resulted in material incidents, losses or adverse effects on our operations, largely due to the measures we implemented. However, due to the evolving and increasingly sophisticated nature of these threats, we cannot provide any assurance that our current and future systems will be entirely free from vulnerabilities, and our risk and exposure cannot be fully quantified or entirely mitigated, making cybersecurity a material risk for us and our business. A cyber-attack, whether directed to us or third-party infrastructure on which we rely, could adversely affect our business, operational results, and financial condition.

Our operations could cause environmental risks and any change in environmental laws could increase our operating costs

Some of our operations are subject to environmental risks that could arise unexpectedly and cause material adverse effects on our operational results and financial condition. In addition, the occurrence of any of these risks could lead to personal injury, loss of life, environmental damage, repair and expenses, equipment damage and liability in civil, criminal and administrative proceedings. We cannot assure you that we will not incur additional costs related to environmental issues in the future, which could adversely affect our operational results and financial condition. In addition, we cannot ensure that our insurance coverage is sufficient to cover the losses that could potentially arise from these environmental risks.

Moreover, we are subject to a broad range of environmental legislation, both in Argentina and in other countries where companies we have interests in are located. Local, provincial and national authorities in Argentina and other countries where companies we have interests in are located may implement new environmental laws and regulations and may require us to incur higher costs to comply with new standards. The imposition of more stringent regulatory and permit requirements in relation to our operations in Argentina could significantly increase the costs of our activity.

We cannot predict the effects of the implementation of any new environmental laws and regulations on our financial condition and operational results.

We may be unable to collect payments of amounts due, or to collect them in a timely manner, from CAMMESA, ENARSA, the Argentine Government and other customers

As electricity generators, fuel producers and in our petrochemical business, we receive payments from CAMMESA, ENARSA, the Argentine Government and other customers. These payments could be altered and/or delayed.

We collect funds from CAMMESA for energy and capacity sold on the spot market, as well as under PPAs. CAMMESA, in turn, supplies this energy to the distributors, who must make payments to CAMMESA for the electricity provided and are currently indebted to CAMMESA for substantial sums owed for the energy supplied.

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Accordingly, payments to generators should be settled within 42 days from the end of each month; however, in recent years there have been significant delays in such payments. In addition, the Argentine Government has, at times, implemented exceptional mechanisms affecting the manner and timing of settlement of CAMMESA obligations. For example, during 2024, payments corresponding to the months of December 2023 and January 2024 were paid with Argentine Sovereign Bonds, resulting in significant losses to our results.

Regarding direct contracts with customers, distributors and/or energy traders, the recent issuance of SE Resolution No. 400/25 reinstalled a Term Market (MAT) with certain restrictions (see “Item 4 - The Argentine Energy Sector – Electricity Regulatory Framework”). Consequently, not all of our generation units are eligible to participate in MAT contracts. Insofar as we are able to enter into such contracts, our revenues would depend on the timely collection of our credits from our customers.

We cannot assure you that measures aimed at reducing the debt of distributors will be implemented, that CAMMESA will be able to pay generators or that the WEM Large Users will comply with their payment obligations.

Furthermore, we have participated and continue to participate in programs aimed at promoting or incentivizing natural gas production by the Argentine Government to achieve self-sufficiency and, in turn, generate higher levels of activity, investment, and employment in the national natural gas sector. See “Item 4 - The Argentine Energy Sector - Oil & Gas Regulatory Framework”.

Under these programs, we have entered into natural gas supply contracts with CAMMESA (which supplies this fuel to electricity market generators) and ENARSA, receiving payments from both entities as consideration for the gas supplied and a price supplement from the Argentine Government for such gas. Payments due from CAMMESA, ENARSA and the Argentine Government have suffered significant delays in recent years. SE Resolution No. 606/25 provided a 30-day period for ENARSA to establish the terms of such assignment. Such period was extended to 45 days by SE Resolution No. 36/26 and for an additional 180 days by SE Resolution No. 54/26. See “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework - Assignment of contracts with ENARSA”. We cannot assure you that the existing debts owed to the adhering producers will be resolved in a manner favorable to us, which could adversely affect our operational results, revenues, and financial position.

Moreover, our operational results also depend on the timely collection of receivables from our other customers. Our customers’ ability to meet their payment obligations is heavily influenced by Argentina’s overall economic environment, including high inflation rates, fluctuations in disposable income, and restricted access to financing, as previously described in this annual report. See “Our business, operational results and financial condition depend on economic and political conditions in Argentina, which remain vulnerable”. Any significant economic downturn or sustained period of financial instability in Argentina could lead to an increase in payment defaults, higher delinquency rates, or requests for extended payment terms. If we experience a material increase in uncollectible accounts or a significant slowdown in our collection cycle, our liquidity, cash flows, and results of operations may be adversely affected.

We cannot guarantee that CAMMESA, ENARSA, the Argentine Government and/or other customers will not experience payment delays, or that such payments will not be altered in any way. Such delays or modifications could negatively affect our operational results, revenues, investment plans and financial position, including our ability to pay our debts when due and, consequently, the market value of our shares and ADSs.

As of the date of this annual report, certain expropriation and condemnation events with respect to us may constitute an event of default, which, if declared, could trigger the acceleration of our obligations under the relevant indebtedness and require us to immediately repay all such accelerated indebtedness. In addition, a significant part of our outstanding financial indebtedness includes certain events of default related to bankruptcy and voluntary reorganization proceedings (concurso preventivo). If we are not able to comply with certain payment obligations as a result of our financial situation and if the requirements set forth in the Argentine Bankruptcy Law No. 24,522 are met, any creditor, including us, would be qualified to file for bankruptcy, or we would be able to file for a voluntary reorganization proceeding (concurso preventivo). In addition, certain of our outstanding financial indebtedness also includes cross-default or cross-acceleration provisions that could cause all of our indebtedness to be accelerated if the indebtedness including the expropriation or bankruptcy or reorganization proceeding events of default goes into default or is accelerated. In such case, we would expect to actively pursue formal waivers from the corresponding financial creditors to avoid such potential situation, but if those waivers are not timely obtained and an immediate repayment is required, we could face short-term liquidity problems, which could adversely affect our operational results and cause the market value of our ADSs to decline.

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Covenants in our indebtedness could adversely restrict our financial and operating flexibility

Some of our current indebtedness includes, and our future indebtedness may include, affirmative and restrictive covenants that limit our ability to create liens, incur additional indebtedness, dispose of our assets, pay dividends or consolidate, merge or sell part of our businesses. These restrictions may limit our ability to operate our business and may prohibit or limit our ability to enhance our operations or take advantage of potential business opportunities as they arise. The breach of any of these covenants or the failure to meet any of such conditions could result in a default under the relevant indebtedness. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions and the renegotiation of concessions and licenses used in our businesses.

Natural disasters, pandemics, catastrophic events, terrorist attacks and operational failures could disrupt our assets and impair our ability to fulfill contractual commitments

Our hydrocarbon blocks, pipelines or any other fuel transportation infrastructure, power generation facilities, power transmission infrastructure, or any third-party infrastructure that we rely on may be damaged or disrupted by flooding, fires, earthquakes, extreme weather events, and other catastrophic disasters arising from natural or accidental or intentional human causes. Public health crises, such as the Covid-19 pandemic or other similar crisis, could lead to labor stoppages or could cause demand for energy to plummet, negatively affecting our business. We could experience severe business disruptions, significant decreases in revenues based on lower demand arising from catastrophic events, or significant additional costs not otherwise covered by business interruption insurance clauses. There may be an important time lag between a major accident, catastrophic event or terrorist attack and our definitive recovery from our insurance policies, which typically carry non-recoverable deductible amounts and are subject to caps per event. In addition, any of these events could have adverse effects on the demand of some of our customers and of consumers generally in the affected market. Some of these considerations could have a material adverse effect on our business, financial condition and our result of operations.

For example, during a storm that occurred in January, 2025, in San Rafael, Mendoza, significant damage was caused to the Atuel Canyon, rendering the Nihuil II and Nihuil III power plants out of service and inoperative. The corresponding insurance claims were filed under the terms of our All-Risk Operational insurance policy, and we initiated the loss adjustment process as well as official communications with the authorities. As of the date of this report, the remediation works of the sites have been completed and a thorough assessment of the assets performed. However, returning the units to commercial operation in good repair will require significant time and investment. These investments should be performed by the next concessionaries (see “We may face extra costs due to the termination of the concession agreements for HINISA, HIDISA and/or HPPL”). The units are still out of service.

Additionally, our facilities are subject to the risk of mechanical or electrical failures and may experience periods of unavailability affecting our ability to fulfill our contractual commitments, such as during the general blackout suffered in June 2019. We cannot guarantee that any other event in the Argentine grid or any unplanned unavailability of our facilities will not damage or affect in any way our power generation and transmission units or adversely affect our financial condition or operational results and our ability to fulfill our contractual commitments, which could result in fines and penalties, consequently affecting our operational results.

Our activities may be adversely affected by events in other countries in which we do business

Although most of our operations and activities are concentrated in Argentina, we have investments in other countries in Latin America, including Bolivia and Ecuador. Latin America has experienced significant economic, social, political and regulatory volatility. In recent years, many governments in Latin America have taken steps to assert greater control or increase their share of revenues from the energy sector, spurred by soaring oil and gas prices and nationalist policies. The level of government intervention in the economy of Latin American countries has adversely affected our business and operational results, and it may adversely affect it in the future.

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We continue evaluating investment projects to expand our activity, which could entail an increase in our indebtedness and additional costs

We have entered or could enter into credit facilities and have incurred or will incur other forms of indebtedness, including for investment projects. Leveraged assets are more sensitive to declines in revenues, increases in expenses and interest rates, and adverse economic, market and industry developments. The incurrence of indebtedness could result in increased fixed payment obligations, and we may be required to agree to certain restrictive covenants, such as limitations on our ability to incur additional debt, limitations on our ability to make investments, and other operating restrictions that could adversely impact on our ability to conduct our business.

Some of our subsidiaries’ and affiliates’ investment projects could be guaranteed by Pampa, resulting in the incurrence of additional guaranteed debt and causing us to become liable for such obligations. Therefore, if we declare bankruptcy or are liquidated, the guaranteed lenders will have priority over the claims for payment of our notes to the extent of the assets that constitute their guarantee. If such subsidiaries and affiliates are unable or fail to pay any of their indebtedness in respect of which our Company has provided a guarantee, we may be required to pay all amounts due under such indebtedness, which may affect our financial health and make us more vulnerable to adverse economic conditions. If assets remain after the payment of the guaranteed lenders, those assets could be insufficient to satisfy the credits of the holders of our corporate bonds and other unsecured debt, as well as the credits of other general creditors who will be entitled to participate pro rata with the holders of our corporate bonds.

Additionally, the development of new projects is exposed to risks inherent to construction activities, such as cost overruns, particularly in inflationary environments, construction delays, increases in input and labor costs, and logistical or supply chain disruptions that could result in costs in excess of original estimates. These projects are also subject to obtaining and maintaining environmental and other regulatory permits, and delays or additional requirements could increase costs or postpone their execution. Furthermore, once completed, new projects may fail to achieve anticipated levels of efficiency, output or profitability due to adverse market, regulatory or operating conditions.

Any of these factors could adversely affect the expected returns of our projects and have a material adverse effect on our results of operations and financial condition.

Climate change, energy transition and regulatory framework promoted for such purposes could affect our business, our results of operations and financial condition

Global climate change creates new challenges for the energy sector and its adverse effects are a common concern of humanity. Consequently, the United Nations and several countries have adopted, or are evaluating the adoption of new measures and/or regulatory requirements for the mitigation or reduction of GHG emissions in the atmosphere, such as taxes on carbon, raising efficiency standards or adopting cap and trade regimes. Certain mitigation actions could require radical changes to development models, such as the transition from the use of conventional energy sources to the use of renewable energy sources, which reduce environmental pollution, contribute to sustainable development and avoid global warming since the GHG emissions of renewable energy sources are usually very low.

The risks associated with climate change involve severe weather events; legal and regulatory risks, including eventual litigation with respect to environmental damage and climate change; market risk; reputational risk with investors; lower consumption of fossil fuels; and energy transitions in the global economy towards a lower carbon energy matrix with the inclusion of substitute products for fossil fuels and greater use of electricity, which may cause a negative impact on the demand for our products in the long term and could have an adverse effect on our results of operations.

The progress and challenges of the energy transition could have a significant adverse effect on the Company if it is unable to keep up with the pace of the global energy transition and allocate its resources towards efficient energy sources and resources to address the concerns related to climate change, which could have a material adverse effect on the results of our operations and our financial condition.

Guarantees that we granted to third parties could be enforced

We, or other companies within the Pampa Group, may from time to time grant guarantees in favor of third parties to support the payment or other commercial obligations of our subsidiaries, affiliates or other third parties. If the underlying obligor fails to satisfy its obligations, those guarantees could be enforced in accordance with their terms and conditions.

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We cannot assure you that defaults or other triggering events will not occur in the future or that, if such events occur, they do not have an adverse effect on Pampa’s operations and consolidated financial results.

Risks Related to Our Businesses

Risks Related to our Oil and Gas Business

Oil and gas companies have been affected by certain measures taken by the Argentine Government and may be further affected by additional changes in their regulatory framework

The Argentine Government has historically implemented, and may continue to implement, significant regulatory changes affecting the oil and gas sector, creating ongoing uncertainty that could materially adversely affect our business, results of operations, and financial condition (see “The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate”).

Since December 2011, the Argentine Government has adopted from time to time a number of measures concerning the repatriation of funds obtained from oil and gas exportation and charges applicable to the production of liquid gas, which has affected the oil and gas business. Beginning in April 2012, the Argentine Government provided for the nationalization of YPF and imposed major changes to the system under which oil companies operate, principally through Law No. 26,741, Decree No. 1277/12 and Law No. 27,007. Further changes in such regulations may increase the adverse effect of such measures on the business, revenues and our results of operations and financial condition. Furthermore, the current administration of the Argentine Government has shown interest in including ENARSA in privatization processes. Since we operate in a context in which the governing law and applicable regulations change frequently, in part as the result of changes in government administrations, it is difficult to predict if and how our activities will be affected by such changes. We cannot affirm that the Argentine economic, regulatory, social and political framework or the policies or measures that the Argentine Government adopts or may adopt, will not adversely affect our business, financial condition and/or operational results.

Argentine oil and gas production concessions and exploration permits are subject to certain conditions and may not be renewed or could be revoked, or their terms and economic conditions may be modified

The Hydrocarbons Law provides for oil and gas concessions to remain in effect for 25, 30 or 35 years, depending on the concession, beginning on the date of their award, and further provides for the concession term to be extended for periods of ten additional years, subject to terms and conditions approved by the grantor at the time of the extension. See “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework”.

We cannot assure you that our concessions will be extended in the future as a result of the review by the relevant authorities of the investment plans submitted for such purposes, or that additional requirements will not be imposed, or that the economic or other conditions applicable to obtaining or renewing such concessions or permits will not be imposed or changed.

Hydrocarbon activities (including exploitation, industrialization, transportation and commercialization) in the territory of Argentina are deemed of “national public interest.” We cannot assure you that any measures that may be adopted by the Argentine Government to secure Argentina’s self-sufficiency in oil and gas supply or any other measures imposed by the national or provincial governments will not have a material adverse effect on the Argentine economy and, as a consequence, adversely affect our financial condition, our operational results and the market value of our shares and ADSs.

Substantial or extended declines and volatility in the prices of crude oil, oil products and natural gas may have an adverse effect on our operational results and financial condition

A significant amount of our revenue is derived from crude oil, oil products and natural gas sales. Factors affecting international prices for crude oil and related oil products include: political developments in crude oil producing regions, particularly the Middle East; the ability of the Organization of Petroleum Exporting Countries and other crude oil-producing nations to set and maintain crude oil production levels and prices; global and regional supply and demand for crude oil, gas and related products; competition from other energy sources; domestic and foreign government regulations; weather conditions; storage capacity and global and local conflicts, wars or acts of terrorism. We have no control over these factors. Although crude oil prices had maintained an increasing trend in recent years, at the beginning of 2020 the conflict between Saudi Arabia and Russia, which was magnified with the effects of the global crisis caused by Covid-19, resulted in a collapse of crude oil prices. In 2022, due to the conflict between Russia and Ukraine, and the fact that Russia is the second largest oil exporter in the world and the largest producer of natural gas, world oil prices jumped over U.S.$ 110 per barrel, and the cost of natural gas reached a new record high in Europe.

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In 2025, oil prices declined compared to 2024 due to sluggish demand, weak economic activity, and trade uncertainty. OPEC+’s announcements of higher production targets added further downward pressure. On a monthly average basis, Brent crude oil spot prices declined from a high of U.S.$ 79 per barrel in January to a low of U.S.$ 63 per barrel in December, the lowest monthly average price since early 2021. During the first week of April 2025, developments in trade policy and oil production led to a significant drop in oil prices, driven in particular by tariffs on imports imposed by the United States; the Brent crude oil spot price fell by 14% between April 2 and April 7, 2025, reaching U.S.$ 66 per barrel. Natural gas spot prices diverged across global regions, declining below 2024 levels in Asia and Europe while rising in the United States.

In March 2026, the war in Iran led to heightened concerns regarding potential disruptions to Middle Eastern oil supplies and critical transportation routes, contributing to increased volatility in global oil markets; in that context, the Brent crude spot price reached U.S.$ 122 per barrel on March 30, 2026 (see “External shocks and “contagion” effects could have an adverse effect on the Argentine economy”).

As a result, we cannot assure that substantial or extended declines in international prices of crude oil and related oil products will not have a material adverse effect on our business, operational results and financial condition and the value of our proven reserves. In addition, significant decreases in the prices of crude oil and related oil products may require the incurrence of impairment charges in the future or cause us to reduce or alter the timing of our capital expenditures, and this could adversely affect our production forecasts in the medium-term and our reserves estimates in the future.

Oil and gas prices and sale conditions could affect our level of capital expenditures

The prices that we are able to obtain for our hydrocarbon products affect the viability of investments in new exploration and development activities, and as a result, the timing and amount of our projected capital expenditures for such purposes. We budget capital expenditures by considering, among others, the market prices for our hydrocarbon products. In the event that current domestic prices decrease, the ability to improve our hydrocarbon recovery rates, identify new reserves and carry out certain other capital expenditure plans is likely to be affected, which, in turn, could have an adverse effect on our operational results.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control. Historically, factors affecting the prices of oil and natural gas include:

changes in the supply of and demand for hydrocarbons, which are affected by general economic and business conditions;

the costs of exploring, producing, and delivering oil and gas;

the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and the expanded alliance known as OPEC+ to set and maintain production levels for oil;

the level of oil and gas exploration and production activity;

the level of excess production capacity;

the level of refining and storage capacity;

the level of oil and gas inventories;

access to potential resources;

political and economic uncertainty, wars, armed conflicts and geopolitical unrest;

governmental laws, policies, regulations, subsidies, and other actions, including initiatives to promote the use of renewable energy sources;

speculation as to the future price of oil and the speculative trading of oil and gas futures contracts;

technological advances affecting energy consumption; and

extreme weather conditions, natural disasters, and public health or similar issues, such as pandemics and epidemics.

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The Argentine Government has, from time to time, introduced and revised export authorization requirements, import regulations and other measures affecting hydrocarbons and related oil products. These measures have limited our ability, and that of other oil and gas companies, to benefit from international market prices for these commodities, and have materially affected our competitiveness and operational results. See “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework”.

In particular, the Argentine Government has periodically revised its natural gas export authorization procedures. On August 22, 2018, the Argentine Government issued a Natural Gas Exportation Procedure regulating the process to obtain the authorizations needed to export natural gas. On April 27, 2021, through SE Resolution No. 360/21, a new Natural Gas Exportation Procedure was established for obtaining such authorizations, which was subsequently modified by SE Resolution No. 774/22.

The Argentine Government has also imposed and amended export duties on hydrocarbons through a series of decrees and legislative changes. On September 4, 2018, Decree No. 793/18 imposed an export duty on several goods, including natural gas, until December 31, 2020, consisting of a Ps. 4 tax on every U.S.$ 1.00 worth of exports, subject to a maximum rate of 12% on the value of exports. Thereafter, the Social Solidarity and Productive Reactivation Law modified the prior export duties for hydrocarbons that are commercialized in the external market. Subsequently, following the effective date of Decree No. 488/20 (Barril Criollo), exports of oil, natural gas and liquefied gas were exempted from export duties as long as the price of Brent published by the SE at the close of each month was equal to or lower than U.S.$ 45/bbl. Under that regime, the export duty rate was subject to a gradual increase up to 8% as the reference price rose, and such 8% rate applied if the price was equal to or higher than U.S.$ 60/bbl. The export duty regime for crude oil has been updated again pursuant to Decree No. 59/26, which introduced a distinction between conventional and unconventional crude oil production. Under this updated regime, for crude oil from conventional reservoirs, export duties do not apply when the international price is at or below U.S.$ 65/bbl, increase according to the applicable formula when such price is above U.S.$ 65/bbl but below U.S.$ 80/bbl, and are set at 8% when the price reaches or exceeds U.S.$ 80/bbl.

We cannot guarantee that the Argentine Government will not create new export and import regulations or amend the ones currently in place. We cannot predict the impact that any such changes may have on our operational results and financial condition.

We conduct most of our oil and gas operations through joint arrangements (joint operations for accounting purposes), in which we may not always act as operators. Our inability to maintain or resolve disagreements with our partners within such joint arrangements could materially affect the success of their operations

We generally carry out most of our oil and gas exploration and exploitation activities through joint arrangements (joint operations for accounting purposes) entered into with third parties. Under the terms of these arrangements, one of the parties is appointed as operator and is responsible for conducting and managing the activities of the joint operation. We do not always act as operators and, in those cases, we are exposed to risks related to the operator’s performance, decisions, operational execution, and compliance with applicable agreements, laws and regulations. Actions or omissions by the operator could adversely affect the execution, efficiency or success of the joint operation and, as a result, could have a material adverse effect on our results of operations and financial condition.

In addition, the continuation of the joint arrangements is fundamental to the success of those operations. If we are unable to resolve material disagreements with our partners, or if any of our partners were to terminate its participation in a joint operation or transfer its interest, we may not be able to replace such partner or obtain the financing necessary to acquire its interest. Any failure to resolve material disagreements or to maintain our joint arrangements on acceptable terms could impair our ability to continue the underlying operations, which could, in turn, materially affect our financial condition, results of operations and prospects.

Our failure to comply with our investment commitments could negatively affect our operational results

We have commitments to make certain investments, such as, among others, under investment agreements. Failure to comply with such commitments in a timely manner could result in a breach of the relevant partnership agreement, foreclosure of any guarantees and/or the loss of all rights over the underlying area which could have an adverse effect on our operational results. See “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework” and “Our Oil and Gas Business”.

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Oil and gas activities are subject to significant economic, environmental and operational risks

Oil and gas exploration and production activities are subject to particular economic and industry-specific operational risks, some of which are beyond our control, such as production, equipment and transportation risks, as well as natural hazards and other uncertainties, including those relating to the physical characteristics of oil or natural gas fields. Our operations may be curtailed, delayed or cancelled due to bad weather conditions, mechanical difficulties, shortages or delays in the delivery of equipment, compliance with governmental requirements, fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards, such as oil spills, gas leaks, ruptures, contamination of soil or water sources or discharges of toxic gases. If these risks materialize, we may suffer substantial operational losses or disruptions in our operations. Drilling may be unprofitable, not only with respect to dry wells, but also with respect to wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs are considered.

Water is an essential component of drilling, completion and hydrocarbon production activities. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), could materially and adversely impact our oil and gas operations. Severe drought conditions can result in local water districts taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic stimulation in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, it may need to be obtained from new sources and transported to drilling sites, or other facilities, resulting in increased costs, which could have an adverse impact on our financial condition and cash flows. Additionally, if we were unable to obtain water from any sources, we might be forced to halt our drilling and completion activities, which could have a material adverse effect on our growth prospects, financial condition, results of operations and cash flows.

Unless we replace our oil and gas reserves, such reserves and production will decline over time

The possibility of replacing our crude oil and gas reserves in the future depends on our ability to access new reserves through successful exploration, reserve acquisitions and investments. Although we have geological and engineering assessments that estimate certain unproven reserves and contingent and prospective resources, we cannot guarantee their successful exploration and future development.

Moreover, oil and gas production declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Accordingly, the amount of proved reserves declines as these reserves are produced.

Without successful exploration activities or reserves acquisitions, our proved reserves would decline as our oil and gas production would depend solely on our current portfolio of assets. The level of our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing current reserves, entering into new investment agreements and economically finding or acquiring additional recoverable reserves.

While we have had success in identifying and developing commercially exploitable deposits and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable deposits or successfully drill, complete or produce more oil or gas reserves, and the wells that we have drilled and currently plan to drill may not result in the discovery or production of any further oil or natural gas.

If we are not able to successfully find, develop or acquire sufficient additional reserves, our reserves and therefore our production may decline and, consequently, this may adversely affect our future operational results and financial condition.

Our estimated oil and gas reserves are based on assumptions that may prove inaccurate

We estimate our oil and gas reserves at least once a year. Our oil and gas reserves estimation as of December 31, 2025 was audited by GaffneyCline, as the Independent Reserves Engineers Firm, based on its year-end Reserves Report. Although classified as “proved reserves,” the reserves estimates set forth in the Reserves Report are based on certain assumptions that may prove inaccurate. The Independent Reserves Engineers Firm’s primary economic assumptions in estimates included oil and gas sales prices determined according to the guidelines described in the Reserves Report, future expenditures and other economic assumptions (including interests, royalties and taxes) provided by us.

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The estimation process is initiated with an initial review of the assets by geophysicists, geologists and engineers. A reserves coordinator protects the integrity and impartiality of the reserves estimates through supervision and technical support to technical teams responsible for the preparation of the reserves estimates. Our reserves estimates are approved by the Executive Director of Oil and Gas. Reserves engineering is a subjective process of estimating underground accumulations involving a certain degree of uncertainty. Reserves estimates depend on the quality of the available engineering and geological data as of the estimation date and on the interpretation and judgment thereof.

Oil and gas accumulations cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out in this annual report. Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil and gas reserves, including projecting future rates of production, timing and amounts of development expenditures and prices of oil and gas, many of which are beyond our control. Results of drilling, testing and production after the date of the estimate may require revisions to be made. The estimate of our oil and gas reserves would be impacted if, for example, we were unable to sell the oil and natural gas we produced. Accordingly, reserves estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and if such recovered quantities are substantially lower than the initial reserves estimate, this could have a material adverse impact on our operational results. See “Item 4. Our Oil and Gas Business - Reserves”.

We face significant competition in the acquisition of exploratory acreage and oil and natural gas reserves

The Argentine oil and gas industry is extremely competitive. When we bid for exploration or exploitation rights with respect to a hydrocarbon block, we face significant competition not only from private companies, but also from national or provincial public companies that are highly competitive in the Argentine oil and gas market. As a result, we cannot assure you that we will be able to acquire new exploratory acreage or oil and gas reserves in the future, which could negatively affect our financial condition and operational results. There can be no assurance that the participation of national or provincial public companies in the bidding processes for new oil and gas concessions will not influence market forces in such a manner that could have an adverse effect on our financial condition and operational results.

We may incur significant costs and liabilities related to environmental, social, health and safety matters

Our operations, like those of other companies in the Argentine oil and gas industry, are subject to a wide range of environmental, health and safety laws and regulations. These laws and regulations have a substantial impact on our operations and could result in material adverse effects on our financial position and operational results.

Environmental, health and safety regulation and case law in Argentina is developing at a rapid pace and no assurance can be provided that such developments will not increase our cost of doing business and complying with applicable regulations. In addition, due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, new regulatory requirements to reduce greenhouse gas emissions, such as carbon taxes, increased efficiency standards, or the adoption of cap and trade regimes. If adopted in Argentina, these requirements could make our products more expensive as well as shift hydrocarbon demand toward relatively lower-carbon sources such as renewable energies.

We may also face opposition from local communities and negative media attention that could materially disrupt our operations. Although we are committed to operating in a socially responsible manner, several of our operations are carried out in regions where community relations present significant risks. Local communities, including indigenous communities, have engaged in various forms of protest against business activities in general, including oil and gas. We cannot ensure that any form of protest, including roadblocks, actions limiting access of our workers or contractors to our operations, sabotage, or any disruptive action will not impact our operations. Any such action could have an adverse effect on our reputation, financial condition, and results of operations, including our ability to service financial debt obligations.

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Limitations on local pricing in Argentina may adversely affect our operational results

In recent years, due to regulatory, economic and government policy factors, domestic prices of crude oil, gasoline, diesel and other fuels have differed substantially from the prices for such products prevailing on the international and regional markets, and our ability to increase or maintain prices to adjust to international price or domestic cost variations has been limited. See “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework”.

The natural gas market in Argentina is subject to government regulations that could adversely affect our results. In particular, gas prices for residential consumers still remain subject to subsidies, and sale prices to electric power generation plants are also subject to regulatory constraints. These pricing limitations, combined with CAMMESA’s competitive bidding processes for power generation supply, have intensified competition and reduced demand from other market segments, resulting in fewer firm commitments and/or shorter contract terms. We cannot assure you that additional regulations affecting local natural gas prices will not be imposed in the future.

We cannot assure you that we will be able to maintain or increase the domestic prices of our products, and limitations on our ability to do so could adversely affect our financial condition and operational results. Similarly, we cannot affirm that hydrocarbon prices in Argentina will track increases or decreases in hydrocarbon prices in the international or regional markets. Discrepancies between domestic and international prices may adversely affect our financial condition and operational results.

We are exposed to contractions in the crude oil and natural gas demand and to contractions in the demand for any of their by-products

Crude oil and natural gas demand are highly influenced by economic activity and growth locally and globally. While demand increased in the past, it has also experienced significant contraction and is subject to future volatility. Crude oil by-products demand may also contract under certain conditions, particularly during economic downturns. According to the latest OPEC estimates in December 2025, global demand for crude oil is expected to increase by 1.4 million barrels per day during 2026, but such expectations may not materialize due to the current world conflicts. See “External shocks and “contagion” effects could have an adverse effect on the Argentine economy”.

A further contraction in demand or the maintenance of current demand levels for long periods of time could negatively affect our results of operations.

Risks Related to Our Generation Business

Government intervention in the electricity sector may have an impact on our business operations, financial condition and/or results of operations

Historically, the Argentine Government has exerted significant influence on the economy, including the energy sector, and companies like us that operate in this sector have done so in a highly regulated context that aims mainly at guaranteeing the supply of domestic demand.

To address the Argentine economic crisis in 2001 and 2002, the Argentine Government adopted the Public Emergency Law No. 25,561 (the “Public Emergency Law”) and other regulations, which made a number of material changes to the regulatory framework applicable to the electricity sector and tariffs on public services. Over the years, the energy sector was one of the sectors most affected by the economic policies that the Argentine Government adopted from the crisis of 2001 onwards. At that time, a freeze on natural gas and electricity rates was imposed, which disincentivized investments in the sector. The Argentine government tried to boost investment by subsidizing energy consumption, but these measures were ineffective and caused both oil and gas production and electricity generation, transmission and distribution to stagnate, while consumption continued to grow. The energy crisis led to a scarcity scenario. The National Government’s response was to increase energy imports, generating adverse consequences for the trade balance and the international reserves of the BCRA. These measures severely affected electricity generation, distribution and transmission companies. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework”.

Since taking office, and particularly during 2025, the current administration has pursued broad deregulation of the Argentine economy, including the electricity sector through measures such as the DNU No. 70/23, the Bases Law and SE Resolution No. 400/25. These measures seek to reduce restrictions on the supply of goods and services and to promote market-based pricing across various sectors of the economy. While certain of these reforms could benefit our business, many are recent and their full impact on the electricity sector remains uncertain.

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Accordingly, we cannot assure you that such measures will correct problems in the generation, transportation and distribution of energy in Argentina. Similarly, we cannot assure you that certain other regulations or measures that may be adopted by the Argentine Government will not have a material adverse effect on our business and operational results or on the market value of our shares and ADSs or that the Argentine Government will not adopt further emergency legislation or other similar regulations in the future that may increase our obligations, including increased taxes, unfavorable alterations to our tariff structures or remuneration scheme and other regulatory obligations, compliance with which would increase our costs and may have a direct negative impact on our operational results and cause the market value of our ADSs and our common shares to decline.

We could be adversely affected by limited electricity transmission and distribution capacity or sudden increases or decreases in energy demand in the short or medium term

From 2002 to 2016, electricity demand in Argentina grew significantly, driven mainly by the relatively low cost, in real terms, of electricity for consumers due to subsidies from the Argentine Government. As a result, electricity demand grew faster than the structural expansion of electricity generation, transmission, and distribution capacities, which led, on certain occasions, to power shortages and disruptions, including blackouts in Buenos Aires and other cities across Argentina. Moreover, although certain investments were made in recent years particularly in electricity generation, the general condition of the Argentine electricity market provided little incentive to further invest in expanding generation, transmission, and distribution capacities, since such investments require material long-term financial commitments. In particular, the amount of energy that generators can deliver at any given time is directly constrained by the capacity of the transmission and distribution systems.

The current administration has stated that one of its main goals is to reduce public expenditure through the application of a zero-deficit policy (see “The policies or measures adopted by the Argentine Government from time to time may adversely affect the Argentine economy and the sectors in which we operate”). This has resulted in cuts to electricity subsidies and, consequently, tariff increases (see “Item 4. The Argentine Energy Sector – Electricity Regulatory Framework”). Notwithstanding these developments, it is still necessary to make several investments in the transmission and distribution system to guarantee the delivery of electricity to users and reduce the frequency of interruptions. Although the current administration has recently enacted several measures intended to deregulate the energy sector and, in turn, attract new investments in the sector (see “Government intervention in the electricity sector may have an impact on our business operations, financial condition and/or results of operations”), such measures may not achieve their intended results. A sustained increase in electricity demand could give rise to future shortages.

We cannot guarantee that we will not experience a lack of dispatch from our generation units due to transmission and distribution limitations, or that government interventions, measures, and regulations in the energy sector related to transmission and distribution will not adversely affect our business, our results of operations, and our financial condition and cause the market value of our ADSs and our common shares to decline.

Our power generation plants may be subject to new regulations that require additional investments, or adversely affect their dispatch

Certain regulations, particularly environmental (e.g. emissions limits, prohibitions to use certain consumables or materials, etc.) and public safety (e.g. public roads and railway crossings) regulations, may vary from time to time, which may require unplanned investments in our power plants to adapt to any new requirements. We cannot assure you that these measures or any future measures will not lead to our recording lower revenues and operational results as a result of the new investments or lack of availability or dispatch until such investments are made.

Measures encouraging renewable and nuclear energy generation projects may affect our generation sales

Law No. 27,191 was enacted on October 15, 2015, determining, among other things, that by December 31, 2025, 20% of the total domestic energy demand must be sourced from renewable energy sources. In order to meet such goal, the statute required wholesale users and CAMMESA to cover their respective portion of domestic energy demand with renewable sources of energy at 8% by December 31, 2017. The percentage of domestic energy demand required to be covered by renewable energy increases every two years, reaching 20% by 2025. The statute also includes tax and other benefits for new renewable energy projects. The 2025 deadline has now expired, creating uncertainty whether the tax incentives and other benefits for renewable energy projects will be extended, modified, or eliminated, any of which could affect the competitive dynamics of the generation market and our operational results.

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Additionally, ME&M Resolution No. 281/17 regulated contracts for energy of renewable sources among WEM agents. Pursuant to Resolution No. 306/25, such regulatory authority was delegated to the Undersecretariat of Electricity. Such resolution allows GUMA and GUME to purchase their total energy demand from a generator of renewable sources that made an investment in generation (see “Item 4. Our Generation Business - Renewable Energy”). However, we cannot make any assurances that the implementation of this law and its regulation will not affect our generation sales, particularly sales under the Energy Plus regime, which, in turn, could adversely affect our operational results and financial condition.

On December 20, 2024, President Javier Milei announced the “Argentine Nuclear Plan”, outlining a policy agenda that would construct new nuclear reactors across the country in a bid to fuel energy-intensive artificial intelligence projects. In 2025, the Government also publicly discussed attracting private investment into the nuclear sector, including through plans to partially privatize the state nuclear operator Nucleoeléctrica Argentina. An increase in nuclear energy production could potentially impact our generation sales.

Our ability to generate electricity in our thermal generation plants depends on the availability and price of natural gas and other fuels, and any disruption to our fuel supply or the regulatory framework governing its procurement could materially adversely affect our operational results

Several of our generation facilities are equipped to run solely on gas and, in the event that gas becomes unavailable, these facilities will not be able to switch to other types of fuel in order to continue generating electricity. The supply or price of gas used in our generation business has been and may from time to time continue to be affected by, among others, the availability of gas in Argentina, our ability to enter into contracts with local gas producers and gas transportation companies, and the need to import a larger amount of gas at a higher price than the price applicable to domestic supply in the event of a shortage in domestic production.

In addition, our ability to procure fuel, manage fuel costs and operate our thermal plants depends in part on the regulatory framework applicable to fuel supply and dispatch in Argentina. In December 2023, through Decree No. 55/23, the Argentine Government declared an emergency with respect to electricity generation, transmission and distribution, as well as natural gas transportation and distribution, until December 31, 2024. That emergency was later extended by Decree No. 370/25 until July 9, 2026 and, with respect to natural gas transportation and distribution, by Decree No. 49/26 until December 31, 2027. Against this backdrop, the rules applicable to fuel supply and dispatch for thermal generators have continued to evolve.

The dispatch scheme established by Plan Gas.Ar that divided the dispatch of thermal generators into five categories according to the source of the natural gas supply was recently abrogated. According to SE Resolution No. 21/25, power generators may, as of March 1, 2025, supply their own fuels and their dispatch will be conditioned on their “Variable Production Cost” (“Costo Variable de Producción” or “CVP”). As a result, our dispatch may be affected by, and will depend in part on, whether our CVP remains competitive.

Following SE Resolution No. 400/25, which introduced new rules for the normalization of the WEM and No. 501/25, the supply of fuel for generators was decentralized from CAMMESA to each generator. CAMMESA remains the supplier of last resort. SE Resolution No. 400/25 includes a gradual transition toward decentralized fuel management. Under this framework, generators will progressively assume responsibility for procuring natural gas and alternative fuels, with full mandatory self-management starting January 1, 2029. During the transition period, generators may either access natural gas through CAMMESA under the “GN Agreement” or procure their own supply; but cost recovery will depend on their declared CVP and competitive dispatch. Generators that fail to manage their own fuel will face restrictions, such as exclusion from the Term Market and reduced remuneration, which could reduce dispatch opportunities and associated revenues.

Additionally, SE Resolution No. 501/25 allows natural gas producers and electricity generators to agree on their natural gas supply by taking on the volumes committed under the Plan Gas.Ar contracts between producers and CAMMESA. Such volumes shall be treated as generators’ own gas and remunerated according to the declared CVP for dispatch, as well as for the determination of the generator’s income. Moreover, WEM supply agreements under SEE Resolution No. 287/17 also require that the generator cover its fuel supply. If we cannot guarantee our fuel supply, penalties under such supply agreements may apply, which, together with any resulting lower production of the relevant generation units, could adversely affect our operational results. See “Item 4. The Argentine Energy Sector – Electricity Regulatory Framework”.

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These changes may require significant operational and contractual adaptations and could expose us to market risks and price volatility once centralized procurement ends. If we are unable to purchase gas at prices that are favorable to us, if the supply of gas is reduced or if CAMMESA does not provide gas to our generation facilities, our costs could increase or our ability to profitably operate our generation facilities could be impaired. Any disruption or inability to acquire the necessary fuels for our generation business could, in turn, materially adversely affect our operational results and financial condition and the market value of our ADSs.

We may be subject to penalties under our energy supply agreements with CAMMESA and/or WEM Large Users

We have executed several energy supply agreements with CAMMESA under which a breach of our commitments may adversely affect the revenues derived from such agreements, including: (i) a breach of the availability commitments set forth in our WEM supply agreements under SE Resolution No. 220/07, SEE Resolution No. 21/16, SEE Resolution No. 287/17 and SE Resolution No. 59/23 allows CAMMESA to apply penalties to us that may adversely impact the revenues derived from such agreements, which in turn may adversely affect our results or reduce the capacity payments under the relevant PPA; and (ii) a breach of the energy delivery commitments set forth in PEA’s PPA allows CAMMESA to apply penalties that may adversely impact the revenues derived from such agreements and, ultimately, result in an obligation to sell the assets involved in the operation of the wind farm, which in turn may adversely affect our results. See “Item 4. Our Generation Business - Renewable Energy” and “Electricity Regulatory Framework”.

Moreover, in the agreements with WEM Large Users, a breach of certain conditions may cause the early termination of such agreements or the application of penalties if: (i) the generator loses its authorization to act as a generator in the WEM, initiates bankruptcy proceedings, suffers judicial intervention, or certain other events occur, which could adversely affect our operational results; or (ii) the generator does not meet the energy committed under the DoP set forth in the agreements. Any early termination or other penalties that could be applied may adversely affect the revenues derived from such agreements and our generation units.

We may be subject to sanctions for breaches of applicable regulations or for failing to obtain the required permits and authorizations for our operating or new power generation units

Our generation units are subject to extensive regulation by local, provincial and national authorities. A breach of such regulations or the impossibility or delay to obtain and keep the relevant permits and authorizations may result in sanctions, including fines, which could affect our operational results if they were to be imposed. Also, our expansion projects require several permits and authorizations to be obtained at scheduled dates to accomplish entry into commercial operations at the estimated dates. We have experienced several delays from relevant authorities in the issuance of such permits and authorizations and could face such delays in the future.

We cannot assure you that, even if fulfilling any and all legal requirements, relevant permits would be granted as scheduled. This could mean delays of the entry into commercial operations of new projects that, in turn, may result in sanctions, penalties, loss of dispatch priorities, loss of sales and increased costs and payments, which would affect our operational results and adversely affect the availability and revenues derived from our generation units.

Likewise, we cannot assure you that new environmental protective regulation would not prevent us from obtaining the relevant permits and authorizations for the development of new projects.

Revenues from our renewable generation assets depend on meteorological and hydrological conditions, as well as on our ability to contract the energy produced and maintain the applicable dispatch priorities

The electricity generation from our renewable assets, including our wind farms and hydroelectric plants, depends on prevailing meteorological and hydrological conditions, which are inherently variable and beyond our control. Lower-than-expected wind speeds may reduce electricity generation at our wind farms and could result in breaches of our sales commitments with CAMMESA, in the case of PEA, and with WEM Large Users, in the case of PEPE II, PEPE III, PEPE IV and PEPE VI. Such breaches could lead to the imposition of penalties payable to our customers, which vary depending on the contractual arrangements applicable to each project, and could adversely affect our revenues and results of operations. Additionally, severe meteorological events may cause outages, curtailed operations, or damage to our power generation assets requiring extensive remediation measures and work. See “Natural disasters, pandemics, catastrophic events, terrorist attacks and operational failures could disrupt our assets and impair our ability to fulfill contractual commitments”.

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In addition, the ability of PEPE II, PEPE III, PEPE IV and PEPE VI to fully monetize their estimated energy generation depends on their ability to contract such generation with WEM Large Users and on each project maintaining its applicable priority dispatch. If a project were to lose its priority dispatch, or if it were otherwise unable to contract its energy generation with WEM Large Users, the uncontracted energy would be sold under the spot market remuneration scheme, which may result in lower prices. Our ability to contract the energy generated by these projects may also be adversely affected by regulatory measures adopted by CAMMESA or other relevant authorities. For example, measures affecting the ability of WEM Large Users to comply with their renewable energy purchase obligations through the “Group Purchase Mechanism” (Mecanismo de Compra Conjunta) could reduce demand for renewable energy from MATER projects and negatively affect our operational results.

Similarly, the operations of our hydroelectric generation plants (HINISA, HIDISA and HPPL) are dependent on hydrological conditions, which we cannot fully predict. Since 2006, the year in which our hydroelectric facilities recorded their highest water intake levels, hydrological conditions have been generally unfavorable, with particularly adverse conditions recorded in 2014, when water intake at HINISA and HIDISA was 62% and 64% lower, respectively, than in 2006. A prolonged period of poor hydrological conditions could reduce electricity generation at our hydroelectric plants and, in the event of electricity shortages, could lead the Argentine government to implement electricity conservation measures, mandate reductions in electricity generation or consumption, or prioritize electricity generation from thermal plants that use fossil fuels in order to preserve water resources for future use. While such measures could benefit our thermal generation assets, they would negatively affect our hydroelectric operations.

Moreover, if water levels at the dams of our hydroelectric facilities were to decrease to the minimum thresholds established under the applicable concession agreements, the relevant local water authorities, including the Province of Mendoza and the Interjurisdictional Authority (Autoridad Interjurisdiccional de Cuenca or “AIC”), would assume control over the amount of water that may be dispatched in order to ensure the continuity of other priority uses, such as human consumption and irrigation.

Any of the foregoing factors could reduce revenues in our generation business and have a material adverse effect on our financial condition, results of operations and the market value of our shares and ADSs.

Operational difficulties could limit our ability to generate electricity, which could adversely affect our operational results

We may experience operational difficulties that could require us to temporarily suspend operations or otherwise affect our ability to generate electricity and, as a result, adversely impact our operating results. These difficulties may affect our generation equipment, electromechanical components or, in general, any of our assets required for the supply of electricity. We cannot make any assurances that events of such nature will not occur in the future. While we maintain comprehensive insurance for each of our facilities, we cannot make any assurances that the amounts for which we are insured or the amounts that we may receive under such insurance policies would cover all of our losses. If operational difficulties prevent our electricity generation, the disruption may lead to reduced revenues from our generation business, which would have an adverse effect on our operational results and may negatively affect the market value of our shares or ADSs.

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We may face extra costs due to the termination of the concession agreements for HINISA, HIDISA and/or HPPL

The initial concession agreements for HINISA and HIDISA terminated on June 1 and October 19, 2024, respectively. Since those dates, we have operated the facilities under a one-year extension provided for in each concession agreement.

With respect to HINISA, in May 2025, the Province of Mendoza enacted Law No. 9,630, which declared an emergency for HINISA for a 14-month term due to the flood that occurred in January 2025, thereby extending the one-year period provided in the concession agreement. The Province of Mendoza incorporated a new corporation called “Hidroelectricidad Mendocina” that will become the future owner of the Nihuiles assets upon the termination of the concession and its extensions and the reversion of the assets.

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.

In the case of HPPL, the concession is expected to expire in the year 2029. We cannot assure that, upon expiration of the concession, we will be able to renew such concession.

In all three cases, we expect to incur additional costs and investments in connection with the reversion of the assets, which may adversely affect our operational results.

At the time of CPB’s privatization in 1997, the Province of Buenos Aires agreed to expropriate and transfer to CPB the real property on which the plant was built and to create administrative easements in our favor over the third-party lands through which a gas pipeline and an electricity transmission line run. Although the Province of Buenos Aires is in the process of expropriating the property on which the plant is built, as of the date of this annual report, it had not transferred all of the real property with clear and marketable title to us. In addition, the Province of Buenos Aires has not created administrative easements for CPB’s gas pipeline or the electricity transmission line. In July 2008, we sued the Province of Buenos Aires seeking the creation of the administrative easements in our favor. We have received several complaints from third parties seeking compensation for the use of this land. If the Province does not complete the expropriation process or the administrative easement process, we may be exposed to judicial claims by third parties seeking compensation or damages for which we have not established a provision in our consolidated financial statements. If we were required to pay material damages or compensation for the right to use this real property as a result of adverse outcomes from legal proceedings, we could be required to use cash from operations to cover such costs, which could have a materially adverse effect on our financial condition and consolidated operational results and cause the market value of our ADSs to decline. This risk extends to our thermal generation plant CTIW which is constructed on CPB’s real property.

The national antitrust authorities could decide not to approve the acquisition of the CTEB

In 2019, Pampa and YPF were jointly awarded the National and International Public Bid No. CTEB 02/2019, which was launched through SGE Resolution No. 160/19, regarding the sale and transfer by IEASA (now ENARSA) of the goodwill of the CTEB (the “CTB Transaction”). The transaction closed on June 26, 2019.

As of the date of this annual report, the CTB Transaction has not been approved by the national antitrust authorities. In the event that the CTB Transaction is not approved, the business, the financial situation and the results of the operations of the Company could be substantially and adversely affected. Further, the Company could even be forced to reverse and unwind such transactions and undo all their effects.

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Our profits may be affected by the cancellation of the Energy Plus Program

The enactment of SE Resolution No. 21/25 established a deadline for the execution of new contracts or the renewal of supply agreements under Energy Plus Contracts. Since November 2025, we have been unable to execute new energy supply contracts under such program and, consequently, if we cannot allocate such energy under new supply contracts within the new regulatory scheme, our revenues could be affected. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework”.

Our energy projects may not perform as expected

Our energy projects and other operating assets may not continue to perform as they have in the past and there is a risk of equipment failure due to wear and tear, latent defect, design error, operator error, extreme weather events or early obsolescence, among other things, which could have an adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow. Equipment failure at our assets could also result in significant personal injury or loss of life, damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations. This could be on a large scale, such as the failure of a wind turbine or on a small scale, such as equipment catching on fire. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties as well as reputational harm.

In addition, certain defects may be detected on the wind turbines used in our energy projects, that could potentially affect their effectiveness and generation capacity and, in turn may affect the operations of our wind farms. These defects could eventually affect our wind farm operations and have an adverse effect in the compliance of their energy supply agreements and, ultimately, on the business, our financial condition, operational results or our ability to pay our debts. While our projects meet rigorous quality standards, there can be no assurance that such projects will not experience operational process or product failures and other problems, including as a result of outdated technology, or through manufacturing or design defects, process or other failures of contractors or third-party suppliers, cyber-attacks or other intentional acts that could result in potential product, safety, regulatory or environmental risks.

We may face competition in the electricity sector and related industries

Numerous strong and capable participants characterize the power generation markets in which we operate, many of which may have extensive and diversified developmental or operating experience and financial resources similar to or significantly greater than ours. The recent enactment of SE Resolution No. 400/25 is expected to increase competition in the generation segment. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework”. The effects of such new regulatory scheme and any future amendments could cause reductions in prices and increase acquisition prices for fuel, raw materials and existing assets and, therefore, adversely affect our results of operations and financial condition.

Our ability to compete effectively is further constrained by infrastructure limitations, We, and our competitors, are connected to the same electrical grid that has limited capacity for transportation, which, under certain circumstances, may reach its capacity limits. Therefore, new generators may connect, or existing generators may increase, their outputs and dispatch more electric power to the same grid that would prevent us from delivering our energy to our customers. In addition, the Argentine Government might not make the necessary investments to increase the system’s capacity. In fact, the Argentine Government has recently enacted legislation to promote private funding of transmission investments, granting reserved transmission capacity to funding parties, which could place us at a competitive disadvantage.

Moreover, under the current regulatory framework, renewable energy contracts entered into by Large Users of the WEM through the MATER mechanism benefit from a reduction in the cost of capacity purchases in the spot market, as renewable energy contracts do not provide capacity backup. In contrast, thermal energy contracts do not have such benefit. As a result of this differential regulatory framework, our profitability and the competitiveness of our thermal generation assets participating in the contract market could be adversely affected.

As a result, an increase in competition could affect our operations, which would adversely affect our results of operations and financial condition.

Risks arise for our business from technological changes in the energy market

The energy market is subject to far-reaching technological change, both on the generation and demand sides. With respect to energy generation, examples include the development of energy storage devices (battery storage in the megawatt range) or facilities for the temporary storage of power through conversion to gas (so-called “power-to-gas-technology”), the increase in energy supply due to new technological applications such as fracking or the digitalization of generation and distribution networks. New technologies to increase energy efficiency and improve heat insulation, for the direct generation of power at the consumer level, or that will enhance refeeding (for example, by using power storage for renewable generation) may, on the demand side, lead to structural market changes in favor of energy sources with low or zero carbon dioxide emissions or in favor of decentralized power generation, (for instance, via small-scale power plants within or close to residential areas or industrial facilities).

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If our business cannot react to changes caused by new technological developments and the associated changes in market structure, these changes may have an adverse effect on our operational results.

Our suppliers may not be able to provide spare parts and/or upgrades to our generation units

We cannot assure you that the manufacturers of our generation units and their suppliers will provide in a timely manner the spare parts and/or upgrades required for the maintenance of such equipment. Consequently, in case of outage of a unit, the term for its entry into service shall be longer than expected or alternative solutions would be required. Such situations might affect our operations and have an adverse effect in the compliance of the relevant energy supply agreement and, ultimately, on the business, our financial condition, operational results or our ability to pay our debts.

We have executed several energy supply agreements with CAMMESA under SE Resolution No. 220/07, SEE Resolution No. 21/16, SEE Resolution 287/17 and RenovAr Programs. Such PPAs could be revoked, modified or in any other way affected by any measure adopted by the Argentine Government. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework”. Also, we could not be able to renew our PPAs or enter into new PPAs.

We cannot assure you that we will be in a position to renew our PPAs or execute new PPAs under the same economic conditions, or that such PPAs will not be unilaterally modified or resolved or that certain other regulations or measures that may be adopted by the Argentine Government in connection with the electricity regulatory framework will not have a material adverse effect on our business, operational results and financial condition.

The generation activity involves the handling of dangerous elements such as fuels that have an associated potential risk for premises and people

Although we comply with all standards and best practices related to environmental safety, an accident involving materials with which we operate could have environmental consequences and cause harm to people and/or damage our or third-party facilities. This could in turn result in the unavailability of our equipment and, consequently, could affect our financial condition and our operational results.

Risks Related to our Shares and ADSs

Previous national administrations have established restrictions on the conversion of Argentine currency into foreign currencies and on the remittance to foreign investors of proceeds from their investments in Argentina. Conversion of dividends, distributions, or the proceeds from any sale of shares from Pesos into U.S. Dollars, as well as the transfer of those funds abroad, is limited (see “Item 10. Additional Information - Exchange Controls”). Future restrictions on the movement of capital to and from Argentina such as those that previously existed could, if reinstated, impair or prevent the conversion of dividends, distributions, or the proceeds from any sale of shares, as the case may be, from Pesos into U.S. Dollars and the remittance of such U.S. Dollars abroad. Also, certain of our indebtedness includes covenants limiting the payment of dividends.

The current administration has reiterated its commitment to abolish all currency restrictions however, as of the date of this report, many such restrictions remain in place. We cannot assure you that the remaining restrictions will be lifted or that additional restrictions will not be imposed in the future. In such a case, the depositary for the ADSs may hold the Pesos it cannot otherwise convert for the account of the ADS holders who have not been paid. In addition, any future adoption by the Argentine Government of restrictions on the movement of capital out of Argentina may affect the ability of our foreign shareholders and holders of ADSs to obtain the full value of their shares and ADSs and may adversely affect the market value of our shares and ADSs.

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ADS holders’ ability to receive cash dividends may be limited

Our shareholders’ ability to receive cash dividends may be limited by the ability of the depositary to convert cash dividends paid in Pesos into U.S. Dollars. Under the terms of our deposit agreement with the depositary for the ADSs, the depositary will convert any cash dividend or other cash distribution we pay on the common shares underlying the ADSs into U.S. Dollars, if it can do so on a reasonable basis and can transfer the U.S. Dollars to the United States. If this conversion is not possible or if any government approval is needed and cannot be obtained, the deposit agreement allows the depositary to distribute the foreign currency only to those ADS holders to whom it is possible to do so. If the exchange rate fluctuates significantly during a time when the depositary cannot convert the foreign currency, shareholders may lose some or all of the value of the dividend distribution.

Under Argentine law, shareholder rights may be fewer or less well-defined than in other jurisdictions

Our corporate affairs are governed by our bylaws and by LGS, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States, such as the States of Delaware or New York, or in other jurisdictions outside Argentina. In addition, the rights of holders of the ADSs or the rights of holders of our common shares under LGS to protect their interests relative to actions by our board of directors may be fewer and less well-defined than those under the laws of those other jurisdictions. Although insider trading and price manipulation are illegal under Argentine law, the Argentine securities markets are not as highly regulated or supervised as the U.S. securities markets or markets in some other jurisdictions. In addition, rules and policies against self-dealing and regarding the preservation of shareholder interests may be less well-defined and enforced in Argentina than in the United States, putting holders of our common shares and ADSs at a potential disadvantage.

Holders of ADSs may be unable to exercise voting rights with respect to the common shares underlying the ADSs at our shareholders’ meetings

Shares underlying the ADSs are held by the depositary in the name of the holder of the ADS. As such, we will not treat holders of ADSs as one of our shareholders and, therefore, holders of ADSs will not have shareholder rights. The depositary will be the holder of the shares underlying the ADSs and holders may exercise voting rights with respect to the shares represented by the ADSs only in accordance with the deposit agreement relating to the ADSs. There are no provisions under Argentine law or under our bylaws that limit the exercise by ADS holders of their voting rights through the depositary with respect to the underlying shares. However, there are practical limitations on the ability of ADS holders to exercise their voting rights due to the additional procedural steps involved in communicating with these holders. For example, holders of our shares will receive notice of shareholders’ meetings through publication of a notice in the Official Gazette, an Argentine newspaper of general circulation and the daily bulletin of the BASE and will be able to exercise their voting rights by either attending the meeting in person or voting by proxy. ADS holders, by comparison, do not receive notice directly from us. Instead, in accordance with the deposit agreement, we provide the notice to the depositary. If we ask it to do so, the depositary will mail to holders of ADSs the notice of the meeting and a statement as to the manner in which instructions may be given by holders. To exercise their voting rights, ADS holders must then instruct the depositary as to voting the shares represented by their ADSs. Due to these procedural steps involving the depositary, the process for exercising voting rights may take longer for ADS holders than for holders of shares, and shares represented by ADSs may not be voted as the holders of ADSs desire. Shares represented by ADSs for which the depositary fails to receive timely voting instructions may, if requested by us, be voted at the corresponding meeting either in favor of the proposal of the board of directors or, in the absence of such a proposal, in accordance with the majority.

Our shareholders may be subject to liability for certain votes of their securities

Because we are a limited liability corporation, our shareholders are not liable for our obligations. Shareholders are generally liable only for the payment of the shares they subscribe. However, shareholders who have a conflict of interest with us and who do not abstain from voting at the respective shareholders’ meeting may be liable for damages to us, but only if the transaction would not have been approved without such shareholders’ votes. Furthermore, shareholders who willfully or negligently vote in favor of a resolution that is subsequently declared void by a court as contrary to the law or our bylaws may be held jointly and severally liable for damages to us or to other third parties, including other shareholders.

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Provisions of our bylaws and of Argentine securities laws could deter takeover attempts and have an adverse impact on the price of our shares and the ADSs

Our bylaws and Argentine securities laws contain provisions that may discourage, delay or impair a change of control of our Company, such as the requirement, upon the acquisition of a controlling interest in our capital stock, to launch a mandatory tender offer to acquire all our voting stock and any securities convertible into, or entitling the holder thereof to subscribe for or acquire, any voting shares in our capital stock. These provisions may delay, defer or prevent a transaction or a change of control that might otherwise be in the best interest of our shareholders and may adversely affect the market value of our shares and ADSs. In addition, the provisions of our bylaws and of Argentine securities laws with respect to the obligation to launch a mandatory tender offer differ in certain respects; as of the date of filing of this annual report, it is unclear whether the provisions of our bylaws, which might be more beneficial to minority shareholders under certain circumstances than the provisions of Argentine securities laws in effect as of the date hereof, would prevail over the provisions of Argentine securities laws.

A non-U.S. corporation will be a passive foreign investment company (“PFIC”) if, in any particular year, either (i) 75% or more of its gross income for such year consists of certain types of “passive” income or (ii) 50% or more of the value of its assets (generally determined on the basis of a quarterly average) is attributable to assets that produce or are held for the production of passive income.

Based on our Consolidated Financial Statements and relevant market and shareholder data, we believe that we were not a PFIC for U.S. federal income tax purposes in 2025. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not expect to become a PFIC in 2026 or in future taxable years. However, because the PFIC tests must be applied each year, and the composition of our income and assets and the value of our assets may change, it is possible that we may be a PFIC in the current or a future year. In particular, because the value of our assets may be determined for purposes of these tests by reference to the market price of our common shares or ADSs, fluctuations in the market price of our common shares or ADSs may cause us to become a PFIC.

If we are a PFIC in any taxable year, during which a U.S. holder (as defined in “Taxation - United States Federal Income Tax Considerations”) holds our shares or ADSs, certain materially adverse U.S. federal income tax consequences could apply to such U.S. holder. See “Item 10. Additional Information – Taxation - United States Federal Income Tax Considerations - Passive Foreign Investment Company Rules”. U.S. holders should consult their own tax advisor regarding the potential application of the PFIC rules to an investment in our shares or ADSs.

For more information, see “Item 10. Additional Information – Taxation - United States Federal Income Tax Considerations - Passive Foreign Investment Company Rules”.

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Item 4.

Information on the Company

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.”

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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.

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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.

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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.

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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.

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.”

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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.

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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.

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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.

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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.

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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

468

Pampa

85.00%

2025

Las Tacanas Norte

Neuquén

NQN

Pampa

90.00%

2027

Total Exploration Blocks

468

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

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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.

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.”

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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.”

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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.

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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.

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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.

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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%.

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.

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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.

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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.

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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.

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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.

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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
Summary of Electricity Generation Assets	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).

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Summary of Electricity Generation Assets	Thermal
Summary of Electricity Generation Assets	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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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.

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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.

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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.

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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.

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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.

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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):

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:

Conventional exploitation concession: 25 years;

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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:

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.

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.

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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.

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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:

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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”).

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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.

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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.

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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.

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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.

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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.

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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.

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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 1^st, 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.

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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.

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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)
Thermal / Period	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)
Hydrological – Technology / Scale	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

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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

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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

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.

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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.

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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

U.S.$./ MW

0.5

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.

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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

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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.

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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.

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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.

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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.

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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.

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Item 4A.

Unresolved Staff Comments

Not applicable.

Item 5.

Operating and Financial Review and Prospects

This section contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in “Note 6.1 - Critical accounting estimates and judgments” of our Consolidated Financial Statements “Forward-Looking Statements” and “Item 3. Key Information - Risk Factors” and the matters set forth in this annual report generally.

The following discussion is based on, and should be read in conjunction with, our Consolidated Financial Statements and related notes contained in this annual report.

Sources of Revenues

Oil & Gas

Our oil and gas operations derive revenues from the sale of natural gas to CAMMESA and gas distributors and from the sale to oil and gas industrial clients in the domestic market and to a lesser extent in the foreign market. Revenues are recognized when the control of these products is transferred.

Generation

Our generation operations derive revenues from the sale of electricity sales contracts with large users within the MAT, supply agreements with CAMMESA and sales to the spot market. Revenues are recognized when power plants are available and the delivery of energy is effective.

Petrochemicals

Our petrochemicals operations generate revenues from the sale of styrene, polystyrene and elastomers, and plastics derived from oil production. We produce a wide array of products, such as intermediate gasoline, aromatic solvents, hexane and other hydrogenated paraffinic solvents, propellants for the cosmetic industry, monomer styrene, as well as rubber and polymers for both the domestic and foreign markets from natural gas, virgin naphtha, propane and other supplies. Revenues are recognized when the control of these products is transferred.

Holding and others segment

Our holding and others segment generate revenues mainly from contracts with customers in relation to technical assistance and administration services to related companies.

Factors Affecting Our Results of Operations

Our results of operations are principally affected by economic conditions in Argentina, changes in local and international crude oil prices, natural gas prices and international petrochemical product’s prices, fluctuations in demand for oil related products, natural gas and electricity in Argentina, costs of sales, operating expenses and climate change. See “Item 3. Key Information - Risk Factors”.

Argentine Economic Conditions

Because most of our operations, facilities and customers are located in Argentina, we are affected by general economic conditions in the country. In particular, the general performance of the Argentine economy affects demand for energy, and inflation and fluctuations in currency exchange rates affect our costs and our margins. Inflation primarily affects our business by increasing operating costs, while reducing our revenues in real terms.

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The following table sets forth key economic indicators in Argentina during the years indicated:

	*Year ended December 31,*
	*2025*	*2024*	*2023*
Real GDP (% change)	4.4%	(1.3)%	(1.6)%
Nominal GDP (in millions of Ps.)	847,622,873	583,909,615	191,404,997
Real Consumption (% change)	7.9%	(2.9)%	1.0%
Real Investment (% change)	16.4%	(17.2)%	(2.0)%
Industrial Production (% change)	1.6%	(9.4)%	(1.8)%
Consumer Price Index	31.5%	117.8%	211.4%
Nominal Exchange Rate (in Ps. /U.S.$ at year end)	1,455.00	1,032.50	808.48
Exports (in millions of U.S.$)	87,111	79,703	66,789
Imports (in millions of U.S.$)	75,791	60,776	73,714
Trade Balance (in millions of U.S.$)	11,320.08	18,927.64	(6,925.1)
Current Account (% of GDP)	(1.5)% **	0.9%	(3.2)%
Reserves (in millions of U.S.$)	41.1	29.6	23.1
Tax Collection (in millions of Pesos)	200,448,447	142,031,453		46,463,191
Primary Surplus (in millions of Pesos)	11,769,219	10,405,810	(5,164,637)
Public Debt (% of GDP at December 31) *	75.6% **	82.6%	156.6%
Public Debt Service (% of GDP)	1.2%	1.5%	1.7%
External Debt (% of GDP at December 31)	56.3% **	49.0%	121.6%

Sources: INDEC; Central Bank; Ministry of Treasury.

*Includes hold-outs ** As of September 30, 2025. *** As of November 2025.

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Macroeconomic Context

2025 was marked by high volatility associated with the economic cycle and midterm elections. This dynamic was reflected in financial markets. Argentina’s country risk began the year at around 578 basis points, peaked at 1,456 in September, and ended the year close to its initial level. Likewise, the wholesale exchange rate closed at Pesos 1,459 per U.S.$ as of December 2025, up 41% from year-end 2024 and 36% year-on-year.

Despite the challenging environment, the Government maintained a fiscal surplus for the second consecutive year, a cornerstone of its economic plan. In 2025, the accumulated primary balance reached 1.4% of GDP and the financial balance 0.2% of the GDP. As a result, inflation continued on a downward path and ended the year at 31.5% annually, the lowest level since 2017, following 117.8% in 2024 and 211.4% in 2023. According to the Central Bank’s Market Expectations Survey (REM), inflation is expected to continue decelerating and hover around 20% in 2026, consolidating the price normalization process. Disinflation also led to a reduction in the poverty rate, which fell from 53% in the first quarter of 2024 to 30% in 2025.

Even amid persistent fiscal adjustment, economic activity grew by 4.6% through the third quarter of 2025 and, according to the REM, is projected to grow by 3.4% in 2026. However, sector performance was heterogeneous: fishing, mining, oil and gas, and financial intermediation led economic expansion, while construction, trade, and manufacturing recorded cumulative declines of 2.2%, 5.7%, and 6.6%, respectively, through September, posing challenges going forward. Nevertheless, the unemployment rate remained stable at around 7.6%.

On the exchange rate front, in February 2025, the crawling peg pace was reduced from 2% to 1% per month. In April, a banded floating exchange rate regime was adopted, with bands widening by 1% per month, and the BCRA was authorized to intervene within them. In addition, exchange rate controls for individuals were partially lifted, the distribution of dividends on 2025 earnings was authorized, import payment terms were relaxed, and the differential exchange rate for exports was eliminated, measures that narrowed the gap between the official and free exchange rates.

In April 2025, an agreement for U.S.$ 20 billion was signed with the IMF, including disbursements of U.S.$ 14.5 billion in 2025, complemented by financing from multilateral organizations. Following exchange rate pressures triggered by an adverse outcome for the ruling party in the Buenos Aires Province elections, the National Government received explicit support from the U.S. Treasury for its policies, which intervened by purchasing Pesos and providing U.S.$ 20 billion in financing. This support proved decisive in preserving the exchange rate regime. Starting in 2026, the exchange rate bands will be adjusted based on monthly inflation with a two-month lag.

Given limited access to international capital markets, the Argentine Treasury continued to repay obligations to creditors. Consolidated gross national debt declined from 169% of GDP in December 2023 to 79% in October 2025, while foreign-currency debt with private creditors fell from 40% to 16% over the same period. These repayments were supported by record foreign currency purchases by the BCRA (U.S.$ 22 billion over two years) and the Treasury (U.S.$ 1.5 billion), as well as by an increase in gross reserves, which rose to U.S.$ 41.2 billion from U.S.$ 23 billion in December 2023. However, net reserves remained negative at -U.S.$ 15.5 billion, compared with -U.S.$ 8.5 billion in December 2023. During 2025, the BCRA eliminated interest-bearing liabilities (monetary issuance), and the Argentine Treasury canceled non-transferable notes, strengthening its balance sheet and generating a crowding-in effect that boosted private-sector credit from 5% to 11% of GDP.

The current account posted a cumulative deficit of U.S.$ 10 billion through the third quarter of 2025, compared to a surplus of U.S.$ 5 billion in the same period of 2024. While the goods trade balance recorded a surplus driven by record exports, partially offset by higher imports, deficits in services and income resulted in an overall negative balance. In the trade balance, the energy sector stands out with a surplus of U.S.$ 7.8 billion, supported by all-time highs in gas and oil production driven by the development of Vaca Muerta.

The Argentine corporate sector increased its access to international markets, with issuances exceeding U.S.$ 9.3 billion.

Finally, after two years, the National Congress approved the 2026 budget, representing an institutional step forward that, among other aspects, authorizes the Argentine Treasury to resume financing in international capital markets.

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Reserves and Production of oil and gas

Natural gas and oil constitute the main energy sources in the national primary energy matrix. The following chart illustrates their shares as of December 31, 2024, as there is no available information for the year 2025:

2024 Argentine energy matrix

100% = 83 million Tons of oil equivalent

Note: It excludes other primary sources for 5.2%. Source: SE.

Natural Gas

In 2025, Argentina’s total gross natural gas production amounted to 137 million m³ per day, a 6% increase compared to 2024. This increase is explained by growth in the Austral and Neuquina Basins.

Total demand grew by 3% year-on-year to 141 million m3 per day, mainly due to higher industrial demand (14% compared to 2024) and a slight increase in power plants’ gas consumption, partially offset by lower Compressed Natural Gas (CNG) and residential demand due to milder weather. Natural gas imports declined sharply by 44% compared to 2024, supported by new evacuation capacity from Vaca Muerta and the reversal of the Northern gas pipeline. Lower imports from Bolivia (from 3.3 to 0.6 million m3 per day on average in 2025) and reduced Liquefied Natural Gas (LNG) injections (from 4.5 to 3.6 million m3 per day on average in 2025) were recorded. In contrast, exports to Chile increased by 13% to 7.3 million m3 per day, representing 5% of total production in 2025.

As of December 31, 2024, the country’s natural gas reserves and resources totaled 2,258 billion m³, a 23% increase compared to 2023. Of the total, 24% were proven reserves, and 83% came from unconventional formations.

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Evolution of natural gas production, and reserves and resources*
In billion m³, 2012-2025

Note: * There is no information on reserves for 2025. Source: SE.

Crude Oil

In 2025, Argentina’s total oil production reached 794 kbpd, a 13% increase compared to 2024 and the highest since 1999. This growth was led by the Neuquina Basin, where production increased by 21% compared to 2024 following the expansion of evacuation capacity from Vaca Muerta in the Oldelval and Oleoducto Transandino S.A. systems. Of total production, 74% came from the Neuquina Basin (584 kbpd), 23% from the Golfo San Jorge Basin (182 kbpd, a 4% decrease compared to 2024) and the remainder from the Cuyana, Austral and Noroeste Basins (27 kbpd, a 7% decrease compared to 2024).

Evolution of oil production, and reserves and resources*

In million boe, 2012-2025

Note: * There is no information on reserves for 2025. Source: SE.

For information about the regulatory framework of our oil and gas business, see “Item 4. The Argentine Energy Sector - Oil & Gas Regulatory Framework.”

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Electricity prices and tariffs

Our revenues and margins in our electricity generation businesses are substantially dependent on the prices we are able to charge for the electricity sold by our generation plants, as well as the composition of our transmission tariffs. See “Item 4. The Argentine Energy Sector - Electricity Regulatory Framework.”

Electricity demand and supply

Electricity demand depends to a significant extent on economic and political conditions prevailing from time to time in Argentina, as well as seasonal factors. In general, the demand for electricity varies depending on the performance of the Argentine economy, as businesses and individuals generally consume more energy and are better able to pay their bills during periods of economic stability or growth. As a result, energy demand is affected by Argentine Governmental actions concerning the economy, including with respect to inflation, interest rates, price controls, foreign exchange controls, taxes and energy tariffs.

Electricity consumption in Argentina experienced a slight 0.7% increase in 2025 when compared to 2024, reaching 141,249 GWh. This was explained by increases of 2% and 1%, respectively, in the industrial and retail segments, partially offset by a 3% decline in the demand from Large Users within the distribution segment. The following chart shows the breakdown of electricity consumption in 2025 by type of customer.

Electricity demand by type of customer

Source: CAMMESA.

Peak Demand Records

	2017	2018	2019	2020	2021	2022	2023	2024	2025
Capacity (MW)	25,628	26,320	26,113	25,791	27,088	28,283	29,105	29,653	30,257
Date	Feb-24	Feb-8	Jan-29	Feb-4	Dec-29	Dec-6	Mar-13	Feb-1	Feb-10
Temperature (°C)	27.7	30.2	34.0	29.5	31.7	29.0	31.0	31.5	31.1
Hour	14:25	15:35	14:25	14:57	14:28	14:43	15:28	14:48	14:47

Source: CAMMESA.

During 2024, power generation grew by 0.5% in 2025, reaching 142,267 GWh, compared to 141,592 GWh recorded in 2024, mainly driven by renewable sources (a 17% increase compared to 2024) and nuclear power availability (a 3% increase compared to 2024), partially offset by a 10% reduction in hydropower generation, net of pumping.

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The grid maintained its dependence on thermal generation, using both natural gas and liquid fuels (GO and FO) and mineral coal, contributing 53% of the total energy volume or 75,225 GWh, followed by hydropower generation net of pumping of 29,622 GWh (21% of the total energy volume), renewable energies with a generation of 26,659 GWh (19% of the total energy volume) and nuclear power with a generation of 10,761 GWh or 8% of the total energy volume.

Although the SADI has been a net power importer for the fourth consecutive year, in 2025 imports decreased by 8% to 4,304 GWh when compared to 2024, exports decreased by 48% to 509 GWh compared to 2024, and losses were reduced by 5% to 4,813 GWh compared to 2024.

The following chart shows the evolution of electric power generation by type of technology:

Generation by Type of Power Plant

In %, 2015 – 2025

Note: It includes WEM and Patagonian WEM System. Hydroelectric power generation net of pumping. Source: CAMMESA.

During 2025, generation facilities recorded an increase in their installed capacity of 826 MW compared to the previous year, reaching a total of 44,177 MW as of December 2025. This increase is mainly due to the commissioning of renewable units ( an increase of 1,006 MW compared to 2024) and 13 MW of thermal additions, offset by the decommissioning of obsolete units ( a decrease of 194 MW compared to 2024). The chart below shows the composition of installed capacity in Argentina as of December 31, 2025:

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2025 Argentine installed power capacity

100% = 44.2 GW

Source: CAMMESA.

Commercial management and fuel supply for power plants were centralized in CAMMESA, except for generators with PPAs under Energía Plus and SE Resolution No. 287/17. Since January 2021, with the implementation of Plan Gas.Ar and the transfer of gas and its transportation by exempted generators to CAMMESA, thermal dispatch prioritized units supplied with gas imported from Bolivia under a Take or Pay condition, followed by those supplied by Plan Gas.Ar according to their efficiency and, finally, units that had assigned gas to CAMMESA.

This framework began to change on January 28, 2025, when the SE repealed SE Resolution No. 354/20, effective as of February 1, 2025, and authorized generators to directly manage fuel supply for spot units, as of March 1, 2025, according to SE Resolution No. 21/25.

On November 1, 2025, SE Resolution No. 400/25 introduced a gradual transition toward a decentralized fuel-supply scheme. Generators will progressively assume full responsibility for fuel sourcing, and, from 2029, the management must be fully autonomous. Generators must provide their own alternative fuels, such as fuel oil and gas oil. For natural gas, thermal generators may choose between: (i) self procurement, or (ii) contracting through CAMMESA while the Plan Gas.Ar remains in force, under “Gas Acuerdo” (or “Gas Agreement”) modality, with costs resulting from a mix of costs associated with Plan Gas and/or LNG imports, subject to biweekly updates. Generators that do not self procure their fuel will face operational restrictions and a progressive reduction in their capacity and energy remuneration. CAMMESA will continue to centralize fuel management for PPAs under SE Resolutions No. 220/07, No. 21/17, and No. 287/17. This transition process may require significant operational and contractual adjustments and will gradually expose generators to greater market risks and price volatility once centralized procurement ends.

Additionally, the SE authorized producers and generators to agree on natural gas supply arrangements, considering the volumes committed under Plan Gas contracts with CAMMESA, according to SE Resolution No. 501/25. Such volumes will be treated as the generators’ own gas and remunerated in accordance with the CVP declared for dispatch purposes.

Regarding fuel consumption by power plants, it decreased by 3% year-on-year in 2025, totaling 44.1 million m3 per day of gas equivalent. Natural gas accounted for 95% of total consumption, with a 1% increase to 42.1 million m3 per day, 94% of which was local and 6% imported. The use of liquid fuels, FO and GO, decreased by 61% and 54%, respectively, due to higher domestic gas production, while mineral coal consumption increased by 5%.

The chart below shows fuel consumption by type:

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Fuel consumption by type

In % and million m³/day of gas equivalent, 2015 – 2025

Source: CAMMESA.

As of December 31, 2025, the maximum spot price of energy in the WEM amounted to Pesos 14,381 (SE Resolution No. 602/25). However, the following chart shows the monthly wholesale price that all electricity system users should pay to prevent the power grid from running into a deficit, as well as the seasonal energy price. The wholesale cost includes, in addition to the energy price, the power capacity payment, generation costs, fuels such as natural gas, FO, GO and mineral coal, and other minor items. As of December 2025, the coverage amounted to 78%.

Wholesale monthly cost and seasonal price

In U.S.$/MWh

Source: CAMMESA, converted into U.S.$ at the official exchange rate.

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Cost of sales

Our most significant costs of sales include purchases of inventory, energy and gas, personnel costs and property, plant and equipment depreciation, works contracts, fees and compensation for services and canons and royalties.

Operating expenses

Our most significant operating expenses are administrative and selling expenses, which include related personnel costs, fees and compensations for services, transportation and freights charges, and taxes.

Results of Operations

The table below provides a summary of our results of operations for the years ended December 31, 2025, and 2024.

	*For the year ended December 31,*
	2025	2024
Revenue	1,998	1,876
Cost of sales	(1,369)	(1,279)
Gross profit	629	597
Selling expenses	(98)	(74)
Administrative expenses	(192)	(239)
Exploration expenses	-	(21)
Other operating income	100	175
Other operating expenses	(72)	(88)
Recovery of impairment (Impairment) of property, plant and equipment, intangible assets and inventories	15	(34)
Impairment of financial assets	(21)	(56)
Share of profit from associates and joint ventures	142	146
Profit from sale/acquisition of companies’ interest	-	34
Operating income	503	440
Finance income	45	32
Finance costs	(196)	(185)
Other financial results	230	211
Financial results, net	79	58
Profit before income tax	582	498
Income tax	(204)	121
Profit of the year	378	619

Total Profit of the year attributable to:
Owners of the Company	377	619
Non - controlling interest	1	-


	2025	2024
Revenue
Oil and Gas	862	730
Generation	792	672
Petrochemical	443	516
Holding and others	24	65
Eliminations	(123)	(107)
Total Revenue	1,998	1,876

Gross profit
Oil and Gas	249	215

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Generation	342	305
Petrochemical	14	29
Holding and others	24	48
Eliminations	-	-
Total Gross profit	629	597


Operating income (loss)
Oil and Gas	91	69
Generation	375	204
Petrochemical	(31)	43
Holding and others	68	124
Eliminations	-	-
Total operating income	503	440

Total profit (loss) of the year
Oil and Gas	(55)	(5)
Generation	298	461
Petrochemical	4	72
Holding and others	131	91
Eliminations	-	-
Total profit of the year	378	619

Total profit (loss) attributable to owners of the company
Oil and gas	(55)	(5)
Generation	297	461
Petrochemical	4	72
Holding and others	131	91
Eliminations	-	-
Total profit attributable to owners of the company	377	619

Total profit attributable to non - controlling interest
Generation	1	-
Total profit attributable to non - controlling interest	-	-

We are a fully integrated power company in Argentina, mainly participating in the oil and gas production and electricity generation businesses.

Through its own activities, subsidiaries and shareholdings in joint ventures and based on the business nature, customer portfolio and risks involved, the Company operates its businesses through following reportable segments:

●

Oil and Gas, principally consisting of the Company’s interests in oil and gas areas, the activities of Pampa Energía S.A. – Sucursal Dedicada Proyecto RDA and through its direct and indirect interests in SESA and PECSA;

●

Electricity Generation, principally consisting of the Company’s direct and indirect interests in HINISA, HIDISA, VAR, CTB, TMB, TJSM and through our own electricity generation activities through thermal plants CTG, CPB, Piquirenda, CTLL, CTGEBA, Ecoenergía, CTPP, CTIW, the HPPL hydroelectric complex and PEPE II, III, IV and VI wind farms;

●

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in Argentina; and

●

Holding, Transportation and Others, principally consisting of our interests in joint businesses CITELEC, CIESA and their respective subsidiaries holding the concession over high-voltage electricity transmission and gas transportation, respectively, as well as our direct and indirect interest in VMOS, Oldelval and OCP Ltd., holding activities, and other investments activities.

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We manage our operating segments based on its individual net result in U.S. Dollars.

Fiscal year ended December 31, 2025 compared to the fiscal year ended December 31, 2024

Oil and Gas Segment

	Oil and Gas (in millions of U.S.$)
	For the fiscal year ended
	December 31, 2025	December 31, 2024	Variation	%
Revenue	862	730	132	18%
Cost of sales	(613)	(515)	(98)	19%
Gross profit	249	215	34	16%

Selling expenses	(80)	(58)	(22)	38%
Administrative expenses	(83)	(82)	(1)	1%
Exploration expenses	-	(21)	21	(100%)
Other operating income and expenses, net	26	59	(33)	(56%)
Share of profit from associates	3	-	3	100%
Impairment of property, plant and equipment	(3)	(34)	31	(91%)
Impairment of financial assets	(21)	(10)	(11)	110%
Operating income	91	69	22	32%

Financial income	-	2	(2)	(100%)
Financial costs	(101)	(96)	(5)	5%
Other financial results	(35)	(11)	(24)	218%
Financial results, net	(136)	(105)	(31)	30%
Loss before income tax	(45)	(36)	(9)	25%

Income tax	(10)	31	(41)	(132%)
Loss of the year	(55)	(5)	(50)	1000%


Owners of the Company	(55)	(5)	(50)	1000%

Revenue

Revenue from our oil and gas segment increased 18%, to U.S.$862 million for the Fiscal year ended December 31, 2025, compared to U.S.$730 million for the Fiscal year ended December 31, 2024. This increase is primarily attributable to the ramp-up of shale oil output at the Rincón de Aranda block, partially offset by lower oil sale prices, and to a lesser extent a decrease in gas volumes and prices.

The average sale price for oil was U.S.$61.5/bbl for the fiscal year ended December 31, 2025, 12% lower than the U.S.$70.2/bbl average sale price for the fiscal year ended December 31, 2024, in line with the decrease of the international price of Brent, which is the main reference for the Company’s oil sale prices.

The following table shows our production and sales for the oil and gas segment for the years shown:

	Fiscal year ended
	December 31, 2025	December 31, 2024	Variation
Production
Oil (k bbl/day)	11.7	4.8	145%
Gas (million m³/day)	12.4	12.5	(1%)
Total (k boe/day)	84.4	78.2	8%

Sales
Oil (k bbl/day)	11.8	5.0	139%
Gas (million m³/day)	12.4	12.5	(1%)
Total (k boe/day)	84.8	78.3	8%

Average prices
U.S.$/bbl	61.5	70.2	(12%)
U.S.$/MBTU	3.7	3.7	(1%)

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Cost of Sales

The cost of sales from our oil and gas segment increased by 19%, to U.S.$613 million for the Fiscal year ended December 31, 2025, from U.S.$515 million for the Fiscal year ended December 31, 2024. The variation is mainly due to higher lifting costs related to gas treatment expenses and the ramp-up of Rincón de Aranda block; higher property, plant and equipment depreciation, and increased royalties related to higher crude oil production.

Gross Profit

Gross profit from our oil and gas segment increased by 16%, from U.S.$215 million in the Fiscal year ended December 31, 2024, to U.S.$249 million for the Fiscal year ended December 31, 2025. This variation is mainly explained by the increase in crude oil sale volumes, partially offset by higher costs, weaker gas demand, and lower average oil and gas sale prices.

Additionally, the gross margin on sales is 29% for both fiscal years ended December 31, 2025 and 2024.

Selling Expenses

Selling expenses from our oil and gas segment increased to U.S.$80 million for the Fiscal year ended December 31, 2025, compared to U.S.$58 million for the same period in 2024 due to increased oil and gas transportation expenses, driven by crude oil production growth at Rincon de Aranda block, higher gas production at Sierra Chata block and higher gas exports to Chile.

Administrative Expenses

Administrative expenses from our oil and gas segment increased to U.S.$83 million for the Fiscal year ended December 31, 2025, compared to U.S.$82 million for the Fiscal year ended December 31, 2024 due to increased fees and compensation for services.

Exploration Expenses

Exploration expenses from our oil and gas segment recorded U.S.$ 21 million for the fiscal year ended December 31, 2024, corresponding to the impairment of unproductive wells in Rincon del Mangrullo block. No exploration expenses were recorded during the fiscal year ended December 31, 2025.

Other Operating Income and Expenses, net

Other operating income and expenses, net from our oil and gas segment recorded gains of U.S.$ 26 million for the Fiscal year ended December 31, 2025, compared to U.S.$ 59 million for the Fiscal year ended December 31, 2024, mainly due to lower Plan Gas.Ar’s income, reduced overdue interest and the gain from the sale of the 22.51% share interest in Gobernador Ayala block recorded in 2024.

Share of profit from associates

The share of profit from associates from our oil and gas segment amounted to U.S.$ 3 million for the Fiscal year ended December 31, 2025 due to our 20% stake in SESA, the company aiming to develop the FLNG Project for LNG export.

Impairment of property, plant and equipment

Our oil and gas segment recorded an impairment of property, plant and equipment of U.S.$3 million and U.S.$19 million in El Tordillo/La Tapera area for the fiscal years ended December 31, 2025 and 2024, respectively, on October 1, 2025, the Company transferred the 35.6706% interest in the concessions of such blocks and collected U.S.$ 2 million. Additionally, a U.S.$ 15 million impairment was recorded in Rincon del Mangrullo area for the fiscal year ended December 31, 2024.

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Impairment of financial assets

Impairment of financial assets from our oil and gas segment increased to U.S.$21 million for the Fiscal year ended December 31, 2025, compared to U.S.$10 million for the Fiscal year ended December 31, 2024. The current fiscal year charge is mainly attributable to a deterioration in collectability ratios, primarily resulting from increased delays in the collection of receivables from ENARSA.

Operating Income

The operating income from our oil and gas segment increased by U.S.$22 million (32%) to U.S.$91 million for the Fiscal year ended December 31, 2025 compared to U.S.$69 million for the Fiscal year ended December 31, 2024.

The operating margin in relation to sales for the Fiscal year ended December 31, 2025, increased to 11% compared to 9% for the Fiscal year ended December 31, 2024.

Financial Results, Net

Financial results, net from our oil and gas segment amounted to losses of U.S.$ 136 million for the Fiscal year ended December 31, 2025, compared to U.S.$ 105 million for the Fiscal year ended December 31, 2024, mainly attributable to higher foreign currency exchange losses over the net monetary asset position in Argentine Pesos.

Income Tax

Our oil and gas segment recorded an income tax charge of U.S.$10 million for the Fiscal year ended December 31, 2025, compared to an income tax benefit of U.S.$31 million for the Fiscal year ended December 31, 2024. The variation is mainly related to a non-cash credit on deferred income tax due to inflation exceeding Peso devaluation for the Fiscal year ended December 31, 2024, while during the current period the inflation and devaluation variables exhibited the opposite behavior.

Loss of the year

As a result of the foregoing, our oil and gas segment recorded losses of U.S.$55 million for the Fiscal year ended December 31, 2025, compared to U.S.$5 million for the Fiscal year ended December 31, 2024, both of which were entirely attributable to the owners of the Company.

Generation Segment

	Generation (in millions of U.S.$)
	For the fiscal year ended
	December 31, 2025	December 31, 2024	Variation	%
Revenue	792	672	120	18%
Cost of sales	(450)	(367)	(83)	23%
Gross profit	342	305	37	12%

Selling expenses	(4)	(3)	(1)	33%
Administrative expenses	(42)	(52)	10	(19%)
Other operating income and expenses, net	12	21	(9)	(43%)
Share of profit/loss from joint ventures	12	(21)	33	157%
Recovery of impairment of property, plant and equipment	55	-	55	100%
Impairment of financial assets	-	(46)	46	(100%)
Operating income	375	204	171	84%

Financial income	18	8	10	125%
Financial costs	(46)	(53)	7	(13%)
Other financial results	168	183	(15)	(8%)
Financial results, net	140	138	2	1%
Profit before income tax	515	342	173	51%

Income tax	(217)	119	(336)	(282%)
Profit of the year	298	461	(163)	(35%)

Owners of the Company	297	461	(164)	(36%)
Non - controlling interest	1	-	1	100%

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Revenue

Revenue from our generation segment increased by U.S.$120 million, amounting to U.S.$792 million in the Fiscal year ended December 31, 2025, compared to U.S.$672 million in the Fiscal year ended December 31, 2024.

This increase is mainly explained by: (i) higher renewable generation due to the commissioning of PEPE VI at the end of 2024; (ii) increased revenues arising from the recognition of fuel self-supply; (iii) higher spot prices driven by new remuneration items added towards the end of 2024, together with the implementation, effective November 1, 2025, of the new spot regime aimed at promoting competition and fuel decentralization (SE Resolution No. 400/25). These effects were partially offset by forced outage at HINISA as a result of the weather-related event that occurred in January 2025.

Power generation during the Fiscal year ended December 31, 2025 decreased by 2%, to 16,699 GWh, compared to 17,002 GWh for the Fiscal year ended December 31, 2024, mainly due to lower hydroelectric generation, partially offset by an increase in wind and thermal generation.

The following table shows net power generation and sales (in GWh) for our power generation plants:

	For the fiscal year ended
	December 31, 2025		December 31, 2024
in GWh	Net generation	Installed capacity (In Mw)	Net generation	Installed capacity (In Mw)
in GWh	(In GWh)	Installed capacity (In Mw)	(In GWh)	Installed capacity (In Mw)
Hydroelectric	1,360	938	2,363	938
Wind	1,714	427	1,270	427
Thermal	13,625	4,107	13,369	4,107
Total	16,699	5,472	17,002	5,472

Cost of Sales

Cost of sales increased by 23% to U.S.$450 million for the Fiscal year ended December 31, 2025, compared to U.S.$367 million for the Fiscal year ended December 31, 2024, mainly explained by higher depreciation of property, plant and equipment, higher maintenance expenses, higher purchases for fuel self-supply.

Gross Profit

Gross profit from our generation segment increased by 12%, to U.S.$342 million for the Fiscal year ended December 31, 2025, compared to U.S.$305 million for the Fiscal year ended December 31, 2024.

The gross margin on sales decreased to 43% for the Fiscal year ended December 31, 2025, compared to 45% for the same period in 2024.

Selling Expenses

Selling expenses from our generation segment increased to U.S.$4 million for the Fiscal year ended December 31, 2025, compared to U.S.$3 million for the Fiscal year ended December 31, 2024.

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Administrative Expenses

Administrative expenses from our generation segment decreased to U.S.$42 million for the Fiscal year ended December 31, 2025, compared to U.S.$52 million for the Fiscal year ended December 31, 2024, mainly explained by lower labor costs.

Other Operating Income and Expenses, Net

Other operating income and expenses, net from our generation segment decreased to a U.S.$12 million gain for the Fiscal year ended December 31, 2025, compared to a U.S.$21 million gain for the Fiscal year ended December 31, 2024. This variation is primarily attributable to lower overdue interests with CAMMESA resulting from reduced interest rate and collectability term; partially offset by higher insurance recoveries.

Share of profit (loss) from joint ventures

The share of profit (loss) from joint ventures in our generation segment amounted to a U.S.$12 million gain for the Fiscal year ended December 31, 2025, compared to a U.S.$21 million loss for the Fiscal year ended December 31, 2024. This variation is mainly explained by the impairment of property, plant and equipment recorded by CTB in 2024, and was partially offset by the loss linked to the non-monetary credit for deferred income tax, driven by the Argentine peso’s devaluation outpacing inflation during 2025.

Recovery of impairment of property, plant and equipment

Our generation segment recorded a recovery of impairment of property, plant and equipment of U.S.$ 55 million for the fiscal year ended December 31, 2025 in CPB, resulting from the updated estimate of the asset’s recoverable value, reflecting the impact of the new spot pricing regime established by SE Resolution No. 400/25.

Impairment of financial assets

Our generation segment recorded an impairment of financial assets of U.S.$46 million for the Fiscal year ended December 31, 2024, primarily due to an agreement entered into with CAMMESA on May 27, 2024, pursuant to which CAMMESA settled certain overdue wholesale electricity payments through (i) the delivery of sovereign bonds valued at 65.0% of their face amount to settle December 2023 and January 2024 WEM´s transactions and (ii) a cash payment to settle February 2024 WEM’s transaction. No impairment was recorded for the Fiscal year ended December 31, 2025.

Operating Income

Operating income from our generation segment increased by U.S.$171 million (84%), to U.S.$375 million for the Fiscal year ended December 31, 2025, compared to U.S.$204 million for the Fiscal year ended December 31, 2024. This variation is mainly attributable to the increase in 2025 gross profit; CPB’s recovery of impairment of property, plant and equipment, lower labor costs, higher insurance recoveries and higher share of profit from CTB. These effects were partially offset by the decrease of commercial interest gains in 2025.

The operating margin on sales for the Fiscal year ended December 31, 2025, increased to 47%, compared to 30% for the Fiscal year ended December 31, 2024.

Financial Results, net

Financial results, net, amounted to gains of U.S.$140 million for the Fiscal year ended December 31, 2025, compared to U.S.$138 million for the Fiscal year ended December 31, 2024. This increase is mainly due to higher financial interest gains, lower foreign currency exchange losses over the net monetary position in Argentine Pesos; partially offset by lower gains from changes in the fair value of financial instruments.

Income Tax

The generation segment recorded an income tax charge of U.S.$217 million for the Fiscal year ended December 31, 2025, compared to an income tax benefit of U.S.$119 million for the Fiscal year ended December 31, 2024. The variation is mainly related to a non-cash credit for deferred income tax due to inflation exceeding Peso devaluation for the Fiscal year ended December 31, 2024, while during the current period the inflation and devaluation variables exhibited the opposite behavior.

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Profit of the year

As a result of the foregoing, the generation segment recorded profits of U.S.$298 million for the Fiscal year ended December 31, 2025, compared to U.S.$461 million for the Fiscal year ended December 31, 2024, mostly attributable to the owners of the Company.

Petrochemicals Segment

	Petrochemical (in millions of U.S.$)
	For the fiscal year ended
	December 31, 2025	December 31, 2024	Variation	%
Revenue	443	516	(73)	(14%)
Cost of sales	(429)	(487)	58	(12%)
Gross profit	14	29	(15)	(52%)

Selling expenses	(12)	(13)	1	(8%)
Administrative expenses	(6)	(7)	1	(14%)
Other operating income and expenses, net	10	34	(24)	(71%)
Impairment of property, plant and equipment	(37)	-	(37)	100%
Operating income	(31)	43	(74)	(172%)

Financial income	27	21	6	29%
Financial costs	-	(3)	3	(100%)
Other financial results	3	7	(4)	(57%)
Financial results, net	30	25	5	20%
Profit before income tax	(1)	68	(69)	(101%)

Income tax	5	4	1	25%
Profit of the year	4	72	(68)	(94%)

Owners of the Company	4	72	(68)	(94%)

Revenue

Revenue from our petrochemicals segment amounted to U.S.$443 million for the Fiscal year ended December 31, 2025, 14% lower than the U.S.$516 million reported for the Fiscal year ended December 31, 2024. This variation is mainly due to lower prices across all products, reflecting the trend in international reference prices within a more competitive economic context.

Total sold volumes during the Fiscal year ended December 31, 2025, decreased 2% compared to the Fiscal year ended December 31, 2024. This variation is mainly explained by lower sale volumes from SBR and styrenics.

The following table shows sales volumes in the petrochemicals segment during the specified years:

Volume sold in k ton	Fiscal year ended
Volume sold in k ton	December 31, 2025	December 31, 2024
Reforming Plant	335	336
Styrene & polystyrene	84	88
SBR	41	45
Total	460	469

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Cost of Sales

Cost of sales from our petrochemicals segment decreased by 12%, to U.S.$429 million for the Fiscal year ended December 31, 2025, compared to U.S.$487 million for the Fiscal year ended December 31, 2024. This variation resulted from decreased sales volumes and reduced prices for raw materials primarily used at the reforming plant.

Gross Profit

Our petrochemical segment recorded a gross profit of U.S.$14 million for the Fiscal year ended December 31, 2025, compared to U.S.$29 million for the same period in 2024, mainly due to lower polystyrene, SBR and styrene margins, which were partially offset by higher reforming plant margin.

The gross margin on sales reached 3% for the Fiscal year ended December 31, 2025, compared to 6% for the Fiscal year ended December 31, 2024.

Selling Expenses

Selling expenses from our petrochemicals segment decreased to U.S.$12 million for the Fiscal year ended December 31, 2025, compared to U.S.$13 million for the Fiscal year ended December 31, 2024.

Administrative Expenses

Administrative expenses from our petrochemicals segment decreased to U.S.$6 million for the Fiscal year ended December 31, 2025, compared to U.S.$7 million for the Fiscal year ended December 31, 2024 mainly due to lower labor costs.

Other operating income and expenses, net

Other operating income and expenses, net amounted to gains of U.S.$10 million for the Fiscal year ended December 31, 2025, compared to U.S.$34 million for the Fiscal year ended December 31, 2024. This variation is mainly explained by the higher reversal of the customs contingency provision recorded in 2024, lower gains driven by the settlement of exports at a differential U.S. dollar exchange rate through the Export Increase Program and losses from idle capacity in our reforming, SBR, styrene and polystyrene plants.

Impairment of property, plant and equipment

Our petrochemical segment recorded an impairment of property, plant and equipment of U.S.$37 million for the fiscal year ended December 31, 2025 as a result of the recoverability assessment performed, considering the identified adverse market conditions due to the sustained decline in petrochemical product sales prices within a more competitive economic context.

Operating Income

The operating income from our petrochemicals segment decreased to a loss of U.S.$31 million in the Fiscal year ended December 31, 2025, compared to U.S.$43 million gain for the Fiscal year ended December 31, 2024.

Financial Results, Net

Our petrochemicals segment recorded gains for financial results, net of U.S.$30 million for the Fiscal year ended December 31, 2025, compared to U.S.$25 million for the Fiscal year ended December 31, 2024. This variation is mainly explained by the higher reversal of accrued interests related to the customs contingency provision recorded in previous periods.

Income Tax

The petrochemicals segment recorded an income tax benefit of U.S.$5 million for the Fiscal year ended December 31, 2025, compared to U.S.$4 million for the same period in 2024.

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Profit of the year

The petrochemicals segment recorded profits of U.S.$4 million for the Fiscal year ended December 31, 2025, compared to U.S.$72 million for the Fiscal year ended December 31, 2024, both of which were entirely attributable to the owners of the Company.

Holding, Transportation and Others Segment

	Holding, transportation and others (in millions of U.S.$)
	For the fiscal year ended
	December 31, 2025	December 31, 2024	Variation	%
Revenue	24	65	(41)	(63%)
Cost of sales	-	(17)	17	(100%)
Gross profit	24	48	(24)	(50%)

Selling expenses	(2)	-	(2)	100%
Administrative expenses	(61)	(98)	37	(38%)
Other operating income and expenses, net	(20)	(27)	7	(26%)
Share of profit from associates and joint ventures	127	167	(40)	(24%)
Profit from sale of companies’ interest	-	34	(34)	(100%)
Operating income	68	124	(56)	(45%)

Financial income	-	1	(1)	(100%)
Financial costs	(49)	(33)	(16)	48%
Other financial results	94	32	62	194%
Financial results, net	45	-	45	100%
Profit before income tax	113	124	(11)	(9%)

Income tax	18	(33)	51	(155%)
Profit of the year	131	91	40	44%

Owners of the Company	131	91	40	44%

Revenue

Revenue from our holding, transportation and others segment decreased by 63% to U.S.$24 million in the Fiscal year ended December 31, 2025 compared to U.S.$65 million for the Fiscal year ended December 31, 2024, mainly explained by the consolidation of OCP, which became effective on August 30, 2024 and included crude oil transportation activity until the concession ended on November 29, 2024.

Cost of Sales

Our holding, transportation and others segment recorded cost of sales of U.S.$17 million in the Fiscal year ended December 31, 2024, entirely attributable to the consolidation of OCP, which became effective on August 30, 2024 and included crude oil transportation activity until the concession ended on November 29, 2024.

Gross Profit

Our holding, transportation and others segment recorded a gross profit of U.S.$24 million in the Fiscal year ended December 31, 2025 compared to U.S.$48 million for the fiscal year ended December 31, 2024, mainly due to OCP’s crude oil transportation activity in 2024.

Selling and Administrative Expenses

Selling and administrative expenses from our holding, transportation and others segment decreased to U.S.$63 million for the Fiscal year ended December 31, 2025, compared to U.S.$98 million for the Fiscal year ended December 31, 2024, mainly due to lower executive compensation accrual in line with the share price performance, partially offset by higher fees and compensation for services.

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Other Operating Income and Expenses, Net

Other operating income and expenses, net from our holding, transportation and others segment recorded losses of U.S.$20 million for the Fiscal year ended December 31, 2025, compared to U.S.$27 million for the Fiscal year ended December 31, 2024. The variation is mainly due to provision for contingencies charges recorded in 2024.

Share of profit from associates and joint ventures

Share of profit from associates and joint ventures from our holding, transportation and others segment amounted to U.S.$127 million for the Fiscal year ended December 31, 2025, compared to U.S.$167 million for the Fiscal year ended December 31, 2024. This variation is explained by lower profit from our stake in OCP, mainly due to gains recognized in the acquisition of additional shares in OCP’s capital stock in 2024, partially offset by higher profits from our stakes in CIESA and CITELEC consistent with monthly rate increases received by TGS and Transener in 2025.

Profit from sale of companies’ interest

The profit from sale of companies’ interest from our holding, transportation and others segment amounted to U.S.$34 million for the Fiscal year ended December 31, 2024 due to the sale of our direct interest in TGS.

Operating Income

Operating income from our holding, transportation and others segment amounted to a U.S.$68 million profit for the Fiscal year ended December 31, 2025, compared to U.S.$124 million for the Fiscal year ended December 31, 2024.

Financial Results, Net

Our holding, transportation and others segment recorded a U.S.$45 million net financial gain for the Fiscal year ended December 31, 2025 due to higher foreign currency net exchange gains on the liability monetary position in Argentine pesos, partially offset by higher interest expenses on fiscal liabilities. No net charges were recorded for the Fiscal year ended December 31, 2024.

Income Tax

Our holding, transportation and others segment recorded an income tax benefit of U.S.$18 million for the Fiscal year ended December 31, 2025, compared to an income tax charge of U.S.$33 million for the Fiscal year ended December 31, 2024. The variation is mainly related to the tax inflation adjustment over the net monetary position.

Profit of the year

Our holding, transportation and others segment recorded profits of U.S.$131 million for the Fiscal year ended December 31, 2025, compared to U.S.$91 million for the Fiscal year ended December 31, 2024, both of which were entirely attributable to the owners of the Company.

Fiscal year ended December 31, 2024 compared to the fiscal year ended December 31, 2023

For a discussion of the results for the fiscal year ended December 31, 2024 compared to the fiscal year ended December 31, 2023, please refer to “Item 5. Operating and Financial Review and Prospects” of our Annual Report on Form 20-F for the year ended December 31, 2024 filed on April 16, 2025.

Liquidity and Capital Resources

Analysis of our Financial Condition

Our ability to execute and carry out our strategic business plan depends upon our ability to obtain financing at a reasonable cost and on reasonable terms. Along these lines, and as a guiding principle, financial solvency is the foundation on which the sustainable development of our businesses is built. Pursuant to these strategic guidelines, we seek to: (a) Design a capital structure consistent with industry standards adaptable to the financial markets in which we operate; (b) Maintain a liquidity level—invested in financial assets with high credit quality—that allows us to meet our obligations; (c) Maintain a debt maturity profile consistent with projected cash generation; and (d) Efficiently manage borrowing costs.

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Adhering to these guidelines enables us to treat financial management as a key element in the value creation process.

Our business activities are focused on the development and value-enhancement of our energy assets, while continuing to identify, evaluate and invest in other opportunities in the Argentine energy industry that offer significant growth potential and/or synergies.

Total consolidated borrowings as of December 31, 2025 and 2024 were U.S.$ 1,892 million and U.S.$ 2,079 million, respectively. As of December 31, 2025 and 2024, 100% and 99% of our borrowings were denominated in U.S. Dollars, respectively.

As of December 31, 2025 and 2024, cash and cash equivalents were U.S.$725 million and U.S.$ 738 million, respectively. We maintain our cash and cash equivalents in Pesos, and in U.S. Dollars depending on medium term requirements and availability, at all levels of operations. We conducted financings mostly at fixed rates.

The table below reflects our cash position at the dates indicated and the net cash provided by (used in) operating, investing and financing activities during the years indicated:

	As of December 31,
	2025	2024
Cash and cash equivalents at the beginning of the year	738	171
Net cash generated by operating activities	778	435
Net cash used in investing activities	(401)	(344)
Net cash (used in) generated by financing activities	(390)	476
Cash and cash equivalents at the end of the year	725	738

Net cash generated by operating activities

Net cash generated by operating activities amounted to U.S.$778 million for the year ended December 31, 2025, attributable to cash flow generated by net income without considering (i) non-cash losses (mainly related to U.S.$414 million for depreciation and amortization of assets, U.S.$204 million for income tax, U.S.$139 million for interest accrual and U.S.$21 million for financial assets impairment), and (ii) non-cash profits (mainly related to U.S.$181 million for changes in the fair value of financial instruments, U.S.$142 million for share of profit from joint ventures and associates, U.S.$48 million for net exchange differences and U.S.$15 million for non-financial assets impairment recovery), but considering (iii) changes in operating assets and liabilities (mainly related to increases of U.S.$100 million in trade and other receivables and U.S.$69 million in trade and other payables).

Net cash generated by operating activities amounted to U.S.$435 million for the year ended December 31, 2024, attributable to cash flow generated by net income without considering (i) non-cash losses (mainly related to U.S.$342 million for depreciation and amortization of assets, U.S.$106 million for interest accrual, U.S.$61 million for compensation agreements accrual, U.S.$56 million for financial assets impairment, U.S.$34 million for non-financial assets impairment and U.S.$27 million for defined benefit plans accrual), and (ii) non-cash profits (mainly related to U.S.$213 million for changes in the fair value of financial instruments, U.S.$146 million for share of profit from joint ventures and associates, U.S.$121 million for income tax and U.S.$34 million for companies’ interest sales), but considering (iii) changes in operating assets and liabilities (mainly related to an increase of U.S.$411 million in trade and other receivables).

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Net cash used in investing activities

Net cash used in investing activities amounted to U.S.$401 million for the year ended December 31, 2025, including payments of U.S.$993 million for purchases of property, plant and equipment and U.S.$44 million for capital integration in companies; partially offset by U.S.$592 million cash proceeds for net collection of public securities and shares’ sales and U.S.$25 million for dividends collection.

Net cash used in investing activities amounted to U.S.$344 million for the year ended December 31, 2024, including payments of U.S.$447 million for purchases of property, plant and equipment and U.S.$48 million for the acquisition of companies; partially offset by U.S.$71 million cash proceeds for purchase of subsidiary; U.S.$39 million collection for equity interests in companies’ sales and U.S.$37 million collection for joint ventures’ share repurchase.

Net cash used in or generated by financing activities

Net cash used in our financing activities amounted to U.S.$401 million for the year ended December 31, 2025, principally due to U.S.$1,304 million payments made in connection with bank and financial borrowings (including principal, interests, repurchase and redemption of corporate bonds); partially offset by U.S.$986 million proceeds from borrowings.

Net cash generated by our financing activities amounted to U.S.$476 million for the year ended December 31, 2024, principally due to U.S.$1,174 million in proceeds from borrowings; partially offset by U.S.$694 million payments made in connection with bank and financial borrowings (including principal, interests, repurchase and redemption of corporate bonds).

Capital Expenditures

The following table sets forth our capital expenditures for the years ended December 31, 2025 and 2024:

	At December 31,
	2025	2024
Oil and Gas	1,039	354
Generation	66	105
Petrochemical	15	6
Holding and others	12	10
	1,132	475

Our capital expenditures in our oil and gas segment amounted to U.S.$1,039 million in 2025, mainly related to the development of the Rincón de Aranda area, through well drilling and completion, as well as progress in the construction of surface facilities and the permanent treatment plant; and to a lesser extent, to the Sierra Chata area, through well drilling and completion.

In 2025, our capital expenditures in our generation segment amounted to U.S.$66 million mainly related to the modernization and replacement of generation equipment extending assets’ useful lives, ensuring reliability and operational efficiency at CTLL, and CTGEBA.

Our capital expenditures in our oil and gas segment amounted to U.S.$354 million in 2024, mainly related to well and facility works in order to develop the Rincón de Aranda area and to increase gas production in the Sierra Chata and El Mangrullo areas.

In 2024, our capital expenditures in our generation segment amounted to U.S.$105 million mainly related to the completion of the construction of the 140MW in PEPE VI wind farm, which commercial commissioning was completed in November 2024.

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Future Capital Requirements

We estimate that our capital investment requirements, debt payment obligations, and working capital will be financed through cash flow from operations, new debt financing, capital contributions, and potential divestments, as well as the prevailing political, economic, and social situation in Argentina. For more information, and those factors that could affect our levels of investments see “Item 3. Key Information - Risk Factors.”

In the oil and gas segment, the 2026 investment plan will focus heavily on our unconventional fields, with significant investments in developing our main crude oil area in Vaca Muerta, Rincón de Aranda, through the RDA Project. Specifically, we will execute a 2026 investment plan of approximately U.S.$ 0.8 billion, to that end.

Also, as part of our equity participation in VMOS and SESA, we will allocate funds in 2026 as capital contributions for the partial financing of the Vaca Muerta Oil Sur Project and the FLNG Project.

In our generation segment, future capital investments will focus on maintaining our currently operating power plants.

For further information on our investment commitments in oil and gas areas and our generation projects, please see Note 18 to our Consolidated Financial Statements.

Description of Indebtedness

Our total consolidated financial indebtedness as of December 31, 2025 was U.S.$ 1,892 million, of which 97% was long-term debt, 96% of which was denominated in U.S. Dollars (excluding U.S.$ linked debt for U.S.$ 80 million). The amount of our total consolidated financial debt does not include Transener, TGS and CTB given that our stake in those companies constitutes an interest in a joint venture, and as such is not consolidated and is valued according to the equity method of accounting in the Consolidated Financial Statements.

The below is a description of the main characteristics of the indebtedness of our group companies:

	2025	2024
	(in millions of U.S.$)
Short-Term Debt
Corporate Bonds	15	584
Financial borrowings	33	122
Bank overdrafts	-	-
	48	706
Long-Term Debt
Corporate Bonds⁽¹⁾	1,799	1,341
Financial borrowings	45	32
Total	1,844	1,373
Total Indebtedness	1,892	2,079

⁽¹⁾

Net of the following face value repurchases: U.S.$ 76.2 million of Series 9 notes and U.S.$ 7.5 million of Series 3 notes as of December 31, 2024.

Financings

During 2025, we continued to strengthen our maturity profile, primarily through the following actions: (i) on May 28, 2025, we reopened our 7.875% notes due December 2034 (the “Series 23 notes”) for a total amount of U.S.$ 340 million and an 8% yield, increasing the total amount outstanding to U.S.$ 700 million; (ii) on August 6, 2025, we issued a new local note (“Series 25 notes”) for a total amount of U.S.$ 105 million at a 7.25% fixed annual interest rate and maturing in August, 2028; and (iii) on November 14, 2025, we issued a 7.75% international note due in November 2037 for an amount of U.S.$ 450 million (the “Series 26 notes”), and an 8.125% yield, maturing in December 2037.

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Additionally, we repaid at maturity: (i) the outstanding total amount of our Series 19 notes for Ps. 17,131.3 million; (ii) our Series 16 notes for U.S.$ 56 million; and (iii) the second amortization of our Series 9 notes for U.S.$ 59 million. Moreover, we redeemed the outstanding total amount of our: (i) Series 1 notes for U.S.$ 353 million, on January 24, 2025; (ii) Series 18 notes for U.S.$ 63 million, on May 8, 2025, net of repurchases; (iii) Series 3 notes for U.S.$ 293 million, on June 23, 2025, net of repurchases; (iv) Series 9 notes for U.S.$ 61 million, on December 8, 2025; and (v) Series 20 notes for U.S.$ 36 million, on December 11, 2025, net of repurchases.

Finally, we repaid net short-term bank loans for a total amount of U.S.$ 53 million and we cancelled net short-term import financings for an amount of U.S.$ 2.9 million. We also obtained pre-export financings for U.S.$ 70 million, which were cancelled before the end of the 2025 fiscal year.

After the end of the 2025 fiscal year, we cancelled financings with banks for a net total amount of U.S.$ 23 million and we issued a new local note (“Series 27 notes”) for a total amount of U.S.$ 200 million at a 5.49% fixed annual interest rate and maturing in April, 2029.

The following table describes our debt maturity profile for the periods indicated, including principal amount plus the corresponding accrued interest as of December 31, 2025:

	*< 1 year*	*1-5 years*	*> 5 years*	*Total*
	*(in millions of U.S.$)* *(1)*
Total Indebtedness	48	313	1,531	1,892

(1)

The sums are rounded and they may not add up.

Corporate Bonds

Throughout 2025, we remained active in local and international capital markets by issuing the following notes:

Notes	Currency	Legislation	Face value *(in millions)*	Interest Rate	Maturity
Series 23¹	U.S.$	Foreign	340	7.875%	Dec-34
Series 25	U.S.$	Argentine	105	7.250%	Ago-28
Series 26	U.S.$	Foreign	450	7.750%	Nov-37

(1) On May 28, 2025 we reopened Series 23 notes for a total amount of U.S.$ 340 million, increasing the total outstanding to U.S.$ 700 million.

Credit Ratings

On February 6, 2025, S&P Global Ratings upgraded Pampa’s local and foreign currency debt rating from “CCC” to “B-” as a result of the upgrade in Argentina’s “Transfer and Convertibility” assessment, and later on August 2025, upgraded Pampas rating Stand-Alone from “b+” to “bb-”.

After the end of 2025, our commercial relationship with Moody’s expired and was not renewed. Consequently, the company is currently not rated by this agency. In March 2026, Fitch Ratings upgraded Pampa’s Long-Term Foreign and Local Currency Issuer Default Ratings from “B-” to “B” and has also upgraded Pampa’s senior unsecured notes from “B” to “B+” with a Recovery Rating of “RR3”.

As of the date of this annual report, Pampa’s ratings are as follows:

Agency	Rating
	Global	Local¹²⁾
S&P	B-, bb- (stand alone)	-
FitchRatings	B, B+ (bond rating)	AAA (long term) A1+ (short term)

(1) Local ratings issued by FIX SCR (affiliate of Fitch Ratings).

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Covenants of our Indebtedness

Under the terms of the respective outstanding debt, we and certain of our subsidiaries are subject to a number of restrictive covenants, including limitations on incurrence of new indebtedness, capital expenditures and dividend payments, among others. As of December 31, 2025, we and our subsidiaries were in compliance with the covenants under our respective outstanding indebtedness.

Item 6.

Directors, Senior Management and Employees

General

We are managed by our board of directors, which is composed of ten directors and an equal or smaller number of alternate directors subject to the annual Shareholders’ Meeting decision. Five of our ten directors are independent according to the criteria and requirements for independent directors under applicable Argentine law. Five of our alternate directors are independent. The directors are elected on a staggered basis each year (three directors at a time in each of the first two years of a three-year cycle, and four in the third year). Our directors are elected for a three-fiscal-year term and can be reelected.

Pursuant to section 12 of our by-laws, any shareholder or group of shareholders who holds more than 3% of our capital stock (each, a “Proposing Shareholder”) may require our board of directors to give notice to our other shareholders of the candidate or candidates to be nominated by such shareholder or group of shareholders at our shareholders’ meeting for election of our board of directors. To such end, the relevant slate executed by the Proposing Shareholder or its representatives, as applicable, will be sent to the chairman of our board of directors, no less than five business days prior to the date of the relevant shareholders’ meeting, to be published in the bulletin of the BASE at least two days prior to the date of our shareholders’ meeting. To facilitate the formation of the slates and the record of the candidates’ names, as of the date of the first notice calling for the relevant meeting, a special book will be made available to our shareholders at our registered office in which the names of the candidates proposed by any proposing shareholder shall be recorded. Similarly, our board of directors will propose to the shareholders’ meeting the candidates for election by slate or, if election by slate is objected to, individually. The names of the candidates proposed by the board will be made known to all our shareholders together with the slates proposed by the Proposing Shareholder. In addition, no proposal for the election of directors may be made, either before or during the shareholders’ meeting, unless written evidence of acceptance of office by the proposed candidates is submitted to us. Such slate or person, as the case may be, who obtains the vote of a majority of the shares present at the meeting will be declared elected. If no slate obtains such majority, a new vote will be taken in which the two slates or persons that obtained the largest number of votes will take part, and the slate or person who obtains the largest number of votes will be declared elected. The preceding rules will not prevent a shareholder who is present at the shareholders’ meeting from proposing candidates not included in the proposals from our board of directors.

Duties and Liabilities of Directors

Pursuant to section 59 of the LGS, directors have the obligation to perform their duties with the loyalty and the diligence of a prudent businessperson. Directors are jointly and severally liable to the company, the shareholders and third parties for the improper performance of their duties, for violating the law, the company’s by-laws or regulations, if any, and for any damage caused by fraud, abuse of authority or negligence, as provided for in Section 274 of the LGS. The following are considered integral to a director’s duty of loyalty: (1) the prohibition on using corporate assets and confidential information for private purposes; (2) the prohibition on taking advantage, or to allow another to take advantage, by action or omission, of the business opportunities of the company; (3) the obligation to exercise board powers only for the purposes for which the law, the company’s by-laws or the shareholders’ or the board of directors’ resolution have intended; and (4) the obligation to take strict care so that acts of the board are not contrary, directly or indirectly, to the company’s interests. A director must inform the board of directors and the supervisory committee of any conflicting interest he or she may have in a proposed transaction and must abstain from voting thereon.

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A director shall not be responsible for the decisions taken in a board of directors’ meeting as long as he or she states his or her opposition in writing and informs the supervisory committee before any claim arises. A director’s decision approved by the company’s shareholders releases that director of any responsibility for his decision, unless shareholders representing 5% or more of the company’s capital stock object to that approval, or the decision was taken in violation of applicable law or the company’s by-laws. The company is entitled to file judicial actions against a director if a majority of the company’s shareholders at a shareholders’ meeting request that action.

Under the LGS, the board of directors is in charge of the administration of the company and, therefore, makes any and all decisions in connection therewith, as well as those decisions expressly provided for in the LGS, the company’s by-laws and other applicable regulations. Furthermore, the board is generally responsible for the execution of the resolutions passed by shareholders’ meetings and for the performance of any particular task expressly delegated by the shareholders. In general, our board of directors may be more involved in operating decision-making than might be customary in other jurisdictions. Under the LGS, the duties and responsibilities of an alternate director, when acting in the place of a director on a temporary or permanent basis, are the same as those discussed above for directors. They have no other duties or responsibilities as alternate directors.

Board of Directors

The following table sets forth information about the members and alternate members of our board of directors. In accordance with Argentine law, each member maintains his or her position on the board until a new shareholders’ meeting elects new directors.

*Full Name*	*Age*	*Position*	*Appointment Date*	*Termination Date*
Marcos Marcelo Mindlin	62	Chairman	04/29/2024	12/31/2026
Gustavo Mariani	55	Vice Chairman	04/07/2026	12/31/2028
Ricardo Alejandro Torres	68	Director	04/07/2026	12/31/2028
Damián Miguel Mindlin	60	Director	04/29/2024	12/31/2026
Carolina Zang⁽¹⁾⁽²⁾	53	Director	04/07/2025	12/31/2027
Gabriel Szpigiel ^{(1) (2)}	59	Director	04/07/2025	12/31/2027
Daniela Rivarola Meilan ⁽¹⁾⁽²⁾	29	Director	04/07/2025	12/31/2027
Julia Sofía Pomares ^{(1) (2)}	50	Director	04/07/2025	12/31/2027
Nicolás Mindlin	36	Director	04/07/2025	12/31/2026
Nicolás Aguzín ^{(1) (2)}	57	Director	04/07/2026	12/31/2028
Clarisa Lifsic⁽¹⁾⁽²⁾	63	Alternate Director	04/07/2025	12/31/2027
María Carolina Sigwald	58	Alternate Director	04/07/2025	12/31/2027
María de Lourdes Vázquez ^{(1) (2)}	64	Alternate Director	04/29/2024	12/31/2026
Clarisa Vittone ^{(1) (2)}	58	Alternate Director	04/29/2024	12/31/2026
Diego Martín Salaverri	61	Alternate Director	04/07/2025	12/31/2027
María Agustina Montes	44	Alternate Director	04/07/2026	12/31/2028
Mauricio Penta	49	Alternate Director	04/29/2024	12/31/2026
Horacio Jorge Tomás Turri	65	Alternate Director	04/07/2026	12/31/2028
Flavia Vanesa Bevilacqua ^{(1) (2)}	41	Alternate Director	04/07/2025	12/31/2027
Lorena Rappaport ^{(1) (2)}	54	Alternate Director	04/07/2025	12/31/2027

(1)

Independent Directors under CML and CNV’s regulations.

(2)

Independent Directors under Rule 10A-3 under the Securities Exchange Act of 1934, as amended.

Marcos Marcelo Mindlin and Nicolás Mindlin are father and son. Also, Marcos Marcelo Mindlin and Damián Miguel Mindlin are brothers. There are no other family relationships between the other members of our board of directors.

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Nomination Policy and Nomination Committee

The Company’s board of directors approved a Nomination Policy to establish the principles governing the nomination and appointment of members of the Board of Directors.

Within the Nomination Policy framework, the Board of Directors created a Nomination Committee that provides assistance to the Board of Directors and the shareholders in the nomination and appointment of the members of the Board, according to the requirements and procedures set forth in the applicable rules and regulations in force in Argentina, Pampa’s bylaws and the rules of the committee.

The Nomination Committee reports to Pampa’s Board of Directors and consists of three regular members and an equal or lower number of alternate members.

The President of the committee must be independent, as determined by the guidelines set forth by the national securities commission. At present, Pampa’s Nomination Committee is composed as follows:

*Name*		*Position*
Julia Sofía Pomares		President
Gustavo Mariani		Regular Member
Gabriel Szpigiel		Regular Member
María Carolina Sigwald		Alternate Member
Clarisa Lifsic		Alternate Member

Senior Management

The table below sets forth certain information concerning our senior management:

*Name*	*Position*	*Age*
Marcos Marcelo Mindlin	Chairman	62
Gustavo Mariani	Executive Vice president - Chief Executive Officer (CEO)	55
Ricardo Alejandro Torres	Executive Vice president	68
Damián Miguel Mindlin	Executive Vice president	60
Nicolás Mindlin	Executive Vice president	36
Horacio Jorge Tomás Turri	Executive Director of Exploration and Production	65
Adolfo Zuberbuhler	Executive Director of Finances (CFO)	48
María Carolina Sigwald	Executive Director of Legal Affairs	58
Mauricio Penta	Executive Director of Administration, IT and Supply	49

The business address of each of our current directors and executive officers is Maipú 1, City of Buenos Aires, Argentina (C1084ABA).

Set forth below are brief biographical descriptions of the members of our board of directors and our senior management.

Marcos Marcelo Mindlin was born on January 19, 1964. He has been a member of our board of directors since 2006 and serves as Chairman of Pampa. Mr. Mindlin received a Master of Science in Business Administration from the Universidad del CEMA (Center of Macroeconomic Studies). He also holds a degree in Economics from the Universidad de Buenos Aires. From 1989 to 2004, Mr. Mindlin served as the founder, Senior Portfolio Manager and a shareholder of Grupo Dolphin. From 1991 to 2003, Mr. Mindlin was also a shareholder, Vice-Chairman and Chief Financial Officer of Inversiones y Representaciones S.A. (IRSA), a leading Argentine real estate company listed on the New York Stock Exchange. In November 2003, Mr. Mindlin resigned from IRSA to focus his work on Grupo Dolphin. Mr. Mindlin has extensive expertise in Latin America through his role as Chairman of the board of directors of Grupo Dolphin and several of its affiliates. From 1999 to 2004, Mr. Mindlin also served as Vice Chairman of Alto Palermo S.A. (a leading owner and operator of shopping centers in Buenos Aires), Vice Chairman at Cresud S.A.I.C. (one of the largest listed agricultural companies in Argentina) and ODS S.A. He also served as Director and member of the Executive Committee of Banco Hipotecario, the leading mortgage bank in Argentina. In 2008, Mr. Mindlin founded, and since that time has directed, the Foundation whose purpose is to improve childhood development and education. Mr. Mindlin is also a member and was Chairman of the Board of the Executive Committee of Tzedaká, a leading Jewish-Argentine foundation, and a member of the Council of the Americas. Mr. Mindlin is currently Chairman of Grupo Dolphin Holding S.A., Emes Finance S.A. and member of the board of Orígenes Seguros de Retiro S.A., among others.

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Gustavo Mariani was born on September 9, 1970. He has been a member of our board of directors since 2005 and serves as Vice-Chairman and CEO of Pampa. Mr. Mariani holds a degree in Economics from the Universidad de Belgrano and a Master in Finance from the Universidad del CEMA (Center of Macroeconomic Studies) and is a Chartered Financial Analyst (CFA) since 1998. Mr. Mariani joined Grupo Dolphin in 1993 as an analyst and served as an investment portfolio manager. Mr. Mariani is currently member of the board of HIDISA, HINISA, Generación Argentina S.A., SACDE, Emes Air S.A., Grupo Emes S.A., Emes Finance S.A., Grupo Dolphin Holding S.A., Orígenes Seguros de Retiro S.A. and the Foundation, among others.

Damián Miguel Mindlin was born on January 3, 1966. He has been a member of our board of directors since November 2005 and serves as Executive Vice president. Mr. Mindlin joined Grupo Dolphin in 1991 as a shareholder and a director. Since November 2003, Mr. Mindlin has served as Investment Portfolio Manager of Grupo Dolphin. He is currently member of the board of SACDE, Profingas S.A., Líneas del Norte S.A., Minera Geometales S.A., Compañía Americana de Transmisión Eléctrica S.A. (CATESA), Líneas de Comahue Cuyo S.A., HIDISA, HINISA, Grupo Emes S.A., Emes Finance S.A, Grupo Dolphin Holding S.A., Líneas Mesopotámicas S.A., Orígenes Seguros de Retiro S.A. and CIESA, among others.

Ricardo Alejandro Torres was born on March 26, 1958. He has been a member of our board of directors since November 2005 and serves as Executive Vice president. Mr. Torres holds a degree in accounting from the Universidad de Buenos Aires and a master’s in business administration from the Instituto de Altos Estudios Empresariales-Escuela de Negocios de la Universidad Austral and was a professor of Tax and Finance at the school of Economics of the Universidad de Buenos Aires. He is currently member of the board of Pop Argentina S.R.L., SACDE, CITELEC, HIDISA, HINISA, Transba, Transener, Fiplasto S.A., Orígenes Seguro de Retiro S.A. and Fundación Observatorio Argentinos por la Educación, among others.

Nicolás Mindlin was born on November 11, 1989. He has been a member of our board of directors since April 2025 and serves as Executive Vice president of the Company. Mr. Mindlin holds an Industrial Engineer degree from the Technological Institute of Buenos Aires and was CFO of Pampa until his appointment as Executive Vice President. Mr. Mindlin serves as member of the board of PEB and VAR, among others.

Gabriel Szpigiel was born on February 3, 1967. He has been a member of our Board of Directors since April 2025 and serves as President of our Audit Committee. He holds a degree in Economics from the Universidad de Buenos Aires. With over 30 years of experience as an investment professional, Mr. Szpigiel has held various senior positions at renowned institutions, including ING Bank, Smith Barney, Deutsche Bank in New York and London, and Marathon Asset Management in New York, where he served as Partner and Global Head of Emerging Markets. He is currently a Partner Emeritus at Marathon Asset Management. Additionally, he serves on the boards of the Americas Society/Council of the Americas and Women Across Frontiers. Mr. Szpigiel is also a member of the Latin American Circle of the Guggenheim Museum and has previously served as Vice Chair of the Emerging Markets Traders Association.

Nicolás Aguzín was born on December 10, 1968. He has been a member of our board since 2026. Mr. Aguzín holds a Bachelor of Science degree in Economics from Wharton School of the University of Pennsylvania and is fluent in Spanish, Portuguese and English. He was the Chief Executive Officer of the Hong Kong Stock Exchanges and Clearing Ltd. from 2021 to 2024. Prior to that position, Mr. Aguzín served as the CEO of J.P. Morgan’s International Private Bank and a member of the Operating Committee for the firm’s Asset & Wealth Management business. Mr. Aguzín is a member of the Board of Trustees of the Asia Society as well as the Eisenhower Fellowships. He is also a member of the Asia Pacific Council of the Nature Conservancy. He was a member of the board of directors of Globant S.A. between 2021 and 2024 and since 2017 he is a member of the board of directors, audit committee and the nominating and corporate governance committee of Mercado Libre, Inc.

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Carolina Zang was born on October 26, 1972. She has been a member of our board of directors since 2022 and serves as member of our Audit Committee. Ms. Zang holds a law degree in Universidad de Buenos Aires and has a master’s in law from New York University School of Law. She is also a partner of Zang, Bergel & Viñes Law Firm in the market and finance area. She worked at Chadbourne & Parke LLP and in the National Legal Directorate of the Secretariat of Natural Resources and Human Environment. Ms. Zang also is a Director in the Bar Association of the City of Buenos Aires, member of the boards of the Adeba Foundation, member of the Cippec Advisory Council and of the Council of Lawyers for Civil and Economic Rights of the Cyrus R. Vance Center for International Justice in New York City. Ms. Zang is also member of the Board of Directors of Banco Hipotecario S.A., among others.

Daniela Rivarola Meilan was born on October 24, 1996. She has been a member of our board of directors since April 2025. She holds a degree in Law from the Universidad de Buenos Aires and in International Relations and Foreign Affairs from the Universidad del Salvador. Ms. Rivarola is a business development professional with extensive experience in identifying market opportunities, contract negotiation, and business relationship management and currently holds the position of head of business development in Decrypto.la.

Julia Sofía Pomares was born on June 6, 1975. She has been a member of our board of directors since 2024 and serves as member of our Audit Committee. Dr. Pomares is also a member of the board of directors of Sociedad Importadora y Exportadora de la Patagonia La Anónima. Additionally, she serves on the Executive Council of Hacedoras, an organization dedicated to promoting the involvement and influence of women in public policies in Latin America. Ms. Pomares holds a bachelor’s degree in political sciences from the University of Argentina, where she graduated with honors. She also obtained a master’s in Comparative Politics and Research Methods in Political Science, as well as a PhD in Political Science from the London School of Economics and Political Science (United Kingdom). With over 20 years of experience at the intersection of the public and private sectors, Dr. Pomares focuses on emerging technologies, particularly generative AI, and institutional governance. She is the Co-Founder and Director of the LATAM Regional Chapter of The Global Initiative for Digital Empowerment and serves as Visiting professor at the School of Government, Torcuato Di Tella University, where she teaches on Prospective Policy Analysis and AI Governance.

Clarisa Diana Lifsic was born on July 28, 1962. She has been a member of our board of directors since 2022. She is also Director of La Pionera de Anta, La Morocha del Sur, STAT Research y Biomakers SA, among others. Ms. Lifsic holds a bachelor’s in economics from the Universidad de Buenos Aires, where she graduated with honors and a Master of Science in Management from the Massachusetts Institute of Technology (Summa Cum Laude).

María Carolina Sigwald was born on November 15, 1967. She has been a member of our board of directors since 2017 and serves as Executive Director of Legal Affairs of the Company since November 2017. Ms. Sigwald obtained her law degree from the Universidad de Buenos Aires, where she graduated with honors. She started her professional career as a lawyer in Central Puerto S.A. after its privatization and then joined Chadbourne & Parke in New York and later the IIC in Washington. Carolina returned to Argentina in 1998 as founding partner of Law Firm Díaz Bobillo, Sigwald & Vittone, where she performed as external advisor for energy companies, Pampa among them. She is currently member of the board of CITELEC, CTB, Transba, TGS, CIESA, VMOS, VAR, PEB, Generación Argentina S.A. and the Foundation, among others.

María de Lourdes Vázquez was born on February 11, 1962. She has been member of our board of directors since 2024. Mrs. Vázquez is a lawyer from the Universidad Católica Argentina and holds an LL.M. Master of Laws from Harvard Law School. She also holds a degree in cinematography from the Centro de Investigación Cinematográfica (Argentina). Mrs. Vázquez is dean of the law department in the Universidad de San Andrés where she has been a professor in different graduate and postgraduate courses; and is also visiting and associate professor at Harvard University. She has also held in-house counsel positions in EMI Records (New York) and Virgin Records (London) and as a partner in Marval, O’Farrel & Mairal Law Firm (Buenos Aires).

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Clarisa Vittone was born on October 6, 1967. She has been a member of our board of directors since 2022. Mrs. Vittone has a Law degree, with a specialization in Business Law, from Universidad de Buenos Aires. She also completed a Postgraduate Studies in NGO Management at Universidad de San Andrés. Since 2011 she has been Partner at Amrop Argentina and is member of the Regional Committee of Business Development for Amrop Latinoamerica. She leads the practice of diversity and inclusion in Latin America. She also specializes in digital talent advising, promoting digital transformation and the development of digital capabilities for C-level and Boards of Directors. Previously she worked at Valuar, a local prestigious executive search company. Previously, Mrs. Vittone worked for 15 years at Deutsche Bank and EFG Bank in executive roles of corporate, investment and private banking.

Diego Martín Salaverri was born on August 7, 1964. He has been a member of our Board of Directors since 2021. Mr. Salaverri is founding partner of the Argentine law firm of Salaverri, Burgio & Wetzler Malbrán. He earned a degree in law in 1988 from the Universidad Católica Argentina, Buenos Aires. Currently, Mr. Salaverri serves as member of the Board of Directors of SACDE and member of the Supervisory Committee of Cardif Seguros S.A., Soluciones de Asistencia Integral S.A., Préstamos y Servicios S.A., Life Seguros de Personas y Patrimoniales S.A., Orígenes Seguros de Retiro S.A., Grupo Dolphin Holding S.A., Partners I S.A. and Norpatagónica S.A., among others.

María Agustina Montes was born on September 28, 1981. She has been a member of our board of directors since 2021. Ms. Montes holds a bachelor’s in law from the Universidad de Buenos Aires. Currently, she serves as Pampa’s Corporate Legal and M&A Manager, having joined the company in 2011. She worked at the firm Cleary, Gottlieb, Steen & Hamilton in its New York offices in 2014. Previously, Ms. Montes worked as a lawyer in the firm Bruchou, Fernandez Madero & Lombardi. Currently, Ms. Montes is member of the board of HINISA, PEB, CTB, HIDISA, Transba, TGS and VAR, among others.

Mauricio Penta was born on July 23, 1976. He is the Executive Director of Administration IT and Supply of the Company. Mr. Penta graduated in Public Accounting from the Universidad Argentina de la Empresa and he received an MBA from the Altos Estudios Empresariales. Previously, Mr. Penta worked for Deloitte and Grupo Cencosud as Tax Manager. Mr. Penta serves as member of the board of CTB, Pampa Energía Soluciones S.A., Generación Argentina S.A, and VAR.

Horacio Jorge Tomás Turri was born on March 19, 1961. He serves as Executive Director of Exploration and Production. Mr. Turri is an industrial engineer and received his degree from Instituto Tecnológico Buenos Aires. Mr. Turri served as Chief Executive Officer of Central Puerto S.A., Hidroeléctrica Piedra del Águila and Gener Argentina S.A. He worked as an analyst of investment projects in the oil, gas and electricity sectors at SACEIF Luis Dreyfus from 1990 to 1992. He also worked at Arthur Andersen & Co. and Schlumberger Wireline in 1987-1990 and 1985-1987, respectively. He currently serves as member of the board of TGS and CIESA, among others.

Flavia Vanesa Bevilacqua was born on July 30, 1984. She has been a member of our board of directors since April 2025. She holds a degree in Law and a master’s in business and economy law, both from the Universidad Católica Argentina. She is a Certified Compliance Officer, by the International Federation of Compliance Associations (IFCA) - Universidad del CEMA - Asociación Argentina de Etica y Compliance. Ms. Bevilacqua is currently Corporate Matters Director at the FGS – ANSES, where she previously was coordinator of production, industry and services in such direction. She was also member of the Board of different Argentine companies such as EDENOR, Mirgor SACIFIA, Transener and Naturgy Ban S.A., among others.

Lorena Rappaport was born on October 21, 1971. She has been a member of our board of directors since 2022. Mrs. Rappaport holds a bachelor’s in law from Universidad de Belgrano in 1997, is a Certified Compliance Officer, by the International Federation of Compliance Associations (IFCA) - Universidad del CEMA - Asociación Argentina de Etica y Compliance in 2016; and holds a specialization in Legal Tech and Innovation granted by George Washington University in 2020.

Adolfo Zuberbuhler was born on March 20, 1978. Mr. Zuberbuhler is currently CFO of Pampa. After many years in banking, he joined the Company in 2007 as an analyst, later served as investment portfolio manager and then as Director of Finance until January 2025 when he was appointed CFO. He has wide experience in capital markets and financial investments. He holds a degree in Business Economics and a master’s degree in applied economics from Universidad Torcuato Di Tella and a diploma in Finance from UNR. He is a professor in the finance department at Universidad del CEMA and a guest professor at the Burgundy School of Business.

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On April 16, 2018, CNV issued its Resolution No. 730, which establishes the criteria to determine if a director for the board of directors of companies under public regime shall not be considered independent. The Argentine independence standards under CNV rules differ in many ways from the NYSE, National Association of Securities Dealers Automated Quotation (“NASDAQ”) or the U.S. federal securities law standards. See “Item 16G. Corporate Governance.”

The following directors, including alternate directors, do not qualify as independent members of our board of directors in accordance with the CNV criteria: Marcos Marcelo Mindlin, Ricardo Alejandro Torres, Damián Miguel Mindlin, Gustavo Mariani, Nicolás Mindlin, María Carolina Sigwald, Diego Martín Salaverri, Mauricio Penta, María Agustina Montes and Horacio Jorge Tomás Turri.

On the other hand, the following directors, including alternate directors, qualify as independent members of our board of directors according to the above-mentioned criteria: Nicolás Aguzín, Gabriel Szpigiel, Daniela Rivarola Meilan, Julia Sofía Pomares, María Vázquez, Carolina Zang, Clarisa Vittone, Clarisa Lifsic, Lorena Rappaport and Flavia Vanesa Bevilacqua.

Audit Committee

According to the provisions of Section 109 of the CML, the Company established an audit committee. On February 18 and November 21, 2019, the audit committee approved an amendment of the audit charter, including the possibility of reelection of the members of the audit committee for successive terms.

Composition

Our audit committee is composed of three members of the board and of three alternate members. All the members of our audit committee must be independent according to the audit charter and must have professional experience in finance, accounting, law and/or management.

The following table sets forth certain relevant information of the members of our audit committee:

*Name*		*Position*
Gabriel Szpigiel		President
Julia Sofía Pomares		Regular Member
Carolina Zang		Regular Member
Clarisa Lifsic		Alternate Member
Clarisa Vittone		Alternate Member
Lorena Rappaport		Alternate Member

Each of the members of the Audit Committee satisfies the independence requirements of Rule 10A-3 of the Exchange Act. For biographical information on the members of the audit committee, see their biography under “Board of Directors”.

Budget

Our audit committee has an annual budget approved by the ordinary annual shareholders’ meeting based on available funds from, without limitation, our revenues, investments and cost savings.

Duties and authority

Our audit committee is responsible for the performance of the duties that fall within its scope of authority pursuant to the provisions of the CML. These duties include, among others, the following:

supervising the operation of the internal control systems and the administrative-accounting system of the Company as well as the reliability of the administrative-accounting system and of all the financial information for any other material facts submitted to the consideration of the authorities in compliance with the applicable reporting requirements in force;

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issuing an opinion on the external auditors nominated by the board of directors to be retained by the Company and verifying if they are independent pursuant to the CML;

reviewing the plans submitted by the external auditors, supervising and assessing their performance and issuing an opinion thereon upon the presentation and publication of the Company’s annual financial statements and overseeing internal audit planning and performance;

supervising compliance with the risk management information policies in place in the Company;

issuing an opinion in relation to transactions with related parties in the events set forth in the applicable law and inform the provisions of the applicable law to the extent there is or may be an alleged conflict of interest in the Company;

providing the market with complete information regarding transactions in which there are conflicts of interest with the members of our corporate bodies or controlling shareholders;

verifying compliance with applicable standards of conduct;

issuing an opinion with respect to the reasonableness of the fees of members of the Board of Directors and stock option plans proposed by the Board of Director;

issuing an opinion with respect to the compliance with legal requirements and on the reasonableness of proposals to issue shares or securities convertible into shares, in the case of capital increases that exclude or limit preemptive rights;

Providing any report, opinion or statement required by the current regulations in force, with the scope and frequency required by such regulations, as amended;

Complying with all obligations provided for in our by-laws, as well as regulations binding for us; and

preparing an annual working plan to be reported to the Board of Directors and the Supervisory Committee within a term of 60 calendar days as from the beginning of the fiscal year.

Independence Criteria

Pursuant to the CML and CNV regulations, we are required to have an audit committee consisting of at least three members of our Board of Directors. Under CNV regulations, at least a majority of the members of the audit committee must be independent directors under CNV standards (see “Item 16G. Corporate Governance. Section 303A.02”).

Pursuant to NYSE Rule 303A.06, we are required to have an audit committee that complies with Rule 10-A3 of the Securities Exchange Act of 1934, as amended. Under rule 10-A3 of the Securities Exchange Act of 1934, as amended, we are required to comply with certain independence standards. Each member of the audit committee must be independent and a member of the board of directors. Pursuant to Rule 10-A3, in order to be considered “independent”, a member of an audit committee of a listed issuer may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee:

accept directly or indirectly any consulting, advisory, or other compensatory fee from the issuer or any subsidiary thereof. Compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the listed issuer (provided that such compensation is not contingent in any way on continued service); or

be an affiliated person of the issuer or any subsidiary thereof.

Additionally, as of the date of this annual report, all members of our Audit Committee satisfy the independence requirements of Rule 10A-3 of the Securities Exchange Act of 1934, as amended, applicable NYSE standards to the audit committees of foreign private issuers and CNV requirements.

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Supervisory Committee

Our current by-laws set forth a supervisory committee composed of three regular and three alternate members. The members of the supervisory committee shall hold office for a term of three fiscal years. Pursuant to the LGS, only lawyers and accountants admitted to practice in Argentina may serve as members of a supervisory committee of an Argentine sociedad anónima, or limited liability corporation.

The primary responsibilities of the supervisory committee are to monitor the management’s compliance with the LGS, the by-laws, its regulations, if any, and the shareholders’ resolutions, and to perform these duties include, inter alia, the following:

(1)

attending meetings of the board of directors, audit committee and shareholders;

(2)

calling extraordinary shareholders’ meetings when deemed necessary and ordinary and special shareholders’ meetings when not called by the board of directors; and

(3)

investigating written complaints of shareholders.

In performing these functions, the supervisory committee does not control our operations or assess the merits of the decisions made by the directors. The duties and responsibilities of an alternate member, when acting in the place of a regular member on a temporary or permanent basis, are the same as those discussed above for the regular members. They have no other duties or responsibilities as alternate members.

The following table sets forth certain relevant information of the members of our supervisory committee:

Name	Position	Age
Roberto Antonio Lizondo	Regular Member	56
José Daniel Abelovich	Regular Member	69
Tomás Arnaude	Regular Member	44
Noemí Cohn	Alternate Member	66
Martín Fernandez Dussaut	Alternate Member	45
Germán Wetzler Malbrán	Alternate Member	56

Set forth below are brief biographical descriptions of the members of our supervisory committee:

Roberto Antonio Lizondo was born on September 25, 1969. Mr. Lizondo obtained a law degree from Universidad Nacional de Tucumán and a Master of Laws degree from The London School of Economics and Political Science. He is a partner of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán and was a foreign associate of Brown & Wood in 1999-2000. He is a member of the Supervisory Committee of Life Seguros de Personas y Patrimoniales S.A.

José D. Abelovich. Mr. Abelovich obtained a degree in accounting from Universidad de Buenos Aires. He is a founding member and partner of Lisicki Litvin & Abelovich. Formerly, he was a manager of Harteneck, López y Cía/Coopers & Lybrand and served as senior advisor in Argentina for the United Nations and the World Bank. He is a member of the supervisory committees of CITELEC, CIESA, HIDISA, VAR, Transba, Transener, TGS, Cresud, IRSA and Banco Hipotecario S.A., among others.

Tomás Arnaude was born on December 17, 1981. Mr. Arnaude received his law degree from the Universidad Católica Argentina. He is a partner of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán and was a foreign associate of Shearman & Sterling LLP in 2010 - 2011. He currently serves as a member of the Supervisory Committee of Fertil Pampa S.A.U., Generación Argentina S.A., Life Seguros de Personas y Patrimoniales S.A. and Vientos Solutions Argentina S.A.U., among others.

Martín Fernandez Dussaut was born on January 29, 1981. Mr. Fernández Dussaut received his law degree from the Universidad Católica Argentina. He is a partner of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán and was a foreign associate at Cleary, Gottlieb, Steen & Hamilton in 2008. He is a member of the Board of Directors of Latin Securities S.A., Alicurá Hidroeléctrica Argentina S.A., Capital Markets Argentina S.A., Cerros Colorados Hidroeléctrica Argentina S.A., Delta Asset Management S.A., Grupo Emes S.A. and Galileo Argentina Sociedad Gerente de Fondos Comunes de Inversión S.A., among others. Additionally, he is a member of the Supervisory Committee of Emes Air S.A., Generación Argentina S.A., Geopark Argentina S.A., Grupo Dolphin Holding S.A., Numera Analytics S.A.U., Life Seguros de Personas y Patrimoniales S.A., Minera Geometales S.A.U., Open Cars S.A., Pampa Energía Soluciones S.A., SCD Servicios S.A.U., TAP Billetera S.A.U., VAR, Vientos Solutions Argentina S.A.U., SACDE, among others.

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Noemí Ivonne Cohn was born on May 20, 1959. Mrs. Cohn obtained a degree in accounting from Universidad de Buenos Aires. She is a partner of Lisicki Litvin & Abelovich. Mrs. Cohn worked in the audit area of Harteneck, López y Cía/Copers, Coopers & Lybrand in Argentina and Los Angeles, California. Mrs. Cohn is member of the supervisory committees of Cresud, IRSA, Generación Argentina S.A. and VAR, among others.

Germán Wetzler Malbrán was born on April 25, 1970. Mr. Wetzler Malbrán received his law degree from the Universidad Católica Argentina. He is a partner of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán and was a foreign associate of Simpson Thacher & Bartlett LLP in 2005. He currently serves as a member of the Supervisory Committee of AUNTAP B2 S.A.U., Operaciones de Petróleo y Gas S.A., Compañía Americana de Transmisión Eléctrica S.A., Comercializadora de Petróleo y Gas S.A., Envases Plásticos S.A., Emes Air S.A., Generación Argentina S.A., Grupo Dolphin Holding S.A.U., Life Seguros de Personas y Patrimoniales S.A., Minera Geometales S.A.U., Orígenes Seguros de Retiro S.A., Open Cars S.A., Pampa Energía Soluciones S.A., Prestamos y Servicios S.A., SACDE, Salta Refrescos S.A., SCD Servicios S.A., Soluciones de Asistencia Integral S.A., VAR, Vientos Solutions Argentina S.A.U., among others.

Corporate Governance

The Company enacted several policies and practices, including a comprehensive code of conduct:

Code of Conduct. This code, approved by our board, constitutes the guide for making honest decisions in daily activities and defines how to address challenges. It sets out core principles to ensure a service of excellence for our customers and build relationships with our suppliers, teammates, shareholders, authorities, intermediate organizations and the Pampa community.

Ethics Committee. It is a consultation body. Its main responsibilities include providing guidance on the Code of Conduct, following up on cases received through the ethics hotline, and rendering its opinion on disciplinary actions and conflicts of interest. This committee comprises the human resources, legal and audit departments, with oversight of our CEO.

Ethics Hotline. The Company has implemented an exclusive channel to report, under strict confidentiality, any suspected misconduct or breach of the Code of Conduct.

Fraud, Corruption and Other Irregularities Policy. This policy reaffirms transparency and ethics as essential behaviors to lead the Company’s business and achieve sustainable growth. It also prohibits fraud, corruption in any form, or acts of misconduct within Pampa. Moreover, it sets Pampa’s stance on preventing corruption and other acts of misconduct, complementing the principles and values defined in our Code of Conduct. Therefore, both documents should be read in conjunction. This Policy also includes clauses on the obligation to report any actual or suspected violation of laws and/or regulations, as well as the prohibition of retaliation against anyone filing a report legitimately and in good faith or refusing to participate in acts of corruption.

Related Parties Transactions Policy. Pursuant to this policy, and as stated in the applicable regulations, all high-value transactions (i.e. all exceeding 1% of the net worth of the Company according to the last approved financial statements) made by the Company with individuals and/or legal entities which are considered to be “related parties” pursuant to the provisions set forth in applicable regulations, must be subject to a specific prior authorization and control procedure that is carried out under the coordination of the Company’s legal affairs executive department and which involves both the Company’s board and its Audit Committee, as applicable.

Policy on Material Information’s Disclosure. This policy regulates processes for publishing relevant information as per the regulatory requirements of the stock exchanges where Pampa’s securities are traded or those in which Pampa is a registered issuer. To ensure the duly execution and compliance with the policy and applicable regulations with respect to this matter, the Company established an Information Disclosure Committee.

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Policy on Best Security Market Practice. This policy outlines certain restrictions and formalities on trading Pampa and/or its affiliates marketable securities listed in a stock exchange. It ensures transparency and guarantees that no benefit or economic advantage is gained from misusing material non-public information about Pampa and/or its affiliates. It applies to employees (including all of our senior management lines), directors and members of the Supervisory Committee. For more information, please see “11.1. Insider Trading Policy”.

Integrated Management Policy. This policy is an evolved version of the Quality, Safety, Environment and Labor Health Policy, adapted to the Company’s present situation and the challenges it faces, driving the sustainable development of our businesses. It adds supplementary aspects to QHSE, such as the efficient use of energy and natural resources, the reliability and integrity of our facilities and operations, and asset management optimization. The policy reaffirms that integrated management is an essential part of our operations and includes ten management principles guiding its simple and agile implementation and strengthening Pampa’s culture.

Self-Assessment Questionnaire for the Board of Directors. Our Board of Directors implemented an annual self-assessment questionnaire to evaluate its own performance and management. The Company’s Corporate Law Department is in charge of examining and filing each questionnaire with the individual answers given by the Board members and, based on the results, it shall submit to the Board any proposed measures deemed useful to improve the performance of the board’s duties.

Nomination Policy. This policy establishes the principles governing the nomination and appointment of members of the Board of Directors of Pampa and is designed pursuant to the rules and regulations in force in Argentina, the bylaws of the Company and the rules of the Nomination Committee that are applicable to the matter.

Compensation Policy. This policy is designed in accordance with the laws and regulations in force in Argentina, the bylaws of the Company and the rules of the Compensation Committee and provides guidance on the principles pursuant to which compensation is payable to the members of the Board of Directors of Pampa. It will be used by the shareholders, the Board of Directors and the Compensation Committee to guide their practice.

Compensation Recovery (Clawback) Policy. This policy was approved by our Board during 2023, in accordance with applicable SEC regulations. For more information about our Clawback Policy, please see Exhibit 6 - Compensation Recovery Policy.

Dividend Policy. This policy, in accordance with laws and regulations in force in Argentina and the Company’s bylaws, outlines the guidelines for balancing distributed amounts and Pampa’s investment plans.

Pre-approval of Principal Accountant Services. This Policy standardizes the internal process that allows the Audit Committee to comply with its obligation to grant prior approval of the provision by the external auditor of any kind of authorized service to the Company.

Compensation of Directors and Officers

The LGS provides that the compensation payable to all directors (including those directors who are also members of senior management) in a fiscal year may not exceed 5% of net income for such fiscal year, if the company is not paying dividends in respect of such net income. The LGS increases the annual limitation on director compensation to up to 25% of net income if all the net income for such year is distributed as dividend. The percentage decreases proportionally based on the relation between the net income and the dividends distributed. The LGS also provides that the shareholders’ meeting may approve the remuneration of the directors in excess of the limits set by the LGS in case the company has no net income or the net income is low, if the relevant directors performed during such fiscal year special commitments or technical-administrative functions. The audit committee issues an opinion with respect to the reasonableness of the fees of members of the Board of Directors. Also, the aggregate amount payable to the Board of Directors’ members will be previously submitted to the Compensation Committee (as defined below) as to whether the compensation proposed is consistent with compensation received by directors at other comparable local companies. The compensation of all directors and members of the supervisory committee requires shareholders’ approval at an ordinary shareholders’ meeting.

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At the ordinary shareholders’ meeting held on April 7, 2026, the compensation for Pampa’s directors was set for a total amount of Ps. 23,904 million for the year ended December 31, 2025. This amount includes fees, remunerations, gratifications and benefits of compensation agreements.

Compensation Plans

Stock-based Compensation Plan

With the aim of aligning personnel performance with our strategic plan and creating a transparent and direct link between value creation for the shareholders and personnel remuneration, on February 8, 2017, our board of directors approved the creation of stock-based compensation plan (the “Plan”). In order to implement the Plan, we can create individual plans each year.

The Company acquired 6 million of its own shares, out of which around 2 million were allocated to the compensation of senior managers. As of the date of this annual report, we held in treasury 3,505,832 common shares to be delivered to employees under such plan, which represents 0.3% of our issued capital.

During fiscal years ended on December 31, 2023, 2024 and 2025, the Company delivered 0.6, 0.5 and 0.5 million, respectively, of its own shares each year as payments under the stock compensation plan for officers and other key staff. As of the date of this report, during 2026, the Company delivered 0.4 million shares as payments under the stock compensation plan for officers and other key staff.

Compensation Agreements – Senior Management

The Company has executed compensation agreements with the Company’s main executives, aimed at aligning the interests of such executives with those of the Company and its shareholders, creating value for them only to the extent that value is created for the shareholders. These agreements mainly provide for an annual, variable and contingent compensation equivalent to, in the aggregate, to 3.6% of the Company’s annual market value appreciation, measured in U.S. Dollars, with an annual cap of 50% of the accrued amount and 1.8% of the Company’s operating income before interest, taxes and other non-cash items (adjusted EBITDA provision) for the period to be compensated. Accrued amounts which have not been paid by the Company will be deferred to future fiscal periods.

The payment of the annual compensation will be subject to the prior approval of the Shareholders’ Meeting to be held in each fiscal year.

Furthermore, Pampa will deduct from the variable compensation, if applicable, remunerations that beneficiaries may have collected on account of bonds and/or other similar items from subsidiaries of Pampa, proportionally to the Company’s interests in such companies.

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Compensation Policy and Compensation Committee

The Company’s Board of Directors approved a Compensation Policy to provide guidance on the principles pursuant to which compensation is payable to the members of the Board of Directors of Pampa.

Within the Compensation Policy framework, the Board of Directors created a Compensation Committee that will assist them and the shareholders in matters related to the compensation of the members of Pampa’s Board of Directors, in compliance with the requirements and procedures set forth in the applicable rules and regulations in force in Argentina, Pampa’s bylaws and the rules of the committee. The Compensation Committee reports to the Board of Directors and will consist of three regular members and equal or lower number of alternate members, who shall not serve in executive offices at Pampa.

As of the date of this annual report, Pampa’s Compensation Committee is composed as follows:

*Name*		*Position*
Gabriel Szpigiel		President
Julia Sofía Pomares		Regular Member
Carolina Zang		Regular Member
Clarisa Lifsic		Alternate Member

Share Ownership

As of March 31, 2026, to the Company’s best knowledge, the following members of our board of directors and senior management owned shares in the Company: Marcos Marcelo Mindlin (189,155,448 shares – 13.87%), Gustavo Mariani (44,333,592 shares – 3.25%), Damian Miguel Mindlin (40,015,695 shares – 2.93%), Ricardo Alejandro Torres (24,482,050 shares – 1.80%), Horacio Turri (6,184,270 shares – 0.45%), María Carolina Sigwald (295,773 shares – 0.02%), Mauricio Penta (180,160 shares – 0.01%), Gabriel Szpigiel (175,000 shares – 0.01%) and Adolfo Zuberbuhler (68,975 shares – 0.01%). To the Company’s best knowledge, no other member of our board of directors or senior management owns any shares of the Company. None of the members of our board of directors and senior management have voting rights that differ from those of our other shareholders. See “Item 7. Major Shareholders and Related Party Transactions.”

Employees

Excluding those employed by us on a temporary basis and including controlled-subsidiaries, as of December 31, 2025, we had 1,847 full-time employees. Additionally, we operate CTEB, which is jointly owned with YPF and has 108 full-time employees.

Approximately 50.73% of our workforce is affiliated with a union and/or is a party to a collective bargaining agreement. We have completed salary negotiations for 2025, except for the Zarate Plant, where the 2024 salary negotiations are still under discussion and a lack of agreement could lead to organized labor actions. See “We employ a largely unionized labor force and could be subject to organized labor action, including work stoppages”.

We offer a variety of benefits beyond those required by the Argentine Labor Contract Law but make no payments to retirees or terminated employees. In accordance with the agreements we have entered with the unions at some of our subsidiaries, we are required to pay certain seniority premiums to retiring employees as a one-time payment upon retirement.

Item 7.

Major Shareholders and Related Party Transactions

Major Shareholders

As of December 31, 2025 our capital stock was comprised of 1,363,520,380 shares. On April 7, 2026, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 19,920,279 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,343,600,101 shares.

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J.P. Morgan informed us that, as of March 31, 2026, there were 21,938,121 outstanding ADSs. As of such date, there was one registered holder of our ADSs in the United States. Since certain of our ADSs are held by brokers or other nominees, the number of direct record holders in the United States may not be fully indicative of the number of direct beneficial owners in the United States of our ADSs, or of where the direct beneficial owners of such ADSs are resident. We have no information concerning holders with registered addresses in the United States that hold our shares, which are not represented by ADSs.

The table below sets forth information concerning the beneficial ownership of our common shares and other major shareholders that, according to the public information available, hold 5% or more of our capital stock, as of March 31, 2026:

Name of Shareholder	Number of Shares	Percentage of our Capital Stock	Percentage of voting power
Management - Control Group
Marcos Marcelo Mindlin	189,155,448	13.87%	13.87%
Gustavo Mariani	44,333,592	3.25%	3.25%
Damián Miguel Mindlin	40,015,695	2.93%	2.93%
Ricardo Alejandro Torres	24,482,050	1.80%	1.80%

Other Major Shareholders
ANSES (¹)	311,029,993	22.81%	22.81%
Hidden Lake S.A.	72,139,594	5.29%	5.29%

Note: Our major shareholders do not have different voting rights.

(1) On November 20, 2008, the Argentine Congress passed a law unifying the Argentine pension and retirement system into a system publicly administered by the ANSES and eliminating the retirement savings system previously administered by private pension funds under the supervision of a governmental agency. In accordance with the new law, private pension funds transferred all of the assets administered by them under the retirement savings system to the ANSES. These transferred assets included 295,765,953 common shares of the Company, representing 20.50% of our capital stock at that date. The ANSES is subject to the same investment rules, prohibitions and restrictions that were applicable to the Argentine private pension funds under the retirement savings system, except as described in the following sentence. On April 12, 2011, the Executive Power issued Emergency Decree No. 441/11, which annulled the restrictions under Section 76(f) of Law No. 24,241on the exercise of more than 5% of the voting power in any local or foreign company, such as the Company, in any meeting of shareholders, irrespective of the actual interest held in the relevant company’s capital stock. The annulment of the restrictions under Section 76(f) of Law No. 24,241 came into effect on April 14, 2011. As of such date, ANSES may exercise its voting power in any local or foreign company, such as the Company, based on the actual interest held in the relevant company’s capital stock.

Related Party Transactions

The LGS permits directors of a corporation to enter transactions with that corporation provided that any such transactions are consistent with prevailing market practice. The CML provides that corporations whose shares are subject to public offerings must submit to their respective audit committees the issuance of a prior opinion of all transactions with a related party involving an amount that exceeds 1% of the corporation’s net worth.

Compensation Plans

See “Item 6. Directors, Senior Management and Employees – Compensation Plans”.

For further information on our related parties’ transactions and our outstanding balances from our transactions with related companies (including companies under joint control), please see Note 17 to our Audited Consolidated Financial Statements.

Except as set forth above and as otherwise permitted under applicable law, we are currently not party to any transactions with, and have not made any significant loans to, any of our directors, key management personnel or other related persons, and have not provided any guarantees for the benefit of such persons, nor are there any such transactions contemplated with any such persons.

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Interests of experts and counsel

During the year ended December 31, 2023, 2024 and 2025 we engaged the services of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán. One alternate director, Mr. Diego Martín Salaverri, two members of our Supervisory Committee, Tomás Arnaude and Roberto Antonio Lizondo, and two of the alternate members of our Supervisory Committee, Martín Fernandez Dussaut and Germán Wetzler Malbrán, are partners of Salaverri, Burgio & Wetzler Malbrán.

Item 8.

Financial Information

CONSOLIDATED FINANCIAL STATEMENTS

See “Item 18. Financial Statements” beginning on page F-1.

LEGAL PROCEEDINGS

We are party to several civil, commercial, contentious-administrative, tax, customs and labor proceedings and claims that arise in the ordinary course of our business. In determining a proper level of provision, the Company has considered its best estimate mainly with the assistance of legal and tax advisors. As of December 31, 2025, we recorded provisions for U.S.$ 53.5 million in relation to civil, commercial, environmental, administrative, labor, tax and customs complaints brought against us, including charges for judicial costs and expenses, and corresponding to atomized claims with individual unsubstantial amounts, except for the proceeding detailed below:

Petrobras Operaciones S.A. (“POSA”) has filed an international arbitration claim against the Company before the International Chamber of Commerce (“ICC”) on account of alleged breaches of the Assignment Agreement entered into between Petrobras Argentina S.A. (currently Pampa) and POSA in 2016 for the transfer of a 33.6% interest in the “Río Neuquén” Concession. The breaches alleged by POSA in its arbitration claim consist of the failure to transfer certain assets associated with the assigned interest, and differences in the calculation of adjustments in the assignment price. The arbitration will be conducted according to the ICC Rules of Arbitration, the applicable law will be that of the Republic of Argentina, and the seat of arbitration will be Buenos Aires, Argentina. On April 30, 2021, POSA filed its statement of claim and on September 15, 2021, the Company filed its statement of defense and its statement of counterclaim. On December 15, 2021, POSA filed its statement of defense to the counterclaim. After the proceedings were suspended by the Court at the request of the parties, the latter decided to continue with the proceeding. On April 3, 2024, ICC notified the parties of the final award issued by the arbitration court on April 2, 2024, resolving to: (i) reject all of POSA’s claims except one, ordering Pampa to pay the corresponding 33.60% of (a) the payments received under the Leasing Agreement up to the date of the Final Award plus interest and (b) the payments that the Company receives under the mentioned contract and (ii) grant Pampa’s counterclaim. On April 10, 2024, the Company filed an action for a partial annulment of the final award. During 2025, POSA filed its response, and hearings were held before the Court of Appeals in Commercial Matters on July 15, 2025 and August 27, 2025. On March 31, 2026, the Court of Appeals in Commercial Matters rejected the action filed by the Company. As of the date of this report, the period to potentially file a federal extraordinary appeal is currently running.

Set forth below are brief descriptions of the nature of the significant legal proceedings or claims in which the Company is a party. As of December 31, 2025, the Company, in accordance with the analysis of our internal and external legal advisors, considers that such legal proceedings are not probable.

Labor Claims - Compensatory Plan

We face several legal proceedings associated with one of our defined benefit plans, the “Compensatory Plan” (see “Item 18. Financial Statements—Note 11.8”). We hereinafter describe the nature of currently-pending labor claims:

Claims alleging that the index (IPC) used to update the plan benefits is ineffective to keep the benefits’ “constant value”. In two proceedings, the Company obtained a favorable ruling, which were appealed by the plaintiffs. During 2025, the ruling of one of the proceedings became final. On the contrary, in another proceeding the Company obtained an unfavorable ruling that was later dismissed by the Court of Appeals. Such ruling is now final.

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Claims on an alleged underfunding of the plan upon the elimination of the Company’s contributions based on earnings. The Company obtained a favorable first instance judgment. The plaintiff appealed and the Court of Appeals granted the plaintiff’s claim. Against such ruling, the Company filed a federal extraordinary appeal before the CSJN, which the Court rendered inadmissible. Consequently, the Company filed a motion for reconsideration of dismissal of appeal before the CSJN and filed an appeal on the grounds of unconstitutionality before the Superior Court of Justice of the Autonomous City of Buenos Aires (“STJBA”). The STJBA sustained the Company’s motion for reconsideration of dismissal of appeal and, consequently, requested the Chamber of Commerce to send the file to the STJBA, to treat the unconstitutionality appeal filed. The Court of Appeals in Commercial Matters rejected the STJBA order so, consequently, the file was sent to the CSJN to resolve the jurisdictional dispute.

Tax Claims

Tax on Liquid Fuels and Natural Gas

ARCA claims the payment of Ps. 54 million due to an alleged omission in the payment of the tax on liquid fuels and natural gas for the fiscal periods from January 2006 to August 2011, plus compensatory interest and a fine of Ps. 38 million as a result of alleged tax avoidance. ARCA’s claim is based on the existence of misappropriation of a tax benefit that was meant for sales in regions that are considered by tax law as tax relieved. The proceeding is currently being heard before the National Tax Court (“NTC”), and the evidentiary period has been completed.

Relevant Customs Proceedings - Gasoline Exports

There are an important number of proceedings in process before the NTC in which the tax authority challenges the tariff heading used by Petrobras during 2008-2014. The fiscal authority takes a position of a higher export duty rate. In seventeen cases, the NTC issued judgments in favor of the Company all of which were acquiesced to by the tax authority and, consequently, became final.

Environmental Claims

The Association of Landowners of Patagonia (ASSUPA) has brought a complaint for an indefinite amount against the Company and other companies seeking the restoration of the environment to the state prior to the exploration, exploitation, production, storage and transportation of hydrocarbon works conducted by the defendants and the prevention of alleged future environmental impacts on certain blocks in the Austral Basin. The National Government and the Provinces of Santa Cruz and Tierra del Fuego have been summoned as third parties. The proceeding is at the complaint answer stage.

ASSUPA has instituted a complaint before the CSJN against 10 companies, including the Company. The National Government and the Provinces of Buenos Aires, La Pampa, Mendoza, Neuquén and Río Negro have been summoned as third parties. The main claim seeks that the defendants should be ordered to redress the alleged environmental damage caused by the hydrocarbon activity developed in the Neuquina Basin and to set up the environmental restoration fund provided for by section 22 of the General Environmental Law. Alternatively, and in case restoration is not possible, it seeks the redress of the allegedly sustained collective damages for an amount estimated at U.S.$547 million based on a United Nations Development Program report. The proceeding is in the complaint answer stage.

Fundación SurfRider Argentina has requested the performance of preliminary proceedings on account of alleged indications of environmental damage in the City of Mar del Plata. The plaintiff seeks environmental restoration, or compensation for the alleged damage caused by all companies owning gas stations in the coastal area of the City of Mar del Plata for an alleged fuel leakage from gas stations’ underground storage tanks into the water, soil and marine system. The Foundation estimates damages in the amount of Ps. 200 million. The parties agreed to suspend the procedural deadlines, for the purpose of evaluating the possibility of entering into an agreement with some co-defendants. Subsequently, the partial agreement entered between the plaintiff and some co-defendants was officially approved. The Company, for its part requested the disassociation from the process because it does not currently own any service station. However, it should be noted that some service station owners (for which the Company was sued) presented in the file agreements entered with the plaintiff for their official approval. Some have already been officially approved and the plaintiff was considered to have partially withdrawn the action and right against the owners of said service stations and against the Company with respect to them - and others are in the approval stage.

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Civil and Commercial Claims

The consumers’ association named “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of U.S.$3,650 million as compensation for damages against Pampa, Petrolera Pampa and certain Pampa directors in office during 2016 who are co-plaintiffs together with Petroleo Brasileiro S.A. A complaint has been brought against Petrobras Brasil for the depreciation of the share quotation value as a result of the “lava jato operation” and the so-called “Petrolao”, and the plaintiffs claim Pampa’s, Petrolera Pampa’s and the directors’ joint and several liability alleging the acquisition of indirect control in Petrobras Argentina S.A. may have thwarted the enforcement of a possible judgment favorable to the plaintiff (for up to the amount of the price paid by Pampa for the acquisition of control over Petrobras Argentina S.A.). The plaintiff appealed the Arbitration Court’s decision declaring the dismissal of the main claim upon the failure to pay the arbitration fee. The Court of Appeals in Commercial Matters upheld the extraordinary appeal. On its part, Petróleo Brasileiro S.A. filed an appearance, requesting that a lack of substance of the filed appeal should be declared, and, in the alternative, answering such appeal. The Company was notified that the Court of Appeals in Commercial Matters had upheld the appeal and filed a motion in this regard. Subsequently, the CSJN declared the nullity of the decision of the Court of Appeals in Commercial Matters that granted the extraordinary appeal and sent the proceedings back for a new decision. The Court of Appeals in Commercial Matter rejected the extraordinary federal appeal filed by the aforementioned Association. The Association filed a motion of dismissal of appeal before the CSJN. During 2025, the CSJN issued a ruling rejecting the proceeding, concluding with a favorable result for the Company.

Administrative claims

CTLL (currently Pampa) filed an administrative litigation complaint against the Federal Government for contractual breach during the January 2016 - March 2016 period. CTLL claims that CAMMESA’s decision regarding the renewal and recognition of costs associated with natural gas supply agreements should be reversed and that, alternatively, sustained damages should be redressed. Subsequently, CTLL filed a new administrative litigation complaint against the Federal Government for contractual breach during the April 2016-October 2018 period. Both cases are currently pending judgment. On June 13, 2025, the Company obtained a favorable judgment, awarding it ARS 62.8 million and ARS 862.9 million, for the periods January 2016 – March 2016 and April 2016 – October 2018, respectively, plus interest. The judgment was appealed by the National State and, on December 23, 2025, the Court of Appeals in Administrative Matters granted the appeal and reversed the first-instance judgment. Against such decision, on February 11, 2026, the Company filed an extraordinary appeal before the CSJN.

Upon the determination of the expiration of the Veta Escondida block concession granted by the Province of Neuquén, the Company filed a writ of amparo and, as secondary petition, a declaratory judgment action to achieve certainty under the original jurisdiction of the CSJN pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. The Company requested judgment and the CSJN set a preliminary hearing, which was held. Following the opinion issued by the Attorney General’s Office, the case is currently pending judgment before the CSJN.

On March 31, 2021, the Company brought a Preliminary Administrative Claim before Argentina’s Ministry of Economy seeking the amount due, plus interest, which was borne by the National State during the term of the Executive Order 1053/18 for the difference in the exchange rate between the price of gas purchased by gas distributors and the price of gas recognized in the final rates of gas distributors for the April 2018-March 2019 period. On September 1, 2021, a motion for prompt intervention was filed. On December 2, 2021, the Company filed a writ of amparo for late payment seeking the defendant’s compliance, which was later rejected. Against this decision, the Company filed an appeal, which was rejected by the acting Court. Since the term for MECON to make a statement on the RAP has expired, the Company brought a proceeding against the National State. The case is open to evidence.

Civil and Commercial claims

Pampa Bloque18, in its capacity as assignee of the Ecuadorian company Petromanabí S.A., has filed an international arbitration proceeding against the Republic of Ecuador seeking the payment of 12% of the Settlement Value, the latter pursuant to the terms of the Hydrocarbon Exploration and Crude Oil Exploitation Participation Agreement in Block 18 entered into on December 19, 1995 and/or the Hollín Common Field Unified Exploitation Operating Agreement executed on August 7, 2002 —in both cases, as amended. The arbitration will be conducted according to the Arbitration Rules of the United Nations Commission on International Trade Law, the applicable law will be the Ecuadorian law, and the seat of arbitration will be the City of Santiago de Chile. The first stages of the international arbitration process began in 2021. As of the date of this report, the arbitration process is still ongoing.

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During 2025, the Company initiated a legal action against ENARSA for breach of contracts executed under the Plan Gas.Ar. This action seeks the payment of certain invoices for gas supply that became due in February 2025, for a total amount of Ps. 22,534 million plus interest. This proceeding is currently at its initial stage.

DIVIDENDS

In accordance with the provisions of the Argentine Personal Asset Tax Law, we are required to pay the personal asset tax, payable by all of our shareholders who are subject to the tax to the ARCA as of December 31 of each year. Although the law permits companies to recover the amounts paid, recovery can be burdensome. In practice, companies usually bear the cost of this tax, which adversely affects their results and does not generate any income tax deduction. Pursuant to the Argentine Income Tax Law (the “Income Tax Law”), dividends may be subject to income tax. For more information see “Item 10. Additional Information - Taxation”.

We did not declare any dividends for the fiscal years ended on either December 31, 2023, 2024 or 2025.

We have a formal dividend policy, for more information see “Item 6. Directors, Senior Management and Employees - Corporate Governance - Dividend Policy” and “Item 10. Additional Information - Dividends.”

SIGNIFICANT CHANGES

There are no significant changes to the financial information included in the most recent audited consolidated financial statements contained in this annual report, other than as otherwise described in this annual report.

Item 9.

The Offer and Listing

TRADING HISTORY

Our capital stock consists of common shares, with a par value of Ps.1.00 each. Each share entitles the holder thereof to one vote at shareholders’ meetings. All outstanding shares are fully paid in and our common shares have been listed on the BASE since 1947. Since October 9, 2009, our ADSs have been listed on the NYSE. The ADSs have been issued by the Bank of New York as depositary. Each ADS represents 25 common shares.

Shares

Our common shares are currently traded on the BASE under the symbol “PAMP”, and our ADSs are traded on the NYSE under the symbol “PAM”.

The following table sets forth, for the years indicated, the reported high and low sales prices as well as the average daily trading volume of our shares traded on the BASE, and of our ADSs traded on the NYSE:

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	Buenos Aires Stock Exchange			New York Stock Exchange
			Average Daily			Average Daily
	Pesos per Share		Trading Volume	U.S. Dollars per ADS		Trading Volume
	High	Low	Pesos	High	Low	U.S. Dollars

2021⁽¹⁾	171.50	73.20	61,971,893	21.28	12.17	2,133,439
2022⁽¹⁾	440.70	152.00	111,318,600	32.00	17.97	3,100,657
2023⁽¹⁾	2,234.00	425.00	964,980,524	52.17	26.86	7,271,123
2024⁽¹⁾	4,315.00	1,584.65	4,020,615,621	93.11	38.15	14,453,681
2025⁽¹⁾	5,750.00	3,205.00	7,038,858,341	97.55	54.95	20,368,666

⁽¹⁾ Values provided by Bloomberg.

The following table sets forth, for the periods indicated, the reported high and low sales prices as well as the average daily trading volume of our shares traded on the BASE, and of our ADSs traded on the NYSE:

	Buenos Aires Stock Exchange			New York Stock Exchange
			Average Daily			Average Daily
	Pesos per Share		Trading Volume	U.S. Dollars per ADS		Trading Volume
	High	Low	Pesos	High	Low	U.S. Dollars
2024⁽¹⁾
First Quarter	2,625.00	1,584.65	2,290,900,550	50.01	38.15	9,475,477
Second Quarter	2,500.00	1,765.10	4,405,751,778	51,32	40.88	17,407,336
Third Quarter	3,055.00	2,090.00	3,804,797,846	62.66	38.58	12,196,478
Fourth Quarter	4,315.00	2,935.00	5,657,795,511	93.11	59.02	20,448,525
2025⁽¹⁾
First Quarter	4,645.00	3,500.00	6,238,320,459	97.55	72.68	20,888,133
Second Quarter	4,200.00	3,280.00	5,099,599,552	87.59	59.63	15,318,956
Third Quarter	4,440.00	3,205.00	8,035,773,391	83.10	54.95	22,443,080
Fourth Quarter	5,750.00	3,555.00	8,637,337,970	94.50	57.14	22,699,160
2026⁽¹⁾
First Quarter	5,490.00	4,152.50	6,028,038,450	90.30	69.34	19,071,245
Second Quarter⁽²⁾	5,325.00	4,947.50	9,174,282,250	89.97	84.18	25,159,164

⁽¹⁾ Values provided by Bloomberg.

⁽²⁾ Represents the average of the lowest and highest daily rates from April 1 through April 8, 2026.

The following table sets forth, for the months indicated, the reported high and low sales prices as well as the average daily trading volume of our shares traded on the BASE, and of our ADSs traded on the NYSE:

	Buenos Aires Stock Exchange			New York Stock Exchange
			Average Daily			Average Daily
	Pesos per Share		Trading Volume	U.S. Dollars per ADS⁽²⁾		Trading Volume
	High	Low	Pesos	High	Low	U.S. Dollars
2025⁽¹⁾
April	4,200.00	3,285.00	5,937,146,632	82.11	59.63	18,163,691
May	4,060.00	3,280.00	5,453,243,550	87.59	68.00	15,806,478
June	3,755.00	3,280.00	3,889,795,632	78.05	67.72	11,820,087
July	4,195.00	3,330.00	7,795,782,545	80.00	67.15	17,248,874
August	4,440.00	3,540.00	6,567,455,650	83.10	65.38	19,709,217
September	3,900.00	3,205.00	9,610,598,545	69.60	54.95	30,618,492
October	5,270.00	3,555,00	10,596,665,773	88.37	57.14	32,344,300
November	5,530.00	4,650.00	10,459,169,053	92.20	82.74	24,318,028
December	5,750.00	5,235.00	4,751,337,860	94.50	86.26	11,217,491

2026⁽¹⁾
January	5,490.00	4,660.00	5,989,749,381	90.27	77.15	17,264,056
February	5,300.00	4,480.00	4,109,780,000	87.92	76.48	16,619,262
March	5,295.00	4,152.50	7,710,549,048	90.30	69.34	22,831,767
April⁽²⁾	5,325.00	4,947.50	9,174,282,250	89.97	84.18	25,159,164

⁽¹⁾ Values provided by Bloomberg.

⁽²⁾ Represents the average of the lowest and highest daily rates from April 1 through April 8, 2026.

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Purchases of Pampa’s Shares

During fiscal year 2025, the Board of Directors approved a new Share Repurchase Program for U.S.$ 100 million, with a maximum price of U.S.$ 60 per ADR and Ps. 3,480 per common share, for a 120-day period as from September 8, 2025.

During 2025, the Company directly and indirectly acquired 0.03 million own common shares and 0.8 million own ADRs for a value of U.S.$ 47 million.

For more information, please see “Item 16.E — Purchases of Equity Securities by the Issuer and Affiliated Purchasers”.

American Depositary Shares

Since October 9, 2009, our ADSs have been listed on the NYSE and trade under the ticker PAM. Each ADS represents 25 common shares (or a right to receive 25 common shares). Pursuant to the provisions of the Deposit Agreement, on January 23, 2017, Pampa sent a notice to The Bank of New York Mellon stating that Pampa (i) removed The Bank of New York Mellon as depositary and (ii) appointed J.P. Morgan as successor Depositary thereunder, effective on the later to occur of the close of business New York City time on (a) February 21, 2017 and (b) the date of effectiveness of the Form F-6 filed with respect to the appointment of J.P. Morgan as successor Depositary under the Deposit Agreement. On February 22, 2017, Pampa filed the F-6 and the appointment of J.P. Morgan became effective as of such date.

Furthermore, the Company made certain amendments to the Deposit Agreement by Form of Amendment No. 1 to the Second Amended and Restated Deposit Agreement (previously filed as Exhibit 99.A2 to our Registration Statement on Form F-6 POS (File No. 333-216157) on November 18, 2020).

Each ADS will also represent any other securities, cash or other property, which may be held by the ADS Depositary, J.P. Morgan.

The ADS Depositary’s office at which the ADRs are administered is located at 4 New York Plaza, Floor 12, New York, New York 10004. See “Item 12. Description of Securities Other than Equity Securities - Description of American Depositary Shares.” The Designated Market Maker on the trading floor of the NYSE for our ADSs is GTS.

The ADS Depositary has informed us that, as of December 31, 2025, there were 21,826,958 outstanding ADSs.

THE ARGENTINE SECURITIES MARKET

Trading in the Argentine securities market

Pursuant to the provisions of the CML, the securities market in Argentina is comprised of several Authorized Markets, including the BYMA, the A3, the Mercado de Valores de Córdoba S.A., among others. The CML allows the Authorized Markets to delegate certain of its duties and rights as a market to other qualified entities, as previously authorized by the CNV. Securities listed on these exchanges include corporate equity, bonds and government securities.

On December 29, 2016, the CNV authorized BYMA and on January 2, 2017, IGJ and CNV authorized the creation and operation of BYMA. Almost seventy percent of its capital stock is held by free float and the other percentage is owned by BASE.

ByMA is the largest authorized market in Argentina. Pursuant to CNV Resolution No. 18,629, ByMA was authorized to operate as an Authorized Market and allowed ByMA to delegate certain of its rights and duties as a market in the BASE, including without limitation, the right to authorize the listing of issuers and securities in the ByMA, and the right to publish the daily market gazette.

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In Argentina, debt and equity securities traded on an exchange or the over-the-counter market must, unless otherwise instructed by their shareholders, be deposited with Caja de Valores. Caja de Valores is the central securities depositary of Argentina and provides central depositary facilities, as well as acting as a clearing house for securities trading and as a transfer and paying agent for securities transactions. Additionally, Caja de Valores handles the settlement of securities transactions carried out by the BASE and operates the computerized exchange information system mentioned above.

ByMA incorporated 99.96% of Caja de Valores’ equity, and as a result, the operating cycle of the capital market industry is vertically integrated. At the technological level, ByMA acquired the Millennium Stock Exchange platform belonging to the London Stock Exchange group as a sign of its innovative vocation and with the aim of providing the best attention to its participants and investors. Millennium, a leading global technology provider in trading and post-trading software, currently serves the London, Milan, Oslo and Johannesburg Stock Exchanges, among others.

Although companies may list all of their capital on ByMA or any other Authorized Market, controlling shareholders in Argentina typically retain the majority of a company’s capital stock, resulting in a relatively small percentage of active trading of the companies’ stock by the public on any such Authorized Market.

Securities may also be listed and traded through over-the-counter market brokers who are linked to an electronic reporting system. The activities of such brokers are controlled and regulated by A3, an electronic over-the-counter market reporting system that functions independently from ByMA. Under an agreement between the BASE and A3, trading in equity and equity-related securities is conducted exclusively on the BASE (now ByMA) and trading in corporate debt securities is conducted on both the BASE (now ByMA) and the A3. Trading in Argentine Government securities, which are not covered by the agreement, may be conducted on either or both of the ByMA and the A3. The agreement does not extend to other Argentine exchanges.

Regulation of the Argentine securities market

The Argentine securities market is regulated and overseen by the CNV, pursuant to the CML, as well as stockbroker transactions, market operations, the public offering of securities, corporate governance matters relating to public companies and the trading of futures and options. Argentine insurance companies are regulated by a government agency, the Superintendencia de Seguros de la Nación, whereas financial institutions are regulated primarily by the Central Bank.

On June 1, 2001, the Argentine Government issued Decree No. 677/01, which provided certain guidelines and provisions relating to capital markets transparency and best practices. Further improvements to Argentine securities market regulations were introduced in December 2011 when the Argentine Criminal Code was amended to include insider trading as a criminal offense. In addition, on November 29, 2012, the Argentine Government enacted the CML, which revoked Law No. 17,811, and Decree No. 677/01. However, CML incorporated most of the provisions established in those regulations. These provisions were regulated by the CNV through Resolution No. 622/13 and further modifications.

On May 9, 2018, the Argentine Congress approved the Law No. 27,440, called Ley de Financiamiento Productivo, which introduced significant reforms to the CML, the Mutual Funds Law No. 24,083 and the Argentine Negotiable Obligations Law No. 23,576, among others.

Prior to offering securities to the public in Argentina, an issuer must meet certain requirements established by the CNV (for example, regarding the issuer’s assets, operating history and management, among others), and only securities authorized for public offering by the CNV may be listed on a stock exchange. Although issuers of listed securities are required to file with the CNV and the stock exchange on which their securities are listed several financial documents (such as, unaudited quarterly financial statements, audited annual financial statements, various other periodic reports), as well as to report any event related to the issuer and its shareholders that may materially affect the value or trading volume of the traded securities, the CNV approval does not imply any kind of certification as to the quality of the securities or the solvency of the issuer.

Money Laundering

The concept of money laundering is commonly used to refer to operations that aim to enter funds from criminal activities into the institutional system and thus convert profits from illegal activities into assets of apparently lawful origin.

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On April 13, 2000, the Argentine Congress passed the Anti-Money Laundering Law which classifies money laundering as a crime. Additionally, such law, which amended several sections of the Argentine Criminal Code, has established sanctions for those incurring in such illicit activity and has created the UIF, a unit of the actual Ministry of Justice created to prevent money laundering and financing of terrorist activities.

The Argentine Criminal Code defines money laundering as the exchange, transfer, management, sale or any other use of money or other assets obtained through a crime, by a person who did not take part in such original crime, with the potential result that such original assets (or new assets resulting from such original assets) appear as if obtained through legitimate means, provided that the aggregate value of the assets involved, whether through one or more related transactions, exceeds an amount equivalent to one hundred and fifty (150) minimum living wages (salario mínimo vital y móvil) in force at the time of the relevant conduct. As previously mentioned, the Anti-Money Laundering Law created the UIF, which is in charge of the analysis, supervision and conveyance of information in order to prevent (A) the laundering of assets obtained from: (i) crimes related to illegal traffic and commercialization of narcotics (Law No. 23,737); (ii) crimes related to smuggling of arms and other goods under the Argentine Customs Code (Law No. 22,415); (iii) crimes related to the activities of an illegal association as defined in Article 210 bis of the Argentine Criminal Code; (iv) illegal acts committed by illegal associations (Article 210 of the Argentine Criminal Code) organized to commit crimes with political or racial motivation; (v) crimes of fraud against the Public Administration (Article 174, Section 5 of the Argentine Criminal Code); (vi) crimes against the Public Administration under Chapters VI, VII, IX and IX bis of Title XI of Book Two of the Argentine Criminal Code; (vii) crimes of underage prostitution and child pornography under Articles 125, 125 bis, 127 bis and 128 of the Argentine Criminal Code; (viii) crimes related to financing of terrorism (Article 306 of the Argentine Criminal Code, as supplemented by Article 41 quinquies thereof); (ix) crimes of extortion (Article 168 of the Argentine Criminal Code); (x) tax crimes, related to social security and fiscal resources (pursuant to Law No. 24,769) and (xi) crimes related to human trafficking; and (B) crimes related to financing terrorism.

The Anti-Money Laundering Law assigns information and control duties to certain private sector entities, such as banks, agents, stock exchanges and insurance companies, according to the regulations of the UIF, and for financial entities, the Central Bank.

Financial entities must inform the UIF about any suspicious or unusual transaction, or transactions lacking economic or legal justification, or that are unnecessarily complex. In addition, guidelines and internal procedures were created to detect unusual or suspicious transactions, which must be implemented by financial institutions and other entities.

Pursuant to the same criteria that underlies the aforementioned law, in 2012, the office of the Attorney General issued Resolution No. 914/12, which created the Office of the Prosecutor for Economic Crime and Money Laundering (PROCELAC). As PROCELAC has no competence to apply sanctions, its main role is to collaborate with the federal prosecutors in the investigation of economic crimes and in receiving complaints in order to initiate preliminary investigations.

UIF issued Resolution No. 156/18, consolidated the texts of previous UIF’s resolutions, streamlining and updating the AML/TF framework for obliged subjects. The Resolution No. 156/18 was subsequently amended by, among others, Resolutions No. 117/19, No. 112/21, No. 50/22, No. 14/23, No. 78/23, No. 126/23 and No. 132/24 (“AML in the Capital Market Sector”). The AML in the Capital Market Sector establishes certain procedures that must be followed by the authorized agents of the CNV involved in the placement, intermediation and public offering of securities (the “Obliged Subjects in the Capital Market Sector”) in order to prevent, detect and report (within the deadlines established) the acts, transactions or omissions that may arise from committing money laundering and terrorist financing crimes in the capital market sector. Additionally, the AML in the Capital Market Sector introduced general guidelines to identify different types of customers (including a distinction between frequent, casual and inactive customers), the requested information, the documentation to be kept and the procedure to detect and report all suspicious transactions within the established deadlines.

The main obligations pursuant to the AML in the Capital Market Sector are the following: (i) to prepare manuals providing the mechanisms and procedures for the prevention of money laundering and financing of terrorism; (ii) to appoint a compliance officer; (iii) to audit regularly; (iv) to provide training programs to the employees; (v) to enforce measures that would allow the Obliged Subjects in the Capital Market Sector to compile the transactions performed by the customers using a computerized method, as well as technological tools which would enable the analysis and supervision of different transactions to identify behaviors and detect potential suspicious operations; (vi) the implementation of technological tools that would result in effective control and prevention procedures against money laundering and financing of terrorism; and (vii) to record the analysis and risk management of the suspicious transactions that were detected and those that, for having been considered suspicious, have been reported.

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The Central Bank and the CNV should also comply with provisions of the Anti-Money Laundering Law. In this respect, the CNV regulations provide that entities involved in the public offering of securities (other than issuers), including, among others, underwriters of any primary issuance of securities, must comply with the standards set forth by the UIF. In particular, they must comply with the obligation regarding customer identification and required information, record-keeping, precautions to be taken to report suspicious transactions, policies and procedures to prevent money laundering and terrorist financing. Whilst the acquirers of notes will provide the information and documentation required regarding the origin and legality of the funds used for the subscription.

On the other hand, pursuant to Resolution No. 156/18, as amended subsequently, the Obliged Subjects in the Capital Market Sector shall identify and evaluate the risks that they are exposed to and, as a result, adopt administrative measures for mitigating them, in order to more effectively prevent money laundering. In accordance with this standard, the Obliged Subjects in the Capital Market Sector must have policies and procedures to know their client, which must be applied according to the risk rating resulting from the implemented risk model. Within this framework, individuals are enabled to implement reputable technological platforms, which allow long-distance procedures without the need to present documentation in person, without prejudice to the fulfillment of due diligence duties.

With respect to issuers (such as the Company), CNV regulations provide that any person (either individuals or legal entities) performing significant capital contributions or loans must be identified, whether a shareholder or not at the time of the contributions, and must meet the requirements for general participants in the public offering of securities, set forth in the CNV regulations and the UIF regulations, especially with respect to the identification of such persons and to the origin and legality of the funds and loans provided.

On October 14, 2016, the UIF issued Resolution No. 135/16, which was subsequently amended by later UIF resolutions, including Resolution No. 66/23, which updates certain procedures for international cooperation, such as information requests, data transmission and confidentiality requirements, in order to strengthen the international exchange of information between similar authorities which may enter into agreements or memoranda of understanding as well as to the foreign public bodies that are members of the Egmont Group of UIF or the Asset Recovery Network of the Financial Action Task Force of Latin American.

On January 11, 2017, the UIF published Resolution No. 4/17, which established that special due diligence measures must be applied for identifying foreign and domestic investors (who shall comply with the requirements therein set forth to qualify as such) in the Republic of Argentina upon requesting the opening of special investment accounts.

Among different resolutions, including Resolutions No. 35/23 and No. 192/24, the UIF established the criteria to be considered a “politically exposed persons” (“PEP”) in Argentina, taking into account any positions occupied by them in the present or in the past, and their relationship by closeness or affinity with third parties who occupy or have occupied such positions.

Likewise, it is specified that the affidavit through which clients are required to declare whether they do or do not hold the status of PEP must be signed not only at the commencement of the business relationship but also at the moment of changing the PEP status, whether they begin to hold such status or cease to do so.

In July 2019, by Decree No. 489/19, the PEN created the Public Registry of Persons and Entities Linked to Acts of Terrorism and its Financing (Registro Público de Personas y Entidades Vinculadas a Actos de Terrorismo y su Financiamiento) (the “RePET”), to centralize and manage all information related to the administrative freezing of assets linked to acts of terrorism and its financing. This Decree was later amended by Decree No. 496/24, which allows the inclusion in RePET of persons, groups or entities when the relevant bodies of the PEN decide, based on a reasoned decision, in the event of a current or potential threat to national security. RePET is empowered to provide public access and guarantee the exchange of information with agencies with competence in the field and with third countries, and the reporting parties must provide all information related to transactions carried out or attempted by individuals or legal entities included in RePET.

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In turn, on November 14, 2019, by means of CNV Resolution No. 816, the CNV adapted the regulations related to the prevention of money laundering and financing of terrorism, in order to include the new obliged subjects contemplated in the Anti- Money Laundering Law and in the Regulations on Money Laundering in the Capital Market Scope. In this way, crowdfunding platforms, global investment advisory agents and human or legal persons acting in the placement of mutual funds or other collective investment products, among others, were included as obliged subjects. This Resolution has been subsequently amended by, among others, CNV Resolution No. 1026, which modified the scope and list of obliged subjects.

On October 21, 2021, the UIF issued Resolution No. 112/21, as amended, among others, by Resolution No. 200/24, whereby it establishes the measures and procedures that the regulated entities listed in Article 20 of the Anti-Money Laundering Law must observe to identify the ultimate beneficial owner of the customer in question. In this sense, such Resolution 112/21 established that the ultimate beneficial owner shall be considered the natural person who owns at least 10% of the capital or voting rights of a legal person, a trust, an investment fund, an affectation patrimony and/or any other legal structure; and/or the natural person who by other means exercises the final control of the same.

Moreover, UIF Resolution No. 61/23, dated April 14, 2023, approved the “Risk-Based Supervision Procedure of the UIF”. This procedure incorporates a monitoring framework that encompasses a spectrum of activities and tools available in terms of supervision to be applied with a Risk-based approach (“RBA”). This marks a substantial change from previous regulations as it aims at the continuous observation and permanent monitoring of the obliged subjects covered by this procedure.

The aim of this procedure is to establish regulatory measures for supervisory procedures aimed at overseeing compliance by obliged subjects with obligations pertaining to the identification, assessment, monitoring, management, and mitigation of AML and TF risks. Its primary objective is to mitigate the risk of obliged subjects being exploited by third parties for criminal purposes related to AML/TF activities.

On May 2, 2023, the UIF issued Resolution No. 72/23, which unifies the duty of collaboration of the supervisory agencies (BCRA, CNV, Superintendence of Insurance of the Nation, and National Institute of Associative and Social Economy) in supervisory procedures. This regulation facilitates coordination between agencies and adopts a RBA for obliged subjects. Likewise, the “Regulations of the Working Groups” and the “Final Technical Report Model” are approved as a reference for the preparation of reports by the supervisory bodies.

On May 9, 2023, by Resolution No. 78/23, minimum requirements for the identification, evaluation, monitoring, management, and mitigation of AML and TF risks were established. This resolution was slightly amended by UIF Resolution No. 56/24.

As from March 2024, UIF Resolutions No. 1/23 and No. 2/23 established new minimum requirements for the identification, evaluation, monitoring, management, and mitigation of AML and TF risks. These requirements apply to certain obliged subjects included in Article 20, paragraphs 2, 10, and 11 of Law No. 25,246. The aim is to ensure that these entities adopt and apply appropriate policies, procedures, and controls to prevent the risk of being used by third parties for criminal AML/TF purposes.

On March 15, 2024, Law No. 27,739 was published in the Official Gazette, introducing modifications to the Argentine Criminal Code and reforming the system for the prevention of AML/TF, and the Proliferation of Weapons of Mass Destruction. Among the modifications to the Criminal Code, the following stand out: (i) the expansion of the criminal scope of money laundering and terrorism financing; (ii) the introduction of the criminal offense of financing the proliferation of weapons of mass destruction; and (iii) the extension of aggravating factors for terrorism to offenses specified in special laws or laws that incorporate into domestic law criminal offenses provided for in international conventions ratified in Argentina. Additionally, this law also creates: (i) a public registry of beneficial owners, managed by ARCA, to centralize accurate and updated information regarding individuals who are beneficial owners; and (ii) a registry of virtual asset service providers (“Proveedores de Servicios de Activos Virtuales” or PSAVs), managed by CNV, to centralize information regarding individuals and legal entities operating as PSAVs.

On March 19, 2024, UIF Resolution No. 47/24 was published in the Official Gazette, modifying the Operations Reporting System. Specifically, it incorporates among the requirements for the registration of Obligated Subjects, the certification issued by the National Registry of Recidivism regarding the criminal records of the members of the administrative body and the ultimate beneficiaries. Likewise, it includes a procedure to manage the deregistration as an Obligated Subject.

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For more information, you should seek advice from your legal counsel and read the applicable rules mentioned herein, including their amendments, which can be found at the following websites: www.infoleg.gob.ar, the UIF’s website: www.argentina.gob.ar/uif and the Central Bank’s website: www.bcra.gob.ar. The information contained on these websites is not part and shall not be deemed incorporated into this annual report.

Corporate Criminal Liability Law

On March 1, 2018, the Corporate Criminal Liability Law came into effect, after having been enacted by the Argentine Congress on November 8, 2017, providing for the criminal liability of corporate entities for certain offenses against the public administration and cross-border bribery committed by, among others, of their attorneys-in-fact, directors, managers, employees, or representatives. A company found liable under this law may be subject to various sanctions, including, among others, fines from two to five times the undue benefit obtained or that could have been obtained and the partial or total suspension of their activities for up to ten years. In addition, this law extended the criminal liability under the Argentine Criminal Code to actions committed outside Argentina by Argentine citizens or companies domiciled in Argentina.

On April 5, 2018, the PEN issued Decree No. 277/18, which regulates the Corporate Criminal Liability Law, providing that the Anticorruption Office of the Ministry of Justice and Human Rights establishes guidelines to comply with the Corporate Criminal Liability Law’s provisions related to the Integrity Program. On October 1, 2018, the Anticorruption Office issued Resolution No. 27/18, which approved the “Integrity’s Guidelines for the best compliance of sections 22 and 23 of the Corporate Criminal Liability Law”.

Upon the enactment and entry into force of the Corporate Criminal Liability Law, our Board of Directors assessed the level of compliance with the Integrity Program set forth in sections 22 and 23 of such law, which seeks to implement a set of internal procedures, mechanisms and actions for integrity, supervision and control, geared at preventing, detecting and correcting the irregularities and acts covered by such law.

The Integrity Program set forth by law has mandatory and optional requirements, and we have defined the need to comply with all of them.

Furthermore, the Integrity Program is periodically monitored by our Board of Directors to identify the existence of improvement opportunities or necessary updates. Our Board of Directors has defined that our internal audit department will be responsible for the implementation of the Integrity Program.

Item 10.

Additional Information

MEMORANDUM AND ARTICLES OF ASSOCIATION

Corporate Purpose

On April 7, 2025, the General Ordinary and Extraordinary Shareholders’ Meeting approved the amendment of Article 4 of the Company’s by-laws. Such amended by-laws were filed with the SEC on Form 6-K on the same date. Article 4 of our by-laws, as amended, provides that our corporate purpose is to carry out the following activities: (a) Industrial: 1) Operations for the generation, transformation, transmission and distribution of electric power; 2) To explore, exploit, prospect, detect, probe and drill hydrocarbon and any other fields, areas and/or wells, and to develop mining activities generally; 3) to purchase, sell, lease and exploit drilling equipment, any spare parts and accessories thereof, and enter into any contracts and perform any acts and transactions related to mining extraction; 4) to manufacture, process, industrialize, purchase, sell, import, export and transport (i) hydrocarbons and any byproducts thereof belonging to the Company or to third parties, either liquid, solid or gaseous; and (ii) chemical products and those derived from the petrochemical industry, such as, without limitation, fertilizers; 5) to enter into any kind of contracts for the performance of works and/or services related to the foregoing activities; 6) Exploitation in any manner of agriculture, livestock-farming, fruit-growing, winemaking, olive grove, forestry growth and/or farming establishments; and 7) Production through any form of industrial process of agricultural or winemaking products or byproducts. (b) Commercial: Commercial transactions by importing, exporting, selling and purchasing, transporting, storing and distributing products, byproducts and goods related to the electric power generation process, mining production and agricultural and winemaking products and byproducts including the exercise or performance of activities as representative or commission, consignment and other agents. (c) Financial: Financial transactions generally; to extend loans and/or make capital contributions to individuals and companies in connection with business operations performed or to be performed; to provide guarantees, collateral and surety in favor of third parties; to sell, purchase and manage shares, governmental securities, debentures and other securities on any of the systems and in any form created or to be created, other than transactions falling within the scope of the Financial Entities Law. (d) Investment: Investing activities in undertakings and companies of any nature, in accordance with and subject to the limitations established by applicable laws and regulations; the Company may organize or take part in the organization of companies or purchase and hold equity interests in companies now existing or to be created in the future in Argentina or abroad, be a party to temporary business associations, cooperative associations, joint ventures and business associations. The Company may also, for investment purposes, purchase, develop and dispose of real and private property of any kind, encumber and convey and receive such property under a lease, a concession or a financial lease. (e) Services: To provide services or act as an agent in its name or for the benefit of third parties.

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Year-End Date

Our fiscal year-end date is December 31 each year.

Redemption and Withdrawal Rights

Our shares are subject to a proportional redemption in connection with a capital reduction by the vote of a majority of shareholders at an extraordinary shareholders’ meeting based on a favorable report of a statutory auditor. Any shares so redeemed must be cancelled by us.

If such were the case, we would be required to reimburse the value of the shares to the shareholders exercising such right in the cases described below.

Whenever our shareholders approve a spin-off or merger in which we are not the surviving corporation and the shares our shareholders receive as a result of such spin-off or merger are not publicly traded, the change of our corporate legal status, a fundamental change in our corporate purpose, change of our domicile outside of Argentina, voluntary withdrawal from public offering or delisting, our continuation in the case of mandatory delisting or cancellation of the public offering authorization, or a total or partial recapitalization following a mandatory reduction of our capital or liquidation, any shareholder that voted against such action or did not attend the meeting at which the decision was taken, may withdraw and receive the book value of its shares, determined on the basis of our latest balance sheet prepared or that should have been prepared in accordance with Argentine laws and regulations, provided that such shareholder exercises its appraisal rights within a determined period. However, because of the absence of legal precedent directly on point, there is doubt as to whether holders of ADSs will be able to exercise their appraisal rights either directly or through the depositary with respect to the shares represented by the ADSs. The appraisal rights must be exercised within the five days following the adjournment of the meeting at which the resolution was adopted, in the event that the dissenting shareholder voted against such resolution, or within 15 days following such adjournment if the dissenting shareholder did not attend such meeting and can prove that it was a shareholder on the date of such meeting. In the case of merger or spin-off, appraisal rights may not be exercised if the shares to be received as a result of such transaction are authorized for public offering or listed. Appraisal rights are extinguished if the resolution giving rise to such rights is revoked at another shareholders’ meeting held within 60 days of the meeting at which the resolution was adopted.

Payment on the appraisal rights must be made within one year of the date of the shareholders’ meeting at which the resolution was adopted, except when the resolution was to delist our shares or to continue following a mandatory delisting, in which case the payment period is reduced to 60 days from the resolution date.

Preemptive and Accretion Rights

Pursuant to section 194 of the LGS, holders of common shares have preemptive rights proportionate to the number of shares held by each holder, to subscribe for shares of capital of the same class owned by the shareholder, and accretion rights to subscribe additional common shares not subscribed by other shareholders on a pro rata basis. Preemptive rights and accretion rights may be waived only by each shareholder on a case-by-case basis. In accordance with section 194 of the LGS, our by-laws provide that the holders of common shares have preemptive rights to subscribe additional common shares in any amount sufficient to maintain their pro rata share of capital.

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In this way, pursuant to the LGS, in exceptional cases and on a case by case basis when required for the best interest of the company, the shareholders at an extraordinary meeting with a special majority may decide to limit or suspend shareholders’ preemptive rights, provided that the resolution is included in the agenda of the meeting and the shares to be issued are paid in kind or are issued to cancel preexisting obligations.

Pursuant to Section 6 of our by-laws, Shareholders shall be entitled to first-refusal and accretion rights for the subscription of any newly issued shares, pro rata to their respective shareholding, and the relevant notices shall be published to this effect as legally required. First-refusal and accretion rights may be exercised within the legally established periods and shall be solely limited or suspended by resolution of an Extraordinary Meeting of Shareholders in compliance with the conditions established by section 197 of the LGS.

According to our by-laws, (a) first-refusal and accretion rights shall be solely limited or suspended (i) in accordance with the Section 6 of the bylaws or (ii) when an Extraordinary Meeting of Shareholders approving an issuance of shares and convertible notes has resolved that first-refusal rights shall not be applicable both under section 194 of LGS and under the CML, and in such an event any shareholders wishing to take part in the capital increase shall not be entitled to first-refusal rights and compliance with the conditions for first-refusal rights to be suspended under section 197 of LGS shall not be required; (b) in case of a capital increase through the issuance of shares or convertible notes offered by means of a public offering under the CML and subject to the approval of the meeting of shareholders approving the respective issuance of shares and convertible notes, the first-refusal right contemplated in section 194 of LGS and section 11 of Law No. 23,576 and any other statutory rules that may replace them in the future shall be exercised by means of the placement procedure determined in the respective public offering prospectus; and the holders of shares and convertible notes, as the beneficiaries of such preemptive right, shall be acknowledged priority in the awarding of shares up to the amount they may be entitled to, based on their respective shareholding percentage. This shall be so provided that any purchase orders submitted by the shareholders or holders of convertible notes, as the beneficiaries of such first-refusal right, are placed at the price resulting from the placement procedure or at an established price either equal to or higher than the subscription price determined in the public offering, and accretion rights shall not be applicable. Until the new applicable law permits the foregoing provisions, section 6 of these bylaws shall be applied.

Pursuant to Argentine Law, if authorized by an extraordinary shareholders’ meeting, companies authorized to make public offerings of their shares may shorten the period during which preemptive rights may be exercised from 30 to up to ten days following the publication of the offering to the shareholders to exercise preemptive rights in the Official Gazette and a newspaper of wide circulation in Argentina. Preemptive rights are exercisable following the described publication (which has to be made for three days) for a period of 30 days, provided such period is not reduced as described above.

Shareholders who have exercised their preemptive rights have the right to exercise accretion rights at the same time, on a pro rata basis, with respect to any unsubscribed common shares. Shares not subscribed by shareholders by virtue of preemptive or accretion rights may be offered to third parties.

Holders of ADSs may be restricted in their ability to exercise preemptive rights if a prospectus under the Securities Act relating thereto has not been filed or is not effective or an exemption from registration is not available.

Voting Rights

Under our by-laws, our common shares entitle the holder thereof to one vote per share at any meeting of our shareholders.

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Dividends

In accordance with section 36 of our by-laws, our yearly net income (as adjusted to reflect changes in prior results) is allocated in the following order:

(1) to comply with our legal reserve policy requirement of 5% of our realized and liquid earnings until such reserve equals up to 20% of the capital (pursuant to section 70 of the LGS);

(2) to pay the accrued fees of the members of the Board of Directors and the Supervisory Committee;

(3) for voluntary or contingent reserves, as may be resolved from time to time by our shareholders at the annual ordinary shareholders’ meeting; and

(4) the remainder of the net income for the year may be distributed as dividends on common shares or as otherwise decided by our shareholders at the annual ordinary shareholders’ meeting.

Registration Requirements of Foreign Companies

Under the LGS, foreign companies that hold shares in an Argentine company must register with the public registry of commerce to exercise certain shareholder rights, including voting rights. The registration with the public registry of commerce in certain jurisdictions, such as in the City of Buenos Aires, requires the filing of corporate and accounting documents in order to demonstrate that the foreign shareholder: (1) is not a special purpose vehicle created solely to conduct business in Argentina, (2) owns non-current assets outside of Argentina that are significant compared to its assets owned or to be owned in Argentina and (3) is entitled to conduct business in its place of organization.

Under the CNV provisions, foreign companies could attend a shareholders’ meeting only with a dully authorized official, with no additional formal registration needed. The following are considered to be duly authorized: (i) the legal representative of the company in Argentina, and (ii) an attorney with enough power to represent the company in Argentina. The power could be granted in Argentina or abroad, complying with all legal and formal requirements (duly legalized and apostilled).

Liquidation Rights

Pursuant to section 109 of the LGS, in the case of our liquidation or dissolution, our assets will be applied to satisfy our outstanding liabilities and then proportionally distributed among holders of our shares.

Ordinary and Extraordinary Shareholders’ Meetings

Shareholders’ meetings may be ordinary meetings or extraordinary meetings. We are required to convene and hold an ordinary meeting of shareholders within four months of the close of each fiscal year to consider the matters specified in the first two paragraphs of Section 234 of the LGS, such as the approval of our financial statements, allocation of net income for such fiscal year, approval of the reports of the board of directors and the audit committee and election, performance and remuneration of directors and members of the supervisory committee. In addition, pursuant to the CML, at an ordinary shareholders’ meetings, our shareholders must consider (1) the disposition of, or creation of any lien over, our assets as long as such decision has not been performed under the ordinary course of business and (2) the execution of administration or management agreements and whether to approve any agreement by virtue of which the assets or services provided to us are paid partial or totally with a percentage of our income, results or earnings, if the payment is material when measured against the volume of the ordinary course of business and our shareholders’ equity. Other matters that may be considered at an ordinary shareholders’ meeting convened and held at any time include the responsibility of directors and members of the supervisory committee, capital increases and the issuance of certain notes. Extraordinary shareholders’ meetings may be called at any time to consider matters beyond the authority of an ordinary meeting including, without limitations, the amendment of our by-laws, issuance of debentures, early dissolution, merger, spin off, reduction of capital stock and redemption of shares, transformation from one type of entity to another, appointment, removal and retribution of the liquidators and limitation or suspension of shareholders’ preemptive rights.

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In accordance with Article 21 g) of our by-laws, our board of directors has broad borrowing powers, and may incur any indebtedness without the approval of the shareholders, unless the indebtedness consists of the issuance of notes (pursuant to Law No. 23,576) or debentures (pursuant to the LGS), in which cases, the decision must be approved by our shareholders as described above, except for such bonds that are not convertible into stocks.

On February 17, 2021, the Company’s General Ordinary and Extraordinary Shareholders’ Meeting approved the amendment of Section 30 of the Company’s by-laws in order to allow to virtually hold Shareholder’s meetings in the following way: Article 30: To be validly assembled, an Ordinary Meeting of Shareholders held on first call shall require the presence of shareholders representing a majority of voting shares, and on second call a Meeting shall be validly assembled with any number of such shares present. Extraordinary Meetings of Shareholders shall be validly held on first call with the presence of shareholders representing not less than 60% of voting shares, and on second call the presence of not less than 30% of such shares shall be required. The Shareholder’s Meetings may be held with its members present or communicated between them by other means allowing for the simultaneous transmission of sound, images and words, and Shareholders both present and attending remotely shall be computed for purposes of quorum and majority requirements. The minutes of these meetings shall be prepared and signed within five (5) days after the relevant meeting has been held by the President and the appointed Shareholders. If a Shareholders’ Meeting cannot be validly held due to the absence of the required number of attendants, and if an Ordinary Shareholders’ Meeting has not been convened on first and second call at the same time, the Meeting must be convened again within the following 30 days.

Notices of Meetings

Notices of shareholders’ meetings are governed by the provisions of the LGS. Furthermore, notice of shareholders’ meetings must be published for five days in the Official Gazette, in an Argentine newspaper of wide circulation and at the markets’ means of publications, at least 20 but not more than 45 days prior to the date on which the meeting is to be held. Such notice must include information regarding the type of meeting to be held, the date, time and place of such meeting and the agenda. If a quorum is not available at such meeting, a notice for a meeting on second call, which must be held within 30 days of the date on which the first meeting was called, must be published for three days at least eight days before the date of the meeting on second call. The above-described notices of shareholders’ meetings may be effected simultaneously for the meeting on second call to be held on the same day as the first meeting, only in the case of ordinary meetings and special shareholders’ meetings of a relevant class of shares. Shareholders’ meetings may be validly held without notice if all the shares of our outstanding share capital are present and resolutions are adopted by unanimous vote of shares entitled to vote.

Quorum and Voting Requirements

The quorum for ordinary meetings of shareholders on first call is a majority of the shares entitled to vote, and action may be taken by the affirmative vote of an absolute majority of the shares present that are entitled to vote on such action. If a quorum is not available at the first meeting a meeting on second call may be held at which action may be taken by the holders of an absolute majority of the shares present, regardless of the number of such shares. The quorum for an extraordinary shareholders’ meeting on first call is 60% of the shares entitled to vote, and if such quorum is not available, a meeting on second call may be held, for which the quorum is 30% of the shares entitled to vote.

Action may be taken at extraordinary shareholders’ meetings by the affirmative vote of an absolute majority of shares present that are entitled to vote on such action, except that: the approval of a majority of shares with voting rights (for these purposes, non-voting preferred shares shall have voting rights and multiple votes shares shall have one vote per share), is required at both the meetings on first and second call for: (1) the transfer of our domicile outside Argentina, (2) a fundamental change of the corporate purpose set forth in our by-laws, (3) total or partial recapitalization, (4) limitation or suspension of the shareholders’ preemptive and accretion rights, (5) the creation of voluntary reserves with the company’s net profits, if such funds together with the existing voluntary reserves exceeds the amount of capital stock and legal reserves, (6) continuation of the company upon delisting or cancellation of our public offering authorization or (7) merger or spin-off (except if we are the absorbing company), and (8) our anticipated dissolution.

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Pursuant to Article 33 of our by-laws: (1) any amendment to the regime of mandatory public tender offer upon acquisition of a controlling interest in our capital stock, as described below under “Mandatory Public Tender Offer Upon Acquisition of 50% of our Voting Shares,” requires for approval the favorable vote of shares representing at least 66.6% of the capital stock issued and outstanding, (2) any amendment to the rules of the Audit Committee as well as any amendment to the regime of mandatory public tender offer upon acquisition of a significant interest in our capital stock as described below under “Mandatory Public Tender Offer upon Acquisition of 35% of our Voting Shares,” shall require for approval the favorable vote of at least 66.6% of the shareholders in attendance at the meeting to the extent that they represent at least 35% of the capital stock issued and (3) any amendment to the special majority regime as established above which shall require for approval the same special majority intended to be amended.

Shareholders’ meetings may be called by the board of directors or the members of the supervisory committee whenever required by law or whenever they deem it necessary. Also, the board or the members of the supervisory committee are required to call shareholders’ meetings upon the request of shareholders representing an aggregate of at least five percent of our outstanding share capital in which case the meeting must take place within 40 days of such shareholders’ request. If the board of directors or the supervisory committee fails to call a meeting following such a request, a meeting may be ordered by the CNV or by the courts. In order to attend a meeting, a shareholder must also deposit with us a certificate of book entry shares registered in its name and issued by Caja de Valores at least three business days prior to the date on which the meeting is to be held. If so entitled to attend a meeting, a shareholder may be represented by proxy. Proxies may not be granted to our board, members of the supervisory committee, officers or employees.

Election of Directors

In accordance with Article 12 of our by-laws, our Board of Directors is composed of ten regular members appointed by the Ordinary Meeting of Shareholders. Our directors will be elected for a three-year term, which terms shall be in force until a replacement director is appointed. The election of our directors will be on a staggered basis, so that one third of the board membership is renewed each year. The directors will be elected by slate, always provided that no shareholder or group of shareholders holding more than 3% of our capital stock objects to such election method. In the event of such an objection, their election will be made individually. Any shareholder or group of shareholders who holds more than 3% of our capital stock (each, a Proposer) may require our Board to give notice to the other shareholders of the candidate slate or individual candidates to be proposed by such shareholder or group of shareholders to the shareholders’ meeting for election. In the case of depositary banks that are holders of shares of our common stock registered in their name, this rule will be applicable to the beneficiaries. To such end, the relevant slate executed by the Proposer or its representatives, as applicable, will be sent to the chairman of our board or whoever replaces him, no less than five business days prior to the date of the relevant shareholders’ meeting, so as to be officially notified by publication in the bulletin of the BASE at least two days prior to the meeting’s date. In order to facilitate the formation of the slates and the record of the candidates’ names, as of the date of the first notice calling for the relevant meeting, a special book will be made available to the shareholders at the registered office in which the names of the slates or candidates proposed by any shareholders shall be recorded. Similarly, our Board of Directors will propose to the shareholders’ meeting a slate of candidates for election by slate or individually, if the former election method were objected to, whose names will be made known to all the shareholders together with the slates proposed by the Proposer. In addition, no proposal for the election of directors may be made, either before or during the shareholders’ meeting, unless written evidence of acceptance of office by the proposed candidates is submitted to us. Such slate or person, as the case may be, who obtains the vote of a majority of the shares present at the meeting will be declared elected. If no slate obtains such majority, a new voting will be taken in which the two slates or persons that obtained the largest number of votes will take part, and the slate or person who obtains the largest number of votes will be declared elected. The preceding rules will not prevent a shareholder who is present at the shareholders’ meeting from proposing candidates not included in the proposals from our Board of Directors. All proposed directors must comply with our Nomination Policy rules prior to their designation.

There are no provisions under Argentine law or in our by-laws providing for the retirement of directors under an age limit requirement.

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Directors’ compensation

In accordance with Article 31 of our by-laws, our director’s compensation is considered and approved by our shareholders in an ordinary meeting held in compliance with the LSC. Additionally, pursuant to our Compensation Policy and the compensation committee charter, such committee considers any proposal related to the remuneration and compensation of the members of our board, before any non-binding proposal is submitted by our Board of Directors to the shareholders for their consideration.

Mandatory Public Tender Offer Upon Acquisition of 35% of Our Voting Shares

Our by-laws provide in Article 38 that in the event that any person, directly or indirectly, individually or in agreement with other persons, by any means or title (pursuant to a sale, an assignment, pursuant to foreclosure proceedings either at court or out of court, or pursuant to any other means of disposal or transfer), acquires or becomes the beneficial owner of shares of our common stock, options, warrants or securities of the company convertible into shares, convertible notes, GDRs or ADRs and options to acquire shares (together, our “Securities”) representing, or entitling in the event of conversion, when added to such person’s prior holding, if any, to 35% or more of our voting stock, even though such interest does not confer control over us, such person or group of persons shall be required to publicly tender for 100% of our outstanding capital stock and Securities at a price no less than the highest of: (1) the share price of the company in U.S. Dollars determined based on a valuation of our net worth prepared by an independent, internationally-recognized investment bank, the valuation must take into account an increase in the company’s capital stock as a result of the exercise of conversion rights as contained in the Securities and must be performed on the basis of the most recent balance sheet approved by the company; (2) 135% of the subscription price (denominated in U.S. Dollars), as of the date of subscription of any shares issued as a result of a capital increase during the 24-month period immediately preceding the date of the notice of such person or group of persons announcing the commencement of the mandatory tender offer for the acquisition of a significant interest herein established, adjusted to reflect any stock split, stock dividends, par value variation, capital reduction, earning capitalization, reserves, accounting adjustments or any other special item of our balance sheet or corporate transactions whereby bonus shares of our common stock and/or Securities are delivered; and (3) 135% of the weighted average listing price in U.S. Dollars (at closing of trading) of our shares of common stock and/or GDRs during the 120-day period immediately preceding the notice announcing the commencement of the mandatory tender offer due to acquisition of a significant interest, in the BASE and in New York and at any other exchange or market in which our shares and Securities are listed, adjusted to reflect any stock split, stock dividend, par value variation, capital reduction, earning capitalization, reserves, accounting adjustments or any other special item of our balance sheet or corporate transactions whereby bonus shares of our common stock and/or Securities are delivered.

Mandatory Public Tender Offer Upon Acquisition of 50% of Our Voting Shares

Our by-laws provide in Article 38 that in the event that any person, directly or indirectly, individually or in agreement with other persons, by any means or title (pursuant to a sale, an assignment, foreclosure proceedings either at court or out of court, or to any other means of disposal or transfer), acquires or becomes the beneficial owner of shares of our common stock and/or Securities, representing or entitling in the event of conversion, when added to such person’s prior holding, if any, more than 50% of our voting stock or in any other way entitling the purchaser to exercise the power to remove a majority of our directors (each, a Controlling Interest), prior to acquiring such Controlling Interest, such person or group of persons shall make a public tender offer to purchase shares of our common stock and Securities held by all other shareholders at a price no less than the highest of: (1) the share price of the company in U.S. Dollars, determined based on a valuation of our net worth prepared by an independent, internationally-recognized investment bank, the valuation must take into account an increase in the company’s capital stock as a result of the exercise of conversion rights as contained in the Securities of the company and must be performed on the basis of the most recent balance sheet approved by the company; (2) 135% of the subscription price denominated in U.S. Dollars, as of the date of subscription of any shares issued as a result of a capital increase during the 24-month period immediately preceding the date of the notice announcing the commencement of the mandatory tender offer for the acquisition of a significant interest herein established, adjusted to reflect any stock split, stock dividends, par value variation, capital reduction, earning capitalization, reserves, accounting adjustments or any other special item of our balance sheet or corporate transactions whereby bonus shares of our common stock and/or Securities are delivered; (3) 135% of the weighted average listing price in U.S. Dollars (at closing of trading) of our shares of common stock and/or GDRs or ADRs during the 120-day period immediately preceding the notice announcing the commencement of the mandatory tender offer due to acquisition of a significant interest, in the BASE and in New York and at any other exchange or market in which our shares and Securities are listed adjusted to reflect any stock split, stock dividends, par value variation, capital reduction, earning capitalization, reserves, accounting adjustments or any other special item of our balance sheet or corporate transactions whereby bonus shares of our common stock and/or Securities are delivered; and (4) the highest price per share or Securities paid by such person or on behalf of such person, in relation to any acquisition of shares and/or Securities within a period of two years immediately prior to the announcement of Acquisition of a Controlling Interest, adjusted to reflect any stock split, stock dividend, par value variation, capital reduction, earning recapitalization, reserves, accounting adjustments or any other special item of our balance sheet or corporate transactions whereby shares of our common stock or other securities are delivered.

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Duty to Inform

Our by-laws provide in Article 38 that any person, whether acting directly or indirectly through other persons or legal entities, as well as any group of people acting in agreement with other persons, who (1) acquires or sells our shares of common stock or Securities by any means or title, (2) alters the configuration or composition of its direct or indirect interest in our capital stock, (3) converts notes into shares of common stock, (4) exercises options to purchase any convertible securities mentioned or (5) changes its intention with respect to its interest in our capital stock, in existence at the time any of the assumptions provided for in preceding (1) to (4), as long as, in each case, the purchase made in each of such assumptions grants control over 5% or more of our capital stock or voting rights, shall, immediately upon consummation of the transaction or change in intentions, inform us of such circumstances, irrespective of compliance with any additional duty that applicable securities rules and regulations may require if such were the case. Future transactions for an amount equivalent to a multiple of 5% of our capital stock or voting rights must also be communicated to us.

Form and Transfer

Our current share capital is represented by book-entry shares. Our shareholders are required to hold their shares through book-entries directly made by Caja de Valores in the shares registry of the company carried by Caja de Valores or through book-entries with brokers, banks and other entities approved by the CNV that have accounts with Caja de Valores, or with the participants of Caja de Valores. Caja de Valores is in charge of maintaining a shares registry on our behalf based on information received from shareholders that choose to hold their shares directly by registration on the shares registry of the company and from participants of Caja de Valores, and in accordance with Argentine Law only those holders listed in the shares registry either directly or through participants of Caja de Valores will be recognized as shareholders. Shares held by participants of the Caja de Valores have the same rights as shares recorded in our shareholders’ register.

MATERIAL CONTRACTS

Not Applicable.

EXCHANGE CONTROLS

The following is a summary of the main measures taken by the BCRA with the purpose of regulating inflows and outflows in the MLC to maintain the exchange rate stability and protect international reserves in view of the high degree of uncertainty and volatility in the exchange rate by tightening exchange controls and restrictions on the inflow and outflow of foreign exchange. In this regard, the BCRA issued a series of communications which introduced restrictions associated, among other factors, with transactions with stock market assets by companies and the disposal of liquid foreign assets, thus imposing further restrictions on access to the MLC. The latest consolidated text of the applicable foreign exchange regulations as of the date of this annual report can be found in Communication “A” 8307 (as amended, the “FX Regulations”). Through the FX Regulations, the BCRA consolidated the regulations concerning foreign affairs and exchanges into a single body, incorporating successive modifications that had been made to the previous consolidated text and introducing certain amendments.

Among the most important provisions regarding income from the MLC contained in the FX Regulations, the following may be highlighted: (i) the obligation to enter and settle foreign currency transactions in the foreign exchange market within certain specified terms resulting from the export of goods and services by residents and from the receipt of amounts in foreign currency from the disposal to non-residents of non-produced non-financial assets, (ii) the obligation to enter and settle in the MLC disbursements resulting from foreign financial indebtedness of residents after September 1, 2019 and the amounts resulting from the issuance of securities denominated and subscribed in foreign currency with public registration in the country beginning on November 29, 2019, as a requirement, together with the declaration in the BCRA’s survey of foreign assets and liabilities, for the subsequent access to the MLC in order to meet the payment of the principal sum and its interest, and (iii) the possibility for entities to carry out swaps and arbitration transactions with customers to the extent that they do not correspond to transactions covered by the obligation to settle in the MLC, among others.

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There are differences throughout the FX Regulations between the regime applicable to legal entities and that applicable to individuals. As from Communication “A” 8226, many of the limitations and requirements previously applicable to individuals ceased to apply, given that this communication established that individual residents may access the MLC without prior approval from the BCRA for the purchase of foreign currency for holding or for the establishment of deposits (concept codes A07 and A09), subject to certain requirements but under a more flexible framework than that applicable under the prior regime.

The most important provisions concerning the specific outflow requirements of the MLC are:

(i)

the imposition of certain restrictions for access to the MLC for the payment of imports and import debts, including interest of goods and services by residents abroad;

(ii)

the need to comply with the requirements set forth in section 3.4 of the FX Regulations, under which the foreign exchange regulations allow access to the MLC for the transfer abroad of foreign currency from profits and dividends. to non-resident shareholders;

(iii)

the obligation to comply with certain requirements for those who intend to access the MLC for the repayment of the principal sum and interest of financial indebtedness abroad, such as (a) to demonstrate the entry and liquidation of foreign currency in the MLC for an amount equivalent to the nominal value of the financial indebtedness abroad, except in certain cases in which it is considered to be complied with, (b) to contain the declaration corresponding to the indebtedness in question in the last due presentation of the survey of foreign assets and liabilities, (c) the access to the MLC must take place no more than three (3) business days prior to maturity date of the principal sum or interest to be paid, unless the BCRA previously agrees or under the fulfillment of certain requirements and conditions, (d) the possibility of prepaying principal and interest simultaneously with the settlement of a new financial borrowing abroad, under certain situations; (e) the need for BCRA’s prior authorization to access the MLC for the cancellation at maturity date of the principal amount of the financial indebtedness of the non-financial private sector abroad when the creditor is a counterparty related to the debtor, except for certain transactions, provided they fall within the scenarios contemplated under section 3.5.6 of the FX Regulations, (f) the lack of BCRA’s prior approval to access the MLC for the payment at maturity date of the principal amount and interest of foreign financial indebtedness, when certain conditions are met, (g) the possibility that financial indebtedness with foreign countries may be cancelled, including its principal sum and interest services, as of its maturity through the application of collections of exports of goods and services, to the extent that certain requirements are met, allowing for said collections to be accumulated, for the amounts required in the indebtedness contracts, in accounts abroad and/or in the country in order to guarantee the cancellation of services of the financial indebtedness with foreign countries;

(iv)

access to the MLC to make interest payments on commercial debts for the import of goods and services with related parties abroad as long as the interest maturity occurs from July 5, 2024;

(v)

the prohibition of access to the MLC for the payment of debts and other obligations in foreign currency between residents entered into as of September 1, 2019, except for the cancellation as from the maturity of the principal amount and interest of (a) financing in foreign currency granted by local financial entities, including payments for consumption in foreign currency made through credit or purchase cards, except for the settlement of overdrafts in U.S. Dollar-denominated checking accounts, which may only be made with funds in such currency that are freely available to the customer, (b) the issuance of debt securities made as of September 1, 2019 with the purpose of refinancing debts included in item 3.6.2. of the FX Regulations and that entail an increase of the average duration of the obligations (c) issues made beginning on November 29, 2019 of debt securities with public registration in the country, denominated and subscribed in foreign currency and whose services are payable in foreign currency in the country, to the extent that the total of the funds obtained have been settled in the MLC. In case of debt securities issued by local financial institutions through transactions entered into as from May 26, 2025, payment shall take place only after a minimum period of 12 months has elapsed from their date of issuance, (d) promissory notes with public offering issued under CNV Resolution No. 1003/24 and related, denominated and subscribed in foreign currency and whose principal and interest services are payable in foreign currency in the country, provided that all the funds obtained have been settled in the exchange market, (e) Fiduciary debt securities issued by trustees of financial trusts with a public offering carried out in accordance with the provisions of the CNV on the matter, denominated and subscribed in foreign currency and whose principal and interest services are payable in foreign currency in the country, to the extent that all the funds obtained have been settled in the MLC, (f) issuances of securities falling within items (c) through (e) above (Sections 3.6.1.3 through 3.6.1.5 of the FX Regulations) that did not give rise to any disbursements, as they constituted restructurings of indebtedness falling within those same items, to the extent that such refinancings do not accelerate maturities of the original debt;

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(vi)

the possibility of accessing the MLC for the cancellation, upon maturity, of (A) foreign currency obligations between residents instrumented through public registries or deeds as of August 30, 2019, and (B) foreign currency financing granted by local financial institutions outstanding as of August 30, 2019;

(vii)

the need for BCRA’s prior authorization to access the MLC prior to maturity for debts between residents, unless the transaction falls under any of the situations and all the conditions stipulated in section 3.6.4. and concordant provisions of the FX Regulations, such as (a) financing from local entities for consumption in foreign currency through credit or purchase cards, (b) other financing in foreign currency from local financial entities, except for the settlement of overdraft balances in U.S. Dollar-denominated checking accounts, paid with the income from financial indebtedness abroad, (c) pre-cancellation of interest within the framework of a debt security exchange process, (d) pre-cancellation of principal and interest of a debt security registered in the country simultaneously with the settlement of a financial indebtedness abroad, (e) pre-cancellation of principal and interest of a debt security registered in the country simultaneously with the settlement of a new debt security, (f) Pre-cancellation of principal and interest by a VPU adhering to the RIGI;

(viii)

the possibility for entities to grant access to the MLC to make payments of principal amount and/or interest to trusts constituted in the country by a resident to guarantee the payment of principal amount and interest services of its obligation, to the extent that it verifies that the debtor would have had access to make the payment on its behalf by complying with the applicable regulatory provisions;

(ix)

resident individuals’ access to the MLC for the purchase of foreign currency in cash for savings purposes or for the establishment of deposits (concept codes A07 and A09), without the need for prior authorization from the BCRA, provided that all of the requirements set forth in Section 3.8 of the FX Regulations are complied with;

(x)

the need for BCRA’s prior authorization to access to the MLC by legal entities for the constitution of external assets and for the constitution of all kinds of guarantees related to the arrangement of derivative transactions;

(xi)

in connection with the purchase of foreign currency for transactions with financial derivatives (a) entities may grant access to the MLC for the payment of premiums, constitution of guarantees and payments corresponding to interest rate hedging contract transactions for the obligations of residents abroad declared and validated, if applicable, in the survey of external assets and liabilities, as long as higher risks are not covered in foreign liabilities that the debtor actually registers in the interest rate which risk is being covered with the execution (b) the remaining financial derivative transactions to be carried out with access to the MLC by residents that are not entities authorized to operate in foreign exchange shall be governed by the provisions of points 3.8. and 3.10. of the FX Regulations, as applicable, and (c) all settlements of futures transactions in regulated markets, forwards, options and any other type of derivatives arranged in the country carried out by entities beginning on September 11, 2019 must be made in local currency;

(xii)

limitations on access to the MLC for the repatriation of investments by non-residents, which require prior authorization from the BCRA pursuant to Section 3.13 of the FX Regulations, and which provide for certain exceptions, including those set forth in Section 3.13.1.12, relating to the repatriation by non-residents of principal, income and proceeds from the sale of portfolio investments in instruments quoted on local markets authorized by the CNV, subject to the requirements specified therein.

(xiii)

regarding to swaps and arbitrages with clients not associated with an inflow of foreign currency from abroad, entities may carry out with their clients swap and arbitrage transactions not associated with an inflow of foreign currency from abroad in the following cases (a) transfer of foreign currency abroad of human persons from their local accounts in foreign currency to their own bank accounts abroad, (b) transfer of foreign currency abroad for the payment of imports of goods and services pursuant to the provisions of sections 10.10.2.13, 10.10.2.14 and 13.3.9., using foreign currency funds deposited in local financial institutions, (c) arbitrage transactions not involving transfers abroad may be carried out without restrictions as long as the funds are debited from a foreign currency account of the customer in a local financial entity, (d) swap and arbitrage operations with funds deposited in a local account and originating from capital and interest collections in foreign currency of BOPREAL bonds, as long as the required conditions are met and are intended for (i) the payment of commercial debts for imports of goods with customs entry registration until 12.12.23, (ii) the payment of commercial debts for services provided or accrued until 12.12.23, (iii) the payment of debts to non-resident shareholders for profits and dividends as stipulated in point 4.6.1 of the FX Regulations, and (iv) the repatriation of portfolio investments of non-residents originating from profits and dividends collected in the country since 9.1.19, (v) payment of principal and compensatory interests on indebtedness owed to related parties that were eligible pursuant to the provisions of section 4.7.of the FX Regulations, and (e) the remaining swap and arbitrage transactions may be carried out with customers without the prior approval of the BCRA to the extent that, if implemented as individual transactions passing through Pesos, they may be carried out without such approval in accordance with the exchange regulations in force, being this applicable to local central securities depositories for the funds received in foreign currency for the services of capital and income of foreign currency securities paid in the country; and

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(xiv)

In line with the provisions of Decree No. 892/20 with respect to transactions intended to finance projects under the Plan Gas.Ar, the BCRA has provided that that entities may access the MLC to (i) remit foreign currency abroad as profits and dividends to non-resident shareholders as of the second year of the investment and when they correspond to closed and audited balance sheets, and for an amount not exceeding the amount corresponding to them according to the distribution determined by the shareholders’ meeting; (ii) to pay the maturity of principal and interest services of indebtedness abroad, provided that the indebtedness has an average life of not less than 2 years; (iii) in case of repatriation of direct investments of non-residents, beginning in the second year, up to the amount of the direct investment contributions settled in the foreign exchange market in the case of capital reduction and/or return of irrevocable contributions made by the local company, when the documentation proving that the applicable legal requirements have been complied with and it has been verified that it has been declared, if applicable, in the last due presentation of the “Relevamiento de activos y pasivos externos” (Survey of Foreign Assets and Liabilities). The transactions covered will be the transactions that have been entered and settled by the MLC as of November 16, 2020 and destined to the financing of projects within the framework of the Plan Gas.Ar. In all cases, the entity must have the documentation that allows it to verify the genuine nature of the operation to be carried out and that the funds were destined to finance projects included in the Plan Gas.Ar.

In turn, Section 3.16. of the FX Regulations established complementary requirements in connection with outflows through the MLC, the most important provisions include:

(i)

prior authorization from the BCRA in the event that the customer is an individual or legal entity included by ARCA in the database of invoices or equivalent documents classified as apocryphal. This requirement does not apply to access to the market for the repayment of foreign currency financings granted by local financial institutions, including payments for foreign currency-denominated transactions made through credit or purchase cards;

(ii)

for certain operations, the prior authorization of BCRA is required to access the MLC, unless the entity has a sworn statement from the customer regarding its holdings of liquid foreign assets -with a few exceptions-, stating that (a) all of its foreign currency holdings in the country are deposited in accounts in financial institutions and that it did not possessed Argentine Certificates of Deposit representing foreign shares (CEDEARS) and/or liquid foreign assets available at the beginning of the day on which it requests access to the market for an amount greater than U.S.$ 100,000 (one hundred thousand dollars), being considered liquid external assets, among others: holdings of banknotes and coins in foreign currency, cash in gold coins or bars of good delivery, demand deposits in financial institutions abroad and other investments that allow obtaining immediate availability of foreign currency (for example, investments in external public securities with custody in the country or abroad, funds in investment accounts with investment managers based abroad, crypto-assets, funds in accounts of payment service providers, etc.) and excluding those funds deposited abroad that could not be used by the client because they are reserve or guarantee funds constituted by virtue of the requirements set forth in debt contracts, export pre-financings covered by Section 7.8.5 of the FX Regulations or funds provided as collateral for derivative transactions entered into abroad. In the event that such liquid foreign assets exceed U.S.$ 100,000, an additional affidavit may be submitted stating that such excess no longer exists because, among others, the amount exceeding the specified limit corresponds to funds deposited in bank accounts abroad, originating from the new financial indebtedness abroad in the last 180 calendar days and received on or after November 29, 2024; and

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(iii)

the need for BCRA prior authorization to access the MLC (not applicable to individual residents), unless the entity has a sworn statement from the customer with a few exceptions stating that (a) on the day it requests access and in the previous 90 calendar days, it has not entered into sales in the country of securities issued by residents for foreign assets with settlement in foreign currency exchanges of securities issued by residents for foreign assets, transfers of securities to depository entities abroad, acquisitions in the country with settlement in pesos of securities issued by non-residents , acquisitions of CEDEAR representing foreign shares of securities, acquisitions of securities representing private debt issued in foreign jurisdiction or deliveries of funds in local currency or other local assets (except funds in foreign currency deposited in local financial institutions) to any person (whether individual or legal, resident or non-resident, related or not), receiving as prior or subsequent consideration, directly or indirectly, by itself or through a related, controlled or controlling entity, external assets, crypto-assets or securities deposited abroad; and finally, there must be a commitment not to conclude the detailed operations during the 90 calendar days following the request for access to the MLC. Likewise, for the access of legal entities to the MLC, it is required to submit an additional affidavit stating: (a) the details of the individuals or legal entities that exercise direct control, according to the rules of the BCRA; and (b) that on the day on which access to the MLC is required and in the previous 90 calendar days, no funds in local currency or other liquid local assets (except funds in foreign currency deposited in local financial institutions) were delivered in Argentina, to any individual or legal entity exercising direct control, or to other companies with which it is part of the same economic group, except for those directly associated with habitual transactions for the acquisition of goods and/or services. The requirement indicated in item (b) may be considered fulfilled if an affidavit is submitted with respect to transactions with securities of each of those individuals or legal entities, in accordance with the exchange regulations in force. Finally, the BCRA established that sales of securities settled in foreign currency in the country or abroad should not be taken into account when all the funds obtained from such settlements have been used or will be used within 10 calendar days of the certain operations listed in item 3.16.3.6.iii) of the FX Regulations.

For more information regarding Argentina’s foreign exchange policies, you should seek advice from your legal counsel and read the applicable rules mentioned herein, including their amendments, which can be found at the following websites: www.infoleg.gov.ar and the Central Bank’s website: www.bcra.gob.ar. The information contained on these websites is not part and shall not be deemed incorporated into this annual report.

TAXATION

The following summary contains a description of the principal Argentine and U.S. federal income tax consequences of the acquisition, ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all the tax considerations that may be relevant to a decision to purchase common shares or ADSs. The summary is based upon the tax laws of Argentina and regulations thereunder and on the tax laws of the United States and regulations thereunder as in effect on the date hereof, which are subject to change. No assurance can be given that the courts or tax authorities responsible for the administration of the laws and regulations described herein will agree with this interpretation. Investors should consult their own tax advisors as to the tax consequences of the Acquisition, ownership and disposition of common shares or ADSs.

There are agreements, currently in force, between Argentina and the United States on the exchange of Country-by-Country Reports and automatic exchange of financial account information to facilitate implementation of the U.S. Foreign Account Tax Compliance Act (FATCA), but there is no tax treaty or convention in effect between both countries.

Although there is currently no income tax treaty between Argentina and the United States, there have been negotiations between tax authorities of both countries that may derive in the celebration of such treaty. No assurance can be made as to whether or when a treaty will enter into force or how it will affect the U.S. holders of common shares or ADSs.

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Argentine Tax Considerations Capital gains tax

Resident individuals

Law No. 27,430 provides for the taxation of Argentine resident individuals’ income from the sale, exchange or other disposition of shares will be subject to income tax rate of 15%.

The Tax Reform establishes an exemption for individuals tax residents on the sale of shares that are publicly traded in stock exchanges under the supervision of the Argentine Securities and Exchange Commission (CNV).

Foreign beneficiaries

Pursuant to Law No. 27,430, all income resulting from the purchase and sale, exchange or other disposition of shares and other securities earned by foreign beneficiaries will be exempt of the income tax, if they are (i) listed on stock exchanges or securities markets and/or have an authorization for public offering under the supervision of the CNV and (ii) the foreign beneficiaries do not reside in or the funds do not arise from “non-cooperating jurisdictions” (the “publicly traded exemption”). In case the disposition does not meet the requirement mentioned in (i) above and the foreign beneficiaries do not reside in or the funds do not arise from “non-cooperating jurisdictions”, the income obtained will be taxable at a 13.5% rate on the gross price or 15% rate on the net capital gain (with the possibility of adjusting the value of acquisitions from January 1, 2018 and onwards for the purpose of determining the net capital gain, taking into account the variation of the Internal Wholesale Price Index).

In case the foreign beneficiaries reside in or the funds arise from “non-cooperating jurisdictions”, the tax rate applicable for the sale, exchange or other disposition of shares and/or ADSs amounts to 35%. The non-cooperating jurisdictions list is prepared and published by the executive branch. The ARCA has prepared an indicative and non-exhaustive list of jurisdictions considered to be low-or-no-tax jurisdictions, which can be consulted on their web site at: https://www.afip.gob.ar/fiscalidad-internacional/jurisdicciones-no-cooperantes/jurisdicciones-baja-nula-tributacion/que-son.asp. The U.S. is currently not a non-cooperating jurisdiction.

The Tax Reform, effective as of January 1, 2018, specifies that in case of share certificates issued abroad that represent shares issued by Argentine companies (i.e., ADSs), the “source” is defined by the location of the original issuer of the shares. However, the tax will not be due if the publicly traded exemption, described above, applies in respect of the underlying shares.

Local entities

Capital gains obtained by Argentine entities in general, entities organized or incorporated under Argentine law, certain traders and intermediaries, local branches of non-Argentine entities, sole proprietorships and individuals carrying on certain commercial activities in Argentina derived from the sale, exchange or other disposition of our common shares or ADSs are subject to income tax at the rate of 30% for fiscal periods starting on January 1, 2018 until January 1, 2021, and 25% for the fiscal periods starting thereafter. Losses arising from the sale of our common shares or ADSs can be applied to offset such income.

Additionally, a withholding of 7% or 13% is established for the periods mentioned above, on the dividends distributed by the capital companies in favor of their shareholders, when they are legal persons or undivided successions resident in the country, or are foreign beneficiaries.

Law No. 27,630 established a tiered marginal tax rate structure with three segments depending on the level of accumulated taxable net income. The new tax rate structure is applicable for the fiscal year starting on January 1, 2021 and the amounts comprehended in the referred scale are adjusted annually since January 1, 2022, considering the annual variation of the IPC provided by the INDEC, for the month of October of the previous year of the adjustment, in respect with the same period of the previous year. The amounts fixed by the described mechanism will be applicable for the tax years beginning after each adjustment.

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Dividends tax

Pursuant to Law No. 26,893, dividends and other profits paid in cash or in kind —except for stock dividends—by companies and other entities incorporated in Argentina referred to in the Argentine Income Tax Law (the “Income Tax Law”), Sections 73 (a)(1), (2), (3), (6) and (7), and Section 69(b), were subject to income tax at a 10% rate except for those beneficiaries that were domestic corporate taxpayers. Law No. 27,260 repealed this withholding tax as of July 23, 2016. Consequently, no withholding tax is to levied on dividends distributed to either Argentine or non-Argentine resident shareholders since then. This treatment applies only to dividends to be distributed at any time out of retained earnings accumulated until the end of the last fiscal year starting before January 1, 2018.

Likewise, the portion of those dividends exceeding the company’s accumulated net taxable income (as determined by application of the Argentine Income Tax Law), if any, is subject to a 35% withholding tax on such excess (the “Equalization Tax”). For purpose of the Equalization Tax, the amount of accumulated net taxable income to be considered shall be determined by (1) deducting the income tax paid by the company, and (2) adding the dividends and profits not subject to tax received as distributions from other corporations. If the distribution is in-kind, then the corporation must pay the tax to the Argentine tax authorities and will be entitled to seek reimbursement from the shareholders.

Dividends to be distributed out of earnings accrued in fiscal years starting on or after January 1, 2018, are to be subject to a tax treatment different from the one previously described, based on the recent enactment of a comprehensive tax reform (Law No. 27,430), published in the Official Gazette on December 29, 2017, and generally effective since January 1, 2018.

Pursuant to Law No. 27,430, dividends and other profits paid in cash or in kind —except for stock dividends—by companies and other entities incorporated in Argentina referred to in the Argentine Income Tax Law, Sections 73 (a)(1), (2), (3), (6), (7) and (8), and Section 73(b) out of retained earnings accumulated in fiscal years starting on or after January 1, 2018, will be subject to withholding tax at a 7% rate (on profits accrued during fiscal years starting January 1, 2018 until January 1, 2021), and at a 13% rate (on profits accrued for the fiscal years starting thereafter), provided that they are distributed to Argentine resident individuals and foreign shareholders (including holders of common shares or ADSs).

Nevertheless, Law No. 27,630 modified the above mentioned 13% rate to 7% rate for fiscal year starting on January 1, 2021.

With respect to dividends paid to shareholders residing abroad, such withholding may be reduced by a tax treaty between Argentina and their country of residence. See “Tax Treaties” below.

Capital reductions and other distributions

Capital reductions and redemptions of our common shares and ADSs are not subject to income tax up to an amount equivalent to the contributed capital corresponding to the common shares and ADSs to be redeemed. Any distribution exceeding this amount, however, will be considered as a dividend for tax purposes and subject to withholding tax as described above.

Other Income Tax provisions

Transfer pricing

The Transfer Pricing regime includes import and export controls of any product with the intervention of an international intermediary, that is not the importer at destination or exporter at origin, respectively.

In addition, for exports of goods with known prices and with the intervention of an intermediary (either related, or located in “non-cooperating” or low or no tax jurisdictions), the law requires the Argentine exporter to file with ARCA the agreements supporting the transactions.

Equalization income tax

Equalization income tax established by section 74 of the Income Tax Law will not be applicable on profits generated on or after January 1, 2018.

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Upgrade

The Tax Reform re-establishes the adjustment for inflation procedures in the Income Tax Law with the following rules: (i) inflation adjustment of new acquisitions and investments carried out from January 1, 2018 and onwards, considering the variation of the Internal Wholesale Price Index (in Spanish, Indice de Precios Internos al Consumidor Nivel General or IPC) supplied by the INDEC; and (ii) the application of an integral inflation adjustment mechanism when, the variation of the IPC is higher than 100% for the 36-month period before the end of the fiscal period or else, with respect to the first, second and third fiscal year of effectiveness, this procedure will be applicable in case the accumulated variation of the IPC, calculated from the beginning of the first of them and until the end of each year, exceeds fifty-five percent (55%), thirty percent (30%) and fifteen percent (15%) for the first, second and third year of application, respectively. The inflation adjustment that must be calculated in the first three fiscal years beginning on January 1, 2018 must be charged in equal quotas (1/3 in fiscal period 2018 and the remaining 2/3 in equal parts in the remaining fiscal periods, and 1/6 in fiscal periods 2019 and 2020, and the remaining 2/6 in equal parts in the remaining fiscal periods).

Law No. 27,701 included an important measure in regard to the tax inflation adjustment requirements, which provides that if a taxpayer determines a positive adjustment for inflation according to the requirements in the first and second fiscal years beginning on 1 January 2022, the taxpayer may allocate one-third in that fiscal year and the remaining two-thirds, in equal parts, in the two immediately following fiscal years. These beneficial allocation terms are limited to taxpayers that invest at least ARS 30,000,000,000 in the purchase, construction, manufacture, processing, or definitive importation of fixed assets (except automobiles) during each of the two fiscal years immediately following the year of the initial one-third allocation. Failure to comply with the investment condition will cancel the benefit.

Personal assets tax

Argentine entities, such as us, are required to pay the personal assets tax corresponding to Argentine and foreign individuals and foreign entities for the holding of our shares at December 31 of each year. The applicable tax rate is 0.5% and is levied on the equity value, or the book value, of the shares arising from the last balance sheet. Pursuant to the Personal Assets Tax Law, the Argentine company is entitled to seek reimbursement of such paid tax from the applicable Argentine individuals and/or foreign shareholders or by withholding dividend payments.

Asset Regularization Regime

Law No. 27.743 established an Asset Regularization Regime. This law provides taxpayers with a clear legal framework to disclose undeclared assets located in Argentina or abroad. The voluntary regime allows individuals, undivided estates and entities to bring previously unreported assets into compliance. This includes real estate, financial instruments and other properties, under specific conditions. Adhering to this regime avoids fines and penalties associated with non-compliance. The law also offers reduced tax rates based on the type and timing of the disclosure, incentivising early participation.

Gross Income Tax

The gross income tax is a local tax; therefore, the rules of the relevant provincial jurisdiction should be considered, which may levy this tax on the customary purchase and sale, exchange or other disposition of common shares and ADSs, and/or the collection of dividends at an average rate between 5% and 10%, unless an exemption is applicable. In the particular case of the City of Buenos Aires, any transaction involving common shares and/or the collection of dividends and revaluations is exempt from this tax. To date, there is no withholding regime provided for foreign holders of common shares and ADSs.

Value added tax

The sale, exchange or other disposition of our common shares or ADSs and the distribution of dividends are exempted from the value added tax.

Transfer taxes

The sale, exchange or other disposition of our common shares or ADSs is not subject to transfer taxes.

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Stamp taxes

Stamp taxes may apply in the City of Buenos Aires and in certain Argentine provinces in case transfer of our common shares or ADSs is performed or executed in such jurisdictions by means of written agreements.

Other taxes

Commissions paid on brokerage transactions for the sale of our common shares on the BCBA are subject to VAT at a rate of 21%.

There is no inheritance, gift, succession or VAT applicable to the ownership, transfer, exchange or disposition of our common shares or ADSs, except for the inheritance tax applicable only to corporations or individuals with tax domicile in the Province of Buenos Aires with a fixed amount tax plus a tax rate between 1.603% and 9.513% depending on the relationship and the amount of inheritance.

Tax for an inclusive and caring Argentina (Impuesto Para una Argentina Inclusiva y Solidaria “PAIS”)

The Social Solidarity and Productive Reactivation Law, established on an emergency basis and for the term of five fiscal periods as of the entry into force, a 30% tax on the purchase of foreign currency and other foreign exchange operations carried out by individuals and legal entities resident in Argentina.

As of 23 December 2024, the referred tax has been eliminated, after being in force for five years. The rates varied over the years, with the latest applicable rates being: (i) 7.5% on the acquisition abroad of freight services and other transportation services for import or export operations of goods, or their acquisition in the country when provided by nonresidents, (ii) 7.5% on the import of goods, except luxury goods, and (iii) 25% on the import of services.

The potential investors of the ADS should consult their own tax advisers about the effects of the aforementioned tax according to their particular circumstances.

Tax treaties

Argentina has signed tax treaties for the avoidance of double taxation with Australia, Belgium, Bolivia, Brazil, Canada, Chile, Denmark, Finland, France (which amendment protocol is pending ratification), Germany, Italy, Mexico, Norway, Qatar, Russia, Spain, Sweden, Switzerland, Turkey, The Netherlands, the People’s Republic of China, United Arab Emirates, United Kingdom, and Uruguay (through an information exchange treaty that contains clauses for avoidance of double taxation). In addition, Argentina has signed tax treaties Austria, Japan and Luxembourg, but they are still pending approval by the Argentine Congress. In turn, tax treaties have been negotiated with Saudi Arabia, Korea, Kuwait and the Czech Republic and are awaiting to be signed by the parties. Furthermore, tax treaties are being negotiated with Colombia, India and Israel, and amendments to the current tax treaty with Germany. There are currently agreements between Argentina and the United States on the exchange of Country-by-Country Reports, and automatic exchange of financial account information to facilitate implementation of the U.S. Foreign Account Tax Compliance Act (FATCA), but there is no tax treaty or convention in force between both countries. It is not clear when, if ever, a treaty will be ratified or entered into effect. As a result, the Argentine tax consequences described in this section will apply, without modification, to a holder of our common shares or ADSs that is a U.S. resident. Foreign shareholders located in certain jurisdictions with a tax treaty in force with Argentina may be exempted from the payment of the personal asset tax.

Argentina enacted Law No. 27,788, through which it ratified the “Multilateral Convention to Implement Tax Treaty-Related Measures to Prevent Base Erosion and Profit Shifting” (MLI). The ratification will be effective as of January 1, 2026. The convention enables the incorporation of anti-abuse clauses, improvement in the definition of permanent establishment, and optimization of dispute resolution mechanisms between countries. It also allows for changes to be made to the existing network of double tax treaties without renegotiating each agreement bilaterally.

United States Federal Income Tax Considerations

This summary describes certain U.S. federal income tax consequences for a U.S. holder (as defined below) of acquiring, owning, and disposing of ADSs. This summary applies to a U.S. holder only if such holder holds the ADSs as capital assets for tax purposes. This summary does not address the Medicare tax on net investment income or the alternative minimum tax and does not apply to investors that are members of a class of holders subject to special rules, such as:

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a dealer in securities or currencies;

a trader in securities that elects to use a mark-to-market method of accounting for securities holdings;

a bank;

a life insurance company;

a tax-exempt organization;

an entity treated as a partnership for U.S. federal income tax purposes, or a partner therein;

a person that holds ADSs that are a hedge or that are hedged against interest rate or currency risks;

a person that holds ADSs as part of a straddle or conversion transaction for tax purposes;

former citizens or residents of the United States;

a person whose functional currency for U.S. tax purposes is not the U.S. Dollar; or

a person that owns or is deemed to own 10% or more of any class of our stock.

This summary is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations promulgated thereunder, published rulings and court decisions, all as currently in effect. These laws are subject to change, possibly on a retroactive basis. Investors should consult their own tax advisors concerning the consequences of purchasing, owning, and disposing of ADSs in their particular circumstances, including the possible application of state, local, non-U.S. or other tax laws. For purposes of this summary, an investor is a “U.S. holder” if such investor is a beneficial owner of an ADS and is:

a citizen or resident of the United States;

a U.S. domestic corporation; or

otherwise subject to U.S. federal income tax on a net income basis with respect to income from the ADS.

In general, if a U.S. holder is the beneficial owner of ADSs, such U.S. holder will be treated as the beneficial owner of the common shares represented by those ADSs for U.S. federal income tax purposes, and no gain or loss will be recognized if such U.S. holder exchanges an ADS for the common shares represented by that ADS.

Passive Foreign Investment Company Rules

Special U.S. federal income tax rules apply to investors in companies that are PFICs. We will be classified as a PFIC in a particular taxable year if either:

•

75% or more of our gross income for the taxable year is passive income; or

•

50% or more of the value of our assets (generally determined on the basis of a quarterly average) is attributable to assets that produce or are held for the production of passive income.

For this purpose, passive income generally includes dividends, interest, gains from certain commodities transactions, rents, royalties and the excess of gains over losses from the disposition of assets that produce passive income.

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Based on our Consolidated Financial Statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes in 2025. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not expect to become a PFIC in 2026 or in future taxable years. However, the determination of whether we are a PFIC must be made annually based on the facts and circumstances at that time, some of which may be beyond our control, including the valuation of our assets as implied by the market price for our common shares or ADSs. Accordingly, it is possible that we could become a PFIC in the current or a future year.

If we are classified as a PFIC in any taxable year during which a U.S. holder holds our ADSs, such U.S. holder could be subject to a special tax at ordinary income rates on “excess distributions,” including certain distributions by us and gain recognized on the sale of the ADSs. The amount of income tax on any excess distributions will be increased by an interest charge to compensate for tax deferral, calculated as if the excess distributions were earned ratably over the period the U.S. holder held the ADSs. Classification as a PFIC may also have other adverse consequences, including, in the case of individuals, the denial of a step-up in the basis of the ADSs at death. In addition, if we are a PFIC for any year during which a U.S. Holder holds our common shares or ADSs, we will generally continue to be treated as a PFIC for all subsequent years during which such U.S. Holder holds our common shares or ADSs, unless we cease to be a PFIC and the U.S. Holder makes a special “purging” election on IRS Form 8621.

Except where otherwise noted, the remainder of this summary assumes that we were not a PFIC for our 2025 taxable year and that we will not become a PFIC in the current or any future year. U.S. holders should consult their own tax advisers as to our status as a PFIC and the potential tax consequences to them of such status.

Dividends

The gross amount of distributions that U.S. holders receive (prior to deduction of Argentine taxes) generally will be subject to U.S. federal income taxation as foreign source dividend income, to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. We do not expect to maintain calculations of our earnings and profits in accordance with U.S. federal income tax principles. U.S. holders therefore should expect that distributions generally will be treated as dividends for U.S. federal income tax purposes. Dividends paid in Argentine Pesos will be included in a U.S. holder’s income in a U.S. Dollars amount calculated by reference to the exchange rate in effect on the date of the depositary’s receipt of the dividend, regardless of whether the payment is in fact converted into U.S. Dollars. A U.S. holder will have a tax basis in such Pesos for U.S. federal income tax purposes equal to the U.S. Dollars value on the date of such receipt. Any subsequent gain or loss in respect of such Pesos arising from exchange rate fluctuations will be ordinary income or loss and will be treated as income from U.S. sources for foreign tax credit purposes. If such a dividend is converted into U.S. Dollars on the date of receipt, investors generally should not be required to recognize foreign currency gain or loss in respect of the dividend income. The U.S. Dollars amount of dividends received by an individual U.S. holder in respect of ADSs generally will be subject to taxation at a maximum rate of 20% if the dividends are “qualified dividends”. Subject to certain exceptions for short-term (60 days or less) positions, dividends paid on the ADSs will be treated as qualified dividends if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a PFIC. The ADSs are listed on the New York Stock Exchange and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on our Consolidated Financial Statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes in 2024 or 2025. See “—Passive Foreign Investment Company Rules,” above.

Because the common shares are not themselves listed on a U.S. exchange, dividends received with respect to the common shares may not be treated as qualified dividends. U.S. holders of should consult their own tax advisors regarding the availability of the reduced dividend tax rate in the light of their own particular circumstances.

Distributions of additional shares in respect of ADSs that are made as part of a pro-rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax, unless a U.S. holder that receives the distribution has the right to receive cash or property, in which case the U.S. holder will be treated as if it received cash equal to the fair market value of the distribution.

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Sale or other disposition

Upon a sale or other disposition of ADSs, a U.S. holder will recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference between the U.S. Dollars value of the amount realized and such U.S. holder’s tax basis, determined in U.S. Dollars, in the ADSs. Generally, such gain or loss realized on the sale or other disposition of ADSs will be treated as U.S. source capital gain or loss, and will be long-term capital gain or loss if the ADSs were held for more than one year. The ability to offset capital losses against ordinary income is limited. Long-term capital gain recognized by an individual U.S. holder, generally is subject to taxation at a reduced rate.

Foreign tax credit considerations

Investors should consult their own tax advisors to determine whether they are subject to any special rules that limit their ability to make effective use of foreign tax credits. Subject to generally applicable limitations and conditions, Argentine withholding tax on dividends paid at the appropriate rate applicable to the U.S. holder may be eligible for a credit against such U.S. holder’s U.S. federal income tax liability. These generally applicable limitations and conditions include requirements adopted by the U.S. Internal Revenue Service (“IRS”) in regulations promulgated in 2021 and any Argentine tax will need to satisfy these requirements in order to be eligible to be a creditable tax for a U.S. holder. In the case of a U.S. holder that consistently elects to apply a modified version of these rules under temporary guidance and complies with specific requirements set forth in such guidance, the Argentine tax on dividends generally will be treated as meeting the new requirements and therefore as a creditable tax. In the case of all other U.S. holders, the application of these requirements to the Argentine tax on dividends is uncertain and we have not determined whether these requirements have been met. If the Argentine dividend tax is not a creditable tax or the U.S. holder does not elect to claim a foreign tax credit for any foreign income taxes paid or accrued in the same taxable year, the U.S. holder may be able to deduct the Argentine tax in computing such U.S. holder’s taxable income for U.S. federal income tax purposes. Dividend distributions will constitute income from sources without the United States and, for U.S. holders that elect to claim foreign tax credits, generally constitute a “passive category” income for foreign tax credit purposes.

It is unclear whether the Argentine personal assets tax (as described in “—Argentine Tax Considerations Capital gains tax”) is treated as an income tax for U.S. federal income tax purposes. If the Argentine personal assets tax is not treated as an income tax for U.S. federal income tax purposes, a U.S. holder would be unable to claim a foreign tax credit for any Argentine personal assets tax withheld. A U.S. holder may be able to deduct such tax in computing its U.S. federal income tax liability, subject to applicable limitations.

A U.S. holder generally will not be entitled to credit any Argentine tax imposed on the sale or other disposition of ADSs against such U.S. holder’s U.S. federal income tax liability, except in the case of a U.S. holder that consistently elects to apply a modified version of the U.S. foreign tax credit rules that is permitted under issued temporary guidance and complies with the specific requirements set forth in such guidance. Additionally, capital gain or loss recognized by a U.S. holder on the sale or other disposition of the shares generally will be U.S. source gain or loss for U.S. foreign tax credit purposes. Consequently, even if the withholding tax qualifies as a creditable tax a U.S. holder may not be able to credit the tax against its U.S. federal income tax liability unless such credit can be applied (subject to generally applicable conditions and limitations) against tax due on other income treated as derived from foreign sources. If the Argentine tax is not a creditable tax, the tax would reduce the amount realized on the sale or other disposition of the shares even if the U.S. holder has elected to claim a foreign tax credit for other taxes in the same year. U.S. holders should consult their own tax advisors regarding the application of the foreign tax credit rules to a sale or other disposition of the shares and any Argentine tax imposed on such sale or disposition.

The availability and calculation of foreign tax credits and deductions for foreign taxes depend on a U.S. holder’s particular circumstances and involve the application of complex rules to those circumstances. The temporary guidance discussed above also indicates that the Treasury and the IRS are considering proposing amendments to the December 2021 regulations and that the temporary guidance can be relied upon until additional guidance is issued that withdraws or modifies the temporary guidance. U.S. holders should consult their own tax advisors regarding the application of these rules to their particular situations.

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U.S. information reporting and backup withholding rules

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries are subject to information reporting unless the holder is an exempt recipient and may also be subject to backup withholding unless the holder (1) provides its taxpayer identification number and certifies that it is not subject to backup withholding or (2) otherwise establishes an exemption from backup withholding. Investors may obtain a refund of any excess amounts withheld under the backup withholding rules by timely filing the appropriate claim or refund with the IRS and filing any required information.

A holder that is a foreign corporation or a non-resident alien individual may be required to comply with certification and identification procedures in order to establish its exemption from information reporting and backup withholding.

Specified Foreign Financial Assets

Certain U.S. holders that own “specified foreign financial assets” with an aggregate value in excess of U.S.$50,000 on the last day of the taxable year or U.S.$75,000 at any time during the taxable year are generally required to file an information statement along with their tax returns, currently on IRS Form 8938, with respect to such assets. “Specified foreign financial assets” include any financial accounts held at a non-U.S. financial institution, as well as securities issued by a non-U.S. issuer that are not held in accounts maintained by financial institutions. Higher reporting thresholds apply to certain individuals living abroad and to certain married individuals. Regulations extend this reporting requirement to certain entities that are treated as formed or availed of to hold direct or indirect interests in specified foreign financial assets based on certain objective criteria. U.S. holders who fail to report the required information could be subject to substantial penalties. In addition, the statute of limitations for assessment of tax would be suspended, in whole or part. Investors should consult their own tax advisors concerning the application of these rules to their particular circumstances.

DOCUMENTS ON DISPLAY

The materials included in this annual report on Form 20-F, and exhibits therein, may be inspected and copied at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any SEC filings we make are also available to the public over the Internet at the SEC’s website: www.sec.gov.

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Item 11.

Quantitative and Qualitative Disclosures about Market Risk

Our activities are exposed to market risk, including the exchange rate risk, the interest rate risk and the price risk. Financial risks are those derived from financial instruments we are exposed to during or at the closing of each fiscal year. Risk management systems and policies are reviewed on a regular basis to reflect changes in market conditions and our activities, with a focus not placed on the individual risks of the business units’ operations, but with a wider perspective focused on monitoring risks affecting the whole portfolio. Financial risk management is controlled by the Financial Department, which identifies, evaluates and covers financial risks. Our risk management strategy seeks to achieve a balance between profitability targets and risk exposure levels.

For further information on our market risks, please see Note 6.2 to our Consolidated Financial Statements.

Item 12.

Description of Securities Other than Equity Securities

DESCRIPTION OF AMERICAN DEPOSITARY SHARES

Payment of Taxes

The holders of ADSs will be responsible for any taxes or other governmental charges payable on their ADSs or on the deposited securities represented by any of their ADSs. The depositary may refuse to register any transfer of the ADSs or allow the holders to withdraw the deposited securities represented by their ADSs until such taxes or other charges are paid. The depositary may apply payments owed to the holders or sell deposited securities represented by their American Depositary Shares to pay any taxes owed and the holder will remain liable for any deficiency. If the depositary sells deposited securities, it will, if appropriate, reduce the number of ADSs to reflect the sale and pay to ADS holders any proceeds, or send to ADS holders any property, remaining after it has paid the taxes.

Fees and Expenses for Holders of ADRs

Persons depositing or withdrawing shares or ADS holders must pay:	For:
· U.S.$5.00 (or less) per 100 ADSs (or portion of 100 ADSs)	· Issuance of ADSs, including issuances resulting from a distribution of shares or rights or other property; and · Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates
· U.S.$0.02 (or less) per ADS	· Any cash distribution to ADS holders
· A fee equivalent to the fee that would be payable by the holder if the Company distributes shares and the holder deposits the shares with the depositary for issuance of ADSs	· Distribution of securities to holders of deposited securities which are distributed by the depositary to ADS holders
· U.S.$0.02 (or less) per ADS per calendar year	· Depositary services
· Registration or transfer fees	· Transfer and registration of shares on our share register to or from the name of the depositary or its agent when the holder deposits or withdraws shares

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· Expenses of the depositary

· Cable, telex and facsimile transmissions (when expressly provided in the deposit agreement); and

· Converting foreign currency to U.S. Dollars

· Taxes and other governmental charges the depositary or the custodian have to pay on any ADS or share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes

· As necessary

· Any charges incurred by the depositary or its agents for servicing the deposited securities

· As necessary

Depositary Payments to the Company

J.P. Morgan, as depositary, has agreed to reimburse us for expenses they incur that are related to establishment and maintenance expenses of the ADS program. The depositary has agreed to reimburse us for its continuing annual stock exchange listing fees. The depositary has also agreed to pay the standard out-of-pocket maintenance costs for the ADRs, which consist of the expenses of postage and envelopes for mailing annual and interim financial reports, printing and distributing dividend checks, electronic filing of U.S. Federal tax information, mailing required tax forms, stationery, postage, facsimile, and telephone calls. It has also agreed to reimburse us annually for certain investor relationship programs or special investor relations promotional activities. In certain instances, the depositary has agreed to provide additional payments to the Company based on any applicable performance indicators relating to the ADR facility. There are limits on the amount of expenses for which the depositary will reimburse us, but the amount of reimbursement available to us is not necessarily tied to the amount of fees the depositary collects from investors.

The depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The depositary collects fees related to making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The depositary may collect its annual fee for depositary services by deduction from cash distributions or by directly billing investors or by charging the book-entry system accounts of participants acting for them. The depositary may generally refuse to provide fee-attracting services until its fees for those services are paid.

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Item 13.

Defaults, Dividend Arrearages and Delinquencies

Not applicable.

Item 14.

Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15.

Controls and Procedures

(a) Disclosure Controls and Procedures

We have evaluated, with the participation of our chief executive officer and chief financial officer, the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as of December 31, 2025.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2025, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

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

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the Company; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).

Based on such evaluation, Management concluded that our internal control over financial reporting was effective as of December 31, 2025. The effectiveness of our internal control over financial reporting as of December 31, 2025 has been audited by Price Waterhouse & Co S.R.L., an independent registered public accounting firm, as stated in their report which appears herein.

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(c) Attestation Report of the Registered Public Accounting Firm

Reference is made to the report of Price Waterhouse & Co. S.R.L. on page F-3 of this annual report.

(d) Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting that occurred during the period covered by this annual report, that have materially affected, or are reasonably likely to materially affect, Pampa’s internal control over financial reporting.

Item 16A.

Audit Committee Financial Expert

Gabriel Szpigiel, an independent member of our Board of Directors, under Argentine law and Rule 10A-3, is our “audit committee financial expert” as defined in Item 16A of Form 20-F under the Securities and Exchange Act of 1934 and pursuant to section 407 of Sarbanes Oxley Act.

Item 16B.

Code of Ethics

Our Code of Conduct, approved by our Board of Directors, applies to all our employees, including our principal executive, financial and accounting officers, as well as other corporate governance policies (see “Item 6. Directors, Senior Management and Employees—Corporate Governance”) is posted, both in English and Spanish, on our website at https://ri.pampa.com/en/corporate-governance/code-of-conduct/

Item 16C.

Principal Accountant Fees and Services

Principal Accountant’s fees

Price Waterhouse & Co. S.R.L. acted as our independent registered public accounting for the fiscal years ended December 31, 2025 and 2024. The following table discloses the services rendered to Pampa and its consolidated companies by Price Waterhouse & Co. S.R.L and the fees for those services:

	Year ended December 31,
	2025	2024
	(in million U.S.$)

Audit Fees ⁽¹⁾	1.5	1.4
Audit-related Fees ⁽²⁾	0.8	0.5
Tax Fees ⁽³⁾	-	-
Other non-audit Fees ⁽⁴⁾	0.1	0.1
Total	2.4	2.0

(1) Audit Fees comprised of audit of our financial statements and our subsidiaries, the review of the interim financial statements, review of the Company’s annual report on Form 20-F, work to comply with the requirements of the Sarbanes Oxley – Section 404 and other services rendered by the external auditor in connection with statutory or regulatory filings or engagements.

(2) Audit-related Fees comprised of those outside the normal scope of the services included in an audit but are nevertheless reasonably related to the performance of the audit or review of our financial statements or our subsidiaries and may be effectively and efficiently rendered by the external auditor because of his knowledge of our financial information.

(3) Tax Fees comprised of services rendered by the external auditor for tax compliance.

(4) Other fees, include fees related to the verification of the sustainability report.

For a description of the permissible services included under these headings, please see the description of the categories of services of the “Audit Committee’s Pre-approval Policy” described below.

All of our audit fees contained in the above table were billed by Price Waterhouse & Co. S.R.L.

Audit Committee’s Pre-approval Policy

The Audit Committee has developed a Pre-approval Policy regarding the engagement of services by the external auditor, establishing the obligation to obtain prior approval from the audit committee for any service to be rendered by the external auditor to the Company. The policy ensures that the external auditor preserves its independence and is applicable to the Company.

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The Audit Committee has delegated to one of its members the authority to grant pre-approvals to auditors. The pre-approved services are later presented to the audit committee at their regular meetings.

Pre-approval is required for all services rendered by the external auditor. Pre-approval is automatic for i) audit and audit related services not exceeding U.S.$ 15,000 separately nor U.S.$ 100,000 cumulatively per fiscal year and ii) tax services not exceeding U.S.$5,000 separately nor U.S.$25,000 cumulatively per fiscal year.

Item 16D.

Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period	(a) Total Number of Shares(or Units) Purchased		(b) Average Price Paid per Share (or Units)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
2025	ADS	Common Shares	ADS	Common Shares	*Common Shares ^()**
Pampa
September	-	35,304	-	3,469.77	35,304	N/A¹
GASA
September	384,195	-	58.65	-	9,604,875	N/A¹
October	411,204	-	59.50	-	10,280,100	N/A¹

(*) Each ADS represents 25 common shares.

1 Rule 10b-18 safe harbor protection

Item 16F.

Change in Registrant’s Certifying Accountant

Not applicable.

Item 16G.

Corporate Governance

Among the corporate governance principles that are applicable at the Company are several provisions of Argentine law, including, but without limitation: (i) the LGS; (ii) the CML; and (iii) the regulations of the CNV approved on September 5, 2013 (the “Regulations”).

In addition, we follow certain corporate governance guidelines and practices that prevail in the international markets and in international regulations applicable to us (sometimes mandatory), including United States law. On August 27, 2009, we registered with the SEC as a “foreign private issuer” and began to trade American Depositary Shares on the NYSE.

Thus, we are subject to the provisions of Section 303A.11 of the NYSE’s Listed Company Manual (“LCM”) and Item 16.G of Form 20-F of the SEC, which require foreign issuers to disclose the differences existing between their corporate governance practices and the corporate governance requirements for U.S. domestic companies under their applicable listing standards. The following table provides the comparison required under the Section 303A.11 of the NYSE LCM and Item 16.G of the SEC’s Form 20-F mentioned above:

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CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
Section 303A.01	Independent directors must constitute the majority of a listed company’s board of directors.	Under Argentine law, the board of directors of a listed company need not be composed of a majority of independent directors. Nonetheless, the CML and the CNV’s Regulations require listed companies to have a sufficient number of independent directors to form the audit committee, which must be composed of a majority of independent members. Although not required by Argentine law, and in accordance with our audit committee’s regulations, all the members of our audit committee must qualify as independent.

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Section 303A.02

This rule establishes the standards that determine whether a director qualifies as independent.

It provides that directors cannot qualify as independent unless the board of directors finds them to have no material relationship with the listed company. A number of per se exclusions from independence apply, generally triggered by having a connection, individually or through an immediate family member, to the listed company or to a company that has a material relationship with the listed company as a shareholder, employee, officer, or director of the listed company.

The CNV’s Regulations, specifically Article 11 of Section III, Chapter III, Title II I, indicate the criteria for establishing independence of a director. They provide that any director is not independent when:

(i) has been a member of the management body for the controlling entity or another company belonging to the same economic group of the issuer by a preexistent relationship to the moment of his/her election, or if said relationship had ceased to exist during the previous three years;

(ii) is associated to the issuer or any of its shareholders that have significant participation, directly or indirectly, with the issuer; or with companies with which they have significant participation, directly or indirectly; or if he/she was associated to them by an employment relationship for the past three years;

(iii) has professional relationships or is affiliated to a professional organization or entity that maintains a frequent professional relationship of such nature and of relevant volume with, or that entitles him or she to a remuneration or fees (different from those corresponding to the functions that he/she fulfills in the management body), from the issuer, the issuer’s shareholders that have directly or indirectly “significant participations” or with companies in which these too have, directly or indirectly, “significant participations”. This prohibition comprises the professional relationships and affiliation during the last three years prior to the appointment as director;

(iv) holds 5% or more, directly or indirectly, of shares attached with voting rights and/or capital stock of the issuer or any company with a “significant participation” in it;

(v) directly or indirectly, sells and/or provides goods and/or services – different from those accounted for in subsection c) – frequently and in such nature and volume relevant to the issuer or its shareholders that have a “significant participation” with it, directly or indirectly, for which he or she has perceived amounts substantially superior to those perceived for his or her functions as a member of the management body. This prohibition comprises the commercial relationships that took place during the last three years prior to his/her appointment as director;

(vi) has been director, manager, administrator or principal executive of nonprofit organizations that have been benefited from funds proceeding from the company, its controlling company and any other company belonging to the same organization, by an amount superior to those described in article 12 subsection I) of the UIF Resolution No. 30/11 and its amendments thereto;

(vii) receives any payment, including the participation in plans or stock option schemes, from the company or from another company belonging to the same economic group, other than the compensation paid as a member of the board of directors, except dividends paid as a shareholder of the company in the terms of paragraph d) and the corresponding to the consideration described in paragraph e);

(viii) has been a director for the issuer, the controlling entity or another company belonging to the same economic group of the issuer for more than ten years. If said relationship had ceased to exist during the previous three years, the independent condition will be recovered;

(ix) is spouse or a legally recognized partner, up to the third grade of consanguinity or second grade of affinity, of the members of the management body of the company that do not comply with the conditions described in the previous points;

(x) is a member of the board of directors or supervisory committee in one or more companies registered as Agente de Negociación, Agente de Liquidación y Compensación y/o Agente de Corretaje de Valores Negociables, which are members of the respective stock exchange market or depend on members of such stock exchange market; and

(xi) directly or indirectly, maintains a significant participation in one or more companies registered as Agente de Negociación, Agente de Liquidación y Compensación y/o Agente de Corretaje de Valores Negociables, which are members of the stock exchange market.

In addition, Article 4 of Section III, Chapter I, Title XII of the CNV’s Regulations provides that at each election of directors, the non-independence or independence of any candidates proposed at the shareholders’ meeting must be disclosed. Moreover, after the shareholders’ meeting in which directors are appointed, the personal data of the appointed directors and their qualification as independent or non-independent (in the latter case in the form of an affidavit executed by each director) must be disclosed to the CNV and the exchanges where the company has its securities listed.

Section 303A.03

This rule requires regularly scheduled meetings of non-management directors to increase the involvement and efficiency of such directors.

Argentine law does not require that non-executive directors hold separate meetings. Non-executive directors attend the general board meetings, which must be held at least every three months pursuant to Section 267 of the LGS.

Section 303A.04

Listed companies must organize a Nominating and Corporate Governance Committee composed entirely of independent directors.

The organization of an Appointment and Corporate Governance Committee is not mandatory. In most cases, the functions of such committee are functions that the Audit Committee is already required to perform. Nonetheless, the CNV’s Regulations suggest (among its non-binding recommendations) that an Appointment and Corporate Governance Committee be organized.

We have a Nomination Committee, whose president must be an independent member of the Board of Directors. Additionally, and with respect to corporate governance matters, the Legal Corporate Department of Pampa oversees this area.

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Section 303A.05

Listed companies must organize a Compensation Committee composed entirely of independent directors, which satisfy additional independence requirements specific to Compensation Committee membership.

The organization of a Compensation Committee is not mandatory under Argentine law. In most cases, some of the functions of such a committee are included in the functions that the audit committee is required to perform. However, the CNV’s Regulations suggest (among its non-binding recommendations) that a Compensation Committee be organized.

Pampa has a Compensation Committee that is currently composed entirely of independent directors.

Section 303A.06

Listed companies must organize an Audit Committee that meets the requirements of Rule 10A-3 set forth in the Securities Exchange Act of 1934.

Pursuant to Section 303A.00, Pampa, as a foreign private issuer, is subject to Rule 303A.06, and we are in full compliance.

Section 303A.07

The audit committee must have at least three members, all of whom must satisfy the requirements for independence set out in Section 303.A.02, in the absence of an applicable exemption, Rule 10A-3(b)(1).

In addition, the audit committee must have written regulations establishing: (i) the purpose of the committee; (ii) the annual assessment of the committee’s performance; and (iii) the committee’s duties and responsibilities.

Finally, the rule establishes that listed companies must have internal audit functions within their organization in order to assist both the audit committee and the company’s management in matters related to risk and internal control processes.

Article 109 of the CML and Article 16, Section 5, Chapter III, Title II of the CNV Regulations provide that the audit committee must have at least three board members, the majority of whom must qualify as independent. All the members of our audit committee qualify as independent.

Argentine law requires the audit committee to issue its own regulations. The scope of the committee’s powers and obligations is detailed in Article 110 of the CML and Article 17 and following sections of Section 5, Chapter III, Title II, of the CNV’s Regulations. Such obligations and responsibilities are similar to those attributed to this body under the U.S. law.

Our audit committee has approved its own written regulations.

Argentine law does not require the audit committee to conduct an annual self-assessment. However, the CNV’s Regulations recommend that all directors (i.e., not only the independent directors who are members of the audit committee) complete a self-assessment.

We have adopted this recommendation and have developed a self-assessment form to be completed by all our directors at the close of each fiscal year.

Argentine laws contain no rules regarding internal audit functions. However, Pampa has an internal audit department that is supervised by, and reports to, Pampa’s Audit Committee. Additionally, Pampa’s audit committee regularly reviews, during its meetings, the internal audit reports submitted to it.

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Section 303A.08

The shareholders must be given the opportunity to vote on all equity-compensation plans and their material revisions, although there are exceptions to this requirement, such as when these compensation plans serve as labor incentive tools.

Directors’ compensation is fixed at the ordinary shareholders’ meeting (Section 234, Subsection 2, of the LGS). That compensation is for national currency cash.

With the aim of aligning the personnel performance, on February 8, 2017, our Board of Directors approved the creation of the stock-based compensation plan in accordance with Section 64 of CML and CNV’s regulations. See “Item 6. Directors, Senior Management and Employees—Stock-based Compensation Plan”.

Section 303A.09

Listed companies must adopt and disclose their corporate governance guidelines.

Listed companies must meet the annual disclosure requirements of the CNV’s Regulations. Listed companies must issue a report stating whether and how they followed the recommendations provided by the CNV’s Regulations or explaining the reasons for their failure to adopt such recommendations, and/or whether they plan to adopt them in the future. This information must appear in their annual report, attached to the financial statements for the relevant fiscal year as a separate exhibit. Once filed with the CNV and the exchanges where the company is listed, the CNV’s Regulations report qualifies as public information.

We comply with the CNV’s Regulations annual disclosure requirements and disclose our corporate governance policies and practices. This information may be viewed on the Company’s website, www.pampa.com.

Section 303A.10

Listed companies must adopt and disclose a Code of Ethics and Business Conduct which is applicable to their directors, officers and employees. The Code must require that any waiver of the code for executive officers or directors may be made only by the board or a board committee. In addition, any waiver of the provisions contained in this Code in favor of any of the parties that are subject to it must be immediately disclosed.

Under Argentine law there is no requirement that listed companies adopt a Code of Ethics and Business Conduct.

Nonetheless, in 2008, our Board of Directors approved a Code of Business Conduct applicable to all the employees, interns and trainees of Pampa and of its controlled and related companies and subsidiaries. This Code is applicable to all directors and statutory auditors of Pampa and its controlled and related companies and subsidiaries, as well as to their suppliers and consultants. Additionally, in 2010, Pampa approved the implementation of the Ethics Hotline as a channel to be solely used for reporting, in the strictest confidentiality, any presumed irregularity concerning the Business Conduct Code and/or violations thereof. The Code of Ethics was updated by our Board in 2021.

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Section 303A.12

The Chief Executive Officer (CEO) of a listed company must certify on a yearly basis that he or she has no knowledge of any violation or default of the corporate governance listing standards.

Additionally, the CEO must promptly notify the NYSE in writing after any executive officer

of the listed company becomes aware of any non-compliance with any provision of the

governance listing standards.

Listed companies must submit an executed written affirmation annually to the NYSE. In addition, each listed company must submit an interim written affirmation as and when required by the interim written affirmation form specified by the NYSE.

Pursuant to Section 303A.00, Pampa, as a foreign private issuer, is subject to Section 303A.12, with the exception of the annual CEO certification. Pampa is in full compliance with the applicable provisions.

Item 16H.

Mine Safety Disclosure

Not applicable.

Item 16I.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

Item 16J.

Insider Trading Policies.

Our Policy on Best Security Market Practices outlines certain restrictions and formalities on trading Pampa and/or its affiliates marketable securities listed in a stock exchange. It seeks that no benefit or economic advantage is gained from misusing material non-public information about Pampa and/or its affiliates. It applies to certain employees (including all of our senior management lines), directors and members of the Supervisory Committee (all of them, Covered Persons).

The terms of this Policy are concordant with those established in Section 117 of the Capital Market Act No. 26,831, as well as other enforcement regulations thereof, Section 1, Article XII, Chapter III, Title I of the Regulations of the CNV (N.T.2013), the rules and regulations of the SEC, the Federal Laws on Financial Instruments of the United States of American and the Sarbanes – Oxley Act. The policy is filed as Exhibit 11.1 to this annual report.

Item 16K.

Cybersecurity.

Risk Management and Strategy

We maintain a comprehensive process (the “Cybersecurity Program”) for assessing, identifying, managing, documenting and analyzing potential cybersecurity threats and incidents across the organization, including risks that could affect our business operations. The Cybersecurity Program is managed by our Information Security Manager (“CISO”) and overseen by our Chief Information Technology Director (“CIO”), who leads our information security team.

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As part of our Cybersecurity Program, the information security team carries out the following activities:

Coordinates the actions that we execute to detect, respond to and recover from cybersecurity incidents, such as processes to triage, assess severity for, escalate, contain, investigate and remediate the incident, as well as to comply with potentially applicable legal obligations and mitigate brand and reputational damages.

Uses the National Institute of Standards and Technology (NIST) Cybersecurity Framework to measure our security posture and manage risk.

Monitors, detects and prevents cybersecurity threats through different software and hardware solutions to protect our environment, such as multifactor authentication, firewalls, penetration testing, and a 24/7 Security Operation Center (SOC).

Conducts annual cybersecurity trainings for all our employees with the aim of deepening awareness and learning regarding risks, threats, and good practices in information security, where different interactive initiatives are performed. During the year 2025, we carried out these trainings for the ninth consecutive year.

Completes regular tests of our controls through penetration testing, vulnerability scanning and attack simulation.

Maintain and develop disaster recovery plans for both administrative and control environments to ensure preparedness and continuity in the event of disasters that could disrupt normal operations.

Despite encountering various cybersecurity threats during 2025, none resulted in material incidents, losses or adverse effects on our operations, largely due to the measures we implemented. However, due to the evolving and increasingly sophisticated nature of these threats, our risk and exposure cannot be fully quantified or entirely mitigated, and our contingency plans may not be sufficient to cover all potential liabilities associated with such incidents. See “Risk Factors - Cybersecurity events, including cyber-attacks, could adversely affect our business, financial condition, operational results and cash flows”. Accordingly, we continue to deploy security technologies and implement operational procedures aimed at preventing, detecting and mitigating the adverse effects of potential cybersecurity incidents.

We remain committed to continuously enhancing our Cybersecurity Program to protect our business operations and stakeholders.

Governance

Board of Directors

Our Board recognizes the importance of cybersecurity in safeguarding the Company’s sensitive information and the potential effects that a cybersecurity incident could have on our operations. The Board is responsible for overseeing overall risk management for the Company, including cybersecurity risks, and has delegated responsibility for such oversight to the Audit Committee. Our Board receives periodic updates about cybersecurity risks and events from our CISO and CIO. These updates include information regarding the deployment and administration of our Cybersecurity Program, status of projects relating to cybersecurity, and cybersecurity activities of the period, among other matters.

Management

The cybersecurity risk management processes described above are implemented through our information security team, managed by our CISO and overseen by our CIO. This team is responsible for the development and execution of the Cybersecurity Program and is composed of individuals with formal education, degrees and certifications in information technology or cybersecurity and relevant experience working in information technology and cybersecurity, including related industries of the Company. Additionally, they receive periodic updates, training, and education on cybersecurity related topics. The information security team informs the CISO, through e-mails and automated security alerts, of any cybersecurity matter. At least weekly, the CISO informs the CIO of the relevant events during the period, having special meetings or communications if urgent matters arise.

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Item 17.

Financial Statements

Not applicable.

Item 18.

Financial Statements

Our Consolidated Financial Statements are included in this annual report beginning on page F-1.

Item 19.

Exhibits

Documents filed as exhibits to this annual report:

1.1	Amended and Restated By-laws (estatutos sociales) of the Registrant (English translation) (previously filed as 6-K (File No. 001-34429) – (Film No. 25818697) on April 7, 2025 and incorporated by reference herein.)

2.1	Form of Second Amended and Restated Deposit Agreement among the Registrant, J.P. Morgan as successor Depositary thereunder (previously filed as Exhibit 99.A to our Registration Statement on Form F-6 (File No. 333-216157) on February 22, 2017 and incorporated by reference herein), as amended by Form of Amendment No. 1 to the Second Amended and Restated Deposit Agreement (previously filed as Exhibit 99.A2 to our Registration Statement on Form F-6 POS (File No. 333-216157) on November 18, 2020 and incorporated by reference herein.)

2(d)	Description of Securities

6	Compensation Recovery Policy

8.1	List of subsidiaries of Pampa

11.1	Policy on Best Security Market Practices

12.1	Certification of Gustavo Mariani, Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

12.2	Certification of Adolfo Zuberbuhler, Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

13.1	Officer Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

13.2	Reserves Reports of GaffneyCline, dated January 21, 2026

13.3	Consent of GaffneyCline

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Linkbase Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	Pampa Energía S.A.
	By: /s/ Gustavo Mariani
	Name: Gustavo Mariani Title: Chief Executive Officer

	By: /s/ Adolfo Zuberbuhler
	Name: Adolfo Zuberbuhler Title: Chief Financial Officer

Date: April 9, 2026

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CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2025 AND 2024

FOR THE YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023

(In millions of U.S. dollar (“US$”))


	F-1

Pampa Energía S.A.
Consolidated Financial Statements as of December 31, 2025 and 2024, and for the Years Ended December 31, 2025, 2024 and 2023

Report of Independent Registered Public Accounting Firm (PCAOB ID 1349)	F-3
Consolidated Statement of Comprehensive Income	F-12
Consolidated Statement of Financial Position	F-14
Consolidated Statement of Changes in Equity	F-16
Consolidated Statement of Cash Flows	F-17
Notes to the Consolidated Financial Statements	F-18


	F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Pampa Energía Sociedad Anónima (Pampa Energía S.A.)

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated statement of financial position of Pampa Energía Sociedad Anónima (Pampa Energía S.A.) and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under item 15. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,

www.pwc.com.ar

Price Waterhouse & Co. S.R.L., Bouchard 557, 8th floor, C1106ABG – Autonomous City of Buenos Aires, Argentina, T: +(54.11) 4850.0000


	F-3

assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Proved Estimates of Oil and Gas Reserves on Oil and Gas Segment Property, Plant and Equipment and Allocated Goodwill.

As described in Notes 7, 11.1 and 11.2 to the consolidated financial statements, as of December 31, 2025, the Company’s consolidated net book value of property, plant and equipment balance of the oil and gas segment was US$ 1,896 million, the goodwill balance allocated to the oil and gas segment was US$ 35 million, and depreciation expense for the year ended December 31, 2025 was US$ 276 million. As described in Note 6.1.7 to the consolidated financial statements, the Company’s management estimates oil and gas reserves which are used in the determination of depreciation of property, plant and equipment used in oil and gas areas, as well as assessing the recoverability of these assets and goodwill allocated to the oil and gas segment. There are numerous uncertainties in estimating proved and unproved reserves, future production profiles, development costs and prices, including several factors beyond the producer’s control. Reserve engineering is a subjective process of estimating underground accumulations involving a certain degree of uncertainty. Reserves estimates depend on the quality of the available engineering and geological data as of the estimation date and on the interpretation and judgment thereof. The estimates of oil and gas reserves have been developed by employed specialists, specifically petroleum engineers, and audited by independent specialists engaged by the Company.

The principal considerations for our determination that performing procedures relating to the impact of estimates of proved oil and gas reserves on oil and gas segment property, plant and equipment and allocated


	F-4

goodwill are a critical audit matter are the significant judgment by management, including the use of specialists when developing the estimates of oil and gas reserves, which in turn led to a high degree of auditor judgment and effort in performing procedures to evaluate the significant assumptions used in developing those estimates related to future production profiles, development costs and prices.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of oil and gas reserves. These procedures also included, among others, evaluating the methods and significant assumptions used by management in developing these estimates related to future production profiles, development costs and prices. The work of management’s engaged specialist was used in performing the procedures to evaluate the reasonableness of these estimates of proved oil and gas reserves. As a basis for using this work, the specialists’ competence, capability and objectivity were understood, as well as their methods and assumptions. The procedures performed also included tests of the data used by the Company’s engaged specialists and an evaluation of their findings. Evaluating the significant assumptions relating to the estimates of proved oil and gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit. The procedures performed also included testing that the estimates of oil and gas reserves were appropriately included in the Company’s determination of depreciation expense, as well as in the impairment of non-financial assets assessment of oil and gas segment.

Impairment of Non-Financial Long-Lived Assets Related to the Generation Segment

As described in Note 7 to the consolidated financial statements, as of December 31, 2025, the Company’s consolidated property, plant and equipment balance of the generation segment was US$ 1,370 million. According to Notes 4.8, 6.1.1. and 11.1.1, as of December 31, 2025, there were impairment / reversal of impairment indicators in the generation segment. Management analyzes the recoverability of its non-financial long-lived assets when events or changes in circumstances indicate that the carrying amount may not be recoverable or a reversal of a previous impairment is possible. The recoverable amount is the higher of fair value less costs of disposal and value in use. Management used value in use to determine the recoverable amount. The value in use is determined based on the present value of future net cash flows expected to be derived from the cash generating units (“CGU”), using discount rates that consider the business segment and the country conditions where the operations are performed. Management’s assessment of the existence of impairment indicators and cash flow projections included key judgments and assumptions relating to spot remuneration price evolution under SE Resolution N° 400/25, energy dispatch projections, costs evolution considering fuel self-supply, and the discount rate. During the year ended December 31, 2025, the Company recorded a reversal of impairment losses recorded in previous years in the amount of US$ 55.6 million at the Central Térmica Piedra Buena thermal power plant CGU.

The principal considerations for our determination that performing procedures relating to the impairment of non-financial long-lived assets related to the generation segment is a critical audit matter are the significant judgment by management when evaluating the existence of impairment / reversal of impairment indicators and when developing the recoverable value measurement of the non-financial long-lived assets. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures to evaluate management’s assessment of impairment indicators and cash flow projections and key assumptions related to spot remuneration price evolution under SE Resolution N° 400/25, energy dispatch projections, costs evolution considering fuel self-supply, and the discount rate. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist us in performing these procedures and evaluating the audit evidence obtained.


	F-5

evaluating the determination of the Company’s CGUs, as well as the allocation of the assets and liabilities thereto; evaluating the reasonableness of management’s assessment over the existence of impairment / reversal of impairment indicators; testing management’s process for developing the value in use estimate; evaluating the appropriateness of the discounted cash flow model, as well as the mathematical precision of the calculations; testing the completeness, accuracy, and relevance of underlying data used in the model; and evaluating the key assumptions used by management related to spot remuneration price evolution under SE Resolution N° 400/25, energy dispatch projections, costs evolution considering fuel self-supply, and the discount rate. Evaluating management’s assumptions involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the CGUs, (ii) the consistency with external market and industry data, and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s discounted cash flow model and the discount rate. The procedures performed also included evaluating the sufficiency of the information disclosed in the consolidated financial statements regarding the evaluation of the recoverable value of long-lived non-financial assets.

/s/ PRICE WATERHOUSE & CO. S.R.L.

/s/ Carlos Martin Barbafina (Partner)

Autonomous City of Buenos Aires, Argentina, March 2, 2026

We have served as the Company’s auditor since 2006


	F-6

GLOSSARY OF TERMS

The following are not technical definitions, but they are helpful for the reader’s understanding of some terms used in the notes to the Consolidated Financial Statements of the Company.

Terms		Definitions
ADR		American Depositary Receipt
ARCA		Revenue Collection and Customs Control Agency
BCBA		Buenos Aires Stock Exchange
BCRA		Argentina’s Central Bank
BNA		Banco de la Nación Argentina
BO		Official Gazette
CAMMESA		Compañía Administradora del Mercado Eléctrico Mayorista S.A.
CB		Corporate Bonds
CC		Combined Cycle
CGU		Cash-Generating Unit
CIESA		Compañía de Inversiones de Energía S.A.
Citelec		Compañía Inversora en Transmisión Eléctrica Citelec S.A.
CNG		Compressed Natural Gas
CNV		National Securities Commission of Argentina
CPB		Piedra Buena thermal power plant
CPI		Consumer's price index
CSJN		Argentina’ Supreme Court of Justice
CTB		CT Barragán S.A.
CTEB		Ensenada Barragán thermal power plant
CTG		Güemes thermal power plant
CTGEBA		Genelba thermal power plant
CTIW		Ingeniero White power plant
CTLL		Loma La Lata thermal power plant
CTPP		Parque Pilar power plant

F- 7

GLOSSARY OF TERMS: (Continuation)

Terms		Definitions
EISA		Energía e Inversiones S.A.
EMESA		Empresa Mendocina de Energía S.A.
ENARGAS		National Regulator of Gas
ENARSA		Energía Argentina S.A.
ENRE		National Regulatory Authority of Electricity
ENRGE		National Regulatory Authority of Gas and Electricity
FLNG		Floating Liquefied Natural Gas
FNEE		National Electric Energy Fund
FTR		Five-Year Tariff Review
GASA		Generación Argentina S.A.
GU300		Large users with demand greater than 300 Kw
GUDI		Distributors’ large users
HB		Pumped Hydroelectric Power Plant
HI		Hydropower plants
HIDISA		Hidroeléctrica Diamante S.A.
HINISA		Hidroeléctrica Los Nihuiles S.A.
HPPL		Hidroeléctrica Pichi Picún Leufú
HR		Renewable Hydroelectric
IAS		International Accounting Standards
IASB		International Accounting Standards Board
ICC		International Chamber of Commerce
ICSID		International International Centre for Settlement of Investment Disputes
IFRS		International Financial Reporting Standards
IPIM		Wholesale Domestic Price Index
INDEC		National Institute of Statistics and Censuses

F- 8

GLOSSARY OF TERMS: (Continuation)

Terms		Definitions
KBBL/day		Thousands of barrels per day
LGS		Argentine Business Organizations Law
LNG		Liquefied Natural Gas
LPG		Liquefied Petroleum Gas
M³		Cubic meter
MAT		WEM’s Forward Market
MATER		Renewable Energy Forward Market
MBTU		Million of BTU
MCI		Internal Combustion Engines
MECON		Ministry of Economy of Argentina
MEyM		Ministry of Energy and Mining
MLC		Foreign Exchange Market
MW		Megawatt
MWh		Megawatt – hour
MWhrp		Remunerated megawatt during capacity remuneration hours
NTC		National Tax Court
NYSE		New York Stock Exchange
OCP		Oleoductos de Crudos Pesados Ltd
OCPSA		Oleoductos de Crudos Pesados S.A.
Oldelval		Oleoductos del Valle S.A.
PAIS tax		Tax for an Inclusive and Supportive Argentina
PB18		Pampa Bloque 18
PE Arauco		Arauco Wind Farm
PEB		Pampa Energía Bolivia S.A.
PECSA		Pampa Energía Chile S.A.
PEN		National Executive Branch
PEPE II		Pampa Energía II Wind Farm

F- 9

GLOSSARY OF TERMS: (Continuation)

Terms		Definitions
PEPE III		Pampa Energía III Wind Farm
PEPE IV		Pampa Energía IV Wind Farm
PEPE VI		Pampa Energía VI Wind Farm
PESOSA		Pampa Energía Soluciones S.A.
PISA		Pampa Inversiones S.A.
PIST		Transportation System Entry Point
RDA		Rincón de Aranda
RIGI		Incentive Regime for Large Investments
SACDE		Argentine Society of Construction and Strategic Development
SCEyM		Energy and Mining Coordination Secretary
SE		Secretary of Energy
SEC		Security and Exchange Commission
SESA		Southern Energy S.A.
TG		Gas Turbine
TGS		Transportadora de Gas del Sur S.A.
The Company / Pampa		Pampa Energía S.A.
The Group		Pampa Energía S.A. and its subsidiaries
TJSM		Termoeléctrica José de San Martín S.A.
TMB		Termoeléctrica Manuel Belgrano S.A.
Transba		Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires Transba S.A.
Transener		Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.
TV		Vapor Turbine
US$		U.S. dollar
VAR		Vientos de Arauco Renovables S.A.U.
VAT		Value Added Tax

F- 10

GLOSSARY OF TERMS: (Continuation)

Terms		Definitions
VMOS		VMOS S.A.
WACC		Weighted Average Cost of Capital
WEM		Wholesale Electrical Market
YPF		YPF S.A.
$		Argentine Pesos

F- 11

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2025, 2024 and 2023

(In millions of US$ – unless otherwise stated)


	Note	12.31.2025	12.31.2024	12.31.2023

Revenue	8	1,998	1,876	1,732
Cost of sales	9	(1,369)	(1,279)	(1,107)
Gross profit		629	597	625

Selling expenses	10.1	(98)	(74)	(66)
Administrative expenses	10.2	(192)	(239)	(185)
Exploration expenses	10.3	-	(21)	(7)
Other operating income	10.4	100	175	177
Other operating expenses	10.4	(72)	(88)	(88)
Recovery of impairment (Impairment) of property, plant and equipment, intangible assets and inventories		15	(34)	(39)
Impairment of financial assets		(21)	(56)	-
Share of profit (loss) from associates and joint ventures	5.1.2	142	146	(2)
Profit from sale/acquisition of companies´ interest		-	34	9
Operating income		503	440	424

Financial income	10.5	45	32	5
Financial costs	10.5	(196)	(185)	(364)
Other financial results	10.5	230	211	558
Financial results, net		79	58	199
Profit before income tax		582	498	623
Income tax	10.6	(204)	121	(318)
Profit of the year		378	619	305

Other comprehensive income
Items that will not be reclassified to profit or loss
Results related to defined benefit plans		-	-	(5)
Income tax		-	-	2
Exchange differences on translation		(26)	123	(78)
Items that may be reclassified to profit or loss
Gain on cash flow hedges		46	-	-
Income tax		(16)	-	-
Exchange differences on translation		(25)	138	(97)
Other comprehensive (loss) income of the year		(21)	261	(178)
Total comprehensive income of the year		357	880	127

F- 12

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Continuation)

For the years ended December 31, 2025, 2024 and 2023

(In millions of US$ – unless otherwise stated)

	Note	12.31.2025	12.31.2024	12.31.2023
Total profit of the year attributable to:

Owners of the company		377	619	302
Non-controlling interest		1	-	3
Profit of the year		378	619	305

Total comprehensive income of the year attributable to:

Owners of the Company		356	880	124
Non-controlling interest		1	-	3
Total comprehensive income of the year		357	880	127

Earnings per share attributable to equity holders of the Company
Total basic and diluted earning per share	13.2	0.28	0.46	0.22

The accompanying notes are an integral part of these Consolidated Financial Statements.

F- 13

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2025 and 2024

(In millions of US$ – unless otherwise stated)


	Note	12.31.2025	12.31.2024
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment	11.1	3,303	2,607
Intangible assets	11.2	89	95
Right-of-use assets	19.1.1	36	11
Deferred tax asset	11.3	43	157
Investments in associates and joint ventures	5.1.2	1,059	993
Financial assets at fair value through profit and loss	12.2	33	27
Trade and other receivables	12.3	43	75
Total non-current assets		4,606	3,965

CURRENT ASSETS
Inventories	11.4	231	223
Financial assets at amortized cost	12.1	-	80
Financial assets at fair value through profit and loss	12.2	366	850
Derivative financial instruments		52	1
Trade and other receivables	12.3	614	488
Cash and cash equivalents	12.4	725	738
Total current assets		1,988	2,380
Total assets		6,594	6,345

F- 14

CONSOLIDATED STATEMENT OF FINANCIAL POSITION (Continuation)

As of December 31, 2025 and 2024

(In millions of US$ – unless otherwise stated)

	Note	12.31.2025	12.31.2024
SHAREHOLDERS´ EQUITY
Share capital		36	36
Share capital adjustment		191	191
Share premium		516	516
Treasury shares adjustment		1	1
Treasury shares cost		(54)	(7)
Legal reserve		44	44
Voluntary reserve		2,399	1,657
Other reserves		(12)	(13)
Other comprehensive income		124	119
Retained earnings		351	742
Equity attributable to owners of the company		3,596	3,286
Non-controlling interest		9	9
Total equity		3,605	3,295

LIABILITIES
NON-CURRENT LIABILITIES
Provisions	11.5	100	137
Income tax and minimum notional income tax provision	11.6	26	75
Deferred tax liability	11.3	56	49
Tax liabilities	11.7	212	-
Defined benefit plans	11.8	26	30
Borrowings	12.5	1,844	1,373
Trade and other payables	12.6	86	84
Total non-current liabilities		2,350	1,748

CURRENT LIABILITIES
Provisions	11.5	13	10
Income tax liability	11.6	83	257
Tax liabilities	11.7	56	30
Defined benefit plans	11.8	6	7
Salaries and social security payable	11.9	36	39
Borrowings	12.5	48	706
Trade and other payables	12.6	397	253
Total current liabilities		639	1,302
Total liabilities		2,989	3,050
Total liabilities and equity		6,594	6,345

The accompanying notes are an integral part of these Consolidated Financial Statements.

F- 15

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the years ended December 31, 2025, 2024 and 2023

(In millions of US$ – unless otherwise stated)


	Equity holders of the company					Retained earnings
	Share capital	Share capital adjustment	Share premium	Treasury shares adjustment	Treasury shares cost	Legal reserve	Voluntary reserve	Other reserves	Other comprehensive income (loss)	Unappropiated retained earnings	Equity attributable to owners	Non-controlling interest	Total equity
Balance as of December 31, 2022	36	191	516	1	(23)	45	968	(15)	81	477	2,277	7	2,284
Voluntary reserve constitution	-	-	-	-	-	-	478	-	-	(478)	-	-	-
Capital reduction	-	-	-	-	16	-	(13)	-	-	-	3	-	3
Dividens ditribution	-	-	-	-	-	-	-	-	-	-	-	(1)	(1)
Profit of the year	-	-	-	-	-	-	-	-	-	302	302	3	305
Other comprehensive loss of the year	-	-	-	-	-	-	-	-	(100)	(78)	(178)	-	(178)
Balance as of December 31, 2023	36	191	516	1	(7)	45	1,433	(15)	(19)	223	2,404	9	2,413
Voluntary reserve constitution	-	-	-	-	-	(1)	224	-	-	(223)	-	-	-
Stock compensation plans	-	-	-	-	-	-	-	2	-	-	2	-	2
Profit of the year	-	-	-	-	-	-	-	-	-	619	619	-	619
Other comprehensive income of the year	-	-	-	-	-	-	-	-	138	123	261	-	261
Balance as of December 31, 2024	36	191	516	1	(7)	44	1,657	(13)	119	742	3,286	9	3,295
Voluntary reserve constitution	-	-	-	-	-	-	742	-	-	(742)	-	-	-
Treasury shares acquisition	-	-	-	-	(47)	-	-	-	-	-	(47)	-	(47)
Dividens ditribution	-	-	-	-	-	-	-	-	-	-	-	(1)	(1)
Stock compensation plans	-	-	-	-	-	-	-	1	-	-	1	-	1
Profit of the year	-	-	-	-	-	-	-	-	-	377	377	1	378
Other comprehensive income (loss) of the year	-	-	-	-	-	-	-	-	5	(26)	(21)	-	(21)
Balance as of December 31, 2025	36	191	516	1	(54)	44	2,399	(12)	124	351	3,596	9	3,605

The accompanying notes are an integral part of these Consolidated Financial Statements.

F- 16

CONSOLIDATED STATEMENT OF CASH FLOWS

For the years ended December 31, 2025, 2024 and 2023

(In millions of US$ – unless otherwise stated)


	Note	12.31.2025	12.31.2024	12.31.2023
Cash flows from operating activities:
Profit of the year		378	619	305
Adjustments to reconcile net profit to cash flows from operating activities	14.1	418	152	406
Changes in operating assets and liabilities	14.2	(18)	(336)	(136)
Net cash generated by operating activities		778	435	575
Cash flows from investing activities:
Payment for property, plant and equipment acquisitions		(993)	(447)	(758)
Collection for sales (Payment for purchases) of public securities and shares, net		592	(5)	130
Recovery (Suscription) of mutual funds, net		3	(10)	96
Capital integration in companies		(44)	-	-
Payment for companies´acquisitions		(1)	(48)	(1)
Collection for equity interests in companies sales		1	39	72
Collection for joint ventures´ share repurchase		-	37	-
Collections for property, plant and equipment sales		-	-	1
Collections for intangible assets sales		9	-	20
Dividends collection		25	9	-
Collection for equity interests in areas sales		7	9	-
Cash addition for purchase of subsidiary		-	71	-
Collection (Payment) of loans		-	1	(6)
Net cash used in investing activities		(401)	(344)	(446)

Cash flows from financing activities:
Proceeds from borrowings	12.5	986	1,174	424
Payment of borrowings		(306)	(236)	(191)
Payment of borrowings interests	12.5	(161)	(145)	(280)
Repurchase and redemption of corporate bonds	12.5	(837)	(313)	(6)
Dividends payment		(1)	-	(1)
Payment for treasury shares acquisition		(47)	-	-
Payments of leases		(24)	(4)	(3)
Net cash (used in) generated by financing activities		(390)	476	(57)
(Decrease) Increase in cash and cash equivalents		(13)	567	72

Cash and cash equivalents at the beginning of the year	12.4	738	171	106
Exchange difference generated by cash and cash equivalents		-	-	(7)
(Decrease) Increase in cash and cash equivalents		(13)	567	72
Cash and cash equivalents at the end of the year	12.4	725	738	171

The accompanying notes are an integral part of these Consolidated Financial Statements.

F- 17

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023

(In millions of US$ – unless otherwise stated)

NOTE 1: GENERAL INFORMATION

1.1 General information of the Company

The Company’s principal executive office is located in Maipú 1, Autonomous City of Buenos Aires in Argentina, which participates in the energy sector, mainly in the production of oil and gas and power generation.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, reaching a production level of 12.4 million m3/day of natural gas and 11.7 thousand boe/day of oil (including the production from El Tordillo, La Tapera and Puesto Quiroga areas until its assignment in October 2025) and maintaining 9 productive areas and 2 exploratory areas in Argentina as of December 31, 2025. Its main production blocks are located in the Province of Neuquén. Additionally, the Company participates in SESA, an entity dedicated to natural gas liquefaction.

In the generation segment, the Company, directly and through its subsidiaries and joint ventures, has a 5,472 MW installed capacity as of December 31, 2025, which represents approximately 12% of Argentina’s installed capacity, and being one of the largest independent generators in the country.

In the petrochemicals segment, the Company operates 2 high-complexity plants in Argentina producing styrene, synthetic rubber and polystyrene, with a share ranging between 86% and 98%, in the domestic market.

Finally, through the holding, transportation and others segment, the Company participates in the electricity transmission and gas transportation businesses. In the transmission business, the Company jointly controls Citelec, which has a controlling interest in Transener, a company engaged in the operation and maintenance of a 22,445 km high-voltage electricity transmission network in Argentina with an 86% share in the Argentine electricity transmission market. In the gas transportation business, the Company jointly controls CIESA, which has a controlling interest in TGS, a company holding a concession for the transportation of natural gas with 9,248 km of gas pipelines in the center, west and south of Argentina, and which is also engaged in the processing and sale of natural gas liquids through the Cerri Complex, located in Bahía Blanca, in the Province of Buenos Aires, in addition to shale gas transportation and conditioning at Vaca Muerta. Additionally, the Company participates in VMOS, an entity that will operate an oil pipeline connecting Vaca Muerta with an offshore export port. Finally, the segment includes advisory services provided to related companies.

F- 18

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 1: (Continuation)

1.2 Economic context

The Company operates in an economic context which main variables are experiencing volatility as a result of political and economic events both in the domestic and international spheres.

The Argentine economy recorded a 5.2% accumulated increase and a 2.6% accumulated decrease in the Gross Domestic Product as of the third quarter of 2025 and 2024, respectively, a 31.5% and 117.8% cumulative inflation considering the CPI and a 41% and 27.7% depreciation of the peso against the U.S. dollar, according to the BNA exchange rate, for fiscal years 2025 and 2024, respectively.

Under the economic stabilization plan, the Government maintained a primary fiscal surplus and implemented a series of measures to ease the exchange rate regime and strengthen the monetary system, aimed at reducing inflation and boosting economic activity. In 2025, the Argentine economy showed a strong recovery in the first semester of the year, followed by a slowdown in activity in the second semester.

The context of volatility and uncertainty continues as of the date of issuance of these Consolidated Financial Statements and it is not possible to foresee the macroeconomic and financial situation of Argentina or the international context’ evolution or what new measures might be announced.

The Company’s Management permanently monitors the evolution of the variables affecting its business to define its course of action and identify potential impacts on its assets and financial position.

The Company’s Consolidated Financial Statements should be read in the light of these circumstances.

NOTE 2: REGULATORY FRAMEWORK

On May 30, 2025, through Executive Order No. 370/25, the Federal Government extended the national emergency for the electricity generation, transmission and distribution, and the natural gas transportation and distribution segments through July 9, 2026.

On July 7, 2025, through Executive Orders No. 450/25 and No. 452/25, amendments were introduced to Laws No. 15,336 and No. 24,065, and the ENRGE was created to replace and unify ENARGAS and ENRE, respectively, in accordance with the guidelines set forth in the Bases Law (Law No. 27,742). As of the date of issuance of these Consolidated Financial Statements, this entity has not yet been effectively implemented.

Executive Order No. 450/25 establishes a 24-month transition period during which the SE must issue the regulations required, among other matters, to develop a competitive hydrocarbons market through the free contracting of fuel, and to establish the transfer mechanisms for contracts entered into by CAMMESA for the WEM’s supply and demand sides. In addition, the SE is authorized to approve the execution of expansions of the transmission system within an existing concession, subject to prior consultation with CAMMESA, which may be financed with resources from the FNEE. Alternatively, network expansions may be carried out by private initiative and at the risk of the party executing them, with priority rights over the use of transmission capacity and the possibility of assigning it to third parties.

F- 19

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

Within this framework, on September 26, 2025, SE Resolution No. 379/25 approved the “Energy Demand Management Program” to mitigate reserve shortfalls in the WEM or the distribution network through user demand management to be called by CAMMESA in line with seasonal programming. Successful tenders submitted by adhering large users will be remunerated with a fixed charge of US$ 1,000/MW-month, plus a variable charge and an additional incentive charge linked to commitment compliance. Failure to comply with CAMMESA’s requirements will result in a penalty equivalent to three times the fixed charge.

Similarly, on October 21, 2025, SE Resolution No. 400/25 established the “Rules for the Normalization of the WEM and its Progressive Adaptation”, which have been in effect since November 1, 2025. These rules introduce a new framework aimed at fostering competition among generators, promoting direct contracting of demand, and advancing toward a decentralized fuel supply scheme. It is worth highlighting that the implementation of certain changes requires additional regulation.

Regarding distributor demand, a new category of users subject to seasonal prices is established: the seasonalized demand (excluding large distribution company users, or “GUDI”). For this category, the distributor must maintain a minimum coverage of 75% of such demand. Seasonalized demand will be supplied through the assigned generation, with first priority given to the residential sector.

Additionally, the pricing regime for spot demand and the seasonal pricing for distributor demand have been modified. GUDI are allocated the seasonal spot energy costs and may opt to become WEM large users subject to a minimum one-year term of permanence, or to contract energy and power capacity with one or more generators through distributors.

Regarding services provided by generators in the WEM, new base and additional reliability reserve services are contemplated.

In addition, a mechanism is envisaged to transfer the costs of forced generation to the relevant jurisdiction until the additional costs incurred are properly allocated.

Finally, it is provided that any new WEM demand outside the scope of a distributor’s concession connected to the transmission system and representing a relative increase exceeding at least 0.5% of the WEM’s average demand must submit, together with its request for access to the WEM and the transmission capacity, a supply plan ensuring: i) at least 80% of new energy production; and ii) sufficient physical capacity backup to cover 80% of its consumption.

The main regulations applicable to the Company’s activities are detailed below. It is worth highlighting that this is not an exhaustive list of all regulations the Company is subject to.

F- 20

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1 Oil and gas

2.1.1 Argentine Hydrocarbons Law

Laws No. 27,007 and 27,742, enacted in 2014 and 2024 respectively, amended Hydrocarbons Law No. 17,319, enacted in 1967, establishing the general principles for the exploration, exploitation, industrialization, transportation and commercialization of hydrocarbon resources in Argentina. The most relevant aspects are as follows:

It empowers the Federal Government or the Provinces to grant exploration and exploitation permits and concessions to the private sector.

It establishes the terms for exploration permits: (i) conventional: term of 2 periods of up to 3 years each, plus 1 optional extension for up to 5 years; (ii) unconventional: term of 2 periods of 4 years each, plus 1 optional extension for up to 5 years; and (iii) on the continental shelf and in the territorial sea: term of 2 periods of 3 years each with the possibility of increasing by 1 year each.

It sets the terms for exploitation concessions: (i) conventional: 25 years; (ii) unconventional: 35 years; and (iii) on the continental shelf and in the territorial sea: 30 years.

It establishes that transportation concessions will be granted for the same term as the originating exploitation concession.

It empowers the Federal Government or the Provinces to grant authorizations for hydrocarbon processing, conditioning or separation and natural gas liquefaction, not necessarily linked to an exploitation concession.

It empowers the Federal Government to grant authorizations for underground storage of natural gas in natural reservoirs of depleted hydrocarbons.

This legislation sets the values of the exploration and exploitation canons payable at each stage by reference to the average price per oil barrel, adjustable annually based on the Brent quotation, and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

It sets royalties at 12%, payable monthly to the grantor, on the proceeds from liquid hydrocarbons extracted at wellhead and on natural gas production, and establishes a 15% base royalty rate for new awards.

It establishes the setting of commercialization prices in the domestic market without the PEN’s intervention and the free international trade of hydrocarbons, in the absence of an objection by the SE.

It restricts the Federal Government and the Provinces from reserving new blocks in favor of public or mixed companies or entities.

F- 21

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.2 Gas Market

2.1.2.1 Argentine Natural Gas Production Promotion Plan (“GasAr Plan”)

Executive Order No. 892/20 approved the Argentine Natural Gas Production Promotion Program (“GasAr Plan”) to promote the development of the Argentine gas industry based on a call for tenders mechanism. Within this framework, the national public call for tenders for the 2020–2024 GasAr Plan was launched, involving the execution of individual contracts among gas producers, distribution companies and CAMMESA, with the Federal Government taking on responsibility for paying directly to producers, on a monthly basis, the difference between the tendered price and the price under the tariff scheme through a price supplement.

The Company was awarded: (i) Round 1: a base volume of 4.9 million m³/day of natural gas at an annual average price of US$ 3.60 per MBTU for the 2021–2024 period, and an additional 1 million m³/day volume at a price of US$ 4.68 per MBTU during the winter period; (ii) Round 2: volumes of 0.70 million m³/day, 0.90 million m³/day and 1 million m³/day for the months of June, July and August–September 2021, respectively, and 0.86 million m³/day to supply the 2022–2024 winter peak period, at a price of US$ 4.68 per MBTU; and (iii) Round 3: a volume of 2 million m³/day at a price of US$ 3.347 per MBTU for the 2022–2024 period.

Subsequently, Executive Order No. 730/22 established the 2023 – 2028 Reinsurance and Enhancement Plan for Federal Hydrocarbon Production, Domestic Self-Sufficiency, Exports, Import Substitution and Expansion of the Transportation System for All Hydrocarbon Basins in the Country (the “Reinsurance Plan”) with the following main objectives: (i) consolidating a 70 million m³/day flat block (awarded under GasAr Plan’s Rounds 1 and 3), excluding winter peaks; and (ii) developing demand for incremental volumes that may be evacuated using the new transportation capacity following the construction of the Perito Francisco Pascasio Moreno Gas Pipeline.

The Company was awarded: (i) Round 4.1: the extension of the commitments under the GasAr Plan - Rounds 1 and 3 until 2028, maintaining the originally tendered prices; and (ii) Round 4.2: 4.8 million m³/day of demand associated with flat gas at a price of US$ 3.485 per MBTU from July 2023 to December 2028.

The awards granted to the Company and the executed contracts represented a 13.8 million m³/day commitment under the Reinsurance Plan for fiscal years 2025 and 2024.

Lastly, in Round 5.2, the Company, together with all partners of the Aguaragüe Joint Operation, was awarded an incremental 400,000 m³/day volume to be sold to ENARSA at a price of US$ 9.8 per MBTU from October 2023 to December 2026, and US$ 6 per MBTU from January 2027 to December 2028. The Company holds a 15% stake in this Joint Operation.

2.1.2.2 Withdrawal of Volumes from the GasAr Plan

Through SE Resolution No. 501/25, complementary guidelines were established for producers holding contracts with CAMMESA and/or ENARSA to withdraw volumes under the GasAr Plan pursuant to SE Resolution No. 400/25.

F- 22

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

On December 12, 2025, the Company, in its capacity as owner of thermal generation units in the WEM and pursuant to SE Resolution No. 501/25, requested CAMMESA to assign in its favor GasAr Plan agreements for volumes of up to 4.9 million m³/day. On December 30, 2025, CAMMESA granted its consent to the assignment of the contractual position requested by the Company.

2.1.2.3 Assignment of Contracts with ENARSA

In late December 2025, SE Resolution No. 606/25 was issued, introducing adjustments to the GasAr Plan applicable to adhering producers.

Adhering producers are required to accept the assignment of contracts with ENARSA to distributors and CAMMESA, through a procedure to be determined together with ENARSA, and with access to the following benefits: (i) an increase in the provisional payment percentage (GasAr Plan compensation paid by the Government) from 85% to 90%, based on the affidavit submitted by each producer; (ii) a reduction in the injection commitment along the production curve; and (iii) the discontinuation of the quarterly investment plan progress reporting regime.

The opt-in procedure is carried out through the submission of a notice to the SE within 45 administrative business days from notification of the Resolution, and distributors must opt in within the same period. ENARGAS will oversee the assignment process and the allocation of volumes.

2.1.2.4 Natural gas for the residential segment and CNG

During 2025, the SE issued monthly resolutions establishing the update of the PIST price to be passed on to end users, pursuant to the agreements entered into under the GasAr Plan, for gas consumption made from January to December 2025 and on the tariff schemes published by ENARGAS´ effective date.

It is worth highlighting that the PIST value updates increase the amount collectable by the Company directly from distributors, decreasing the price compensation payable by the Federal Government under the GasAr Plan.

2.1.2.5 Acquisition of Natural Gas for Generation

SE Resolution No. 21/25, dated January 28, 2025, established that generators remunerated under the spot scheme may manage their own fuel. In the same sense, SE Resolution No. 400/25, effective as from November 1, 2025, modifies fuel management for power generation and the recognition of related costs, promoting generators’ self-supply. CAMMESA will remain as the supplier of last resort until 2029, when fuel management will become the generators’ exclusive responsibility, and the centralized scheme managed by CAMMESA will be fully discontinued.

2.1.2.6 Natural Gas and Liquefied Natural Gas Exports

(i) Natural Gas

Current regulations establish a procedure to authorize natural gas exports delimiting four export zones: the Neuquina Basin and the Austral Basin, with summer quotas, and the Noroeste Basin and other zones, with no quota definition.

F- 23

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The distribution of firm summer quotas among producers is made considering (i) the share of the producer’s volume in the basin’s total volume, and (ii) the highest discount in the weighted-average price discount per volume against the basin’s incremental volume.

An export quota was allocated for the 2025 summer periods (January–April and October–December) of 9 million m³/day for the Neuquina Basin and 2 million m³/day for the Austral Basin, with a minimum price equal to the simple average of Brent crude quotations for the first fifteen days of the month prior to delivery, multiplied by 5.5%. The Company was allocated an 892,589 m³/day volume for the 2025 summer period.

In addition, the SE established the export quotas for the 2025 winter period (May–September), totaling 7 million m³/day. In line with its participation in the GasAr Plan, the Company was allocated a volume of 694,236 m³/day for the 2025 winter period.

For 2026, an export quota of 7.7 million m³/day for the Neuquina Basin and 2 million m³/day for the Austral Basin was allocated for the summer periods (January–April and October–December), while for the winter period (May–September) 7.4 million m³/day was allocated for the Neuquina Basin.

For the Neuquina Basin, in both periods, the minimum price is equal to the average awarded price under all GasAr Plan rounds for the basin multiplied by the applicable seasonal adjustment factor.

The Company was allocated the following volumes:

1,195,267 m³/day for the January–March 2026 period.

1,215,267 m³/day for April 2026.

989,809 m³/day for the May–August 2026 period.

1,048,088 m³/day for September 2026.

1,228,600 m³/day for the October–December 2026 period.

It is worth highlighting that, as of the date of issuance of these Consolidated Financial Statements, there is an 8% tax on natural gas exports in effect.

(ii) Liquefied Natural Gas (LNG)

SE Resolution No. 145/25 approved the procedure for exporting LNG, establishing that a firm LNG export authorization will be granted for a term of up to 30 years from the commissioning of the liquefaction plant or its expansions. This authorization grants its holders the right to export the authorized volumes without interruptions, restrictions or redirection during its term.

2.1.2.7 Compensation for Natural Gas Consumption Subsidies

ENARGAS Resolution No. 125/25 restructures the compensation system for natural gas consumption subsidies applicable to natural gas distribution companies, modifying the recipient of such compensation. The new mechanism, effective as from February 1, 2025, provides that compensation will be received directly by natural gas producers and deducted from the producers’ invoicing to distributors.

F- 24

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.3 Oil market

2.1.3.1 Crude oil price

As of December 31, 2025, there is no reference price for the sale of crude oil in the domestic market. As with natural gas exports, there is an 8% export duty on crude oil.

2.2 Generation

2.2.1 Generation units

Generation units are remunerated under: i) sales contracts with large users within the MAT and supply agreements with CAMMESA and ii) sales to the spot market. The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:

In operation as of December 31, 2025:


Generator	Generating unit	Tecnology	Fuel	Power	Applicable regime
CTG	GUEMTG01	TG	Gas	100 MW	Resolution No. 400/25 (*)
CTG	GUEMTV11	TV	Gas	63 MW	Resolution No. 400/25
CTG	GUEMTV12	TV	Gas	63 MW	Resolution No. 400/25
CTG	GUEMTV13	TV	Gas	135 MW	Resolution No. 400/25
Piquirenda	PIQIDI 01-10	MCI	Gas	30 MW	Resolution No. 400/25
CPB	BBLATV29	TV	Dual	310 MW	Resolution No. 400/25
CPB	BBLATV30	TV	Dual	310 MW	Resolution No. 400/25
CT Ing. White	BBLMD01-06	MCI	Dual	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	Gas	555 MW	Resolution No. 400/25
CTLL	LDLATG04	TG	Gas	105 MW	Res. No. 220/07 (75%)
CTLL	LDLATG05	TG	Gas	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	MCI	Gas	15 MW	Resolution No. 400/25
CTGEBA	GEBATG01/TG02/TV01	CC	Gas	685 MW	Resolution No. 400/25
CTGEBA	GEBATG03	TG	Gas	169 MW	Resolution No. 400/25 (*)
CTGEBA	GEBATG03/TG04/TV02	CC	Gas	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	Vapor	14 MW	Resolution No. 400/25 (*)
CT Parque Pilar	PILBD01-06	MCI	Dual	100 MW	Resolution No. 21/16
CTB	EBARTG01 - TG02	TG	Dual	569 MW	Resolution No. 400/25
CTB	EBlARTV01	TV	Dual	279 MW	Resolution No. 220/07
HIDISA	AGUA DEL TORO	HI	-	150 MW	Resolution No. 602/25
HIDISA	EL TIGRE	HR	-	14 MW	Resolution No. 602/25
HIDISA	LOS REYUNOS	HB	-	224 MW	Resolution No. 602/25
HINISA	NIHUIL I - II - III	HI	-	265 MW	Resolution No. 400/25
HPPL	PPLEHI	HI	-	285 MW	Resolution No. 602/25
PEPE II	PAMEEO	Wind	-	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	-	53 MW	MATER Res. No. 281/17
PEPE IV	PEP3EO - PE32EO	Wind	-	81 MW	MATER Res. No. 281/17
PE Arauco - PEPE V	AR21EO	Wind	-	100 MW	Renovar
PEPE VI	PEP6EO	Wind	-	140 MW	MATER Res. No. 281/17

(*) Additionally, it markets capacity and energy under residual Energy Plus contracts pursuant to Resolution No. 1,281/06.

F- 25

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.2 Sales contracts with large users within the MAT and Supply agreements with CAMMESA

2.2.2.1 New MAT Regime

SE Resolution No. 400/25 modified the MAT as from November 1, 2025, promoting free contracting among agents and establishing two markets: MAT Power Capacity and MAT Energy.

Thermal and hydroelectric generation installed before January 1, 2025 may sell, under contracts, up to 100% of generated energy to distributors to cover unmet seasonalized demand, or up to 20% of generated energy to WEM large users or to distributors for GUDI. Starting in 2030, these generators may freely contract with any demand segment.

Thermal generation installed after January 1, 2025 with self-managed fuel supply or with additional firm gas transportation capacity may contract with any demand segment without limitations. Renewable-source generation maintains the MATER conditions. Storage projects may enter into contracts without restrictions.

2.2.2.2 Renewable Energy Term Market (“MATER” Regime)

SE Resolution No. 281/17 regulated the regime for large users and large demands by WEM distribution agents (covered by Section 9 of Law No. 27,191) to meet their renewable-source demand supply obligation through individual contracting under the MATER, under terms and conditions to be agreed between the parties.

Within the framework of this regulation, the Company, through its PEPE II, III, IV and VI wind farms, sells energy for a maximum of 327 MW. Additionally, during 2025, renewable energy from third-party generators was commercialized for a total volume of 1.25 MW.

2.2.2.3 Energy Plus Contracts

SE Resolution No. 1,281/06 set a specific regime for new generation capacity installed by certain agents, which enabled the execution of Energy Plus contracts in the MAT at prices negotiated with GU300.

In 2025, SE Resolution No. 21/25 limited the submission or renewal of Energy Plus contracts until October 31, 2025. As a result, the Energy Plus market will cease to be in force upon the expiration of the contracts submitted or renewed up to that date.

As of December 31, 2025, the Company, through its CTG, EcoEnergía and CTGEBA power plants, sells power capacity and energy under residual Energy Plus contracts, mainly denominated in U.S. dollars or, alternatively, adjusted based on CAMMESA price variations. The Company’s Energy Plus contracts will expire during 2026.

F- 26

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.2.4 Supply Agreements with CAMMESA – Specific Regimes

Aiming to promote new generation capacity and/or combined-cycle closing projects at existing facilities, SE Resolutions No. 220/07, No. 21/16 and No. 287/17 authorized CAMMESA to enter into long-term power supply agreements with certain agents and/or awarded projects.

Under these regulations, the Company holds supply agreements with CAMMESA remunerating: (i) 79 MW from CTLL and 279 MW from the closed cycle of CTEB, owned by CTB, maturing in July 2026 and February 2033, respectively, under SE Resolution No. 220/07; (ii) 305 MW of power capacity and energy generated by CTLL, CTPP and CTIW thermal power plants, maturing between August and December 2027, under SE Resolution No. 21/16; and (iii) 400 MW of power capacity and energy generated by the CTGEBA thermal power plant, maturing in July 2035, under SE Resolution No. 287/17.

SE Resolution No. 501/25 introduced a fuel self-managed regime applicable to thermal units operating with gas assigned by producers under the GasAr Plan. However, this regime does not modify the centralized fuel management scheme applicable to the specific supply agreements executed under SE Resolutions No. 220/07, No. 21/16 and No. 287/17, which remain under CAMMESA’s administration pursuant to SE Resolution No. 21/25.

2.2.2.5 Renovar Programs

In order to meet the objectives set forth by Laws No. 26,190 and No. 27,191 promoting the use of renewable energy sources, the MEyM called for open rounds for the procurement, within the WEM, of electricity generated from renewable sources (Renovar Programs). For awarded projects, renewable electricity supply agreements were executed for the commercialization of an annual committed electricity block over a 20-year term.

The Company has a power supply agreement with CAMMESA in place for the PE Arauco for a total of 100 MW, maturing in March 2040.

F- 27

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.3 Remuneration at the spot market

2.2.3.1 New Spot Regime

Pursuant to SE Resolution No. 400/25, the remuneration scheme for generation in the spot market was modified as from November 1, 2025, making a distinction by energy source.

Generated energy is remunerated based on the variable production cost (“CVP”) and the adjusted marginal rent (“RMA”). The RMA reflects the hourly marginal cost (“CMgh”), adjusted, where applicable, by the loss factor (“FP”) corresponding to the relevant node and by an adapted rent factor (“FRA”), that is: RMA = (CMgh x FP – CVP) x FRA.

For thermal generation, a minimum rent scheme is established, equivalent to US$ 2/MWh and US$ 7/MWh for existing generation with a CVP below US$ 60/MWh, and a CVP equal to or exceeding US$ 60/MWh, respectively. The applicable adapted rent factors are as follows:


FRA	Installed generation
	2025 onwards	up to 2024
		With fuel self-management	with gas supplied by CAMMESA	with no fuel management (*)
2025 and 2026	1	15%	12%	0
2027		25%	15%
2028 onwards		35%	17.50%
	(*) CVP equivalent to regulated values.

F- 28

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

For hydroelectric and renewable generation, a minimum RMA of US$ 22/MWh and US$ 32/MWh, respectively, is established for units commissioned before January 1, 2025, with no minimum or maximum established for units commissioned after that date. Additionally, a CVP = 0 is assumed, and the following adapted rent factors are applied:


FRA	Commissioned generation
	2025 onwards	up to 2024
2025 and 2026	1	15%
2027		25%
2028 onwards		35%

Additionally, available capacity (“PPAD”) is remunerated based on 90 weekly hours at a rate of US$ 12/MWhrp, adjusted by a seasonal correction factor (“FCE”):


FCE	Thermal generation		Hydros	Renewable sources
	with fuel self-management
	natural gas	Alternative fuels
Winter / Summer	1.1	1.5	0.5	0
Remaining periods	0.9	1

For thermal generation without fuel self-management or supplied by CAMMESA, the following available capacity remuneration scheme applies:


PPAD	Thermal generation
	Dispatched	Non-dispatched
2026	100%	80%
2027		40%
2028 onwards		0%

Additionally, a base reliability reserve payment of US$ 1,000/MW-month is recognized, regardless of the fuel used or its management.

Under this new regime, the Company operates all thermal power plants not remunerated under specific regimes, as well as the HINISA hydroelectric power plant.

F- 29

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.3.2 Prior Spot Regime

Up to October 31, 2025, spot generation was remunerated based on tariffs denominated in pesos, which were updated through the issuance of different resolutions. During 2025, SE Resolutions No. 603/24, No. 27/25, No. 113/25, No. 143/25, No. 177/25, No. 227/25, No. 280/25, No. 331/25, No. 356/25 and No. 381/25 updated spot generation remuneration values, providing for 4%, 4%, 1.5%, 1.5%, 2%, 1.5%, 1%, 0.4%, 0.5% and 0.5% increases, respectively, applicable to economic transactions from January through October 2025. The maximum WEM spot price for October 2025 amounted to $ 13,622/MWh.

This scheme established a minimum capacity remuneration and allowed generating agents to offer guaranteed availability commitments for quarterly periods: a) summer (December to February); b) winter (June to August); and c) “remaining periods” (March to May and September to November).

Guaranteed capacity remuneration for thermal generators with availability commitments under SE Resolution No. 381/25 amounted to $ 7,011,177/MW-month for the summer and winter periods, and $ 5,258,385/MW-month for the remaining periods of the year.

In the case of hydroelectric generators, base remuneration under SE Resolution No. 381/25 included the following scales and prices:


Technology / Scale	($ / MW- month)
Medium HI Capacity > 120 ≤ 300 MW	2,570,771
Small HI Capacity > 50 ≤ 120 MW	3,534,805
Medium Pumped HI Capacity > 120 ≤ 300 MW	2,570,771
Renewable HI Capacity ≤ 50 MW	5,784,224

Lastly, the following remuneration levels were established for energy generated and operated under SE Resolution No. 381/25:


Remuneration	Thermal Power Plants ($ / MWh)	Hydroelectric Power Plants ($ / MWh)	Non-conventional source ($ / MWh)
Generated energy	Between 4,678 and 8,186	4,089	32,718
Operated energy	1,627	1,627	-

F- 30

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

In the case of thermal generators, remuneration for generated energy depended on the type of fuel used.

Between November 2022 and October 2025, a differentiated remuneration scheme was established for energy generated during peak hours, applicable to thermal and hydroelectric generators, with a value of twice the prevailing remuneration for energy generated during peak hours (6:00 p.m. to 11:00 p.m.) on all days of the months of December, January, February, June, July and August, and of once such value for the same hours of the remaining months.

2.2.3.3 Remuneration for CC

SE Resolution No. 59/23 established a regime that enabled CC holders to enter into availability and efficiency improvement agreements with CAMMESA, with an availability commitment of 85% of net capacity for a maximum term of five years; a remuneration of US$ 2,000/MW-month for available capacity; U.S. dollar-denominated energy prices based on the fuel used (US$ 3.5/MWh for natural gas and US$ 6.1/MWh for fuel oil and gas oil), and where applicable, a 35% and 15% reduction in the remuneration collectable for guaranteed capacity in the spot market for the summer–winter and autumn–spring periods, respectively.

The Company entered into agreements with CAMMESA for its CTLL and CTGEBA power plants’ CC. In addition, CTB entered into an agreement with CAMMESA for its open-cycle GT units. The above-mentioned agreements contemplated a term from March 1, 2023 to February 29, 2028. However, on October 28, 2025, the Company and CTB withdrew from the scheme established under SE Resolution No. 59/23 and opted into the new spot regime, effective as from November 2025, thus, obligations assumed under Resolution SE No. 59/23 were suspended as long as the conditions set forth in Resolution SE No. 400/25 remain in force.

2.2.3.4 Additional, Complementary and Exceptional Remuneration for Thermal Generation

To promote the availability of thermal power plants during critical months and hours, SE Resolution No. 294/24, effective from December 2024 through March 2026, established an additional, complementary and exceptional remuneration that includes: (i) a US$ 2,000/MW-month remuneration for power capacity, adjusted by a criticality factor that takes into account the node where the generation unit is located, and the unit’s actual availability in the most critical hours, plus 50% of such remuneration for the power capacity exceeding that committed; and (ii) a remuneration for the energy generated during the most critical days and hours, also adjusted by the criticality factor, ranging from US$ 3.4/MWh to US$ 10.5/MWh depending on the fuel and the generation technology used. The resolution provides for a 12-month period scheme extension, subject to the submission of specific maintenance programs.

Under this regulation, the Company opted into the call and formalized availability agreements for the energy not committed under other regimes for its CPB, CTG, Piquirenda, CTLL, CTGEBA and Ecoenergía thermal power plants.

In January 2026, the SE approved the maintenance programs submitted by the power plants and granted the extension of the detailed remuneration for an additional 12-month period, through March 2027.

F- 31

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.4 Remuneration for Assigned Generation

Assigned generation includes generation under effective WEM power supply agreements, Federal Government generation, thermal generation managed by ENARSA and hydroelectric generation under concessions granted by the Federal Government.

The remuneration for assigned generation continues to be based on the values established in the effective agreements and/or on specific regulations issued by the SE. For this reason, SE Resolutions No. 483/25 and No. 602/25, applicable to economic transactions as from November and December 2025, respectively, updated the values established under SE Resolution No. 381/25.

Under this regime, the Company operates the HIDISA and HPPL hydroelectric power plants until new Federal Government concession agreements are executed, with the following availability capacity prices for December 2025:


Technology / Scale	($ / MW-month)
Medium HI Capacity > 120 ≤ 300 MW	2,963,070
Medium Pumped HI Capacity > 120 ≤ 300 MW	2,963,070
Renewable HI Capacity ≤ 50 MW	8,745,746

Lastly, it establishes $ 4,317/MWh and $ 1,718/MWh remunerations for generated and operated energy, respectively, and maintains a differentiated remuneration scheme for energy generated during peak hours, at an amount equivalent to twice the prevailing remuneration for generated energy, applicable to peak hours (6:00 p.m. to 11:00 p.m.) on all days of the summer and winter months, and at an amount equivalent to once such value for the same hours in the remaining months of the year.

2.2.5 Fuel supply for thermal generators

Under the prior scheme, fuel supply for power generation was centralized by CAMMESA.

As from March 1, 2025, SE Resolution No. 21/25 authorized the recognition of fuel costs based on reference prices and the values declared and accepted in the Production Cost Statement, plus freight, natural gas transportation and distribution costs, and applicable taxes and fees.

In turn, Note SE NO-2025-35216647-APN-SE#MEC dated April 4, 2025, established guidelines for the gas dispatch priority scheme for thermal generation in the WEM. Tenders submitted by generators opting to self-manage their fuel supply are considered firm and, in the event of non-compliance, are subject to a Deliver-or-Pay penalty equivalent to 70% of the unavailable volume's reference price.

F- 32

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The new reference price equals 90% of the basin-weighted average natural gas price in the PIST, using Round 4.2’s prices for the Neuquina Basin and the Norte Basin, and Round 4.1’s prices for the Austral Basin.

Reference prices for liquid fuels are set for each generator based on international indicators, including a premium covering associated financial and logistics costs. Prices for liquid fuels and for natural gas sourced from neighboring countries are recognized at the exchange rate applicable on the business day immediately preceding the relevant transactional due date and are associated with the recognized consumption in the respective economic transaction.

Finally, SE Resolution No. 400/25 modified fuel management for power generation and the recognition of related costs, promoting generators’ self-supply, with CAMMESA remaining as the supplier of last resort until 2028. As from 2029, fuel management will become the generators’ exclusive responsibility.

Additionally, SE Resolution No. 501/25 allowed producers and generators to agree on natural gas supply considering volumes committed under GasAr Plan contracts executed between producers and CAMMESA. Such volumes will be treated as the generators’ own gas and remunerated based on the declared CVP for dispatch.

2.3 Gas Transportation

2.3.1 TGS’s Tariff situation

During 2025 and until completion of the FTR process, TGS received monthly tariff increases of 2.5%, 1.5% and 1.7% for the January to March 2025 period.

On April 30, 2025, through ENARGAS Resolution No. 256/25, the conditions for the 2025-2030 FTR were established. Key aspects include: (i) the capital base as of December 31, 2024; (ii) a real, after-tax WACC discount rate of 7.18%; (iii) a weighted average tariff increase of 3.67%, subsequently adjusted to 4.74%, to be implemented in 31 equal and consecutive monthly installments starting in May 2025; (iv) an investment plan totaling $279,108 million (in June 2024 currency values), subject to ENARGAS oversight; and (v) regulated operating expenses.

Subsequently, under Executive Order No. 371/25, the SE was designated as the enforcement authority to introduce contractual or tariff modifications. In this line, SE Resolution No. 241/25, dated June 4, 2025, provided for a monthly periodic update of transportation tariffs in lieu of the previous semiannual scheme. TGS expressed its conformity with this resolution on June 5, 2025, and ENARGAS Resolutions No. 350/25, No. 421/25, No. 539/25, No. 622/25, No. 732/25, No. 812/25, No. 907/25, No. 1,000/25 and No. 32/26 approved the tariff schemes, incorporating monthly 2.81%, 0.62%, 1.63%, 2.38%, 2.49%, 2.89%, 1.71%, 2.03% and 2.63% updates for the June 2025 to February 2026 period, in addition to the implementation of the FTR increases.

2.3.2 License extension request

On July 24, 2025, Executive Order No. 495/25 was published, whereby the PEN provided for a 20-year extension of the license granted to TGS, effective as from December 28, 2027.

F- 33

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.3.3 Regulatory framework of the segment of Production and Commercialization of Liquids

2.3.3.1 Domestic market

The liquids and other services’ production and commercialization activities are not subject to ENARGAS regulation. However, in recent years, the Argentine Government has issued a number of regulations having a significant impact on these activities.

Law No. 26,020/05 ‘Regulatory regime for the liquefied petroleum gas industry and commercialization’, sets forth the regulatory framework for the LPG industry and commercialization. Under this regime, the SE issues rules to ensure domestic supply, including the determination of minimum volumes and the setting of selling prices for the domestic market.

The Household Gas Bottles’ Program (the ‘Household Plan’) has been in effect since 2015. This program established maximum reference prices and mandatory supply quotas for producers. SE Resolution No. 15/25, dated January 24, 2025, eliminated the maximum sales price established for products supplied under the Household Plan, setting as a cap the export parity price published by the SE under Law No. 26,020. In addition, it maintained the obligation to supply the domestic market, but eliminated the previously required product contributions. In this sense, during 2025, supply obligations at regulated prices remained in place, with cumulative 41.42% increases between 2024 and 2025.

Additionally, TGS is party to the Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids (the ‘Propane for Networks Agreement’). Under this agreement, TGS undertakes to sell propane to distributors and subdistributors at a price below market, receiving economic compensation equivalent to the difference between the agreed selling price and the reference export parity price determined by the SE.

As of December 31, 2025, the Argentine Government owes TGS $ 12,720 million under these items.

2.3.3.2 Foreign market

The applicable rate for export duties on certain gas- and oil-derived products, including those produced and exported by TGS, is 8%.

2.4 Transmission

2.4.1 Transener and Transba tariff situation

The ENRE determined the hourly remuneration values, establishing 4%, 4%, 2% and 4% increases for the January to April 2025 period compared to the values in force for Transener and Transba.

On April 3, 2025, ENRE Resolution No. 236/25 modified the high-voltage and main electricity distribution utility concessionaires’ rate of return, increasing it from 6.10% to 6.48% after tax.

F- 34

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

On April 30, 2025, the tariff scheme resulting from the FTR process was approved, and the ENRE established 42.89% and 10.30% increases for Transener and Transba, respectively, compared to the tariffs in force as of April 2025. Similarly, the ENRE determined the remuneration for independent transmission companies, including Transener, for the operation of the Choele Choel–Pto. Madryn Interconnection and the Fourth Line, and Transba, for the operation of Transportista Independiente de Buenos Aires (TIBA)’s facilities, establishing a tariff equivalent to 77.92%, 100% and 99.73%, respectively, of the tariff established for Transener.

In all cases, the increases were applied as follows: 20% as from May 1, 2025, and the remaining 80%, on a monthly basis during the June-December 2025 period. In addition, a monthly tariff update mechanism is contemplated based on the CPI and IPIM indexes.

Accordingly, the ENRE established the following increases:

Schedule of transmission tariff
	Jun-25	Jul-25	Aug-25	Sep-25	Oct-25	Nov-25	Dec-25
Transener and Fourth Line	7.25%	4.64%	6.02%	6.95%	7.12%	7.61%	5.87%
Transba	4.06%	1.53%	2.87%	3.78%	3.94%	4.41%	2.73%
Choele Choel – Pto. Madryn Interconnection	4.35%	1.80%	3.14%	4.05%	4.22%	4.69%	3.00%
Transportista Independiente de Buenos Aires (TIBA)	7.22%	4.61%	5.99%	8.10%	8.27%	8.76%	7.01%

On August 18, 2025, the ENRE upheld the motions for reconsideration filed by Transener and Transba on June 17, 2025, and, consequently, modified the cost and investment structure for Transener, Transba, the Choele Choel–Puerto Madryn Interconnection and TIBA. In the case of the independent transmission companies, including TIBA, the ENRE additionally recognized an increase in revenues arising from the payment to Transener for operation and maintenance supervision, applicable as from September 2025.

As a result of the introduced changes, on September 5, 2025, the investment plans to be executed by Transener, Transba, TIBA, and the Choele Choel - Puerto Madryn Interconnection over the May 2025-April 2030 period were duly and timely submitted for approval by the ENRE. As of the date of issuance of these Consolidated Financial Statements, ENRE’s approval has not been received.

On December 23, 2025, through ENRE Resolution No. 811/25, the assignment of the rights and obligations under the Operation and Maintenance Agreement for the Choele Choel–Puerto Madryn Interconnection from Integración Eléctrica Sur Argentina S.A. to Transener was approved, establishing that Transener will be remunerated in accordance with the hourly values applicable to its regulated equipment, and that it will take on the execution of the investment plan established in the FTR for Integración Eléctrica Sur Argentina S.A.

Lastly, the ENRE established 1.88% and 2.55% tariff increases for January and February 2026, respectively.

F- 35

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.5 Regulations on access to the MLC

In 2020, BCRA establishes measures with the purpose of regulating inflows and outflows in the MLC to maintain the exchange rate stability and protect international reserves in view of the high degree of uncertainty and volatility in the exchange rate, including restrictions associated with transactions with stock market assets by companies and the disposal of liquid foreign assets.

During 2025, the BCRA eased several restrictions on access to the MLC and established a number of measures aimed at fostering the repatriation of direct investments by non-residents.

In general terms, all currency demand transactions in the MLC require BCRA’s prior authorization, with certain exceptions, such as: (i) affidavits stating that all foreign currency holdings in the country are deposited with local financial institutions and that no liquid foreign assets are held in an amount exceeding US$ 100,000; (ii) payments for certain imports of capital goods; (iii) payments for services rendered by non-residents; (iv) legal entities with profits from fiscal years beginning on or after January 1, 2025, to remit abroad profits and dividends to non-resident shareholders; (v) where an affidavit is stating the commitment not to carry out certain transactions involving the sale, exchange or transfer of marketable securities during the 90 consecutive days following the request for access to the MLC; (vi) non-resident entities acquiring an equity interest in resident companies (other than financial institutions or their controlling entities); (vii) resident entities acquiring 100% of the share capital of non-resident companies whose only asset is an interest in local companies; and (viii) resident entities acquiring certain non-resident interests in concessions for the exploitation of natural resources granted in the country, simultaneously with the settlement of funds arising from foreign financial indebtedness or local foreign-currency financial loans under a foreign credit line.

In addition, the BCRA imposes, in certain circumstances, the obligation to enter and settle funds received abroad within 20 business days from collection or receipt.

It is worth highlighting that the detailed information does not list all possibly applicable exchange regulations; for more information on Argentina’s exchange rate policies, please visit the Central Bank’s website: www.bcra.gov.ar.

2.6 Tax regulations

2.6.1 Income tax

2.6.1.1 Income tax rate

Law No. 27,630, effective in Argentina for fiscal years beginning on or after January 1, 2021, established a tiered rate scheme of 25%, 30% and 35% and, where applicable, a flat tax depending on the level of annual net taxable income.

On its part, the income tax rates used at year-end in Ecuador, Bolivia, Uruguay and Chile are 25%, 25%, 25% and 27%, respectively. A 3% surcharge on income tax will be added in Ecuador when the shareholder is an entity incorporated in a jurisdiction considered a tax haven under Ecuadorian law.

In Uruguay, effective January 1, 2023, the Income Tax on Economic Activities (IRAE) includes as Uruguayan-source income certain passive income obtained by entities making up multinational groups and considered non-qualified.

F- 36

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.6.1.2 Tax on dividends

Law No. 27,430 and modifications introduced by Law No. 27,541 and Law No. 27,630, established a 7% tax on dividends derived from earnings accrued during fiscal years beginning as from January 1, 2018, when distributed by Argentine companies to individuals, undivided estates or beneficiaries residing abroad.

Dividends resulting from benefits gained until the fiscal year prior to that beginning on January 1, 2018, in Argentina, will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax’ transition period) for all beneficiaries.

In Bolivia, payments of Bolivian-source income made to foreign beneficiaries are subject to a 12.5% withholding tax on the profits of the foreign beneficiary companies.

In Ecuador, effective January 1, 2020, dividends distributed to foreign shareholders are subject to a 10% withholding tax. In addition, starting in fiscal year 2025, a tax is levied under a tiered rate scheme ranging from 0% to 2.5% based on the amount of accumulated profits pending distribution as of July 31 of each year. This tax may be offset as an advance payment against the tax applicable to the actual distribution of dividends or against income tax, provided that certain conditions set forth in the applicable regulations are met.

In Chile, dividend payments to non-residents are subject to a 35% withholding tax.

In Uruguay, dividends distributed by IRAE taxpayers are taxed —until the concurrence of the net income taxed by IRAE—, at a general 7% rate, while the amount of a company’s taxable income that remains undistributed after 3 fiscal years is treated as a deemed distribution and is subject to the 7% dividend tax.

2.6.1.3 Tax inflation adjustment

Law No. 27,430 sets out the following rules for the application of the income tax inflation adjustment mechanism:

(i)

a cost adjustment for goods acquired or investments made during fiscal years beginning after January 1, 2018 taking into consideration the percentage variations in the CPI published by the INDEC; and

(ii)

the application of the adjustment provided for by Title VI of the Income Tax Law when variations in the above-mentioned index exceed 100% over the 36 months preceding the closing of the fiscal period to be settled.

Law No. 27,541 provided that, as regards the positive or negative fiscal inflation adjustment determined as a result of the application of the adjustment provided for by Title VI of the Income Tax Law corresponding to the first and second fiscal year starting as from January 1, 2019, one-sixth should be charged in that fiscal period and the remaining five sixths, in equal parts, in the five immediately following fiscal periods.

On December 1, 2022, Law No. 27,701 was published in the BO, which established that taxpayers determining a positive inflation adjustment in the first and second fiscal year starting from January 1, 2022 (inclusive) may allocate one-third in that fiscal period and the remaining two-thirds, in equal parts, in the two immediately following fiscal periods. This computation only applies to subjects making investments in the purchase, construction, manufacture, production or final import of property, plant and equipment, except automobiles, during each of the two fiscal periods immediately following that in which the computation of the first third of the period in question exceeds or equals $ 30,000 million.

F- 37

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

As of the date of issuance of these Consolidated Financial Statements, this provision has not yet been regulated.

The Company and its subsidiaries determine and disclose the impact of the tax inflation adjustment for each of the fiscal periods in which it is applicable.

2.6.2 Value-added tax

A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity.

2.6.3 Export Increase Program

On April 14, 2025, PEN Executive Order No. 269/25 reinstated the MLC entry and settlement requirement for 100% of the value of exports.

2.6.4 Other regimes

Law No. 27,742 established the RIGI in Argentina, a regime designed to attract capital through tax, customs and foreign exchange benefits. Under this regime, adhering Single Project Vehicles (“SPV”) must execute investments in excess of US$ 200 million in strategic sectors of the country, such as energy, mining, technology and infrastructure. Key income tax benefits include the application of a fixed 25% rate, accelerated tax depreciation of investments, and the inflation adjustment of tax losses with no prescription limitations and the possibility of transferring them to third parties. Regarding VAT, the main tax benefit consists of avoiding the accumulation of technical tax credits and improving project cash flows through a payment mechanism using tax credit certificates. Tax benefits are protected by 30 years of regulatory stability, preventing the imposition of taxes more burdensome than those in effect at the opt-in time.

Provinces that have opted into the RIGI include Neuquén, Río Negro, Chubut, Mendoza and Córdoba. The province of Buenos Aires, in turn, has established its own regime within its jurisdiction.

NOTE 3: BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS Accounting Standards as issued by the IASB, are expressed in million dollars and were approved for their issuance by the Board of Directors on March 2, 2026. Significant accounting policies adopted in the preparation of these Consolidated Financial Statements are described in Note 4, which have been consistently applied.

This consolidated financial information has been prepared under the historical cost convention, modified by the measurement of financial assets at fair value through profit or loss.

These accounting policies have been applied consistently by all Group companies. Additionally, certain non-significant reclassifications have been made to financial statements presented with comparative purposes to keep the consistency in the presentation with the amounts of the current year.

F- 38

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: ACCOUNTING POLICIES

The main accounting policies used in the preparation of these Consolidated Financial Statements are explained below.

Pursuant to CNV General Resolution No. 972/23, the early application of IFRS Accounting Standards and/or their amendments is not allowed, unless specifically allowed at the time of adoption.

As of December 31, 2025, the Company has not opted for the early application of IFRS Accounting Standards and/or its amendments.

4.1

New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2025 and adopted by the Company

The Company has applied the following standards and/or amendments for the first time as of January 1, 2025:

IAS 21 - “The Effects of Changes in Foreign Exchange Rates” (amended in August 2023)

The application of the detailed standards and amendments did not have any impact on the results of the operations or the financial position of the Company.

4.2

New standards, amendments and interpretations issued by the IASB not yet effective and which have not been early adopted by the Company

As of December 31, 2025, the Company has not early applied the following standards and/or amendments:

- IFRS 18 - “Presentation and Disclosures in Financial Statements”: issued in April 2024. It establishes new presentation and disclosure requirements aiming to ensure that financial statements provide relevant information faithfully representing an entity’s situation. The standard does not affect the recognition or measurement of financial statement items; however, it introduces new requirements for improved comparability among entities. Specifically, the following are worth mentioning: (i) the classification of revenues and expenses into operating, investing and financing categories; (ii) the incorporation of required subtotals; and (iii) the disclosure of performance measures defined by management. The standard is applicable retroactively to fiscal years and interim periods beginning on or after January 1, 2027, allowing for early adoption. The Company is currently analyzing the disclosure impact on the financial statements in relation to the application of the standard.

F- 39

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

- IFRS 19 - “Subsidiaries without Public Accountability: Disclosures”: issued in April 2024 and amended in August 2025. It allows for reduced disclosures for entities without public accountability which are subsidiaries of an entity that prepares consolidated financial statements available for public use and comply with IFRS accounting standards. The standard is applicable for periods beginning on or after January 1, 2027, allowing for early adoption. The application of the standard will not have an impact on the Company’s results of operations or financial position.

- IFRS 9 and IFRS 7 - “Financial Instruments and Disclosures”: in May 2024, the application guidance for IFRS 9 is modified and disclosure requirements are incorporated into IFRS 7. In particular, it incorporates the option to consider the derecognition of a financial liability before its settlement in case of issuance of electronic payment instructions meeting certain requirements, and incorporates disclosure requirements for investments in equity instruments designated at fair value through other comprehensive income and instruments at amortized cost or fair value through other comprehensive income. The amendments apply to fiscal years beginning on or after January 1, 2026, allowing for early adoption. The application of the standard will not have an impact on the Company’s results of operations or financial position.

- IMPROVEMENTS TO IFRS - Volume 11: in July 2024, minor amendments are incorporated into IFRS 1, IFRS 7, IFRS 9, IFRS 10 and IAS 7. The amendments are applicable to fiscal years beginning on or after January 1, 2026, allowing for early adoption. The application of the amendments will not have an impact on the Company’s operating results or financial position.

- IFRS 9 and IFRS 7 “Financial Instruments and Disclosures”: in December 2024, IFRS 9 is amended and disclosure requirements are incorporated into IFRS 7 concerning nature-dependent electricity purchase agreements. In particular, it allows for exemption from registration at fair value for entities that are net buyers of electricity during the contracts; and makes designation as a hedging instrument more flexible for contracts not meeting the requirements for the above-mentioned exemption. The amendments are applicable to fiscal years beginning on or after Friday, January 1, 2027, allowing for early adoption. The application of the standard will not have an impact on the Company’s results of operations or financial position.

- IAS 21 - “Effects of Changes in Foreign Exchange Rates”: In November 2025, IAS 21 was amended regarding the translation of financial statements for presentation in a currency different from the functional currency, and certain disclosure requirements were introduced. In particular, for the translation from a non-hyperinflationary functional currency to a hyperinflationary presentation currency, it establishes that all amounts (assets, liabilities, equity items, income and expenses, including comparative information) are translated at the closing exchange rate. The amendments are retrospectively applicable for annual periods beginning on or after January 1, 2027, with early adoption permitted. The Company is assessing the impact of applying the translation methodology on profit or loss, other comprehensive income arising from exchange differences on translation and comparative information.

F- 40

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.3

Effects of changes in foreign exchange rates

4.3.1 Functional and presentation currency

The information included in these Consolidated Financial Statements is recorded and presented in U.S. dollars, which is the Company’s functional currency, that is, the currency of the primary economic environment where the entity operates.

4.3.2 Foreign-currency transactions and balances

Foreign currency transactions are translated into the functional currency at the exchange rates prevailing on each transaction date or valuation date, when items are remeasured. Foreign exchange gains and losses arising on the settlement of monetary items and on translating monetary items at the closing of the fiscal year using year-end exchange rate are recognised within the financial results in the statement of comprehensive income, with the exception of capitalized amounts.

4.3.3 Group entities’ translation into functional currency

The results and financial position of subsidiaries, joint ventures and associates whose functional currency is the Argentine Peso, a currency of a hyperinflationary economy, are translated into the Company’s functional currency using the year-end exchange rate. The results generated by the application of the IAS 29 adjustment mechanism for hyperinflationary economies on the opening equity measured in functional currency are recognized under “Other comprehensive income”.

4.3.4 Presentation of Other comprehensive income within the Company’s equity

The Company classifies and directly accumulates within equity, in the retained earnings line, the results generated by the application of the IAS 29 adjustment mechanism on the opening retained earnings, while the remaining results are presented in a separate component of equity and accumulated until the disposal of the foreign operation in “Other comprehensive income”, in accordance with IAS 21.

4.4

Consolidation and participation in companies

4.4.1 Subsidiaries

The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group and ceases consolidation of entities from the date that control ceases.

The acquisition method of accounting is used to account for business combinations by the Group. Thus, identifiable assets acquired and liabilities and contingent liabilities assumed are recognized at their fair value at the acquisition date and the non-controlling interest at the proportional interest in the amounts of the identifiable net assets. The excess consideration transferred over the above-mentioned fair value is recognized as goodwill under Intangible Assets and the shortfall as gain on purchase in profit or loss for the period.

F- 41

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

If the business combination is completed in stages, the carrying amount of the previous interest in the acquiree is measured at fair value at the acquisition date. Any gain or loss arising from such measurement is recognized in profit or loss.

Intercompany transactions, balances and unrealized gains and losses on transactions between Group entities are eliminated. Accounting policies of subsidiaries have been changed when necessary to ensure consistency with the policies adopted by the Group.

Non-controlling interests in the results and equity of subsidiaries are shown separately in the Consolidated Statement of Comprehensive Income and Consolidated Statement of Changes in Equity respectively. The Company concluded that there are no significant minority shareholdings that require additional disclosures.

4.4.2 Joint operations

The Company recognizes its direct right to the assets, liabilities, incomes and expenses of joint operations and its share of any jointly held or incurred assets, liabilities, incomes and expenses.

4.4.3 Associates and joint ventures

Interests in associates and joint ventures are accounted for using the equity method, after initial recognition at cost. Under this method, investments are adjusted for post-acquisition changes to recognize the Group’s share of the profit or loss for the period and other comprehensive income of each investee.

At the time of acquisition, any difference between the cost of the investment and the Company’s share of the net fair value of the identifiable assets and liabilities in an associate or joint business is recorded as follows: (i) goodwill is included in the carrying amount of the investee and is not amortized; and (ii) any excess of the net fair value over cost is recorded as income for the determination of the Company’s share in the investee’s results.

Unrealized gains and losses on transactions between the Group and its associates and joint businesses are eliminated to the extent of the Group’s interest in these entities. Accounting policies of investees have been modified where necessary to ensure consistency with the accounting policies adopted by the Group.

The carrying amount of investments is reviewed for impairment following the policy described in Note 4.8.

4.5

Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the Executive committee.

The Executive Committee, is the highest decision-making authority, is the body responsible for allocating resources and setting the performance of the entity’s operating segments and has been identified as the body executing the Company’s strategic decisions.

F- 42

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

In segmentation the Company considers transactions with third parties and intercompany operations, which are done on internal transfer pricing based on market prices for each product.

4.6

Property, plant and equipment

Property, Plant and Equipment is measured following the cost model. It is recognised at acquisition cost less depreciation a less any accumulated impairment.

Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. The carrying amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance are charged to profit or loss during the reporting period in which they are incurred.

Works in progress are valued according to their degree of progress. The cost of work in progress whose construction will extend over time includes, if applicable, the computation of financial costs accrued on loans granted by third parties and other pre-production costs. Revenues and costs arising from the sale of elements obtained during the start-up process are charged to the profit and loss of the period.

Assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each year. An asset’s carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated recoverable amount. (see Note 4.8).

Any gain or loss generated by the disposal of an asset is charged or credited to income for the period in which the asset is derecognized.

4.6.1

Oil and gas exploration assets

The Company uses the successful efforts method to account for operations related to oil and gas exploration and production activities. Under this method, the following are capitalized: i) the costs of acquiring properties in oil and gas production and exploration areas; ii) the costs of drilling and equipping exploratory wells that result in the discovery of economically exploitable reserves; iii) the costs of drilling and equipping development wells and; iv) the estimated future costs of abandonment and plugging of wells.

Exploration costs, excluding the costs of exploratory wells, are charged to income during the period in which they are incurred. The exploratory wells’ drilling costs are capitalized until it is determined whether there are proven reserves justifying their commercial development. If no such reserves are found, the drilling costs are charged to income. Occasionally, an exploratory well may determine the existence of reserves, but such reserves may not be classified as proved when drilling is completed, in which case, such costs continue to be capitalized to the extent that the well encounters sufficient reserves to justify its completion as a producing well and the company makes sufficient progress in the economic and operational evaluation of the project’s viability.

F- 43

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.6.2

Depreciation methods and useful lives

The group depreciates productive wells and drilling equipment in the oil and gas production areas according to the units of production method, by applying the ratio of oil and gas produced to estimated proved developed oil and gas reserves. The acquisition cost of property with proved reserves is depreciated by applying the ratio of oil and gas produced to estimated proved oil and gas reserves. Acquisition costs related to properties with unproved reserves is valued at cost with recoverability periodically assessed on the basis of geological and engineering estimates of possible and probable reserves that are expected to be proved over the life of each concession.

Generation plants (including any significant identifiable component) are depreciated under the hour of operation method.

The group´s remaining items of property, plant and equipment (including any significant identifiable component) are depreciated by the straight-line method based on estimated useful lives, as detailed below:

Schedule of estimated useful lives
	Buildings:	50 years
	Vehicles:	3 - 5 years
	Furniture and fixtures, tools, software and communication equipments:	3 - 5 years
	Petrochemical plants:	3 - 30 years
	Other goods:	3 - 10 years

The depreciation method is reviewed and, if appropriate, adjusted at the end of each year.

4.6.3

Asset retirement obligations and wind turbines decommissioning

Estimated future costs of asset retirement obligations on well abandonment in oil and gas areas and wind turbines decommissioning, discounted at a risk adjusted rate, are capitalized in the cost of the assets and depreciated using the units of production method. Additionally, a liability at the estimated value of the discounted amounts payable is recognised. Changes in the measurement of asset retirement obligations that result from changes in the estimated timing, amount of the outflow of resources required to settle the obligation, or the discount rate, are added to, or deducted from, the cost of the related asset. If a decrease in the liability exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss.

4.7

Intangible assets

4.7.1

Goodwill

Goodwill is the result of business combinations (See Note 4.4.1) and does not depreciate.

For impairment testing, goodwill acquired in a business combination is allocated from the acquisition date to each of the CGU or group of CGU that are expected to benefit from the synergies of the combination.

F- 44

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.7.2

Concession arrangements

Corresponding to the Diamante and Nihuiles hydroelectric concessions, they are recorded at cost less amortization and any accumulated impairment losses. Amortization is calculated by the straight-line method according to the useful life, which corresponds to the term of each concession agreement.

4.7.3

Identified intangible assets in acquired investments

Corresponds to intangible assets identified in the moment of the acquisition of companies that meet the criteria established for capitalization less depreciation and less any accumulated impairment. They are amortized by the straight-line method according to the useful life of each asset.

4.7.4

Digital Assets

The Company accounts for digital assets (cryptocurrencies) as intangible assets with indefinite useful life, they are recognised at acquisition cost less any accumulated impairment.

4.8

Impairment of non-financial long-lived assets

Intangible assets that have an indefinite useful life and goodwill are not subject to amortization and are tested annually for impairment, or more frequently if events or changes in circumstances indicate that they might be impaired.

The remaining non-financial long-lived assets are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs of disposal and value in use. For the purpose of assessing the recoverability, assets are grouped at the lowest levels for which there are separately identifiable cash flows which are largely independent of the cash inflows from other assets or groups of assets (CGU).

Non-financial long-lived assets, other than goodwill, that have been impaired are reviewed for possible reversal of the impairment at the end of each reporting period.

4.9

Leases

In leases where the Company acts as a Lesee (Note 19.1), a right-of-use asset and a lease liability are recognized on the date on which the leased asset is available for use by the Company.

The lease liability at inception corresponds to the value of the unpaid lease payments discounted using the Company’s incremental borrowing rate. The finance cost is charged to income over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period. The lease liability is included within “Trade and other payables”.

F- 45

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

The right-of-use asset is measured at cost, which comprises the amount of the initial measurement of the lease liability considering advances net of incentives received, initial direct costs and estimated expenditures to dismantle or restore the underlying asset, if applicable. Right-of-use assets are depreciated using the straight-line method over the asset’s useful life or, if shorter, during the term of the lease.

The Company recognizes short-term lease payments (up to 12 months) and leases in which the underlying asset is a low-value asset (IT equipment and office supplies) as an expense using the straight-line method over the term of the lease.

Leases in which the Company, as a lessor, has transferred all risks and rewards incidental to ownership are classified as financial leases (Note 19.2.1). Financial leases are recognized at the beginning of the lease at the fair value of the leased property or, if lower, the present value of the minimum lease payments to be received. The corresponding lease rights, net of financial charges, are included in “Trade and other receivables”. Financial income is recognized as a profit over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period.

Leases in which the Company, as a lessor, has retained a significant portion of the risks and rewards of ownership are classified as operating leases. Revenues from associated leases are recognized in income on a straight-line basis over the term of the lease (Note 19.2.2). The respective leased assets are included in the Consolidated Statement of Financial Position in view of their nature.

4.10

Financial instruments

Based on the entity’s business model for managing the financial assets and the contractual cash flow characteristics, the Group classifies its financial assets in the following categories:

(i)

Financial assets that are subsequently measured at fair value through profit or loss: they are initially recognized at fair value, transaction costs incurred are expensed and changes in fair value are recognized in “Financial results” in the statement of comprehensive income; and

(ii)

Financial assets that are subsequently measured at amortized cost: they are initially recognized at fair value plus costs directly attributable to the acquisition of instruments, and are subsequently measured at amortized cost using the effective interest rate method less any impairment loss.

Conventional purchases and sales of financial assets are recorded on the settlement date.

The Company subsequently measures all investments in equity instruments at fair value through profit or loss. Dividends from these investments are recognized in the income statement.

The company reclassifies financial assets when and only when it changes its business model for managing those financial assets.

Financial assets are derecognized when contractual rights to the cash flows from the assets have expired or been transferred, and the Company has substantially transferred all risks and rewards of asset ownership.

Financial liabilities are initially recognized at fair value less transaction costs incurred and are subsequently measured at amortized cost using the effective interest rate method.

F- 46

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

If a debt contract is amended or swapped, the Company records the cancellation of the original liability, and recognizes a new financial liability if the new conditions are substantially different from the original ones. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the reporting period.

General and specific borrowing costs that are directly attributable to the acquisition, construction or assembly of an asset that necessarily requires a substantial or prolonged period to prepare for its intended use are capitalized during that period. The returns from the temporary investment of funds from specific borrowings pending disbursement in eligible assets are deducted from the borrowing costs for capitalization.

Any other borrowing costs are recorded in the income statement for the period in which they are incurred under “Financial results” in the statement of comprehensive income.

Financial liabilities are derecognized in the event of extinction, that is, when the obligation has been paid, canceled or has expired.

Financial assets and liabilities are offset when there is a legally enforceable right to offset the recognized amounts, and there is an intention to pay on a net basis, or to realize the asset and settle the liability simultaneously.

4.10.1

Impairment of financial assets

The Company assesses the expected credit losses related to its financial instruments at amortized cost.

The Company applies the simplified approach allowed by IFRS 9 to measure expected credit losses for trade receivables and other receivables with similar risk characteristics. For this purpose, receivables are grouped by business segment and based on shared credit risk characteristics and expected credit losses are determined based on rates calculated for different ranges of default days from the due date.

The expected loss rates are based on the sales collection profiles over a period of 24 months before the end of each year, considering historical credit losses experienced within this period that are adjusted, if applicable, to reflect forward-looking information that could affect the ability of customers to settle the receivables.

When applicable, provisions for impairment on tax credits have been recognised based on estimates on their uncollectibility within their statutory limitation period, taking into consideration the Company’s current business plans.

4.10.2

Derivative financial instruments and hedging accounts

Derivative financial instruments are recorded at their fair value, determined on the basis of the cash value to be collected or payable required to settle the instrument at the measurement date, net of advances collected or paid. The accounting for subsequent changes in fair value depends on whether the derivative is designated as a hedging instrument and, if so, the nature of the item being hedged.

F- 47

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

During 2025, the Company entered into crude oil forward sales contracts without physical delivery and designated a portion of those derivative financial instruments as cash flow hedges.

Gains or losses on the effective portion of the hedging instrument are recognized in other comprehensive income (cash flow hedge reserve), and any remaining gain or loss is recognized in profit or loss for the year.

The cash flow hedge reserve is included in the initial cost when forecast hedged transactions subsequently result in the recognition of a non-financial asset or liability. If, instead, the expected hedged future cash flows affect profit or loss, the cash flow hedge reserve is reclassified to profit or loss for the year.

4.11

Inventories

This line item includes crude oil stock, raw materials, work in progress and finished products relating to Petrochemicals, Oil and Gas and Generation.

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average price method and includes expenditure incurred in purchases and production and other necessary costs to bring them to their existing location and condition. In case of manufactured products and production in process, the cost includes a portion of indirect production costs, excluding any idle capacity (slack). The net realizable value is the estimated selling price in the ordinary course of business less the estimated cost of completion and the estimated costs to make the sale.

The Company has classified materials and spare parts into current and non-current, depending on the timing in which they are expected to be used for replacement or improvement on existing assets. The portion of materials and spare parts for maintenance or improvements on existing assets, is exposed under the heading “Property, plant and equipment”.

4.12

Cash and cash equivalents

Corresponds to cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. If any, bank overdrafts are shown within borrowings in current liabilities, and there are not disclosed under Cash and cash equivalents in the Consolidated Statement of Cash Flows since they are not part of the Company’s cash management.

4.13

Shareholder´s equity

Equity’s movements accounted for in accordance with the pertinent decisions of shareholders' meetings and legal or regulatory standards.

All equity accounts were restated in terms of the current measurement unit until the functional currency changeover date (January 1, 2019). The adjustment resulting from the restatement of the accounts Share capital and Treasury shares held until December 31, 2018 is disclosed in the Comprehensive share capital adjustment and Comprehensive treasury shares adjustment lines, respectively.

F- 48

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Share capital represents the capital issued, composed of the contributions that were committed and/or made by the shareholders and represented by shares that comprise outstanding shares at nominal value.

Share premium includes:

(i)

The portion of the collected price exceeding the face value of the shares issued by the Company, net of absorbed accumulated losses.

(ii)

The difference between the fair value of the consideration paid/collected and the accounting value of the equity interest in the subsidiary acquired/sold/diluted which does not represent a loss of control; and

(iii)

The difference between the proportional equity value registered before the merger of the subsidiary and the value resulting from applying to the subsidiary’s merged equity interest, the new ownership share resulting from the exchange relationship.

In accordance with the LGS, 5% of the profit arising from the statement of income for the year, prior years' adjustments, the translation differences which are directly accumulated in Retained earnings (see Note 4.3.4), the amounts transferred from other comprehensive income and prior years' accumulated losses, must be appropriated to a legal reserve until such reserve equals 20% of the Company’s share capital and the related adjustment of share capital. When for any reason, the amount of this reserve is reduced, dividends may not be distributed, until such amount is reached.

The voluntary reserve corresponds to retained earnings as allocated by the Shareholders’ Meeting.

Other reserves correspond to the result of transactions with non-controlling interests that do not result in a loss of control and reserves for stock compensation plans.

Retained earnings comprise the profit or loss of the year, the prior year’s retained and undistributed earnings, those transferred from other comprehensive income, prior years’ adjustments by application of IFRS’ Accounting Standards and translation differences appropriated to retained earnings in accordance with the policy described in Note 4.3.4

Other comprehensive income includes gains and losses from the remeasurement process of foreign operations and the translation differences which are not classified and directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4, actuarial gains and losses for defined benefit plans, gains or losses on the effective portion of the hedging instrument and the related tax effect.

The distribution of dividends to the Company’s shareholders is recognized as a liability in the year in which the dividends are approved by the Shareholders’ Meeting. The distribution of dividends is made based on the Company’s Stand-Alone Financial Statements, which are presented in pesos, the legal currency in Argentina, pursuant to regulatory requirements.

F- 49

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.14

Compensation plans

4.14.1

Compensations payable in cash:

Corresponds to compensation agreements – senior management: fixed compensation and annual, variable and contingent long-term compensation established based on the Company’s annual market value appreciation, with a payment cap calculated over the Company’s adjusted operating income. Any analogous compensation paid to senior managers is deducted from the compensation amount.

The reasonable value of the received services is measured through a share appreciation estimate using the Monte Carlo simulation model. The fair value of the amount payable is accrued and acknowledged as an expense, with the corresponding increase in liabilities. Liabilities are revalued on each balance sheet date. Any change in the fair value of liabilities is disclosed under profit or loss.

4.14.2

Compensations payable in shares:

Corresponds to stock compensation plan by which certain officers and other key staff receive a certain number of the Company’s shares.

The number of shares for each eligible employee is calculated as from a percentage over the total annual remuneration, including the bonus, divided by the weighted average price, in pesos, of the Company’s share and ADR for the same period; with one-third vesting each year, which will be awarded together with the payroll for April of the year following the vesting date, with the requirement that the employment relationship continues at least until each vesting date. The fair value of the received services is measured at the fair value of the shares at the time of granting and is disclosed during the vesting period, together with the corresponding increase in equity.

4.15

Defined benefit plans

Defined benefit plans define an amount of pension benefit that an employee will receive on retirement, depending on one or more factors, such as age, years of service and compensation. In accordance with conditions established in each plan, the benefit may consist in a single payment, or in making complementary payments to those made by the pension system.

The defined benefit liability recognised in the financial statement balance sheet, at the end of the reporting period, is the present value of the defined benefit obligation net of the fair value of the plan assets, when applicable. The defined benefit obligation is calculated annually by independent actuaries using the projected unit credit method. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using future actuarial assumptions about demographic and financial variables that affect the determination of the amount of such benefits.

Actuarial gains and losses from experience adjustments and changes in actuarial assumptions, are recognised in other comprehensive income (loss) in the period in which they arise and past service costs are recognised immediately in the statement of income (loss).

F- 50

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.16

Provisions, contingent liabilities and contingent assets

Provisions are recognized when the Company has a present obligation as a result of a past event, an outflow of resources will probably be required to settle it, and a reliable estimate of the amount can be made. They are measured at the present value of the disbursements expected to settle the obligation, taking into account the best information available at the date of preparation of the financial statements, based on assumptions and methods considered appropriate and taking into consideration the opinion of the Company’s legal advisors. Estimates are reviewed and adjusted periodically as additional information is obtained by the Company. The increase in provisions generated by the passage of time is recognized within other financial results.

Contingent liabilities are possible obligations, arising from past events, which existence is subject to the occurrence of uncertain future events not wholly within the control of the Company; or present obligations for which settlement an outflow of resources is not likely to be required or which amount cannot be measured with sufficient reliability. They are not recognized, but information regarding the nature of material contingent liabilities is disclosed in the note.

Contingent liabilities for which the possibility of an eventual outflow of resources for settlement is remote are not disclosed, unless they involve guarantees.

Contingent assets are assets of a possible nature, arising from past events, which existence will be confirmed only by the occurrence or non-occurrence of uncertain future events, which are not entirely within the control of the Company. They are not recognized, but information regarding the nature of material contingent assets is disclosed in the note when the inflow of related economic benefits is deemed probable.

4.17

Revenue from contracts with customers

4.17.1

Oil and gas segment

The Company recognizes revenue from the sale of oil and gas to third parties or other segments when control of the product is transferred, that is, at the output of each area, when the oil and gas is delivered to the carrier and to the extent there is no unfulfilled obligation that may affect the acceptance of the product by the purchaser. Revenues from these sales are recognized based on the price per product specified in each contract, to the extent that it is highly probable that there will be no significant reversal.

Revenues are not adjusted for the effect of financing components as sales are made with an average term of 45 days, in line with market practice.

F- 51

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.17.2

Generation segment

4.17.2.1 Revenues from the sale of energy to the spot market

The Company recognizes revenues from: i) available capacity, as the various power plants are available to generate during the scheduled hours; and ii) generated energy, when energy is actually delivered, based on the applicable price formulas according to each power plant’s energy source. Revenues are not adjusted for the effect of financing components as sales are made with an average term of 47 days, in line with market practices.

4.17.2.2 Revenues from contracts with CAMMESA

The Company recognizes revenues from supply contracts with CAMMESA for: i) monthly power capacity availability, if applicable, as the different plants are available to generate and ii) generated energy when the energy is actually delivered, based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales are made with an average term of 47 days, in line with market practice.

4.17.2.3 Revenues from contracts with the MAT

The Company recognizes revenues from the sale of energy (including plus and renewable energy) upon actual delivery of the energy at the price established in each contract. Revenues are not adjusted for the effect of financing components as sales are made with an average term of 27 days, in line with market practice.

4.17.3 Petrochemical segment

The Company recognizes revenues from the sale of petrochemical products, whether in local or foreign markets, when the control of the product is transferred, that is, when the products are delivered to the client and there is no unfulfilled obligation that could affect the acceptance of the product by the client. The delivery, as established in each contract, is occurs:

(i)	when the products are dispatched and transported by and in charge of the client, or,

(ii)	when the products have been dispatched by the Company to a specific location, the obsolescence risks and loss have been transferred to the client, and the client has accepted the, or when the Company has objective evidence that all acceptance criteria have been met.

Revenues from these sales are recognised based on the price specified in each contract, to the extent that it is highly probable that a significant reversal will not occur. Revenues are not adjusted for the effect of financing components as sales are made with an average term of 26 days, which is consistent with market practice.

F- 52

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.17.4 Holding, Transportation and Others segment

The Company recognizes revenues from contracts with customers in relation to advisory services to related companies as services are rendered based on the price established in each agreement. Revenues are not adjusted for the effect of financing components, as sales are made with an average credit term of 30 days, which is consistent with market practice.

4.18

Other Income

4.18.1

GasAr Plan

The Company recognizes price complement revenues under the GasAr Plan, with the actual delivery of the gas and based on the price established in the respective regulation, only to the extent that it is highly probable that no significant reversal will occur and that it is probable that the consideration will be received, that is, to the extent that the procedure defined by the Government is formally complied with.

These revenues fall within the scope of IAS 20 since they involve compensation as a consequence of the maintenance or increase in the committed production volume and are shown under the caption other operating income in the statement of comprehensive income. Furthermore, the associated fiscal costs are disclosed under other operating expenses in the consolidated statement of comprehensive income.

4.18.2

Interest

Interest income from financial assets at fair value through profit or loss is included into the result of changes in the fair value of those assets. Interest income from financial assets at amortized are recognised in the statement of income.

Interest income is calculated by using the effective interest rate to the gross carrying amount of a financial asset (without considering impairment provision), except for impaired financial assets, that is calculated by applying the effective interest rate to the carrying amount net of impairment provision.

Commercial interest corresponding to late payment surcharges in the cancellation of sales receivables is disclosed under Other operating income as it provides relevant information on the business’ operations and operating flows.

4.19

Income tax

The tax expenses for the year include current and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in other comprehensive income or directly in equity.

The current income tax charge is calculated on the basis of the tax laws. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions, where appropriate, on the basis of amounts expected to be paid to the tax authorities.

F- 53

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Deferred income tax is recognised, using the liability method on temporary differences between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax assets are recognised only to the extent that it is probable that future taxable profit will be available and can be used against temporary differences.

Deferred income tax is provided on temporary differences from investments in subsidiaries, joint ventures and associates, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the group and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred assets or liabilities are recognised on account of gains or losses from fiscal tax inflation which, pursuant to Law No. 27,541 and No 27,701, are deferred and accounted for in subsequent fiscal periods.

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset the recognised amounts and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

Current and deferred tax assets and liabilities are stated at their nominal value.

Deferred tax assets and liabilities are measured using the tax rates expected to apply in the period when the asset is realized or the liability is settled.

Finally, receivables have been disclosed on account of the application of the minimum presumed income tax prior to its abrogation as from January 1, 2019, which are computable as an advance payment of income tax in any of the following ten years.

The Company’s management evaluates the recoverability of the recorded receivables at the closing of each fiscal year, and allowances are created as long as it is estimated that the computable amounts will not be recoverable within the statutory limitation period taking into consideration the Company’s current business plans.

F- 54

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: GROUP STRUCTURE

5.1

Interest in subsidiaries, associates and joint ventures

5.1.1 Subsidiaries information

Unless otherwise indicated, the country of the registered office is also the principal place where the subsidiary develops its activities.

Schedule of subsidiaries information
			12.31.2025	12.31.2024
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Autotrol Renovables S.A.	Argentina	Generation	100.00%	100.00%
Ecuador Pipeline Holdings Limited	Gran Cayman	Investment	100.00%	100.00%
EISA	Uruguay	Investment	100.00%	100.00%
Enecor S.A.	Argentina	Electricity transportation	70.00%	70.00%
Fideicomiso CIESA	Argentina	Investment	100.00%	100.00%
GASA	Argentina	Investment	100.00%	100.00%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
OCP	Gran Cayman	Investment	100.00%	100.00%
Pampa Ecuador Inc	Nevis Island	Investment	100.00%	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PECSA	Chile	Trader	100.00%	100.00%
PESOSA	Argentina	Trader	100.00%	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
PB18	Ecuador	Oil	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
VAR	Argentina	Generation	100.00%	100.00%
Vientos Solutions Argentina S.A.U.	Argentina	Advisory services	100.00%	100.00%

F- 55

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.1.2 Information about investments in associates and joint ventures

The following table presents the main activity and financial information used for valuation and percentages of participation in associates and joint ventures; unless otherwise indicated, the share capital consists of millions of common shares, each granting the right to one vote:


		Information about the issuer
	Main activity	Date	Share capital	Profit (Loss) of the period	Equity	Direct and indirect participation %
Associates
SESA	Gas treatment	12.31.2025	1.00	(7)	60	20.00%
VMOS	Hydrocarbon transportation	12.31.2025	115.00	(52)	301	10.20%

Joint ventures
CIESA ⁽¹⁾	Investment	12.31.2025	0.44	152	1,159	50.00%
Citelec ⁽²⁾	Investment	12.31.2025	0.38	69	312	50.00%
CTB	Generation	12.31.2025	6.00	25	484	50.00%

⁽¹⁾

The Company holds a 50% interest in CIESA, a company that holds a 53.83% interest in TGS’s capital stock; therefore, the Company has a 26.91% indirect interest in TGS.

As of December 31, 2025, TGS’s common shares and ADR traded on the BCBA and NYSE were listed at $ 9,325.00 and US$ 31.09, respectively, giving Pampa’s holding an approximate market value of US$ 1,260 million ($ 1,889,210 million).

⁽²⁾

The Company has 50% interest in Citelec, a company that holds a 52.65% interest in Transener’s capital stock; therefore, the Company has a 26.33% indirect interest in Transener. As of December 31, 2025, Transener’s common share price listed at the BCBA was $ 3,577.50, conferring Pampa’s indirect holding an approximate market value of US$ 287.8 million ($ 418,783 million).

F- 56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The details of the balances of investments in associates and joint ventures are as follows:


	12.31.2025	12.31.2024
Disclosed in non-current assets
Associates
VMOS	31	-
SESA	12	-
Total associates	43	-
Joint ventures
CIESA	618	605
Citelec	156	158
CTB	242	230
Total joint ventures	1,016	993
Total associates and joint ventures	1,059	993

The following tables show the breakdown of the share of profit from associates and joint ventures:


	12.31.2025	12.31.2024	12.31.2023
Associates
OCP	-	-	5
SESA	3	-	-
TGS	-	1	3
VMOS	(5)	-	-
Total associates	(2)	1	8

Joint ventures
CIESA	97	89	6
Citelec	35	18	2
CTB	12	(21)	(18)
OCP	-	59	-
Total joint ventures	144	145	(10)
Total associates and joint ventures	142	146	(2)

F- 57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The evolution of investments in associates and joint ventures is as follows:


	12.31.2025	12.31.2024	12.31.2023
At the beginning of the year	993	672	902
Dividends	(70)	(8)	-
Increases	1	39	1
Capital contribution	44	-	-
Share repurchase	-	(37)	-
Sale of equity interests	-	(38)	(58)
Decrease due to obtained control	-	(76)	-
Profit from sale/acquisition of equity interest	-	16	3
Share of profit (loss)	142	146	(2)
Exchange differences on translation	(51)	279	(174)
At the end of the year	1,059	993	672

5.1.3 OCP

Pursuant to the terms and conditions of the crude oil transportation concession authorization agreement in Ecuador, OCP caused OCPSA to establish two guarantees, one operational and one environmental, each in the amount of US$ 50 million (including surety bonds provided by the Group as a shareholder in the amount of US$ 84 million), which would remain in effect for the term of the agreement and until 90 days after its termination on November 30, 2024. Therefore, the guarantees were scheduled to expire on March 1, 2025, since as of that date, no claim had been initiated that could be considered covered within their scope. However, Citibank Ecuador informed OCP that the guarantees had not expired because OCPSA had not complied with certain required formalities.

On April 11, 2025, OCP filed an arbitration proceeding before the ICSID seeking the effective release of the guarantees and compensation for the sustained damages and, subsidiarily, to receive from Ecuador the amount of the guarantees plus interest and sustained damages.

On October 28, 2025, the Ecuadorian Government 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 guarantee deposits funds.

On November 14, 2025, OCP requested the Arbitration Court to discontinue the arbitration, and the Ecuadorian Government granted its consent on December 15, 2025. On January 23, 2026, the Arbitration Court signed the order discontinuing the proceeding and, consequently, the arbitration was terminated.

F- 58

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.1.4 CIESA - TGS

Perito Moreno Gas Pipeline (GPM) Expansion

On May 22, 2025, ENARSA launched a call for tenders to expand the GPM, aiming to increase by 14 MMm³/d the natural gas transportation capacity of the Tratayén–Salliqueló Section by assigning such capacity to the awardee for a term of 15 years, including the operation and maintenance of the pipeline and related infrastructure. The award to TGS was approved by the SE on October 17, 2025.

In addition, TGS undertook to carry out a complementary expansion in the final sections of its licensed system to meet the project’s objectives.

The works provide for an execution period finishing on April 30, 2027.

On October 26, 2025, an application was filed for adherence to the RIGI for ‘Transportadora de Gas del Sur S.A. – Dedicated Branch 1’, which will operate for the sole purpose of executing and operating the GPM expansion project. As of the issuance of these Consolidated Financial Statements, the enforcement authority has not issued a decision.

Issuance of Class 4 CB

On November 20, 2025, TGS issued Class 4 CB with a face value of US$ 500 million, bearing an annual 7.75% fixed interest rate and maturing on November 20, 2035.

Net proceeds, after issue discount, amounted to US$ 491.5 million, and will be used for general corporate purposes, including the GPM and the final sections of TGS’s transportation system expansion.

Weather event

On March 7, 2025, a weather event occurred in the city of Bahía Blanca, characterized by intense rainfall that caused the Saladillo García stream to overflow, flooding the Cerri Complex and affecting the electricity distribution system and the power generation facilities.

Consequently, liquid production at the Cerri Complex was completely interrupted until the end of April 2025, and natural gas transportation service was partially affected. During the fiscal year ended December 31, 2025, TGS recorded a $ 54,281 million loss for event-related expenses and received $ 3,307 million from insurance companies as an advance payment on account of the final settlement of the claim.

F- 59

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.1.5 SESA

FLNG Project

SESA will develop the FLNG Project, a gas liquefaction project which includes the installation of two liquefaction vessels (Hilli and MKII) in the Gulf of San Matías, province of Río Negro, and the construction of all ancillary and related facilities. Both vessels will have a processing and export capacity of approximately 6 million tons per year of LNG, equivalent to 27 million m³/day of natural gas, which will position Argentina in the global LNG market and represent an approximate US$ 7,000 million investment over the project’s 20-year operating term. Operations of the Hilli and the MKII vessels are expected to commence in late 2027 and 2028, respectively.

To supply the vessels with natural gas, SESA entered into 20-year natural gas supply agreements with the Company, Pan American Energy, S.L., Sur Inversiones Energéticas S.A.U. and Wintershall DEA Argentina S.A., in connection with their participation in SESA. In this regard, for both vessels to be able to operate year-round, SESA contemplates the construction of a dedicated gas pipeline from the province of Neuquén to the Gulf of San Matías, in Río Negro.

On April 24, 2025, through SE Resolution No. 165/25, SESA was granted the certificate authorizing the free export of the LNG volumes to be produced by the Hilli over a 30-year term starting on July 1, 2027, and on August 25, 2025, through SE Resolution No. 353/25, it was granted authorization to freely export the LNG volumes to be produced by the MKII for a 30-year term starting on September 1, 2028.

MECON Resolution No. 559/25 approved SESA’s adherence to the RIGI, effective April 28, 2025, in connection with the development of the project involving the deployment of the Hilli vessel, and, through Note NO-2025-112641573-APN-MEC, dated October 9, 2025, MECON informed SESA of the expansion of the RIGI project to include the MKII vessel.

5.1.6 VMOS

Vaca Muerta Sur Project

VMOS will develop the Vaca Muerta Sur project, consisting of the construction, development and operation of an approximately 437-km long pipeline from Allen to Punta Colorada, province of Río Negro, with a capacity of up to 550,000 barrels of crude oil per day (“bpd”), expandable up to 700,000 bpd, a loading and unloading terminal equipped with interconnected single-point moorings, a tank farm and other associated ancillary facilities for the transportation, storage, dispatch, shipment and export of crude oil and other liquid products.

The project contemplates an estimated US$ 3,000 million investment, and the first stage of commercial operation is scheduled for the first half of 2027.

On March 21, 2025, MECON Resolution No. 302/25 approved VMOS’s adherence to the RIGI.

F- 60

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

Syndicated international loan

On July 8, 2025, VMOS entered into a syndicated international loan with a consortium of financial institutions for a total amount of US$ 2,000 million to finance the project. The financing has a 5-year term and accrues interest at a rate equal to Term SOFR plus 5.50%. Disbursements may be requested by VMOS on a monthly basis until completion of the works or July 31, 2027, whichever occurs first. As of December 31, 2025, the banks have made disbursements totaling US$ 820 million.

To secure the obligations assumed under the loan, VMOS assigned as collateral its collection rights under the transportation agreements entered into with the initial shippers (including the Company), and each initial shipper entered into a direct agreement with the banks, whereby, among other matters, they acknowledge the assignment of the transportation agreements as collateral.

In addition, proceeds from VMOS’s exports will be credited to an offshore bank account structure administered by a bank acting as collateral agent. Furthermore, a local tariff collateral trust was created, under which the Citibank, N.A. Branch, as trustee, will administer VMOS’s local revenues, as well as funds received from abroad.

In turn, VMOS’s Class A shareholders (including the Company) have executed a fiduciary assignment of their shares as collateral for the financing, which will remain in effect until the works’ completion.

As of December 31, 2025, VMOS has complied with all covenants undertaken under the syndicated loan agreement.

5.2

Operations in oil and gas consortiums

5.2.1 General considerations

The Company is jointly and severally liable with the other participants for meeting the contractual obligations under these arrangements.

The production areas in Argentina are operated pursuant to concession production agreements with free hydrocarbons availability.

For the computable crude oil and natural gas production in Argentina, royalties equivalent to 12% of the wellhead price of crude oil and natural gas are paid. The wellhead price is calculated by deducting freight and other sales-related expenses from the sale price obtained. The aforementioned rate may increase from 3% to 4% depending on the producing jurisdiction and market value of the product.

F- 61

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.2 Oil and gas participation details

As of December 31, 2025, the Company is part of the joint operations and consortiums for the exploration and production of oil and gas as indicated below:


		Participation		Duration Up To
Name	Location	Direct	Operator	Duration Up To

Argentine production
Río Neuquén	Río Negro and Neuquén	31.42% and 33.07%	YPF	2027/2051
Sierra Chata	Neuquén	45.55%	PAMPA	2053
El Mangrullo	Neuquén	100.00%	PAMPA	2053
Aguaragüe	Salta	15.00%	Tecpetrol	2037
Río Limay este (Ex Senillosa) ⁽¹⁾	Neuquén	85.00%	PAMPA	2040
Rincón de Aranda	Neuquén	100.00%	PAMPA	2058
Veta Escondida	Neuquén	55.00%	PAMPA	2027
Rincón del Mangrullo	Neuquén	50.00%	YPF	2052
Los Blancos (ex Chirete) ⁽²⁾	Salta	50.00%	High Luck Group Limited	2045

Argentine exploration
Parva Negra Este ⁽³⁾	Neuquén	85.00%	PAMPA	2027
Las Tacanas Norte	Neuquén	90.00%	PAMPA	2027

⁽¹⁾

In the process of relinquishment.

⁽²⁾

Operator in the process of removal.

⁽³⁾

Through Provincial Executive Order No. 550/25, issued on May 17, 2025, the Province of Neuquen approved a 2-year extension of the evaluation period for the Parva Negra Este area from April 3, 2025 to April 2, 2027.

F- 62

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The assets and liabilities as of December 31, 2025 and 2024 and the production cost for the years ended December 31, 2025, 2024 and 2023 of Joint Operations and Consortiums in which the Company has interests are detailed below:

Schedule of assets and liabilities
	12.31.2025	12.31.2024

Non-current assets	122	151
Current assets	9	13
Total assets	131	164

Non-current Liabilities	40	52
Current Liabilities	21	26
Total liabilities	61	78

	12.31.2025	12.31.2024	12.31.2023

Production cost	91	99	94

It is worth highlighting that the information presented does not include charges recorded by the Company as a member of the Joint Operations and Consortiums.

Assignment of mixed companies in Venezuela

On May 6, 2022, the Company transferred to Integra Petróleo y Gas S.A. (the “Assignee”) all the rights and obligations of the Company for its direct and indirect interest in the capital of the following mixed companies in the Bolivarian Republic of Venezuela: Petroritupano S.A., Petroven-Bras S.A., Petrowayú S.A. and Petrokariña S.A. (the “Mixed Companies”) that exploit four hydrocarbon production areas in that country: Oritupano Leona, La Concepción, Acema and Mata (the “Areas”). As consideration for the assignment, the Assignee will pay to the Company 50% of any payment it obtains, whether monetary or in kind (including, without limitation, an indemnity, compensation, reparation or similar) related to the direct or indirect interest in the Mixed Companies and the Areas. This transaction is subject to the change of control approval by the Minister of Popular Power of Petroleum of the Bolivarian Republic of Venezuela.

As of the date of issuance of these Consolidated Financial Statements, the Company considers contingent the collection right associated with the assignment, in terms of IAS 37, taking into consideration that it is subject to the change of control approval and subsequent collection of payments by the Assignee.

Assignment of interests in the El Tordillo, La Tapera and Puesto Quiroga areas

On October 1, 2025, in connection with the El Tordillo, La Tapera and Puesto Quiroga areas, the Company transferred to Crown Point Energía S.A., on a joint basis: (i) a 35.6706% interest in the hydrocarbon exploitation concessions and hydrocarbon transportation concessions, and (ii) the Joint Operation Agreements for hydrocarbon exploration, development and production. The transaction was completed with the collection of US$ 2 million by the Company.

F- 63

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.3 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2025, 2024 and 2023:

Schedule of exploratory well costs
	12.31.2025	12.31.2024	12.31.2023

At the beginning of the year	18	32	37
Increases	32	6	2
Derecognition of unproductive wells	-	(20)	(7)
At the end of the year	50	18	32
Number of wells at the end of the year	6	4	4

NOTE 6: RISKS

6.1

Critical accounting estimates and judgments

The preparation of financial statements requires the Company’s Management to make future estimates and assessments, to apply critical judgment and to establish assumptions affecting the application of accounting policies and the amounts of disclosed assets and liabilities, income and expenses.

The applied estimates and accounting judgments are evaluated on a continuous basis and are based on past experiences and other reasonable factors under the existing circumstances. Actual future results might differ from the estimates and evaluations made at the date of preparation of these Consolidated Financial Statements. The estimates which have a significant risk of producing adjustments on the amounts of the assets and liabilities during the following year are detailed below:

6.1.1 Impairment of non-financial long-lived assets

Non-financial long-lived assets, including identifiable intangible assets and right-of-use assets, are reviewed for impairment at the lowest level for which there are separately identifiable cash flows (CGU). For this purpose, each assets group with independent cash flows, each associate and each jointly controlled company has been considered a single CGU, as all of their assets jointly contribute to the generation of cash inflows, which are derived from a single service or product; thus cash inflows cannot be attributed to individual assets.

The value in use of each CGU is estimated on the basis of the present value of future net cash flows expected to be derived on the CGU. Management uses approved budgets up to one year as the base for cash flow projections that are later extrapolated into a term consistent with the assets’ remaining useful life, taking into consideration the appropriate discount rates. The discount rates used to discount future net cash flows is the WACC, for each CGU a specific WACC was determined which considered the business segment and the country conditions where the operations are performed. In order to calculate the fair value less the costs of disposal, the Company Management uses the estimated value of the future cash flows that a market participant could generate from the appropriate CGU, less the necessary costs to carry out the sale of the corresponding CGU.

F- 64

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The Company Management is required to make judgments at the moment of the future cash flow estimation. The actual cash flows and the values may differ significantly from the expected future cash flows and the related values obtained through discount techniques.

6.1.2 Current and deferred Income tax

The Company’s Management periodically evaluates tax treatments affecting the determination of taxable profit regarding uncertain tax treatment under tax law considering the acceptability of a particular tax treatment by the relevant taxation authority, and, if applicable, recognizes tax provisions to reflect the effect of the uncertainty for each tax treatment based on the amount estimated to be paid to the tax authorities.

If the final tax resolution regarding uncertain tax treatments differs from recognised figures, such differences will have an effect on income tax and deferred income tax at the year of such determination.

Deferred tax asset is reviewed at each reporting date and reduced in accordance with the probability that the sufficient taxable base will be available to allow and for the total or partial recovery of these assets. In assessing the recoverability of deferred tax assets, Management considers if it is likely that a portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets depends on the generation of future taxable income in the periods in which these temporary differences become deductible. To make this assessment, Management takes into consideration the scheduled reversal of deferred tax liabilities, the projections of future taxable income and tax planning strategies.

The generation of future taxable profits may differ from these estimated affecting the deductibility of deferred tax assets.

6.1.3 Provision for contingencies

Liabilities related to claims, lawsuits and other legal proceedings arising from the Company’s activities cannot be estimated with certainty. The Company analyzes the status of each contingency and assesses the potential financial exposure, applying the criteria indicated in Note 4.16; to such effect, it prepares estimates mainly with the assistance of legal counsel, based on the information available to Management at the date of preparation of the Consolidated Financial Statements, and taking into account the litigation and resolution/settlement strategies.

The final resolutions of the litigation could differ from Management's estimates, generating current provisions to be inadequate, which could have a material adverse effect on the statement of financial position, comprehensive income, changes in equity and cash flows.

6.1.4 Asset retirement obligations and decommissioning of wind turbines

Asset retirement obligations in oil and gas areas after completion of operations require the Company’s Management to estimate the number of wells, long-term well abandonment costs and the time remaining until abandonment.

In the same way, the obligations related to the decommissioning of wind turbines in wind farms require the Company’s Management to estimate long-term dismantling costs and the time remaining until the dismantling.

F- 65

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

Technology, costs and political, environmental and safety considerations constantly change and may result in differences between actual future costs and estimates.

Asset retirement obligations’ and the decommissioning of wind turbines’ estimates are adjusted at least once a year or more frequently if there are changes in the assumptions considered in the assessment.

6.1.5 Impairment of financial assets and other credits

The Group is exposed to losses for uncollectible receivables. The Company Management estimates the final collectability of the accounts receivable.

The accounting of expected credit losses for trade receivables and other receivables with similar risk characteristics is based on the Company's best estimate of the default risk and the calculation of the expected credit losses rates, based on historical information of the behavior of the Company's clients, current market conditions and forward-looking estimates at the end of each reporting period.

In order to estimate collections related to the sale of gas and energy in the spot market and revenues associated with natural gas production promotion plans, the Company mainly considers CAMMESA’s and federal government’s capacity to meet its payment obligations to generators and producers, including the resolutions issued by the SE, which allow the Company to collect its receivables through different mechanisms.

Future adjustments to the allowance may be necessary if future real economic conditions differ substantially from the assumptions used in the assessment for each year.

6.1.6 Actuarial assumptions in defined benefit plans

Commitments with defined benefit plans to employees are recognised as liabilities in the statement of financial position based on actuarial estimates revised annually by an independent actuary, using the projected unit credit method.

The present value of defined benefit pension plan depends on multiple factors that are determined according to actuarial estimates, net of the fair value of the plan assets, when applicable. For this purpose, certain assumptions are used including the discount rate and wage growth rate assumptions. It may be necessary to make adjustments in the future if future real economic conditions materially differ from the assumptions used in the valuation of each year.

6.1.7 Oil and gas reserves

Reserves include oil and gas volumes (in m3 of oil equivalent) that are economically producible, in the areas where the Company operates or has a direct or indirect interest and over which the Company has exploration and exploitation rights.

There are numerous uncertainties in estimating proved and unproved reserves, future production profiles, development costs and prices, including several factors beyond the producer’s control. Reserve engineering is a subjective process of estimating underground accumulations involving a certain degree of uncertainty.

Reserves estimates depend on the quality of the available engineering and geological data as of the estimation date and on the interpretation and judgment thereof.

F- 66

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The Company’s estimates of oil and gas reserves have been developed by the Company’s internal specialists, specifically petroleum engineers, and audited by independent specialists engaged by Company.

The Company uses the information obtained from the calculation of reserves in the determination of depreciation of properties, plant and equipment used in oil and gas areas, as well as assessing the recoverability of these assets and including, when applicable, goodwill allocated to the oil and gas segment (see Notes 4.6 to 4.8).

6.1.8 Fair value of financial assets that are not traded in active markets

The fair value of financial instruments that are not traded in active markets is determined using valuation techniques. These valuation techniques consider estimates based on information available to the Management at Consolidated Financial Statements date, for those significant variables that cannot be observed in the market, including the discount rate, among others.

Future adjustments may be necessary if future real economic conditions differ substantially from the assumptions used in the valuation for each period.

6.2

Financial risk management

6.2.1 Financial Risk Factors

The Company’s activities are subject to several financial risks: market risk (including the exchange rate risk, the interest rate risk and the price risk), credit risk and liquidity risk.

Financial risk management is encompassed within the Company’s global policies, there is an integrated risk management methodology, where the focus is not placed on the individual risks of the business units’ operations, but there is rather a wider perspective focused on monitoring risks affecting the whole portfolio. The Company’s risk management strategy seeks to achieve a balance between profitability targets and risk exposure levels. Financial risks are those derived from financial instruments the Company is exposed to during or at the closing of each fiscal year. The Company uses derivative instruments to hedge certain risks when it deems it necessary according to its risk management internal policies.

Financial risk management is controlled by the Financial Department, which identifies, evaluates and covers financial risks. Risk management systems and policies are reviewed on a regular basis to reflect changes in market conditions and the Company’s activities, and have been applied consistently during the periods included in these Consolidated Financial Statements. This section includes a description of the main risks and uncertainties which may adversely affect the Company’s strategy, performance, operational results and financial position.

6.2.1.1 Market risks

6.2.1.1.1 Foreign exchange risk

The Company’s results of operations and financial position are exposed to changes in the exchange rate between the Company’s functional currency, which is the U.S. dollar and other currencies, primarily with respect to the Argentine peso (which is the legal currency in Argentina). In some cases, the Company may use derivative financial instruments to mitigate the associated exchange rate risk.

F- 67

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

In fiscal year 2025, the U.S. dollar recorded an approximate 41% increase against the Argentine peso, from $ 1,032 in December 2024 to $ 1,455 in December 2025, and the Company recorded net foreign exchange gain in the amount of US$ 29 million as of December 31, 2025. Taking into account the net passive financial position in Argentine pesos as of December 31, 2025, the Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values a increase/(decrease) of US$ 22 million in the fiscal year’s income, before income tax.

The Group´s exposure to other foreign currency movements is not material.

6.2.1.1.2 Price risk

The Company’s investments in financial assets classified as “at fair value through profit or loss” are sensitive to the risk of changes in the market prices resulting from uncertainties as to the future value of such financial assets.

The Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of each active market price would generate the following increase/(decrease) in the fiscal year’s income, before income tax in relation to financial assets at fair value through profit and loss detailed in Note 12.8 to these Consolidated Financial Statements:

Schedule of exposure to the price risk
Financial assets			Increase / decrease of the result for the year 2025
Shares			1
Corporate bonds			5
Government securities			31
Mutual funds			40
Guarantee deposits			14
Variation of the result of the year			91

6.2.1.1.3 Cash flow and fair value interest rate risk

The management of the interest rate risk seeks to reduce financial costs and limit the Company’s exposure to interest rate increases; to this effect, the Company evaluates: (i) different liquidity sources available in the financial and capital markets, both local and international; (ii) different interest rate, currency and maturity alternatives available to companies in the industry with a risk similar to the Company's; and (iii) availability, access and cost of interest rate hedging agreements.

Indebtedness at variable rates exposes the Company to the interest rate risk on its cash flows due to the possible volatility they may experience. Indebtedness at fixed rates exposes the Company to the interest rate risk on the fair value of its liabilities, since they may be considerably higher than variable rates.

As of December 31, 2025, the Company is not exposed to a significant risk of increases in variable interest rates, since all financial debt is at a fixed rate and given current market conditions; the Company considers the risk of a significant drop in interest rates to be low, and therefore does not perceive a substantial risk in its fixed rate indebtedness.

F- 68

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The following table shows the breakdown of the Company’s borrowings classified by interest rate and the currency in which they are denominated:


	12.31.2025	12.31.2024
Fixed interest rate:
U.S. dollar	1,825	1,929
Subtotal loans obtained at a fixed interest rate	1,825	1,929

Floating interest rate:
Argentine pesos	-	17
U.S. dollar	-	20
Subtotal loans obtained at a floating interest rate	-	37

Non interest accrued:
U.S. dollar	67	113
Subtotal loans no interest accrued	67	113
Total borrowings	1,892	2,079

6.2.1.2 Credit risk

The credit risk represents the exposure to possible losses resulting from the breach by commercial or financial counterparties of their obligations taken on with the Company. This risk stems mainly from economic and financial factors or a possible counterparty default.

In the ordinary course of its business, the Company grants credit to a large customer base, mainly different sectors of industry, including petrochemical companies, natural gas distributors and large electricity users, among others. For this purpose and in accordance with its credit policies, it establishes individual credit limits based on internal or external ratings, approved by the Finance Department, and permanently performs credit assessments on its customers’ financial capacity to minimize the potential risk of uncollectibility losses.

As of December 31, 2025, the Company’s trade receivables totaled US$ 355 million and is classified as current. With the exception of CAMMESA, which represents approximately 33% of such trade receivables, the Company does not have a significant credit risk concentration, as this exposure is distributed among a large number of customers and other counterparties.

The impossibility by CAMMESA to pay these receivables may have a substantially adverse effect on cash income and, consequently, on the result of operations and financial situation which, in turn, may adversely affect the Company’s repayment capacity.

F- 69

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The credit risk of liquid funds and other financial investments is limited since the counterparties are high credit quality banking institutions. If there are no independent risk ratings, the Financial Department evaluates the customer’s creditworthiness, based on past experiences and other factors.

The Company applies the simplified approach of IFRS 9 to measure the expected credit losses of trade receivables and other receivables in accordance with the policy described in Note 4.10.

The expected credit loss on trade receivables and financial assets as of December 31, 2025, 2024 and 2023 amounts to US$ 21 million, US$ 1.5 million and US$ 1 million, respectively and was determined based on credit loss rates calculated for days past due detailed below:


12.31.2025	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Oil and Gas	7.10%	11.48%	12.95%	14.83%	23.28%	30.22%	31.23%	38.07%
Generation	0.13%	0.30%	0.97%	1.79%	4.05%	6.95%	15.68%	19.26%
Petrochemicals	0.05%	0.14%	1.01%	3.81%	11.32%	13.07%	15.83%	16.59%
Holding, Transportation and others	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%


12.31.2024	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Oil and Gas	0.01%	0.04%	0.34%	6.25%	19.99%	27.11%	28.79%	37.16%
Generation	0.09%	0.55%	3.70%	8.92%	12.26%	14.78%	16.40%	21.41%
Petrochemicals	0.01%	0.11%	9.50%	17.12%	24.00%	24.24%	24.93%	25.46%
Holding, Transportation and others	0.24%	3.37%	4.49%	12.45%	12.45%	16.67%	16.67%	16.67%


12.31.2023	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Oil and Gas	0.06%	0.30%	2.19%	3.83%	5.06%	10.14%	10.14%	10.21%
Generation	0.32%	1.26%	8.33%	16.63%	20.72%	23.46%	27.00%	28.96%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	28.96%
Holding, Transportation and others	0.18%	1.04%	8.44%	9.09%	9.09%	9.09%	9.09%	9.09%

Finally, although cash, cash equivalents and financial assets are also subject to the impairment requirements of IFRS 9, the identified impairment loss is immaterial.

Allowance of impairment of financial assets and other credits evolution as of December 31, 2025, 2024 and 2023, is detailed in Note 12.3.

The Company’s maximum exposure to credit risk is based on the book value of each financial asset in the Consolidated Financial Statements. On the basis of the change in an assumption, while holding all other assumptions constant, a 5% increase/(decrease) in the estimated trade receivables’ uncollectibility rate would result in US$ 1 million (decrease)/increase in fiscal year’s results, before income tax.

F- 70

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

6.2.1.3 Liquidity risk

The liquidity risk is associated with the Company’s capacity to finance its commitments and conduct its business plans with stable financial sources, as well as with the indebtedness level and the financial debt maturities profile. The cash flow projection is made by the Financial Department.

The Company Management supervises updated projections on liquidity requirements to guarantee the sufficiency of cash and liquid financial instruments to meet operating and financing needs of the Company while keeping at all times a sufficient margin of unused credit facilities. In this way, the aim is that the Company does not breach indebtedness levels or the Covenants, applicable, of any credit facility. Those projections take into consideration the Company’s debt financing plans, the meeting of the covenants and, if applicable, the external regulatory or legal requirements such as, for example, restrictions on the use of foreign currency. Additionally, the Financial Department regularly monitors the available credit for the Company, both in the local and international capital market as well as in the banking sector.

Excess cash and balances above working capital management requirements are managed by the Company’s Treasury Department, which invests them in marketable securities, term deposits and mutual funds, selecting instruments having proper currencies and maturities, and an adequate credit quality and liquidity to meet cash needs estimated in the previously indicated projections.

The Company keeps its sources of financing diversified between banks and the capital market, and it is exposed to the refinancing risk at maturity.

The determination of the Company’s liquidity index for fiscal years ended December 31, 2025 and 2024 is detailed below:

Schedule of liquidity index
	12.31.2025	12.31.2024

Current assets	1,988	2,380
Current liabilities	639	1,302

Liquidity ratio	3.11	1.83

The following table includes an analysis of the Company trade receivables, other receivables and financial liabilities, grouped according to their maturity dates and considering the period remaining until their contractual maturity date from the date of the Consolidated Financial Statements. Derivative financial instruments are included in the analysis if their contractual maturities are essential for the understanding of the cash flow calendar. The amounts shown in the table are the contractual undiscounted cash flows.

F- 71

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)


As of December 31, 2025	Trade and other receivables	Trade and other payables ⁽¹⁾	Borrowings
Less than three months	531	366	45
Three months to one year	26	31	124
One to two years	5	76	240
Two to five years	11	4	593
More than five years	27	6	2,057
Non set maturity term	57	-	-
Total	657	483	3,059



As of December 31, 2024	Trade and other receivables	Trade and other payables ⁽¹⁾	Borrowings
Less than three months	330	237	480
Three months to one year	21	16	334
One to two years	66	75	250
Two to five years	-	4	735
More than five years	-	5	977
Non set maturity term	146	-	-
Total	563	337	2,776

(1)

Includes Lease Liabilities (see Note 19).

6.3

Capital risk management

The aims of managing capital are to safeguard its capacity to continue operating as an on-going business with the purpose of generating return for its shareholders and benefits to other stakeholders, and keeping an optimal capital structure to reduce the cost of capital.

To keep or adjust its capital structure, the Company may adjust the amount of the dividends paid to its shareholders, reimburse capital to its shareholders, issue new shares, conduct stock repurchase programs or sell assets to reduce its debt.

In line with industry practices, the Company monitors its capital based on the leverage ratio. This ratio is calculated by dividing the net debt by the total capital. The net debt equals the total indebtedness (current and non-current) minus cash and cash equivalents and current financial assets at fair value through profit and loss. The total capital corresponds to the shareholders’ equity as shown in the statement of financial position, plus the net debt.

Financial leverage ratios as of December 31, 2025 and 2024 were as follows:

Schedule of financial leverage ratios
	12.31.2025	12.31.2024
Total borrowings	1,892	2,079
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(1,091)	(1,588)
Net debt	801	491
Total capital	4,406	3,786
Leverage ratio	18.18%	12.97%

F- 72

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: SEGMENT INFORMATION

The Company is a fully integrated power company in Argentina, which participates mainly in the production of oil and gas and power generation.

Through its own activities, subsidiaries and share holdings in joint ventures, and based on the business nature, customer portfolio and risks involved, the following business segments have been identified:

Oil and Gas, principally consisting of the Company’s interests in oil and gas areas, the activities of Pampa Energía S.A. - Sucursal Dedicada Midstream RDA and direct and indirect interest in SESA and PECSA.

Generation, principally consisting of the Company’s direct and indirect interests in HINISA, HIDISA, VAR, CTB, TMB, TJSM and through its own electricity generation activities through thermal plants CTG, CPB, Piquirenda, CTLL, CTGEBA, Ecoenergía, CTPP, CTIW, the HPPL hydroelectric complex and PEPE II, PEPE III, PEPE IV and PEPE VI wind farms.

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in local plants.

Holding, Transportation and Others, principally consisting of our stake in joint businesses CITELEC, CIESA and their respective subsidiaries holding the concession over high-voltage electricity transmission and gas transportation, respectively, the direct and indirect interests in VMOS, Oldelval and OCP, holding activities, and other investment activities.

The Company manages its operating segment based on its individual net result in U.S. dollars.

F- 73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2025	Oil and gas	Generation	Petrochemicals	Holding, Transportation and others	Eliminations	Consolidated
Revenue - local market	541	788	265	24	-	1,618
Revenue - foreign market	199	3	178	-	-	380
Intersegment revenue	122	1	-	-	(123)	-
Cost of sales	(613)	(450)	(429)	-	123	(1,369)
Gross profit	249	342	14	24	-	629

Selling expenses	(80)	(4)	(12)	(2)	-	(98)
Administrative expenses	(83)	(42)	(6)	(61)	-	(192)
Other operating income	49	23	19	9	-	100
Other operating expenses	(23)	(11)	(9)	(29)	-	(72)
Recovery of impairment (Impairment) of property, plant and equipment, intangible assets and inventories	(3)	55	(37)	-	-	15
Impairment of financial assets	(21)	-	-	-	-	(21)
Share of profit from associates and joint ventures	3	12	-	127	-	142
Operating income	91	375	(31)	68	-	503

Financial income	-	18	27	-	-	45
Financial costs	(101)	(46)	-	(49)	-	(196)
Other financial results	(35)	168	3	94	-	230
Financial results, net	(136)	140	30	45	-	79
Profit (Loss) before income tax	(45)	515	(1)	113	-	582

Income tax	(10)	(217)	5	18	-	(204)
Profit (Loss) of the year	(55)	298	4	131	-	378

Depreciation and amortization	292	116	6	-	-	414

F- 74

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2025	Oil and gas	Generation	Petrochemicals	Holding, Transportation and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	(55)	297	4	131	-	377
Non-controlling interest	-	1	-	-	-	1


Consolidated financial position information as of December 31, 2025
Assets	2,513	3,046	147	931	(43)	6,594
Liabilities	1,737	668	73	554	(43)	2,989

Net book values of property, plant and equipment ⁽¹⁾	1,896	1,370	-	37	-	3,303

Additional consolidated information as of december 31, 2025
Increases in property, plant and equipment, intangible assets and right-of-use assets	1,039	66	15	12	-	1,132

⁽¹⁾

Assets located in Argentina

F- 75

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2024	Oil and gas	Generation	Petrochemicals	Holding, Transportation and others	Eliminations	Consolidated
Revenue - local market	515	669	326	65	-	1,575
Revenue - foreign market	108	3	190	-	-	301
Intersegment revenue	107	-	-	-	(107)	-
Cost of sales	(515)	(367)	(487)	(17)	107	(1,279)
Gross profit	215	305	29	48	-	597

Selling expenses	(58)	(3)	(13)	-	-	(74)
Administrative expenses	(82)	(52)	(7)	(98)	-	(239)
Exploration expenses	(21)	-	-	-	-	(21)
Other operating income	87	35	41	12	-	175
Other operating expenses	(28)	(14)	(7)	(39)	-	(88)
Impairment of property, plant and equipment, intangible assets and inventories	(34)	-	-	-	-	(34)
Impairment of financial assets	(10)	(46)	-	-	-	(56)
Share of profit from associates and joint ventures	-	(21)	-	167	-	146
Profit from sale of companies´ interest	-	-	-	34	-	34
Operating income	69	204	43	124	-	440

Financial income	2	8	21	1	-	32
Financial costs	(96)	(53)	(3)	(33)	-	(185)
Other financial results	(11)	183	7	32	-	211
Financial results, net	(105)	138	25	-	-	58
Profit (Loss) before income tax	(36)	342	68	124	-	498

Income tax	31	119	4	(33)	-	121
Profit (Loss) of the year	(5)	461	72	91	-	619


Depreciation and amortization	237	100	5	-	-	342

F- 76

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2024	Oil and gas	Generation	Petrochemicals	Holding, Transportation and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	(5)	461	72	91	-	619

Consolidated financial position information as of December 31, 2024
Assets	1,918	3,155	173	1,116	(17)	6,345
Liabilities	1,583	857	109	518	(17)	3,050

Net book values of property, plant and equipment ⁽¹⁾	1,183	1,357	28	39	-	2,607

Additional consolidated information as of December 31, 2024
Increases in property, plant and equipment, intangible assets and right-of-use assets	354	105	6	10	-	475

⁽¹⁾

Assets located in Argentina

F- 77

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2023	Oil and gas	Generation	Petrochemical	Holding, Transportation and others	Eliminations	Consolidated
Revenue - local market	402	648	359	14	-	1,423
Revenue - foreign market	161	-	148	-	-	309
Intersegment revenue	103	-	-	-	(103)	-
Cost of sales	(412)	(354)	(444)	-	103	(1,107)
Gross profit	254	294	63	14	-	625

Selling expenses	(49)	(2)	(15)	-	-	(66)
Administrative expenses	(74)	(50)	(6)	(55)	-	(185)
Exploration expenses	(7)	-	-	-	-	(7)
Other operating income	86	75	13	3	-	177
Other operating expenses	(32)	(27)	(7)	(22)	-	(88)
(Impairment) Recovery of impairment of property, plant and equipment, intangible assets and inventories	(38)	-	(3)	2	-	(39)
Share of profit from associates and joint ventures	-	(18)	-	16	-	(2)
Profit from sale of companies´ interest	-	-	-	9	-	9
Operating income	140	272	45	(33)	-	424

Financial income	2	2	-	7	(6)	5
Financial costs	(203)	(119)	(3)	(45)	6	(364)
Other financial results	(15)	280	15	278	-	558
Financial results, net	(216)	163	12	240	-	199
Profit (Loss) before income tax	(76)	435	57	207	-	623

Income tax	29	(225)	(27)	(95)	-	(318)
Profit (Loss) of the year	(47)	210	30	112	-	305

Depreciation and amortization	166	96	5	-	-	267

F- 78

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 7: (Continuation)


	in million of US$
Consolidated profit and loss information for the year ended December 31, 2023	Oil and gas	Generation	Petrochemical	Holding, Transportation and others	Eliminations	Consolidated
Total profit of the year attributable to:
Owners of the company	(47)	207	30	112	-	302
Non-controlling interest	-	3	-	-	-	3




Consolidated financial position information as of December 31, 2023
Assets	1,396	2,684	157	631	(146)	4,722
Liabilities	1,213	729	137	376	(146)	2,309

Net book values of property, plant and equipment ⁽¹⁾	1,138	1,345	27	34	-	2,544

Additional consolidated information as of December 31, 2023
Increases in property, plant and equipment and right-of-use assets	556	259	7	5	-	827

⁽¹⁾

Assets located in Argentina

F- 79

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 8: REVENUE

Schedule of revenue
	12.31.2025	12.31.2024	12.31.2023

Gas sales	463	485	432
Oil sales	267	127	121
Other sales	10	11	10
Oil and gas sales subtotal	740	623	563

Energy sales in Spot Market	281	206	196
Energy sales by supply contracts	380	356	363
Fuel supply	121	102	87
Other sales	9	8	2
Generation sales subtotal	791	672	648

Products from catalytic reforming sales	251	277	217
Styrene sales	59	71	79
Synthetic rubber sales	69	83	78
Polystyrene sales	63	83	131
Other sales	1	2	2
Petrochemicals sales subtotal	443	516	507

Technical assistance and administration services sales	24	25	14
Other sales	-	40	-
Holding, Transportation and others subtotal	24	65	14
Total revenue ^{(1) (2)}	1,998	1,876	1,732

⁽¹⁾

Revenues from CAMMESA represent 34%, 31% and 33% of total revenues for the fiscal years ended December 31, 2025, 2024 and 2023, respectively, and correspond mainly to the Oil & Gas and Generation segments.

⁽²⁾

Including US$ 14.9 million, US$ 8.7 million and US$ 13.1 million in the Oil and gas segment and US$ 8.8 million, US$ 10.1 million and US$ 8.2 million in the Petrochemical segment corresponding to export duties for the years ended December 31, 2025, 2024 and 2023, respectively.

F- 80

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 9: COST OF SALES

Schedule of cost of sales
	12.31.2025	12.31.2024	12.31.2023
Inventories at the beginning of the year	223	205	173

Plus: Charges of the year
Purchases of inventories, energy and gas	410	450	411
Salaries and social security charges	87	90	85
Employees benefits	13	19	17
Defined benefit plans	3	8	8
Works contracts, fees and compensation for services	149	128	111
Property, plant and equipment depreciation	384	328	254
Intangible assets amortization	4	4	5
Right-of-use assets amortization	17	2	1
Energy transportation	14	12	9
Transportation and freights	45	21	20
Consumption of materials	29	28	27
Penalties	2	1	2
Maintenance	62	61	47
Canons and royalties	112	97	92
Environmental control	5	6	4
Rental and insurance	23	27	31
Surveillance and security	8	6	5
Taxes, rates and contributions	5	6	7
Other	5	3	3
Total charges of the year	1,377	1,297	1,139

Less: Inventories at the end of the year	(231)	(223)	(205)
Total cost of sales	1,369	1,279	1,107

F- 81

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

Schedule of selling expenses
	12.31.2025	12.31.2024	12.31.2023
Salaries and social security charges	5	5	5
Employees benefits	-	1	1
Fees and compensation for services	2	3	3
Taxes, rates and contributions	21	15	13
Transportation and freights	68	49	43
Other	2	1	1
Total selling expenses	98	74	66

10.2 Administrative expenses

Schedule of administrative expenses
	12.31.2025	12.31.2024	12.31.2023
Salaries and social security charges	65	64	58
Employees benefits	8	11	10
Defined benefit plans	8	19	18
Fees and compensation for services	54	39	29
Compensation agreements	14	61	37
Directors' and Syndics' fees	6	6	7
Property, plant and equipment depreciation	9	8	7
Maintenance	3	3	2
Transport and per diem	2	2	2
Rental and insurance	1	3	1
Surveillance and security	1	2	1
Taxes, rates and contributions	14	14	8
Communications	1	1	1
Other	6	6	4
Total administrative expenses	192	239	185

10.3 Exploration expenses

Schedule of exploration expenses
	12.31.2025	12.31.2024	12.31.2023
Geological and geophysical expenses	-	1	-
Derecognition of unproductive wells	-	20	7
Total exploration expenses	-	21	7

F- 82

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation)

10.4 Other operating income and expenses


	12.31.2025	12.31.2024	12.31.2023
Other operating income
Insurance recovery	21	7	1
Results for property, plant and equipment sale	-	11	1
Results for intangibles assets sale	5	-	-
Results for other assets sale	1	-	-
Services provided to third parties	-	-	1
Recovery of provision for contingencies	17	30	-
Expenses recovery	-	-	8
Commercial interests	14	50	70
Contractual indemnity	-	-	7
GasAr Plan	34	44	55
Export Increase Program	2	19	24
Fair value of consortiums' previous interest	-	-	7
Other	6	14	3
Total other operating income	100	175	177

Other operating expenses
Provision for contingencies	(14)	(36)	(8)
Provision for environmental remediation	(7)	(3)	(4)
Results for property, plant and equipment sale and derecognition	-	-	(2)
Results for other assets sale and derecognition	(1)	-	-
Tax on bank transactions	(24)	(19)	(18)
PAIS import tax	-	(3)	(5)
Donations and contributions	(3)	(3)	(3)
Institutional promotion	(2)	(2)	(4)
Costs of concessions agreements completion	(1)	(6)	(5)
Contractual penalty	-	-	(7)
Royalties GasAr Plan	(5)	(6)	(8)
Incident costs	(5)	-	-
Ecuador's transactional agreement	-	-	(5)
Impairment of other receivables	-	-	(5)
Other contractual expenses	-	-	(6)
Other	(10)	(10)	(8)
Total other operating expenses	(72)	(88)	(88)

F- 83

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation)

10.5 Financial results

Schedule of financial assets
	12.31.2025	12.31.2024	12.31.2023
Financial income
Financial interests	17	9	2
Other interests	28	23	3
Total financial income	45	32	5

Financial costs
Financial interests ⁽¹⁾	(139)	(145)	(304)
Commercial interests	-	(1)	(1)
Fiscal interests	(50)	(28)	(47)
Other interests	-	(6)	(4)
Bank and other financial expenses	(7)	(5)	(8)
Total financial costs	(196)	(185)	(364)

Other financial results
Foreign currency exchange difference, net	29	(11)	123
Changes in the fair value of financial instruments	202	239	444
Result from present value measurement	(3)	(7)	(10)
Result from repurchase of CB	2	(10)	1
Total other financial results	230	211	558
Total financial results, net	79	58	199

⁽¹⁾

Net of US$ 6 million, US$ 8 million and US$ 21 million capitalized in property, plant and equipment for the years ended December 31, 2025, 2024 and 2023, respectively.

F- 84

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation)

10.6 Income tax

The breakdown of income tax charge is:

Schedule of income tax benefit expense
	12.31.2025	12.31.2024	12.31.2023
Current tax	97	280	19
Deferred tax	105	(405)	272
Difference between previous fiscal year income tax provision and the income tax statement	2	4	27
Total income tax - Loss (Profit)	204	(121)	318

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:


	12.31.2025	12.31.2024	12.31.2023
Profit before income tax	582	498	623
Current income tax rate	35%	35%	35%
Income tax at the statutory tax rate	204	174	218
Share of profit from companies	(50)	(52)	1
Non-taxable results	(5)	(4)	(17)
Effects of exchange differences and other results associated with the valuation of the currency, net	269	136	752
Effects of valuation of property, plant and equipment, intangible assets and financial assets	(325)	(737)	(1,146)
Difference between income and deferred tax provision and the income tax statement	3	18	3
Effect for tax inflation adjustment	104	346	501
Non-deductible cost	5	-	9
Recovery of impairment on deferred assets	-	-	(3)
Other	(1)	(2)	-
Total income tax - Loss (Profit)	204	(121)	318

F- 85

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: NON-FINANCIAL ASSETS AND LIABILITIES

11.1 Property, plant and equipment


	Original values
Type of good	At the beginning	Increases ⁽¹⁾	Increases for incorporation	Transfers	Decreases	(Impairment) / Recovery	At the end


Lands	14	-	-	-	-	(3)	11
Buildings	204	-	-	2	-	(28)	178
Vehicles	11	1	-	-	(1)	(1)	10
Furniture and fixtures, tools and software and communication equipment	44	4	-	10	(3)	(1)	54
Thermal generation plants	1,091	-	-	117	-	80	1,288
Renewable generation plants	686	1	-	24	-	-	711
Petrochemical plants	42	5	-	5	-	(52)	-
Mining property, wells and drilling equipment	1,962	14	-	594	(14)	(2)	2,554
Drilling and work in progress	335	1,059	-	(752)	(2)	(9)	631
Other goods	1	-	-	-	-	-	1
Total at 12.31.2025	4,390	1,084	-	-	(20)	(16)	5,438
Total at 12.31.2024	4,169	472	3	-	(99)	(155)	4,390

⁽¹⁾

Includes US$ 6 million and US$ 8 million capitalized in property, plant and equipment for the years ended December 31, 2025 and 2024, respectively.

F- 86

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

	Depreciation					Net book values
Type of good	At the beginning	Decreases	For the year ⁽¹⁾	Impairment (Recovery)	At the end	At 12.31.2025	At 12.31.2024


Lands	-	-	-	-	-	11	14
Buildings	(95)	-	(8)	24	(79)	99	109
Vehicles	(8)	1	(2)	1	(8)	2	3
Furniture and fixtures, tools and software and communication equipment	(37)	3	(6)	1	(39)	15	7
Thermal generation plants	(544)	-	(67)	(24)	(635)	653	547
Renewable generation plants	(78)	-	(35)	-	(113)	598	608
Petrochemical plants	(24)	-	(5)	29	-	-	18
Mining property, wells and drilling equipment	(996)	5	(270)	1	(1,260)	1,294	966
Drilling and work in progress	-	-	-	-	-	631	335
Other goods	(1)	-	-	-	(1)	-	-
Total at 12.31.2025	(1,783)	9	(393)	32	(2,135)	3,303
Total at 12.31.2024	(1,625)	57	(336)	121	(1,783)		2,607

⁽¹⁾

As of December 31, 2025, segment’s composition is as follows: Oil and gas US$ 276 million, Generation US$ 111 million; and Petrochemicals US$ 6 million.

F- 87

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.1.1 Impairment of Property, plant and equipment

The Company regularly monitors the existence of events or changes in circumstances that could indicate that the carrying amount of property, plant and equipment may not be recoverable, as well as the possible reversal of impairment losses in accordance with the policy described in Notes 4.8 and 6.1.1.

During 2025, measures were implemented to develop a competitive electricity market through direct demand contracting, and to promote fuel supply decentralization. In this regard, SE Resolution No. 400/25 established new rules that mainly impacted the Generation segment (see Note 2.2).

In addition, adverse market conditions were identified due to the sustained decline in petrochemical products’ selling prices in a more competitive macroeconomic environment, which affected the Petrochemicals segment.

As a result of the impairment / reversal of impairment indicators mentioned above, the Company determined the recoverable amount of the CGUs comprising the Generation and Petrochemicals segments as of December 31, 2025.

The methodology used to estimate the recoverable amount consisted of calculating the value in use of each CGU based on the present value of future net cash flows expected to be obtained from the CGU, discounted at a rate reflecting the weighted average cost of the capital used.

Oil & Gas segment

As of December 31, 2025, the Company has not identified any indicators that may affect the assumptions taken into consideration in the segment’s recoverability assessment.

However, during 2025, the Company recognized an impairment loss of US$ 2.3 million in connection with the assignment of interests in the El Tordillo, La Tapera and Puesto Quiroga areas (see Note 5.2).

It is worth highlighting that, as of December 31, 2025, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value.

Power Generation segment

As of December 31, 2025, the recoverability assessment of the segment’s CGUs resulted in the reversal of impairment losses recorded in previous fiscal years in the amount of US$ 55.6 million at the CPB thermal power plant.

Cash flows were prepared based on estimates of the future behavior of key assumptions for the determination of the value in use, including the following: (i) spot remuneration price evolution under SE Resolution No. 400/25; (ii) energy dispatch projections; (iii) costs evolution, considering fuel self-supply; (iv) macroeconomic variables such as the inflation and exchange rates, among others; and (v) an 11.04% after-tax WACC.

F- 88

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

Actual amounts obtained may differ significantly from those projected. The Company believes that any sensitivity analysis considering changes in any of the estimates considered individually may lead to distorted conclusions, resulting in an adverse impact on the Company’s results.

Petrochemicals Segment

As of December 31, 2025, the segment’s recoverability assessment resulted in the recognition of impairment losses for US$ 37 million.

Cash flows were prepared based on estimates on the future behavior of key assumptions for the determination of value in use, including the following: (i) products reference price evolution; (ii) costs evolution; (iii) macroeconomic variables such as the inflation and exchange rates, among others; and (iv) an 11.40% after-tax WACC.

F- 89

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.2 Intangible assets

Schedule of intangible assets
	Original values
Type of good	At the beginning	Increases	Decreases	Impairment	At the end


Concession agreements	2	-	-	-	2
Goodwill ⁽¹⁾	35	-	-	-	35
Intangible identified in acquisitions of companies	71	-	-	-	71
Digital assets	3	3	(4)	(1)	1
Total at 12.31.2025	111	3	(4)	(1)	109
Total at 12.31.2024	108	3	-	-	111


	Amortization
Type of good	At the beginning	For the year	At the end


Concession agreements	(2)	-	(2)
Intangible identified in acquisitions of companies	(14)	(4)	(18)
Total at 12.31.2025	(16)	(4)	(20)
Total at 12.31.2024	(12)	(4)	(16)

	Net book values
Type of good	At 12.31.2025	At 12.31.2024


Goodwill ⁽¹⁾	35	35
Intangible identified in acquisitions of companies	53	57
Digital assets	1	3
Total at 12.31.2025	89
Total at 12.31.2024		95

⁽¹⁾ Assigned to oil and gas segment.

F- 90

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.3 Deferred tax assets and liabilities

The composition of the deferred tax assets and liabilities is as follows:


	12.31.2024	Profit (Loss)	Other comprehensive income	12.31.2025
Tax loss carryforwards	9	(7)	-	2
Property, plant and equipment	210	(115)	-	95
Trade and other receivables	1	(1)	-	-
Provisions and other non-deductible liabilities	62	(7)	-	55
Other assets	1	3	-	4
Deferred tax asset	283	(127)	-	156
Property, plant and equipment, intangible assets, right of use assets and inventories	(98)	(17)	-	(115)
Investments in companies	(9)	(1)	-	(10)
Financial assets at fair value through profit and loss	(4)	(16)	(16)	(36)
Trade and other receivables	(6)	4	-	(2)
Provisions and other non-deductible liabilities	-	(6)	-	(6)
Tax inflation adjustment	(58)	58	-	-
Deferred tax liability	(175)	22	(16)	(169)

	12.31.2023	Profit (Loss)	12.31.2024
Tax loss carryforwards	144	(135)	9
Property, plant and equipment	-	210	210
Trade and other receivables	1	-	1
Provisions and other non-deductible liabilities	58	4	62
Other assets	-	1	1
Deferred tax asset	203	80	283
Property, plant and equipment, intangible assets and inventories	(301)	203	(98)
Investments in companies	(7)	(2)	(9)
Financial assets at fair value through profit and loss	(18)	14	(4)
Trade and other receivables	(10)	4	(6)
Tax inflation adjustment	(163)	105	(58)
Other assets	(1)	1	-
Deferred tax liability	(500)	325	(175)

Deferred tax assets and liabilities are offset in the following cases: a) when there is a legally enforceable right to offset tax assets and liabilities; and b) when deferred income tax charges are associated with the same fiscal authority. The following table shows the figures disclosed on the Consolidated Statement of Financial Position, which for its determination, were adequately compensated:


	12.31.2025	12.31.2024
Deferred tax asset, net	43	157
Deferred tax liability, net	(56)	(49)
Deferred tax (liability) asset	(13)	108

F- 91

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.4 Inventories

Schedule of inventories
	12.31.2025	12.31.2024
Current
Materials and spare parts	158	160
Advances to suppliers	9	6
In process and finished products	64	57
Total ⁽¹⁾	231	223

⁽¹⁾

It includes impairment loss as a result of the performed recoverability assessment for US$ 0.36 million and US$ 0.04 million for the years ended December 31, 2025 and 2024, according with the policy described in Note 4.11.

11.5 Provisions

Schedule of provisions
	12.31.2025	12.31.2024
Non-Current
Contingencies	53	95
Asset retirement obligation and wind turbines decommisioning	29	25
Environmental remediation	18	17
Total Non-Current	100	137

Current
Asset retirement obligation and wind turbines decommisioning	5	5
Environmental remediation	4	1
Other provisions	4	4
Total Current	13	10

F- 92

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

The evolution of the provisions is set out below:

Schedule of evolution of provisions
	12.31.2025
	Contingencies	Asset retirement obligation and decommisioning of wind turbines	Environmental remediation
At the beginning of the year	95	30	18
Increases	13	18	5
Utilization	(2)	(1)	-
Decrease due to sale of equity interests in areas	-	(11)	-
Foreign currency exchange difference	(7)	-	-
Decreases	(46)	(2)	(1)
At the end of the year	53	34	22

	12.31.2024
	Contingencies	Asset retirement obligation and decommisioning of wind turbines	Environmental remediation
At the beginning of the year	109	29	17
Increases	41	8	2
Utilization	(1)	-	-
Foreign currency exchange difference	(4)	-	-
Decrease due to sale of equity interests in areas	-	(1)	-
Decreases	(50)	(6)	(1)
At the end of the year	95	30	18



	12.31.2023
	Contingencies	Asset retirement obligation and decommisioning of wind turbines	Environmental remediation

At the beginning of the year	107	27	17
Increases	15	6	3
Utilization	(4)	-	(1)
Foreign currency exchange difference	(9)	-	-
Decreases	-	(4)	(2)
At the end of the year	109	29	17

F- 93

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.5.1

Provision for Environmental remediation

The Company is subject to extensive environmental regulations in Argentina. The Company’s management believes that its current operations are in compliance with applicable environmental requirements, as currently interpreted and enforced, including regulatory remediation commitments assumed. The Company undertakes environmental impact studies for new projects and investments and, to date, environmental requirements and restrictions imposed on these new projects have not had any material adverse impact on Pampa’s business.

In particular, the Province of La Pampa has submitted a claim to the Company regarding the abandonment of certain wells and the execution of certain tasks associated with the relinquishment of the Jagüel de los Machos and Medanito blocks, which took place in 2015 and 2016, respectively. The Company has challenged the different administrative acts passed by the provincial authorities (including a governor’s executive order) and is addressing claims for the Jagüel de los Machos block in the judicial jurisdiction. During the month of March 2021 the province answered the complaint and the Company has started formal negotiations to resolve the dispute, agreeing on the suspension of procedural time limits. As of December 31, 2025, the Company maintains recorded provisions, regarding these claims, for the estimate of remediation work costs to be incurred in these blocks.

The Company has performed a sensitivity analysis relating to the discount rate. The 1% increase or decrease in the discount rate would not have a significant impact on the Company’s results of operations.

11.5.2

Asset retirement obligations and wind turbines decommissioning

Pursuant to the regulations in force in Argentina, where it develops its oil and gas exploration and production operations, the Company is under an obligation to incur costs associated with the plugging and abandonment of wells. Furthermore, pursuant to the associated usufruct agreements, the Company is under an obligation to decommission wind turbines in wind farms.

11.5.3

Provision for legal proceedings

The Company (directly or indirectly through subsidiaries) is a party to several civil, commercial, contentious-administrative, tax, custom and labor proceedings and claims that arise in the ordinary course of its business. In determining a proper level of provision, the Company has considered its best estimate mainly with the assistance of legal and tax advisors.

F- 94

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

During fiscal year 2025, the Company recocognized a recovery of US$ 44 million, including interest, in relation to the following process:

The tax authority has challenged the tariff classification assigned and, consequently, the tax rate applied to certain gasoline exports carried out by Petrobras Argentina S.A. during the 2008–2014 period. The National Tax Court (“NTC”) issued 17 rulings favorable to the Company, 15 of which were accepted by the tax authority and, accordingly, became final and binding. For the remaining cases, the term is currently running for the tax authority to potentially appeal. However, in view of the above-described progress, the Company believes there are grounds to conclude that the related provision is not probable.

As of December 31, 2025, the Company has recorded provisions of US$ 53.5 million in relation to civil, commercial, environmental, administrative, labor, tax and customs complaints brought against the Company, including charges for judicial costs and expenses, and corresponding to atomized claims with individual unsubstantial amounts, except for the process detailed below:

Petrobras Operaciones S.A. (“POSA”) has filed an international arbitration claim against the Company before the ICC on account of alleged breaches to the Assignment Agreement entered into between Petrobras Argentina S.A. (currently Pampa) and POSA in 2016 for the transfer of a 33.6% interest in the “Río Neuquén” Concession. The breaches alleged by POSA in its arbitration claim consisted of the failure to transfer certain assets associated with the assigned interest, and differences in the calculation of adjustments in the assignment price. The arbitration was conducted according to the ICC Rules of Arbitration, the applicable law is the one of the Republic of Argentina, and the seat of arbitration is Buenos Aires, Argentina. On April 3, 2024, the ICC Court notified the parties of the Final Award issued on April 2, 2024, resolving to: (i) disallow all but one of POSA’s claims, ordering the Company to pay the corresponding 33.60% of (a) the revenues collected under the Leasing Agreement up to the Final Award’s date for US$ 18.8 million, plus a 6% annual interest rate, and (b) the payments that the Company receives in the future under the before-mentioned agreement; and (ii) sustain the Company’s counterclaim for US$ 2 million plus interest at an annual 6% rate. On April 10, 2024, the Company filed an appeal for partial annulment against the Final Award. During 2025, POSA answered the service of notice, and on July 15, 2025, and on August 27, 2025 hearings were held before the National Chamber of Appeals in Commercial Matters.

11.6 Income tax and minimum notional income tax liability


	12.31.2025	12.31.2024
Non-current
Income tax	22	69
Minimum notional income tax	4	6
Total non-current	26	75

Current
Income tax, net of witholdings and advances	83	257
Total current	83	257

F- 95

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.6.1 Income tax liability

The tax inflation adjustment mechanism set out in Title VI and different supplementary sections of the Income Tax Law is inconsistent in certain aspects generating a confiscatory lien, including, but not limited to, the failure to update tax losses and the cost of acquisitions or investments made before January 1, 2018, which bears resemblance with the parameters in re “Candy S.A.” and “Telefónica”, where the CSJN ordered the application of the inflation adjustment mechanism.

As of December 31, 2025, the Company and its subsidiaries hold a provision for the additional income tax liabilities that should have been assessed due to the stated reasons. The amount provisioned for the periods not prescribed and/or those without a final and conclusive judgment in favor of the Company, including compensatory interest, amounts to US$ 22 million.

In November 2025, the Company accessed a payment facility plan provided for in ARCA General Resolution No. 5,684/25, in order to partially cancel the duly recorded provision, the related liability is disclosed within tax liabilities item (see Note 11.7).

11.6.2 Minimum Notional Income Tax liability

The Company and its subsidiaries have filed a petition for declaratory relief under Sect. 322 of the Federal Code of Civil and Commercial Procedure to gain assurance as to the application of the minimum notional income tax for the fiscal years 2011-2018 based on CSJN’s decision in re “Hermitage” passed on June 15, 2010. In this established precedent, the CSJN declared the unconstitutionality of this tax on the grounds that it is unreasonable and it breaches the taxpaying capacity principle when the absence of taxable income in the period evidences that the income presumed by the legislator has not existed.

However, on August 26, 2021, the CSJN dismissed the tax refund claim lodged by the Company for the 2008 and 2009 periods alleging that, despite the evidenced tax losses, the existence of accounting profits is a manifestation of the taxpaying capacity and, therefore, the precepts of the Hermitage precedent are not met.

Considering the CSJN’s current position, the Company and its subsidiaries have recorded, for non-prescribed periods presenting tax losses and accounting profits, liabilities on the amount of the applicable interest on the Notional Income Tax, plus the determined tax provision for those cases in which Minimum Notional Income Tax is not considered to be computable as an Income Tax advance payment. As of December 31, 2025, the aforementioned liability amounts to US$ 4 million.

F- 96

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.7 Tax liabilities

Schedule of tax liabilities
	12.31.2025	12.31.2024
Non-current
Payment plans	212	-
Total non-current	212	-

Current
Value added tax	2	3
Personal assets tax provision	11	10
Tax withholdings to be deposited	11	8
Payment plans	14	-
Royalties	12	6
Other	6	3
Total current	56	30

11.8 Defined benefits plans

The main characteristics of benefit plans granted to Company employees are detailed below:

(i)

Pension and retirement benefits: Benefit plan whereby Company employees, in some cases covered by certain collective bargaining agreements, meeting certain conditions are eligible to receive upon retirement, and in some cases, disability or death, a certain number of salaries according to the provisions of the plan or collective bargain agreement, if applicable.

(ii)

Compensatory plan: Benefit plan whereby some of the Company employees meeting certain conditions are eligible to receive upon retirement a certain amount according to the provisions of the plan (based on the last computable salary and the number of years working for the Company) after deducting the benefits from the pension system. The plan, until 2003, called for a contribution to a fund exclusively by the Company and without any contribution by the employees. These contributions were derived to a trust fund and were invested in U.S. dollar-denominated money market instruments in order to preserve the accumulated capital and obtain a return in line with a moderate risk profile. Funds were mainly invested in U.S. government bonds, commercial papers rated A1 or P1, AAAm- rated mutual funds and time deposits in banks rated A+ or higher in the United States of America, in accordance with the Trust Agreement dated on March 27, 2002 entered with The Bank of New York Mellon, duly amended by the Permitted Investment Letter dated on September 14, 2006. The Bank of New York Mellon is the trustee and Willis Towers Watson is the managing agent. In case there is an excess, duly certified by an independent actuary, of the funds to be used to settle the benefits granted by the plan, the Company will be entitled to choose to use it, in which case it may have to notify the trustee thereof.

F- 97

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

As of December 31, 2025, 2024 and 2023, the most relevant actuarial information corresponding to the described benefit plans is the following:

Schedule of benefit plans information
	12.31.2025
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	41	(4)	37
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	12	(2)	10
Benefit payments	(3)	-	(3)
(Gains) Losses on exchange difference	(14)	1	(13)
At the end of the year	37	(5)	32


	12.31.2024
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	23	(4)	19
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	32	(6)	26
Items classified in Other comprehensive income
Actuarial (gains) losses	(4)	4	-
Benefit payments	(3)	-	(3)
(Gains) Losses on exchange difference	(8)	2	(6)
At the end of the year	41	(4)	37

F- 98

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)


	12.31.2023
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	38	(4)	34
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	29	(4)	25
Items classified in Other comprehensive income
Actuarial losses (gains)	7	(2)	5
Benefit payments	(3)	-	(3)
(Gains) Losses on exchange difference	(49)	6	(43)
At the end of the year	23	(4)	19

As of December 31, 2025, 2024 and 2023, the breakdown of net liabilities per type of plan is as follows: a) US$ 17 million, US$ 20 million and US$ 9 million correspond to the Pension and Retirement Benefits Plan and b) US$ 15 million, US$ 17 million and US$ 10 million correspond to the Compensatory Plan, respectively.

Estimated expected benefits payments for the next ten years are shown below. The amounts in the table represent the undiscounted cash flows and therefore do not reconcile to the obligations recorded at the end of the year.


	12.31.2025
Less than one year	6
One to two years	3
Two to three years	3
Three to four years	4
Four to five years	3
Six to ten years	14

F- 99

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

Significant actuarial assumptions used were as follows:


	12.31.2025	12.31.2024	12.31.2023
Real discount rate	5%	5%	5%
Real wage increase rate	1%	1%	1%
Inflation rate	16%	29%	156%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount:


	12.31.2025
Discount rate: 4%
Obligation	40
Variation	3
	8%

Discount rate: 6%
Obligation	34
Variation	(3)
	(7%)

Real wage increase rate: 0%
Obligation	36
Variation	(1)
	(3%)

Real wage increase rate: 2%
Obligation	38
Variation	1
	4%

The sensitivity analyses are based on a change in an assumption while holding all other assumptions constant. In practice, this is unlikely to occur, and changes in some of the assumptions may be correlated. Therefore, the presented analysis may not be representative of the actual change in the defined benefit obligation. The methods and types of assumptions used in preparing the sensitivity analysis did not change compared to the prior period.

F- 100

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.9 Salaries and social security payable


	12.31.2025	12.31.2024
Current
Salaries and social security contributions	5	6
Provision for vacations	8	9
Provision for gratifications and annual bonus for efficiency	23	24
Total current	36	39

NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1 Financial assets at amortized cost


	12.31.2025	12.31.2024
Current
Term deposit	-	80
Total current	-	80

Due to the short-term nature of investments at amortized cost, it is considered that their book value does not differ from their fair value.

12.2 Financial assets at fair value through profit and loss


	12.31.2025	12.31.2024
Non-current
Shares	33	27
Total non-current	33	27

Current
Government securities	308	692
Corporate bonds	47	110
Shares	3	37
Mutual funds	8	11
Total current	366	850

F- 101

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.3 Trade and other receivables

Schedule of trade and other receivables
	Note	12.31.2025	12.31.2024
Non-Current
Related parties	16	-	4
Advances to suppliers		42	43
Prepaid expenses		1	5
Tax credits		-	8
Receivables for sale of assets		-	10
Contractual indemnity receivable		-	2
Expenses to be recovered		-	3
Other receivables		43	75
Total non-current		43	75




	Note	12.31.2025	12.31.2024
Current
Receivables		249	172
CAMMESA		118	107
Related parties	16	8	10
Impairment of financial assets		(20)	(1)
Trade receivables, net		355	288

Current
Related parties	16	4	11
Tax credits		58	8
Receivables for complementary activities		-	9
Prepaid expenses		18	3
Guarantee deposits ⁽¹⁾		142	130
Expenses to be recovered		3	8
Insurance to be recovered		-	1
Receivables for sale of assets		9	6
GasAr Plan		16	7
Contractual indemnity receivable		2	2
Receivable for maintenance contract		1	1
Impairment of other receivables		(1)	-
Other		7	14
Other receivables, net		259	200
Total current		614	488

⁽¹⁾

Includes guarantee deposits on derivative financial instruments amounting for US$ 141 million and US$ 45 million as of December 31, 2025, and December 31, 2024, respectively.

Due to the short-term nature of investments at amortized cost, it is considered that their book value does not differ from their fair value. For non-current investments at amortized cost, fair values also do not differ significantly from book values.

F- 102

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

The movements in the impairment of financial assets were as follows:


	Note	12.31.2025	12.31.2024	12.31.2023
At the beginning of the year	###	1	1	6
Impairment		20	55	1
Write off for utilization		-	(54)	-
Reversal of unused amounts		-	-	(1)
Foreign currency exchange difference		(1)	(1)	(5)
At the end of the year		20	1	1

The movements in the impairment of other receivables are as follows:


	Note	12.31.2025	12.31.2024	12.31.2023
At the beginning of the year	###	-	-	-
Impairment		1	-	-
At the end of the year		1	-	-

12.4 Cash and cash equivalents

Schedule of cash and cash equivalents
	12.31.2025	12.31.2024
Cash	-	1
Banks	335	73
Term deposit	-	46
Mutual funds	390	618
Total	725	738

12.5 Borrowings

Schedule of borrowings
	12.31.2025	12.31.2024
Non-Current
Financial borrowings	45	32
Corporate bonds	1,799	1,341
Total non-current	1,844	1,373

Current
Financial borrowings	33	122
Corporate bonds	15	584
Total current	48	706
Total	1,892	2,079

F- 103

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

As of December 31, 2025 and 2024, the fair values of the Company’s CB amount approximately to US$ 1,833 million and US$ 1,912 million, respectively. Such values were calculated on the basis of the determined market price of the Company’s CB at the end of each year (fair value level 1).

The carrying amounts of short-term borrowings approximate their fair value due to their short-term maturity.

The long-term borrowings were measured at amortized cost, which does not differ significantly from its fair value.

As of the date of issuance of these Consolidated Financial Statements, the Company is in compliance with the covenants established in its indebtedness contracts.

12.5.1 Movements in borrowings:

Schedule of changes in borrowings
	12.31.2025	12.31.2024	12.31.2023
Borrowings at the beginning of the year	2,079	1,448	1,613
Proceeds from borrowings	986	1,174	424
Payment of borrowings	(315)	(236)	(191)
Accrued interest	139	145	304
Payment of interests	(161)	(145)	(280)
Repurchase and redemption of CB	(837)	(313)	(6)
Result from repurchase of CB	(2)	10	(1)
Foreign currency exchange difference	(3)	(12)	(356)
Decrease for sale of subsidiaries	-	-	(80)
Borrowing costs capitalized in property, plant and equipment	6	8	21
Borrowings at the end of the year	1,892	2,079	1,448

F- 104

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5.2 Details of borrowings:

Type of instrument

Company

Currency

Residual value

Interest

Rate

Expiration

Book value as of 12.31.2025

Corporate bonds ⁽¹⁾

Class 13 CB

PAMPA

US$

Fixed

0.00%

Dec-27

Class 25 CB

PAMPA

US$

105

Fixed

7.25%

Aug-28

107

Class 22 CB

PAMPA

US$

Fixed

5.75%

Oct-28

Class 21 CB

PAMPA

US$

410

Fixed

7.95%

Sep -31

412

Class 23 CB

PAMPA

US$

700

Fixed

7.88%

Dec-34

693

Class 26 CB

PAMPA

US$

450

Fixed

7.75%

Nov-37

437

1,814

Financial loans ⁽²⁾

PAMPA

US$

Fixed

5.40%

Mar-26

PAMPA

US$

Fixed

3.00%

May-26

PAMPA

US$

Fixed

5.50%

Jan-28

1,892

⁽¹⁾

On February 28, 2025, November 4, 2025 and December 8, 2025, the Company repaid at maturity Class 19 CB for $ 17,131 million, Class 16 CB for US$ 56 million and the second principal installment of Class 9 CB for US$ 59 million, respectively. Additionally, on January 24, 2025, May 8, 2025, June 23, 2025, December 8, 2025, and December 11, 2025, the Company early redeemed, net of repurchases, if applicable: Class 1 CB for US$ 353 million, Class 18 CB for US$ 63 million, Class 3 CB for US$ 293 million, the final principal installment of Class 9 CB for US$ 61 million and Class 20 CB for US$ 36 million.

⁽²⁾

During the fiscal year ended December 31, 2025, the Company (i) repaid net bank debt for US$ 53 million (totaling US$ 104 million net of US$ 51 million proceeds); (ii) repaid import financing for US$ 2.9 million; and (iii) took out export pre-financing for US$ 70 million, which was fully repaid. Post-closing, the Company cancelled bank debt for US$ 8 million.

F- 105

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

Type of instrument

Company

Currency

Residual value

Interest

Rate

Expiration

Book value as of 12.31.2024

Corporate bonds ⁽¹⁾⁽²⁾

Class 19 CB

PAMPA

17,131

Variable

Badlar - 1%

Feb-25

Class 18 CB

PAMPA

US$

Fixed

5.00%

Sep-25

Class 16 CB

PAMPA

US$

Fixed

4.99%

Nov-25

Class 20 CB

PAMPA

US$

Fixed

6.00%

Mar-26

Class 9 CB

PAMPA

US$

120

Fixed

9.50%

Dec-26

123

Class 1 CB

PAMPA

US$

353

Fixed

7.50%

Jan-27

363

Class 13 CB

PAMPA

US$

Fixed

0.00%

Dec-27

Class 22 CB

PAMPA

US$

Fixed

5.75%

Oct-28

Class 3 CB

PAMPA

US$

293

Fixed

9.13%

Apr-29

294

Class 21 CB

PAMPA

US$

410

Fixed

7.95%

Sep -31

410

Class 23 CB

PAMPA

US$

360

Fixed

7.88%

Dec-34

358

1,925

Financial loans ⁽³⁾

PAMPA

US$

Fixed

3.00%

Mar-25

PAMPA

US$

Fixed

4.25%

Apr-25

PAMPA

US$

Fixed

5.40%

Mar-26

PAMPA

US$

Fixed

3.00%

May-26

117

Other financial loans ⁽⁴⁾

PAMPA

US$

283

Variable

SOFR + 0%

Aug-25

PAMPA

US$

Fixed

Between 9.50% and 10.25%

Between Feb-25 and Sep-25

GASA

U$S

14,937

Fixed

3.25%

May-25

2,079

⁽¹⁾Net

of repurchases for a face value of US$ 76.2 million for Class 9 CB and US$ 7.5 million for Class 3 CB.

⁽²⁾On

February 5, 2024 and June 27, 2024, the Company redeemed all its Class 17 and Class 15 CB for a total amount of $ 5,980 million and $ 18,264 million, respectively. Additionally, the Company paid at maturity the first redemption of Class 9 CB for a US$ 59 million amount net of repurchases.

⁽³⁾During

the fiscal year ended December 31, 2024, the Company repaid: (i) short-term bank net debt with local financial institutions, for $ 25,968 million; (ii) the last two principal installments of the FINNVERA Credit Facility for US$ 8 million; and (iii) net import financing for the equivalent of US$ 16 million. In addition, it borrowed US$ 130 million net from local banks.

⁽⁴⁾During

the fiscal year ended December 31, 2024, the Company received disbursements in the amount of US$ 223 million under the credit facilities taken out with BNP Paribas S.A. in 2020.

F- 106

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5.3 Global Program of CB and frequent issuer prospectus

On April 7, 2025, the Company’s Ordinary and Extraordinary General Shareholders’ Meeting resolved to approve the increase in the amount of the CB Issuance Program, created in 2021, from US$ 2 billion to US$ 2.1 billion or its equivalent in other currencies or units of value. The increase was approved by the CNV on May 27, 2025.

The Company is registered as a frequent issuer, a status that was ratified by CNV’s Issuers’ Management Office Provision No. I-2025-32-APN-GE#CNV dated March 11, 2025. Under this Provision, the CNV also approved (i) the increase in the frequent issuer prospectus amount from US$ 0.6 billion to US$ 1.3 billion or its equivalent in other currencies or units of value; and (ii) the amendment of the prospectus’ terms and conditions to include the possibility of issuing thematic (social, green and sustainable) marketable securities, all of which was in turn approved by the Company’s Board of Directors at its meeting held on March 5, 2025.

12.5.4 Reopening of international Class 23 CB and Issuance of Class 25 CB and international Class 26 CB

On May 28, 2025, the Company reopened international Class 23 CB for a face value of US$ 340 million at a 7.875% fixed annual interest rate and an 8% yield, maturing in December 2034. As a result, the total outstanding face value amounts to US$ 700 million. The net proceeds were used to early redeem all Class 3 CB.

Subsequently, on August 6, 2025, the Company issued Class 25 CB for a face value of US$ 104.6 million, at a 7.25% fixed annual interest rate and maturing August 6, 2028.

Lastly, on November 14, 2025, the Company issued international Class 26 CB for a face value of US$ 450 million, at a 7.75% fixed annual interest rate and with an 8.125% yield, maturing in November 2037.

12.5.5 Partial Application of Proceeds – Class 26 CB

In compliance with the provisions of CNV General Resolution No. 1,095/25, the Company hereby reports, as a sworn statement, that, as of December 31, 2025, it has partially applied a total of US$ 181.2 million of the issued amount of Class 26 CB, with US$ 268.8 million remaining pending application.

Likewise, and in accordance with the use of proceeds disclosed in the issuance documents of the Class 26 CB, it is informed that such funds have been applied as follows: (i) placement agents’ fees and other issuance expenses; (ii) working capital contributions in Argentina; (iii) investments in property, plant and equipment in Argentina; and (iv) refinancing and redemption of the Company’s existing liabilities.

F- 107

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.6 Trade and other payables

Schedule of trade and other payables
	Note	12.31.2025	12.31.2024
Non-Current

Compensation agreements		70	71
Leases liability		15	11
Contractual penalty debt		-	2
Other		1	-
Other payables		86	84
Total non-current		86	84

Current
Suppliers		314	206
Customer advances		13	14
Related parties	16	29	13
Trade payables		356	233

Compensation agreements		14	12
Leases liability		21	4
Contractual penalty debt		2	2
Various creditors		4	2
Other payables		41	20
Total current		397	253

Due to the short-term nature of the trade payables and other payables, their carrying amounts do not differ significantly from their fair value. For most other non-current debts, fair values also do not significantly differ from their book values.

F- 108

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.7 Financial instruments by category

The following table presents financial instruments by category:

Schedule of financial instruments
As of December 31, 2025	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and loss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade and other receivables	397	141	538	119	657
Financial assets at fair value through profit and loss
Government securities	-	308	308	-	308
Corporate bonds	-	47	47	-	47
Shares	-	36	36	-	36
Mutual funds	-	8	8	-	8
Derivative financial instruments	-	52	52	-	52
Cash and cash equivalents	335	390	725	-	725
Total	732	982	1,714	119	1,833

Liabilities
Trade and other payables	470	-	470	13	483
Borrowings	1,892	-	1,892	-	1,892
Total	2,362	-	2,362	13	2,375


As of December 31, 2024	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and loss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade and other receivables	496	-	496	67	563
Financial assets at amortized cost
Term deposit	80	-	80	-	80
Financial assets at fair value through profit and loss
Government securities	-	692	692	-	692
Corporate bonds	-	110	110	-	110
Shares	-	64	64	-	64
Mutual funds	-	11	11	-	11
Derivative financial instruments	-	1	1	-	1
Cash and cash equivalents	120	618	738	-	738
Total	696	1,496	2,192	67	2,259

Liabilities
Trade and other payables	323	-	323	14	337
Borrowings	2,079	-	2,079	-	2,079
Total	2,402	-	2,402	14	2,416

The categories of financial instruments have been determined according to IFRS 9.

F- 109

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

The income, expenses, gains and losses derived from each of the financial instrument categories are indicated below:


As of December 31, 2025	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and loss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	59	-	59	-	59
Interest expenses	(139)	-	(139)	(50)	(189)
Foreign currency exchange difference, net	(79)	(48)	(127)	156	29
Changes in the fair value of financial instruments	-	202	202	-	202
Result from present value measurement	(4)	-	(4)	1	(3)
Other financial results	(5)	-	(5)	-	(5)
Total	(168)	154	(14)	107	93


As of December 31, 2024	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and loss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	82	-	82	-	82
Interest expenses	(146)	-	(146)	(34)	(180)
Foreign currency exchange difference, net	(23)	(30)	(53)	42	(11)
Changes in the fair value of financial instruments	-	239	239	-	239
Result from present value measurement	(2)	-	(2)	(5)	(7)
Other financial results	(15)	-	(15)	-	(15)
Total	(104)	209	105	3	108


As of December 31, 2023	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and loss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	75	-	75	-	75
Interest expenses	(307)	-	(307)	(49)	(356)
Foreign currency exchange difference, net	(1,035)	(560)	(1,595)	1,718	123
Changes in the fair value of financial instruments	-	444	444	-	444
Result from present value measurement	(1)	-	(1)	(9)	(10)
Other financial results	(7)	-	(7)	-	(7)
Total	(1,275)	(116)	(1,391)	1,660	269

F- 110

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.8 Fair value of financial Instruments

The Company classifies the fair value measurements of financial instruments using a fair value hierarchy, which reflects the relevance of the variables used to perform those measurements. The fair value hierarchy has the following levels:

Level 1: quoted prices (not adjusted) for identical assets or liabilities in active markets.

Level 2: data different from the quoted prices included in Level 1 observable for the asset or liability, either directly (i.e. prices) or indirectly (i.e. derived from prices).

Level 3: Asset or liability data based on information that cannot be observed in the market (i.e., unobservable data).

The following table shows the Company’s financial assets measured at fair value as of December 31, 2025 and 2024:


As of December 31, 2025	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and loss
Government securities	308	-	-	308
Corporate bonds	47	-	-	47
Mutual funds	8	-	-	8
Shares	5	-	31	36
Cash and cash equivalents
Mutual funds	390	-	-	390
Derivative financial instruments	-	52	-	52
Other receivables
Guarantee deposits	141	-	-	141
Total assets	899	52	31	982


As of December 31, 2024	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and loss
Government securities	692	-	-	692
Corporate bonds	110	-	-	110
Mutual funds	11	-	-	11
Shares	37	-	27	64
Cash and cash equivalents
Mutual funds	618	-	-	618
Derivative financial instruments	-	1	-	1
Total assets	1,468	1	27	1,496

F- 111

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

The value of the financial instruments negotiated in active markets is based on the market quoted prices as of the date of these Consolidated Financial Statements. A market is considered active when the quoted prices are regularly available through a stock exchange, broker, sector-specific institution or regulatory body, and those prices reflect regular and current market transactions between parties that act in conditions of mutual independence. The market quotation price used for the financial assets held by the Company is the current offer price. These instruments are included in Level 1.

The fair value of financial instruments that are not negotiated in active markets is determined using valuation techniques. These valuation techniques maximize the use of market observable information, when available, and rely as little as possible on specific estimates of the Company. If all significant variables to establish the fair value of a financial instrument can be observed, the instrument is included in Level 2.

If one or more variables used to determine the fair value cannot be observed in the market, the financial instrument is included in Level 3.

The techniques used for the measurement of assets at fair value, classified as Level 2 and 3, are detailed below:

Derivative Financial Instruments: calculated from variations between market prices at the closing date of the year, and the amount at the time of the contract.

Shares: it was mainly determined using the income-based approach through the “Indirect Cash Flow” method, that is, the net present value of expected future cash flows, mainly through the collection of dividends taking into consideration the equity interest in TJSM and TMB thermal plants and Oldelval and discount rates of 16.5% and 15.1% for the thermal plants and Oldelval, respectively. The projections used were prepared based on estimates regarding the future behavior of certain sensitive variables, including: (i) the dividend distribution policy; (ii) prices for energy traded on the spot market; (iii) prices for hydrocarbon transportation; (iv) projections of plants availability and dispatch; (v) evolution of structural costs and expenses and; (vi) macroeconomic variables such as inflation rates and exchange rates, among others. The Company recognized results arising from changes in the fair value of financial instruments classified as Level 3 under the “Other financial results” line item in the Statement of Comprehensive Income. Actual values obtained may vary significantly from those projected, mainly due to: i) the timing and magnitude of dividend distributions; ii) the timing and magnitude of energy and hydrocarbon transportation prices increases; and/or iii) costs evolution. The Company estimates that any sensitivity analysis that considers changes in any of the estimates taken individually may lead to distorting conclusions, generating an adverse effect on the Company’s results.

F- 112

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.9 Hedge accounting

During 2025, the Company entered into forward crude oil sale contracts, without physical delivery, and designated a portion of these derivative financial instruments as cash flow hedges.

The Company applies cash flow hedge accounting to certain transactions to manage the international reference price risk associated with a specific volume of forecasted crude oil sales for the May 2025-November 2026 period, thereby ensuring stable cash flows.

As of December 31, 2025, the fair value of forward crude oil sale contracts designated as hedges amounts to a US$ 46 million asset, recognized in other comprehensive income as the hedge is effective; this amount is expected to be fully reclassified to profit or loss during the January 2026-November 2026 period, as the hedged crude oil sales are recognized in revenues.

The amount reclassified from other comprehensive income to revenue, from designated hedges, generated a US$ 15 million gain during the May - December 2025 period.

The contracts are entered into in markets or with financial institutions with high credit ratings; therefore, the Company considers that there are no significant credit risks to its operations as a result of its derivative activities.

F- 113

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 13: EQUITY COMPONENTS

13.1 Share capital

As of December 31, 2025, the share capital amounts to $ 1,364 million, including approximately $ 4 million treasury shares.

13.1.1 Share repurchase plan

Taking into consideration the market volatility and the persisting divergence between the Company’s share price and the economic reality its assets currently or potentially have, which is detrimental to the interests of its shareholders, and considering the Company’s history of strong cash position and fund availability, the Board of Directors has implemented several share repurchase programs, considering in each case that treasury shares may not exceed the 10% capital stock capitalization.

On September 8, 2025, the Company’s Board of Directors approved a share repurchase program for up to US$ 100 million, an initial term of 120 calendar days and maximum prices of US$ 60 per ADR and $ 3,480 per common share.

During the fiscal year ended December 31, 2025, the Company directly and indirectly acquired 35 thousand shares for $ 122 million and 795 thousand ADRs for US$ 46.8 million, respectively.

As of the date of issuance of these Consolidated Financial Statements the share repurchase plan is no longer in effect and no treasury shares have been acquired under this plan subsequent to December 31, 2025.

13.1.2 Stock Compensation Plan

As of December, 31 2025, 4 million remained in treasury to be delivered to employees under such plan (see Note 4.15).

F- 114

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 13: (Continuation)

13.2 Earnings per share

Basic earnings per share are calculated by dividing the result attributable to the Company’s equity interest holders by the weighted average of outstanding common shares during the year. Diluted earnings per share are calculated by adjusting the weighted average of outstanding common shares to reflect the conversion of all dilutive potential common shares.

Potential common shares will be deemed dilutive only when their conversion into common shares may reduce the earnings per share or increase losses per share of the continuing business. Potential common shares will be deemed anti-dilutive when their conversion into common shares may result in an increase in the earnings per share or a decrease in the losses per share of the continuing operations.

The calculation of diluted earnings per share does not entail a conversion, the exercise or another issuance of shares which may have an anti-dilutive effect on the losses per share, or where the option exercise price is higher than the average price of ordinary shares during the year, no dilutive effect is recorded, being the diluted earnings per share equal to the basic. As of December 31, 2025, 2024 and 2023, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

Schedule of earnings (loss) per share
	12.31.2025	12.31.2024	12.31.2023
Earning attributable to equity holders of the Company	377	619	302
Weighted average amount of outstanding shares	1,360	1,360	1,366
Basic and diluted earnings per share	0.28	0.46	0.22

13.3 Profit distributions

Dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or after January 1, 2018 are subject to a 7% withholding tax (see Note 2.6.1.2). The distribution of dividends is made based on the Company’s Stand-Alone Financial Statements which are presented in pesos, the legal currency in Argentina, pursuant to regulatory requirements.

The Company may pay and distribute dividends and any other type of profits to its shareholders, except if: (i) there is an event of breach; or (ii) the Company is not in a position to incur debt under the indentures governing the Class 21, Class 23, Additional Class 23 and Class 26 CB. As of the date of issuance of these Consolidated Financial Statements, the Company has complied with all commitments set forth in the indentures governing the above-mentioned CB.

F- 115

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 14: STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit to cash flows generated by operating activities


	Note	12.31.2025	12.31.2024	12.31.2023
Income tax	10.6	204	(121)	318
Accrued interest		139	106	283
Depreciations and amortizations	9 and 10.2	414	342	267
Share of profit from associates and joint ventures	5.1.2	(142)	(146)	2
Profit from sale of companies´ interest		-	(34)	(9)
Results for property, plant and equipment sale and derecognition	10.4	-	(11)	1
Results for intangible assets sales	10.4	(5)	-	-
(Recovery) Impairment of property, plant and equipment, intangible assets and inventories		(15)	34	39
Impairment of financial assets		21	56	-
Result from present value measurement	10.5	3	7	10
Changes in the fair value of financial instruments		(181)	(213)	(392)
Exchange differences, net		(48)	-	(190)
Result from repurchase of CB	10.5	(2)	10	(1)
Costs of concessions agreements completion	10.4	1	6	5
Contractual indemnity	10.4	-	-	(7)
Contractual penalty	10.4	-	-	7
Provision for contingecies, net	10.4	(3)	6	8
Provision for environmental remediation	10.4	7	3	4
Accrual of defined benefit plans	9 and 10.2	11	27	26
Fair value of consortiums' previous interest	10.4	-	-	(7)
Impairment of other receivables	10.4	-	-	5
Ecuador's transactional agreement	10.4	-	-	5
Expenses recovery	10.4	-	-	(8)
Compensation agreements	10.2	14	61	37
Derecognition of unproductive wells	10.3	-	20	7
Other		-	(1)	(4)
Adjustments to reconcile net profit to cash flows from operating activities		418	152	406

F- 116

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 14: (Continuation)

14.2 Changes in operating assets and liabilities


	12.31.2025	12.31.2024	12.31.2023
Increase in trade receivables and other receivables	(100)	(411)	(151)
Increase in inventories	(13)	(20)	(35)
Increase in trade and other payables	69	75	17
Increase in salaries and social security payables	10	25	20
Defined benefit plans payments	(3)	(3)	(3)
Increase in tax liabilities	22	17	27
Decrease in provisions	(10)	(19)	(7)
Income tax payment	(8)	-	-
Collection (Payments) for derivative financial instruments, net	15	-	(4)
Changes in operating assets and liabilities	(18)	(336)	(136)

14.3 Significant non-cash transactions


	12.31.2025	12.31.2024	12.31.2023
Acquisition of property, plant and equipment through an increase in trade payables	(169)	(99)	(82)
Borrowing costs capitalized in property, plant and equipment	(6)	(8)	(21)
Increase in other receivables through a decrease in financial assets at fair value through profit or loss	(131)	-	-
Collection of dividends from joint ventures through financial assets	45	-	-
Payment of borrowings through financial assets at amortized cost transfer	(9)	-	-
Increase in intangible assets through the reduction of other receivables	(3)	-	-
Increase in right-of-use assets through an increase in other liabilities	(44)	-	(13)
Decrease in financial assets at fair value through profit or loss through a decrease in income tax liability	(3)	-	-
Compensation of trade receivables through an increase in financial assets at fair value through profit and loss	-	(53)	-
Increase (Decrease) in asset retirement obligation and wind turbines decommision through property, plant and equipment	15	(5)	(5)
Credit for equity interests in areas sales	-	14	-
Increase of property, plant and equipment through exchange of assets	-	-	(25)

F- 117

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: CONTINGENT LIABILITIES AND ASSETS

We hereinafter detail the nature of significant proceedings as of December 31, 2025, not considered as probable by the Company based on the opinion of the Company’s internal and external counselors.

15.1 Labor Claim – Compensatory Plan

The Company faces several legal proceedings associated with the Defined Benefit Plan “Compensatory Plan” (see Note 11.8). We hereinafter describe the nature of currently pending labor claims:

Claims on considering that the index (CPI) used to update the plan benefits is ineffective to keep their “constant value”. In three of the causes, the Company obtained a favorable judgment, two of which are final, while the remaining one has been appealed by the plaintiff.

Claims on an alleged underfunding of the plan upon the elimination of the Company’s contributions based on earnings. The Company obtained a favorable first-instance judgment. The Commercial Court of Appeals sustained the plaintiff’s appeal. Against said pronouncement, the Company filed a Federal Extraordinary Appeal before the CSJN, which was disallowed by the Appeals Chamber. Consequently, the Company filed a petition in error before the CSJN and an appeal on the grounds of unconstitutionality before the Supreme Court of Justice of the Autonomous City of Buenos Aires, this Court requested the Chamber to refer back the proceedings and ordered the hearing of the unconstitutionality appeal the Chamber had dismissed. In view of the Chamber's dismissal, the file was sent to the CSJN, which will settle the dispute over jurisdiction.

15.2 Tax claim

The ARCA filed a claim in the amount of $ 54 million against the Company for an alleged omission in the payment of Taxes on Liquid Fuels and Natural Gas during fiscal periods January 2006 through August 2011, plus compensatory interest and a penalty of $ 38 million for such omission. The tax entity supports its claim on the allegation that the tax benefit granted to sales to areas declared exempt by the tax law has been misappropriated. The proceeding is currently being heard before the Federal Tax Court, and the evidentiary period has been completed.

15.3 Environmental claims

The Association of Land Owners of Patagonia (ASSUPA) has brought a complaint for an indefinite amount against the Company and other companies seeking the restoration of the environment to the state prior to the exploration, exploitation, production, storage and transportation of hydrocarbon works conducted by the plaintiffs and the prevention of alleged future environmental impacts on certain areas in the Austral Basin. The National Government and the Provinces of Santa Cruz and Tierra del Fuego have been summoned as third parties. The proceeding is at the complaint answer stage.

F- 118

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

ASSUPA has instituted a complaint before the CSJN against 10 companies, including the Company. The National Government and the Provinces of Buenos Aires, La Pampa, Mendoza, Neuquén and Río Negro have been summoned as third parties. The main claim seeks that the plaintiffs should be ordered to redress the alleged environmental damage caused by the hydrocarbon activity developed in the Neuquina Basin and to set up the environmental restoration fund provided for by section 22 of the General Environmental Law. Subsidiarily, and in case restoration is not possible, it seeks the redress of the allegedly sustained collective damages for an amount estimated at US$ 547 million. The proceeding is in the complaint answer stage.

Fundación SurfRider Argentina has requested the performance of preliminary proceedings on account of alleged indications of environmental damage in the City of Mar del Plata. The plaintiff seeks the recomposition of the alleged environmental damage having collective impact, or the compensation for the alleged damages caused by all companies owning service stations in the coastal area of the City of Mar del Plata for an alleged fuel leakage from service stations’ underground storage tanks into the water, soil and marine system. The Foundation estimates damages in the amount of $ 200 million. The parties agreed on a stay of the procedural time limits to evaluate the possibility of reaching an agreement with some co-defendants. Subsequently, the partial agreement reached between the plaintiff and some co-defendants was ratified. On its part, the Company has requested to be severed from the proceeding as it does not currently own any service station. However, it should be noted that some service station owners (which have sued the Company), have submitted agreements entered into with the plaintiff for their ratification under the proceeding. Some of them have already been ratified —and the plaintiff was deemed to have partially waived the action and rights against the owners of these service stations and also against the Company regarding them—, whereas others are in the ratification stage.

15.4 Civil and Commercial Claims

The “Consumidores Financieros Asociación Civil Para Su Defensa” Association claimed from Petróleo Brasileiro S.A. a nominal amount of US$ 3,650 million as compensation for the share market value loss resulting from the “Lava Jato” operation and the so-called “Petrolão”, and sought to hold Pampa and certain directors serving during 2016 jointly and severally liable for the price paid by Pampa to acquire control of Petrobras Argentina S.A., alleging that such acquisition may have frustrated the enforcement in Argentina of a judgment potentially favorable to the plaintiff. Upon the failure to pay the arbitration fee, the Arbitration Court deemed the main action withdrawn. The plaintiff filed an extraordinary appeal before the Commercial Court of Appeals, which was ultimately denied. The plaintiff filed a complaint against this denial, which was dismissed by the CSJN in 2025, and the proceedings were concluded with a favorable outcome for the Company.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2025 where the related inflows of economic benefits are estimated to be probable by the Company.

F- 119

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

15.5 Administrative claims

CTLL (currently Pampa) filed two administrative litigation complaints against the Federal Government for breach of contract, the first one for the January 2016 - March 2016 period, and the second one for the April 2016 - October 2018 period. It is requested that CAMMESA’s decision regarding the renewal and recognition of costs associated with natural gas supply agreements be reversed and that, subsidiarily, sustained damages be compensated. On June 13, 2025, a judgment was rendered in favor of the Company, awarding it $ 62.8 million and $ 862.9 million for the January 2016–March 2016 and April 2016–October 2018 periods, respectively, plus interest. The judgment was challenged by the Federal Government, which filed its grounds for appeal, and the Company submitted its response. On December 23, 2025, the Federal Court of Appeals in Administrative Litigation upheld the Federal Government’s appeal and reversed the first-instance judgment. On February 11, 2026, the Company filed an extraordinary appeal against such decision before the CSJN.

Upon the determination of the expiration of the Veta Escondida block concession granted by the Province of Neuquén, the Company filed a declaratory judgment action to achieve certainty under the original jurisdiction of the CSJN pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. Currently, after the opinion rendered by the National Attorney General, the proceeding is pending judgment by the CSJN.

On March 31, 2021, the Company submitted a Preliminary Administrative Claim (RAP) against the National Ministry of Economy (MECON) to claim the owed amount, plus the applicable interest, assumed by the Federal Government during the term of validity of PEN Executive Order No. 1,053/18 on account of the exchange difference between the price of the gas purchased by gas distributors and that recognised in their final tariffs during the April 2018 - March 2019 period. Upon the expiration of the term for MECON to state its position on the RAP, the Company brought a complaint against the Federal Government, which was timely answered. The case is currently open for evidence.

15.6 Civil and Commercial Claims

EcuadorTLC S.A. (currently PB18), in its capacity as assignee of the Ecuadorian company Petromanabí S.A., filed an international arbitration proceeding against the Republic of Ecuador seeking the payment of 12% of the Settlement Value, the latter pursuant to the terms of the Hydrocarbon Exploration and Crude Oil Exploitation Participation Agreement in Block 18 entered into on December 19, 1995 and/or the Hollín Common Field Unified Exploitation Operating Agreement executed on August 7, 2002 and amendments. The arbitration is conducted according to the Arbitration Rules of the United Nations Commission on International Trade Law, the applicable law is Ecuadorian law, and the seat of arbitration is the City of Santiago de Chile. In 2021, the first stages of the international arbitration proceeding have already begun. As of the issuance of these Consolidated Financial Statements, the arbitration proceeding is ongoing.

During 2025, The Company filed a claim against ENARSA for breach of the agreements entered into under the GasAr Plan framework seeking payment of certain gas supply invoices due as of February 2025 in the amount of $ 22,534 million, plus interest. The case is currently at its initial stage.

F- 120

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: RELATED PARTIES´ TRANSACTIONS

16.1 Balances with related parties


As of December 31, 2025	Trade receivables	Other receivables	Trade payables
As of December 31, 2025	Current	Current	Current
Associates and joint ventures
TGS	8	4	16
Other related parties
SACDE	-	-	13
	8	4	29

As of December 31, 2024	Trade receivables	Other receivables		Trade payables
As of December 31, 2024	Current	Non-current	Current	Current
Associates and joint ventures
TGS	10	4	8	11
Other related parties
SACDE	-	-	3	2
	10	4	11	13

F- 121

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: (Continuation)

16.2 Operations with related parties


Operations for the year	Sales of goods and services ⁽¹⁾			Purchases of goods and services ⁽²⁾			Fees and compensation for services ⁽³⁾			Other operating expenses ⁽⁴⁾
Operations for the year	2025	2024	2023	2025	2024	2023	2025	2024	2023	2025	2024	2023
Associates and joint ventures
CTB	2	2	2	-	-	-	-	-	-	-	-	-
TGS	54	51	42	(98)	(76)	(53)	-	-	-	-	-	-
Transener		-	-	(5)	-		-	-		-	-
Other related parties
Fundación	-	-	-	-	-	-	-	-	-	(2)	(2)	(2)
SACDE	-	-	-	(223)	(103)	(65)	(3)	-	-	-	-	-
Salaverri, Dellatorre, Burgio & Wetzler	-	-	-	-	-	-	-	(1)	(1)	-	-	-
	56	53	44	(326)	(179)	(118)	(3)	(1)	(1)	(2)	(2)	(2)

⁽¹⁾

Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas.

⁽²⁾

Correspond to natural gas transportation services and other services imputed to cost of sales for US$ 99 million, US$ 76 million and US$ 53 million and infrastructure works contracted to SACDE and Transener imputed in property, plant and equipment for US$ 227 million, US$ 103 million and US$ 65 million, of which US$ 57 million, US$ 21 million and US$ 15 million correspond to fees and general expenses calculated on the costs incurred by SACDE and/or Pampa to carry out these for the years ended December 31, 2025, 2024 and 2023, respectively.

⁽³⁾

Disclosed within administrative expenses.

⁽⁴⁾

Corresponds mainly to donations.

F- 122

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: (Continuation)

Operations for the year	Financial income ⁽¹⁾			Dividends collection			Dividends distributed
Operations for the year	2025	2024	2023	2025	2024	2023	2025	2024	2023
Associates and joint ventures
CIESA	-	-	-	45	-	-	-	-	-
Citelec	-	-	-	25	-	-	-	-	-
OCP	-	-	-	-	9	-	-	-	-
TGS	1	1	2	-	-	-	-	-	-
Other related parties
EMESA	-	-	-	-	-	-	(1)	-	(1)
	1	1	2	70	9	-	(1)	-	(1)

⁽¹⁾	Corresponds mainly to financial leases and accrued interest on borrowings granted.

F- 123

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: (Continuation)

16.3 Key management personnel remuneration

The total remuneration accrued in favor of Directors and Executive Officers during the fiscal years ended December 31, 2025, 2024 and 2023 amounts to US$ 20 million (US$ 6 million for directors’ and syndics’ fees and US$ 14 million for Stock Compensation Plans and Compensation Agreements), US$ 67 million (US$ 6 million for directors’ and syndics’ fees and US$ 61 million for Stock Compensation Plans and Compensation Agreements), and US$ 44 million (US$ 7 million for directors’ and syndics’ fees and US$ 37 million for Stock Compensation Plans and Compensation Agreements), respectively.

NOTE 17: INVESTMENT COMMITMENTS

17.1 Development and evacuation projects in Vaca Muerta

Rincón de Aranda’s development

The Company focuses its investments in the development and exploitation of its unconventional oil and gas reserves in the Rincón de Aranda block in the Vaca Muerta formation. The development plan began in August 2024, with an active well drilling campaign and the construction of facilities and treatment plants. Investments are estimated to exceed US$ 1.5 billion, aiming to reach a production of 45 kbbl/day by the end of 2027.

On July 1, 2025, Pampa Energía —through its “Pampa Energía S.A. - Sucursal Dedicada Midstream RDA” Dedicated Branch, established on May 12, 2025 by the Company’s Board of Directors, submitted its application to opt into the RIGI to develop an oil and gas treatment plant at its Rincón de Aranda field. The project contemplates an estimated US$ 376 million investment, and its entry into operation is scheduled for 2026.

Transportation agreements

Pursuant to its equity interest in VMOS (see Note 5.1), the Company entered into a firm transportation agreement for 50,000 bpd, as well as storage and dispatch capacity through the project facilities (Allen–Punta Colorada section), which will enable the evacuation of incremental production from the Rincón de Aranda block.

The above evacuation capacity is supplemented by the firm transportation agreement entered into with Oldelval in 2022, providing 6,302 bpd of dispatch capacity on the Allen–Puerto Rosales pipeline section, effective through the end of the term of Oldelval’s transportation concession in 2037. Additionally, the Company entered into an agreement with Oiltanking Ebytem to increase dispatch capacity by 6,302 bpd and storage capacity by 37,789 barrels, exclusively for crude oil exports.

Lastly, in 2024, the Company entered into a firm transportation agreement with YPF S.A. for the Loma Campana-Allen pipeline section, providing transportation capacity of 6,302 bpd in Phase 1 and 56,608 bpd in Phase 2.

F- 124

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 17: (Continuation)

17.2 Investment commitment for the exploration and exploitation of hydrocarbons

As of the issuance of these Consolidated Financial Statements, the Company has committed investments until 2027 for an estimated total amount of US$ 43 million, including commitments associated with the participations detailed in Note 5.2.

NOTE 18: INCIDENTS AT HINISA

On January 11, 2025, there was a strong storm in San Rafael, Province of Mendoza, with rainfall exceeding historical records causing an extraordinary flooding of the Atuel River, inflicting serious damage along the Atuel Canyon. The affected facilities included the Nihuil II and III plants, which, severely damaged, were forced out of service.

HINISA completed the clean-up and remediation works at the power plants on October 2, 2025, and currently continues working on repairs to perimeter and building enclosures and the conditioning of the high-voltage transmission system and the power supply for auxiliary services within the plants. In addition, HINISA completed the sorting of materials and tools recovered from the incident, and their disposition concluded in December 2025.

In addition, HINISA and the insurance companies have engaged Hidronor Ingeniería y Servicios S.A. and Restore Mitigation Services, respectively, to carry out the process of identifying and assessing damage to the affected equipment. The resulting reports were received by HINISA and submitted to the Granting Authority.

During the year ended December 31, 2025, HINISA recorded US$ 5 million losses corresponding to incident-related costs.

In addition, HINISA continued proceedings with the adjusters appointed by the insurance companies and, as of December 31, 2025, has received advance payments of US$ 7.1 million, recognized under the insurance recovery line item, to carry out the cleaning and remediation tasks necessary to determine the final damages and costs. Moreover, HINISA is negotiating an additional US$ 2.4 million advance applicable to loss of profit coverage.

As of the date of issuance of these Consolidated Financial Statements, the final cost of the incident and the amount of insurance proceeds have not yet been assessed by HINISA.

NOTE 19: LEASES

19.1 Lessee

The Company leases a key part for thermal power plants operation for a 20-year term and has entered into certain oil services agreements (mainly gas compression services) which, considering their characteristics, contain the lease of the assets for the rendering of the services with terms ranging between 2 and 6 years.

The terms of the lease agreements are negotiated on an individual basis and comprise a broad range of terms and conditions.

The evolution of right-of-use assets and lease liabilities recognised as of December 31, 2025 and 2024 is disclosed below:

F- 125

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 19: (Continuation)

19.1.1 Right of use assets

Schedule of right of use assets
	Original values
Type of good	At the beginning	Increases	Decreases	Transfers	At the end
Machinery and equipment	25	45	(6)	-	64
Total at 12.31.2025	25	45	(6)	-	64
Total at 12.31.2024	33	-	-	(8)	25


	Amortization
Type of good	At the beginning	For the year	Decreases	At the end
Machinery and equipment	(14)	(17)	3	(28)
Total at 12.31.2025	(14)	(17)	3	(28)
Total at 12.31.2024	(12)	(2)	-	(14)


	Net book values
Type of good	At 12.31.2025	At 12.31.2024
Machinery and equipment	36	11
Total at 12.31.2025	36
Total at 12.31.2024		11

F- 126

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 19: (Continuation)

19.1.2 Lease liabilities

Schedule of lease liabilities
	12.31.2025	12.31.2024
At the beginning of the year	15	18
Increases	45	-
Result from measurement at present value ⁽¹⁾	3	2
Decrease due to sale of equity interests in areas	(2)	-
Transfers	-	(1)
Reversal of unused amounts	(1)	-
Payments	(24)	(4)
At the end of the year	36	15

⁽¹⁾	Included in Other financial results.

As of December 31, 2025 and 2024, this liability is disclosed under Other current payables in the amounts of US$ 21 million and US$ 4 million and Other non-current payables for US$ 15 million and US$ 11 million, respectively.

The following table includes an analysis of the Company lease liabilities, grouped according to their maturity dates. The amounts shown in the table are the contractual undiscounted cash flows:


			12.31.2025
Less than three months			6
Three months to one year			15
One to two years			7
Two to three years			2
Three to four years			2
Four to five years			2
More than five years			10
Total			44

19.1.3 Short-term or low value leases

As of December 31, 2025, 2024 and 2023, the Company has recognised costs and administrative expenses in the amounts of US$ 5 million, US$ 4 million and US$ 6 million respectively, on account of lease payments associated with short-term leases.

F- 127

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 19: (Continuation)

19.2 Lessor

19.2.1 Financial leases

Corresponding to the financing granted to TGS for the sale of certain property, plant and equipment belonging to the Oil & Gas business segment. This agreement was entered into on August 11, 2016 and consists of the collection of 119 monthly consecutive installments of US$ 623 thousand, without considering taxes, and a purchase option for a like amount payable at the end of the 120 months of the contract life.

As of December 31, 2025 and 2024, this receivable is disclosed under Other current receivables in the amounts of US$ 4 million and US$ 7 million, respectively and under Other non-current receivables in the amount of US$ 4 million as of December 31, 2024.

The following table includes an analysis of the Company receivable, grouped according to its maturity dates. The amounts shown in the table are the contractual undiscounted cash flows:


			12.31.2025
Less than three months			2
Three months to one year			2
Total			4

19.2.2 Operating leases

The Company has executed lease agreements to install commercial and administrative offices in Pampa Energía S.A.’s building, located in Maipú 1, Autonomous City of Buenos Aires, for three to five years terms.

Future minimum collections from operating leases as of December 31, 2025 are detailed below:


			12.31.2025
Three months to one year			1
Total			1

Total income from operating leases amounts to US$ 1 million for each of the fiscal years ended December 31, 2025, 2024 and 2023.

F- 128

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 20: TERMINATION OF HYDROELECTRIC CONCESSIONS

On June 1, 2024, the HINISA concession contract expired. Through Executive Orders No. 1,021/24 and 1,085/24 and SE Resolutions No. 98/24 and 383/24, the Province of Mendoza and the SE established a 12-month transition period for HINISA’s concession.

On October 19, 2024, HIDISA’s concessions —one for the assets and the use of water resources, granted by the Province of Mendoza, and the other for the generation of electric power, granted by the Federal Government— expired. Through Executive Order No. 2,096/24, the Province of Mendoza set a 12-month transition period. At the national level, through SCEyM Resolution No. 01/24, the Secretariat of Energy and Mining Coordination established a transition period until June 1, 2025.

On March 8, 2025, the Federal Government and the province of Mendoza signed an agreement to jointly conduct the national and international open call for tenders for the concession of the Diamante and Nihuiles Hydroelectric Complexes as a single business unit. The coordination and execution of this tender process was delegated to the Public Enterprises Transformation Agency, which, within a maximum 60 business days’ period, would transfer 51% of the share package of the company becoming the concessionaire and owner of the assets.

On May 26, 2025, Provincial Law No. 9,630 was published, declaring a state of emergency for the Los Nihuiles Hydroelectric System over a 14-month period from its enactment. The Law provides for the continuity of the transition period until verification of compliance with the obligations arising from the concession contract with HINISA, without prejudice to any authorizations that must be granted by the Federal Government.

It is worth highlighting that HINISA has fully and timely complied with its obligations throughout the term of the concession contract and the transition period; and that, as of the date of issuance of these Consolidated Financial Statements, the Federal Government has not issued any statement or granted the required authorizations.

In these circumstances, at the end of the contractual transition period on June 1, 2025, HINISA notified both the Ministry of Energy and Environment of the Province of Mendoza and the SE that the extension of the transition period beyond the term stipulated in the contract requires an agreement with the concessionaire. However, to protect the concession’s assets, avoid affecting the supply of electricity in the WEM and ensure the safety of property and persons, HINISA informed that it would continue operating the Los Nihuiles Hydroelectric Complex, without this implying consent to any unilateral extension of the transition period, the assumption of additional obligations or responsibilities, or the waiver of its rights.

Finally, it is worth highlighting that HINISA is willing to proceed with the assets’ handover as soon as the competent authorities so decide and/or to execute the necessary agreements given this extraordinary situation.

On the other hand, on June 5, 2025, SE Resolution No. 240/25 extended HIDISA’s concession transition period until October 19, 2025. On October 20, 2025, through SE Resolution No. 398/25, it was proposed HIDISA to opt into the concession extension until June 30, 2026, subject to the terms of the original agreement and new provisions, including, among others, the update of guarantees, the waiver of claims against the Government arising from changes in the remuneration scheme, and the payment of royalties to the Province of Mendoza. On November 19, 2025, HIDISA confirmed its opt-in, proposing certain amendments, which, as of the date of issuance of these Consolidated Financial Statements, have not been challenged by the SE.

F- 129

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 21: DOCUMENTATION KEEPING

In compliance with CNV General Resolution No. 629/14, the Company, infoms having sent non-sensitive work papers and information corresponding to the periods not covered by the statute of limitations for their keeping in the Administración de Archivos S.A. (AdeA)’s data warehouse located at Ruta 36, km 34.5, Florencio Varela, Province of Buenos Aires.

A list of the documentation delivered for storage, as well as the documentation provided for in Article 5.a.3) Section I, Chapter V, Title II of the PROVISIONS (2013 regulatory provisions and amending rules), is available at the Company headquarters.

NOTE 22: OIL AND GAS RESERVES (Information not covered by the auditors’ report)

The table below presents the estimated proved reserves of oil (including crude oil, condensate and LNG) and natural gas, by geographic area as of December 31, 2025.

Schedule of proved reserves
	Proved Reserves

	Proved Developed		Proved Undeveloped		Total Proved

	Oil and LNG ⁽¹⁾	Natural Gas ⁽²⁾	Oil and LNG ⁽¹⁾	Natural Gas ⁽²⁾	Oil and LNG ⁽¹⁾	Natural Gas ⁽²⁾



Argentina	23,993	23,055	32,972	17,525	56,965	40,580


Total at 12.31.2025	23,993	23,055	32,972	17,525	56,965	40,580

⁽¹⁾	In thousands of barrels.

⁽²⁾	In millions of cubic meters.

F- 130

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2025, 2024 and 2023 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 23: SUBSEQUENT EVENTS

RIGI amendment

Pursuant to Executive Order No. 105/26, dated February 19, 2026, the deadline to apply for the RIGI was extended until July 8, 2027. In addition, the decree expanded the list of eligible projects to include, among others: (i) the construction of infrastructure for the collection, treatment, processing, fractionation, and liquefaction of natural gas, as well as the transportation of natural gas intended for the export of liquefied natural gas; (ii) the exploration and production of new onshore liquid and gaseous hydrocarbon developments located in areas that, at the time of submitting the application for adhesion, do not have existing investments in exploration or production activities; and (iii) the exploration and production of new offshore liquid and gaseous hydrocarbon developments. Additionally, it set a minimum investment threshold of US$ 600 million for onshore developments and US$ 200 million for offshore developments.

Where activities not covered by the RIGI coexist within the same hydrocarbon area, segregation and traceability must be ensured through independent measurement systems and the VPU must be the exclusive owner of the assets, rights, and operations associated with the RIGI-eligible project.

F- 131

SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES (UNAUDITED)

The following information on oil and gas activities has been prepared in accordance with the methodology prescribed by ASC No. 932 "Extractive Activities - Oil and Gas". This information includes the Company’s and its subsidiaries’ oil and gas production activities.

Costs incurred

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as of December 31, 2025, 2024 and 2023. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory well equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.

	Consolidated companies (Argentina)
	12.31.2025	12.31.2024	12.31.2023
	(in million of US$)
Acquisition of properties
Proved	-	-	-
Unproved	-	-	-
Total property acquisition	-	-	-
Exploration	32	6	3
Development	965	348	541
Total costs incurred	997	354	544

Capitalized cost

The following table presents the capitalized costs as of December 31, 2025, 2024 and 2023, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

	Consolidated companies (Argentina)
	12.31.2025	12.31.2024	12.31.2023
	(in million of US$)
Proved properties
Equipment, camps and other facilities	430	518	520
Mineral interests and wells	2,160	1,490	1,362
Other uncompleted projects	525	168	222
Unproved properties	50	17	32
Gross capitalized costs	3,165	2,193	2,136
Accumulated depreciation	(1,269)	(1,010)	(998)
Total net capitalized costs	1,896	1,183	1,138

S-1

Results of operations

The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2025, 2024 and 2023. Income tax for the years presented was calculated utilizing the statutory tax rates.

	Consolidated companies (Argentina)
	12.31.2025	12.31.2024	12.31.2023
	(in million of US$)
Revenue	740	623	563
Intersegment sales	122	107	103
Argentine Natural Gas Production Promotion Plan	34	44	55

Production costs, excluding depreciation
Operating costs and others	(299)	(269)	(237)
Royalties	(109)	(93)	(88)
Total production costs	(408)	(362)	(325)
Exploration expenses	-	(21)	(7)
Depreciation, depletion and amortization	(292)	(237)	(166)
Results of operations before income tax	196	154	223
Income tax	(69)	(54)	(78)
Results of oil and gas operations	127	100	145

Estimated oil and gas reserves

Proved reserves estimated quantities of oil (including crude oil, condensate and natural gas liquids) and natural gas, which available geological and engineering data demonstrates with reasonable certainly to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.

The Company believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC rules, which were issued by the SEC at the end of 2008.

The Company estimates its reserves at least once a year. The Company reserves estimation as of December 31, 2025 was audited by Gaffney, Cline & Associates. Gaffney, Cline & Associates is an independent petroleum engineering consulting firm. The independent audit covered 99% of the estimated reserves located in areas operated and non-operated by the Company. Gaffney, Cline & Associates audited the proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S-X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC Topic 932 of the FASB. We provided all information required during the course of the audit process to Gaffney, Cline & Associates’ satisfaction.

S-2

Proved reserves are estimated by the Company’s reservoir engineers. Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be accurately measured, and the reserve estimation depends on the quality of available information and the interpretation and judgment of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.

The following table sets forth the estimated oil (including crude oil, condensate and natural gas liquids) and natural gas (including natural gas estimated to be consumed as fuel in operations) net proved reserves as of December 31, 2025, 2024 and 2023:

	Reserves as of December 31, 2025		Reserves as of December 31, 2024		Reserves as of December 31, 2023
	Crude oil, condensate and natural gas liquids	Natural Gas	Crude oil, condensate and natural gas liquids	Natural Gas	Crude oil, condensate and natural gas liquids	Natural Gas

Reserves category	(million of barrels)	(billion of cubic feet)	(million of barrels)	(billion of cubic feet)	(million of barrels)	(billion of cubic feet)

PROVED Developed	24.0	814.2	4.4	741.6	7.6	724.8

PROVED Undeveloped	33.0	618.9	12.8	542.5	4.0	399.5

Total proved reseves (developed and undeveloped)	57.0	1,433.1	17.2	1,284.2	11.6	1,124.2

S-3

The following table sets forth the reconciliation of our reserves data between December 31, 2023, December 31, 2024 and December 31, 2025:

	Consolidated companies (Argentina)
	Crude Oil, Condensate and natural gas liquids	Natural Gas
Proved reserves (developed and undeveloped)	(in thousand of barrels)		(in millions of cubic feet)
Reserves as of December 31, 2022	10,937	1,010,492
Increase (decrease) attributable to:
Revisions of previous estimates	(414)	(64,771)
Improved recovery	95	28
Extension and discoveries	2,211	301,453
Purchases of proved reserves in place	527	5,381
Sales of proved reserves in place	(7)	(337)
Year's production	(1,763)	(128,001)
*Reserves as of December 31, 2023 ()**	11,586	1,124,245
Increase (decrease) attributable to:
Revisions of previous estimates	(5)	(10,011)
Improved recovery	253	56
Extension and discoveries	9,167	321,665
Sales of proved reserves in place	(2,003)	(365)
Year's production	(1,796)	(151,417)
*Reserves as of December 31, 2024 ()**	17,201	1,284,172
Increase (decrease) attributable to:
Revisions of previous estimates	1,967	76,280
Extension and discoveries	43,106	221,718
Sales of proved reserves in place	(947)	(700)
Year's production	(4,361)	(148,363)
*Reserves as of December 31, 2025 ()**	56,967	1,433,107

(*) Includes proved developed reserves:
As of December 31, 2023	7,592	724,775
As of December 31, 2024	4,409	741,634
As of December 31, 2025	23,994	814,199

S-4

Standardized measure of discounted future net cash flows

The following table discloses estimated future cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate, natural gas liquids and natural gas (excluding natural gas estimated to be consumed as fuel in operations). As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas, such future net cash flows were estimated using the average first day of the month price during the twelve-month period for 2025, 2024 and 2023 using a 10% annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the Company and operators of the fields in which the Company has an interest. The future income tax was calculated by applying the statutory tax rate in effect in the respective countries in which we have interests, as of the end of each reporting period.

This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Company’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed bellow. For all these reasons, this information does not necessarily indicate the perception the Company has on the discounted future net cash flows from the reserve of hydrocarbons.

	12.31.2025	12.31.2024	12.31.2023
	(in million of US$)
Future cash inflows	8,202	5,695	5,255
Future production costs	(3,228)	(2,619)	(2,122)
Future development and abandonment costs	(1,259)	(977)	(675)
Future income tax	(797)	(322)	(618)
Undiscounted future net cash flows	2,918	1,777	1,840
10% annual discount	(1,241)	(632)	(677)
Standarized measure of discounted future net cash flows	1,677	1,145	1,163

S-5

Changes in the standardized measure of discounted future net cash flows

The following table discloses the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2025, 2024 and 2023:

	Consolidated companies (Argentina)
	12.31.2025	12.31.2024	12.31.2023
	(in million of US$)
Standarized measure at the beginning of year	1,145	1,163	1,141
Changes related to Oil & Gas Activities:
Sales Net of Production costs	(488)	(412)	(396)
Net Change in sales prices, net of future production costs	108	(353)	(182)
Changes in future development costs	(1,193)	(582)	(464)
Extensions, discoveries and improved recovery, net of futures production and assocciated costs	1,342	581	541
Development costs incurred	965	348	541
Revisions of quantity estimates	154	(3)	(101)
Purchase of reserves in place	-	-	22
Sale of reserves in place	(10)	(31)	-
Net change in income tax	(311)	176	(75)
Accretion of discount	137	153	148
Changes in production rates	(224)	56	(17)
Other changes	52	49	5
Standarized measure at the end of year	1,677	1,145	1,163

S-6