20-F

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, 2022

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:

1,379,765,666 outstanding shares of common stock, par value Ps.1.00 per share, excluding 3,878,939 treasury shares.

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

☒ Yes ☐ No

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

☐ Yes ☒ No

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

☒ Yes ☐ No

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

☒ Yes ☐ No

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

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	7
Item 2.	Offer Statistics and Expected Timetable	7
Item 3.	Key Information	7
EXCHANGE RATES		7
RISK FACTORS		8
Item 4.	Information on the Company	43
HISTORY AND DEVELOPMENT OF THE COMPANY		43
OUR BUSINESS		44
Organizational structure		51
Our Generation Business		53
Our Oil and Gas Business		61
Our Petrochemicals Business		75
Our Holding and Other Business		76
IT and Cybersecurity		81
Quality, Health, Safety and Environment		82
Corporate Responsibility		85
Property, Plant and Equipment		88
Insurance		88
Patents and Trademarks		88
THE ARGENTINE ENERGY SECTOR		89
Item 4A.	Unresolved Staff Comments	119
Item 5.	Operating and Financial Review and Prospects	119
Item 6.	Directors, Senior Management and Employees	147
Item 7.	Major Shareholders and Related Party Transactions	159
Item 8.	Financial Information	161
CONSOLIDATED FINANCIAL STATEMENTS		161
LEGAL PROCEEDINGS		161
DIVIDENDS		166
SIGNIFICANT CHANGES		166
Item 9.	The Offer and Listing	166
TRADING HISTORY		166
THE ARGENTINE SECURITIES MARKET		168
Item 10.	Additional Information	173
MEMORANDUM AND ARTICLES OF ASSOCIATION		173
MATERIAL CONTRACTS		180
EXCHANGE CONTROLS		180
TAXATION		187
DOCUMENTS ON DISPLAY		195
Item 11.	Quantitative and Qualitative Disclosures about Market Risk	196
Item 12.	Description of Securities Other than Equity Securities	196
Item 13.	Defaults, Dividend Arrearages and Delinquencies	198
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	198
Item 15.	Controls and Procedures	198
Item 16A.	Audit Committee Financial Expert	199

Item 16B.	Code of Ethics	199
Item 16C.	Principal Accountant Fees and Services	199
Item 16D.	Exemptions from the Listing Standards for Audit Committees	200
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	201
Item 16F.	Change in Registrant’s Certifying Accountant	202
Item 16G.	Corporate Governance	202
Item 16H.	Mine Safety Disclosure	206
Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.	206
Item 17.	Financial Statements	207
Item 18.	Financial Statements	207
Item 19.	Exhibits	207

PRESENTATION OF INFORMATION

This document comprises Pampa’s annual report on Form 20-F for the year ended December 31, 2022 . This annual report was approved by our Board of Directors by resolution following its meeting held on April 28, 2023. 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, 2022 and 2021, 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, 2022, 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 International Financial Reporting Standards (“IFRS”) 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 9, 2023 and by the Shareholder’s meeting held on April 26, 2023.

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 therefore 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, 2022, 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, 2022 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, 2022. 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—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. 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 on 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:

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

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

- changes in the price of hydrocarbons and their derivatives;

- changes in the price of power and other related services;

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

- our ability to renew certain 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;

- the treatment of the tariff update according to RTI;

- electricity shortages;

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

- 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;

- general economic, social and political conditions in Argentina, and other regions where we, our subsidiaries, associates or joint ventures operate, such as the rate of economic growth, fluctuations in exchange rates of the Peso or inflation;

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

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

- competition in the hydrocarbon sector and related industries;

- obsolescence of products manufactured in our petrochemical facilities;

- export limitations to our production;

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

- the impact of high rates of inflation on our costs;

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

- changes to our capital expenditure plans;

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

- deterioration in regional and local business and economic conditions in or affecting Argentina;

- any potential negative consequences arising in connection with our potential mergers, acquisitions, divestitures or other corporate reorganizations;

- changes in general economic, business, political or other conditions in Argentina or changes in general economic or business conditions in other Latin American countries;

- the effects of the Covid-19 pandemic and any subsequent mandatory regulatory restrictions or containment measures imposed in response thereto;

- risks related with cybersecurity events, including potential cyberattacks;

- the risks associated with climate change and severe weather events;

- the transition process and phasing out of LIBOR; and

- other risks factors discussed under “Item 3. Risk Factors.”

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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.

3 

GLOSSARY

Glossary of certain terms used in this Annual Report

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

· “ADR”: American Depositary Receipt;

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

· “AFIP”: Federal Administration of Public Revenue (Administración Federal de Ingresos Públicos);

· “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. 27/2018;

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

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

· “Banco Nación”: Banco de la Nación Argentina;

· “BASE”: Buenos Aires Stock Exchange;

· “bbl”: Barrel of crude oil;

· “BCL”: Business Corporation Law;

· “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.);

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

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

· “CC”: Combined Cycle;

· “CENCH”: unconventional hydrocarbon exploitation concession;

· “CIESA” Compañía de Inversiones de Energía;

· “CISA”: Comercializadora e Inversora S.A. (former Pampa Comercializadora S.A.);

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

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

· “CMIEE”: Average Incremental Charge of Surplus Demand (Cargo Medio Incremental de la Demanda Excedente);

· “CNG”: compressed natural gas;

· “CNV”: Comisión Nacional de Valores;

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

· “Covid-19”: the novel coronavirus, pneumonia originating in Wuhan, China;

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

· “CPI”: Consumers Prices Index;

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

· “CTB”: CT Barragán S.A. (former Parques Eólicos Argentinos S.A.);

· “CTEB”: Central Térmica Ensenada de Barragán;

· “CTIW”: Central Térmica Ingeniero White;

· “CTG”: Central Térmica Güemes S.A.;

· “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;

· “DoP”: delivery or pay;

· “Pampa Bloque18”: Pampa Bloque18 S.A. (former EcuadorTLC S.A.);

· “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;

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

· “ENOPSA”: Energía Operaciones ENOPSA S.A. (former Petrobras Energía Operaciones Ecuador S.A.);

· “Energy Plus” or “Energía Plus”: a program under SE Resolution 1,281/2006;

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

· “FCA”: United Kingdom Financial Conduct Authority;

· “FO or GO”: Fuel Oil or Gas Oil;

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· “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;

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

· “GDP”: Gross Domestic Product;

· “GHG” Greenhouse gas;

· “Greenwind”: Greenwind S.A.;

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

· “GT”: gas turbine;

· “GU”: Large Users (Grandes Usuarios);

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

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

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

· “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 Money Fund;

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

· “Independent Reserves Engineers Firm”: Gaffney, Cline & Associates;

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

· “IREC”: International Renewable Energy Certificates;

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

· “LPG”: liquefied petroleum gas;

· “MAE”: Mercado Abierto Electrónico S.A.

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

· “MAT ER”: 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);

· “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”: Oleoducto de Crudos Pesados Ltd.;

· “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.;

· “PDVSA”: Petróleos de Venezuela S.A.;

· “PEA”: Parque Eólico Arauco II

· “PEB”: Pampa Energía Bolivia S.A. (former “PBI” - Petrobras Bolivia Internacional S.A.);

· “PEMC”: Parque Eólico Ingeniero Mario Cebreiro;

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

· “PEO”: Petrobras Energía Operaciones S.A.;

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

· “Petrobras”: Petroleo Brasileiro S.A;

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

· “PGSM”: Puerto General San Martin;

· “PISA”: Pampa Inversiones S.A.;

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

5 

· “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 Gaffney, Cline & Associates;

· “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;

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

· “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);

· “SGE”: Former Government Secretariat of Energy (former Ministry of Energy (former ME&M)) (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;

· “SOFR”: Secured Overnight Financing Rate;

· “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 Stated of America;

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

· “UTEs”: joint operations (Unión Transitoria);

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

· “VAT”: Value Added Tax;

· “WEM”: Wholesale Electricity Market;

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

· “WEMTF”: Wholesale Electricity Market of Tierra del Fuego;

· “YPF”: YPF S.A.

6 

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,
2018	41.250	18.410	28.093	37.700
2019	60.400	36.900	48.234	59.890
2020	84.150	59.815	70.599	84.150
2021	102.720	84.700	95.161	102.720
2022	177.160	103.000	130.810	177.160
Month
January 2023	187.000	178.150	182.245	187.000
February 2023	197.150	187.290	191.890	197.150
March 2023	209.010	197.570	203.110	209.010
April 2023(3)	222.000	210.370	216.206	222.000

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 27, 2023.

Pursuant to Argentine law, in case we pay dividends, we are required to pay them in cash in Pesos, and 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.

7 

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

· A global or regional financial crisis and unfavorable credit and market conditions may negatively affect our liquidity, customers, business and operational results

· The Argentine economy is a vulnerable economy and any significant decline may adversely affect our business, operational results and financial condition

· The impact of the next congressional and presidential elections on the future economic and political environment of Argentina remains uncertain

· The Argentine economy is vulnerable to external shocks that could be caused by significant economic difficulties of Argentina’s major regional trading partners, or by more general “contagion” effects. Such external shocks and “contagion” effects could have a material adverse effect on Argentina’s economic growth, and consequently, on our operational results and financial condition

· The ongoing conflict between Russia and Ukraine could adversely affect the global economy, the Argentine economy and our operational results and financial condition

· Economic and political developments in Argentina, and future policies of the Argentine Government may adversely affect the Argentine economy and the sectors in which we perform our activities

· Exchange rate volatility may adversely affect the Argentine economy

· If the high levels of inflation continue, the Argentine economy and our operational results could be adversely affected

· 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 and, consequently, affect our business, results of our operations and growth prospects

· The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operations

· 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

·        There is no certainty as to the effects that the measures that the Argentine Government may adopt in order to resolve the crisis in the energy sector will have on our business operations, financial condition or results of operations

· The Argentine economy and finances may be adversely affected as a consequence of a decrease in the international prices of commodities

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

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

· The Argentine Government has intervened in the electricity sector in the past, and may continue intervening to adopt, among others, measures in connection with tariffs on public services

Risks Relating to our Company

· We operate a material portion of our business pursuant to public concessions granted by the Argentine Government, the revocation or termination of which would have a material adverse effect on our business

· 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 that could have a material adverse effect on our business

· In the event of an accident or other event not covered by our insurance policies, we could face significant losses that could result in a material adverse effect on our business and operational results

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

· If we are not able to effectively hedge our currency risk in full and a devaluation of the Argentine Peso occurs, our results of operations and financial condition could be materially adversely affected

· We and our affiliates are involved in various legal proceedings which could result in unfavorable rulings against us

· Downgrades in our credit ratings could have negative effects on our funding costs and business operations

· Cybersecurity events, such as a cyber-attack 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

· CAMMESA could alter and delay payments to power generators and fuel producers

· 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

· Our businesses are subject to risks arising from natural disasters, catastrophic accidents and terrorist attacks. Additionally, our businesses are subject to the risk of mechanical or electrical failures and any resulting unavailability may affect our ability to fulfill our contractual commitments and thus adversely affect our business and financial performance

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

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

· We and our subsidiaries continue evaluating investment projects to expand our activity, which could imply an increase in our indebtedness

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

· Uncertainty relating to the LIBOR transition process and the phasing out of LIBOR may adversely affect us

Risks Relating to Our Generation Business

· There are electricity transmission constraints in Argentina that may prevent us from dispatch, which could materially adversely affect the financial results of our generation business

· If the demand for energy is increased suddenly, current levels of power generation and the difficulty in increasing the capacity of transmission and distribution companies in a short or medium term could adversely affect the Company

· Changes in certain regulations may require the adjustment of the facilities of our power plants that may require new investments or may affect the dispatch of our generators

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· We may be unable to collect amounts due, or to collect them in a timely manner, from CAMMESA and other customers in the electricity sector, which would have a material adverse effect on our financial condition and operational results

· New measures encouraging renewable energy generation projects may affect our generation sales

· Our ability to generate electricity in our thermal generation plants depends on the availability of natural gas (and other fuels), and fluctuations in the supply or price of gas could materially adversely affect our operational results

· Penalties may be applied under our energy supply agreements with CAMMESA which may adversely affect the revenues derived from such contracts or from our generation units

· Penalties and or other sanctions may be applied for breaches to applicable regulation or for not having in a timely manner the required permits for the operation of our generation units, which may adversely affect the availability and revenues derived from our generation units

· A breach to our energy supply agreements with CAMMESA may, ultimately, cause the termination of such agreements, which could adversely affect our operational results

· A breach to our energy supply agreements with WEM Large Users may cause penalties or the termination of such agreements, which could adversely affect our operational results

· Revenues from Greenwind, PEPE II, PEPE III, PEPE IV and PEA depend on meteorological conditions and the ability to contract the energy to be produced by the wind farms to WEM Large Users

· Our ability to generate electricity at our hydroelectric generation plants may be negatively affected by poor hydrological conditions, which could, in turn affect our operational results

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

· We may no longer own a controlling interest in HINISA, if the Province of Mendoza sells its participation in HINISA

· We may not be able to extend the term of the concession agreements for HINISA, HIDISA and/or HPPL

· We could be exposed to third-party claims on real property utilized for our operations 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

· Our profits may be affected by our failure to fulfill the requirements of the Energy Plus Program or by the modification or the cancellation of such program

· The guarantees granted by the Company to its affiliates could be enforced, which could have an adverse effect on results of our operations

· Events that affected PEPE II and PEPE III or similar events may occur in our energy projects

· PEA wind turbines may present certain defects which may hinder their production

· 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

· If in the future we are not in a position to renew our PPAs or execute new PPAs, or if such PPAs are unilaterally modified or resolved, our results of operations and financial condition could be materially adversely affected

· Prohibitions or delays in obtaining the required permits and authorizations for new power generation projects may affect the estimated entry into commercial operations and affect the expected revenues from such projects. Moreover, penalties and fines may apply

· Electricity demand may be affected by price increases, which could lead power generators such as the Company to record lower revenues

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

Risks Relating 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

· Oil and gas reserves in Argentina are likely to decline

· 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 have affected and may continue to affect our operational results

· We may not be the operating partner in all of the joint arrangements (joint operations for accounting purposes) in which we participate, and actions undertaken by the operators in such joint arrangements could have a material adverse effect on the success of these operations

· We conduct most of the operations through joint arrangements (joint operations for accounting purposes), and our failure to resolve any material disagreements with our partners or to continue such joint arrangements could have a material adverse effect on the success of such operations

· Our failure to comply with our commitments to make certain investments could negatively affect our operational results

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

· The Argentine Government could alter and delay payments to natural gas producers under key government programs

· Unless we replace our oil and gas reserves, such reserves and production will deplete 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, health and safety matters

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

· The Company is exposed to contractions in the crude oil and natural gas demand and to contractions in the demand for any of their by-products

Risks Relating 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 and 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 growth rates, inflation rates, currency exchange rates, taxes, interest rates, and other local, regional and international events and conditions that may affect 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 and our subsidiaries 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.

A global or regional financial crisis and unfavorable credit and market conditions may negatively affect our liquidity, customers, business and operational results

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 (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 and, consequently, affect our business, results of our operations and growth prospects.” below). This was the case in 2008, when the global economic crisis led to a sudden economic decline in Argentina in 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 the Covid-19. The stock market crash, which began in late February 2020 and intensified throughout 2020 and 2021, affected many stock markets in the world. As a consequence of the Covid-19, the estimated contraction in the world’s economy for 2020 was 3.5% according to what both the IMF and the Organization for Cooperation and Economic Development expressed. Additionally, the IMF published that the impact of Covid-19 on the world’s economy affects both the supply and the demand side. On the supply side, the virus increases not only morbidity and mortality, but also the efforts and measures taken by governments and companies to combat these effects, which lead to restrictions in freedom of movement, higher operating costs due to the reduction in the supply chain and the tightening of credit. On the demand side, the uncertainty that the virus generates, precautionary behaviors, quarantine efforts and high financing costs all reduce the possibility of spending money. The Covid-19 pandemic has reached every region of the world and has resulted in widespread adverse impacts on the global economy. Different parts of the world are currently experiencing divergent virus case growth rates which leads to recoveries also diverging dangerously between and within countries. Although throughout 2022 and up to the date of this annual report the Covid-19 outbreak decreased significantly, the impact of Covid-19 on sectoral economic activity cannot be measured. According to a report published by the IMF in October 2022, despite the global recovery in 2021, the pandemic has continued to take an enormous health and socioeconomic toll, affecting lives and livelihoods everywhere. Inflation, which had already been rising in many countries as a result of supply-demand imbalances and policy support during the pandemic, is likely to remain high (See “—The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operations” below).

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 in Latin America, such as Brazil, may also have a negative impact on us and third parties with whom we do, or may do, business.

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The Argentine economy is a vulnerable economy and any significant decline may adversely affect our business, operational results and financial condition

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 and a stable rate of inflation, national employment levels and the circumstances of Argentina’s regional trade partners. The Argentine macroeconomic environment, in which we operate, remains vulnerable, as reflected by the following economic conditions: (i) according to the data published by the INDEC in 2022 and 2023, for the years ended December 31, 2021 and 2022, Argentina’s real GDP increased by 10.4% compared to the year ended December 31, 2020, and increased by 5.2% compared to the year ended December 31, 2021, respectively; (ii) continued increases in public expenditures have resulted and could continue to result in fiscal deficit and affect economic growth; (iii) inflation remains high and may continue at those levels in the future; (iv) investment as a percentage of GDP remains low to sustain the growth rate of the past decades; (v) protests or strikes may adversely affect the stability of the political, social and economic environment and may negatively impact the global financial market’s confidence in the Argentine economy; (vi) energy or natural gas supply may not be sufficient to supply increased industrial activity (thereby limiting industrial development) and consumption; (vii) unemployment and informal employment remain high; and (viii) the Argentine Government’s economic expectations may not be met and the process of restoring the confidence in the Argentine economy may take longer than anticipated.

As in the recent past, Argentina’s economy may be adversely affected if political and social pressures inhibit the implementation by the Argentine Government of policies designed to control inflation, generate growth and enhance consumer and investor confidence, or if policies implemented by the Argentine Government that are designed to achieve these goals are not successful. 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. Moreover, Argentina’s economic growth was severely impacted as a consequence of the Covid-19 pandemic.

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 impact of the next congressional and presidential elections on the future economic and political environment of Argentina remains uncertain

The Argentine economy is subject to the effects of uncertainty over political developments in Argentina. In October 2023, Argentina will hold presidential and congressional elections. Electoral uncertainty could lead to high volatility in Argentine financial markets, and uncertainty regarding political developments and the policies the Argentine government may adopt or alter may have material adverse effects on the macroeconomic environment in Argentina, as well as on businesses operating in Argentina, including ours.

On October 7, 2022, the IMF presented a report warning that the Argentine economy is under a very high risk that will increase with the proximity of the 2023 presidential elections. The persistent inflation and lower growth could exacerbate social discontent and weaken political support, causing difficulties in implementing the planned subsidies and social assistance reforms and in securing debt rollover rates.

No assurances can be made as to the policies that may be implemented by a new Argentine administration, or that political developments in Argentina will not adversely affect the Argentine economy and our business, financial condition and results of operations. In addition, we cannot assure you that future economic, regulatory, social and political developments in Argentina will not impair our business, financial condition, or results of operations, or cause the market value of our ADSs and our common shares to decline.

The Argentine economy is vulnerable to external shocks that could be caused by significant economic difficulties of Argentina’s major regional trading partners, or by more general “contagion” effects. Such external shocks and “contagion” effects could have a material adverse effect on Argentina’s economic growth, and consequently, on our operational results and financial condition

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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. 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.

Argentina’s economy is vulnerable to external shocks. For example, economic slowdowns, especially in Argentina’s major trading partners such as Brazil, led to declines in Argentine exports in the last few years. Specifically, fluctuations in the price of commodities sold by Argentina and a significant devaluation of the Peso against the U.S. Dollar could harm Argentina’s competitiveness and affect its exports. In addition, international investors’ reactions to events occurring in one market may result in a “contagion” effect which could lead to an entire region or class of investment being disfavored by international investors. Additionally, financial and securities markets in Argentina are also influenced by economic and market conditions in other markets worldwide.

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. (See “The ongoing conflict between Russia and Ukraine could adversely affect the global economy, the Argentine economy and our operational results and financial condition”).

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 ongoing conflict between Russia and Ukraine could adversely affect the global economy, the Argentine economy and our operational results and financial condition

On February 24, 2022, the President of Russia, Vladimir Putin, announced a military operation in the eastern Donbas region of Ukraine and began a full-scale invasion of the country.

The invasion received widespread international condemnation, with worldwide protests against the Russian invasion of Ukraine. The United States, the United Kingdom and other countries of the European Union imposed economic sanctions on Russia—such as the exclusion of certain Russian banks from the SWIFT financial system, airspace restrictions, export restrictions of Russian oil and gas, among others.

The invasion has had an immediate impact on the global economy resulting in higher energy prices and higher prices for certain commodities, such as oil and natural gas, and goods and services which in turn is contributing to higher inflation in countries across the globe with significant disruption to financial markets and supply and distribution chains for certain raw materials and goods and services on an unprecedented scale . On the other hand, Russia is the second largest oil exporter in the world and the largest producer of natural gas, causing the world oil prices to jump to over US$110 per barrel, and the cost of natural gas to reach a new record high in Europe. Oil prices are particularly sensitive to actual and perceived threats to global political stability and to changes in production from OPEC member states. The Russian invasion of Ukraine has continued to escalate without any resolution of the invasion foreseeable in the near future with the short and long-term impact on financial and business conditions remaining highly uncertain. A further increase, or the threat of an increase, in Russian activities in Ukraine 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 on natural gas may adversely affect our generation dispatch assets.

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Russia has responded in kind to the various economic sanctions imposed by the United States and the European Union. The United Kingdom, Japan, South Korea, Australia and other countries across the globe have imposed their own sanctions on Russia. The United States, the European Union and such other countries acting together or separately could impose wider sanctions or take further actions against Russia if the conflict continues to escalate. Multinational corporations and other corporations and businesses with business and financial ties to Russia have either reduced or eliminated their ties to Russia in a manner that often exceeds what is required pursuant to sanctions by these countries. 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 extent and duration of the military action, sanctions and resulting market disruptions are impossible to predict, but could be substantial. Any such disruptions caused by Russian military action or resulting sanctions may magnify the impact of other risks described in this annual report and may result in compliance and operational challenges for the Company.

Although up to the date of this annual report the conflict is regional in nature, the possible involvement of other member countries of the North Atlantic Treaty Organization could result in a transnational conflict, which could significantly affect the world economy and Argentina and, therefore, our operational results. Volatility in oil and other commodity prices may adversely affect the Argentine economy and our business. The materialization of some or all of these risks, as well as the events that arise in the main regional partners, including the member countries of Mercosur, could have a material negative effect on the Argentine economy, on the interest of investors in Argentine companies, and, indirectly, on our business and operational results.

In addition, any deterioration in credit markets resulting directly or indirectly from the ongoing Russian invasion of Ukraine could limit our ability to obtain external financing to fund our operations and capital expenditures. As a result, a downturn in the worldwide economy resulting from the Russian invasion of Ukraine and other conflicts with a global impact that may arise from time to time could have a material adverse effect on our business, results of operations, and/or financial condition.

Economic and political developments in Argentina, and future policies of the Argentine Government may adversely affect the Argentine economy and the sectors in which we perform our activities

The Argentine Government has historically exercised significant influence over the economy, and our Company has operated 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.

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 to capital movement or other measures in response to an eventual capital flight or a significant depreciation in the Peso, measures that can, in turn, affect our ability to access the international capital markets. In the event of any economic, social or political crisis, companies operating in Argentina may face the risk of strikes, expropriation, nationalization, mandatory amendment of existing contracts, and changes in taxation policies, including tax increases and retroactive tax claims. In addition, Argentine courts have sanctioned modifications on rules related to labor matters, requiring companies to assume greater responsibility for the assumption of costs and risks associated with sub-contracted labor and the calculation of salaries, severance payments and social security contributions. 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 (See “—The impact of the next congressional and presidential elections on the future economic and political environment of Argentina remains uncertain.”)

On September 1, 2019, as a result of the economic instability and uncertainty, the depreciation of the Argentine Peso and rising inflation rates, the former Argentine administration and the BCRA adopted a series of measures reinstating foreign exchange controls. Following the change in government, the new administration extended the validity of such measures and established further restrictions by means of the enacted Social Solidarity and Productive Reactivation Law, including a new tax on certain transactions involving the purchase of foreign currency by both Argentine individuals and entities. 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. There can be no assurances regarding future modifications to exchange controls. 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. For more information, please see “Item 10. Additional Information – Exchange Controls”.

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The success of these measures or other measures that the BCRA may implement in the future, are subject to uncertainty and any further depreciation of the Argentine Peso, further inflation or our inability to acquire foreign currency could have a material adverse effect on our financial condition and results of operations. We cannot predict the effectiveness of these measures. 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. Furthermore, no assurance can be given that, in the future, no additional currency or foreign exchange restrictions or controls will be imposed. Existing and future measures may negatively affect Argentina’s international competitiveness, discouraging 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 restrictions on transferring funds abroad imposed by the government could undermine our ability to 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.

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 the market value of our ADSs, our business, financial condition and/or operational results, and will be successful to correct the energy production sector in Argentina.

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. 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 listed above, on the level of international reserves maintained by the BCRA, which have also shown significant fluctuations in recent years. As of April 27, 2023, the international reserves of the BCRA totaled US$36,478 million. According to the exchange rate information published by the Banco de la Nación Argentina, the Argentine Peso depreciated by 72.5% against the U.S. Dollar during the year ended December 31, 2022 (compared to 58.9%, 102.2% and 17.4% in the years ended December 31, 2021, 2020 and 2019, respectively). 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 also presents risks for the Argentine economy, including the possibility of a reduction in exports (as a consequence of the loss of external competitiveness). 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, our ability to repay our debt within the respective maturity dates and affect the market value of our ADSs, as a result of the overall effects of the weakening of the Argentine economy.

If the high levels of inflation continue, the Argentine economy and our operational results could be adversely affected

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. According to data published by the INDEC, CPI rates for January, February and March 2023 were 6%, 6.6% and 7.7%, respectively; rates for July, August, September, October, November and December 2022 were 7.4.%, 7.0%, 6.2%, 6.3%, 4.9% and 5.1%, respectively; and rates for July, August, September, October, November and December 2021 were 3.0%, 2.5%, 3.5%, 3.5%, 2.5% and 3.8%, respectively. For more information, please see “—The interruption of the publication of Argentine economic indexes or changes in their calculation methodologies could affect the projections made by the Company” below. The National CPI variation was 94.8% in 2022, 50.9% in 2021 and 36.1% in 2020. The Argentine Government’s adjustments to electricity and gas tariffs, as well as the increase in the price of gasoline have affected prices, creating additional inflationary pressure. If the value of the Argentine Peso cannot be stabilized through fiscal and monetary policies, an increase in inflation rates could be expected.

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A high inflation rate affects Argentina’s foreign competitiveness by diluting the effects of the Peso depreciation, negatively impacting employment and the level of economic activity and undermining confidence in Argentina’s banking system, which may further limit the availability of domestic and international credit to businesses. In turn, a portion of the Argentine debt continues to be adjusted by the CER, a currency index, that is strongly correlated with inflation. Therefore, any significant increase in inflation would drive an increase in the Argentine external debt and consequently in Argentina’s financial obligations, which could exacerbate the stress on the Argentine economy. The efforts undertaken by the Argentine Government to reduce inflation have not achieved the desired results. A continuing 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 reduce and control inflation and the potential impact of those policies. An increase in inflation may adversely affect the Argentine economy, which in turn may have a negative impact in our financial condition and 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

In 2014, the INDEC established a new consumer price index, 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. The official CPI inflation rate for the year ended December 31, 2022 was 94.8%.

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 and, consequently, affect our business, results of our operations and growth prospects

Argentina’s history of defaults on its external debt and the protracted litigation with holdout creditors may reoccur in the future and prevent Argentine companies such as us from accessing the international capital markets readily or may result in higher costs and more onerous terms for such financing, and may therefore negatively affect our business, operational results, financial condition, the value of our securities, and our ability to meet our financial obligations. Following the default on its external debt in 2001, Argentina sought to restructure its outstanding debt in exchange offers in 2005 and again in 2010. Holders of approximately 93% of Argentina’s defaulted debt participated in the exchanges, but a number of bondholders held out from the exchange offers and pursued legal actions against Argentina. The Argentine Government settled several agreements with the defaulted bondholders, ending more than 15 years of litigation. In addition, on August 2020, the Argentine Government successfully negotiated the debt restructuring of Argentine bonds representing approximately US$65 billion owed to several bondholders.

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On January 28, 2022, Argentina signed an agreement with the IMF (the “SAF Agreement”) to refinance indebtedness for more than US$40 billion, which Argentina originally incurred with the IMF on 2018. Argentina and the IMF agreed on certain measures related to the reduction of public spending and subsidy rates, focused on the energy sector. The agreement was approved by the Argentinean Congress and by the Board of the IMF. Among other points, an economic and monetary policy was established, where the IMF will be the co-director, carrying out quarterly audits on Argentina's finances and economic development.

On September 19, 2022, IMF staff and the Argentine authorities reached an agreement on an updated macroeconomic framework and associated policies needed to complete the second review under the SAF Agreement. The agreement was subject to approval by the IMF Executive Board. Upon completion of the review, Argentina would have access to about U.S.$3.9 billion. Most of the quantitative program targets through end-June 2022 were met, with the exception of the net international reserves floor, mainly due to higher-than-programmed import volume growth and delays in external official support. The agreement was halted due to a period of volatility in the foreign exchange and bond markets and certain measures were taken to correct earlier setbacks and rebuilt credibility. On March 13, 2023, the IMF approved the fourth revision of the SAF Agreement and authorized the disbursement of approximately U.S.$5.3 billion.

On March 13, 2020, the Minister of Economy addressed a letter to the Paris Club members expressing Argentina’s decision to postpone until May 5, 2021 the US$ 2.1 billion payment originally due on May 5, 2020, in accordance with the terms of the settlement agreement reached with the Paris Club members on May 29, 2014 (the “Paris Club 2014 Settlement Agreement”). On April 7, 2020, the Minister of Economy sent the Paris Club members a proposal to modify the existing terms of the Paris Club 2014 Settlement Agreement, mainly seeking an extension of the maturity dates and a significant reduction in the interest rate. On June 22, 2021, Argentina’s Minister of Economy announced that the Argentine government obtained a “time bridge” within the framework of the Paris Club negotiations, consequently avoiding default. Pursuant to such agreements, Argentina should have reached a restructuring agreement with the Paris Club members by March 31, 2022. However, on March 31, 2022, such agreement was extended until July 31, 2022 and, on May 31, 2022, it was further extended until September 30, 2024.

On October 28, 2022, the Minister of Economy announced a new agreement with the Paris Club. The agreement is an addendum to the Paris Club 2014 Settlement Agreement and recognizes a principal amount of U.S.$1,971 million, extending a repayment period of thirteen semi-annual installments, starting in December 2022 and to be finally cancelled in September 2028. Pursuant to this new agreement, the interest rate was improved from 9% to 3.9% in the first three installments, with a gradual increase to 4.5%. The payment profile implies an average semi-annual payment of $170 million (principal and interest included). Over the next two years, Argentina will repay 40% of the principal due.

Our company cannot predict how this agreement and the policies developed based on it will impact Argentina’s ability to access international capital markets (and indirectly in our ability to access those markets), in the Argentine economy or in our economic and financial situation or in our capacity to extend the maturity dates of our debt or other conditions that could affect our results and operations or businesses.

The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operations

Global public health threats, such as Covid-19 (as described more fully below), influenza and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world, could adversely impact our operations, as well as the operations of our customers.

The Covid-19 pandemic has reached every region of the world and has resulted in widespread adverse impacts on the global economy. The ongoing outbreak of Covid-19 has already caused severe global disruptions and may continue to negatively economic conditions regionally as well as globally and otherwise impact our operations and the operations of our customers and suppliers. Governments in affected countries continue to impose travel bans, quarantines and other emergency public health measures. Companies are also taking precautions, such as requiring employees to work remotely, imposing travel restrictions and temporarily closing businesses. These restrictions, and future prevention and mitigation measures, are likely to continue to have an adverse impact on global economic conditions, which could materially and adversely affect our future operations.

On March 12, 2020, the Executive Branch of the Argentine Government issued Decree No. 260/2020 which declared a public health emergency for a period of one year (currently extended until December 31, 2023, pursuant to Decree No. 863/2022) and established a mandatory quarantine, which was extended several times, affecting our ongoing expansion projects, which were later included as an essential activity. For more information, please see “Item 4—Relevant Events— Measures Designed by the Argentine Government to Address the Covid-19 Outbreak”.

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The long-term effects on the global economy, Argentine economy and the Company of the coronavirus pandemic, are difficult to assess or predict, and may include a decline in market prices (including the market prices of our common shares), risks to employee health and safety, collapse in the demand for our products and reduced sales in the impacted geographic locations. Furthermore, the crisis caused by Covid-19 resulted in a decrease in the demand for crude oil, mainly in the second and third quarters of 2020, since industrial and domestic activity slowed down in many countries due to control measures.

Covid-19 has significantly affected economic conditions in Argentina and in the rest of the world and it is possible that it will continue to affect such conditions during 2023 and in future years. Both the Covid-19 pandemic and the measures implemented by the Argentine Government to mitigate its effects may continue to affect our business, financial condition and results of operations. Additional variants or strains of Covid-19 or an outbreak of another pandemic, disease or similar threat to public health could have or continue to have material adverse effects on the global economic, financial and trade conditions, which could materially and adversely affect our business, financial condition and results of operations. For more information, please see “Item 4—Relevant Events— Measures Designed by the Argentine Government to Address the Covid-19 Outbreak”.

One of the significant areas of impact of Covid-19 on our business has been a shift in company policy to hybrid work arrangements. We have recently implemented a hybrid work model. Although we have allowed all employees to return to the office, a significant number of administrative employees have chosen to continue to work remotely on a part-time basis. Working remotely could increase our cybersecurity risk, create data accessibility concerns, and make us more susceptible to communication disruptions, any of which could adversely impact our business operations.

The continuing occurrence of any of the foregoing events or other epidemics or an increase in the severity or duration of the Covid-19 or other epidemics could have a material adverse effect on our business, results of operations, cash flows and financial condition.

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

There are certain restrictions in Argentina that 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, requiring, in some cases, prior approval by the Central Bank. These restrictions may affect our operations and our expansions projects, as they require the import of services and goods for which payment may be restricted. The Argentine Government may impose or create further restrictions on the access to the MLC. In such case, the ability of Argentine corporations to make payments outside Argentina and to comply with their obligations and duties may be affected.

In addition, as a result of the deepening of exchange controls, the difference between the official exchange rate, which is currently utilized for both commercial and financial operations, and other informal exchange rates that arose implicitly as a result of certain operations commonly carried out in the capital market ( “cash with liquidation”), which decreased during 2022, was a gap of approximately 90% as of December 31, 2022. The Argentine Government could maintain a single official exchange rate or create 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. We cannot predict how such current restrictions may evolve after this annual report, mainly regarding limitations to transfer funds outside the country. The Argentine Government may impose further exchange controls or restrictions to capital transfers and modify and adopt other policies that may limit or restrict our ability to access international capital markets, to make payments of principal and interest and other additional amounts outside the country (including payments relating to our notes), 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.

Argentine public expenditure may generate negative consequences for the Argentine economy

Public expenditure has significantly increased throughout the last decade in Argentina. 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. Primary deficit may increase in the future if public expenditure continues to increase faster than the Argentine Government’s revenues. A greater 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, limit even more Argentine corporations’ access to those markets. For more information, please 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 and, consequently, affect our business, results of our operations and growth prospects.”

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As of the date of this annual report, 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.

There is no certainty as to the effects that the measures that the Argentine Government may adopt in order to resolve the crisis in the energy sector will have on our business operations, financial condition or results of operations.

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.

The Macri administration declared a state of emergency with respect to the national electricity system in order to correct distortions in the sector and stimulate investment. The state of emergency allowed the National Government to adopt measures designed to stabilize the country’s electricity supply, such as eliminating certain energy subsidies and implementing significant adjustments to electricity rates to reflect generation costs. However, some measures of the Macri administration were challenged by the Argentine courts and resulted in injunctions or rulings that limited these measures, such as the injunction that suspended the increases in electricity rates implemented as of February 1, 2016 and holding a series of non-binding public hearings prior to approving the increases.

On May 21, 2021, the SE issued Resolution No. 440/2021 pursuant to which certain aspects of the remuneration scheme established by the SRRYME were modified through Resolution No. 1/19, effective as of as of February 1, 2020 and later modified by Resolution No. 31/2020, which established an increase in remuneration of approximately 29% retroactive to February 2021, and also eliminated the monthly adjustment contemplated in Resolution No. 31/2020.

On February 26, 2022, by means of ENRE Resolutions No. 66, 67, 68, 69, 70, 71, 72, and 74, the hourly values to be applied to regulated equipment were approved, with effects from February 1, 2022, for the following transmission companies, namely: TRANSPA, TRANSCO, TRANSENER, TRANSBA, EPEN, TRANSNOA, TRANSNEA and DISTROCUYO.

On April 18, 2022, by means of Resolution No. 235/2022, the Energy Secretariat called for a public hearing to address the implementation of a segmentation system in the granting of energy price subsidies by the National Government to users of natural gas and electric energy services for the 2022-2023 biennium. The hearing took place on May 12, 2022.

On April 21, 2022, the remuneration scheme was modified by SE Resolution No. 238/22 which established a 30% increase in remuneration retroactive to February 2022 and a new 10% increase to be applied as of 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 again 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.

On June 16, 2022, the Executive Branch issued DNU No. 332/22, establishing a regime of segmentation of subsidies to residential users of the public services of electricity and natural gas. The segmentation regime comprises three different levels that vary according to the users incomes (Tier 1 – Higher Income; Tier 2 – Lower Income; and Tier 3 – Middle Income). On June 27, 2022, the Ministry of Economy issued Resolution No. 467/2022, establishing the conditions for the natural gas and energy public services users to obtain the subsidies.

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On September 1, 2022, through Resolution No. 627/2022 (as amended by Resolution No. 629/2022) the Energy Secretariat defined three segments of residential users with differentiated subsidy levels under the subsidy segmentation regime established by Decree No. 332/2022. In particular, Resolution No. 627/2022 sets forth the criteria for the application of the subsidy segmentation regime, which was applicable from September 1, 2022 until October 31, 2022. Resolution SE No. 627/2022 approved the so-called “POTREF” (Power Reference Prices, by its acronym in Spanish) and the so-called “PEE”(Stabilized Energy Price, by its acronym in Spanish) in the MEM, which had to be applied in the tariff charts by distribution agents and other public distribution service providers from September 1 to October 31, 2022.

However, on September 13, 2022, by SE Resolution No. 649/2022, the subsidies for middle-income households with consumption above 400 kWh were suspended. As a result, those who have been categorized in Tier 3 (middle income) of the Registry of Access to Energy Subsidies (RASE) and whose consumptions exceed the threshold of 400 kWh per month will no longer benefit from the subsidy. Consumption that exceeds the aforementioned limit will pay the same rate –exempt from subsidy- as the rate paid by Tier 1, made up of users with higher income. Tier 2 users (lower income) will not be subject to any cap.

On November 30, 2022 and January 23, 2023, public hearings were held, called by the ENRE through Resolutions No. 539/2022 and 576/2022, in order to inform and hear opinions regarding the proposals submitted by concessionaires of electric power transmission and distribution public utilities which were aimed at obtaining a transitory adjustment of tariffs within the renegotiation process of the integral tariff review, prior to defining the tariffs to be applied by the concessionaires. ENRE Resolutions No. 682/2022 and 154/2023 approved the final reports of such hearings.

On February 7, 2023, Resolution No. 59/2023 was published in the Official Gazette. By means of such resolution the SE authorized generating agents (i) which own thermal generation plants; and (ii) whose technology is classified as “Combined Cycles” according to Resolution No. 826/2022, to adhere to a “Power Availability and Efficiency Improvement Agreement” with CAMMESA (on behalf of the distributors and large users of the MEM), with the purpose of encouraging the necessary investments for major and minor maintenance of the machines.

For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

The failure to adopt new measures to correct problems in the generation, transportation and distribution of energy in Argentina could adversely affect the economic situation of Argentina and the business, financial condition and results of operations of the Company. We cannot guarantee that the Argentine Government will not adopt measures that would have an adverse effect on the Company’s business and/or that the measures adopted by the Argentine Government will be sufficient to restore energy production in Argentina.

The Argentine economy and finances may be adversely affected as a consequence of a decrease in the international prices of commodities

The commodities market is characterized by its volatility. Commodities exports have contributed significantly to the revenues of the Argentine Government. Subsequently, the Argentine economy has remained relatively dependent on the price of its exports (mainly soy). During 2018, Argentina suffered a huge drought – presumably the biggest drought in the last 50 years. The effects of the drought in the agricultural sector caused significant economic problems for Argentina, with impacts in the soy and corn harvests that generated damages of approximately US$6 billion. Currently, Argentina is facing another severe drought, which is expected to result in net income losses of US$ 10.425 billion for the production sector, equivalent to 2.2% of the GDP that the IMF projects for Argentina in 2023.

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 in the agricultural sector, and therefore in 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.

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

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In the past, the National Government has 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 their employees and from unions to grant wage increases and other benefits.

We cannot be sure that in the future the Argentine Government will not enact measures that result in increases in the minimum, vital and mobile salary and/or in benefits, compensation or other labor costs that employers must bear. Any salary increase and/or any other labor cost could result in higher costs and a decrease in the results of the Company’s operations (For more information, see “We employ a largely unionized labor force and could be subject to organized labor action, including work stoppages that could have a material adverse effect on our business”).

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 94 of 180 in the Transparency International’s 2022 Corruption Perceptions Index.

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.

Moreover, in February 2023, the Political Trial Commission of the Chamber of Deputies approved the admissibility of files being processed against the current members of the Supreme Court and initiated proceedings against each member. While the outcome of the impeachment trial remains uncertain, this situation has intensified the institutional imbalance in Argentina, leading to a negative impact on the country's politics and economy.

Recognizing that the failure to address these issues could increase the risk of political instability, distort decision-making processes and adversely affect Argentina’s international reputation and ability to attract foreign investment, the Argentine Government has announced several measures aimed at strengthening Argentina’s institutions and reducing corruption. These measures include the reduction of criminal sentences in exchange for cooperation with the government in corruption investigations, increased access to public information, the seizing of assets from corrupt officials, increasing the powers of the Anticorruption Office (Oficina Anticorrupción) and submitting a bill for the issuance of a new public ethic law, among others. The government’s ability to implement these initiatives is uncertain as it would be subject to independent review by the judicial branch, as well as legislative support from opposition parties.

We cannot estimate the impact that these investigations 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, our financial condition and operational results and affect the trading price of our common shares and ADSs.

The Argentine Government has intervened in the electricity sector in the past, and may continue intervening to adopt, among others, measures in connection with tariffs on public services

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

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To address the Argentine economic crisis in 2001 and 2002, the Argentine Government adopted the Public Emergency Law No. 25,561 and other regulations, which made a number of material changes to the regulatory framework applicable to the electricity sector. These changes severely affected electricity generation, distribution and transmission companies. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

Over the years, the Argentine Government adopted several measures in connection with tariffs on public services. One of the first measures of the current administration was to enact the Social Solidarity and Productive Reactivation Law, which, among other measures, established a 180-day freeze in energy and natural gas tariffs and the relaunching of RTIs (this period has been extended by Decree No. 543/2020 and Decree No. 1020/2020 until the RTI process concludes or the transitional tariff increase is put into effect). The law also enabled the President to intervene in the activities of the regulatory authorities (ENRE and ENARGAS), which occurred in March 2020 by Decrees No. 277/2020 and 278/2020, in December 2021 by Decree No. 871/21 and in December 2022 by Decree No. 815/22. Moreover, Resolution SE 31/2020 modified the power generation segment’s remuneration scheme and established prices denominated in Argentine Pesos (formerly denominated in U.S. Dollars) and reduced such prices in different proportions according to the technology employed. On May 21, 2021 Resolution SE No. 440/21 modified Resolution SE No 31/20 and increased generators revenues by 29%; moreover, it repealed the application of the adjustment mechanism established in the previous resolution. The new resolution is applicable from February 2021, provided that the generator desists from any administrative or judicial claims against the lack of application of the automatic adjustment mechanism established in Resolution SE 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. Such remuneration scheme was again modified on December 12, 2022, 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 beginning in December 2022. It also established a 25% increase to be applied beginning on February 1, 2023, and a 28% increase to be applied beginning in August 2023. For more information, please See “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

Furthermore, on March 21, 2023, due to extensive power cuts that took place in February and March, the Argentine Government announced the temporary intervention of Edesur for 180 days. The intervention was authorized by ENRE Resolution No. 307/2023.

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.

Risks Relating to our Company

We operate a material portion of our business pursuant to public concessions granted by the Argentine Government, the revocation or termination of which would have a material adverse effect on our business

We conduct a material part of our businesses pursuant to public concessions granted by the Argentine Government. 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 Argentine Government. Accordingly, upon the occurrence of specified events of default under these concessions, the Argentine Government would be entitled to foreclose on its pledge of the concessionaire and sell our shares in that concessionaire to a third party. Such sale 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. Finally, 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 the Argentine Government forecloses its pledge over the shares we own in any of our concessionaire companies, such companies could not continue to operate as a going concern, and in turn our consolidated operational results would be materially adversely affected and the market value of our shares and ADSs could decline.

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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 that could have a material adverse effect on our business

The sectors in which we operate are generally unionized across the country. As of December 31, 2022, 53.35% 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 or our operating subsidiaries 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. 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.

In the event of an accident or other event not covered by our insurance policies, we could face significant losses that could result in a material adverse effect on our business and operational results

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 our failure to continue such joint ventures or to settle any potential material disagreements with our partners could have a material adverse effect on the success of these operations

We conduct a portion of our operations through joint ventures and as a result, the continuation of such joint ventures 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 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 CITELEC, which holds a controlling interest of 52.65% in Transener and CIESA which has a controlling interest of 51% in TGS, we are not able to acquire our partners’ interests under applicable Argentine regulations. As a result, the failure to continue some of our joint ventures 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, which would in turn negatively affect our financial condition and operational results and the market value of our shares and ADSs.

If we are not able to effectively hedge our currency risk in full and a devaluation of the Argentine Peso occurs, our results of operations and financial condition could be materially adversely affected

Our revenues are mainly collected in Argentine Pesos. Thus, we are exposed to an exchange rate risk of Peso-denominated trade receivables mainly related to power generation segment’s spot market remuneration scheme established by SE Resolutions. For more information, see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”). 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.

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We and our affiliates are involved in various legal proceedings which could result in unfavorable rulings against us

We and our affiliates are party to a number of 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. See “Item 8. Legal Proceedings”.

Downgrades in our credit ratings could have negative effects on our funding costs and business operations

Credit ratings are assigned to the Company and its subsidiaries. The credit ratings are based on information furnished by us or obtained by the credit rating agencies from independent sources and are also influenced by the credit ratings of Argentine Government bonds and general views regarding the Argentine financial system as a whole. Argentina’s long-term debt denominated in foreign currency is currently rated as “Ca” by Moody’s, as “CCC-” by S&P and “CCC-” by Fitch. On October 26, 2022, Fitch downgraded Argentina’s long-term sovereign credit rating by a notch to “CCC-” from “CCC”, citing deep macroeconomic imbalances and risks over the country’s ability to meet future debt repayments. Similarly, on March 30, 2023, S&P also downgraded Argentina's long-term foreign currency rating from “CCC+” to “CCC-”. We cannot guarantee that Argentina’s credit rating or rating outlook will not be further downgraded in the future, which could have an adverse effect both on the rating and the market price of our ADS and our common shares.

The credit ratings are subject to revision, suspension or withdrawal by the credit rating agencies at any time. A downgrade, suspension or withdrawal in our credit ratings could result in, among others, the following: (i) increased funding costs and other difficulties in raising funds; (ii) the need to provide additional collateral in connection with financial market transactions; and (iii) the termination or cancellation of existing agreements. As a result, our business, financial condition and operational results could be materially and adversely affected.

Cybersecurity events, such as a cyber-attack could adversely affect our business, financial condition, operational results and cash flows

We depend on the efficient and uninterrupted operation of internet-based data processing communication and information exchange platforms and networks, including administrative and business related systems, such as Supervisory Control and Data Acquisition and DCS Software, Inc. Cybersecurity risks have generally increased in recent years as a result of the proliferation of new technologies and the increased sophistication and activities of cyber-attacks. Through part of our business, we have increasingly connected equipment and systems to the internet. Furthermore, we depend on digital technology, including information systems to process financial and operating data, analyze seismic and drilling information and oil and gas reserves estimates. Due to the critical nature of our infrastructure and the increased accessibility enabled through connection to the internet, we may face a heightened risk of cybersecurity incidents such as computer break-ins, fraud, phishing, identity theft and other disruptions that could negatively affect the security of information stored in and transmitted through our computer systems and network infrastructure. In the event of a cyber-attack, we could experience disruption of our business operations, fraud, property damage and stolen customer information; substantial loss of revenues, response costs and other financial loss; and increased regulation, litigation and damage to our reputation. Our power generation operations are partially connected to the manufacturer systems for maintenance and control purposes. An attack on such third parties may affect our operations and information.

In 2022, the Company carried out the following measures: (i) for the fifth consecutive year, an annual cybersecurity training plan for all its employees with the aim of deepening awareness and learning regarding risks, threats and good practices in information security, where different interactive initiatives were carried out in relation to risks, threats and good practices in security matters; (ii) a cybersecurity assessment on our assets to determine the current level of maturity, compared to the last one carried out in 2021 (sustained growth was evident since security levels went from a Medium-Low level to a Medium level according to NIST metrics (NIST Cybersecurity Framework)); (iv) disaster recovery plans for both the administrative and control environments, in order to be prepared and recover operations in the event of disasters that could put the normal operation of the Company on hold; and (v) the development of a process for the management of security incidents in order to identify, manage, record and analyze security threats or incidents that occur in the organization. Through these measures, the Company seeks to offer a solid and complete vision of any cybersecurity problem in both administrative and control environments.

During 2022, we were the target of different cybersecurity threats, but they did not result in a significant loss or a negative impact on our operations since no attack attempt achieved its objective due to the measures implemented by the Company. The Company's risk and exposure to these events cannot be fully calculated or mitigated due, among other things, to the evolution and nature of these threats.

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In addition, while we have not experienced any material loss related to cybersecurity events, contingency plans in place may not be sufficient to cover liabilities associated with any such events and therefore, applicable insurance coverage may be deemed inadequate, preventing us from receiving full compensation for the losses sustained as a result of such a disruption. Although we intend to continue to implement security technology devices and establish operational procedures to prevent disruption resulting from, and counteract the negative effects of cybersecurity incidents, it is possible that not all of our current and future systems are or will be entirely free from vulnerability and these security measures will not be successful. Accordingly, cybersecurity is a material risk for us and a cyber-attack (either targeting us or third-party infrastructure) 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.

CAMMESA could alter and delay payments to power generators and fuel producers

Electricity generators receive, through CAMMESA, payments corresponding to the power availability and the energy effectively supplied to the spot market and under the contracts with CAMMESA. There is a deficit between the inflows from electricity distribution companies and large users and outflows payable to generation and fuel production companies. The Argentine Government has covered such deficit through non-reimbursable contributions from the treasury to CAMMESA. If these treasury contributions are shown not to be enough to cover all of the generators and fuel producer’s claims against CAMMESA, CAMMESA’s payable account would grow over time. As of the date hereof, there is still a portion of the generation costs that is covered by the Argentine Government (approximately 37%, according to CAMMESA’s 2021 annual report). We cannot assure you that the portion of the generation costs not covered by retail distributors’ end-user will not increase in the future or that CAMMESA will be able to pay the generators and fuel producers for its debts. The generators and fuel producers’ inability to collect their receivables from CAMMESA could have a material adverse effect on their income, working capital funding and, consequently, on their operational results and financial and liquidity condition. For more information, please see “Item 4—Relevant Events— Measures Designed by the Argentine Government to Address the Covid-19 Outbreak”, and “The Argentine Energy Sector—Electricity Regulatory Framework”.

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

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, or even we, 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.

Our businesses are subject to risks arising from natural disasters, catastrophic accidents and terrorist attacks. Additionally, our businesses are subject to the risk of mechanical or electrical failures and any resulting unavailability may affect our ability to fulfill our contractual commitments and thus adversely affect our business and financial performance

Our power generation facilities, pipelines and hydrocarbon blocks or the third-party fuel transportation or power transmission infrastructure that we rely on, may be damaged by flooding, fires, earthquakes and other catastrophic disasters arising from natural or accidental or intentional human causes. 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 cause 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.

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. Any unplanned unavailability of our facilities may adversely affect our financial condition or operational results and our ability to fulfill our contractual commitments, so we could be subject to fines and penalties. For example, in June 2019, Argentina suffered a general blackout which hindered the operation of our facilities. Although our power generation and transmission units did not suffer any damage, we cannot guarantee that any other event in the Argentine grid would not affect our units and consequently their availability to fulfill our contractual commitments and 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 periods, 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.

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

On May 29, 2019, the Company, after having made a joint offer, received a notification from IEASA, in which Pampa and YPF, were awarded the National and International Public Bid No. CTEB 02/2019, which was launched through Resolution No. 160/19 of the Secretary of Government of Energy, regarding the sale and transfer by IEASA of the goodwill of the CTEB (the “CTB Transaction”), for which closing was 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, and the Company could even be forced to reverse and unwind the CTB Transaction and undo all its effects.

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We and our subsidiaries continue evaluating investment projects to expand our activity, which could imply an increase in our indebtedness

Some of our and our subsidiaries’ investment projects could be guaranteed by Pampa, incurring additional guaranteed debt. 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 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.

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 industry 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 Argentine Government is carrying out different strategies to combat climate change with the help of the United Nations Development Program. For example, in 2006, Law No. 26,190, as amended, established a legal framework that promotes an increase in the participation of energy from renewable resources in electricity consumption in Argentina. Likewise, in 2019, the Argentine Government focused on implementing policies, programs and projects in order to prevent, mitigate or reduce impacts associated with climate change. If the Argentine Government adopts additional measures, such measures could generate higher production costs, negatively impacting our competitiveness. Likewise, the Argentine Government can modify the demand for hydrocarbons towards relatively low-carbon sources, such as renewable energies. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”. We cannot assure you that other regulations or measures that may be adopted by the Argentine Government will not have an adverse effect on our business and 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.

Uncertainty relating to the LIBOR transition process and the phasing out of LIBOR may adversely affect us

On July 27, 2017, the Chief Executive of the FCA, which regulates LIBOR, announced that the FCA will no longer persuade or compel banks to submit rates for the calculation of LIBOR after 2021. As of the date of this annual report, USD LIBOR is available in five settings (overnight, one-month, three-month, six-month and 12-month). The ICE Benchmark Administration (“IBA”) has stated that it will cease to publish all remaining USD LIBOR settings immediately following their publication on June 30, 2023, absent subsequent action by the relevant authorities. As of January 1, 2022, all non-USD LIBOR reference rates in all settings ceased to be published. There can be no assurance that non USD synthetic LIBOR or USD LIBOR will remain available in the future.

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The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee (the “ARRC”), a steering committee comprised of large U.S. financial institutions, has identified SOFR as its preferred alternative rate for LIBOR. On December 6, 2021, the ARRC released a statement selecting and recommending forms of SOFR, along with associated spread adjustments and conforming changes, to replace references to 1-week and 2-month USD LIBOR. At this time, it is not possible to predict the effect of the transition to SOFR. Although there have been an increasing number of issuances utilizing SOFR, it is unknown whether SOFR or any other alternative reference rates will attain market acceptance as replacements for LIBOR.

Given the inherent differences between LIBOR and SOFR, or any other alternative reference rates that may be established, the transition from LIBOR may disrupt the overall financial markets and adversely affect the market for LIBOR-based securities, including our portfolio of LIBOR-indexed financings or the cost of our borrowings. In addition, changes or reforms to the determination or supervision of LIBOR may result in a sudden or prolonged increase or decrease in reported LIBOR, which could have an adverse impact on the market for LIBOR-based securities, including the value and/or transferability of the LIBOR-indexed financings in our portfolio or the cost of our borrowings. Additionally, if as currently expected LIBOR ceases to exist, we may need to renegotiate the credit agreements extending beyond June 30, 2023, with our credit facility lenders and our portfolio companies that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with SOFR or other alternative reference rates, which could require us to incur significant time and expense and may subject us to disputes or litigation with lenders over the appropriateness or comparability to the relevant replacement reference index. The transition from LIBOR to SOFR or other alternative reference rates may also introduce operational risks in our accounting, financial reporting, loan servicing, liability management and other aspects of our business. We are in the process of transitioning our investments and our borrowings from LIBOR to SOFR and we do not expect that the transition will have a material impact on our business, financial condition or results of operations.

Risks Relating to Our Businesses

Risks Relating to Our Generation Business

There are electricity transmission constraints in Argentina that may prevent us from dispatch, which could materially adversely affect the financial results of our generation business

During certain times of the year, more electricity can be generated than can be transmitted. Consequently, our dispatch may be affected. Moreover, if our renewable energy projects cannot achieve dispatch priority, we may face energy sale curtailments. We cannot make any assurance that required investments will be made to increase the capacity of the transmission system. As a result of lower dispatch, our generation business may record lower operating profits than we anticipate, which could adversely affect our consolidated operational results and financial condition and the market value of our shares and ADSs. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

If the demand for energy is increased suddenly, current levels of power generation and the difficulty in increasing the capacity of transmission and distribution companies in a short or medium term, could adversely affect the Company

Until 2016, the increase in electricity demand was greater than the structural increase in electricity generation, transmission and distribution capacities, which led to power shortages and disruptions, on certain occasions. A sustained increase in electricity demand could generate future shortages. In addition, the condition of the Argentine electricity market has provided little incentive to generators and distributors to further invest in increasing their generation and distribution capacity, respectively, which would require material long-term financial commitments. Although there were several investments in generation during the following years, which increased the installed capacity, the highest density of investments was concentrated in the Greater Buenos Aires area. It is still necessary to make several investments in the transmission and distribution system to guarantee the delivery of electricity to the users and reduce the frequency of interruptions.

The dispatch of electricity by generators could be substantially and adversely affected since the transmission line may lack sufficient capacity to transport the output of all connected power plants. As a result, our operational results could be affected, as well as our financial condition.

We cannot affirm that we will not experience a lack of dispatch from our units or government intervention could not adversely affect our businesses’ financial condition and operational results and cause the market value of our ADSs and our common shares to decline.

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Changes in certain regulations may require the adjustment of the facilities of our power plants that may require new investments or may affect the dispatch of our generators

Certain regulations, particularly those related to the environment (e.g. emissions prohibitions to use certain consumables or materials, etc.) and public safety (e.g. public roads and railway crossings), may vary from time to time which may require adjustment and work on our power plants. We cannot assure you that these kind of measures or any future measure will not lead to us record lower revenues and operational results as a result of the new investments or lack of availability or dispatch until such investments are made.

Additionally, pursuant to Note No. 5,129/13, the former SE instructed CAMMESA to optimize the dispatch of WEM’s generators according to the available fuels and their actual costs. On the other hand, the new dispatch scheme established as a consequence of Plan Gas.Ar may also affect the dispatch and variable income of our power plants. This new dispatch scheme divides the dispatch of thermal generators in five categories according to the source of the natural gas supply and modifies the previous cost-based dispatch. Consequently, our power plants dispatch may be affected. We cannot make any assurance that required investments will be made to increase the capacity of the transmission system. Such modifications or any other modifications or any other measures may result in a lower dispatch of our generators, and our generation business may record lower operating profits than we anticipate and, in turn, such modifications could adversely affect our operational results and financial conditions. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

We may be unable to collect amounts due, or to collect them in a timely manner, from CAMMESA and other customers in the electricity sector, which would have a material adverse effect on our financial condition and operational results

Electricity generators, including ourselves and our subsidiaries, are paid by CAMMESA for their energy and capacity sold on the spot market, which collects revenue from other WEM agents. As of the date of this annual report, the SE has not instructed CAMMESA to pay the generators the amounts collected from WEM agents on account of interest from delayed payments to CAMMESA. Additionally, the stabilization fund created by the SE to cover the difference between the spot price and the seasonal price of electricity recorded a permanent deficit. This difference was due to the intervention of the Argentine Government and the measures adopted pursuant to the Public Emergency Law. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

We cannot provide any assurance that the above mentioned measures aimed at reducing the debt of distributors and large users will have a positive effect on CAMMESA’s payments or that any new measures will be implemented, that the difference between the spot price and the seasonal price will not increase in the future, that the Argentine Government will use funds of the National Treasury to cover any differences or that CAMMESA will be able to pay generators, both with respect to energy and capacity sold in the spot market and/or the payment of the relevant energy supply agreements with CAMMESA. In fact, since November 2019, payments from CAMMESA, which should be settled within 42 days from the end of the month, have been delayed and have been settled within approximately 80 days instead (except for RenovAr agreements which are paid in a timely manner and have FODER’s guarantee). Furthermore, because of the suspension of the incorporation or renewal of contracts in the term market (except for the Energy Plus program and MAT ER), the revenues of electricity generators will depend on the payments received from CAMMESA. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”. Moreover, no electricity exports are allowed to private generators, while CAMMESA does export electricity to countries such as Brazil (under certain bilateral agreements), dispatching Argentine private generators. Although the SE granted spot market generators a temporary additional payment which was repealed as of February 2022 (See “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”), we cannot assure you that such revenues will repeat in the future.

Our generation units, which sells its production under the Energy Plus regime and MAT ER, collect their revenues, mainly, from WEM Large Users. The Covid-19 outbreak, economic crisis and/or a failure of such customers to their payment obligations may affect our revenues.

The inability of generators, including us and certain of our subsidiaries, to collect their credits from CAMMESA or WEM Large Users, or to collect them in a timely manner, may have a material adverse effect on the revenues of our generation subsidiaries and accordingly, on our operational results and financial condition and the market value of our shares and ADSs.

New measures encouraging renewable energy generation projects may affect our generation sales

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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. As of December 31, 2022, 13.9% of the domestic energy demand was covered by renewable sources of energy.

Additionally, under Resolution 281/2017 the ME&M regulated the contracts for energy of renewable sources among WEM agents. Such resolution allows GUMA 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.

Our ability to generate electricity in our thermal generation plants depends on the availability of natural gas (and other fuels), and fluctuations in the supply or price of gas could materially adversely affect our operational results

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, 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.

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. 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 (given the recent measures that returned to a centralized natural gas supply by CAMMESA), our costs could increase or our ability to profitably operate our generation facilities could be impaired. Moreover, WEM supply agreements under Energía Plus and SEE Resolution 287/17 also require that the generator covers its fuel supply. Although our generators have recently agreed to assign their natural gas supply to cover such obligations to CAMMESA, such assignment might terminate and, consequently, if we cannot guarantee our fuel supply, penalties under such supply agreements may apply, which, together with a lower production of the relevant generation units, could adversely affect our operational results. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

Until November 2018, supply remained centralized in CAMMESA (with the exception of fuel supply for generators covered by the Energy Plus program) as provided for by SE Resolution No. 95/2013 and amending provisions. SGE Resolution No. 70/2018 authorized power generators, co-generators and self-generators within the WEM to acquire fuels required for own power generation, originally for units corresponding to capacity under the SEE Resolution No. 19/17, and later being extended to units under PPAs executed with CAMMESA. It should be noted that CAMMESA remained in charge of the commercial management and the dispatch of fuels for power generators which ‘do not or cannot’ make use of such capacity. However, Resolution No. 12/2019 issued by the former Ministry of Productive Development abrogated SGE Resolution No. 70/2018 and returned to the CAMMESA centralized fuel supply scheme as established in SE Resolution No. 95/2013, as amended. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

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.

Penalties may be applied under our energy supply agreements with CAMMESA which may adversely affect the revenues derived from such contracts or from our generation units

We have executed several energy supply agreements with CAMMESA in which a breach of our commitments allows CAMMESA to apply penalties to us that may adversely affect the revenues derived from such contracts, such as: (i) a breach of the availability commitments set forth in our WEM supply agreements under SE Resolution No. 220/2007, SEE Resolution No. 21/2016, SEE Resolution 287/17 and SE Resolution 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; (ii) a breach of the energy delivery commitments set forth in Greenwind’s and PEA’s PPA allows CAMMESA to apply penalties to the generator that may adversely impact the revenues derived by the generator from such agreements and, ultimately, result in the obligation to sell the assets involved in the operation of the wind farm, which in turn may adversely affect our results; and (iii) a breach of PEPE IV’s and PEPE VI’s Expansion Project obligations to enter into commercial operations by the committed date in the process for obtaining the priority dispatch as established in Resolution ME&M No. 281-E/17 may result in (i) the loss of the priority dispatch with no claim for the payments made in consideration of such priority or (ii) an increase in the amounts to be paid to maintain such priority. For more information, please See “Item 4. Our Generation Business—Renewable Energy” and “Electricity Regulatory Framework”.

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Penalties and or other sanctions may be applied for breaches to applicable regulation or for not having in a timely manner the required permits for the operation of our generation units, which may adversely affect the availability and revenues derived from our generation units

Our generation units are subject to an extensive regulation from local, provincial and national authorities. A breach to such regulation or to obtain and keep in a timely manner the relevant permits and authorizations may result in fines and other sanctions which affect our operational results.

For instance, in CPB we use seawater to refrigerate the generation units. According to applicable provincial law, such activity requires a concession to be granted by the provincial government. We consulted the regulatory authorities who informed us that, according to their files, no such concession has been granted to us. The penalties for such infringement may vary from the application of a maximum Ps.50,000 fine to the closing of the plant. While we consider that the likelihood of any such penalties being imposed is low, we cannot assure you that the operation of CPB would not be affected if such penalties were to be imposed.

A breach to our energy supply agreements with CAMMESA may, ultimately, cause the termination of such agreements, which could adversely affect our operational results

A breach of certain conditions set forth in the PPAs, such as those under SE Resolution No. 220/2007, SEE Resolution No. 21/2016, SEE Resolution No. 287/17 and Greenwind’s and PEA’s PPA, may cause the early termination of such agreements, if the generator loses its authorization to act as a generator in the WEM, initiates bankruptcy procedures, suffers judicial intervention, or certain other events happen, which could adversely affect our operational results. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

A breach to our energy supply agreements with WEM Large Users may cause penalties or the termination of such agreements, which could adversely affect our operational results

A breach of certain conditions set forth in the agreements with WEM Large Users, may cause the early termination of such agreements if: (i) the generator loses its authorization to act as a generator in the WEM, initiates bankruptcy procedures, 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 as DoP set forth in the agreements.

Revenues from Greenwind, PEPE II, PEPE III, PEPE IV and PEA depend on meteorological conditions and the ability to contract the energy to be produced by the wind farms to WEM Large Users

Greenwind, PEPE II, PEPE III, PEPE IV and PEA’s energy generation depends on the prevailing meteorological conditions. Meteorological conditions that result in lower winds could lead to a breach of our sales commitments with CAMMESA (in the case of Greenwind and PEA) and WEM Large Users (PEPE II, PEPE III and PEPE IV). Such breach could lead, in turn, to the application of penalties in favor of our clients (such penalties differ based on the type of contract executed with each PEPE II, PEPE III and PEPE IV client).

Moreover, PEPE II, PEPE III and PEPE IV depend on their ability to have their estimated energy generation fully contracted with WEM Large Users and for each project to maintain its priority dispatch. If a project loses its priority dispatch, its ability to contract its energy generation could be impaired. Moreover, if the energy generation is not contracted with WEM Large Users, then such energy will be remunerated according to SE Resolution 826/22 which establishes lower prices. The ability to contract the projects’ energy generation may also be impaired by regulatory measures taken by CAMMESA or the relevant authorities. For example, measures that affect WEM Large Users to exit the “Group Purchase Mechanism” (Mecanismo de Compra Conjunta), a mechanism by means of which WEM Large Users may comply with their statutory obligations to purchase renewable energy from CAMMESA, would result in lower demand for renewable energy from MAT ER projects and, therefore, potentially affect our operational results.

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Our ability to generate electricity at our hydroelectric generation plants may be negatively affected by poor hydrological conditions, which could, in turn affect our operational results

Prevailing hydrological conditions could adversely affect the operations of our hydroelectric generation plants owned by HINISA, HIDISA and HPPL, in several ways which we cannot fully predict. Hydrological conditions since 2006, the year in which our units recorded the greatest intake to date, have been poor. The worst conditions were registered in 2014, in which the water intake at HINISA and HIDISA available for electricity generation was 62% and 64% lower, respectively, as compared to 2006. A prolonged continuation of poor conditions could force the Argentine Government to focus its generation efforts on the use of other sources of electricity generation. In the event of electricity shortages, the Argentine Government could mandate the implementation of broad electricity conservation programs, including mandatory reductions in electricity generation or consumption; the Argentine Government could also mandate increased production from thermal plants that use fossil fuels as their generation sources and preserve the available water resources for future electricity generation. Although such a shift in production could benefit our thermal generation plants, it would negatively affect our hydroelectric plants and any mandated reduction in electricity generation or consumption could reduce revenues in our generation business and lead to a decline in our consolidated operational results, which may have a material adverse effect on our financial condition and the market value of our shares and ADSs.

Moreover, in a case where the water level of the dams of our hydroelectric facilities decreases to the minimums established in the applicable concession contract, the local water authority (i.e. the Province of Mendoza and the Interjurisdictional Authority (“Autoridad Interjurisdiccional de Cuenca” or “AIC”) would gain control of the amount of water that may be dispatched in order to assure the continuity of other water uses such as human consumption and irrigation.

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 generation of electricity, 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.

We may no longer own a controlling interest in HINISA, if the Province of Mendoza sells its participation in HINISA

We own a 52.04% controlling stake in HINISA, a hydroelectric generation company in the Province of Mendoza, Argentina, and the Province of Mendoza, through EMESA, currently owns 47.96% of the capital stock of HINISA. In 2006, the Province of Mendoza publicly announced its intention to sell shares representing 37.75% of the capital stock of HINISA pursuant to HINISA’s concession. If the Province of Mendoza sells these shares, we will be required to sell 20% of HINISA’s capital stock and would no longer own a controlling 52.04% interest in HINISA. In addition, according to HINISA’s by-laws, we would not be permitted to purchase any additional shares of HINISA.

We currently consolidate the operational results of HINISA. If we lose our controlling interest in HINISA, it may have a significant adverse effect on the value of our investment in HINISA and on our consolidated operational results and the market value of the Company. In addition, we have no control over the timing of the Province of Mendoza’s proposed sale or the price at which we would be required to sell our 20% of HINISA’s shares. As a result, these shares may be sold at a time and price per share that are adverse to our interests and the return on our investment in HINISA.

We may not be able to extend the term of the concession agreements for HINISA, HIDISA and/or HPPL

On March 10, 2022, the SE issued Resolution No. 130/22, which created a “work team” to analyze the situation of the hydroelectric concessions that are due to terminate within the next years, including HIDISA, HINISA and HPPL. The work team must present in a one-year period their reports regarding the concessions that terminate in 2023 (Alicurá, El Chocón, Arroyito, Planicie Banderita and Piedra del Águila), and within a two-year period, their reports for the remaining concessions (including HIDISA and HINISA), except for HPPL and F. Ameghino, which end on 2029 and 2044, respectively.

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During 2022, we have answered different requests from the work team and we cannot assure that the analysis to be performed will not result in the imposition of fines or other penalties.

Moreover, we cannot assure you that we will obtain an extension of the terms of the concession agreements. In the process of termination of such agreements, we may be required to incur extra costs and or investments, which would have an adverse effect on our operational results.

We could be exposed to third-party claims on real property utilized for our operations 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

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 the 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 complaint letters 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.

Our profits may be affected by our failure to fulfill the requirements of the Energy Plus Program or by the modification or the cancellation of such program

If we do not comply with the requirements of the Energy Plus Program (SE Resolution No. 1281/2006) or if such program is modified or canceled, the non-compliant party would have to sell the production on the spot market, and also, eventually, under the remuneration scheme applicable to the spot market, which could affect our revenues. In October 2015, CAMMESA issued Note No. B-102407-4, pursuant to which it mandated us to sell our uncommitted production under the Energy Plus Program to the spot market under the price scheme established by SE Resolution No. 482/2015 (currently SE Resolution 826/2022).

In Note No. 567/07, as amended, the SE established the CMIEE as a maximum fee for WEM Large Users for their surplus demand in the event that they do not have their demand backed with a contract under the Energy Plus Program. As of the date of this annual report, the CMIEE applicable to GUMAs and GUMEs is equal to the higher between 1200 Ps./MWh or the transitory dispatch overcharge and for GUDIs of 0 Ps./MWh. The CMIEE implies an indirect maximum limit of one of the components of the price that generators under the Energy Plus Program may charge.

The guarantees granted by the Company to its affiliates could be enforced, which could have an adverse effect on results of our operations

The Company has guaranteed in due time and form the fulfillment of payment obligations and commercial obligations of some of its affiliates. In the event that the affiliates do not comply with the obligations assumed, the guarantees granted by the Company could be enforced in accordance with their terms and conditions.

As of the date of this annual report, no breaches have occurred that triggered the guarantees, but the Company cannot assure that they will not occur in the future. Such breaches may have an adverse effect on our operational results.

Events that affected PEPE II and PEPE III or similar events may occur in our energy projects

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After PEPE II and PEPE III began their commercial operations, certain defects were evident in the blades of their wind turbines, which led to their inability to be used. Many of the blades had to be replaced. Although the Company and the wind turbine supplier took all necessary measures to replace and repair the defects, we cannot assure the full effectiveness of such repairs or that such defects or other defects do not arise in the future, for example in PEPE III’s Expansion Project or in PEPE VI, which in turn may affect the operations of the Company's wind farms and have an adverse effect on the business, our financial condition, operational results or our ability to pay our debts.

PEA wind turbines may present certain defects which may hinder their production

During the due diligence process for PEA’s acquisition, certain defects in the foundation of some of the wind turbines were detected. Even though Siemens GAMESA guaranteed that such defects were solved, we cannot assure you of the full effectiveness of such repairs or that such defects or other defects do not arise in the future, which in turn may affect PEA’s operations and have an adverse effect in the compliance of PEA’s energy supply agreement with CAMMESA and, ultimately, on the business, our financial condition, operational results or our ability to pay our debts.

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. An increase in competition 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. We compete with other generation companies for the megawatt of capacity that is allocated through public auction processes. For more information, please see “Item 4. Our Generation Business”.

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. If there is an increase in energy output, it would allow us and existing and new generators to dispatch our energy to the grid and our customers efficiently. As a result, an increase in competition could affect our ability to deliver our product to our customers, which would adversely affect our business, 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).

 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 will affect our operations and have an adverse effect in the compliance of the relevant energy supply agreement with CAMMESA and WEM Large Users and, ultimately, on the business, our financial condition, operational results or our ability to pay our debts.

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If in the future we are not in a position to renew our PPAs or execute new PPAs, or if such PPAs are unilaterally modified or resolved, our results of operations and financial condition could be materially adversely affected

We have executed several energy supply agreements with CAMMESA under SE Resolution No. 220/2007, SEE Resolution No. 21/2016, SEE Resolution 287/17 and Renovar Programs. In 2021, two of these energy supply agreements with CAMMESA expired and were not renewed: (i) the 10-year term contract for CTP expired in July 2021; and (ii) the 10-year term contract for CTLL expired in October 2021 (210 MW in total). Moreover, the 10-year term contract for CTEB expired in April 2022 (567 MW). Consequently, energy not committed under sales contracts with CAMMESA will be remunerated at the Spot market, currently, under SE Resolution No. 826/22. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

We cannot assure you that we will be in a position to renew our PPAs or execute new PPAs, 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.

Prohibitions or delays in obtaining the required permits and authorizations for new power generation projects may affect the estimated entry into commercial operations and affect the expected revenues from such projects. Moreover, penalties and fines may apply

Our expansion projects require several permits and authorizations to be obtained at scheduled dates in order to accomplish entry into commercial operations at the estimated dates. We have recently experienced several delays from competent authorities in the issuance of such permits and authorizations.

We cannot assure you that, even when fulfilling all and any legal requirements, the relevant permits would be granted as scheduled. Delays in the entry into commercial operations may result in penalties, loss of dispatch priorities, loss of sales and increased costs and payments, which would affect our operational results.

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.

Electricity demand may be affected by price increases, which could lead power generators such as the Company to record lower revenues

During the economic crisis between 2001 and 2002 in Argentina, the demand for electricity was reduced. This reduction was due to the general decrease in economic activity and the difficulty of many consumers in paying their electricity bills. However, in the following years, electricity demand grew significantly: an average year-on-year increase of 3.5% was recorded in total between 2002 and 2017 (despite a drop in 2009), according to information provided by CAMMESA. This increase in electricity demand was mainly driven by the relatively low cost, in real terms, of electricity for consumers due to subsidies from the Argentine Government.

In 2019, the Social Solidarity and Productive Reactivation Law was enacted, which, among other measures, established a freeze on energy and natural gas rates and the re-launch of a comprehensive rate review for a term of 180 days and empowered the Power Executive to administratively intervene in the ENRE and the ENARGAS. Likewise, SE Resolution 31/2020 was issued, which modified the remuneration scheme of the energy generation segment and established prices denominated in Pesos (previously denominated in Dollars) and reduced said prices in different proportions depending on the technology. For further information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

We cannot guarantee that the measures to be adopted or other measures or regulations that may be adopted in the future by the Argentine Government in relation to tariffs could not have a significant adverse effect on our business, our operational results and our financial situation, or that a new public emergency law will not be sanctioned in the future. We cannot assure you that the regulatory obligations to which the Company is subject will not be further increased, including, but not limited to, higher taxes, unfavorable alterations in rate structures and other regulatory obligations, compliance with which could increase our costs and have a direct negative impact on the results of our operations and our financial condition.

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

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Although the Company complies with all standards and best practices related to environmental safety, an accident involving the materials with which the Company operates could have consequences of environmental impact, damage to industrial facilities, and damage to people, causing a damage to the Company due to the possible unavailability of the equipment and, consequently, could affect our financial condition and our operational results.

Risks Relating 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

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. 1277/2012 and Law No. 27,007. Further changes in such regulations may increase the adverse effect of such measures on the business, revenues and our result of operations and financial condition.

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

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. For more information, please 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 to obtain such concessions or permits will not be imposed. With respect to the CENCH for the Sierra Chata block and the committed investment project, a consortium made up of the Company and Mobil Argentina S.A. has continued negotiations with the Province of Neuquén to settle a readjustment proposal for the current investment plan with the aim of reaching an agreement that allows for the continuity of activities in the CENCH. For more information, see Note 18.2 to our Consolidated Financial Statements.

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 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.

Oil and gas reserves in Argentina are likely to decline

The possibility of replacing our crude oil and gas reserves in the future is dependent on our ability to access new reserves, both through successful exploration and reserve acquisitions. We consider exploration, which carries inherent risks and uncertainties, to be our main vehicle for future growth and reserves replacement. The exploration can only be carried out if the economic and operational prospects are feasible, such as pricing, demand, terms and conditions of sale, environmental impact, among other important factors. Without successful exploration activities or reserves acquisitions, our proved reserves would decline as our oil and gas production would be forced to rely on our current portfolio of assets.

We cannot guarantee that our exploration, development and acquisition activities will allow us to offset the decline of our reserves. If we are not able to successfully find, develop or acquire sufficient additional reserves, our reserves and therefore our production may continue to decline and, consequently, this may adversely affect our future operational results and financial condition.

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

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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 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. For more information, please see “The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operations” and “Item 4—Relevant Events— Measures Designed by the Argentine Government to Address the Covid-19 Outbreak”. Recently, due to the conflict between Russia and Ukraine (See “The ongoing conflict between Russia and Ukraine could adversely affect the global economy, the Argentine economy and our operational results and financial condition”), 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 US$110 per barrel, and the cost of natural gas reached a new record high in Europe.

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.

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

On August 22, 2018 the Argentine Government issued a new Natural Gas Exportation Procedure regulating the process to obtain the authorizations needed to export natural gas. Afterwards, on September 4, 2018, the Argentine Government published Decree No. 793/2018 which imposed an exportation duty on several goods including natural gas until December 31, 2020. The exports duty consists of a Ps. 4 tax on every US$1.00 worth of exports, with a maximum tax rate of 12% on the value of exports. Thereafter, the Social Solidarity and Productive Reactivation Law modified the prior exportation duties for hydrocarbons that are commercialized in the external market. Additionally, since the effective date of the Decree No. 488/20 (Barril Criollo), exports of oil, natural gas and liquefied gas have been exempt 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 US$45/bbl. However, the export duty rate was subject to a gradual increase up to 8% as the reference price rose, which rate was to be applied if the price was equal to or higher than US$60/bbl. On April 27, 2021, through Resolution No. 360/2021, the SE created a new natural gas exportation procedure regulating the procedure for obtaining natural gas export authorizations. This exportation procedure was later modified by SE Resolution No. 774/2022. For more information, please see “Item 4. The Argentine Energy Sector—Oil & Gas Regulatory Framework”.

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.

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.

In the context of the coronavirus pandemic crisis, Russia broke the agreement it had with Saudi Arabia in a dispute over oil production and, in response, Saudi Arabia lowered the price of oil to less than US$30 per barrel, levels that have not been seen for 16 years. Moreover, the United States oil prices traded below zero for the first time ever, and producers and traders were essentially paying other market participants to take their oil. For more information, please see “—The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operation” and “Item 4—Relevant Events— Measures Designed by the Argentine Government to Address the Covid-19 Outbreak”. Recently, due to the conflict between Russia and Ukraine (See: The ongoing conflict between Russia and Ukraine could adversely affect the global economy, the Argentine economy and our operational results and financial condition), 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 US$110 per barrel, and the cost of natural gas reached a new record high in Europe.

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Limits on exports and imports of hydrocarbons and related oil products have affected and may continue to affect our operational results

In recent periods, the Argentine Government has introduced a series of measures limiting exports and imports of hydrocarbons and related oil products, which have prevented oil and gas companies from benefiting from the prices of these commodities in the international markets, and materially affected the competitiveness and operational results of those companies. Pursuant to the gas exportations regime approved by SE Resolution No. 774/2022, gas exportations are authorized in the Neuquina and Austral basin (i) during the non-winter season (between October 2023 and April 2024) for up to 9 MM m³/d in the Neuquén basin and for 2 MM/d m³ in the Austral basin; and (ii) during the winter season for up to 3 MM m³/d in the Neuquén basin. For more information, please see “Item 4. The Argentine Energy Sector—Oil & Gas Regulatory Framework”.

The Argentine Government measures in connection with export-import restrictions may significantly and adversely affect our profitability and prevent us from capturing, in the event that international prices so reflect it, the upside of export prices, and may negatively affect the total volume of refined products sold in the domestic market due to the need to regulate processed crude oil volumes in accordance with our storage capacity, adversely affecting our financial condition and operational results.

We may not be the operating partner in all of the joint arrangements (joint operations for accounting purposes) in which we participate, and actions undertaken by the operators in such joint arrangements could have a material adverse effect on the success of these operations

We generally undertake our activities in exploration and exploitation of hydrocarbons in a particular area by entering into an agreement with third parties to participate in joint arrangements (joint operations for accounting purposes). Under the terms and conditions of these agreements, one of the parties takes the role of operator of the joint operation, and thus assumes responsibility for executing all activities undertaken pursuant to the joint operation agreement. However, we may not assume the role of operator and therefore, in such cases, we are exposed to risks relating to the performance of and the measures taken by the operator to carry out the activities. Such actions could have a material adverse effect on the success of these joint operations, and thus adversely affect our financial condition and operational results.

We conduct most of the operations through joint arrangements (joint operations for accounting purposes), and our failure to resolve any material disagreements with our partners or to continue such joint arrangements could have a material adverse effect on the success of such operations

We conduct most of our oil and gas operations through joint operations and as a result, the continuation of such joint operations is vital to their success. In the event that any of our partners were to decide to terminate the relationship in respect of a joint operation or sell their interest in a joint operation, we may not be able to replace that partner or obtain the necessary financing to purchase that partner’s interest. Accordingly, our failure to resolve disagreements with our partners or to maintain our joint operations could adversely affect our ability to conduct the underlying operations of such joint operations, which, in turn, could negatively affect our financial condition and operational results.

Our failure to comply with our commitments to make certain investments 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. For more information, please 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 onshore and offshore 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 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.

The Argentine Government could alter and delay payments to natural gas producers under key government programs

In recent years, we participated in the Gas Plan I and the Gas Plan II (described below). Companies that participate in the Gas Plan I and the Gas Plan II agree to a Base Volume to be sold at a fixed Base Price and receive between US$4.00 and US$7.50 per million BTU (depending on the production level, the “Surplus Price”) for any amount of natural gas produced in excess of the Base Volume (the “Surplus Injection”). The Argentine Government agrees to compensate participating companies, on a monthly basis, for: (i) any difference between the Surplus Price and the price actually received for the sale of the Surplus Injection and (ii) any difference between the Base Price and the price actually received for the sale of the Base Volume. The Gas Plan I and the Gas Plan II of Pampa finished on December 31, 2017 and June 31, 2018 respectively. On November 16, 2020, through the Decree No. 892/20, the Argentine Government created the Plan Gas.Ar with the purpose of promoting the production of Argentine natural gas. The SE instrumented a tender between producers as sellers, and CAMMESA, natural gas distributors and IEASA as purchasers, for a total base volume of 70 million m³/day. The maximum base price was set at US$3.7/MBTU. A 0.82 factor will adjust the award price for the non-winter period, 1.25 for the winter period, and 1.30 for the additional volume during winter. By means of Decree No. 730/2022, the Plan Gas.Ar was extended until 2028. For more information, please see “Item 4. The Argentine Energy Sector—Oil & Gas Regulatory Framework”.

We face the risk of the Argentine Government suspending or further delaying remaining payments due under Resolution No. 97/18, which would negatively affect our financial condition and operational results.

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

Production from oil and gas fields 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. The level of our future oil and natural gas reserves and production, and therefore our cash flows 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 unable to replace our current and future production, the value of reserves will decrease, and our operational results could be negatively affected, as well as our financial condition and operational results.

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, 2022 was audited by Gaffney, Cline & Associates, as the Independent Reserves Engineers Firm, based on in 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.

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.

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Oil and gas reserves engineering is a subjective process of estimating accumulations of oil and gas that 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. For more information, please 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. In fact, the provinces of La Pampa, Neuquén and Chubut have formed companies to carry out oil and gas activities on behalf of their respective provincial governments. The state-owned energy companies IEASA, YPF and other provincial companies (such as G&P and Empresa de Desarrollo Hidrocarburífero Provincial S.A.) are also 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 IEASA or YPF (or any province-owned company) 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, 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.

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

In recent years, due to regulatory, economic and government policy factors, domestic crude oil, gasoline, diesel and other fuel prices have differed substantially from the prices for such products prevailing on the international and regional markets, and the ability to increase or maintain prices to adjust to international price or domestic cost variations has been limited. International crude oil and related oil product prices have declined significantly from the second half of 2014 through December 2017. For example, in 2020, Decree No. 488/2020 (Barril Criollo) set forth that the barrel price of any crude oil deliveries made in the domestic market up to December 31, 2020 had to be invoiced by producers and paid by refiners and traders, using the price of US$45/bbl as a reference for Medanito crude oil. August 28, 2020 was the tenth consecutive day when Brent average price exceeded US$45/bbl, and as a result the decree ceased to be effective on that date. For more information, please see “Item 4. The Argentine Energy Sector—Oil & Gas Regulatory Framework”.

Regarding natural gas, revenues we obtain as a result of selling natural gas in Argentina are subject to government regulations and could be negatively affected, particularly considering the evolution of gas prices for residential consumers, which in turn are still subject to subsidies, and the evolution of sale price to electric generation plants. This situation, in addition to CAMMESA’s bidding processes, which promoted strong competition in the demand of power generation plants, had a sensitive effect on the demand for the remaining segments, generating a lower quantity of firm commitments and/or contracts for shorter terms. We cannot assure that in the future new regulations on local oil prices will not be applied.

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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.

The Company is 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 had a recent significant contraction (as a result of Covid-19) 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, global demand for crude oil is expected to increase by 2.3 million barrels per day during 2023.

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 Relating to our Shares and ADSs

Restrictions on the movement of capitals 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

The Argentine Government has 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 strongly 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. We cannot assure you that the Argentine Government will not take similar measures 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.

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 BCL, 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 BCL 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.

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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.

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.

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

A non-U.S. corporation will be a 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 (the “asset test”).

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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 with respect to our 2021 and 2022 taxable years. 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 2023 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, a U.S. Holder (as defined in “Taxation—United States Federal Income Tax Considerations”) may incur significantly increased U.S. federal income tax on gain recognized on the sale or other disposition of our common shares or ADSs and on the receipt of distributions on our common shares or ADSs to the extent such gain or distribution is treated as an “excess distribution” under the relevant U.S. federal income tax rules, and such U.S. Holder may be subject to burdensome reporting requirements. Further, 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.

See “Item 10. Additional Information—Taxation—United States Federal Income Tax Considerations—Passive Foreign Investment Company Rules” for more details.

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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.pampaenergia.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 and CPB, by way of absorption, with Pampa as the surviving company. The respective Shareholders’ Meetings approved the mergers and the CNV granted its administrative consent to the mergers, which were registered with the IGJ.

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.”

For a description of our strategic divestments, see “Item 4. Information on the Company— Our Business—Relevant Events— Strategic Divestments.”

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OUR BUSINESS

Overview

We are an independent energy integrated company in Argentina, participating in the electricity and the gas value chains. As of December 31, 2022, we, our subsidiaries, joint businesses and our affiliates are engaged in the generation and transmission of electricity, oil and gas exploration and production, petrochemicals, hydrocarbon commercialization and transportation, and oil distribution (for more information, please see Note 5.2 to the Consolidated Financial Statements):

 

Note: As of December 31, 2022. 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. The sum of the parts is subject to rounding.

1 It includes 567 MW at CTEB. 2 It considers CTEB’s 260 MW expansion, commissioned on February 22, 2023; PEPE IV (63 MW) and PEPE VI (94.5 MW, announced in February 2023).

3 2022 average production.

4 In 2023, a production block and an exploration block were relinquished.

· Generation. We are one of Argentina’s leading independent power generation operator. Our generation installed capacity reached approximately 5,088 MW as of December 31, 2022, which represents approximately 12% of Argentina’s installed capacity. In addition, we have committed to develop projects that we expect will increase our installed capacity by 418 MW (see “—Our Generation Business—Summary of the committed expansion projects”), which would bring our total installed capacity to 5,505 MW.

As of December 31, 2022, we are engaged in the generation business through:

o CTGEBA, thermal generation plant located at the central node of the Argentine electricity grid, in Marcos Paz, in the western part of the Greater Buenos Aires area, comprised of two CC gas-fired generating units, one with a 684 MW power 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 with a 182 MW power capacity, known as Genelba Plus, installed in 2009 and repowered in June 2019, another gas turbine of 188 MW installed in 2019, and the 199 MW steam turbine incorporated on July 2, 2020, completing Genelba Plus’s expansion project started in 2017. CTGEBA is the largest thermal generation plant in Argentina, with an installed capacity of 1,253 MW, which represents 2.9% of Argentina’s installed capacity;

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o CTEB, a thermal gas-fired generation plant located in the petrochemical complex of the City of Ensenada, Greater La Plata, Province of Buenos Aires, is owned by CTB, an affiliate that we co-control with YPF. Furthermore, CTEB may consume natural gas or GO and has two tanks for the storage of fuel oil with a combined capacity of 45,000 m³. With the completion and commissioning of the combined cycle on February 22, 2023, it has a total capacity of 827 MW, which represents 2% of Argentina’s installed capacity;

o CTLL, a thermal gas-fired thermal generation plant located in the Province of Neuquén (close to one of Argentina’s largest gas fields bearing the same name as the plant) which 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, a 105 MW GE aero-derivative gas turbine installed in May 2016, a 105 MW GE gas turbine installed in August 2017 and 15 MW MAN gas engines installed in August 2021. CTLL has an installed capacity of 780 MW, which represents 1.8% of Argentina’s installed capacity;

o Hidroeléctrica Los Nihuiles and Hidroeléctrica Diamante, two hydroelectric power generation systems located in the Province of Mendoza, through our subsidiaries HINISA and HIDISA. Pampa holds 61% and 52% interests in HIDISA and HINISA, respectively. Hidroeléctrica Los Nihuiles and Hidroeléctrica Diamante have an aggregate installed capacity of 653 MW, which represents 1.5% of Argentina’s installed capacity;

o CPB, a thermal generation plant located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires. The boilers of CPB can be fed either by fuel oil or natural gas. Natural gas is supplied through a 22 km gas pipeline operated and maintained by CPB, connected to TGS’ main gas pipeline system. Furthermore, CPB has two tanks for the storage of fuel oil with a combined capacity of 60,000 m³. CPB has an installed capacity of 620 MW, which represents 1.4% of Argentina’s installed capacity;

o CTG, a thermal gas-fired generation plant located in General Güemes, in the Province of Salta, comprised of a 261 MW open cycle thermal power generation plant which, with the addition in September 2008 of a natural gas-fired turbo generator unit of 100 MW, has an installed capacity of 361 MW, that represents 0.8% of Argentina’s installed capacity;

o HPPL, a hydroelectric power generation located in the Comahue region, in the Province of Neuquén, which has three electricity generating units with an installed capacity of 285 MW, that represents 0.7% of Argentina’s installed capacity;

o PEMC, a wind farm located in Bahía Blanca, in the Province of Buenos Aires. The wind farm consists of 29 V-126 Vestas wind turbines, each with a 3.45 MW power capacity and an 87-meter hub height. PEMC has a capacity of 100 MW of renewable energy, that represents 0.2% of Argentina’s installed capacity;

o CTIW, a thermal generation plant consists of 6 dual-fuel (natural gas or fuel oil) Wärtsilä engines located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires. The engines are highly efficient, with a 46% performance rate. The plant is interconnected to the 132 kV grid through Transba substation. Liquid fuel is supplied using CPB’s unloading and storage facilities, and natural gas is also provided through CPB’s internal facilities. CTIW has an installed capacity of 100 MW, that represents 0.2% of Argentina’s installed capacity;

o CTPP, a thermal power generation plant at Pilar Industrial Complex, located in Pilar in the northern greater Buenos Aires area, which comprises six Wärtsilä motor generators (Wärtsilä W18V50DF), and which may consume either fuel oil stored in own tanks or natural gas supplied through a dedicated gas pipeline which is connected with Transportadora de Gas del Norte S.A.’s main gas pipeline, whereas the energy is evacuated through a 132 kV line connected to the Pilar substation owned by Edenor. CTPP has an installed capacity of 100 MW, which represents 0.2% of Argentina’s installed capacity;

o PEA is a wind Farm, located in the Province of La Rioja, which was commissioned in March 2020. The wind farm is comprised of 38 Siemens Gamesa G-114 wind turbines, each with a 2.625 MW power capacity and an 80-meter hub height. It has an installed capacity of 99.75 MW, which represents 0.2% of Argentina’s installed capacity;

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o PEPE II is our second wind farm located in the City of Bahía Blanca, Province of Buenos Aires, which was commissioned on May 10, 2019. It consists of 14 V-136 Vestas wind turbines, each with a 3.8 MW power capacity and a 120-meter hub height. PEPE II has an installed capacity of 53 MW of renewable energy, which represents 0.1% of Argentina’s installed capacity;

o PEPE III, PEPE II’s twin wind farm, is our third wind farm located in Coronel Rosales, on national route No. 3, 45 km from the City of Bahía Blanca, Province of Buenos Aires, which was also commissioned on May 10, 2019. PEPE III currently has an installed capacity of 53 MW of renewable energy, which represents 0.1% of Argentina’s installed capacity. The wind farm has a committed expansion project, called PEPE IV, which includes the assembly and installation of 18 Vestas wind turbines. Such capacity will increase to 134.2 MW, once PEPE IV is completed, which we expect to occur in the second quarter of 2023;

o CTP, a thermal gas-fired generation plant located at Piquirenda, General San Martin, in the Province of Salta, with an installed capacity of 30 MW, which represents 0.1% of Argentina’s installed capacity; and

o EcoEnergía, a cogeneration thermal power plant located in Bahía Blanca, in the Province of Buenos Aires with an installed capacity of 14 MW, which represents 0.03% of Argentina’s installed capacity.

We are currently developing PEPE VI, our new wind farm project located in the City of Bahía Blanca, Province of Buenos Aires. The project will be built in three stages with a total estimated investment of US$500 million. The first stage includes the assembly and installation of 21 wind turbines. to add 94.5 MW of power capacity through 21 Vestas wind turbines of 4.5 MW each, the commissioning of which is estimated for the third quarter of 2024.

Our generation business segment recorded US$663 million in revenue and an operating income of US$336 million for the year ended December 31, 2022.

· Oil and Gas. We are engaged in the oil and gas business through direct interests in oil and gas blocks in Argentina:

o As of December 31, 2022, our combined crude oil and natural gas proved reserves amounted to approximately 179.4 million boe, 61% of which were proved developed reserves. Natural gas accounted for approximately 94% of our combined proved reserves and liquid hydrocarbons for 6%;

o As of December 31, 2022, our combined oil and gas production in Argentina averaged 53.1 thousand boe per day, with operations in 13 production blocks, 5 exploratory blocks, and 895 productive wells. Crude oil accounted for approximately 5.3 thousand boe per day, while natural gas accounted for approximately 346 million standard cubic feet per day, or 57.8 thousand boe per day based on a measure of conversion of 6,000 cubic feet of gas per barrel of oil equivalent; and

o In addition, we have a direct 2.1% interest in Oldelval, which operates main oil pipelines providing access to Allen, in the Comahue area and the Allen – Puerto Rosales oil pipeline which allow for the transportation of the oil produced in the Neuquina Basin to Puerto Rosales (a port in the City of Bahía Blanca) and the supply of the Plaza Huincul and Luján de Cuyo distilleries, all located in the pipeline’s area of influence.

Our oil and gas business segment recorded US$646 million in revenue and an operating profit of US$194 million for the year ended December 31, 2022.

· Petrochemicals. We are engaged in the petrochemicals business through two plants that are entirely based in Argentina and produce styrene, SBR and polystyrene, with a domestic market share that ranged between 94% and 100% (per Company estimates) as of December 31, 2022. The petrochemicals division has the following assets:

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o 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 is used as raw material, and propellants), 155,000 tons of aromatics, 290,000 tons of gasoline and refines, 160,000 tons of styrene, 55,000 tons of SBR, 180,000 tons of ethyl benzene and 31,000 tons of ethylene; and

o a polystyrene plant located in the City of Zárate, in the Province of Buenos Aires, with a production capacity of 65,000 tons of polystyrene.

Our petrochemicals business segment recorded US$617 million in revenue and an operating profit of US$52 million for the year ended December 31, 2022.

· Holding and Other Business. We also hold other interests, including:

o As of December 31, 2022, we held a 29.3% direct and indirect interest in TGS, the country’s largest gas transportation company, owning 9,233 km of gas pipelines and a natural gas liquids plant, General Cerri, with a production capacity of 1 million tons/year.

o We hold a 26.33% indirect interest in Transener. Additionally, Transener holds a 100% interest in Transba. As of December 31, 2022, our electricity transmission operations covered 21,7 kilometers of high voltage transmission lines, representing approximately 86% of the high voltage system in Argentina;

o We hold a 30.1% indirect interest in OCP, licensee company of an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day; and

o We hold a 70% interest in Enecor, an independent electricity transmission 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. Such services are provided under a 95-year concession, which is due to expire in 2088.

Our holding and other business segment recorded US$20 million in revenue and an operating profit of US$49 million for the year ended December 31, 2022.

Relevant Events

Generation

PEPE IV expansion (formerly, PEPE III expansion)

During the fourth quarter of 2021, the Company announced PEPE III’s expansion project (now called PEPE IV), adding a gross capacity of 81 MW, with an estimated investment of US$128 million to be partially financed by the Company’s first green bond. Its output will be sold in the MAT ER through a US$-denominated PPA with private parties, and it is estimated to be commissioned in stages, fully commissioned in the second quarter of 2023.

PEPE IV is located in Coronel Rosales, 45 km from the City of Bahía Blanca, Province of Buenos Aires. Currently, it comprises 14 Vestas wind turbines and during 2021 its load factor reached 58%, highlighting the outstanding wind quality in the area. The expansion project consists of the assembly and installation of 18 wind turbines of the same brand.

On December 29, 2022, the first 4 wind turbines with a capacity of 18 MW begun their operations, and on February 25, 2023, another 4 wind turbines started operating. We expect to begin operations of all 18 wind turbines during the second quarter of 2023.

Development of a new wind farm: PEPE VI

On February 2023, we announced PEPE VI, our new wind farm project located 18 km from the City of Bahía Blanca, Province of Buenos Aires, next to PEMC and PEPE II. PEPE VI will be built in three stages with a total estimated investment of US$500 million. The first stage includes the assembly and installation of 21 Vestas wind turbines of 4.5 MW each, the commissioning of which is estimated for the third quarter of 2024.

Acquisition of 50% of Greenwind

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On August 12, 2022, Pampa Group acquired from its business partner 50% of its indirect stake in Greenwind, for a total amount of US$ 20.5 million. Therefore, Pampa Group is now the sole shareholder of Greenwind.

Greenwind’s only asset is PEMC, a wind farm with a 100 MW installed capacity, which has a PPA with CAMMESA under the RenovAr Program for a 20-year period beginning on June 8, 2018.

Acquisition of VAR

On December 16, 2022, we acquired 100% of VAR, a company that operates PEA, located in the Province of La Rioja, with a nominal capacity of 99.75 MW. The purchase price was US$ 170 million, US$ 128 million were paid at closing and the remaining amount will be paid in 12 monthly installments during 2023. PEA has a PPA with CAMMESA under RenovAr Program Round 1.

Acquisition of Autotrol Renovables S.A.

On September 30, 2022, we acquired 100% of the capital stock of Autotrol Renovables S.A., an entity holder of the “Wayra I Wind Farm” project (registered with the National Renewable Energy Projects Registry, “RENPER”) for a price of US$ 50 thousand. 

Updates to the remuneration scheme for capacity not covered by contracts

SE Resolution No. 31/20, which modified certain aspects of the remuneration scheme set by SRRYME Resolution No. 1/19, was in effect until January 2021. The entire remuneration scheme was converted to the local currency at an exchange rate of Ps. 60/US$, and an adjusting factor was established from the second month of its application, with a formula consisting of 60% CPI and 40% IPIM. Moreover, it modified power capacity payments and incorporated an additional monthly remuneration in the HMRT. However, the adjusting factor was eventually not implemented.

Furthermore, SE Resolution No. 440/21, issued on May 21, 2021, increased the remuneration scheme established by SE Resolution No. 31/20 by an average of 29%, retroactive as of February 2021. This resolution also canceled the adjusting factor.

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 exports remuneration. Such remuneration scheme was again modified by SE Resolution No. 826/22 issued on December 12, 2022, 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 an additional 28% increase to be applied as of August 2023. For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

Transitional pricing adjustment for legacy energy

To guarantee the supply of CAMMESA’s electricity exports and procure power plants’ availability and maintenance, SE Resolution No. 1037/21, issued on November 2, 2021, established an additional and transitional recognition for legacy power plants (except for binational hydros) to be remunerated from September 2021 to February 2022.

On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that covered thermal power plants have a use factor of 70%, for which 100% of the power remuneration, would be settled and an additional amount equivalent to Ps. 1,000/MWh of exported energy will be paid in proportion to the energy generated by each generator in such month. This remuneration was repealed by SE Resolution No. 238/22 beginning in February 2022, and subsequently by SE Resolution No. 826/22,, as mentioned before.

CTEB: Maturity of PPA at its steam turbine and commercial operation of its CC

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After fulfilling the 10-year PPA under SE Resolution No. 220/07, CTEB (567 MW) steam turbine started to be remunerated under the spot energy scheme (SE Resolution No. 440/21) as of April 27, 2022.

Also, the CC was commercially enabled starting at midnight on February 22, 2023, when CAMMESA granted the corresponding permits to CTEB's EBARTV01 unit for up to 260 MW of gross power operating with natural gas. Thereafter, the remuneration stipulated in the PPA signed with CAMMESA (SE Resolution No. 220/07) was received for a term of 10 years. With the completion of the project, the total gross power of CTEB rises to up to 827 MW, contributing with a cleaner and more efficient generation park to the electricity supply in a key area. We, as co-controlling shareholders together with YPF, invested more than US$250 million. With this commercial authorization, the resolutive condition of the guarantees granted by the co-controlling shareholders to CTB's ON holders was met. Therefore, said guarantees have ended, losing all force and validity.

Technical problem at CTLL

On June 23, 2022, a technical problem occurred at a gas turbine of CTLL. We, together with the manufacturer, performed the necessary work to dismantle and repair the failure. Moreover, we are making all required filings before the insurance companies to collect the damages compensation resulting from the failure and minimize losses related to the breach of availability commitments.

Hydroelectric concessions termination

On March 10, 2022, the SE issued Resolution No. 130/22 that created a “work team” to analyze the situation of the hydroelectric concessions that are due to terminate in the next years, including HIDISA, HINISA and HPPL. The work team must present in a one-year period the respective reports regarding the concessions that terminate in 2023 (Alicurá, El Chocón, Arroyito, Planicie Banderita and Piedra del Águila), and within a two-years for the rest (including HIDISA and HINISA), except for HPPL and F. Ameghino whose terms ends on 2029 and 2044, respectively.

Oil and Gas

Gas Plan

Plan Gas.Ar

According to Decree No. 892/20, on November 16, 2020, 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.

On December 15 and 29, 2020, the SE awarded 67.4 million m³/day of natural gas (55% destined for power plants) at an average annual base price of US$3.5/MBTU and an additional volume of 3.6 million m³/day during the winter period at US$4.7/MBTU. Pampa was awarded a base volume of 4.9 million m3/day at US$3.6 per million BTU and an additional 1.0 million m³/day volume during the winter period at US$4.7 per million BTU.

In the second round (SE Resolution No. 129/21 issued on February 22, 2021), a total of 3.3 million m³/day at an average of US$4.7/MBTU was awarded for the winter period (May – September) 2021 – 2024, with deliveries from June 2021. The Company participated in this round and was awarded 0.8 million m³/day at an average of US$4.7/MBTU.

Moreover, in the third round (SE Resolution No. 984/21 issued on October 19, 2021), a total of 3 million m³/day was awarded at US$3.43/MBTU for the May 2022 – December 2024 period under a gas supply agreement on the same conditions of the first round awarded in December 2020. The Company participated and was awarded 2 million m³/day at US$3.347/MBTU.

On November 4, 2022, the Executive Branch issued Decree No. 730/2022 by means of which the Plan Gas.Ar was extended until 2028. On November 11, 2022, the SE issued Resolution No. 770/2022, calling for a tender for the extension of the commitments assumed by the awardees under the first and third rounds in the Neuquina basin (round 4.1), as well as the award of the following incremental volumes in the Neuquina basin (round 4.2). In addition, SE Resolution No. 770/2022 called for a tender in order to (i) extend the commitments assumed by the awardees of the first round in the provinces of Chubut and Santa Cruz (round 5.1), and (ii) submit incremental gas projects in the Austral and Northeast basins under the incremental activity plan set forth in Decree No. 826/2020 (as amended by Decree No. 730/2022). Under rounds 4 and 5, approximately 100 m³/day were awarded at an average price of US$3.5/MBTU. We were awarded: (i) with respect to the extension of round one, a volume of 4.9 million m³/day at US$3.600/MTBU, and (ii) with respect to the extension of round three, a volume of 2 million m³/day at US$3.347/MTBU.

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Expansion of capacity and all-time-high gas production record at El Mangrullo

In line with our production commitment under the Gas.Ar Plan and the exceptional productivity of El Mangrullo, the processing capacity of such block was expanded in three stages: (i) in May 2022, at the start of the winter period, the production plant was expanded in 2.5 million m³/day; (ii) in November 2022, the new gas treatment plant was commissioned, with a capacity of 4.8 million m³/day; and (iii) the extension of the use of the Rincón del Mangrullo facilities for 2.0 million m³/day until January 2025. Consequently, the processing capacity of El Mangrullo, a block fully owned by Pampa, was increased to a maximum of 13.6 million m³/day.

Gas export

In May and December 2021, we were granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m³/day and 1.22 million m³/day for the October 2021 – April 2022 and January – April 2022 periods, respectively.

In the summer season, we export to our clients in Chile on a spot basis. In November 2020, we were granted permits to export gas to Chile on an interruptible basis, expiring between April 2021 and January 2022. Moreover, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were granted, with expirations between November 2022 and December 2024. On February 2023, we were granted interruptible exports to Chile with expirations between December 2024 and May 2025. For more information, please see “Item 4. The Argentine Energy Sector—Oil & Gas Regulatory Framework Regulations - Regulations Specifically Applicable to the Gas Market—Natural Gas Export”.

Changes in productive block concessions

On January 19, 2023, we accepted an offer from Oilstone Energía S.A. for the termination of our 15% interest in 9 wells in Anticlinal Campamento, which represented less than 1% of our 2022 gas production, effective as of January 1, 2023. The agreement releases us from any future obligation regarding this block.

On February 3, 2023, the extension of the Aguaragüe block concession (including San Antonio Sur) was agreed upon for a 10-year period (until 2034), and is awaiting the issuance of the Provincial Decree. We own 15% of such block, whose surface area is 1,642 km2 and is located in Cuenca Noroeste.

Strategic Divestments

Sale of Controlling Stake in Edenor

On December 28, 2020, we entered into a binding stock purchase agreement with Empresa de Energía del Cono Sur S.A. (“Cono Sur”), as purchaser, and Integra Capital S.A., Messrs. Daniel Eduardo Vila, Mauricio Filiberti and José Luis Manzano, for the sale of our controlling interest in Edenor. The agreement consisted of a transfer of Pampa’s total Class A shares, which represent 51% of the capital stock and voting rights of Edenor, pursuant to certain conditions precedent, including but not limited to the approval by Pampa’s shareholders’ meeting and the ENRE (the “Transaction”).

The purchase price was paid in three installments: (i) 21,876,856 Class B shares of Edenor and US$5 million, which was collected on the execution date of the agreement; (ii) US$50 million, which were paid on the closing date; and (iii) US$40 million, which were paid one year after the closing date. To the date of this report, there are no pending balances under this agreement.

Venezuela

With the acquisition of Petrobras Argentina, we acquired four productive blocks in Venezuela: Oritupano Leona, La Concepción, Acema and Mata. We held interests in such productive blocks through direct and indirect interests in mixed-capital companies operated by PDVSA: Petroritupano S.A., Petroven-Bras S.A., Petrowayú S.A. and Petrokariña S.A.

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On May 6, 2022, we assigned the above-mentioned interests in Venezuela to Integra Petróleo y Gas S.A. and filed the authorizations regarding the change of control before the Government of Venezuela, and its approval is pending. As consideration, Integra Petróleo y Gas S.A. will pay Pampa 50% of any monetary or in kind compensation it obtains related the blocks and companies.

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 participation 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 US$5.7 million, and the buyer paid 30% of such price at closing, and the remaining 70% balance will be paid 12 months after the closing.

Measures Designed by the Argentine Government to Address the Covid-19 Outbreak

In late December 2019, a notice of a pneumonia originating from Wuhan, Hubei province (Covid-19, caused by a novel coronavirus) was reported to the World Health Organization, with cases soon confirmed in multiple provinces in China, as well as in other countries. Since December 2019, the virus has spread globally and, as of the date of this annual report, affected almost every country around the world, including Argentina. Argentina adopted several measures in response to the Covid-19 outbreak in the country aimed at preventing massive infections of Argentine residents and the congestion of the Argentine health service, which include, mainly: (i) imposition of a nation-wide mandatory lockdown, where exceptionally essential transit was permitted (“Aislamiento, Social, Preventivo y Obligatorio” or “ASPO”), which was later superseded by a “Distanciamiento Social, Preventivo y Obligatorio”, extended on several occasions, for all people who reside or transit in urban areas and in the Argentine provinces that do not have sustained community transmission of the virus and satisfy the corresponding epidemiological and sanitary parameters; (ii) closure of activities with large crowds; (iii) prohibition of audience attendance at sporting events; (iv) stricter surveillance of Argentine borders; (v) shut-down of in-person classes at schools and universities; (vi) closure of Argentine borders; (vii) recognition of Covid-19 as an occupational disease; (viii) increase in the budget allocation for supporting health systems; and (ix) a vaccination campaign; among others. Simultaneously, the Argentine Government implemented several stimulus measures to limit the effects of the Covid-19 outbreak on the economy.

The Argentine Government later provided for several additional preventive measures to limit the effects of the Covid-19 outbreak and carried out a vaccination schedule. To the date of this report, most of Argentine residents have completed their respective vaccination plan and have received vaccination reinforcements.

On December 29, 2022, the Argentine Government through Decree 863/2022 extended the health emergency established by Decree 260/2020 for one more year until December 31, 2023.

For more information regarding the measures currently adopted by the Argentine Government to Address the Covid-19 outbreak, you should visit the Ministry Health’s website: https://www.argentina.gob.ar/salud .The information contained on this websites is not part of, and shall not be deemed incorporated into, this annual report.

Organizational structure

The following chart sets forth our corporate structure as of December 31, 2022. For more information please see “Exhibit 8.1 – List of subsidiaries, Joint Ventures and Associates of Pampa Energía S.A..”

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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, PEA, PEMC and interests in HINISA, HIDISA, and CTB.

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, 2022, 2021 and 2020. 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	Hydroelectric			Wind				Subtotal Hydro + Wind
	HINISA	HIDISA	HPPL	PEMC (1)	PEPE II	PEPE III – IV (2)	PEA (3)
Installed Capacity (MW)	265	388	285	100	53	71	100	1,262
Market Share	0.6%	0.9%	0.7%	0.2%	0.1%	0.2%	0.2%	2.9%
Net Generation 2022 (GWh)	428	303	707	391	231	250	17	2,326
Market Share	0.3%	0.2%	0.5%	0.3%	0.2%	0.2%	0.1%	1.7%
Sales 2022 (GWh)	428	303	707	391	256	250	-	2,335
Net Generation 2021 (GWh)	467	325	550	367	215	256	-	2,181
Variation Net Generation 2022-2021	-8%	-7%	+29%	+6%	+7%	-2%	-	+7%
Sales 2021(GWh)	467	325	550	367	247	256	-	2,212
Net Generation 2020 (GWh)	481	323	742	409	207	243	-	2,404
Variation Net Generation 2021-2020	-3%	1%	-26%	-10%	+4%	+5%	-	-9%
Sales 2020(GWh)	482	323	737	409	207	246	-	2,404
In US$/MWh
Avg. Price 2022	3	12	7	60	54	58	-	26
Avg. Gross Margin 2021	-6	12	7	61	55	58	-	25

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) 100% owned by us beginning on August 12, 2022. Previously, we owned 50% as participation interest. (2) On December 29, 2022 18 aero-generators of 4.5 MW each were authorized. (3) Acquired on December 16, 2022.

Summary of Electricity Generation Assets	Thermal
	CTLL	CTG	CTP	CPB	CTPP	CTIW	CTGEBA	ECO-ENERGÍA	CTEB(1)	Subtotal	Total
Installed Capacity (MW)	780	361	30	620	100	100	1,253	14	567	3,826	5,088
Market Share	1.8%	0.8%	0.1%	1.4%	0.2%	0.2%	2.9%	0.03%	1.3%	8.9%	11.9%
Net Generation 2022 (GWh)	5,103	225	52	1,209	321	308	7,746	73	948	15,985	18,311
Market Share	3.7%	0.2%	0.0%	0.9%	0.2%	0.2%	5.6%	0.1%	0.7%	11.6%	13.3%
Sales 2022 (GWh)	5,103	469	52	1,209	321	308	8,571	152	948	17,133	19,468
Net Generation 2021 (GWh)	4,682	392	53	312	299	301	8,594	75	546	15,252	17,433
Market Share	3.3%	0.3%	0.0%	0.2%	0.2%	0.2%	6.1%	0.1%	0.4%	10.8%	12.3%
Sales 2021 (GWh)	4,692	624	53	313	299	300	9,266	153	546	16,246	18,458

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Summary of Electricity Generation Assets	Thermal
	CTLL	CTG	CTP	CPB	CTPP	CTIW	CTGEBA	ECO-ENERGÍA	CTEB(1)	Subtotal	Total
Net Generation 2020 (GWh)	4,406	368	55	576	193	229	7,912	72	255	14,065	16,470
Variation Net Generation 2021-2020	6%	7%	-4%	-46%	55%	31%	9%	5%	114%	8%	6%
Sales 2020 (GWh)	4,399	418	55	575	193	229	7,946	89	255	14,159	16,563
In US$/MWh
Avg. Price 2021	31	45	84	75	126	100	34	33	N/A	47	46
Avg. Gross Margin 2021	26	10	41	12	103	78	17	12	N/A	31	30

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⁾ Operated by us, which holds an interest of 50% in CTB.

Summary of the committed expansion projects

Project	MW	Marketing	Currency	Date of Commissioning
Thermal
CTEB(1)	260	PPA for 10 years	US$	CC: February 22, 2023
Renewable
PEPE IV	63	MAT ER	US$	Second Quarter 2023(estimated)
PEPE VI	94.5	MAT ER	US$	Second Quarter 2023(estimated)

.⁽¹⁾ Operated by Pampa, which holds an interest of 50% in CTB.

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 239 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 under the Energy Plus Program 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. CTGEBA’s CC is sold in the spot market, whereas Genelba Plus’ gas turbine energy is sold under Energía Plus, and the new gas turbine incorporated in 2019 is sold in the spot market until the commissioning of the CC, when it will start to be sold under a PPA. Currently, the total installed capacity of the CTGEBA complex amounts to 1,253 MW, which represents 2.9% of Argentina’s installed capacity. From 2000 to 2022, CTGEBA’s historical average annual generation was 5,196 GWh, with a generation record high of 8,594 GWh in 2021, and a record low of 3,438 GWh in 2001.

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 is currently comprised of (i) two open cycle gas turbines with an installed capacity of 567 MW; and (ii) a steam turbine that completed the combined cycle with up to a 260 MW capacity, which entered into commercial operations on February 22, 2023. Both (i) and (ii) have a total installed capacity of 827 MW, which represents 2% of the installed capacity in Argentina. From 2013 to 2022, the average annual generation amounted to 1,254 GWh, with a high generation record of 2,093 GWh in 2016, and a low record of 255 GWh in 2020. YPF and Pampa will be in charge of CTEB’s operating management on an alternate basis, for periods of four years. Pampa is currently in charge of operations until June 2023.

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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 2022, CTLL’s average annual generation was 2,309 GWh, with a generation record high of 5,103 GWh in 2022, and a record low of 272 GWh in 2002.

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 sells electricity to the spot market. CPB has an installed capacity of 620 MW, which represents 1.4% of Argentina’s installed capacity. From 1997 to 2022, CPB’s average annual generation was 1,893 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 under the Energy Plus Program, which accounts for 0.8% of Argentina’s installed capacity. From 1993 to 2022, its average annual generation was 1,609 GWh, with a generation record high of 1,903 GWh in 1996, and a record low of 225 GWh in 2022.

CTIW

CTIW is located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires, and consists of six high-efficiency Wärtsilä engines. CTIW is able to fire either natural gas or fuel oil. Engines are high-efficiency, with a 46% performance rate.

The power plant is interconnected to the 132 kV grid through a substation owned by Transba. Liquid fuel supply is made using CPB’s discharge and storage facilities, and natural gas is also supplied from this power plant's internal facilities. On December 22, 2017, CAMMESA granted the commercial operation of CTIW, pursuant to a PPA executed between CAMMESA and Pampa, as awardee pursuant to the call for new generation capacity under Resolution No. 21/2016 of the SEE. 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 2022 was 285 GWh, with a generation record high of 312 GWh in 2019, and a record low of 229 GWh in 2020.

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.

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The plant, which was built under SEE Resolution No. 21/2016 is made up of six cutting-edge Wärtsilä engines with an approximate 43% performance rate. 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 2022 was 235 GWh, with a generation record high of 321 GWh in 2022, and a record low of 168 GWh in 2019.

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 2022, its average annual generation was 104 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 and sells electricity in the Energía Plus market. EcoEnergia has a power capacity of 14 MW, which accounts for 0.03% of Argentina’s installed capacity. From 2012 to 2022, EcoEnergía’s average annual generation amounted to 91 GWh, with a generation record high of 108 GWh in 2018, and a record low of 72 GWh in 2020.

Hydroelectric Generation Plants

We hold interests in three hydroelectric generation plants Hidroeléctrica Diamante (through our subsidiary HIDISA), Hidroeléctrica Los Nihuiles (through our subsidiary HINISA) and, and HPPL (that we fully own).

HIDISA

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 2022, the average annual generation has been 531 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.

HINISA

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 compensator 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 440 m to 480 m. HINISA has an installed capacity of 265 MW, which represents 0.6% of the installed capacity in Argentina. From 1990 to 2022, the average annual generation was 786 GWh, with the highest level of generation (1,250 GWh) recorded in 2006 and the lowest level (467 GWh) recorded in 2021. HINISA also owns 1.6% of the capital stock of TJSM and 1.4% of the capital stock of TMB.

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Summary of HINISA and HIDISA concessions

HINISA’s and HIDISA’s main purpose is the generation, sale and bulk trading of electric power through the exploitation of hydroelectric systems pursuant to the terms and conditions of the following concessions: (i) Provincial concessions granted by the Argentine Government of the Province of Mendoza with similar terms and conditions (for HINISA and HIDISA) and at each company’s own risk for the hydroelectric exploitation of the Atuel River, in the case of HINISA, and the Diamante River, in the case of HIDISA. These concessions were granted pursuant to Provincial Law No. 6,088 dated December 21, 1993 and related provisions; and (ii) national concessions granted by the Argentine Government with similar terms and conditions (for HINISA and HIDISA) and at each company’s own risk for hydroelectric power generation through HINISA’s and HIDISA’s respective hydroelectric systems. These concessions were granted pursuant to Laws No. 15,336, No. 23,696 and No. 24,065 and related provisions.

Term. The term of the HINISA and HIDISA concession agreements is 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 will expire on 2024.

Royalty payments. Each of HINISA and HIDISA is required under the respective concessions to make the following monthly royalty payments: (i) royalties in favor of (1) the Province of Mendoza, of up to 12% in the case of HIDISA and up to 6% in the case of HINISA, and (2) the Province of La Pampa, up to 6% in the case of HINISA, in each case, of the amount resulting from the application of the corresponding bulk sale rate to the electricity sold, pursuant to the provisions of Section 43 of Law No. 15,336, as amended by Law No. 23,164. Pursuant to applicable regulations, in order to establish the basis for the calculation of such royalties, the monomic price (the price of electricity that includes both the price of energy and the capacity charge) of the electricity produced resulting from the following formula should be used: the sum of the value of power generated at the hour value fixed by the wholesale market plus the amount receivable for the power rendered to the spot market if such power were sold within a certain month, divided by the total power generated during the given month; (ii) royalties in favor of the Argentine Government of (1) up to 2.5% of the amount used as the basis for the royalties calculation in the case of HIDISA, and (2) up to 1.5%, estimated on the same basis in the case of HINISA; and (iii) royalties in favor of the Province of Mendoza of up to 2.5% of the amount used as the basis for the royalties calculation for both HINISA and HIDISA.

As of February 2021, SE Resolution No. 440/21 increased the values defined in SE Res. No. 31/20 by 29%. It also repealed the automatic adjustment mechanism included in SE Resolution No. 31/20 (See “The Argentine Energy Sector—Electricity Regulatory Framework”).

Contingency fund. HINISA and HIDISA, along with the other Argentine hydroelectric generation companies, are obligated to 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 companies’ plants, and US$5 million that are not covered by their respective insurance policies.

As a result of the economic crisis in Argentina in 2001 and 2002, the foundation’s administrative council decided that the contribution to the contingency fund in U.S. Dollars required under the concessions, the bidding terms and conditions and the relevant provisions of HINISA’s and HIDISA’s by-laws had to be converted into Pesos at an exchange rate of Ps.1.00 = US$1.00. The indexation clauses contained in such concessions were also replaced with the Coeficiente de Estabilización de Referencia (CER) (a benchmark stabilization coefficient). Upon the conversion from U.S. Dollars into Pesos, the Peso value of the contingency fund exceeded the required funding. As a result, HINISA and HIDISA, along with the other hydroelectric generation companies, have suspended payments to the contingency fund. However, we can make no assurance that HINISA and HIDISA will not be required to resume making payments to the contingency fund in the future.

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From the effective date of the concessions until the suspension of payments, HINISA and HIDISA made contributions totaling US$1.3 million and US$1.9 million, respectively.

Fines and Penalties. HINISA and HIDISA are subject to potential penalties and fines under their respective concessions that are calculated on the basis of the aggregate gross amount invoiced for the 12-month period preceding the imposition of any such penalty. Such penalties and fines range 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 governing authorities or the ENRE); 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 governing authorities), from 0.01% to 0.1% (in cases of failure to submit any requested information or failure to file mandatory reports); 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 from 1% to 10% (in cases of any actions considered by the governing authorities as termination events under the concessions). In the event that the fines levied over 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 their obligations under the respective concessions, HINISA and HIDISA have each deposited the amount required for the benefit of the relevant granting authority under the respective concession. Absent any set off by the relevant granting authority in the event of a breach or any other event of non-compliance under the terms of the respective concession agreements, the guarantee amounts would be released to HINISA and HIDISA, respectively, upon the expiration or termination of the respective concession agreement.

Termination of concessions. HIDISA’s and HINISA’s concession agreements may be terminated for the following reasons (i) breach of material contractual and legal obligations, (ii) certain bankruptcy events in respect of HINISA or HIDISA (as applicable), including any liquidation or winding-up proceedings. In such case, the termination of the relevant concession shall be automatic; (iii) force majeure or certain actions by third parties that prevent the compliance by HINISA and HIDISA with their respective obligations under their respective concession agreements; or (iv) expiration of the respective terms of the concession agreements. In case of termination pursuant to item (i) HINISA or HIDISA, as applicable, shall remain in charge of their concessions during a transitional period established by the granting authority, not exceeding 12 months, and shall indemnify the Argentine Government and the Province of Mendoza for any damages caused (the granting authorities may also apply the performance guarantee amounts toward the payment of any damages). Within 90 days following the receipt of the relevant termination notice, a new company must be incorporated, which would be granted a similar concession and a public bidding process would be called for the purpose of selling the shares of such newly formed company. After deducting all fines, interest and withholdings for prospective claims, the balance would be distributed to HINISA or HIDISA, as applicable, as the only compensation for the transfer of the concessions.

In addition, Section 14(d) of Law No. 6,088 of the Province of Mendoza provides for the termination of the concessions for reasons of public interest or expropriation for public use.

After the termination of the concession agreements for any cause, any assets transferred to HINISA and HIDISA under the respective concession agreements shall be transferred back to the Province of Mendoza and the Argentine Government, as applicable.

HPPL

A 30-year concession fully-owned by us, it was awarded for hydroelectric power generation at HPPL beginning in August 1999. The HPPL complex has three electricity generating units and is located in the Comahue region, Province of Neuquén. The dam is made up of loose materials with a waterproof concrete side. It 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 2022, HPPL’s average annual generation was 922 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 main corporate purpose is the generation, sale and bulk trading of electric power through the exploitation of hydroelectric systems pursuant to the following terms and conditions:

Term. The term of the HPPL concession agreements is 30 years, starting from August 30, 1999.

Royalty payments. Pursuant to our concession contract and applicable laws, beginning in August 2002 we paid 1% in hydroelectric royalties, with scheduled annual increases of 1% per year until royalties reached a cap of 12%, based upon the tariff rate applied to block sales of the electricity sold. In addition, we pay the Argentine Government a monthly fee for the use of the water source amounting to 0.5% of the same amount used for the calculation of hydroelectric royalties.

Contingency fund. HPPL, along with the other Argentine hydroelectric generation companies, are obligated to make quarterly payments to a foundation that owns and manages a contingency fund created to cover up to 80% of the difference between of the aggregate amount of potential costs relating to any repair of the hydroelectric systems at any of the hydroelectric generation companies’ plants and US$5 million that are not covered by their respective insurance policies.

Fines and Penalties. HPPL is subject to potential penalties and fines under the concessions that are calculated on the basis of the aggregate gross amount invoiced for the 12-month period preceding the imposition of any such penalty. Such penalties and fines range 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 ORSEP, CAMMESA, any of the regulatory authorities or the ENRE); 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), from 0.01% to 0.1% (in cases of failure to submit any requested information or failure to file mandatory reports); 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 from 1% to 10% (in cases of any actions considered by the regulatory authorities as termination events under the concessions). In the event that the fines levied over 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 their obligations under the respective concessions, HPPL deposited Ps.2.0 million for the benefit of the relevant granting authority under the respective concession. Absent any set off by the relevant granting authority in the event of a breach or any other event of non-compliance under the terms of the respective concession agreement, the guarantee amounts would be released to HPPL upon the expiration or termination of the respective concession agreement.

Termination of concessions. HPPL’s concession agreements may be terminated for the following reasons (i) breach of material contractual and legal obligations, in which case, HPPL, 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). Within 90 days following the receipt of the relevant termination notice, a new company must be incorporated, which would be granted a similar concession and a public bidding process would be called for the purpose of selling the shares of such newly-formed company. After deducting all fines, interest and withholdings for prospective claims, the balance would be distributed to HPPL as the only compensation for the transfer of the concessions; (ii) certain bankruptcy events in respect of HPPL, 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 the compliance by HPPL of its obligations under their concession agreement; or (iv) expiration of the term of the concession agreements.

Renewable Energy

PEMC

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The PEMC is located at Corti, 12 miles from the City of Bahía Blanca, Province of Buenos Aires that is operated by Greenwind. The PEMC consists of 29 Vestas wind turbines, each with a 3.45 MW power capacity and an 87-meter hub height.

On June 8, 2018, CAMMESA granted the commercial commissioning of PEMC, which was obtained before the date originally stipulated in the PPA executed with CAMMESA under the RenovAr Program (for more information, please see “The Argentine Energy Sector – RenovAr Program”). The PEMC contributes 100 MW of renewable energy to the national Argentine grid, which represents 0.2% of the installed capacity in Argentina. From 2019 to 2022, its historical average annual generation was 387 GWh, with a generation record high of 409 GWh in 2020, and a record low of 367 GWh in 2021.

PEPE II

PEPE II is located in the area known as Corti, 20 km away from the City of Bahía Blanca, in the Province of Buenos Aires, near PEMC. PEPE II consists of 14 wind turbines; each turbine is made up of four tower sections, a nacelle and three blades driving the turbine with a total diameter of 120 meters.

PEPE II was commissioned on May 10, 2019 under Res. No. 281-E/2017, which was passed by the former MEyM for the Renewable Energy Term Market (MAT ER) and sells its energy to large electricity consumption users through PPAs between private parties.

PEPE II has an installed capacity of 53 MW, which represents 0.1% of the installed capacity in Argentina. From 2020 to 2022, its historical average annual generation was 217 GWh.

PEPE III and PEPE IV

PEPE III and PEPE IV are located in the City of Coronel Rosales, 45 km from the City of Bahía Blanca. PEPE III consists of 14 wind turbines; each turbine is made up of four tower sections, a nacelle and three blades driving the turbine with a total diameter of 120 meters.

PEPE III was commissioned on May 10, 2019 under Res. No. 281-E/2017, which was passed by the former MEyM for the MAT ER and sells its energy to large electricity consumption users through PPAs executed between private parties. PEPE III has an installed capacity of 53 MW, which represents 0.1% of the installed capacity in Argentina. From 2020 to 2021, its historical average annual generation was 211 GWh.

During the fourth quarter of 2021, the Company announced PEPE III’s expansion project (now called PEPE IV), which will increase the existing gross capacity in 81 MW, with an estimated investment of US$128 million to be partially financed by the Company’s first green bond. Its output will be sold in the MAT ER through a US$-denominated PPA with private parties, and it is estimated to be commissioned in stages and fully commissioned in the second quarter of 2023. The expansion project consists of the assembly and installation of 18 wind turbines. On December 29, 2022, the first 4 wind turbines with a capacity of 18 MW begun their operations, and on February 25, 2023, another 4 wind turbines started operating. We estimate the beginning of operation of all 18 wind turbines for the second quarter of 2023.

In August 2021, both PEPE II and PEPE III were registered wind farms under the IREC standard, issued by the International REC Standard Foundation, and became the first Argentine power generator to certify wind power. The IREC are internationally recognized certificates that companies employ to offset carbon emission mitigation targets and support renewable energy development. We could issue about 500,000 certificates per year, representing approximately 10% of the total certificates issued in the country.

PEA

On December 16, 2022, we acquired 100% of VAR, located in the Province of La Rioja, that was commissioned in March 2020. The wind farm comprises 38 Siemens Gamesa G-114 wind turbines, each with a 2.625 MW power capacity and an 80-meter hub height. PEA has a PPA with CAMMESA under the RenovAr Program Round 1 and a capacity of 99.75 MW which represents 0.2% of Argentina’s installed capacity.

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PEPE VI

On February 2023, we announced PEPE VI, our new wind farm project located 18 km from the City of Bahía Blanca, Province of Buenos Aires, next to PEMC and PEPE II. PEPE VI will be built in three stages with a total estimated investment of US$500 million. The first stage includes the assembly and installation of 21 Vestas wind turbines of 4.5 MW each, the commissioning of which is estimated for the third quarter of 2024.

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 those 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, 2022:

· our combined crude oil and natural gas proved reserves were 179.4 million boe, 61% of which were proved developed reserves. Natural gas accounted for approximately 94% of our combined proved reserves and liquid hydrocarbons for 6%;

· our combined oil and gas production in Argentina averaged 53.1 thousands of boe per day. Crude oil accounted for approximately 5.3 thousands of boe per day, while natural gas accounted for approximately 346 million standard cubic feet per day, or 57.8 thousands of boe per day based on a measure of conversion of 6,000 cubic feet of gas per barrel of oil equivalent; and

· we hold a 2.1% direct interest in Oldelval. Oldelval operates main oil pipelines providing access to Allen, in the Comahue area, and the Allen - Puerto Rosales oil pipeline, which allow for the evacuation of the oil produced in the Neuquina Basin to Puerto Rosales (a port in the City of Bahía Blanca) and the supply of the Plaza Huincul and Luján de Cuyo distilleries located in the pipeline’s area of influence.

We are also engaged in the oil and gas business directly and through investments in OCP.

During 2022, according to the ME&M, gas gross production in Argentina increased by 7% (4.7 billion cubic feet per day on average), whereas oil gross production increased 13% and stood at 584 thousand barrels per day (on average). For December 2022, according to the ME&M, our consolidated oil and gas production accounted for approximately 1% and 8% of total oil production and gas production in Argentina, respectively.

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Key Information Relating to Oil and Gas

As of December 31, 2022, we had interests in 18 areas, joint operations (UTEs) and agreements in Argentina: 13 oil and gas production areas and 5 exploration blocks located within exploration areas or pending authorization for production. As of December 31, 2022, we were directly the contractual operator of eight of the 18 blocks in which we hold equity interest.

Acreage

As of December 31, 2022, 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	1,354	419	223	98

(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 Borde del Limay, Los Vértices, Aguada Pavón and Río Limay Este areas, which are in the process of relinquishment.

(4) Adjusted at our working interest ownership in the gross acreage.

(*) In Estación Fernández Oro and Anticlinal Campamento areas the acreage of the drainage radius of the drilled wells is considered.

Productive Wells

As of December 31, 2022, 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	468	216	427	150	895	365

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 2022, 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.

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	Year ended December 31,
	2022	2021	2020
	Argentina
Gross wells drilled:
Production:
Development wells:
Oil	31	34	14
Gas	35	31	1
Dry wells
Total	66	65	15
Exploration:
Discovery wells:
Oil	3	-	-
Gas	1	1	-
Dry wells		-	-
Total	4	1	-
Net wells drilled:
Production:
Development wells:
Oil	9	9	4
Gas	26	20	0
Dry wells	-	-
Total	34	29	4
Exploration:
Discovery wells:
Oil	1	-	-
Gas	0	0	-
Dry wells	-	-
Total	1	0	0

Note: All figures have been subject to rounding, so figures shown as totals may not add up.

In 2022, our activity was focused on complying with the production commitments within the Plan Gas.Ar. The core of the activity was concentrated in the Neuquén Basin, mainly in El Mangrullo, where 20 wells were drilled, and Río Neuquén, with 10 wells drilled. In Sierra Chata, 5 development wells were drilled, marking the start of the development of the shale reserves. As for oil, 23 wells were drilled in El Tordillo and 17 wells were drilled in Gobernador Ayala.

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 2022, our production was concentrated in three basins: Neuquén, San Jorge and Noroeste. In Argentina, we own 517,000 net acres, and in the Neuquén basin — the most important basin in the country in terms of oil and gas production —we own approximately 369,000 net acres (representing 71% of our total acres). Our most important fields in the Neuquén basin are El Mangrullo, Sierra Chata, Río Neuquén and Rincón del Mangrullo. As of December 31, 2022, we lifted hydrocarbons from 895 productive wells in Argentina.

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For the year 2022, our average daily production was 5,336 barrels of crude oil and 346 million cubic feet of natural gas. Oil production increased by 14% and gas production increased 23% compared to our 2021 average.

The following table sets forth our oil and gas production during 2022. 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, 2022. 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.

			2022 Production
Production Blocks	Location	Basin	Oil (1)	Gas (2)	Oil  Equivalent  (3)	Operator	Direct and Indirect Interest	Expiration
El Mangrullo	Neuquén	NQN	21	91,659	15,297	Pampa	100.00 %	2053
Sierra Chata	Neuquén	NQN	22	8,469	1,433	Pampa	45.55%	2053
Río Neuquén	Neuquén/Río Negro	NQN	268	19,276	3,481	YPF	33.07%(4)/31.42%(5)	2027/2051
Rincón del Mangrullo (6)	Neuquén	NQN	14	4,425	752	YPF	50.00%	2052
Estación Fernández Oro	Río Negro	NQN	2	87	17	YPF	15.00%(7)	2026
Anticlinal Campamento	Neuquén	NQN	-	68	11	Oilstone	15.00%(8)	2026
Río Limay Este (Ex Senillosa)	Neuquén	NQN	-	-	-	Pampa	85.00%	2040
Aguaragüe(9)	Salta	NOA	57	1,600	324	Tecpetrol	15.00%	2023/2027
El Tordillo	Chubut	CGSJ	945	833	1,084	Tecpetrol	35.67%	2027
La Tapera – Puesto Quiroga	Chubut	CGSJ	15	-	13	Tecpetrol	35.67%	2027
Gobernador Ayala	Neuquén	NQN	404	-	404	Pluspetrol	22.51%	2036
Veta Escondida - Rincón de Aranda	Neuquén	NQN	0	-	0	Pampa	55.00%	2027
Los Blancos(10)	Salta	NOA	200	-	200	High Luck	50,00%	2045
Total			1,948	126,419	23,017

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) Over 13 wells.

(8) Over 9 wells.

(9) Includes San Antonio Sur, expiring in 2023, and Aguaragüe, expiring in 2027.

(10) Exploitation concession beginning on October 15, 2020.

The following table sets forth the production of oil and gas in Argentina for the relevant periods:

	Year ended December 31,
	2022		2021		2020
Argentina	Oil (1)	Gas (2)	Oil (1)	Gas (2)	Oil (1)	Gas (2)
Río Neuquén (3)	268	19,276	208	15,704	169	11,788
El Mangrullo (3)	21	91,659	20	71,347	17	58,338
Rincón del Mangrullo (3)	14	4,425	20	6,744	23	9,836
Other blocks	1,644	11,059	1,467	9,308	1,409	9,154
Total	1,948	126,419	1,715	103,104	1,617	89,117

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.

(3) Río Neuquén, El Mangrullo and Rincón del Mangrullo areas are separately included as they contain more than 15% of our total proved reserves.

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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, 2022, the location and basin of each area, our net working interest and the expiration date for the exploration authorization.

			2022 Production
Blocks/UTE	Location	Basin	Oil kbbl	Gas mcf	Total kboe	Operator	Interest	Expiration
Parva Negra Este	Neuquén	NQN	-	50	08	Pampa	42,50%	2019(1)
Rio Atuel	Mendoza	NQN	-	-	-	Petrolera El Trébol	33,33%	2021(1)
Las Tacanas Norte	Neuquén	NQN	-	-	-	Pampa	90,00%	2023
Borde del Limay	Neuquén	NQN	-	-	-	Pampa	85,00%	2015(2)
Los Vértices	Neuquén	NQN	-	-	-	Pampa	85,00%	2015(2)
Total Exploration Blocks			0	50	08
Total Production			1,948	126,419	23,017

Note: All figures have been subject to rounding, so figures shown as totals may not add up.

(1) Under extension process.

(2) Relinquishment process.

As of December 31, 2022, we held interests in approximately 223,000 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, 2022, 2021 and 2020. This table includes our net share of production, joint operations and associates.

	Year ended December 31,
Argentina	2022	2021	2020
	(in US$ per barrel of oil equivalent)
Production cost	6	6	6
Royalties	4	3	2
Depreciation	5	6	7
Total	15	15	15

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, 2022, 2021 and 2020.

	Year ended December 31,
	2022	2021	2020
Argentina
	(in millions of US$)
Oil	136	99	64
Gas	500	344	219
Others	10	10	11
Total	643	453	294

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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, 2022, 2021 and 2020.

	Year ended December 31,
Average price of sale for barrel of Oil and for million cubic feet of Gas	2022	2021	2020
Argentina
Oil (In US$ per barrel of Oil)	70	58	40
Gas (In US$ per thousand cubic feet)	4	3	2

Delivery commitments

Natural Gas

We are committed to providing fixed and determinable quantities of crude oil and natural gas in the near future under a variety of contractual arrangements.

Under the Plan Gas.Ar tender launched at the end of 2020 by the Argentine Government, Pampa committed to produce at least 7.0 million m³/day of base production, of which 70% are at Plan Gas.Ar price of 3.6 dollars per million BTU, plus 1.8 million m³/day of additional production during the winter, 100% at Plan Gas.Ar price of 4.7 million dollars per million BTU.

In October 2021, in the third Round of the Plan Gas.Ar, Pampa was awarded an additional 2 million m3/day at a price of 3.347 dollars per million BTU, for the period beginning in May 2022, ending in December 2024. Jointly, the contracts awarded to Pampa, sum up to a commitment to delivering 9 million m3/day per day all year, an additional 2 million m3/day during the winter period.

In November 2022, the Argentine Government launched the fourth Round of the Plan Gas.Ar. This round extended the first and third rounds from 2025 to 2028. It also established bidding conditions for the natural gas demand related to the new pipeline named “President Nestor Kirchner”. Pampa successfully extended its natural gas commitments for the first and third round with the same price and was awarded an additional 4.8 million m³/day at a price of US$ 3,485 per million BTU from the operational start of the new pipeline until December 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

In November 2022, Oldelval launched a tender in order to assign crude oil producers for a total of 50,000 m3/day of new transportation capacity between Allen-Puerto Rosales, from the period beginning with the pipeline operational entry (estimated on April 2025) and November 2037. Pampa was awarded a capacity of 1,002 m3/day.

Additionally, Oiltanking Ebytem S.A. (an operator of a oil terminal located in Bahia Blanca), launched a storage and dispatch capacity tender with export destination that followed the Oldelval capacity expansion. In this tender, Pampa was awarded with the same capacity as in 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 it will commence the project 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 97% of our estimated proved reserves as of December 31, 2022. 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 19, 2023, included as Exhibit 13.2 to this annual report. As of December 31, 2022, 2021 and 2020, 97%, 96%, and 98%, respectively, of our estimated proved reserves were audited by GaffneyCline.

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As of December 31, 2022, our liquid hydrocarbon and natural gas proved developed and undeveloped reserves totaled 179.4 million of oil equivalent barrels (boe), 10.9 million barrels of liquid hydrocarbons and 1,010.5 billion cubic feet, or 168.4 million boe, of natural gas, of which 981.7 billion cubic feet were estimated to be sales gas and 28.8 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 6% and 94%, respectively, of our total proved reserves as of December 31, 2022.

 As of December 31, 2022, proved developed reserves of crude oil equivalent represented 61% of our total proved reserves of crude oil equivalent and we had proved reserves equal to approximately eight years of production at 2022 volumes.

The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas as of December 31, 2022, including joint operations and associates.

	Reserves as of December 31, 2022
Reserves Category	Crude oil, condensate and natural gas liquids (millions of barrels)	Natural Gas (billions cubic feet)	Oil Equivalent (million boe)
Proved Developed	7.7	613.5	110.0
Proved Undeveloped	3.2	397.0	69.4
Total proved reserves	10.9	1,010.5	179.4

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.”

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, 2022, 2021 and 2020:

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	2022		2021		2020
	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	110.0	61.3%	95.9	61.1%	69.8	49.2%
Proved undeveloped reserves	69.4	38.7%	61.1	38.9%	72.0	50.8%
Total Proved Reserves	179.4	100.0%	157.0	100.0%	141.8	100.0%

Note: All figures have been subject to rounding, so figures shown as totals may not add up.

During 2022, fifty-five wells were drilled and one drilled uncompleted well was completed in El Mangrullo, Río Neuquén, El Tordillo, Gobernador Ayala and Sierra Chata areas, of which thirty-eight and one wells, respectively, were changed from proved undeveloped reserves to proved developed reserves from the first four areas just mentioned.

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, 2020	13,527	769,519		141.8
Proved developed reserves as of December 31, 2020	7,761	371,99		69.8
Increase (decrease) originated in:
Revisions of previous estimates	205	44,993		7.7
Improved recovery	2	7,696		1.3
Extensions and discoveries	607	145,564		24.9
Year’s production	-1,716	-101,231		-18.6
Total proved developed and undeveloped reserves as of December 31, 2021	12,625	866,541		157.0
Proved developed reserves as of December 31, 2021	7,970	527,870		95.9
Increase (decrease) originated in:
Revisions of previous estimates	-466	-72,518		-12.6
Improved recovery	272	84		0.3
Extensions and discoveries	454	339,021		57.0
Year’s production	-1,948	-122,636		-22.4
Total proved developed and undeveloped reserves as of December 31, 2022	10,937	1,010,492		179.4
Proved developed reserves as of December 31, 2022	7,722	613,505		110.0

⁽¹⁾ Gas converted to oil equivalent using a factor of 6,000 cubic feet of gas per barrel of oil equivalent.

As of December 31, 2022, our liquid hydrocarbon and natural gas proved developed and undeveloped reserves totaled 179.4 million boe (10.9 million boe of liquid hydrocarbons and 1,010.5 billion cubic feet, or 168.4 million boe, of natural gas), representing a 14% increase compared to proved reserves as of December 31, 2021 (a decrease of 13% and an increase of 17% for liquid hydrocarbons and natural gas, respectively).

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During 2022, previous estimates of our fields located in Argentina were subject to revisions representing a decrease of 12.6 million boe, mainly attributable to rescheduling 11 and 8 proved undeveloped wells in the El Mangrullo and Rincón del Mangrullo areas respectively, following the next 5 years reserves development. Extension and discoveries increased by 57.0 million boe through drilling activities, mostly in the El Mangrullo, Sierra Chata and Río Neuquén areas. In addition, an increase of 0.3 million boe was attributable to improved recovery in the Gobernador Ayala area.

As of December 31, 2022, 61% of our proved reserves were developed, while 39% were undeveloped. Proved developed reserves were 110.0 million boe. During 2022, we invested US$ 154.8 million in drilling, completion and facilities, to convert approximately 16.5 million boe of proved undeveloped reserves to proved developed reserves. Our proved undeveloped reserves were 69.4 million boe, all of which corresponded to wells located within one offset of proved developed reserves and gas fields where the activity has been scheduled to maintain production levels in accordance with contracts and installed facilities. We plan to put approximately 92.3% of these proved undeveloped reserves into production through activities to be implemented over the next five years. The balance of 7.7% (5.3 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 14% increase (8.3 million boe) in our proved undeveloped reserves in 2022 compared to 2021 was mainly attributable to:

(1) a decrease of 16.5 million boe by the conversion of proved undeveloped reserves to proved developed reserves, mainly through drilling, completion and workovers activities performed in our production areas in the Neuquén basin, mainly in the El Mangrullo and Río Neuquén areas;

(2) an increase of 35.0 million boe of proved undeveloped reserves by extensions and discoveries, through additional drilling activities, mainly in the El Mangrullo, Sierra Chata and Río Neuquén areas in the Neuquén basin; and

(3) a decrease of 10.2 million boe of proved undeveloped reserves, came from revisions of previous estimates mainly attributable to rescheduling 11 and 8 proved undeveloped wells in the El Mangrullo and Rincón del Mangrullo areas respectively, following the next 5 years reserves development.

The activities described in items (1), (2) and (3) above resulted in a net increase of 8.3 million boe in our proved undeveloped reserves in 2022 compared to 2021.

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, 2022. 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.

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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.

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 (17 CFR Part 210 Rule 4-10 (a)). 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 97% 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.

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Technology used in reserves estimation

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project 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 proved 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.

There are various generally accepted methodologies for estimating reserves including volumetric, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using either 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, 2022 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.

Others

Ecuador

On October 31, 2008, Pampa Bloque18, a wholly-owned subsidiary of the Company established in the Republic of Ecuador, Teikoku Oil Ecuador and Petroecuador, among others, executed a series of amendatory agreements regulating the operation of Block 18 and Palo Azul Unified Field (the Amendatory Agreements), while the parties negotiated the migration to a new contract modality.

The consortium decided not to accept the final proposal received from the Ecuadorian government to migrate from the original arrangements to service agreements in Block 18 and the Palo Azul Unified Field. Consequently, through a Resolution dated November 25, 2010, the Hydrocarbon Secretary notified Pampa Bloque18 of the termination of the participation agreements and instructed Petroamazonas EP to undertake the operational transition process.

Section 9 of the Amendatory Agreements provides that the Ecuadorian government must compensate the terminated parties in an amount equivalent to unamortized investments adjusted by reference to a variable rate, and provides for a period of time for the Ecuadorian government and the terminated parties to work out the details of the termination payment.

After taking the required administrative and judicial steps and being unable to reach an agreement with the Ecuadorian Government, on June 21, 2013, Pampa Bloque18, Cayman International Exploration Company and Teikoku Oil Ecuador, members of the consortium, (the “Plaintiff Parties”) submitted a letter of notification of a dispute under the terms of the Amendatory Agreements to the Ecuadorian State, stating their decision to submit the dispute to international arbitration under the arbitration Rules of the UNCITRAL, which arbitration began on February 26, 2014.

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Pampa Bloque18’s participation in the Bloque 18 Consortium is 30% and the final award by the arbitration tribunal corresponding to Pampa Bloque18 stake, amounted to US$176 million (the “Final Award”).

On March 19, 2018, the Republic of Ecuador and the Plaintiff Parties executed an agreement (the “Arbitration Settlement”) pursuant to which the Plaintiff Parties agreed not pursue the collection of the Final Award, in exchange for a compensation for general damages, which for Pampa Bloque18 comprises (i) a release from fiscal and labor claims currently in the trial stage, amounting to more than US$132 million, and (ii) an additional compensation of US$54 million, which was paid by the end of first half of 2018 (including the recovery of granted guarantees).

Moreover, the Republic of Ecuador has declared and acknowledged within the Arbitration Settlement that (i) such agreement is completely valid and binding for the Republic of Ecuador, (ii) any payment default by the Republic of Ecuador under the Arbitration Settlement will allow the Plaintiff Parties to fully enforce the final award, and (iii) there is no pending obligation remaining by the Plaintiff Parties in relation to the Bloque 18 Consortium’s operation’s and exploitation.

As a result of the Arbitration Settlement, we have disclosed net profits for US$40 million (Ps. 1,116 million) as of December 31, 2018, consisting of: (i) a profit of US$133 million in consequential damages after writing off of the receivable of US$53 million to be recovered from the Ecuadorian Government pursuant to the Amending Agreements, and (ii) a US$93 million loss associated with the agreement to the terms of the tax claims assigned to Pampa Bloque18 in accordance with the Arbitration Settlement.

In 2018, Pampa Bloque18 collected the agreed amount and waived (without this implying an admission of facts or rights) the proceedings brought in the Ecuadorian Internal Revenue System Claims, and the Ecuadorian Government has made the withholding to cancel all tax debts. On September 20, 2019, through an official letter issued by the Ministry of Labor, Pampa Bloque18 was notified of the payment on employee participation profits from 2002 to 2010, to the former consortium workers.

Crude Oil Transportation OCP Agreement

On November 10, 2003, Pampa Bloque18, entered into a “ship or pay” agreement with OCP, whereby it secured an oil transportation capacity of 80,000 barrels per day for a 15-year term (the “OCP Agreement”).

Under the OCP Agreement, Pampa Bloque18 must comply with its contractual obligations for the aggregate committed capacity, regardless of the amount of crude oil actually transported, and pay a rate that covers OCPs operating costs and financial services, among other items.

Pampa Bloque18 is entitled to sell transportation capacity through OCP’s pipeline to mitigate the negative effect of excess contracted capacity. In this respect, Pampa Bloque18 periodically negotiates the sale of committed transportation capacity. On December 31, 2008, Pampa Bloque18 and Petroecuador entered into an agreement under which, beginning on January 1, 2009, transportation of crude oil through OCP’s pipeline is charged by Petroecuador to the transportation capacity committed to under the agreement entered into between Pampa Bloque18 and OCP, up to a maximum of 70,000 barrels per day. In addition, Pampa Bloque18 sold transportation capacity for approximately 8,000 oil barrels per day to third parties for the July 2004-January 2012 period.

In January 2018, Pampa Bloque18 assigned to ENOPSA a transportation capacity of 10,000 barrels per day. As a result, Pampa Bloque18 will pay to PEO US$2.9 million.

In January 2018, PEO declared the Equity Expropriation Event, whereby, under certain circumstances stipulated in the agreement, we, in our capacity as guarantor, will bear the payments for the capital charges associated with the assigned transportation capacity.

In April 2018, Pampa Bloque18 assigned to Trenerec S.A. (a subsidiary company in Ecuador) the remaining transportation capacity of 70,000 barrels per day held with OCP. Additionally, Pampa Bloque18 assigned to Trenerec S.A. the rights and obligations held under the agreement entered into with Petroecuador by which Trenerec will be able to sell to Petroecuador transportation capacity for 70,000 barrels per day.

The OCP Agreement expired on November 10, 2018, and, therefore collaterals held to ensure compliance with related financial commitments were gradually released as those commitments became extinguished. As of December 31, 2019, we do not hold any collateral in this respect.

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During 2019, Pampa Bloque18 initiated a mediation process together with Petroecuador due to certain breaches of contract related to a transportation agreement signed in December 2008 between Petroecuador and Pampa Bloque18. This process ended with no settlement being agreed between the parties.

On February 17, 2021 Pampa Bloque18 initiated an arbitration process against Petroecuador due to breach of contract by Petroecuador. For more information, please see: “Item 8 - Financial Information. Consolidated Financial Statements. Legal Proceedings”.

OCP

In 2001, the Ecuadorian government awarded to OCP the rights to construct and operate for a 20-year term the 503 km-long pipeline that runs from the northeastern region of Ecuador to the Balao distribution terminal on the Pacific Ocean coast. The oil pipeline has a transportation capacity of approximately 450,000 barrels per day, of which at least 350,000 barrels per day are committed under transportation agreements that include a Ship or Pay clause. Because the oil pipeline runs across ecologically sensitive areas, the pipeline was constructed following stringent environmental and technical standards. The construction of the oil pipeline was completed in 2003, when it began operations. As of the date of this Annual Report, we have a 30.06% equity interest in OCP.  

Our subsidiary, Pampa Bloque18, entered into a transportation agreement with OCP that includes a Ship or Pay clause whereby OCP has committed to transport 80,000 barrels per day of our oil for a 15-year term, beginning in November 2003. For more information, see “—Others—Ecuador”.

As of December 31, 2017, OCP had negative shareholders’ equity as a result of certain tax assessments in favor of the Government of Ecuador in issues where OCP and the Ecuadorian Treasury have differences in interpretation. We have not committed to make capital contributions or provide financial assistance to OCP; therefore, our equity interest in OCP was valued at Ps. 0 in our financial statements as of and for the year ended December 31, 2017.

However, on December 6, 2018, OCP and the Republic of Ecuador executed an agreement to settle all claims and legal actions between them in relation to certain tax assessments in favor of the Government of Ecuador in issues where OCP and the Ecuadorian Treasury had differences in interpretation. As a result, a total amount of US$182 million was established for all concepts, of which: (i) US$64 million corresponded to credits for income tax withholdings made by OCP in the following periods: 2004-2005 and 2007-2014; (i) US$7 million was offset by a payment previously made by OCP related to a tax determination for the fiscal period 2003; and (iii) US$111 million was paid in cash in two payments. Following the satisfaction of all obligations in accordance with the agreement, on December 21, 2018, the closing of the agreement between OCP and the Republic of Ecuador took place. As a result of this agreement, OCP recorded a gain of US$387 million. We have resumed the recognition of our equity interest in OCP, through our subsidiary PEB, after recognizing previously unrecognized losses and, therefore, we recognized a gain for our equity interest in OCP of US$35 million as of December 31, 2018.

Furthermore, on December 5, 2018, through our subsidiary PEB, we executed an agreement with Agip Oleoducto de Crudos Pesados BV to purchase shares representing 4.49% of OCP’s capital stock and subordinated debt issued by us. The closing of this transaction is subject to the approval of the Government of Ecuador, among other conditions precedents. On June 20, 2019, upon satisfaction all conditions precedent, the transaction was closed and registered with the Shareholders’ Registry Book.

Subsequently, on August 12, 2021, the Company, through its subsidiary PEB, executed an agreement with Occidental International Exploration and Production Company for the acquisition of all the shares of Occidental del Ecuador Inc. (currently Pampa Ecuador Inc.) for US$5 million. Pampa Ecuador Inc. holds a 14.15 % equity interest in OCP Ltd. The closing of the transaction on the mentioned date involved the recognition of profits for US$25 million and US$17 million, respectively, under IAS 28.

The termination of the pipeline concession contract is scheduled for January 12, 2024, considering the extension of the term due to the suspension of contractual obligations originated in events of force majeure. On such date, OCP Ltd will transfer and deliver to the Ecuadorian State or whoever it designates, all of the shares of OCP SA at no cost and the titles and rights over the assets of the pipeline.

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Recoverable value of the investment

On April 8, 2020, a force majeure event occurred, consisting of the sinking and landslide in the San Rafael sector, on the border of the provinces of Sucumbíos and Napo, Ecuador, which caused the rupture of the “Oleoducto de Crudos Pesados” pipeline. This event also affected the “SOTE” Trans-Ecuadorian Pipeline System and the Shushufindi-Quito Pipeline. On May 7, 2020, OCP S.A. restarted operations and resumed the provision of the crude oil transportation service after completing the construction of a variant that allowed the restoration of the crude oil pipeline system.

Additionally, on June 4, 2020, a contract for the implementation of the specific mutual support agreement was entered into between Petroecuador and OCP, which stipulated that the costs incurred in mitigating and remediating the social and environmental effects resulting from the force majeure event would be reimbursed by the other party proportionately to the spilled hydrocarbon volumes. To such effect, the Agency for the Regulation and Control of Energy and Non-Renewable Natural Resources established a 43% percentage for OCP.

On December 3, 2021, OCP declared the “Operational Urgency” due to an accelerated side erosion in the Rio Quijos, Piedra Fina sector, the boundary between the Napo and Sucumbíos provinces, Ecuador, which caused cracks in the Quito - Lago Agrio road and the subsequent destruction of a section of the road. The applicable competent authorities were immediately notified that a temporary bypass would be constructed to ensure the pipeline’s operational continuity and avoid an environmental incident. On December 8, 2021, OCP suspended crude oil pumping and ordered the complete draining of the pipeline at KP95+736. On December 11, 2021, OCP notified the Ministry of Energy and Non-Renewable Natural Resources of the occurrence of the force majeure event, and operations were restarted on December 31, 2021.

On January 28, 2022, a new force majeure event occurred due to a landslide causing the rupture of the “Oleoducto de Crudos Pesados” pipeline at KP96+526. OCP started the repairs and the cleanup and remediation work on the affected pipeline. The crude oil transportation service was restarted on February 7, 2022.

PEB has performed recoverable amount tests for its investment in OCP as of December 31, 2020 and 2021, considering the present value of the future cash flows it expects to obtain through the collection of dividends during the concession term, the term extension due to the suspension of contractual obligations resulting from the detailed force majeure events and a discount rate of 15.01% and 17.12% for 2020 and 2021, respectively.

As of December 31, 2020, PEB recognized an impairment reversal of US$0.1 million, while no impairment loss was recorded as a result of the recoverability assessment performed as of December 31, 2021 and December 31, 2022.

It should be noted that on February 22, 2023, after the end of the fiscal year, an event of force majeure occurred due to the collapse of the bridge over the Marker River, located in the El Chaco canton, Napo Province. In order to guarantee the continuity of operations and avoid an environmental incident, OCP SA stopped pumping crude oil and ordered the complete drainage of the pipeline in KP96+075. Additionally, OCP SA notified the occurrence of said event to the Ministry of Energy and Non-Renewable Natural Resources. On March 2, 2023, OCP SA resumed the crude oil transportation service.

Contingent liabilities in OCP

Due to the force majeure event resulting from the described rupture at the KP93 pipeline in 2020, several organizations and natural persons filed a constitutional protection complaint against OCP, as well as the Ministry of Energy, the Ministry of the Environment and Water, Petroecuador and the Ministry of Health, alleging the infringement of several constitutional rights. The safeguard action has been disallowed in the first and second instance by Orellana’s Provincial Court of Justice. As of the date of this annual report, the plaintiffs have filed a constitutional protection proceeding, which has been admitted to be heard by the Constitutional Court.

The Company's Management together with its legal advisors have classified an unfavorable ruling as remote, therefore, no provision has been recognized on this matter.

Oldelval

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In line with our strategy to focus resources on our core businesses, on November 2, 2018 we executed an agreement with ExxonMobil Exploration Argentina S.R.L. (“ExxonMobil”) for the sale of 21% of the capital stock of Oldelval, which closed on November 27, 2018. As a result, we hold a 2.1% interest in Oldelval.

Oldelval operates main oil pipelines providing access to Allen, in the Comahue area, and the Allen - Puerto Rosales oil pipeline, which allow for the transportation of the oil produced in the Neuquina Basin to Puerto Rosales (a port in the City of Bahía Blanca) and the supply of the Plaza Huincul and Luján de Cuyo distilleries, all located in the pipeline’s area of influence.

In 2021, Allen’s oil transportation from Allen to Puerto Rosales reached 32,047 m³/day on average, and transportation to the refineries located in the provinces of Neuquén and Mendoza totaled an average of 1,865 m³/day and 619 m³/day, respectively. The total transported volume was 34,532 m³/day, equivalent to 79.3 million bbl in 2021, representing a 19.5% increase compared to 2020.

It is worth highlighting that the Allen – Puerto Rosales main pipeline’s transportation capacity as of the closing of 2021 was 28,800 m3 per day without polymer and 36,000 m³ per day with polymer.

On December 10, 2021, a hydrocarbon spill occurred in the Medanito area, Province of Río Negro and was contained on the same day. There were no injuries, and no nearby watercourses were affected. Moreover, all work necessary for oil recovery have been performed, and soil and vegetation cleanup is expected to soon be completed. The total amount of the incident is estimated at US$6 million, and Oldelval is making the necessary filings before the insurance companies.

During 2022, Oldelval called for bids to award a contract of firm transportation of up to 36,000 m³/day for Allen- Puerto Rosales oil pipeline section in its capacity as holder of the national concession of liquid hydrocarbon transportation.

However, it received bids for a volume much higher than the one originally tendered, equal to a total volume of 130,752 m³/day, and as a result it decided to expand the original tendered volume and extend it to a total of 50,000 m3/day.

This whole volume was awarded, and contracts have already been executed to transport it, effective up to the end of the transportation concession (2037).

It is worth highlighting that during 2022, Oldelval managed to maintain its transportation service, ensuring operational continuity and a reliable pumping system.

Our Petrochemicals Business

Our petrochemical operations are entirely based in Argentina where we own three high-complexity plants producing styrene, SBR and polystyrene, with a domestic market share ranging between 91% and 99% (per Company estimates). 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 the domestic and foreign markets from natural gas, virgin naphtha, propane and other supplies.

In Argentina, we are the only producer of styrene, polystyrene and elastomers, and the only integrated producer of plastics derived from oil production. As part of our efforts to integrate our operations, we use a substantial amount of styrene for the production of polystyrene and SBR.

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, 155,000 tons of aromatics, 290,000 tons of gasoline and refines, 160,000 tons of styrene, 55,000 tons of SBR, 180,000 tons of ethyl benzene and 31,000 tons of ethylene; and

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· 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, 2022 and 2021:

	2022	2021	2020
Technical Information
Sales (in thousand ton):
Styrene (incl. propylene y ethylene)	55	57	47
SBR	46	49	37
Polystyrene	59	58	47
Others	262	254	205
Sales destination
Argentina	69%	63%	66%
Outside	31%	37%	34%

Styrene Division

In 2022, the monomer styrene sales volume totaled 47 thousand tons, 4% lower than in 2021, with a similar domestic sales and a 33% decrease in exports. Polystyrene sales volumes reached 58 thousand tons, 1% higher than in 2021, with a 13% increase in domestic sales, and a 33% decrease in exports, mainly to Chile. Moreover, in 2022 the Company sold 46 thousand tons of rubber, a figure 7% lower than in 2021, with a 6% decrease in domestic sales and a 8% decrease in exports, mainly to Brazil.

Reforming Gasoline Division

Sales of the Reforming division increased by 3% compared to 2021. In 2022, octane bases and gasoline sales totaled 216 thousand tons, a volume 9% higher than in 2021, due to an increase in domestic sales, associated with the fuel consumption recovery. In 2022, 16,000 tons of bases and naphtha were dispatched as toll processing, which were not registered as volume sold. Hexane, paraffin solvents, and aromatics sales volumes totaled 35 thousand tons in 2022, representing a 22% decrease compared to 2021. The excess was used for a greater formulation of octanic bases. In 2022, propellant sales totaled 11 thousand tons, a 7% increase compared to 2021, associated with the higher processing of raw gasoline.

Our Holding and Other Business

Our holding and other business segment is comprised, among other holdings, of our direct and indirect interest in TGS, Argentina’s major gas transportation company, which owns a 9,233 km-long gas pipeline network and a gas fuel processing plant, General Cerri, with an output capacity of one million tons a year. Furthermore, we jointly control Transener with IEASA. Transener is a company that operates and maintains the Argentine high voltage transmission grid covering 14,648 km of proprietary lines, as well as 6,771 km of Transba-owned high voltage lines. Transener transports 86% of the electricity in Argentina.

Our Interest in TGS

TGS is the most important gas transportation company in Argentina, and it operates the biggest pipeline system in Latin America. It is also a leading company in the production and sale of natural gas liquids for both domestic and export markets, conducting its business from the General Cerri Complex located in Bahía Blanca, in the Province of Buenos Aires. TGS also provides comprehensive solutions in the natural gas area and, since 1998, it has also acted in the telecommunications area through its controlled company Telcosur. As of December 31, 2021, Pampa holds a 29.3% interest in TGS.

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Description of TGS’ Business Segments

Regulated Segment: Gas Transportation

Revenues from this segment result mainly from firm natural gas transportation agreements, whereby the gas pipeline capacity is reserved and paid for regardless of its actual use. TGS provides an interruptible service, where natural gas transportation is subject to the gas pipeline’s available capacity. Moreover, TGS provides operation and maintenance services for assets allocated to the natural gas transportation service for the expansions fostered by the Federal Government and held under trusts created for such effects. For this service, TGS receives from customers with incremental natural gas transportation capacities the charge of access and use established by ENARGAS, which remained unchanged from its creation in 2005 until its first update in May 2015.

In constant terms, as of December 31, 2022, annual revenues from this business segment amounted to Ps.40,643 million, representing 25% of TGS’ total revenues and evidencing a 15% decrease compared to 2021.

It is worth recalling that in 2022 transportation contracts on a firm basis represented 84% of revenues from sales in this segment, compared to 81% in 2021. As of December 31, 2022, the total capacity hired on a firm basis amounted to 83.1 million m³/day with a weighted average life of 11 years. During 2022, natural gas daily average injection into the system operated by TGS amounted to 68.6 million m³/day, a volume slightly lower than in 2021. The injection from the Neuquina Basin was higher (+13% vs. 2020), offset by the decrease from the Austral Basin (-11% vs. 2020). In this scenario, TGS’ gas pipeline system was reasonably responsive to the demand needs.

During 2022, TGS executed 148 new contracts, 57 of interruptible transport services and 91 of exchange and displacement services.

Non-Regulated Segment: Production and Marketing of Gas Liquids

Unlike the gas transportation business, the production and commercialization of liquids are not regulated by ENARGAS. In 2022, this segment’s revenues accounted for 63% of TGS’ total revenues, amounting to Ps. 104,215 million, 4% lower in real terms than in 2021. The main cause of the decrease was the impact of the revenue restatement (inflation-adjusted as of the closing of 2022, higher than the Ps. devaluation) on US$-denominated sales, and, the lower demand for buthane and ethane. These effects were partially offset by higher reference international prices and higher dispatch of natural gas and propane.

Liquids production and commercialization activities are conducted at the Cerri Complex, located close to the city of Bahía Blanca, supplied by all of TGS’ main gas pipelines. Ethane, propane, butane, and natural gasoline are recovered at this complex. TGS sells liquids to both domestic and foreign markets. In the domestic market, propane and butane are sold to reseller companies. In the foreign market, these products and natural gasoline are sold at international reference prices. Moreover, ethane is sold to Polisur at a price agreed between the parties.

In 2022, total sales volumes reached 1,124,004 tons, 35% of which were destined for exports. Out of the total sales destined for the domestic market, 80% were made at US$-denominated prices or with a US$-based adjustment clause.

Regarding the foreign market, average sales prices for natural gasoline, butane, and propane during 2022 were similar to 2021.

It is worth highlighting that Decree No. 488/20 established an export duty on liquids, among other products, of 8% in 2022. Moreover, in addition to seaborne exports, TGS makes inland exports to neighboring countries. Although their volumes are substantially lower than those conducted by sea, they allow TGS to capitalize on a higher operating margin. In 2022 and 2021, propane and butane deliveries overseas were made in the spot market, seizing opportunities related to different market niches, enabling a considerable increase in fixed premiums. Natural gasoline was sold both through term contracts and spot transactions.

Regarding the domestic market, during 2022 TGS continued participating in the Household Gas Bottles’ Program and the Propane for Grids Agreement. Prices are regulated by a set of resolutions, provisions, and agreements. The participation in these programs forces TGS to sell at prices ostensibly lower than market prices. Moreover, participation in this program requires the Federal Government to reimburse TGS an economic compensation denominated in Ps., which is currently being collected with delays. Outside these programs, TGS sold 163,625 tons of propane and 13,338 tons of butane, mainly to the reseller market and, to a lower extent, to the industrial, propellant, and automotive market.

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In 2022, TGS continued selling ethane under the long-term agreement executed with Polisur in September 2018. This agreement has commercial guidelines stipulated in 2020, with improvements in the ToP clause (to be met annually), which guarantees TGS a gradual increase in sales volumes over the first five years of the contract. In fiscal year 2021, there was a mild decrease in the volume of ethane sold to Polisur, reaching 329,232 tons, slightly lower than the 353,078 tons sold in 2021, due to the customer’s inability to take a higher volume.

Furthermore, in 2022 TGS continued effectively rendering logistic services at the Puerto Galván facilities, selling LPG by inland transport, dispatching approximately 16,156 trucks (372,813 tons) of its products, compared to 17,348 trucks (410,029 tons) recorded in fiscal year 2021.

Additionally, in May 2021, an LPG dispatch contract was executed with Compañía Mega S.A. for loading tankers in case they cannot use their own quay, effective until December 2023.

Regarding US$-denominated prices for natural gas acquired as PTR (plant thermal reduction) for processing at the Cerri Complex, a 29% increase was recorded compared to 2021 due to Plan Gas.Ar’s impact. However, Plan Gas.Ar reversed the decrease in natural gas production over the last few years, and supports the LNG business.

Non-Regulated TGS’ Segment: Other Services

The other services segment is not regulated by ENARGAS. TGS provides midstream services, which mainly consist of treatment, impurity separation and gas compression. It may also include gas extraction and transportation in gas fields, construction services, inspection and maintenance of compression plants and gas pipelines, as well as steam generation services for the production of electricity. This business segment also includes revenues from telecommunication services provided through its subsidiary Telcosur.

During 2022, this segment represented 12% of TGS’ total revenues, experiencing a 15% increase in real terms compared to 2021. This increase was mainly due to higher natural gas transportation and conditioning services at Vaca Muerta and the impact of revenue restatement (adjusted by inflation as of the closing of 2022, higher than AR$ devaluation) over US$-denominated sales.

The gathering gas pipeline in the Vaca Muerta formation has a 150-km length, with a 60 million m³ per day transportation capacity and a plant in Tratayén with an initial conditioning capacity of 14,8 million m³ per day. Moreover, to face the increase in flows, there are three projects comprised of the installation of: (i) two gas conditioning modular plants with a capacity of 3.5 million m³/day each, and a gasoline stabilizer tower, that started their operations during February 2023; (ii) a conditioning plant with a capacity of 6.6 million m³/day, with an estimated start of operations from December 2023 to the first half of 2024 (the estimated investment will amount to US$270 million); and (iii) a 32 km extension of the northern section of the collector gas pipeline (Los Toldos I Sur – El Tapial), with a transport capacity of 17 million m³ per day, with an estimate investment of US$ 60 million, and start of operations on June 2023.

Finally, regarding the telecommunications service, during 2022 Telcosur, a company controlled by TGS, has entered into new agreements that allowed it to increase its sale capacity and secure its operations.

Midstream service expansion in Vaca Muerta

Currently, the TGS collector pipeline in the Vaca Muerta formation is 150 km long, with a transport capacity of 60 million m³/day, and a plant in Tratayén with a conditioning capacity of 14.8 million m³/day.

To cope with the growing flow and to continue to consolidate its commitment to the country's energy supply, TGS provides efficient solutions to natural gas producers by carrying out large-scale infrastructure projects:

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- Two modular gas conditioning plants, each with a capacity of 3.5 million m³ per day and a gasoline stabilizer tower, operational since February 2023;

- Two conditioning plants, each with a capacity of 6.6 million m³ per day, estimated to start operations in December 2023 and mid-2024, with an investment of US$132 million and US$138 million, respectively; and

- The extension of the northern section of the collector gas pipeline for 32 km (Los Toldos I Sur – El Trapial), with a transport capacity of 17 million m³ per day, with an estimated investment of US$60 million and authorization for June 2023.

 Our Interest in Transener

Pampa holds 50% of CITELEC’s capital stock, which in turn owns 52.65% of the capital stock of Transener, the largest high voltage electricity transmission company in Argentina. Transener’s Class B common shares are listed on the BASE, and the remaining 47.3% of Transener is held by minority public shareholders and the ANSES. The remaining 50% of CITELEC’s capital stock is held by ENARSA.

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 on August 5, 1997.

Transener’s operations

Transener is the leading company in the utility service of high voltage electricity transmission in Argentina at the 500 kV level under an exclusive 95-year concession agreement. It directly operates and maintains 14,926 km high voltage electricity transmission lines and 60 transforming stations, that represent 86% of the high voltage lines of the country.

Transener also indirectly owns one of the seven regional transmission networks in Argentina, the Transba network. The Transba concession grants Transba an exclusive 95-year concession to provide electricity transmission services (from the 66 kV to the 220 kV levels) in the Province of Buenos Aires via trunk lines, which are the main transmission lines that connect to all other lower voltage transmission systems owned and maintained by distribution companies in a certain region, throughout the Transba network spanning approximately 6,771 km and 110 transforming substations.

Transener also generates additional revenues from, among others, the operation and maintenance of the fourth line, and services provided to third parties.

Operation and Maintenance

The extra high voltage power transmission grid operated and maintained by Transener is subject to significant load conditions year after year. On December 6, 2022, a new record-breaking demand for power capacity of 28,283 MW was registered, 4% higher than the maximum peak recorded in 2021.

Despite the great number of power grid requests in 2022, service quality has been wholly acceptable for the values required from a company like Transener, ending the year with a rate of 0.19 failures per each 100 km-line, consistent with international parameters accepted for companies that operate and maintain extra high voltage transmission systems.

Business Development

Engineering Services

Regarding the works to expand the electrical system, Transener has concentrated its activity on those projects for which it has competitive advantages, giving priority to the works to be carried out on the 500 kV and 132 kV system. During 2022, works to support renewable energy generation continued, such as to complementary communications services for the implementation of generation and demand control systems (Automatic Disconnection Systems for Export and Generation Demand and SOTR – Real Time Operation System), and station engineering for a new wind farm. Transener's experience has been a decisive factor for clients to delegate to it the performance of critical tasks. Among the most important works are the ADSS cable laying works between the González Chávez – Chillar – Olavarría transformer station, provision of engineering service of the transformer station and connection of the Vientos Olavarría Wind Farm.

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Simultaneously with this work, Transener continued supplying power equipment to remote sites from the collector wire system for communication systems related to third-party fiber optic leases.

Services related to the Transmission of Electric Energy

Activities relating to the operation, maintenance and other services such as specific tests hired by private clients who own transmission facilities, used for private and/or utility services (independent and international transporters) have been conducted by Transener since the beginning of its activity.

Furthermore, Transener also performs tasks such as bushing replacements, oil analysis, diagnosis tests, optical fiber repairs, electric and magnetic field measurement, implementation of automatisms, line and equipment maintenance of transformer stations, among others.

All necessary proceedings to maintain the actual value of Transener’s remuneration have been fulfilled in every Service Agreement and most of them have been renewed without interruption from the beginning, confirming the quality of the service provided by Transener and customer’s satisfaction.

Communications

In 2022, Transener has continued to provide infrastructure services to different communication companies, including the assignment of dark fiber optics over the system property (line IV), and the lease of space in microwave station and in antenna support structure. The increasing demand from cell phone companies has increased the income through additional volume and higher prices. In addition, Transener continued support services in operative communication and data transmission to the WEM agents.

Others

Service outage in the Argentine Electricity Grid

On June 16, 2019 at 7:07 a.m., the SADI experienced a total outage. The outage was a result of the concurrence of multiple shortcomings within the SADI, some of them unrelated to the transmission system operated and maintained by Transener.

The occurrence of this event had an impact in 2020 on the amount of both penalties, which were increased, and awards, which were reduced, on account of the Additional Service Quality and Penalties Regime established by Resolutions No. 552/16 and No. 580/16.

As a result of this event, on May 14, 2021, the ENRE, pursuant to Resolution No. 121/21, imposed a penalty on Transener for the previously described event, which does not significantly differ from the provision held by Transener under liabilities.

Moreover, the ENRE filed new charges against Transener on account of its liability for alleged breaches in this event. Transener rejected the charges alleging the illegality and irrationality of the filing of a new summary proceeding after the termination of the proceeding that imposed the applicable penalties. If this proceeding is resolved unfavorably for Transener, any penalty or other monetary fine may have an adverse impact on its results. As of the date of this annual report, there is uncertainty on the possible imposition of a penalty and its amount.

Transener and TGS’ Tariff Situation

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The Social Solidarity and Productive Reactivation Law delegates the PEN with the power to administratively intervene the ENRE and ENARGAS (implemented through the Decrees No. 277/20, 278/20, and 963/20, as amended) until December 31, 2022.

On December 17, 2020, DNU No. 1020/20 was issued, launching the RTI renegotiation for a term not to exceed two years from its publication. Until then, all agreements under the respective RTI in force would be suspended, with the scopes to be determined in each case by the ENRE and ENARGAS. The renegotiation process would be completed with the execution of the RTI Final Memorandum of Understanding.

The public hearings to consider TGS, and Transener and Transba’s transitional tariff regime took place on March 16 and 29, 2021, respectively. Despite presenting all documentation required by the ENRE timely and in due form, Transener and Transba have received no instructions from the ENRE. In the case of TGS, as no agreement was reached, on June 2, 2021, it was established that tariff schemes effective in April 2019 would remain unchanged (Decree No. 353/21, ME & ENARGAS Joint Res. No. 1/21, and ENRE Res. No. 149/21). TGS filed a motion for reconsideration and requested the nullity of these provisions.

Moreover, on February 25, 2022, ENRE Res. No. 68/22 and 69/22 were issued, granting the 25% and 23% transitory tariff update to Transener and Transba, respectively, retroactively as of February 1, 2022. Given the differences between these companies’ tariff proposals and the final tariff schemes, Transener and Transba submitted a motion to review the file and a preliminary challenge and will appeal both resolutions.

Furthermore, the Decree No. 91/22 and ENARGAS Res. No. 60/22, issued in February 2022, granted the 60% transitory tariff update to TGS, effective from March 1, 2022. Among other conditions, this grant did not establish a mandatory investments plan and set a prohibition on: (i) distributing dividends; and (ii) early canceling financial and commercial debts taken on with shareholders, acquiring other companies, or granting loans.

Under the 2022 Transitional Agreement, TGS committed not to file new claims, remedies, actions, complaints, or motions of any kind; and/or to suspend or maintain or postpone the suspension of any claims and remedies filed in any way associated with the current Integral Tariff Structure Review, Social Solidarity and Productive Reactivation Law, Decree No. 278/20 and DNU No. 1020/20.

It is worth highlighting that Transener, Transba, and TGS’ tariff schemes had not been modified since August and April 2019, respectively. Moreover, in their respective 2022 public hearings, they had informed the relevant authorities that their transmission costs represented about 2% and 13% of a residential consumer’s final bill (consisting of raw materials, transmission, distribution, and tax).

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.

IT and Cybersecurity

With a focus on the hybrid work modality implemented since the lockdown and searching for more agility and flexibility to enhance our teammates’ experience, and continuing with our head offices’ refurbishment that started in 2021 where most floors were refurbished, the Pampa Building’s servers and communications infrastructure were enhanced for improved agility, security and flexibility. This model began to be replicated in the Company’s main assets, which is expected to be covered by mid-2023.

In the E&P business, we have moved forward with the digital transformation, incorporating geolocation systems for real-time monitoring of all the fields’ vehicles. Moreover, the information from all fields was consolidated in a single application to have indicators supporting decision-making. To this end, the Openwells management software was updated, substantially improving the quality of information from the wells’ operations portal. Furthermore, regarding maintenance engineering, new plants were incorporated into the IRISK solution for the components monitoring and assessment, aiming to minimize risks and operating losses and optimize assigned resources. Additionally, we continued to improve processes for sending information to the SE.

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In the Power Generation business, new machine learning-based tools were incorporated into the main assets’operation and maintenance to maximize their availability. Additionally, information was centralized in a single repository, digitalizing critical systems’ change management process and facilitating data integration with different external entities and sources. Moreover, we have moved forward with the first virtual representation project, a pilot digital twin of the new CTGEBA’s combined cycle, enabling 3D interaction with real-time information. Moreover, the Digital Development Center came into operation, driving initiatives associated with data analytics, artificial intelligence and machine learning.

In connection with corporate areas, we implemented the Contracts Management solution in the procurement area to smooth operations with contractors, minimize paper use and enhance information exchange traceability. Regarding the Administration area, we automated approval strategies in the procurement management system and we also implemented a journal entry approval solution in the Accounting area. Moreover, we updated the policy application in the Insurance area, and implemented the first phase of a tax automation process in the Taxes area. Additionally, we supported the Human Resources area in digitalizing the teammates’ recruiting process, and developed the digital presentation cards and business contacts management solutions in the Marketing area. Additionally, in the Finances and Commercial areas, we continued with the digitalization of customer information in a portal, and we supported the Foundation in implementing the scholarship grantees and external entities relationship solution.

We completed the first stages of the Disaster Recovery Plan (DRP) in IT and for operations at CTLL and CTGEBA. This development is in line with our commitment to improve response and recovery maturity levels in case of a potential cybersecurity attack. Moreover, we expanded the security monitoring coverage at CTEB, the wind farms and the El Mangrullo block. Additionally, we conducted the user awareness-building program for the sixth consecutive year, including webinars, training courses, simulations and other activities to better prepare for potential cyberattack attempts. By the end of 2022, we performed the Digital Transformation Sessions, where all our businesses presented their main initiatives and shared their knowledge with the rest of the Company.

Quality, Health, Safety and Environment

We are committed to developing our businesses to observe the highest quality, safety, environmental, and labor health standards, prioritizing personal welfare, environmental care, and energy efficiency. We want to meet current needs without compromising future generations, pursuing sustainable development.

In 2021 our 2017 QHSE Policy evolved towards a new integrated management policy, reinforcing the commitments to the health, well-being, and safety of individuals, the environment, and our shareholders. Its scope incorporates the efficient use of energy and natural resources, the reliability and integrity of our facilities and operations, and their management optimization. The new policy reaffirms that integrated management is an essential part of our operations; it includes ten management principles that constitute a simple and agile guide facilitating and promoting its implementation.

In 2022, although the pandemic and the required special practices and protocols continued, we moved forward with management programs in all its operations, training the staff under integrated management and strengthening our culture in QHSE aspects.

Quality

We further our management quality using ISO standards and the Argentine National Quality Prize model as references, seeking continuous improvement. The primary Management Quality methodologies applied are RMM (Operational Risk Management Matrix), the QHSE performance cycle, the administration of certified management systems and daily management quality.

The RMM seeks to reduce the risks inherent in our operations. In 2022, we implemented 76% of the improvement plans defined in the assessments conducted in 2020. We also evaluate QHSE performance in all our assets based on targets and the systematic monitoring of the QHSE’s indicator dashboard, developed on the QlikView platform, allowing us to make real-time decisions and know their evolution.

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In 2022, we completed the maintenance and recertification program under ISO standards, showing effectiveness in goal fulfillment and commitments to our stakeholders. We have maintained the following certifications: ISO 9001 (Quality Management), 14001 (Environmental Management) and 45001 (Occupational Health and Safety). We have also kept all power plants’ ISO 55001 (Asset Management) and expanded CTGEBA’s ISO 50001 certification to HIDISA, HINISA, HPPL, CTLL, CTEB, CTG and CTP power generation companies, and PEPE II and III wind farms.

Additionally, we continued enhancing QHSE applications toward preventive management and a digital transformation pathway. In 2022, we implemented applications for Change Management and Preventive Health Examinations (EPS) (COVID-19, psychoactive substances, work at heights, confined spaces, etc.). We also developed QHSE training courses through the Company’s new digital training platform.

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 2022 27th annual meeting, we participated in the topic “Leadership in organizations” and “Digital Transformation”. We also submitted two works: “Gas turbine performance monitoring as a fault prevention tool” (CTG) and “Emissions management improvement opportunities in the E&P business”.

Safety

In 2022, we continued developing initiatives to improve safety management and performance in our assets. We moved forward with the specific training for preventing upper and lower extremity accidents, and an reinforcement training on accident investigation was designed to ensure information quality. Moreover, the QHSE Alerts application was refined to improve the communication of lessons learned during the investigation of accidents, turning them into preventive measures for other assets.

Also, we launched two initiatives assessed in the 2021 strategic planning:

• QHSE management field control: it aims to define a methodology for the field verification of different QHSE preventive practices (golden rules, environmental procedures, facilities conditions, operational, legal compliance, etc.) by asset leaders and reports, supplemented with behavioral preventive observations, thus showing a visible leadership commitment; and

• QHSE in services procurement: it aims to review QHSE requirements for services procurement and these services and contractors’ performance assessments, in line with the integrated management policy, ensuring their compatibility with the Company’s standards.

Regarding industrial hygiene, we continued improving chemical, physical and ergonomic risk maps, which were submitted to the new ART. Additionally, we continued with the carcinogenic substances and compounds surveillance system established by the Superintendence of Labor Risks.

Environment

Pampa’s operations seek sustainable development in line with the Principles of the United Nations Global Compact we signed in 2019. The Company is committed to protecting the environment and endeavors to optimize natural resources in its projects by applying proper and economically viable technologies.

In 2022, we continued implementing and spreading the Environmental Principles, which facilitate compliance with our integrated management policy and are aligned with SDG 4, 6, 7, 8, 9, 12, 13 and 17. Moreover, we have participated in CEADS-EY Argentina’s Connecting Companies with the SDG for the third consecutive year. This program seeks to consolidate the companies’ role in the 2030 Agenda, make their contributions visible, and support them in aligning their agendas with the 17 SDGs. The most prominent initiatives we presented contribute to SDG 4: “Quality education” and SDG 7: “Ensuring access to affordable, reliable, sustainable and modern energy”, evidencing Pampa’s commitment to sustainable development.

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In line with efficient energy management, in 2022, we continued with ISO 50001 implementation and certification in the power generation business, developing usage and consumption matrices in each site to set atmospheric emissions reduction goals and use resources efficiently. Moreover, at E&P, a study was conducted to identify opportunities for reducing CO2 emissions from venting and field carbon capture. In PGSM, an infrared-camera leak detection practice was implemented, allowing for fast scanning and maintenance actions, resulting in loss reduction and work environment improvement.

Additionally, in 2022 Pampa was once again a CDP (Carbon Disclosure Project) signatory on climate change and water security, achieving outstanding scores and improving our operations’ environmental management.

Response to Emergency

At Pampa, we act to prevent undesirable events and are prepared to provide a prompt and effective response to emergencies. We continued making periodic emergency response simulations, promoting established practices and specific improvements, and incorporating them into the integrated management system.

In 2022, we conducted training programs in line with the Emergency Response Plans, with more than 1,500 training hours to develop skills and competencies, in addition to coordinating the necessary activities if an undesired event occurs.

Moreover, we completed the fire detection and suppression systems’ assessment, evaluating and ensuring their proper working condition and response capacity and identifying improvement opportunities for future work plans. Through theoretical and practical training, we implemented an emergency response methodology called the “Incidents Command System”, performing new field simulations and mobilizing resources with the participation of active forces. Finally, relationship-building and training activities were performed with the Volunteer Fire Brigade, Gendarmerie, Civil Defense and other organizations in our communities.

Occupational Health

At Pampa, we have a team of nurses and doctors with whom we continue developing occupational health promotion programs, focusing on prevention and contributing to SDG 3 for a healthy work environment.

Together with the human resources team, we reinforced SUMA Bienestar, a program centered on the teammates’ personal life and physical, emotional, labor and financial wellness. Some needs were identified in the employees’ annual medical check-ups, enabling the design of specific health programs for the assessed groups. Additionally, we continued implementing the Policy on Alcohol, Drugs and Psychoactive Substances, focusing on safety through training and Preventive Health Check-ups (PHC).

In 2022, we continued developing Cardiopulmonary Resuscitation (CPR) and First Aid training courses, a physical activity plan, and flu and tetanus vaccination campaigns. We also continued developing the Cardiac Protection program according to international standards. We were recertified with Experta ART as a “Cardiac Protected Company” until 2023. Moreover, talks were organized with professionals specialized in addictions, smoking cessation, depression and stress management, and the Wellness legal and psychological support service continued. Nutritionists developed healthy eating proposals for food safety, and food quality audits were conducted in our cafeterias.

Pampa is a blood-donation-friendly company. Therefore, in 2022 it continued promoting voluntary blood drives for its employees.

Regarding COVID-19, in 2022, the focus was placed on a sustainable change of habits by our employees, looking after their and their families’ health and well-being and allowing us to maintain and ensure uninterrupted operational continuity. Moreover, in addition to continuing with health measures (symptoms self-monitoring, disinfection with UV radiation or quaternary ammonium, ventilation systems, social distancing, etc.), we have moved forward with a hybrid working scheme for positions allowing so.

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Corporate Responsibility

Pampa’s social investment programs and actions are carried out within a strategic relationship model with our stakeholders, conducted together with the Foundation. With a strong commitment to society, we develop programs that contribute to improving people's quality of life and strengthening the capacities of the institutions belonging to the communities where we are present, thus promoting inclusion.

To support the development of the community and set clear, measurable and assessable goals and intervention modalities, we have framed our social investment strategy on three axes: education, employment and social inclusion. Set forth below is a brief description of our programs.

As a company committed with managing our business’s economic, social and environmental impacts through our social investments and our employees’ voluntary support, we intend to contribute to the Sustainable Development Goals (SDG) in which we can contribute the most to the common good, through our different programs: SDG 4 (quality education), SDG 7 (affordable and clean energy), SDG 8 (decent work and economic growth) and SDG 12 (responsible consumption and production). We strongly rely on the background and the importance of the efforts by social organizations and public entities. In this context, we have partnered with them for the development of social investment initiatives. SDG 17 (partnerships for the goals) cross-cuts all our initiatives.

In 2022, our Educational Trajectory Support Program was recognized by the “Consejo Empresario Argentino para el Desarrollo Sostenible” within the framework of the Connecting Companies with the SDGs program, thanks to the presentation of 4 initiatives that contribute to SDGs 4 and 7. Likewise, we were invited to participate in the 1st social inclusion international forum, Camino al Bienestar, convened by the Secretary of Government of the City of Mendoza in the Social Leadership panel with a focus on educational strengthening from corporate social responsibility.

Education and Labor Placement Training

We believe that education is the key to development and social and labor market inclusion, strengthening knowledge to expand horizons. Therefore, we seek to provide equal opportunities to children and young people in vulnerable situations.

We seek to support the completion of technical secondary education studies and the entry into university and college of teenagers living in the Provinces of Neuquén, Salta, Mendoza, Buenos Aires and Santa Fe. Young people participating in our program receive monthly financial assistance and personalized support, training and educational trips. Our scholarship grantees can get acquainted with formal work environments and perform activities so that they may envision concrete employment possibilities in the future.

In 2022, we supported 1,546 students, 1,151 of whom were attending the last three years of technical secondary education, and 392 university and college students, of whom 360 secondary students and 30 university students graduated from courses of study associated with our businesses, mainly engineering.

Likewise, together with IAPG, we invited 99 university scholarship holders and 1,080 technical secondary students to participate in the AOG (Argentina Oil & Gas) exhibitions in Buenos Aires and Patagonia to learn about aspects of the oil and gas industry. In addition, we invited 125 students to participate in virtual courses taught on the PERFIL e-learning platform, with extensive training content to boost their careers and ventures, providing tools for professional life.

At Pampa, we believe that the students’ environment should also be taken into account when thinking of their educational paths. In 2022, we provided tools to 1,187 teachers and school authorities, who implemented what they learned with more than 25,000 students. We performed ten editions of Energy Researchers, an initiative seeking to develop the scientific spirit at the kindergarten and primary school levels, with the participation of 223 teachers from 128 schools. Additionally, we offered efficient energy workshops to 34 teachers from 12 technical schools from Mendoza, Buenos Aires and Neuquén.

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Regarding school authorities’ accompaniment, we continued strengthening the Foundation’s Schools Network: 27 technical schools participated, and 130 educators completed the training. In addition, we offered 3 instances of teacher training open to the public. More than 800 people attended the "Dialogues for school transformation" that were facilitated by leaders such as Diego Golombek, Rebeca Anijovich and Lila Pinto.

As part of our commitment to improve educational institutions, we contributed to the schools, universities, and training centers of the communities where we operate. In 2022, we invested Ps. 6 million in 14 educational institutes, mainly for equipment and repairments.

Additionally, we conducted professionalizing practices, first job workshops, and training spaces for secondary, college, and university students. Their goal is to consolidate, integrate, and expand knowledge and capabilities matching the students’ developing professional profile, thus increasing their employability. In 2022, we organized different experiences for 1,271 young students.

We continued fostering professionalizing trainings in the last years of technical schools. The number of students participating increased by 20%, thanks to internal practices and partnerships with other entities. The program was held in a hybrid mode for 286 students from 27 technical schools and they completed 15,937 theoretical and practical training hours with the aid of 201 internal and external volunteers. We made alliances with Fundación Siemens, 500RPM to offer professionalizing trainings to an additional 135 high-school students from Neuquén and Buenos Aires. At Pampa’s Headquarters, we carried out a program called Activities to Approach the World of Work for 79 high school students, who completed an average of 65 hours of internships and training in 5 areas of the Company.

Moreover, we organized for the first time, together with the Government House of Neuquén and in alliance with other companies, a day of workshops on employability for more than 250 6th year students from technical secondary schools in the city of Neuquén. And like every year, together with the AcercaRSE group, we hold the "Employability Meeting for Technical Schools" for 420 students from Zárate, Campana and Lima.

At university and college levels, we carried out, together with the Pampa’s HR team, 5 days of mock group interviews and training for the first job for 83 students from Buenos Aires, Neuquén and Bahía Blanca who participate in the university accompaniment program. Additionally, we facilitated 200 hours of supervised professional practices and internships for 10 scholarship students from universities in Salta, Bahía Blanca and Buenos Aires.

Finally, we monitored the 3 teams selected in the “Proyecto Joven 2021” initiative to continue promoting their innovation and triple impact projects thanks to the seed funding and professional support they received as a prize. One of the 3 teams participated in the Mayma Latam impact program.

Local Assessment and Development of Community Impact Projects

We understand that the relationship between the Company and its stakeholders is cross-cutting throughout the business. In 2022, we implemented twenty-nine actions oriented for the community, suppliers and local governments. We also organized five workshops with more than 30 leaders, determining at least 5 cross-cutting indicators for the evaluation and monitoring of proposed plans. Likewise, throughout the country we accompany 16 institutions for sustainable development in social responsibility roundtables and working groups, in addition to providing funding.

We list our most relevant activities during 2022:

(1)  Sustainable energy: As a power company, we develop social projects facilitating access to energy through renewable sources and energy efficiency improvement. In the Province of Salta, since 2017 we have worked with Fundación Solar Inti in the Self-construction of Eco-Stoves to develop autonomy and entrepreneurship among women from the guaraní community in Piriquenda. In 2022, we carried out the maintenance of the stoves installed in 2017 and 2020, and we also added 20 new beneficiaries, increasing the social, environmental and economic impact to 50 families.

Moreover, we offered levels 1 and 2 of the Energy Efficiency program to 11 teachers and 84 students from technical schools in Buenos Aires and Neuquén, who received a certification as technical assistants for energy management, expanding their possibilities of professional insertion. In three years, the program achieved 25% annual energy savings in homes, avoiding the emission of 80 tons of CO2e per year. In schools, a decrease in consumption of 13,294 kWh and a capture of greenhouse gases of 7 tons of CO2 per year are calculated thanks to the implantation of 10 trees per institution.

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In CTGEBA, together with 15 students and 5 teachers from local technical schools, we developed a social and educational project to manufacture and install a low-power 350 W Piggott wind turbine. The system will supply School N°4 in Marcos Paz where 120 children assist. We also performed maintenance works on two other units installed in Coronel Rosales’s rural schools together with 29 students and teachers.

In solar energy, we completed the project to install solar hot water heaters for residents without access to gas in Derqui (Pilar, Buenos Aires), carried out together with Vivienda Digna. This experience, developed since 2020, allowed savings of 40% in electricity consumption of 40 families. It was presented in the National Congress during the debate on housing energy efficiency within the framework of the Housing Labeling Law project.

(2)  Skills training and support for productive undertakings: We continued fostering productive activities and creating employment through job skills courses for people whose profiles are associated with our business or demanded in the community. We also supported productive undertakings generating social and/or environmental benefits.

In Buenos Aires, 129 people from Bahia Blanca graduated from the Good Job Program, which seeks to improve the employability of young people aged 18-35 with no formal occupation. In Ensenada, 27 people participated in 2 courses carried out by the University of La Plata.

In Salta, in partnership with the Ministry of Education and the Municipality of General Güemes, we conducted a construction assistant course for industrial electrical installations with a duration of 312 hours where 39 students graduated.

We also continued with the Programming Inclusion Program together with Fundación Formar and Digital House. In Buenos Aires, 33 young participants graduated as specialists in full stack web programming, and in Neuquén 26 young participants are in training for 10 months to become professional in this proposal.

Likewise, in order to accompany labor inclusion of people with disabilities, we awarded scholarships to 4 students from the Baccigalupo Foundation to graduate as sports assistants. Since 2016, we have awarded scholarships to 28 students. In addition, we continued providing supplies to the Accervil Protected Workshop for product manufacturing by 45 workers with motor disabilities.

On the other hand, we continue with the Responsible Inclusive Purchasing program included in the Company's purchasing procedure to provide equal opportunity to suppliers that integrate social development variables into their value chain and contribute to the local economy. In 2022, we added the environmental variable in the supplier selection matrix, we carried out 2 awareness workshops for different areas of the Company, and we organized 7 face-to-face and 9 virtual fairs in Salta, Mendoza, Santa Fe, Neuquén and Buenos Aires, summoning 35 social enterprises.

(3)              Enhancement of local organizations: We assist in improving organizations’ institutional management by making contributions and supporting the projects they develop. Since 2021, based on different community meetings held with the Saberes Foundation, we seek to empower leaders so that they may play a key role in detecting critical health issues in their spaces. In 2022, we carried out the second stage of the training of 40 health promoters women in Piquirenda, addressing issues related to a healthy community, gender perspective and rights, childhood, adolescence and families. On the other hand, we are founding partners of the Public Private Laboratory, which seeks to accelerate meetings between governments, the private sector and civil society to transform them into allies for development. It is currently being developed in 10 cities. In addition, in the city of Buenos Aires we joined the Social Economy Development Fund (FONDES) to promote private sector investment towards financing alternatives for productive units in poor neighborhoods, social economy ventures and cooperatives.

Volunteering Actions

We are convinced that our employees are our main asset, and that we are responsible for the creation of shared value in and with the communities where we operate our assets. Through the volunteering committees, we seek that our employees may draw up proposals contributing to solving social difficulties identified at the local level and allowing, in turn, to reinforce each asset’s links with the community. Hence, Pampa can contribute to its socio-economic and community development, and strengthen the organizational culture and the employees’ sense of belonging. We currently have 10 active volunteering committees, with 115 persons in total. Committee members of facility meet periodically to define activities, create action plans, and coordinate actions with strategic partners at the local level. In 2022, we fostered 27 actions, with 1,707 volunteers, dedicating more than 5,500 hours to humanitarian activities.

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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, consisting of power plants (thermal plants, hydroelectric complexes and wind farms), oil and gas assets that allow us to explore and exploit oil and gas reserves (mainly wells, facilities and pipelines), petrochemical industrial complex, and corporate office buildings is located in Argentina.

Insurance

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, 2022, the total generation assets covered under these policies are valued at US$5,765 million.

In our oil and gas business, we carry full insurance, including business interruption and general liability insurance. As of December 31, 2022, the total oil & gas assets covered under these insurance policies are valued at US$588 million.

In our petrochemical business and distribution business, we also carry full insurance, including business interruption and general liability insurance. As of December 31, 2022, the total assets covered under insurance policies are valued at US$1,424 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

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 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 ultimate objective of the privatization process was to reduce rates paid by users and improve the quality of the electricity supply service through competition. The privatization process commenced in February 1992 with the sale of several large thermal generation facilities, and continued with the sale of transmission and distribution facilities (some of which we currently own) and additional thermoelectric and hydroelectric generation facilities.

ThePublic 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, are currently operating at near full capacity, which could lead to insufficient supply to meet a growing national energy demand.

To address the electricity crisis, the Argentine Government has repeatedly intervened in and modified the rules of the WEM since 2002. These modifications included the imposition of caps on the prices paid by distributors for electricity power purchases (pursuant to SE Resolution No. 8/02) and the requirement that all prices charged by generators be calculated based on the price of natural gas (which is also regulated by the Argentine Government), regardless of the fuel actually used in generation activities (pursuant to SE Resolution No. 240/03), which together created a huge structural deficit in the operation of the WEM.

In December 2004, the Argentine Government adopted new rules for the electricity market (pursuant to SE Resolutions Nos. 826/04 and 712/04), which come into effect once the construction of two new 800 MW CC generators had been completed. These two generators commenced commercial operations in open cycle during 2008 and in CC during the first quarter of 2010. Construction was partially financed with credit balances of generators resulting from the spread between the sales price of energy and generation variable cost, which were transferred to the FONINVEMEM.

Electricity generators accepted the opportunity under SE Resolution No. 1,427/04 to participate in the FONINVEMEM projects.

The construction of these new generators evidenced a decision by the Argentine Government to take a more active role in promoting energy investments in Argentina. In addition to these projects, in April 2006 the Argentine Congress enacted a law that authorized the Argentine Government to create a special fund to finance infrastructure improvements in the Argentine energy sector through the expansion of generation, distribution and transmission infrastructure relating to natural gas, propane and electricity. Contributions to this fund were made through specific charges passed on to customers as an item on their energy bills.

In 2006, the SE implemented the Energy Plus Program (pursuant to SE Resolution No. 1,281/06) to create an incentive for increased electricity generation. Projects implemented under the Energy Plus Program are not subject to market regulations regarding prices. Instead, prices can be freely negotiated between generators and users within the cap authorized by the former Ministerio de Planificación Federal, Inversión Pública y Servicios.

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The Energy Plus Program sought to increase electricity generation and satisfy domestic demand. For that purpose, CAMMESA requires that all large users (those consuming more than 300 kW) purchase their incremental demand (any volumes exceeding their 2005 consumption) from new generators under the Energy Plus Program.

Through Law No. 26,350, it also modified the official time zone for the summer periods, in order to promote a decrease in the use of electric power.

In order to increase the electric power supply, the Argentine Government also established a program called Delivered Electric Energy, through the supply of small transportable thermal plants and/or embarked power plants. The investment was made by a private investor with a power purchase agreement with ENARSA. The generator in the WEM was ENARSA. As of the date of this annual report almost every generator installed within this scheme, has become a “generator” in the WEM and the contracts with ENARSA have been terminated.

The Argentine Government additionally continued to implement various measures in order to regulate the operation of the WEM and of the intervening agents. SE Resolution No. 95/13, established values for the remuneration of fixed and variable costs to be paid to generators, co-generators and self-generators for energy sales, and an additional remuneration was added. These values were not applicable to bi-national hydroelectric power plants, nuclear generation or to generation committed in contracts regulated by the SE, such as those under the Energy Plus Program. Such resolution temporarily suspended new contracts under the WEM Term Market, other than those regulated by the SE, and it provided that upon the termination of existing contracts in the Term Market, large users must purchase their energy demand from CAMMESA. In addition, the resolution provides that commercial management and fuel delivery to the WEM plants will be centralized in CAMMESA. Resolution No. 95/2013 of the SE, as amended by Resolution No. 529/2014 of the SE, was updated on several occasions to reflect increases to the remuneration of generators. Moreover, SEE Resolution No. 19/2017 modified the entire generation remuneration regime. As of the date of this Annual Report, the current remuneration scheme beginning in February 2020 is established by SE Res. No. 31/20 (see “—The Argentine Energy Sector— Remuneration Scheme for Generation Not Covered by Contracts— SE Res. No. 31/20: February 2020 – January 2021).

In December 2015, through Decree No. 134/2015, the Argentine Government declared a state of emergency with respect to the national electricity system that remained in effect until December 31, 2017. 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. In spite of the fact that the emergency was not extended, the Argentine Government continued its intervention in the energy sector and measures allowing its return to normal are still pending.

In 2019, SEE Resolution No. 1/2019, amended the remuneration scheme established in SEE Resolution No. 19/2017. The SEE Resolution No. 1/2019 was recently amended by SE Resolution No. 31/2020 which modified the power generation segment’s remuneration scheme and established prices denominated in Argentine Pesos (formerly denominated in U.S. Dollars) and reduced such prices in different proportions according to the technology employed. For more information on Resolution No. SEE 1/19 see (“—The Argentine Energy Sector— Remuneration Scheme for Generation Not Covered by Contracts— SE Res. No. 31/20: February 2020 – January 2021”). In the following years the SE amended the remuneration scheme increasing the values set forth in SE Res. No. 31/20 (“The Argentine Energy Sector— SE Res. No. 440/21 amended by SE Res. No. 238/22 and subsequently amended by SE Res. No.826/22. Current Remuneration Scheme beginning in September 2022”).

On December 2019, the Social Solidarity and Productive Reactivation Law was enacted, which, among other measures, established a 180-day freeze in energy and natural gas tariffs and the relaunching of RTI (this period has been extended by Decree No. 543/2020 and Decree No. 1020/2020 until the RTI process concludes or the transitional tariff increase is put into effect) and enabled the President to intervene the regulatory authorities (ENRE and ENARGAS). On March 16, 2021, a public hearing was held to discuss the transitory tariff increases. On December 7, 2022, by means of Decree No. 815/2022, the term for concluding the RTI was extended for one additional year. Consequently, as of the date of this annual report, the determination of the new tariffs is still pending.

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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 the responsibility of the SE;

(2) the ENRE; and

(3) CAMMESA.

The SE advised the Argentine Government on matters related to the electricity sector and was responsible for the application of the policies concerning the Argentine electricity industry. On December 10, 2019, Decree No. 7/2019 modified the Ministries Law No. 22,520. Among other changes, it created the MDP, which assumed the functions and is responsible for the execution of the national policies in relation with the energy sector. The responsibilities of the MDP include participating “in the management of the State’s shareholdings in the corporations and companies operating in the area of its competence.” Later, in September 2020, Decree No. 706/2020 and Decree No. 743/2020 modified the functions of the Ministry of Economy and transferred the SE from the MDP to the Ministry of Economy (ME).

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. 277/2020, 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.

On March 16, 2020, the Executive Branch ordered the intervention of the ENRE as authorized by the Social Solidarity and Productive Reactivation Law (Decree No. 277/2020). On December 16, 2020, the Executive Branch extended the ENRE’s intervention until December 31, 2021 or until the end of the RTI, whichever occurs first. On December 24, 2021, the Executive Branch extended the ENRE’s and ENARGAS’ intervention until December 31, 2022 (Decree No. 871/2021) and, on December 6, 2022, the ENRE’s and ENARGAS interventions were extended until December 31, 2023 or until the conclusion of the RTI process, whichever occurs first (Decree No. 815/2022).

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:

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· 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. 95/2013, 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 (according to section 8 of SE Resolution No.95/2013 and section 4 of SE Resolution No. 529/2014, as amended); 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, (ii) the transmission companies, (iii) the distribution companies and (iv) the large users.

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.

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. 95/2013, which in this respect, remains in effect except for the Energy Plus Program and, as of 2017, renewable energy supply contracts. As of December 31, 2021, Argentina had a nominal installed capacity as reported by CAMMESA of 43.0 GWh. In 2021, thermal generation generated 90,073 GWh (64%), hydroelectrically energy generated 23,580 GWh (17%), renewable energy generated 17,435 GWh (12%) and the nuclear energy generated 10,170 GWh (7%). In 2021, imports amounted to 819 GWh and exports to 3,850 GWh.

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.

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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.

The Organismo de Control de Energía Eléctrica de la Provincia de Buenos Aires (“OCEBA”) monitors compliance by the Province of Buenos Aires distributors, including Eden, Edes and Edea as well as the municipal distributors with the provisions of their respective concession agreements. We and Edesur are the largest distribution companies and, together with Edelap, originally comprised SEGBA, which was divided into three distribution companies at the time of its privatization in 1992.

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”).

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.

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:

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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. 1,398/1992, 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. 1,398/1992, 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.

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 BCL 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.

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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.

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 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 Res. No. 748/21).

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With respect to the remuneration for legacy generation capacity, the remuneration scheme established by SEE Res. No. 19/17 remained in force until February 28, 2019. From March 1, 2019 to January 31, 2020 SRRYME Res. No. 1/19 was in effect, and, beginning on February 1, 2020, SE Res. No. 31/20 has come into in effect. As of February 2021, SE Resolution No. 440/21 increased the values defined in SE Res. 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.

In the case of the 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 2 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 1 times such value for the same hours of the day for March, April, May, September, October and November.

For more information, please see “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”. Upon the entry into force of Plan Gas.Ar, Resolution SE No. 354/2020 established that the thermal power plants should cover the costs related to the supply of the natural gas volumes under such scheme and other associated costs including the costs of the “take or pay” obligations under natural gas supply contracts, import costs and duties, and transport costs, among others.

Power plants dispatch

Upon the entry into force of Plan Gas.Ar, Resolution SE No. 354/2020 changed the dispatch of thermal power plants establishing five categories according to the source of the natural gas supply. This scheme modifies 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 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 over 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 287/17) may operatively assign the volumes and transport capacity that they have contracted. If they proceed with such assignment, they will enter in the third category, on the contrary if they don’t execute the assignment, they will enter in the fifth category.

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 customer) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators. These prices did not change from January 2005 until November 2008. See “Item 5. Operating and Financial Review and Prospects—Electricity prices and tariffs.”

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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.6/2016, 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. 6/2016 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 in generator’s operations.

Moreover, SEE Resolution 20/17 allowed the 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 Res. No. 769/22).

Resolution SEE 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. 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 (Res. SE No. 408/21; 748/2; 1029/21 and 40/22). The main changes included the division of each distributor’s users into different categories in order 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.

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On January 2022, the SE instructed the ENRE to include the discussion of the latest seasonal prices in the public hearing held on February 17, 2022 in relation to the transport and distribution tariffs. For more information see “Item 5. Operating and Financial Review and Prospects—Electricity prices and tariffs.”. After such hearing, on February 24, 2022, the SE issued its Resolution No. 105/22 which included an increase in the WEM seasonal prices for certain users such as public authorities, commercial and general demand, and households, to be applied from March to April 2022. The increases went from 34% to 50% for the WEM and from 10% to 20% for the WEMTF. It also approved an increase in transport fees.

On April 18, 2022, the SE issued Resolutions No. 235/22 and 236/22 which called for public hearing to address a tariff segmentation scheme for 2022 and 2023 and to analyze the WEM seasonal beginning on June 1, 2022. The public hearing will take place on May 11 and 12, 2022.

On April 29, 2022, the SE issued Res. SE No. 305/22, which approved the winter seasonal programming (May – October 2022), and eliminated the subsidies to GUDIs, kept the same capacity and energy reference prices for general and residential users, maintained the same transportation reference prices (SE Res. No. 105/22) and approved new unsubsidized capacity and energy reference prices.

On May 28, 2022, SE Res. N0 405/22 increased the seasonal energy prices for general and residential users in 36.6% and 26.1%, respectively, applicable as of June 1, 2022. Capacity reference prices were not increased.

On July 29, 2022, SE Res. No. 605/22 approved the quarterly seasonal reprogramming increasing the seasonal capacity price in 23% and reducing the energy reference price in 1.8% for GUDIs. It also maintained the transportation reference prices (SE Res. No. 105/22) and increased the unsubsidized capacity and energy reference prices in 40% and 21%, respectively.

On August 30, 2022, SE Res. No. 627/22 and 629/22 increased energy reference prices for GUDIs, which are health and education public institutions (39% to 44%) and for high income residential users (65.9% to 74.8%). As of September 1, such prices apply to medium income residential users for their demand exceeding 400 kWh/month or 550 kWh/month (according to the province).

On October 31, 2022, SE Res. 719/22 approved the summer seasonal programming (November 2022 – April 2023) which: (i) reduced capacity and energy reference prices for GUDIs in 1.42% and 19.6%, respectively; (ii) increased energy reference prices for GUDIs which are health and education public institutions (21.12% to 23.77%); (iii) increased energy reference prices for general (non-residential) demand (22.56% to 25.37%); (iv) increased energy reference prices for high income residential users (32.42% to 35.37%); and (v) reduced the unsubsidized capacity and energy reference prices for 1.42% and 19.16%, respectively. As of February 1, 2023, GUDIs energy reference prices increased by 14%. The resolution also established a new spot price of 1682 $/MWh.

Finally, on February 2, 2023, SE Res. No. 54/23 approved the quarterly seasonal reprogramming (February – April 2023), which established a new grouping for distribution users (e.g., four levels for residential users, two levels for general demand, etc.). Capacity and energy reference prices for GUDIs were increased in 73.12% and 6.24%, respectively. Energy reference prices for residential users (levels 1 and 3) were increased by 28% to 38%. Reference transportation prices remained unchanged and new unsubsidized reference prices were approved.

Term market

Generators may also enter into agreements in the term market to supply energy and capacity to distributors and large users. Distributors are able to purchase energy through agreements in the term market instead of purchasing energy in the spot market. 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. 95/2013 which, in this aspect, remains in effect except for the Energy Plus Program and, as of 2017, renewable energy supply contracts.

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Revenues from the Electric Power Generation Activity

Our revenues from the electric power generation activity come from: (i) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SEE Resolution No. 19/17, from February 2017, SRRYME Resolution No. 1/19 from March 2019 and SE Resolution No. 31/20 from February 2020, and SE Resolution No. 440/21 amended by Resolutions 238/22 and 826/22 of February 2021); (ii) sales contracts with large users within the MAT (Resolutions No. 1,281/06 and No. 281/17); and (iii) supply agreements with CAMMESA (Resolutions No. 220/07, No. 21/16, No. 287/17 and RenovAr Programs). Furthermore, energy not committed under sales contracts with large users within the MAT and with CAMMESA are remunerated at the Spot market.

Remuneration Scheme for Generation Not Covered by Contracts

SE Res. No. 31/20: February 2020- January 2021

SE Res. No. 31/20 was published on February 27, 2020, modifying certain aspects of the remuneration scheme set forth by SRRYME Res. No. 1/19, effective as of February 1, 2020. The new resolution converts the entire remuneration scheme into local currency at an exchange rate of Ps.60/US$ and establishes an update factor beginning in the second month of its application, which follows a formula consisting of 60% CPI and 40% IPIM. However, on April 8, 2020, the SE instructed CAMMESA to postpone the automatic application of the above-mentioned adjustment formula until further notice.

Thermal Power Generators

SE Res. No. 31/20 reduces the power capacity remuneration, whether base or guaranteed, depending on the technology used. However, for thermal generation plants with a total installed power capacity lower than or equal to 42 MW, the base power capacity values set out by SRRYME Res. No. 1/19 remain in effect:

Technology / Scale	Capacity’s Base Price (Ps./MW-month)	Variation vs. SRRYME Res. No. 1/19*
Large CC Capacity > 150 MW	100,650	-45%
Small CC Capacity ≤ 150 MW	112,200	-45%
Large ST Capacity > 100 MW	143,550	-45%
Small ST Capacity ≤ 100 MW, Internal Combustion Engines Capacity (“ICE”) > 42 MW	171,600	-45%
Large GT Capacity > 50 MW	117,150	-45%
Small GT Capacity ≤ 50 MW	151,800	-45%
Small CC Capacity ≤ 15MW	204,000	-
Small ST Capacity ≤ 15MW	312,000	-
Small GT Capacity ≤ 15MW	276,000	-
ICE ≤ 42 MW	312,000	-

Note: * Assumes an exchange rate of Ps.60/US$.

With regards to the remuneration for the offered guaranteed power capacity, the following scheme remains in effect:

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Period	Capacity’s Base Price (Ps-/MW-month)	Variation vs. SRRYME Res. No. 1/19*
Summer (December - February) and Winter (June - August)	360,000	-14%
Other (March - May and September - November)	270,000	-18%
Internal Combustion Engines ≤ 42 MW, summer/winter	420,000	-
Internal Combustion Engines ≤ 42 MW, other	330,000	-

Note: * Assumes an exchange rate of Ps. 60/US$.

As is the case for the SRRYME Res. No. 1/19, the SE Res. No. 31/20 provides for the application of a coefficient which results from the unit’s average utilization factor during the last twelve months to the power capacity remuneration. Although the formula remained unchanged for internal combustion engines ≤ 42 MW, in all other cases, if the usage factor is lower than 30%, then 60% of the power capacity payment is collected.

With respect to the additional remuneration in the hours with a HMRT, which consists of the 50 recorded hours with the highest thermal generation dispatch each month, grouped in two-25 hours blocks each, the following will be applied to the average generated capacity during such hours:

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	-

With respect to the remuneration for generated and operated energy, they remained unchanged in US$ at an exchange rate of Ps.60/US$, but had been set at Ps.240/MWh with natural gas, Ps.420/MWh with fuel oil, Ps.600 with biofuels (except for internal combustion engines, Ps.720/MWh) and Ps.720/MWh with mineral coal. The remuneration for operated energy was set at Ps.84/MWh.

Hydrological Generators

SE Res. No. 31/20 adjusted the power capacity remuneration and added a new HMRT remuneration. The 1.05 factor over the power capacity is maintained to compensate the impact of programmed maintenance, as well as the 1.20 factor for units maintaining control structures on river courses and not having an associated power plant.

Scale	Capacity’s Base Price (Ps./MW-month)	Variation vs. SRRYME Res. No. 1/19*
Large HI Capacity > 300 MW	99,000	-45%
Medium HI Capacity > 120 ≤ 300 MW	132,000	-45%
Small HI Capacity > 50 ≤ 120 MW	181,500	-45%
Renewable HI Capacity ≤ 50 MW	297,000	-45%
Large Pumped HI Capacity > 300 MW	99,000	+10%
Medium Pumped HI Capacity > 120 ≤ 300 MW	132,000	-12%

Note: * Assumes an exchange rate of Ps. 60/US$.

With respect to the HMRT additional remuneration, the following will be applied to the average operated power capacity:

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Scale	Capacity’s HMRT Price Ps./MW-HMRT
Large HI Capacity > 300 MW	27,500
Medium HI Capacity > 120 ≤ 300 MW	32,500
Small HI Capacity >50 ≤ 120 MW	32,500
Renewable HI Capacity ≤ 50 MW	32,500
Large Pumped HI Capacity > 300 MW	27,500
Medium Pumped HI Capacity > 120 ≤ 300	32,500

Weighted by the following coefficients:

HMRT	December - February, June - August	Other
First 25 HMRT hours	1.2	0.2
Second 25 HMRT hours	0.6	-

The prices for generated and operated energy have remained unchanged in US$ at an exchange rate of Ps.60/US$ but have been set at Ps.210/MWh and Ps.84/MWh, respectively. The remuneration for operated energy should correspond to the grid’s optimal dispatch. The provision does not indicate, as it does for thermal generators, which would be the consequence for failing to do so.

Other Considerations

For energy generated from any unconventional source, SE Res. No. 31/20 provides for a single remuneration value of Ps.1,680/MWh, which equals the previous remuneration at an exchange rate of Ps.60/US$, or 50% of this value if it is generated prior to commercial commissioning.

Furthermore, SE Res. No. 31/2020 provides for the application of all receivables accrued in favor of generators for settlement to the repayment of loans for the execution of overhauls, and sets a discount scheme in the generator’s revenues equivalent to Ps.60/MWh, or Ps.42,000/MW-month for the unit’s actual availability, whichever is higher. It is worth highlighting that all overhauls financing owed by Pampa were canceled under the CAMMESA Agreement for the Regularization and Settlement of Receivables with the WEM.

SE Res. No. 440/21 amended by SE Res. No. 238/22 and subsequently amended by SE Res. No. 826/22. Current Remuneration Scheme beginning in September 2022.

On May 21, 2021, SE Res. No. 440/21 was published in the Official Gazette increasing the remuneration scheme on average 29% under SE Res. No. 31/20. The resolution was retroactive as of February 2021 and rendered ineffective the update factor. The resolution further provided that generators could apply this 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 Res. No. 31/20. Pampa adhered to this scheme.

The remuneration scheme approved in Resolution No. 440/21 was modified on April 21, 2022, by SE Res. No. 238/22. The latter established a 30% increase in remuneration retroactive to 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 Res. 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. It also eliminates the use factor used to calculate generators remuneration and the temporary energy export remuneration.

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Thermal Power Generators

The remuneration comprises a fixed remuneration for the monthly available power capacity, with or without DIGO (Guaranteed Availability Commitment), a variable remuneration for generated and operated energy, and an additional monthly remuneration for the average capacity actually delivered during each month’s HMRT (hours of maximum thermal demand).

The prices for power capacity, in Ps./MW-month, for generators not offering DIGO, are as follows:

Technology / scale	From Sep 22 to Nov 22	From Dec 22 to Jan 23	From Feb 23 to July 23	From Aug 23
Large CC > 150 MW	222,804	245,084	306,355	392,135
Small CC ≤ 150 MW	248,370	273,207	341,509	437,132
Large ST > 100 MW	317,769	349,546	436,932	559,273
Small ST ≤ 100 MW & ICE	379,861	417,847	522,308	668,555
Large GT > 50 MW	259,329	285,262	356,577	456,419
Small GT ≤ 50 MW	336,031	369,634	462,042	591,414

Note: Unlike Res. SE Nº 238/22, MCI is not differenced by size.

The prices for power capacity, in Ps./MW-month, for generators offering DIGO, are as follows:

Period	From Sep 22 to Nov 22	From Dec 22 to Jan 23	From Feb 23 to July 23	From Aug 23
Summer (Dec-Feb) and winter (Jun-Aug) in general	796,910	876,601	1,095,752	1,402,562
Others (Mar-May & Sep-Nov) in general	597,683	657,451	821,814	1,051,922

100% of the real power availability is remunerated with DIGO price.

Prices for generated energy according to the fuel used, in Ps./MWh, are as follows:

Fuel	From Sep 22 to Nov 22	From Dec 22 to Jan 23	From Feb 23 to July 23	From Aug 23
Natural gas	532	585	731	936
FO or GO	930	1,023	1,279	1,637
Biofuels in general	1,328	1,461	1,826	2,338
Biofuels for ICE	1,594	1,754	2,192	2,806
Mineral coal	532	585	731	936

The price for operated energy was set at Ps.185/MWh beginning in September 2022. It was later increased to Ps.204/MWh beginning in December 2022, then to Ps.255/MWh beginning in February 2023 and finally to Ps.326/MWh beginning in August 2023, irrespective of the fuel type.

Hydrological Generators

The remuneration is comprised of a fixed remuneration for the monthly available power capacity, a variable remuneration for the generated energy and the operated energy. In addition, a 1.05 factor was set over the power capacity to compensate for programmed maintenance’s impacts, and a 1.20 factor for units maintaining control structures on river courses and not having an associated power plant.

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The following chart shows power capacity prices in Ps./MW-month:

Scale	From Sep 22 to Nov 22	From Dec 22 to Jan 23	From Feb 23 to July 23	From Aug 23
Large HI > 300 MW	219,150	241,065	301,332	385,705
Medium HI > 120 MW & ≤ 300 MW	292,200	321,421	401,776	514,273
Small HI > 50 MW & ≤ 120 MW	401,776	441,953	552,442	707,125
Renewable HI ≤ 50 MW	657,451	723,196	903,995	1,157,114

The price for generated energy was set at Ps. 465/MWh beginning in September 2022, Ps. 512/MWh beginning in December 2022, Ps.639/MWh beginning in February 2023 and Ps.818/MWh beginning in August 2023. The price for operated energy was set at Ps.185/MWh beginning in September 2022, Ps.204/MWh beginning in December 2022, Ps.255/MWh beginning in February 2023 and Ps.326/MWh beginning in August 2023.

The prices of the generated energy in the 5 peak hours (from 6 pm to 11 pm) will be equivalent to their price, applying the following factors:

Period	Factor
Summer (Dec-Feb) and winter (Jun-Aug) in general	2.0
Others (Mar-May & Sep-Nov) in general	1.0

Other Considerations

For energy generated from an unconventional source, a single remuneration was set, of Ps. 1,680/MWh until January 2021, Ps. 2,167/MWh beginning in February 2021, Ps. 2,817 $/MWh beginning in February 2022 and PS. 3,099 $/MWh beginning in June 2022. On the other hand, Resolution SE No. 826/22 set new values as of November 2022, December 2022, February 2023 and August 2023 at Ps. 3,719 MWh, Ps. 4,090 MWh, Ps. 5,113 MWh and Ps. 6,545 MWh, respectively. In all cases, remuneration is reduced by 50% for energy generated before commissioning.

Temporary Additional Remuneration

On November 2, 2021, Resolution SE No. 1.037/21 established: (i) a WEM stabilization fund in which the income from CAMMESA’s electricity export operations will be transferred to finance energy infrastructure works; and (ii) an additional and transitory remuneration for spot market generators in consideration of CAMMESA’s electricity exports between September 1, 2021 and February 28, 2022.

On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that the generators included under the abovementioned scheme have a use factor of 70%, for which 100% of the power remuneration would be settled and an additional amount equivalent to Ps. 1,000/MWh of exported energy will be paid in proportion to the energy generated by each generator in such month. This remuneration was repealed by SE Resolution 238/22 beginning in February 2022.

Differential Remuneration for Conventional Energy

SE Resolution No. 1,281/06: Energy Plus Program

In September 2006, the SEE issued Resolution No. 1281/2006 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:

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· 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 into 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.

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).

For information about our projects aimed at taking advantage of Energía Plus Program. See “—Our Business—Our Generation Business.”

WEM Supply Agreements under SE Resolution No. 220/2007

Aiming to modify the market conditions to encourage new investments and increase the generation supply, the SE passed Res. 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 CT Barragan’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 CT Barragan’s vapor turbine, are remunerated under this scheme.

WEM Supply Agreements under SEE Res. 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 Res. 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 2016/2017 summer, 2017 winter, and 2017/2018 summer periods. Awarded bidders entered into PPAs for a fixed price (in US$/MW-month) and a variable price excluding fuels (in US$/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 Res. 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.

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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 Res. No. 820/17 awarding only three co-generation projects for a 506 MW power capacity, and, in October 2017, pursuant to Res. No. 926/17, it awarded projects for a total 1,304 MW power capacity, where Pampa was awarded with Genelba 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. 354/2020 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.

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 USD 2000/MW-months and the dollarization of energy prices (USD 3.5/MWh for natural gas and USD 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 Res. 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.

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 meet 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 US$113/MWh.

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.

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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), including our 100 MW PEMC project in the Province of Buenos Aires, which was commissioned for service in June 2018. 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 regime 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 17,500 US$/MW for wind and solar projects and 12,500 US$/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. 165/2023 (“Resolution 165”) amended Article 1 of SE Resolution No. 285/2018 (previously amended by SE Resolution No. 742/2021), 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. 202/2016.

On April 25, 2023, SE Resolution No. 284/2023 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 US$ 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.  

RenMDI Program

On February 2, 2023, the SE issued Resolution No. 36/23, which opened a national and international bidding process to select renewable energy generation projects in order to: (i) substitute forced generation (Line 1) and (ii) diversify the energy matrix (Line 2). The bidding terms establish a maximum capacity to be awarded of 500 MW and 120 MW for Lines 1 and 2, respectively. Line 1’s capacity will be distributed in 6 regions, while Line 2’s capacity will cover the entire national territory. The projects under Line 2 are not eligible to obtain dispatch priority.

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The projects will be remunerated by an energy supply contract with CAMMESA with a term of 15 years beginning on the date of entry into commercial operations of the project. Until such date, the bidder must comply with a periodic payment scheme (initial payment and quarterly payments) that will be destined to a special account (managed by CAMMESA)for the expansion of the transmission system. According to the schedule, the deadline for submitting bids was April 27, 2023.

MAT ER

ME&M Resolution No. 281/17 issued on August 18, 2017 regulated the MAT ER 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 MAT ER 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 MAT ER 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 MAT ER 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 and IV projects with the RENPER. We also requested the corresponding priority dispatch under ME&M Resolution No. 281/17, which was granted for the whole 160 MW installed capacity of the three projects.

Regarding the PEPE IV project, even though it was announced on May 23, 2018, the volatility of the economy and changes in the applicable legislation adversely affected the project (for more information, please see “Our Generation Business”).

In October 2021, Pampa obtained dispatch priority for PEPE III’s expansion project for 36 MW out of the total 81MW. The Company estimates to obtain dispatch priority for the remaining capacity in future rounds.

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 be made according to the extension of time and the completion of the work. During the committed term a 500 US$/MW quarterly payment applies. In case of an extension for an additional 180 calendar days with work completed by least 60% the payments will continue to be quarterly and for a 500 US$/MW amount. If the work is completed by less than 60% the payments will be on a monthly basis. For an extra extension of 360 calendar days the payments will raise to 1500 US/MW monthly.

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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. Compensations: 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 each 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. 148/2020 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 Resolution No. 31/2020. For more information, please see (“—The emergence and spread of a pandemic-level disease or threat to public health, such as Covid-19, may have a material adverse impact on the Argentine and global economy, our business operations, financial condition or results of operations”).

Moreover, Law No. 27,591 and SE Resolution No. 40/2020 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.

Oil & Gas Regulatory Framework

The Argentine Hydrocarbons Law

On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319, which considered new drilling techniques in the industry and mainly introduced changes to terms and extensions of exploration permits and exploitation concessions, levies and royalty rates, the incorporation of concepts for on and off-shore unconventional exploration and exploitation, and a promotion regime pursuant to Decree No. 929/13, among others. The main changes introduced by Law No. 27,007 are detailed below:

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Unconventional Hydrocarbons Exploitation

The Law conferred legal status to the concept of “Unconventional Hydrocarbon Exploitation Concession” 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 an unconventional hydrocarbon exploitation concession 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 an unconventional hydrocarbon exploitation concession. 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.

· Holders of an unconventional hydrocarbon exploitation concession that are also holders of a preexisting and adjacent exploitation concession may request the unification of both blocks as a single unconventional hydrocarbon exploitation concession, provided they duly demonstrate the geological continuity of these blocks. Such request should be based on the development of a pilot plan.

Terms for Exploitation Concessions and Permits

The terms for the exploration permits will be established in each tender issued by the enforcement authority according to the exploration’s purpose (conventional or unconventional):

i. Conventional exploration: the basic term is divided into two periods of up to three years each, plus an optional extension of up to five years. In this way, the maximum extension for exploration permits is reduced from fourteen to eleven years;

ii. Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years, that is, up to a maximum of 13 years; and

iii. On and off-shore exploration: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

Upon the expiration of the first period of the basic term, the permit holder will decide whether to continue exploring the block or to transfer it back in whole to the Government. The whole originally-granted block may be kept provided the obligations arising from the permit have been appropriately met. Upon the expiration of the basic term, the holder of the exploration permit will revert the whole block, unless it exercises its right to extend the period, in which case the reversion will be limited to 50% of the remaining block.

Exploitation concessions will be granted for the following terms, which will be computed as of the granting resolution’s date:

i. Conventional exploitation concession: 25 years;

ii. Unconventional exploitation concession: 35 years; and

iii. Continental shelf and off-shore exploitation concession: 30 years.

Moreover, the holder of an exploitation concession may, with a minimum one-year notice before the concession’s expiration, request indefinite extensions for a 10-year term each, provided that it has adequately met its obligations as exploitation concessionaire, hydrocarbons are produced in said block and files an investment plan consistent with the development of the concession.

Awarding of Areas

Law No. 27,007 proposes drafting of a standard bid form that will be jointly prepared by the SE and the provincial authorities, to which all calls for tenders launched by law enforcement authorities should adjust, and introduces specific criteria for the awarding of permits and concessions by incorporating the specific parameter of “greater investment or exploitation activity” as a tie-breaker, at the PEN or the Provincial Executive Branch’s duly justified discretion, as applicable.

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· Levies and Royalties

The amended Hydrocarbons Law updated the values related to the exploration and exploitation levy established by Decree No. 1,454/07; such values may, in turn, be generally updated by the PEN. The current values for each levy and royalty are detailed below.

- Levy

Law No. 27,007 set the levy values per km2 or fraction to be paid annually and in advance by the permit holder. The exploitation permit will amount to Ps.4,500. In contrast, for the exploration permit, the following values will apply: Ps.250 in the first period and Ps.1,000 in the second period of the basic term; and Ps.17,500 during the first year of the extension, with a 25% annual cumulative increase.

The amount payable for the second period of the basic term and the extension period may be readjusted by offsetting it with exploration investments made until reaching 10% of the levy per km2 applicable for the period.

On September 26, 2019, the Province of Neuquén published new levy values per km2 or fraction effective for such province beginning in 2020. The exploitation levy was set at Ps.22,410, and the exploration levy at Ps.1,245 for the first period, Ps.4,980 for the second period, Ps.7,470 for the third period, and Ps.87,150 for the extension period (Decree No. 2032/19).

As of 2021, Decree No. 771/20 set a maximum levy in Ps. equivalent to a certain volume of oil at the average domestic market price, at the Banco Nación’s FX rate effective last business day before payment. This scheme is applicable nationwide (including the Province of Neuquén). The exploitation concession amounts to 8.28 barrels. The exploration permit applies 0.46 barrels in the first period and 1.84 barrels in the second period of the basic term; and 32.22 barrels during the extension period.

Royalties

Royalties are defined as the only revenue the jurisdictions holding title to the hydrocarbons will collect, in their capacity as grantors, from the production of hydrocarbons.

The percentage that the exploitation concessionaire should pay on a monthly basis to the grantor as royalties remains at 12% of the proceeds derived from liquid hydrocarbons production extracted at the wellhead. The production of natural gas will bear a similar percentage of the value of extracted and actually used volumes and will be payable on a monthly basis. In the case of extension, up to 3% additional royalties’ payment is applicable upon the first extension but limited to an 18% rate.

For the conduction of hydrocarbon conventional exploitation complementary activities, beginning on the granted concession’s expiration and within the unconventional hydrocarbons’ exploitation concession, the enforcement authority may fix additional royalties of up to 3% above the current royalties, up to a maximum of 18%, as applicable.

The PEN or the Provincial Executive Branch, as applicable, acting in its capacity as granting authority, may reduce by up to 25% the amount corresponding to royalties applicable to the production of hydrocarbons during a term of 10 years after the conclusion of the pilot project in favor of companies requesting a hydrocarbon unconventional exploitation concession within a period of 36 months beginning on Law No. 27,007’s effective date.

- Extension Bond

For exploitation concession extensions, Law No. 27,007 empowers the enforcement authority to establish the payment of an extension bond, capped by the amount resulting from multiplying the remaining proven reserves at the expiration of the concession by 2% of the average basin price applicable to the specific hydrocarbon during a term of two years before the granting of the extension.

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- Exploitation Bond

The enforcement authority may establish the payment of an exploitation bond, capped by the amount resulting from multiplying the remaining proven reserves associated with the exploitation of conventional hydrocarbons at the expiration of the granted concession by 2% of the average basin price applicable to the specific hydrocarbons for the two years prior to the granting of the hydrocarbon unconventional exploitation concession.

- Transportation Concessions

Transportation concessions (so far granted for 35 years) will be granted for the same term granted for the originating exploitation concession, with the possibility of receiving subsequent extensions of up to 10 years each. Thus, transportation concessions originating in a conventional exploitation concession will have a basic 25-year term. In contrast, an unconventional exploitation concession will have a basic 35-year term, each in addition to any granted extension term. After these terms expire, title to the facilities will be transferred back to the Federal or Provincial Government, as applicable, by operation of law and without any charges or encumbrances.

- Uniform Legislation

Law No. 27,007 provides for two types of non-binding commitments between the Federal Government and the provinces regarding tax and environmental issues:

i. Environmental Legislation: Provides that the Federal Government and the provinces will seek to establish a uniform environmental legislation primarily aiming to apply the best environmental management practices to hydrocarbon exploration, exploitation and/or transportation with the purpose of furthering the development of the activity while properly protecting the environment.

ii. Tax System: Provides that the Federal Government and the provinces will seek to adopt a uniform fiscal treatment encouraging the development of hydrocarbon activities in their corresponding territories in adherence with the following guidelines:

· The gross receipts tax rate applicable to the extraction of hydrocarbons will not exceed 3%;

· The freezing of the current stamp tax rate and the commitment not to charge with it any financial contracts executed in order to structure investment projects, guarantee and/or warrant investments; and

· 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.

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.

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Law No. 27,007 extended the benefits of the Promotion Regime to hydrocarbon projects involving a minimum US$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 US$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 projects 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 US$250 million of foreign currency entering into the Argentine financial market.

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.

Regulations Specifically Applicable to the Gas Market

Plan Gas.Ar

According to Decree No. 892/20, on November 16, 2020, 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 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 US$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.

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.

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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 pay 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 75% 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.

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 AFIP. Such mechanism was regulated by SE Resolution No. 125/2021, which instrumented electronic certifications in foreign currency that producers may directly apply to fulfill fiscal liabilities in Plan Gas.Ar default by the Argentine Government. Moreover, the SE will be empowered to make the awardees’ guarantee enforceable before the AFIP. The AFIP 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 US$3.5/MBTU, as well as an additional volume of 3.6 million m³/day during the winter period at a price of US$4.7/MBTU. Pampa was awarded a base volume of 4.9 million m³/day at US$3.6 per million BTU and an additional volume of 1.0 million m³/day during the winter period at a price of US$4.7 per million BTU.

Moreover, Pampa was one of the three producers tendering additional volume during the winter period, being awarded 1 million m³/day for US$4.68 per million BTU. 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 US$250 million during the four years of 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 Resolution No. 129/2021, the SE called for a second round to award additional winter gas volumes at Neuquina and Austral Basins, 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 US$4.7 per MBTU, is to be delivered as of June 2021. Pampa participated in said round, being awarded 0.8 million m³/day at US$4.7 per MBTU. Additionally, the awarded companies will have to enter into a contract with ENARSA.

On October 19, 2021, through Resolution No. 984/2021, the SE launched the third round to award a total amount of 6 million m³/day of natural gas corresponding, 3 million m³/day at maximum price of US$3.66/MBTU for the Neuquina Basin, 2 million m³/day at maximum price of US$3.52/MBTU for the Austral Basin and 1 million m³/day at maximum price of US$3.577 MBTU for the Northwest Basin. This round is valid from May 1, 2022, to December 31, 2024.

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On November 12, 2021, the SE awarded a total of 3 million m³/day, corresponding to the Neuquén Basin at US$3.43/MTBU and the volumes of the Northwest and Austral Basins were declared void. Pampa was awarded a volume of 2 million m³/day at US$3.347/MTBU. 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. 730/2022 (hereinafter, “Decree 730”) was published. Pursuant to such decree, Gas.Ar Plan 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 Argentinean 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 Gas.Ar Plan 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 Néstor Kirchner gas pipeline (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 Energy Secretariat.

On November 14, 2022, Energy Secretariat Resolution No. 770 (hereinafter, “Res. 770”) was published. Pursuant to Res. 770, within the framework of the Assurance Plan, bidding rounds No. 4 (for Neuquen basin) and No. 5 (for Golfo San Jorge and Austral basins) were called.

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 Gas.Ar Plan 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 US$3.6/MBTU was awarded for Round 4.1 pursuant to Energy Secretariat Resolution No. 860 and, for Round 4.2, a total volume of 14 million m³/day at US$3.3/MBTU was awarded for July and January Peak Gas and a total volume of 14 million m³/day at US$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 US$3.5/MBTU.

Natural Gas for the Residential and CNG Segment

- Priority Demand and CEE

In June 2016, criteria were established to guarantee the Priority Demand's meeting through the CEE in case of operational emergencies that may affect its regular operation (MEyM Res. No. 89/16, as amended). In June 2017, the procedure for the administration of dispatch in the CEE was approved (ENARGAS Res. No. 4502/17). If the CEE did not reach an agreement, ENARGAS defines the required supply considering each producer’s available quantities, deducting the amounts previously contracted to meet the Priority Demand, with a progressive allocation until matching the proportional quota of each producer/importer in the Priority Demand.

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- 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-2 September 2019) and summer (October 2019-April 2020), respectively, at an average tender price of US$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 US$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 Res. 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. added to the tariff freeze (Social Solidarity and Productive Reactivation Law), beginning in April 2020 pricing agreements began to be based on the range recognized by ENARGAS in the tariff schemes.

In December 2020 the tender under 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 US$3.5/MBTU, and an additional winter volume of 3.6 million m³/day was awarded at an average annual base price of US$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 Res. No. 354/20, the reference price at the PIST was set for natural gas production out of Plan Gas.Ar, at US$2.30/MBTU in the summer (October – April) and US$3.50/MBTU in the winter (May – September) for the Neuquina Basin.

On August 2, 2022, SE issued Resolution No. 610/2022 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. 332/2022.

In the case of ENARSA, it has to pay 100% of the price awarded in Gas.Ar Plan. 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 Gas.Ar Plan. It is worth mentioning that, through Energy Secretariat Resolution No. 610/2022, 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 Res. No. 6/2023 was published. Pursuant to such resolution, natural gas PIST prices for contracts executed within the framework of Gas.Ar Plan and the Assurance Plan were adapted to the different types of users.

· Natural Gas for Power Generation

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From December 30, 2019, the fuel supply for power plants was again centralized in CAMMESA (except for generators under Energía Plus and SEE Res. 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 Plan Gas.Ar for the volumes committed under this program over a term of 4 years. Generators covered by Energía Plus and SEE Res. 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 2021 new reference PIST prices were set for production outside Plan Gas.Ar (SE Res. No. 354/20), of US$2.3/MBTU in the summer (October – April) and US$3.5/MBTU in the winter period (May – September) for the Neuquina Basin.

Therefore, in addition to Plan Gas.Ar, in 2021 CAMMESA continued calling for tenders monthly, at the maximum prices stated above, on an interruptible basis for Plan Gas.Ar’s awardees and under a 30% DoP clause for the rest. However, from September 2021, these calls were declared unawarded.

Moreover, from mid-July 2021, CAMMESA launched, on average, fortnightly calls for Plan Gas.Ar’s 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 US$3.4/MBTU (US$4.4/MBTU until September and US$2.9/MBTU onwards). After the closing of 2021, an average of 22.1 million m³/day was awarded at US$2.9/MBTU.

· Natural Gas Export

The procedure for the authorization of natural gas exports established by SGE Res. No. 417/19 —with the security of supply to the Argentine domestic market being a condition in all cases— was in effect until the end of April 2021. It is worth mentioning that the exported volume did not qualify for calculating the incentive for domestic production increase encouragement programs.

In November 2020, Pampa was granted permits to export gas, on an interruptible basis, to different customers in Chile; these permits expired between April 2021 and January 2022.

On April 27, 2021, a new procedure to authorize natural gas exports was implemented (SE Res. 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 May and December 2021, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m³/day and 1.22 million m³/day for the October 2021 – April 2022 and January – April 2022 periods, respectively. In addition, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were added, with expirations between November 2022 and December 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 as long as the international Brent price was equal to or below US$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 US$60/bbl. In 2021, the rate remained at 8%, except for January (3.1%) and February (5.7%).

On November 17, 2022, SR Res. Nº 774 (Res. SE N° 774/22) was published in lieu of SE N° 360/21. The new procedure defines 3 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; (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 Energy Secretariat and the average awarded price adjusted by seasonal index. For the period May-June 2023, the minimum price is equivalent to 7.73 USD/Mmbtu. 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 Gas.Ar and/or Assurance Plan contracts with CAMMESA and/or ENARSA is also allowed.

Program for Access to Foreign Currency for Oil and Gas Incremental Production

On May 28, 2022, Decree Nº 277 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 3 years) by means of future auctions within the framework of Gas.Ar Plan.

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 Free Exchange Market (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.

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. 484/2022 regulating DNU 277 was published. On January 16, 2023, Energy Secretariat 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 277. On February 9, 2023, Pampa filed the request to enroll in RADPIP and RADPIGN programs and applied for the benefit corresponding to the third and fourth quarters of 2022.

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.

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· Liquid Hydrocarbons Export Duty

The 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 US$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 US$60/bbl. As of the date of this annual report, the rate amounts to 8%.

Midstream

· 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 is determined by the SRH, which set a price of Ps. 9,895/ton for butane and Ps. 9,656/ton for propane beginning on July 1, 2019 (SHC Provisions No. 104/19). Later, prices were updated to Ps. 10,885/ton for both products effective as of October 19, 2020 (SE Resolution No. 30/20). Consequently, the participation in this program forces TGS to produce and sell LPG at prices ostensibly lower than market prices, which entails adopting the necessary mechanisms to minimize its negative impact.

With respect to the Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids, on May 30, 2018, TGS executed the 16th extension to the agreement, which set a new methodology for the determination of the price and volumes to be sold under this program for the April 1, 2018 -December 31, 2019 period. On January 14, 2020 TGS received the SE’s instruction to proceed with the deliveries pursuant to such extension. On August 25, 2020, TGS executed the seventeenth extension to the Propane for Grids Agreement, effective until December 31, 2020. As of the date of release of this Annual Report, this program has not been postponed.

Both the Household Gas Bottles’ Program and the Propane for Grids Agreement provide for a compensation payable by the Federal Government to participants, which is calculated as the difference between the sale price under such agreement and the export parity published by the SRH on a monthly basis, although with significant delays in collection terms.

- Natural Gas Import Financing Charges

Regarding Res. I-1,982/11 and I-1,991/11 issued by ENARGAS, 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 US$ 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 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 US$45/bbl, rising gradually as the reference price increases up to 8%, the cap to be recognized when the Brent equals or exceeds US$60/bbl. As of the date of this annual report, the rate amounts to 8%.

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· Regulations Specifically Applicable to Crude Oil Transportation

In June 2016, Oldelval requested the performance of the RTI to the MEyM as tariffs were insufficient to develop a maintenance and investment plan that may guarantee the integrity, efficiency and reliability of the facilities and transportation service. Consequently, on March 10, 2017, a new US$-denominated tariff scheme was published, providing for an average 34% increase, effective for a term of 5 years beginning in March 2017 (MEyM Res. No. 49/17). In November 2018 Pampa divested 21% of Oldelval’s capital stock to ExxonMobil Exploration Argentina S.R.L, keeping a 2.1% equity interest in Oldelval.  

During 2022, Oldelval called for bids to award a contract of firm transportation of up to 36,000 m³/day for Allen- Puerto Rosales oil pipeline section in its capacity as holder of the national concession of liquid hydrocarbon transportation.

However, it received bids for a volume much higher than the one originally tendered, equal to a total volume of 130,752 m³/day, and as a result it decided to expand the original tendered volume and extend it to a total of 50,000 m3/day.

This whole volume was awarded, and contracts have already been executed to transport it, effective up to the end of the transportation concession (2037).

· 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.

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

Generation

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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.

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.

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 from contracts with customers in relation with technical assistance and administration services to related companies.

Factors Affecting Our Results of Operations

Our results of operations are principally affected by economic conditions and inflation 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 (for further information, please see "Risk Factors—Risks Relating to our Company—Climate change, energy transition and regulatory framework promoted for such purposes could affect our business, our results of operations and financial condition").

Argentine Economic Conditions and Inflation

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.

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

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	Year ended December 31,
	2022	2021	2020
Real GDP (% change)	5.9%	10.8%	(9.9)%
Nominal GDP (in millions of Ps.)	75,997,541	43,952,340	27,021,238
Real Consumption (% change)	12.7%	9.8%	(13.1)%
Real Investment (% change)	12.0%	41.9%	(13.0)%
Industrial Production (% change)	4.3%	16.3%	(7.6)%
Consumer Price Index	94.8%	50.9%	36.1%
Nominal Exchange Rate (in Ps. /US$ at year end)	177.13	102.75	84.15
Exports (in millions of US$)	88,446	77,934	54,884
Imports (in millions of US$)	81,523	63,184	42,356
Trade Balance (in millions of US$)	6923	14,750	12,528
Current Account (% of GDP)	(0.9%)	1,3%	0.8%
Reserves (in millions of US$)	44.6	39.7	39.4
Tax Collection (in millions of Pesos)	21,540,626	11,906,731		7,237,410
Primary Surplus (in millions of Pesos)	(1,659,748)	(980,241)	(1,749,957)
Public Debt (% of GDP at December 31) *	74.1%	77.0%	104.5%
Public Debt Service (% of GDP)	2.0%	1.6%	2.0%
External Debt (% of GDP at December 31)	63.3%	62.7%	84.5%

Sources: INDEC; Central Bank; Ministry of Treasury.

*Includes hold-outs

Macroeconomic Context

As of the fourth quarter of 2020, the economic activity recorded an accumulated 9.9% decrease compared to the same period of the previous year, mainly as a result of the 13.1%, 4.7% and 13.0% decreases in private and public consumption, and investment, respectively. The activity contraction affected 14 out of 16 identified sectors of the Argentine economy, the most affected being hotels and restaurants (-49.2%), other community, social and personal activities (-39.9%), construction (-22.6%) and fishing (-20.9%), while financial brokerage and electricity, gas and water experienced a 2.1% and 0.9% increase, respectively. These declines were also partially offset by an increase in exports net of imports of 27.9%.

With regards to the evolution of prices, the National Cost of Living Index published by the INDEC showed a 36.1% variation in 2020. The most important variations were recorded in clothes and footwear (+60%), leisure and culture (+48.0%) and food and beverage (+42.1%). The sectors affected to a lower extent were communications (+7.6%), housing, water, electricity and other fuels (+17.6%) and education (+20.1%). Furthermore, salaries, as measured by the registry of the Stable Workers’ Average Taxable Remuneration (RIPTE) experienced a 34.9% year-on-year increase between December 2020 and the same month of the previous year.

Moreover, as of December 2020 the non-financial public sector’s fiscal accounts accumulated a 6.5% and 8.5% primary and total deficit to GDP, respectively. The annual variation in aggregated tax revenues, measured in Pesos based on figures published by the Federal Administration of Public Revenue, ended 2020 with a 32.2% increase compared to 2020. Additionally, in 2020 primary expenditures by the National Treasury showed a 63.5% year-on year variation.

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With respect to the financial situation, the Central Bank’s U.S. Dollar currency wholesale exchange rate (Res. A3500) closed at Ps.84.15/US$ on December 31, 2020, showing a cumulative 40.5% increase compared to the end of 2019 and a 46.3% average year-on-year variation. The Central Bank’s international reserves amounted to US$39.4 billion at year-end, which represents a US$5.5 billion decrease compared to the previous year. Moreover, the monetary base reached Ps.2,470 billion, showing an increase of 30.3% compared to the previous year. Furthermore, the Central Bank’s debt stock in issued bonds totaled an equivalent amount expressed in dollars of US$35.0 billion as of the closing of 2020, which represents a 97% year-on-year variation.

Finally, at the external level, as of the fourth quarter of 2020 the cumulative current account deficit amounted to US$12.5 billion according to INDEC’s data, which represents 1.5% of the GDP. During this period Free on Board (“FOB”) value exports reached US$54.9 billion, and Cost, Insurance and Freight value imports amounted to US$42.4 billion. Primary exports and agricultural exports decreased by 7.5% and 9.1% respectively during this period, while industrial manufactures exports experienced a 30.7% contraction. Fuel and energy exports experienced a decrease of 19.7%. Imports showed a contraction compared to the same period of 2019 in the automotive (-31.7%), capital goods (-13.0%), fuels and lubricants (-40.7%), consumables goods (-4.7%), parts and accessories (-25.0%) and intermediate goods (-2.1%).

As of the third quarter of 2021, economic activity recorded an accumulated 10.8% increase compared to the same period of the previous year, mainly due to the recovery to pre-pandemic levels, with an increase in private and public consumption and investments of 9.8%, 6.7%, and 41.9%, respectively. The economy recovered in 15 out of 16 identified sectors, the most dynamic ones being construction (+37.1%), manufacturing industry (+18.6%), wholesale and retail business and repairs (+15.5%), and real estate, business, and rental activities (+9.3%). These increases were partially offset by net imports of goods and services, against net exports for the same period in 2020.

Regarding the evolution of prices, the National Cost of Living Index published by the INDEC showed a 50.9% variation in 2021. The most important variations were recorded in restaurants and hotels (+65.4%), clothing and footwear (+64.6%), and transport (+57.6%). The sectors affected to a lower extent were housing, water, electricity utilities, and other fuels (+28.3%), communication (+35.8%), and general goods and services (+38.8%). Furthermore, salaries, as measured by the Stable Workers’ Average Taxable Remuneration (Remuneración Imponible Promedio de los Trabajadores Estables, RIPTE) registry, experienced a 53.4% year-on-year increase as of December 2021, compared to the same month of 2020.

Moreover, as of December 2021, non-financial public sector’s fiscal accounts accumulated a 3.2% and 4.8% primary and financial deficit to GDP, respectively. The annual variation in aggregated tax revenues, measured in Ps. based on figures published by the AFIP, ended with a 64.5% year-on-year increase. In addition, in 2021 primary expenditures recorded by the National Treasury showed a 49.6% year-on-year increase.

Regarding the financial situation, the BCRA’s US$ currency wholesale foreign exchange rate (Res. A3500) closed at Ps. 102.75/US$ on December 31, 2021, showing a cumulative 22.1% increase compared to the end of 2020 and an average 34.8% year-on-year increase. BCRA’s international reserves amounted to US$39.7 billion at year-end, which represents a US$0.3 billion increase compared to the previous year. Moreover, the monetary base reached Ps. 3,654 billion at the end of 2021, showing a 47.9% year-on-year increase. Furthermore, the BCRA’s debt stock in issued bonds totaled an equivalent amount expressed in dollars of US$49.1 billion as of the closing of 2021, which represents a 40.4% year-on-year increase.

Finally, on the external front, according to INDEC’s data, the cumulative current account surplus amounted to US$6.3 billion as of the third quarter of 2021, which represents 1.3% of the GDP. The trade balance surplus mainly accounts for this phenomenon: the FOB value of exports totaled US$58.3 billion, while the Cost, Insurance and Freight value of imports reached US$46.0 billion. Industrial and agricultural manufactures’ exports experienced a substantial 48.1% and 44.6% increase, respectively, followed by fuel and energy exports (+37.4%) and primary exports (+23.9%). Imports increased compared to the same period of 2020, explained by rises in fuels and lubricants (+92.5%), parts and accessories (+66.7%), intermediate goods (+55.6%), capital goods (+41.7%), automotive (+23.0%), and consumables (+18.7%).

As of the third quarter of 2022, economic activity recorded an accumulated 6.4% increase compared to the same period in 2021, driven by 10.7%, 3.2% and 14.6% increases in private and public consumption and investments, respectively. The activity recovery reached 15 out of 16 identified sectors of the economy, the most dynamic ones being transportation, warehousing and communications (+10.2%), wholesale and retail business and repairs (+7.5%), manufacturing industry (+6.4%) and real estate, business and rental activities (+5.6%). However, these increases were partially offset by higher net imports of goods and services, 23.5% higher than in the same period in 2021.

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Regarding the evolution of prices, the National Cost of Living Index published by the INDEC showed a 94.8% variation in 2022. The major variations were recorded in clothing and footwear (+120.8%), restaurants and hotels (+108.8%), and general goods and services (+97.8%). The sectors less affected were communication (+67.8%), housing, water, electricity utilities and other fuels (+80.4%), and leisure and culture (+83.2%). Furthermore, salaries, as measured by the registry of Stable Workers’ Average Taxable Remuneration (Remuneración Imponible Promedio de los Trabajadores Estables, RIPTE), experienced an 89.3% year-on-year increase as of December 2022, compared to the same month in 2021.

Moreover, as of December 2022, Non-Financial Public Sector’s fiscal accounts accumulated a 2.6% and 4.5% primary and financial deficit to GDP, respectively. The annual variation in aggregated tax revenues, measured in AR$ based on figures published by the AFIP, ended with an 80.9% year-on-year increase. Moreover, in 2022 primary expenditures recorded by the National Treasury showed a 70.5% year-on-year variation.

Regarding the foreign exchange situation, the BCRA’s US$ currency wholesale FX rate (Res. A3500) closed at Ps.177.13/US$ on December 31, 2022, showing a cumulative 72.4% increase compared to the end of 2021 and an average 37.5% year-on-year variation. BCRA’s international reserves amounted to US$44.6 billion at year-end, representing a US$4.9 billion increase compared to the previous year. Moreover, the monetary base reached Ps.5,204 billion at the end of 2022, showing a 42.4% year-on-year increase. In addition, the BCRA’s debt stock in issued bonds totaled an equivalent amount expressed in dollars of US$59.2 billion as of the closing of 2022, representing a 20.6% year-on-year increase.

Finally, on the external front, according to INDEC’s data, the cumulative current account deficit amounted to US$5.4 billion as of the third quarter of 2022, representing 0.9% of the GDP. This phenomenon is due to the fact that the small trade balance surplus could not offset the investment account deficit. The FOB value of exports totaled US$67.2 billion (+15.3%), while the Cost, Insurance and Freight (CIF) value of imports reached US$64.7 billion (+40.7%). Increased exports are explained by rises in fuels and energy (+65.4%), industrial manufactures (+20.2%), primary products (+11.2%) and agricultural manufactures (+7.4%). Increased imports are accounted for by increases in fuels and lubricants (+162.6%), parts and accessories (+32.5%), capital goods (+32.3%), intermediate goods (+25.7%), consumables (+25.5%) and automotive (+14.2%).

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. For more information about the electricity prices, please 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.

In 2022, electricity consumption increased by 3.6% compared 2021, mainly driven by the residential segment, with a total electricity demand volume of 138,755 GWh and 133,877 GWh for 2022 and 2021, respectively. The following chart shows the breakdown of electricity consumption in 2022 by type of customer:

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Electricity demand by type of customer

Peak Demand Records

	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022
Capacity (MW)	23,794	24,034	23,949	25,380	25,628	26,320	26,113	25,791	27,088	28,283
Date	23-Dec	20-Jan	27-Jan	12-Feb	24-Feb	8-Feb	29-Jan	4-Feb	29-Dec	6-Dec
Temperature (°C)	35.4	29.6	35.6	35.1	27.7	30.2	34.0	29.5	31.7	29.0
Hour	14:20	15:05	14:13	14:35	14:25	15:35	14:25	14:57	14:28	14:43

Source: CAMMESA.

On December 6, 2022, at 14:43, there was a 28,283 MW record-breaking demand for power capacity registered by the SADI, with a 29.0 ºC temperature.

During 2022, power generation experienced a 2% decrease, with 137,932 GWh and 141,261 GWh volumes for 2022 and 2021, respectively, mainly due to the lower thermal and nuclear dispatch on account of the decreased power grid availability. Unlike 2021, where net electricity exports were recorded, in 2022 the SADI was a net power importer.

Thermal power generation remained the main source to meet the demand, fired with natural gas, liquid fuels (GO and FO) and mineral coal. It supplied an electricity volume of 81,746 GWh (59%), followed by hydroelectric power generation, which contributed 29,377 GWh net of pumping (21%), renewable power generation with 19,340 GWh (14%) and nuclear power generation, with 7,469 GWh (5%). Additionally, there were imports for 6,310 GWh (vs. 819 GWh in 2021), exports for 31 GWh (vs. 3,850 GWh in 2021) and losses for 5,455 GWh (+25% vs. 2021).

Lower thermal (-8,329 GWh) and nuclear (-2,701 GWh) generation compared to 2021 was offset by higher hydroelectric power generation net of pumping (+5,797 GWh, mainly due to higher flows at Yacyretá and Salto Grande) and a higher contribution from renewable energy (+1,904 GWh). The following chart shows the evolution of electric power generation by source:

Generation by Type of Power Plant

In %, 2013 – 2022

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During 2022 generation facilities recorded a decrease in their installed capacity compared to the previous year, totaling 42,927 MW (-62.2 MW compared to 2021). This decrease was mainly due to the recategorization of La Plata Cogeneración (GT) from agent to self-generator (-128.0 MW) and the termination of diesel engine PPA (-14.4 MW), partially offset by the commercial commissioning of renewable units under RenovAr and MAT ER programs (+70.8 MW), including 18 MW from PEPE IV, and power capacity adjustments (+9.4 MW ). The chart below shows the composition of installed capacity in Argentina as of December 31, 2022:

Regarding fuel supply for power generation, beginning on December 30, 2019 and pursuant to MDP Resolution No. 12/19, fuel commercial management and supply was again centralized in CAMMESA, except for generators with contracts under Energía Plus and SEE Resolution No. 287/17. Additionally, following the implementation of Plan Gas.Ar, on December 2, 2020 SE Resolution No. 354/20 was published, which, among other measures, established an optional scheme for the operating assignment of natural gas and its transportation to CAMMESA effective as of January 2021 for such exempted generators. Pampa acceded to this scheme. This new scheme set a new thermal dispatch order centralized in CAMMESA, which prioritizes units supplied with gas imported from Bolivia under a ToP condition, followed by those supplied under Plan Gas.Ar and, lastly, those with gas assigned to CAMMESA.

As regards fuel consumption, in 2022, it reached 50.7 million m³/day of gas equivalent in 2022, a figure 7% lower than in 2021. The use of natural gas for power plants reached 38.9 million m³/day in 2022(-13% compared to 2021), 88% of which was local gas and 12% imported gas. However, alternative fuels (FO, GO and mineral coal) were used in volumes significantly higher than in 2021, especially during winter, to meet thermal energy demands. FO and GO grew by 49% and 20%, to 3.6 million and 6.8 million m³/day of gas equivalent, respectively, whereas mineral coal decreased by 10%, to 1.4 million m³/day of gas equivalent.

The chart below shows the fuel consumption by type:

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Beginning in August 2021, the approved maximum spot price for energy was Ps.930/MWh (SE Res. No. 748/21), later adjusted to Ps.1,682/MWh from November 2022 (SE Res. No. 719/22). However, the following chart shows the average monthly price that all electricity system users should pay so that the power grid would not run into a deficit. In addition to the energy price, this cost includes the power capacity fee, the generation cost, fuels such as natural gas, FO, GO and mineral coal, and other minor items.

Cost of sales

Our most significant costs of sales include purchases of inventory, energy and gas, personnel costs and property, plant and equipment depreciation.

Operating expenses

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

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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, 2021, as there is no available information for the year 2022:

Natural Gas

In 2022, total gross natural gas production amounted to 133 million m³ per day, 7% higher than in 2021. This variation is mainly due to Plan Gas.Ar at the Neuquina Basin (+11.1 million m³/day) and a slight increase at the Golfo San Jorge Basin (+0.4 million m³/day), partially offset by the decline in the Austral and Noroeste Basins (-3.0 million m³ per day).

Although total demand recorded a 2% year-on-year increase, there was again a deficit in local supply, evidenced since 2003. Therefore, the Federal Government resorted to natural gas imports and alternative fossil fuels. In 2022, Bolivia’s supply averaged 11 million m³ per day (-18% vs. 2021) and seaborne LNG at the Escobar and Bahía Blanca ports recorded 6 million m³per day (-35% vs. 2021). On the other side, natural gas exports grew by 121% compared to 2021, to a total of 5 million m³ per day, representing 4% of the total domestic production in 2022.

Based on the last annual information published by the SE, as of December 31, 2021, the country’s total natural gas reserves and resources amounted to 1,620 billion m³, 47% higher than in 2020. Of such natural gas reserves and resources, 26% were proven reserves, and 72% of total reserves were unconventional.

Crude Oil

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In 2022, total oil production totaled 93 thousand m³ per day, increased by 13% compared to 2021, mainly due to the upward trend in international reference prices. Moreover, in 2022, no oil imports were recorded for the second consecutive year. Additionally, in 2022, oil exports amounted to 17 thousand m³ per day, a volume 44% higher than in 2021. This volume represented 18% of the total domestic production in 2022.

As of December 31, 2021, the country’s oil reserves and resources totaled 1,518 million m³, a 82% increase compared to 2020, of which 30% were proven reserves and 60% are classified as unconventional.

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

Results of Operations

The table below provides a summary of our results of operations for the years ended December 31, 2022, 2021 and 2020.

Results of operations related to divested assets of distribution of energy segment, were disclosed within discontinued operations.

	For the year ended December 31,
	2022	2021	2020
Revenue	1,829	1,508	1,073
Cost of sales	(1,148)	(955)	(663)
Gross profit	681	553	410
Selling expenses	(56)	(33)	(26)
Administrative expenses	(138)	(99)	(93)
Other operating income	131	105	51
Other operating expenses	(46)	(58)	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(38)	(4)	(139)
Impairment of financial assets	(8)	(2)	(9)
Share of profit from associates and joint ventures	105	117	85
Operating income	631	579	243
Finance income	5	10	9
Finance costs	(221)	(185)	(177)
Other financial results	166	(14)	84
Financial results, net	(50)	(189)	(84)
Profit before income tax	581	390	159
Income tax	(124)	(77)	(35)
Profit for the year from continuing operations	457	313	124
Loss for the year from discontinued operations	-	(75)	(592)
Profit (Loss) of the year	457	238	(468)
Total Profit (Loss) of the year attributable to:
Owners of the Company	456	273	(367)
Non - controlling interest	1	(35)	(101)

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	For the year ended December 31,
	2022	2021	2020
Revenue
Generation	663	656	559
Oil and gas	646	453	294
Petrochemical	617	490	267
Holding and others	20	22	20
Eliminations	(117)	(113)	(67)
Total Revenue	1,829	1,508	1,073
Gross profit
Generation	293	301	305
Oil and gas	287	164	51
Petrochemical	81	66	34
Holding and others	20	22	20
Eliminations	-	-	-
Total Gross profit	681	553	410
Operating income
Generation	336	350	241
Oil and gas	194	130	(27)
Petrochemical	52	45	6
Holding and others	49	54	23
Eliminations	-	-	-
Total operating income	631	579	243
Total profit (loss) of the year
Generation	254	219	139
Distribution of energy	-	(75)	(592)
Oil and gas	45	22	(53)
Petrochemical	40	28	6
Holding and others	118	44	32
Eliminations	-	-	-
Total profit (loss) of the year	457	238	(468)
Total profit (loss) attributable to owners of the company
Generation	253	218	147
Distribution of energy	-	(39)	(499)
Oil and gas	45	22	(53)
Petrochemical	40	28	6
Holding and others	118	44	32
Eliminations	-	-	-
Total profit (loss) attributable to owners of the company	456	273	(367)
Total profit (loss) attributable to non - controlling interest
Generation	1	1	(8)
Distribution of energy	-	(36)	(93)
Total profit (loss) attributable to non - controlling interest	1	(35)	(101)

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We are a fully integrated power company in Argentina that participates in the electricity and oil and gas value chains.

Through our own activities, subsidiaries and shareholdings in joint ventures and based on the business nature, customer portfolio and risks involved, we were able to identify the following reportable business segments:

· Generation, consisting of our direct and indirect interests in HINISA, HIDISA, Greenwind, VAR, CTB, TMB, TJSM and through our own electricity generation activities through thermal plants Güemes, Piedra Buena, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picun Leufu hydroelectric complex and Pampa Energía II, III and IV wind farms. It is worth highlighting that the results of the segment’s operations reflect the effects of the consolidation with Greenwind and VAR as of August 12, 2022 and December 16, 2022, respectively;

· Oil and Gas, consisting of our own interests in oil and gas areas and through our direct and indirect interests in CISA;

· Petrochemicals, comprised of our own styrene operations and the catalytic reformer plant operations conducted in Argentine plants; and

· Holding and Other Business, principally consisting of our interests in joint businesses CITELEC and CIESA and their respective subsidiaries, which hold the concession over the high-voltage electricity transmission nationwide and over gas transportation in the south of the country, respectively, our interest in the associates OCP and Refinor (until its divestment), holding activities and financial investment transactions.

We manage our operating segments based on their individual net profit.

Fiscal year ended December 31, 2022 compared to the fiscal year ended December 31, 2021

Generation Segment

	Generation
	December 31, 2022			December 31, 2021			Variation			%
Revenue		663			656			7			1	%
Cost of sales		(370	)		(355	)		(15	)		4	%
Gross profit		293			301			(8	)		(3	%)
Selling expenses		(3	)		(2	)		(1	)		50	%
Administrative expenses		(39	)		(31	)		(8	)		26	%
Other operating income and expenses, net		20			37			(17	)		(46	%)
Share of profit from joint ventures		65			47			18			38	%
Impairment of property, plant and equipment, intangible assets and inventories		—			(2	)		2			(100	%)
Operating income		336			350			(14	)		(4	%)
Finance income		1			4			(3	)		(75	%)
Finance costs		(82	)		(46	)		(36	)		78	%
Other financial results		72			(14	)		86			(614	%)
Financial results, net		(9	)		(56	)		47			(84	%)
Profit before income tax		327			294			33			11	%
Income tax		(73	)		(75	)		2			(3	%)
Profit of the year		254			219			35			16	%
Owners of the company		253			218			35			16	%
Non - controlling interest		1			1			—			—

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Revenue

Revenue from our generation segment increased 1%, to US$663 million for the fiscal year ended December 31, 2022, compared to US$656 million for the previous fiscal year. This variation is mainly explained by: (i) higher spot energy sales due to price updates pursuant to SE Resolutions 238/22 and 826/22, (ii) higher volumes and prices due to an increase in Energy Plus market demand, and (iii) the consolidation of Greenwind revenue beginning on August 12, 2022. This was partially offset by PPA contracts maturity at CTLL and CTP in November 1 and July 25, 2021, respectively, leading to spot market sales.

Power generation during the fiscal year ended December 31, 2022, increased by 5% (878 GWh) compared to the fiscal year ended December 31, 2021, due to thermal units’ higher dispatch, mainly in CPB, CTLL and CTEB, partially offset by reduced generation in CTGEBA, CTG and HPPL.

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

	Fiscal year ended
	December 31, 2022		December 31, 2021
In GWh	Net generation	Total sales	Net generation	Total sales
Hydroelectric
HINISA	428	428	467	467
HIDISA	303	303	325	325
HPPL	707	707	550	550
Wind
PEMC	391	391	367	367
PEPE II	231	256	215	247
PEPE III	249	250	256	256
PEPE IV	0	-	-	-
VAR	17	-	-	-
Thermal
CTLL	5,103	5,103	4,682	4,692
CTG	225	469	392	624
CTP	52	52	53	53
CPB	1,209	1,209	312	313
CTPP	321	321	299	299
CTIW	308	308	301	300
CTGEBA	7,746	8,571	8,594	9,266
EcoEnergía	73	152	75	153
CTEB	948	948	546	546
Total	18,311	19,468	17,433	18,458

Cost of Sales

Cost of sales increased by 4%, to US$370 million for the fiscal year ended December 31, 2022, compared to US$355 million for the fiscal year ended December 31, 2021, mainly due to an increase in gas purchases, higher labour costs (which surpassed the AR$ devaluation rate), and expenses for seasonal maintenance works and repairs.

Gross Profit

Gross profit from our generation segment did not experience a significant variation, amounting to US$293 million for the fiscal year ended December 31, 2022, compared to US$301 million for the fiscal year ended December 31, 2021.

Moreover, in the fiscal year ended December 31, 2022, the gross margin in relation to sales decreased to 44%, compared to 46% for the fiscal year ended December 31, 2021.

Selling Expenses

Selling expenses from our generation segment did not vary significantly, amounting to US$3 million for the fiscal year ended December 31, 2022, compared to US$2 million for the fiscal year ended December 31, 2021.

Administrative Expenses

Administrative expenses from our generation segment increased to US$39 million for the fiscal year ended December 31, 2022, compared to US$31 million for the fiscal year ended December 31, 2021, mainly explained by higher labour costs (which surpassed the AR$ devaluation) and higher expenses on fees and compensation for services.

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Other Operating Income and Expenses Net

Other operating income and expenses, net from our generation segment decreased 46%, to a US$20 million gain for the fiscal year ended December 31, 2022, compared to a US$37 million gain for the fiscal year ended December 31, 2021. This decrease is mainly due to the provision recovery for Parque Eólico Las Armas´s guarantee in 2021.

Share of profit from joint ventures

The share of profit from joint ventures from our generation segment increased to US$65 million for the fiscal year ended December 31, 2022, a 38% increase compared to the US$47 million registered for the fiscal year ended December 31, 2021. This increase is mainly explained by the recognition of a US$23 million gain as a result of the acquisition of the additional 50% stake in Greenwind, to reflect the fair value of the 50% previous stake held. This effect was partially offset by lower profits from CTB mainly due to PPA contract maturity.

Impairment of property, plant and equipment, intangible assets and inventories

No generation segment’s charges for impairment of property, plant and equipment and intangible assets were recorded for the fiscal year ended December 31, 2022, compared to a US$2 million loss for impairment of property, plant and equipment, intangible assets and inventories for the fiscal year ended December 31, 2021.

Operating Income

Operating income from our generation segment decreased by US$14 million (a 4% decrease), recording a gain of US$336 million for the fiscal year ended December 31, 2022, compared to a gain of US$350 million for the fiscal year ended December 31, 2021. This variation was mainly attributable to: (i) lower sales due to PPA contract maturity in CTLL and CTP during 2021, (ii) gains from provision recovery recorded during 2021, and (iii) higher labour costs and maintenance expenses in 2022. These effects were partially offset by higher spot and Energy Plus sales, and the impact of Greenwind’s additional stock acquisition and consolidation.

The operating margin in relation to sales for the fiscal year ended December 31, 2022, decreased to 51% compared to a 53% operating margin for the fiscal year ended December 31, 2021.

Financial Results, net

Financial results, net, amounted to a US$9 million loss for the fiscal year ended December 31, 2022, compared to a US$56 million loss for the fiscal year ended December 31, 2021. This variation is mainly due to higher gains from changes in the fair value of financial instruments, partially offset by higher financial interest expenses and exchange differences losses, net.

Income Tax

The generation segment recorded an income tax charge of US$73 million for the fiscal year ended December 31, 2022, compared to US$75 million for the fiscal year ended December 31, 2021.

Total Profit

The generation segment recorded a US$254 million profit for the fiscal year ended December 31, 2022, of which US$253 million was attributable to the owners of the Company, compared to a US$219 million profit for the fiscal year ended December 31, 2021, of which US$218 million was attributable to the owners of the Company.

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Oil and Gas Segment

	Oil and Gas
	December 31, 2022			December 31, 2021			Variation			%
Revenue		646			453			193			43	%
Cost of sales		(359	)		(289	)		(70	)		24	%
Gross profit		287			164			123			75	%
Selling expenses		(36	)		(18	)		(18	)		100	%
Administrative expenses		(60	)		(46	)		(14	)		30	%
Other operating income and expenses, net		35			30			5			17	%
Impairment of property, plant and equipment, intangible assets and inventories		(30	)		—			(30	)		(100	%)
Impairment of financial assets		(2	)		—			(2	)		(100	%)
Operating income		194			130			64			49	%
Finance income		2			3			(1	)		(33	%)
Finance costs		(107	)		(103	)		(4	)		4	%
Other financial results		(28	)		(16	)		(12	)		75	%
Financial results, net		(133	)		(116	)		(17	)		15	%
Profit before income tax		61			14			47			336	%
Income tax		(16	)		8			(24	)		(300	%)
Profit of the period		45			22			23			105	%

Revenue

Revenue from our oil and gas segment amounted to US$646 million for the fiscal year ended December 31, 2022, which was 43% higher than the US$453 million for the fiscal year ended December 31, 2021. This variation is mainly explained by the increase in both export and domestic industry gas prices, higher gas production and higher oil sale volume and prices.

The average sale price for natural gas was US$4.2/BTU for the fiscal year ended December 31, 2022, 16% higher than US$3.6/BTU recorded in the fiscal year ended December 31, 2021, mainly explained by higher export and domestic industry prices. The average sale price for oil was US$69.6/bbl for the fiscal year ended December 31, 2022, 18% higher than average sale price for the fiscal year ended December 31, 2021, mainly due to higher international reference prices.

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The following table shows the production and sale volume for our oil and gas segment:

	For the fiscal period ended
	December 31, 2022		December 31, 2021
Production
Oil (k bbl/day)		5.3		4.7
Gas (k m3/day)		9,811		8,004
Total (k boe/day)		63.1		51.8
Sales
Oil (k bbl/day)		5.3		4.6
Gas (k m3/day)		9,842		8,122
Total (k boe/day)		63.3		52.4

Cost of Sales

The cost of sales from our oil and gas segment increased by 24%, to US$359 million for the fiscal year ended December 31, 2022, compared to US$289 million for the fiscal year ended December 31, 2021, mainly due to: (i) higher royalty charges in line with higher sales prices and volumes; (ii) higher maintenance and contractors charges in line with the increase in gas activity; (iii) higher property, plant and equipment depreciation and (iv) higher transportation and freight expenses.

Gross Profit

Gross profit from our oil and gas segment increased by 75%, from US$164 million in the fiscal year ended December 31, 2021, to US$287 million for the fiscal year ended December 31, 2022. This variation is mainly explained by higher gas exports and higher oil sale volume and prices. These effects were partially offset by increased costs, mainly royalties, maintenance and contractors in line with gas activity, and higher depreciation, transportation and freights charges.

Additionally, the gross margin on sales increased to 44% in the fiscal year ended December 31, 2022, compared to 36% for the fiscal year ended December 31, 2021.

Selling Expenses

Selling expenses from our oil and gas segment increased to US$36 million for the fiscal year ended December 31, 2022, compared to US$18 million for the fiscal year ended December 31, 2021 due to increase in exported gas transportation expenses.

Administrative Expenses

Administrative expenses from our oil and gas segment increased by 30%, amounting to US$60 million for the fiscal year ended December 31, 2022, compared to US$46 million for the fiscal year ended December 31, 2021, mainly due to higher labor costs (which surpassed the AR$ devaluation).

135 

Other Operating Income and Expenses, net

Other operating incomes and expenses, net from our oil and gas segment recorded a US$35 million gain for the fiscal year ended December 31, 2022, compared to a US$30 million gain for the fiscal year ended December 31, 2021, mainly due to the recognition of environmental remediation expenses on reverted oil areas in 2021 and higher Plan Gas.Ar government grants. This was partially offset by the investment plan’s readjustment bond at the Sierra Chata block.

Impairment of property, plant and equipment, intangible assets and inventories

An impairment of property, plant, equipment, intangible assets and inventories of US$30 million was recorded for Rincon del Mangrullo block for the fiscal year ended December 31, 2022, while no impairment charges were recorded for the comparative fiscal year.

Impairment of financial assets

Our oil and gas segment recorded an impairment of financial assets of US$2 million for the fiscal year ended December 31, 2022, while no impairment charges were recorded for the comparative fiscal year.

Operating Income

The operating income from our oil and gas segment increased to a US$194 million gain for the fiscal year ended December 31, 2022, compared to US$130 million for the fiscal year ended December 31, 2021. The variation is mainly explained by higher gas and oil prices and sale volumes, partially offset by increased operating costs and expenses and impairment of property, plant and equipment losses.

The operating margin in relation to sales for the fiscal year ended December 31, 2022, increased to 30% compared to a 29% operating margin for the fiscal year ended December 31, 2021.

Financial Results, Net

Financial results, net from our oil and gas segment amounted to US$133 million loss for the fiscal year ended December 31, 2022, compared to US$116 million loss for the fiscal year ended December 31, 2021, mainly due to higher exchange differences, net losses, corporate bonds exchange losses in 2022 and higher financial interest expenses. These effects were partially offset by lower losses from changes in the fair value of financial instruments.

Income Tax

Our oil and gas segment recorded an income tax charge of US$16 million for the fiscal year ended December 31, 2022, compared to an income tax benefit of US$8 million for the same period in 2021, mainly due to higher profits before tax and losses related to fiscal inflation adjustment in 2022.

Total Profit

Our oil and gas segment recorded a profit of US$45 million for the fiscal year ended December 31, 2022, compared to a US$22 million profit for the prior fiscal year, both of which are entirely attributable to the owners of the Company.

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Petrochemicals Segment

	Petrochemical
	December 31, 2022			December 31, 2021			Variation			%
Revenue		617			490			127			26	%
Cost of sales		(536	)		(424	)		(112	)		26	%
Gross profit		81			66			15			23	%
Selling expenses		(17	)		(13	)		(4	)		31	%
Administrative expenses		(5	)		(4	)		(1	)		25	%
Other operating income and expenses, net		(5	)		(2	)		(3	)		150	%
Impairment of property, plant and equipment, intangible assets and inventories		(2	)		(2	)		—			—
Operating income		52			45			7			16	%
Finance costs		(3	)		(3	)		—			—
Other financial results		6			(2	)		8			(400	%)
Financial results, net		3			(5	)		8			(160	%)
Profit before income tax		55			40			15			38	%
Income tax		(15	)		(12	)		(3	)		25	%
Profit of the period		40			28			12			43	%

Revenue

Revenue from our petrochemicals segment amounted to US$617 million for the fiscal year ended December 31, 2022, 26% higher than the US$490 million reported for the fiscal year ended December 31, 2021. This variation is mainly due to a substantial improvement in domestic and international reference prices.

Total sold volumes were similar for both fiscal years ended December 31, 2022 and 2021.

The following table shows sales volumes in the petrochemicals segment:

	For the fiscal period ended
Volume sold in k ton	December 31, 2022		December 31, 2021
Reforming		114		114
Styrene & polystyrene		46		49
SBR		262		254
Total		421		417

Cost of Sales

Cost of sales from our petrochemicals segment increased by 26%, to US$536 million for the fiscal year ended December 31, 2022, compared to US$424 million for the fiscal year ended December 31, 2021. This variation is mainly due to higher raw material costs (driven by an increase in international reference prices).

Gross Profit

Our petrochemical segment gross profit increased by 23% to US$81 million for the fiscal year ended December 31, 2022, compared to US$66 million for the same period in 2021, mainly due to the increase in international reference prices for reforming products, partially offset by lower gross margin from synthetic rubber and polystyrene margins.

The gross margin on sales reached 13% for both fiscal years ended December 31, 2022 and 2021.

Selling Expenses

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Selling expenses from our petrochemicals segment amounted to US$17 million for the fiscal year ended December 31, 2022, compared to US$13 million for the fiscal year ended December 31, 2021. The variation is mainly explained by higher tax expenses, transportation charges and fees and compensation for services.

Administrative Expenses

Administrative expenses from our petrochemicals segment did not experience significant variation, amounting to US$5 million for the fiscal year ended December 31, 2022, compared to US$4 million for the fiscal year ended December 31, 2021.

Other Operating Income and Expenses, net

Other operating income and expenses, net, recorded a US$5 million loss for the fiscal year ended December 31, 2022, compared to US$2 million loss for the fiscal year ended December 31, 2021. The increase is mainly due to scheduled maintenance shutdowns and unavailability of raw materials.

Impairment of property, plant and equipment, intangible assets and inventories

Our petrochemical segment recorded an impairment of property, plant and equipment, intangible assets and inventories of US$2 million for both fiscal years ended December 31, 2022, and 2021.

Operating Income

The operating income from our petrochemicals segment increased to US$52 million for the fiscal year ended December 31, 2022, compared to US$45 million for the fiscal year ended December 31, 2021. This variation is mainly due to reforming products’ higher gross margin, partially offset by higher operating expenses.

The operating margin in relation to sales for the fiscal year ended December 31, 2022, amounted to 8% compared to a 9% operating margin for the fiscal year ended December 31, 2021.

Financial Results, Net

Our petrochemicals segment recorded a net financial profit of US$3 million for the fiscal year ended December 31, 2022, compared to a US$5 million net loss for the fiscal year ended December 31, 2021. The variation is mainly due to higher net exchange differences gains and losses from changes in the fair value of financial instruments recorded in 2021.

Income Tax

Our petrochemicals segment recorded income tax charge of US$15 million for the fiscal year ended December 31, 2022, compared to US$12 million for the fiscal year ended December 31, 2021, mainly as a result of higher pre-tax profits.

Total profit

The petrochemicals segment recorded a total profit of US$40 million for the fiscal year ended December 31, 2022, compared to US$28 million for the fiscal year ended December 31, 2021, both of which are entirely attributable to the owners of the Company.

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Holding and Others Segment

	Holding and others
	December 31, 2022			December 31, 2021			Variation			%
Revenue		20			22			(2	)		(9	%)
Gross profit		20			22			(2	)		(9	%)
Administrative expenses		(34	)		(18	)		(16	)		89	%
Other operating income and expenses, net		35			(18	)		53			(294	%)
Share of profit from associates and joint ventures		40			70			(30	)		(43	%)
Impairment of property, plant and equipment, intangible assets and inventories		(6	)		—			(6	)		(100	%)
Impairment of financial assets		(6	)		(2	)		(4	)		200	%
Operating income		49			54			(5	)		(9	%)
Finance income		9			4			5			125	%
Finance costs		(36	)		(34	)		(2	)		6	%
Other financial results		116			18			98			544	%
Financial results, net		89			(12	)		101			(842	%)
Profit before income tax		138			42			96			229	%
Income tax		(20	)		2			(22	)		(1,100	%)
Profit of the year		118			44			74			168	%

Revenue

Revenue from our holding and others segment experienced no significant variation, recording US$20 million and US$22 million for the fiscal years ended on December 31, 2022 and 2021, respectively.

Administrative Expenses

Administrative expenses from our holding and others segment increased to US$34 million for the fiscal year ended December 31, 2022, compared to US$18 million for the fiscal year ended December 31, 2021, mainly due to higher compensation agreements expenses.

Other Operating Income and Expenses, Net

Other operating income and expenses, net from our holding and others segment recorded a US$35 million gain for the fiscal year ended December 31, 2022, compared to a US$18 million loss for the fiscal year ended December 31, 2021. The variation is mainly attributable to the arbitration award of US$37 million regarding the arbitration claim in Ecuador and higher contingency charges recorded in 2021.

Share of profit from associates and joint ventures

The profit from joint ventures from our holding and others segment decreased to US$40 million for the fiscal year ended December 31, 2022, compared to US$70 million for the fiscal year ended December 31, 2021. This variation is mainly explained by impairment losses in Refinor since the sale price was below the book value, and the profit recorded in 2021 related to the acquisition of an additional participation in OCP.

Impairment of property, plant and equipment, intangible assets and inventories

Our holding and others segment recorded an impairment of property, plant and equipment, intangible assets and inventories of US$6 million for the fiscal year ended December 31, 2022, while no charges were recorded in 2021.

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Impairment of financial assets

The impairment of financial assets increased to US$6 million for the fiscal year ended December 31, 2022, compared to US$2 million for the fiscal year ended December 31, 2021. This increase is mainly explained by higher tax credits’ impairment losses.

Operating Income

Operating income from our holding and others segment amounted to US$49 million, compared to US$54 million for the fiscal year ended December 31, 2021. This variation is mainly explained by lower profit from joint ventures and associates (US$30 million), higher compensation agreement expenses (US$19 million) and impairment losses of intangible assets recorded in 2022. These effects were partially offset by the arbitration award in Ecuador and higher contingency charges recorded in 2021.

Financial Results, Net

Our holding and others segment recorded a net financial gain of US$89 million for the fiscal year ended December 31, 2022, compared to a US$12 million loss for the fiscal year ended December 31, 2021. This variation is mainly due to higher net exchange difference gains considering the net passive financial position, partially offset by higher losses from present value measurement.

Income Tax

Our holding and others segment recorded an income tax charge of US$20 million for the fiscal year ended December 31, 2022, compared to a US$2 million benefit for the fiscal year ended December 31, 2021, mainly due to higher pre-tax profits.

Total Profit

Our holding and others segment recorded a profit of US$118 million for the fiscal year ended December 31, 2022, compared to US$44 million for the fiscal year ended December 31, 2021, both of which are entirely attributable to the owners of the Company.

Distribution of Energy Segment

The results corresponding to the distribution of energy segment for the fiscal year ended December 31, 2021, have been classified as discontinued operations as a result of the sale of our controlling stake in Edenor.

The distribution of energy segment recorded a total loss of US$75 million from discontinued operations during the fiscal year ended December 31, 2021, of which a US$39 million loss was attributable to the owners of the Company.

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.

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.

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Total consolidated borrowings as of December 31, 2022 and 2021 were US$1,613 million and US$1,438 million, respectively. As of December 31, 2022 and 2021, 86% and 99% of our borrowings were denominated in U.S. Dollars, respectively.

As of December 31, 2022 and 2021, cash and cash equivalents were US$ 106 million and US$110 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 and our subsidiaries conducted financings at both variable and 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,
	2022	2021
Cash and cash equivalents at the beginning of the year	110	141
Net cash generated by operating activities	619	729
Net cash used in investing activities	(575)	(474)
Net cash used in financing activities	(46)	(342)
Exchange difference generated by cash and cash equivalents	(2)	4
Cash and cash equivalents reclassified to assets classified as held for sale	-	52
Cash and cash equivalents at the end of the year	106	110

Net cash generated by operating activities

Net cash generated by operating activities amounted to US$619 million for the year ended December 31, 2022, attributable to cash flow generated by net income from continuing operations without considering (i) non-cash losses (mainly related to US$212 million for depreciation and amortization of assets, US$185 million for interest accrual and US$124 million for income tax), and (ii) non-cash profits (mainly related to US$105 million for share of profit from joint ventures and associates, US$94 million for financial instruments fair value’s changes and US$85 million for net exchange differences), but considering (iii) changes in operating assets and liabilities (mainly related to US$233 million increase in trade and other receivables, partially offset by US$70 million increase in trade and other payables); and (iv) US$2 million in income tax payments.

Net cash generated by operating activities amounted to US$729 million for the year ended December 31, 2021, attributable to cash flow generated by net income from continuing operations without considering (i) non-cash losses (mainly related to US$205 million for depreciation and amortization of assets, US$141 million for interest accrual and US$24 million for financial instruments fair value’s changes), and (ii) non-cash profits (mainly related to US$117 million for share of profit from joint ventures and associates), but considering (iii) changes in operating assets and liabilities (mainly related to US$41 million increase in trade and other receivables and US$ 40 million increase in inventories, partially offset by US$43 million increase in trade and other payables); (iv) US$116 million cash generated by discontinued operations; and (v) US$13 million in income tax payments.

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Net cash used in or generated by investing activities

Net cash used in investing activities amounted to US$575 million for the year ended December 31, 2022, including payments of US$416 million for purchases of property, plant and equipment, US$102 million for public securities and shares acquisitions and US$111 million for the acquisition of subsidiaries and associates.

Net cash used in investing activities amounted to US$474 million for the year ended December 31, 2021, including payments of US$206 million for purchases of property, plant and equipment, US$234 million for public securities and shares acquisitions and US$166 million used in discontinued operations, partially offset by US$52 million proceeds from investment funds recoveries.

Net cash used in financing activities

Net cash used in our financing activities amounted to US$46 million for the year ended December 31, 2022, principally due to payments of US$305 million made in connection with bank and financial borrowings (including principal and interest), US$28 million related to repurchase and redemption of corporate bonds and US$18 million related to the acquisition of our own shares, partially offset by US$308 million proceeds from borrowings.

Net cash used in our financing activities amounted to US$342 million for the year ended December 31, 2021, principally due to payments of US$476 million made in connection with bank and financial borrowings (including principal and interest), US$39 million related to the acquisition of our own shares and US$7 million used in discontinued operations, partially offset by US$188 million proceeds from borrowings.

Capital Expenditures

The following table sets forth our capital expenditures for the years ended December 31, 2022 and 2021:

	At December 31,
	2022	2021
Generation	115	39
Distribution of energy	-	-
Oil and gas	324	213
Petrochemical	7	6
Holding and others	36	6
	482	264

In 2022, our capital expenditures in our generation segment amounted to US$115 million mainly work in progress related to the PEPE IV wind farm Project by 81 MW, initiated in 2021 and expected to be fully operating by the second quarter of 2023.

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Our capital expenditures in our oil and gas segment amounted to US$324 million in 2022, mostly to develop gas reserves, through well drilling and facilities construction, in order to continue reaching the committed gas production under the Plan Gas.Ar programs.

In 2021, our capital expenditures in our generation segment amounted to US$39 million mainly advances to suppliers and work in progress related to the PEPE IV expansion by 81 MW.

Our capital expenditures in our oil and gas segment amounted to US$213 million in 2021, mainly to develop gas reserves, through well drilling and facilities construction, in order to reach the committed gas production under the Plan GasAr.

Future Capital Requirements

For the year of 2023, our Board of Directors has approved a capital expenditure program in an amount of US$ 1,000 million, which will be mainly focused in our gas segment and in PEPE IV and PEPE VI Projects. Because of this, we expect to improve our operating cash flow, driven by an increase in our natural gas production related to the commitments we made under the Plan Gas.Ar tenders.

We estimate that our capital expenditure requirements, debt payment obligations, dividend payments and working capital will be financed mainly from our cash from operations and new debt financings.

We prioritize financial discipline with an adequate liquidity position consistent with our cash flow generation and financial requirements. Our level of investments will depend on a variety of factors, many of which are beyond our control. These include the future evolution of the price of commodities we sell, the behavior of electricity demand in Argentina, the existence and competitive impact of alternative projects, the enforcement of regulations and changes in applicable regulations, taxes and royalties, and the political, economic and social situation prevailing in Argentina.

In our generation segment, future capital investments will be focused on the expansion of renewable energy. In 2023, the Bahía Wind Farm Project (PEPE IV) is expected to be completed, which will add a capacity of 81 MW with 18 wind turbines in operation and a total estimated investment of US$ 130 million. In addition, the construction of PEPE VI will begin. This project includes 300 MW of wind energy in three stages and a total investment of more than US$500 million. The first stage includes the assembly and installation of 21 Vestas wind turbines of 4.5 MW each, with commissioning being estimated for the third quarter of 2024.

Finally, in the oil and gas segment, the investment plans for 2023 have a strong focus on our unconventional fields, with significant investments in gas, in line with the commitments assumed in our participation in the Gas.Ar Plan tenders. In particular, we will be executing an investment plan for the year 2023 that will exceed US$400 million, which will be focused mainly on the development of unconventional gas reserves through the drilling of wells aimed at the Vaca Muerta formation in our operated fields.

For further information on our investment commitments in oil and gas areas and our generation projects, please see Note 17 to our Consolidated Financial Statements.

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Description of Indebtedness

Our total consolidated financial indebtedness as of December 31, 2022 was US$1,613 million, of which 83% was long-term debt, 86% of which was denominated in U.S. Dollars. 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:

	2022	2021
	(in millions of US$)
Short-Term Debt
Corporate Bonds	163	39
Financial borrowings	51	29
Bank overdrafts	59	11
	273	79
Long-Term Debt
Corporate Bonds(1)	1,232	1,301
Financial borrowings	108	58
Total	1,340	1,359
Total Indebtedness	1,613	1,438

⁽¹⁾ Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

Financings

During 2022, the Company cancelled at maturity short term financings with banks and additionally exchanged US$407.1 million face value of its 2023 Notes for US$122.1 million in cash and issued 2026 Notes for US$292.8 million face value at a 9.5% interest rate, amortizing in three consecutive annual installments from December 2024(for more information, please see below “Exchange offer for notes maturing in 2023”) , improving its short term debt profile while keeping a solid cash position. Additionally, from August 12, 2022, it consolidates Greenwind’s net debt due to the acquisition of control of this company. Additionally, net financing in U.S. dollars was paid, and short-term bank loans were taken out in Pesos. As of December 31, 2022, our short-term maturities amounted to US$273 million.

After the end of the 2022 fiscal year, we obtained new bank overdrafts denominated in Argentine Pesos, net of cancellations, in the amount of Ps. 36.2 million and ..net import pre-financing for US$3.6 million.

The following table describes our debt maturity profile for the periods indicated, including principal amount plus the corresponding accrued interest as of December 31, 2022:

	< 1 year	1-5 years	> 5 years	Total
	(in millions of US$)
Total Indebtedness	273	406	946	1,613

Corporate Bonds

On January 2022, we issued Class 8 green bonds for a total amount of Ps. 3,107 million. Class 8 notes accrue interest at a floating rate based on a Private Badlar plus an applicable margin of 2% and are due at a single installment upon their maturity on July 18, 2023. This is the first green bond issued by Pampa, which reflects the commitment to finance projects with a positive impact on the environment and to diversify the country’s energy generation matrix. The issue was qualified by Fix Ratings, an affiliate of Fitch Ratings, with the rating of Green Bond (BV1), the best possible grade, since it is aligned with the four main components of ICMA’s (International Capital Market Association) Green Bond Principles (GBP). It was issued in observance of the “Guidelines for the Issuance of Social, Green and Sustainable Bonds in Argentina” of the CNV Rules and the provisions of BYMA’s Social, Green and Sustainable Guide and the BYMA Rules, and also makes up BYMA’s Social, Green and Sustainable Bonds Panel.

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On July 15, 2022, we issued Class 11 notes for a total amount of Ps. 12,690 million. Class 11 notes accrue interest at a floating rate based on a Private Badlar plus an applicable margin of 0% and are due at a single installment upon their maturity on January 15, 2024.

Additionally, on August 8, 2022, we made a reopening of Class 11 notes for a total amount of Ps.8,964 million at issuance price of 1.0305. The outstanding face value of Class 11 notes amounted to Ps.21,655 million.

On December 13, 2022 we issued Class 13 notes US$-link bond for a total amount of US$ 50 million. Class 13 notes accrue interest at a fix rate of 0% and are due at a single installment upon their maturity on December 19, 2027.

After the end of the 2022 fiscal year, on January we issued Class 15 notes for a total amount of Ps.10,379 million. Class 15 notes accrue interest at a floating rate based on a Private Badlar plus an applicable margin of 2% and are due at a single installment upon their maturity on July 11, 2024.

Finally, on March 6, 2023, we made a reopening of Class 13 and Class 15 notes for a total amount of US$ 48 million and Ps. 7,885 million, respectively. The outstanding face value of Class 13 notes amounted to US$ 98 million; and of Class 15 to Ps. 18,264 million.

Exchange offer for notes maturing in 2023

On June 16, 2022, we announced an offer to exchange our 7.375% US$500 million face value notes due July 2023 (the “2023 Notes”). The offer was amended on July 18, 2022 and for each US$1,000 face value to be exchanged, the following mutually exclusive options were offered: (i) Option A: cash (30% of the total amount tendered and accepted for exchange, evenly distributed among holders choosing Option A), and the balance in 9.5% notes, amortizing in three annual installments starting in 2024 and maturing in December 2026 (the “2026 Notes”), weighted at a 1.02 exchange ratio; or (ii) Option B: US$1,030 in 2026 Notes.

The exchange offer expired on July 29, and US$407.1 million representing 81.4% of the 2023 Notes were tendered and accepted for exchange as per the following breakdown:

· US$193.8 million under Option A: for each US$1,000 face value of 2023 Notes, they receive approximately US$630.2 in cash and US$377.2 in 2026 Notes; and

· US$213.3 million under Option B: for each US$1,000 face value of 2023 Notes, they receive US$1,030 in 2026 Notes.

Consequently, on August 8, 2022 US$122.1 million was paid in cash, and 2026 Notes were issued for a US$292.8 million face value.

As of the date of this annual report, the outstanding face value of the 2023 notes amounted to US$ 92.9 million.

The exchange strengthens our debt profile and equity structure, strategically focusing the use of capital on organically expanding our core businesses: increasing the production and development of unconventional gas reserves and continuing to add efficient power generation. Thus, the Company contributes to the country through local production and a lower carbon footprint and enabling savings in foreign currency reserves.

Credit Ratings

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During 2022, there were no changes in Pampa’s credit ratings. As of the date of this annual report the Pampas’ group ratings are as follows:

Company	Agency	Rating
		Global	Local(2)
Pampa	S&P	b-(1)	-
	Moody’s	Caa3	-
	FitchRatings	b-	AA+ (3) (long term) A1+ (short term)
TGS	S&P	CCC+	-
	Moody’s	Caa3	-
Transener	FitchRatings	-	A+ (long term)
CTEB	FitchRatings	-	A+

(1) Pampa Stand Alone Rating (2) Local ratings issued by FIX SCR (affiliate of Fitch Ratings) (3) Upgraded on April 20,2023 from AA to AA+ due to a greater predictability in the generation of operating flow due to the extension of the Plan Gas.Ar, in effect until the year 2028 and an increase of expected production in the E&P segment.

CTB Corporate Bonds

During 2021, CTB issued the following notes: (i) Class 1 notes for a total amount of US$ 27.3 million, accruing interest at fixed rate of 4% and maturing on June 4, 2023; (ii) Class 2 notes for a total amount of 37,504,954 units of purchasing power (“UVA”), equivalent to $2,928 million, accruing interest at a fixed 4% rate and maturing on June 4, 2024; (iii) CTB reopened (a) Class 1 notes for a total amount of US$ 15.6 million at an issue price of 101.7050%; and (b) Class 2 notes for a total amount of 27.9 million UVA at an initial value of $84.76 per UVA at an issue price of 100.82%; and (iv) Class 4 notes for a total amount of US$ 96 million, accruing interest at an annual 0% fixed rate and maturing on November 26, 2024.

On May 16, 2022, CTB issued: (i) Class 6 notes for a total amount of US$ 25 million at a fixed rate of 0% maturing on May 16, 2025; and (ii) Class 7 notes for a total amount of Ps.$ 1,754 million accruing interest at a floating rate based on a Private Badlar plus an applicable margin of 2.98% and maturing on November 16, 2023.

On August 22, 2022, CTB issued Class 8 notes for a total amount of Ps.$ 4,235 million, accruing interest at a floating rate based on a Private Badlar plus an applicable margin of 1.00% and maturing on February 22, 2024.

Moreover, on December 12, 2022, CTB reopened Class 6 notes for a total amount of US$ 58.6 million accruing interest at a fixed rate of 0% and maturing on May 16, 2025. With the reopening of Class 6 notes, which were subscribed and paid in cash and in-kind through the delivery of Class 1 notes, Class 1 notes with a fair value of US$ 10.7 million were partially canceled, with a US$ 32.2 million outstanding face value.

All notes were secured by a personal guarantee subject to a precedent and subsequent condition granted by YPF and Pampa (the “Guarantees”). The commercial commissioning of the closing of the cycle of the CTEB complied with the resolutive condition of the Guarantees and as a result, as of the date of this annual report the Guarantees have been terminated, ending all effectiveness and validity.

After the end of the 2022 fiscal year, CTB issue Class 9 notes for a total amount of US$ 50 million accruing interest at a fixed rate of 0% and maturing on April 3, 2026. With the issuance of Class 9 notes, which were subscribed and paid in cash and in-kind through the delivery of Class 1 notes, Class 1 notes with a fair value of US$ 2.2 million were partially canceled, with a US$ 30 million outstanding face value.

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, 2022, we and our subsidiaries were in compliance with the covenants under our respective outstanding indebtedness.

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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 BCL, 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 BCL. 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.

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 BCL, 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 BCL, 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 BCL, 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.

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Board of Directors

The following table sets forth information about the members and alternate members of our board of directors, six of whom have terms that will expire in December 2023, while nine have terms that will expire in December 2024 and the remaining five have terms that will expire in December 2025. 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	59	Chairman	04/29/2021	12/31/2023
Gustavo Mariani	52	Vice Chairman	04/26/2023	12/31/2025
Ricardo Alejandro Torres	65	Director	04/26/2023	12/31/2025
Damián Miguel Mindlin	57	Director	04/29/2021	12/31/2023
Carolina Zang(1)(2)	50	Director	04/27/2022	12/31/2024
Carlos Correa Urquiza(1) (2)	53	Director	04/27/2022	12/31/2024
María Renata Scafati (1) (2)	50	Director	12/27/2022	12/31/2024
Dario Epstein(1) (2)	59	Director	04/27/2022	12/31/2024
María Carolina Sigwald	55	Director	04/29/2021	12/31/2023
Silvana Wasersztrom(1) (2)	55	Director	04/26/2023	12/31/2025
Clarisa Lifsic(1)(2)	60	Alternate Director	04/27/2022	12/31/2024
Mariana de la Fuente	54	Alternate Director	04/27/2022	12/31/2024
Diana Mondino (1) (2)	64	Alternate Director	04/27/2022	12/31/2023
Clarisa Vittone (1) (2)	55	Alternate Director	04/27/2022	12/31/2023
Diego Martín Salaverri	58	Alternate Director	04/27/2022	12/31/2024
María Agustina Montes	41	Alternate Director	04/26/2023	12/31/2025
Mauricio Penta	46	Alternate Director	04/29/2021	12/31/2023
Horacio Jorge Tomás Turri	62	Alternate Director	04/26/2023	12/31/2025
Emilse Juárez (1) (2)	38	Alternate Director	12/27/2022	12/31/2024
Lorena Rappaport (1) (2)	51	Alternate Director	04/27/2022	12/31/2024

(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 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 in order 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
Silvina Wasersztrom	President
Gustavo Mariani	Regular Member
Carlos Correa Urquiza	Regular Member
Mariana de la Fuente	Alternate Member
Diana Mondino	Alternate Member
María Carolina Sigwald	Alternate Member

Senior Management

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

Name	Position	Age
Marcos Marcelo Mindlin	Chairman	59
Gustavo Mariani	Executive Vice president - Chief Executive Officer (CEO)	52
Ricardo Alejandro Torres	Executive Vice president	65
Damián Miguel Mindlin	Executive Vice president	57
Horacio Jorge Tomás Turri	Executive Director of Exploration and Production	62
Nicolás Mindlin	Executive Director of Finances (CFO) and M&A	33
María Carolina Sigwald	Executive Director of Legal Affairs	55
Mauricio Penta	Executive Director of Administration, IT and Supply	46

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

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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., Grupo Emes S.A. and Emes Inversora S.A. and member of the board of Orígenes Seguros de Retiro S.A., Orígenes Seguros de Vida S.A. and Consultores Fund Management.

Gustavo Mariani was born on September 9, 1970. He has been a member of our board of directors since November 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’s degree in Finance from the Universidad del CEMA (Center of Macroeconomic Studies) and also is a Chartered Financial Analyst (CFA) since 1998. Mr. Mariani joined Grupo Dolphin in 1993 as an analyst and also served as an investment portfolio manager. Mr. Mariani is currently Chairman of HIDISA, HINISA, CISA, and Generación Argentina S.A., Vice Chairman of SACDE and member of the board of Inversiones QRP S.A.U., ODS S.A., Dolphin Créditos Holding S.A., Emes Inversora S.A., Transba, Grupo Emes S.A., Emes Finance S.A, Grupo Dolphin Holding S.A., Orígenes Seguros de Vida S.A., Orígenes Seguros de Retiro S.A., Sitios Argentinos S.A, TGS, and the Foundation.

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 degree 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 currently serves as Chairman of PISA, Inversiones FPK S.A.U, Energía e Inversiones S.A, Digipa S.A, CITELEC, Pampa Inversiones S.A, Pop Argentina S.R.L., Todos Capital S.R.L., La Fundación Observatorio Argentinos por la Educación Vice Chairman of CISA, Transener S.A and member of the board of HIDISA, HINISA and Transba S.A

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. Additionally, he is currently the Chairman of Inversiones DM S.A.U, Latina de Infraestructura Ferrocarriles e Inversiones S.L., ODS S.A., SACDE, Creaurban S.A., IECSA Chile S.A., Constructora Incolur IECSA S.A LTDA (Chile), Inversora Andina S.A. (Chile), Profingas S.A., Líneas del Norte S.A., Minera Geometales S.A., FIDUS S.G.R, Compañía Americana de Trasnmisión Eléctrica S.A. (CATESA), Corpus Energía S.A., Posadas Encarnación S.A., and ARPHC S.A., as Vice Chairman of Energía e Inversiones S.A., Pampa Inversiones S.A., HIDISA, HINISA, Sitios Argentinos S.A, Dolphin Créditos Holding S.A., Emes Inversora S.A., Grupo Emes S.A. and Grupo Dolphin Holding S.A. and he is member of the board of CIESA, Orígenes Seguros de Vida S.A., Orígenes Seguros de Retiro S.A., Consultores Fund Management Ltd, Emes Air S.A., ByMA, CISA, Digipa S.A, Transba and CITELEC.

María Carolina Sigwald was born on November 15, 1967. She has been a member of our board of directors since 2017. She is the 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. Likewise, she took office in TGS’s and Telefónica de Argentina’s board of directors. She is currently the Chairman of Greenwind, Pampa Bloque18 SA and ENOPSA, Vice Chairman of Autotrol Renovables S.A, Digipa S.A, Generación Argentina S.A, Pampa Energía Bolivia S.A, and member of the board of CITELEC, CISA, CTB, Transba TGS, CIESA, VAR, Transener, the Foundation and Vientos Solutions S.A.U.

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Carlos Correa Urquiza was born on September 17, 1969. He has been a member of our board of directors since 2019. He currently serves as the Trading Desk in the Finance Area Management of Banco Hipotecario SA. Prior to joining BHSA (1999), he held the position of Head of the back-office department of Consultores Asset Management (1994-1999). Carlos holds a Master’ss degree in Banking Management from Universidad del Cema and a Bachelor’s Degree in Business Administration from Universidad de Belgrano.

María Renata Scafati, was born on October 21, 1972. She has been a member of our board of directors since 2022. Mrs Scafati holds a Law degree from the University of Belgrano and is specialized in corporate, regulatory and environmental law. She has a vast experience in private and public legal management. Mrs. Scafati worked at Arthur Andersen-Norte Sabino Asesores Legales, Zang, Bergel & Viñes Law Firm, as an external lawyer of Central Piedra Buena S.A., and as legal and technical manager of the Municipality of Tigre. Prior to that, she was in-house lawyer of Endesa (currently Enel Argentina).

Dario Epstein was born on July 19, 1963. He has been a member of our board of directors since 2019. He currently is a director of Sur Investment, Research for Traders and FinGuru. He is a Public Accountant and has an MBA from the University of Michigan. He was also director of CNV.

Carolina Zang was born on October 26, 1972. She has been a member of our board of directors since 2022. Ms. Zang holds a law degree in Universidad de Buenos Aires and has a masters 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 Board of Directors 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 an alternate member of the Board of Directors of Brasilagro Companhia Brasileira de Properties Agricolas.

Silvana Wasersztrom was born on March 18, 1968. She has been a member of our board since 2019. Ms. Wasersztrom is a lawyer and completed postgraduate studies in Tax and Customs Law at the Universidad Austral and Belgrano. Since 2012 she has practiced independently in her firm. Previously, from 1994 to 2002, she worked at Marval, O’Farrell & Mairal Abogados, and did an internship in Tampa, Florida, United States in the year 1992-1993.

Mariana de la Fuente was born on December 5, 1968. She has been a member of our board of directors since 2022. She has a degree in Psychology from the University of Buenos Aires and completed various specializations and postgraduate courses in business administration in the Instituto de Altos Estudios Empresariales (IAE) and human resources at the University of Michigan, USA. Since November 2021, she is Human Resources Director of Pampa. Previously, since 2014, she served as Human Resources Director of EDENOR and previously at EDEN (Empresa Distribuidora de Energia Norte), both former subsidiaries of Pampa. Since 1990, he has held leadership positions related to human resources for Argentina or Latin American Region in several multinational companies, including Monsanto, Cerveceria Quilmes, Cabot and Abertis.

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. Lifstic holds a Bachelor’s in Economics from the University of Buenos Aires, where she graduated with honors and a Master of Science in Management from the Massachusetts Institute of Technology (Summa Cum Laude).

Diana Mondino was born on August 8, 1958. She has been a member of our board of directors since 2022. After completing her master’s in Business Administration; Major in Marketing and Finance at IESE, Spain Ms. Mondino was Director of Studies at CEMA, where she headed the first master’s in business administration to be taught in Argentina in 1987. She was formerly Region Head for Latin America at Standard & Poor´s, after it bought a domestic rating agency she co-founded. Ms. Mondino is currently CEO of Banco Roela and its fintech operation SIRO; and serves as Director of Institutional Affairs and professor at the master’s in finance and MBA programs at CEMA University. She is also a Board member of the Food Bank Foundation. She is currently Board member of Loma Negra and Bodegas Bianchi.

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Clarisa Vittone was born on October 6th, 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 in Latin America the practice of diversity and inclusion. Her second area of specialization is in the field of digital talent advising since 2015 companies, promoting digital transformation and the development of digital capabilities for C-level and Boards of Directors. Thirdly, she works in boards consultancy practice. Previously she worked at Valuar, a local prestigious executive search company. Before that, 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 and a 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 PE Energía Ecuador LTD, GG Negocios Fiduciarios S.A., ODS, SACDE and Grupo Emes S.A. He also serves as member of the supervisory committee of Grupo Dolphin Holding S.A., Origenes Seguros de Retiro S.A., Genes II Seguros de Retiro S.A., Préstamos y Servicios S.A., and Norpatagónica S.A., among others.

Emilse Juárez was born on February 10, 1985. She has been a member of our board of directors since 2022. Mrs. Juarez holds a degree in Economics from the University of Buenos Aires, with a specialization in social economy. Mrs. Juárez is currently the Administrative and Technical Coordinator of the General Directorate of Management and Corporate Affairs, responsible for the economic-financial and administrative area in the Executive Sub-Directorate of Operations of the FGS of the National Social Security Administration (ANSES). Mrs. Juárez has management experience as a director in companies such as Edenor, Transener, Edesal Holding, Naturgy Ban, TGS, Enel Generación Costanera, and Metrovías.

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 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.

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,Pampa Energía Bolivia S.A., PE Energía Ecuador LTD, Autotrol Renovables S.A CITELEC, CISA, CTB, Digipa S.A, Enecor, Greenwind, HIDISA, Transba, TGS and VAR

Horacio Turri was born on March 19, 1961. Mr. Turri is an industrial engineer and received his degree from the 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 also serves as a Vice-Chairman of TGS and CIESA.

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 and GASAU II S.A., Generación Argentina S.A, Greenwind and VAR.

Nicolás Mindlin was born on November 11, 1989. Mr. Mindlin holds an Industrial Engineer degree from the Technological Institute of Buenos Aires and is currently Executive director of finances (CFO) and M&A. Mr. Mindlin serves as Chairman of Pampa Energía Bolivia S.A. and Vientos Solutions Argentina S.A.U, Vice Chairman of Greenwind, VAR, ENOPSA, Pampa Bloque 18 S.A., and as member of the board of Digipa S.A., PE Energía Ecuador LTD and as a Sole Officer of Vientos Solutions S.L.U.

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On April 16, 2018, the CNV issued Resolution No. 730, which modifies 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, María Carolina Sigwald, Diego Martín Salaverri, Mauricio Penta, María Agustina Montes, Horacio Jorge Tomás Turri and Mariana de la Fuente.

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: Silvana Wasersztrom, María Renata Scafati, Carlos Correa Urquiza, Darío Epstein, Carolina Zang, Clarisa Vittone, Diana Mondino, Clarisa Lifsic, Lorena Rappaport and Emise Juarez.

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 two 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	Age
Darío Epstein	President	59
Carlos Correa Urquiza	Regular Member	53
Silvana Wasersztrom	Regular Member	55
Diana Mondino	Alternate Member	64
Clarisa Lifsic	Alternate Member	60

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 member of the audit committee, see his 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 connection of which there is a 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.

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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.

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 BCL, 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 BCL, 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
Elena Sozzani	Regular Member	46
José Daniel Abelovich	Regular Member	66
Martín Fernandez Dussaut	Regular Member	42
Noemí Cohn	Alternate Member	63
Tomás Arnaude	Alternate Member	41
Germán Wetzler Malbrán	Alternate Member	53

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

José D. Abelovich. Mr. Abelovich obtained a degree in accounting from Universidad de Buenos Aires. He is a founding member and partner of Abelovich, Polano & Asociados S.R.L., an accounting firm member of Nexia International, a global network of accounting and consulting firms. 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 Autotrol Renovables S.A, CITELEC, CISA, CIESA, Greenwind, HIDISA, Transba, Transener, TGS, VAR, Cresud, IRSA and certain subsidiaries, Banco Hipotecario and certain subsidiaries, 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. He is a member of the board of directors of CT Mitre Office S.A., Latin Securities S.A., Escrow Services S.A., and GG Negocios Fiduciarios S.A. and Grupo Emes S.A. Additionally, he is a member of the supervisory committee of ODS S.A., Vientos Solutions Argentina S.A.U., Creaurban S.A., Compañía Americana de Transmisión Eléctrica S.A, Grupo Dolphin Holding S.A., Generación Argentina S.A., TAP Billetera S.A., Numera Analytics S.A.U., Minera Geometales S.A., SACDE, CTB, CINCOVIAL S.A., Inversora al Rio S.A. Autotrol Renovables S.A, Enecor, Generación Argentina S.A., Greenwind S.A, Inversiones DM SAU, GASAU II S.A., VAR and Digipa S.A., among others.

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Elena Sozzani was born on December 5, 1976. Mrs. Sozzani received her law degree from the Universidad Nacional de La Plata. She is a partner of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán. She is a member of the supervisory committee of Autotrol Renovables S.A, Digipa S.A, Enecor, Generación Argentina S.A, Inversora al Rio S.A., Greenwind, GASAU II S.A., Transba and VAR, CISA and Vientos Solutions Argentina S.A.U., 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. He is member of the board of Veinticuatro de Enero S.A. Additionally, he currently serves as member of the Supervisory Committee of SACDE, CISA, ODS, Orígenes Seguros S.A., Creaurban S.A., Vientos Solution Argentina S.A.U., Greenwind, Generación Argentina S.A, GASAU II S.A. and Transba, among others.

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 Abelovich, Polano & Asociados S.R.L., an accounting firm member of Nexia International, a global network of accounting and consulting firms. 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 and subsidiaries, Autotrol Renovables S.A, Generación Argentina S.A, Greenwind, Inversión QRP S.A, 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. He is member of supervisory committee of CINCOVIAL S.A, Compañía Americana de Transmisión Eléctrica S.A., Creaurban S.A., Autotrol Renovables S.A, CISA, CTB, Enecor, Generación Argentina S.A., Greenwind, Grupo Dolphin Holding S.A., Inversiones DM S.A, VAR, Vientos Solutions Argentina S.A.U, Orígenes Seguros  S.A., Orígenes Seguros de Retiro S.A., Salta Refrescos S.A., Prestamos y Servicios S.A., Minera Geometales S.A., SACDE, Genes II Seguros de Retiro S.A., Life Seguros de Personas y Patrimoniales S.A., Digipa S.A. and GASAU II S.A., among others.

Corporate Governance

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

· Code of Conduct. This code states the ethical principles that constitute the foundation of the relationship between the Company and its employees, with suppliers, coworkers, shareholders, authorities, intermediate organizations, and the community as a whole. The Code offers the means and instruments that guarantee the transparency of issues and problems affecting the management of the Company.

· 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 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 jointly. Finally, this policy establishes the obligation to report any actual or suspected violation of laws and/or regulations and/or the policy, as well as the prohibition of retaliation against any employee or third party for filing a report legitimately and in good faith or for refusing to participate in acts of corruption.

· Transactions with Related Parties 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 Corporate Law Division and which involves both the Company’s’ board of directors and its Audit Committee, as the case may be.

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· Policy on Material Information’s Disclosure. This policy standardizes the basic principles concerning the process in which the Company’s material information is disclosed, in accordance with the applicable regulatory regulations. 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.

· Policy on best security market practices. This Policy seeks to prevent the use of non-public material information to obtain an advantage for oneself or others, either directly or indirectly by certain Company’s employees, including directors, supervisory committee members, and senior management lines, as well as to certain related parties.

· Integrated management policy. This policy is an evolution of the Quality, Safety, Environment and Labor Health Policy. It aims to unify QHSE standards in our operations different processes, guaranteeing the maximum possible safety in each activity’s ordinary course of business. Moreover, this Policy strengthens Pampa’s culture and relationship with different stakeholders, makes the commitments required by certifiable international standards visible, and improves their understanding and commitment.

· Swap Transactions Policy. This policy, approved by the Board, sets forth the framework under which the Company shall manage risks related to any Swap it executes under International Swaps and Derivatives Associations (‘ISDA’) agreements. This policy applies only to activities governed by the Commodity Exchange Act, as amended (the “CEA”), and only with respect to the election of the “End-User Exception” as provided in Section 2(h)(7) of the CEA.

· 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.

· Dividend Policy. This policy, in accordance with laws and regulations in force in Argentina and the Company’s bylaws, establishes a set of guidelines to be observed to keep an adequate balance between distributed amounts and Pampa’s investment plans; aiming at establishing a clear, transparent and consistent practice that enables shareholders to make informed decisions. According to this policy, the decision to distribute a dividend is at the sole discretion of the Shareholders’ Meeting, based upon the board of directors’ recommendation. It expressly sets forth that the Company is under no obligation to distribute profits, and the Shareholders’ Meeting will have sole discretion regarding the determination and timing of a dividend distribution.

· 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 or any of its subsidiaries.

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Compensation of Directors and Officers

The BCL 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 BCL 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 BCL also provides that the shareholders’ meeting may approve the remuneration of the directors in excess of the limits set by the BCL 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) for its opinion 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.

At the ordinary shareholders’ meeting held on April 26, 2023, the compensation for Pampa’s directors was set for a total amount of Ps. 2,790,947,708 for the year ended December 31, 2022. 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.

During fiscal year ended December 31, 2020, the Company delivered 0.7 million of its own shares as payments under the stock compensation plan for officers and other key staff. As of December 31, 2020, the Company acquired 6 million of its own shares, out of which 2 million was allocated to the compensation of senior managers and, as of the closing of the fiscal year, 4 million remained in treasury to be delivered to employees under such plan.

During fiscal year ended December 31, 2021 and 2022 the Company delivered 0.6 million 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 2023, the Company delivered 0.6 million shares year as payments under the stock compensation plan for officers and other key staff

As of the date of this annual report, we held in treasury 3,878,939 common shares to be delivered to employees under such plan, which represents 0.3% of our issued capital.

Compensation Agreements – Senior Management

The Company has executed compensation agreements with the Company’s main executives. The objective of these compensation agreements is to align the executives’ interests with the shareholders of the Company, creating value for the executives only if there is also value 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 may only be collected by their beneficiaries to the extent Pampa’s share market capitalization at the time of realization is higher than the recorded maximum (high water mark provision). Additionally, the annual total amount payable should not exceed 1.8% of the adjusted EBITDA of the year subject to compensation. The payment of the annual compensation will be subject to the prior approval of the Shareholders’ Meeting to be held in each fiscal year.

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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.

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
Silvana Wasersztrom	President
Dario Epstein	Regular Member
Carlos Correa Urquiza	Regular Member
Diana Mondino	Alternate Member
Clarisa Lifsic	Alternate Member

Share Ownership

As of March 31, 2023, the following members of our board of directors and our senior management had an ownership interest in our capital stock of: Marcos Marcelo Mindlin (16.99%), Gustavo Mariani (2.87%), Damian Miguel Mindlin (3.12%), Ricardo Alejandro Torres (2.09%), Horacio Turri (0.56%), Nicolás Mindlin (0.01%), Mauricio Penta (0.01%), Carlos Correa Urquiza (0.003%), María Carolina Sigwald (0.002%) and Diego Salaverri (0.01%). No other member of our board of directors or our senior management beneficially owns any shares of our capital stock. 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, 2022, we had 1,907 full time employees. Additionally, we operate CTEB, which is jointly owned with YPF and has 106 full-time employees.

Approximately 53.35% of our workforce is affiliated with a union and/or is a party to a collective bargaining agreement. We have completed salary negotiations for 2022. We maintain a positive relationship with each of the employee unions at the Company and our subsidiaries’ levels.

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

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On April 7, 2020, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 151,585,025 common treasury shares of Pampa. The withdrawal of the repurchased shares from the capital stock allows the Company to repurchase shares in the market. Consequently, our capital stock decreased to 1,596,288,214 shares.

On December 10, 2020, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 140,786,959 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,455,501,255 shares.

On April 29, 2021, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 56,581,600 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,398,919,655 shares.

On September 30, 2021, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 12,513,675 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,386,405,980 shares.

On April 27, 2022, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 2,761,375 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,383,644,605 shares.

Finally, on April 26, 2023, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 20,124,225 common treasury shares of Pampa. Consequently, our capital stock decreased to 1,363,520,380 shares.

J.P. Morgan informed us that, as of March 31, 2023, there were 28,368,453 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 as of March 31, 2023:

Name of Shareholder	Number of Shares	Percentage of our Capital Stock	Percentage of voting power
ANSES (¹)	306,958,364	22.14%	22.14%
Braslyn HL / Hidden Lake S.A.	68,736,655	5%	5%
Management
Marcos Marcelo Mindlin	235,020,708	16.99%	16.99%
Gustavo Mariani	41,274,658	2.98%	2.98%
Damián Miguel Mindlin	44,609,565	3.22%	3.22%
Ricardo Alejandro Torres	28,952,864	2.09%	2.09%

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, 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.

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Related Party Transactions

The BCL permits directors of a corporation to enter into 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.

Interests of experts and counsel

During the year ended December 31, 2020, 2021 and 2022, 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, Martín Fernandez Dussaut and Elena Sozzani, and two of the alternate members of our Supervisory Committee, Tomás Arnaude 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

In the normal course of business, we are a party to lawsuits of various types. Our management evaluates the merit of each claim and assesses the likely outcome, recording an accrual in our financial statements for the related contingent liability when an unfavorable decision is probable and the amount may be reasonably estimated. At December 31, 2022, we had established accruals in the aggregate amount of US$107 million to cover potential losses from such claims and legal proceedings. The above-mentioned amount does not include Transener and TGS given they are not consolidated and are accounted for according to the equity method of accounting in the Consolidated Financial Statements. Except as disclosed below, we are not a party to any legal proceedings or claims that may have a material adverse effect on our financial position or operational results.

Set forth below is a brief description of significant proceedings for which provisions have been recorded as of December 31, 2022:

- Relevant Customs Proceedings - Gasoline Exports: there are an important number of proceedings in process before the National Tax Court 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.

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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, 2022, the Company, in accordance with the analysis of our internal and external legal advisors, considers that such legal proceedings are not viable.

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 by former employees, not covered by the plan, seeking to be included in the plan. One of the claims has resulted in a favorable ruling for the Company, which has been appealed by the plaintiff. The Court of Appeals upheld the first instance judgments that had rejected the claims filed in two lawsuits by former employees who sought being included in the plan. Both rulings stand final.

· Claims by former employees who were dismissed as part of scheduled layoffs due to Company’s change of control.

· Claims alleging that the index (IPC) used to update the plan benefits is ineffective to keep the benefits’ “constant value”. In two of the cases, the Company obtained a favorable judgment, which has been appealed by the plaintiff. On the contrary, another case has obtained an unfavorable judgment for the Company and, consequently, we appealed to the respective Court.

· 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 Aires 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, in order to treat the unconstitutionality appeal filed.

Tax Claims

Tax on Liquid Fuels and Natural Gas

AFIP 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. AFIP’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 Federal Tax Court, and the evidentiary period has been completed.

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 defendants 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.

- 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 US$547 million based on a United Nations Development Program report. The proceeding is in the complaint answer stage.

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- Beatriz Mendoza and 16 other plaintiffs brought a complaint before the CSJN against the National Government, the Province of Buenos Aires, the Government of the Autonomous City of Buenos Aires and 44 companies, including the Company, conducting industrial activities along the Matanza-Riachuelo River Basin. The plaintiffs seek compensation for alleged damages sustained as a result of an alleged environmental impact, its cessation, and environmental restoration, for an estimated amount of US$500 million for the financing of the Matanza-Riachuelo River Basin Environmental Management Plan aiming at the restoration of the basin. The proceeding is in the third-party summoning stage.

- Inertis S.A. has filed a complaint against the Company for alleged damage to the environment in a lot owned by this company as a result of the activities conducted by the Dock Sud Plant seeking the redress of alleged damages for a nominal amount estimated at Ps. 1 million and US$1 million, or the difference between the value of the allegedly affected lot and its valuation. The proceeding is in the evidentiary 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 environmental restoration, or compensation for the alleged damages 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 US$200 million. The CSJN ruled in favor of the civil and commercial court of Mar del Plata and sent the claim back to first instance. There, the Court granted the plaintiff’s request for the dismissal of the anticipated evidence, ruled the termination of the pre-judicial mediation proceedings and ordered the Company and other defendant companies to be served with the claim. The latter having been done, the Court partially granted the summons of third parties composed of the National State, the Province of Buenos Aires and the Municipality of Mar del Plata and ordered a precautionary injunction for better provision, related to the merits of the case. The parties have convened to the suspension of the procedural terms until mid-August 2022, to assess the possibility of reaching a settlement. The plaintiff has settled with three co-defendants. The acting Court sent the proceedings to first instance where the Court ordered a number of informative measures prior to serve notice of the settlement agreement to the remaining co-defendants (including the Company). A partial agreement that was entered into between the plaintiff and co-defendant was approved and the proposal of two other co-defendants is being substantiated. Due to the material impossibility of the Company to comply with the requirements of the agreement (as of 2019 it was not the owner of any service station), our release from the process was requested.

- Some neighbors of the Dock Sud area brought a complaint against 14 oil companies, including the Company, petrochemical companies and waste incineration plants located in the Dock Sud Petrochemical Complex for alleged damage to the environment and alleged individual damage to their goods, health and morale. The CSJN determined it had jurisdiction over the environmental issue and maintained the civil and commercial jurisdiction regarding the compensation for the alleged damages. The Civil and Commercial First Instance Court has opened the evidentiary stage.

- A neighbor of the Province of Salta owning a lot where a joint venture made up of the defendants (the Company and other companies) conducted hydrocarbon activities seeks environmental protection and restoration for alleged damage caused by hydrocarbon prospecting, exploration and/or exploitation activities or, alternatively, compensation in case such environmental restoration is not possible. The proceeding is in the complaint answer stage and Salta’s Court of Justice determined that the Court of First Instance for Contentious Administrative Matters has jurisdiction. The Province of Salta was finally related as co-defendant and not as third party.

- Owners of a lot in the town of Garín, Province of Buenos Aires, seek the performance of preliminary proceedings for alleged indications of damage to the environment in their place of residence which resulted from an alleged leakage from the adjacent gas station under the Company’s branding. Preliminary measures are being conducted in this proceeding.

- Neighbors of the Province of Neuquén brought a proceeding against the Company for alleged environmental damage resulting from the hydrocarbon exploration, exploitation, transportation and well abandonment activities in which that plaintiff has been taking part. Should this not be feasible, they claim compensation for alleged damages to support the Environmental Restoration Fund. Additionally, they request the redress of alleged moral damages to be allocated to the Environmental Restoration Fund. The presence of all involved parties has been properly verified, and the lawsuit has been referred to the administrative litigation jurisdiction.

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- The Company initiated a legal claim against the Province of La Pampa requesting the annulment and revocation of administrative acts through which such Province, through its Undersecretary of Hydrocarbons and Mining and its Undersecretariat of Environment, claims that the Company has definitively abandoned 13 hydrocarbon wells located within the Jagüel de los Machos Area that were inactive by the time the concession belonged to the Company (September 2015), as well as the presentation of a plan for the remediation of certain environmental liabilities. It is worth clarifying that an environmental audit was carried out at the time of the reversal of the hydrocarbon area, and the deviations observed therein are currently corrected. The case is in litigation. The parties have agreed on the suspension of all procedural terms since they are in settlement negotiations.

- Plaintiff Martinez Lidia and other three plaintiffs claim financial compensation for alleged damage to their health and property caused by the alleged environmental affectation sustained as a result of living next to PGSM petrochemical plant (Rosario-Santa Fe). The proceeding is currently pending judgment and pending setting of the hearing date for the drawing of the Public Defender for the heirs of the deceased plaintiff and the Official Defender, who accepted the appointment, has been designated to represent the heirs of the deceased plaintiff.

- A neighbor of the Province of Buenos Aires brought a complaint against the Company seeking the removal of three fuel storage tanks and pumps and the remediation and restoration of the soils where such tanks are located on account of an alleged environmental affectation. The proceeding is in the evidentiary stage.

- Neighbors of the Province of Santa Fe have brought a complaint against the Company for alleged environmental damage. The Company obtained a favorable judgment, which has been appealed by the plaintiff.

Civil and Commercial Claims

- The consumers’ association named “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of US$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 filed 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.

- 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 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 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 procedure. Set forth below are brief descriptions of the nature of the significant legal proceedings or claims brought by the Company. As of December 31, 2022, we consider that such legal proceedings are probable and economic benefits are expected to the Company.

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Administrative claims

- CTLL (currently Pampa) filed an administrative litigation complaint against the Federal Government for contractual breach during the January 2016-July 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. The rendering of judgment was requested. Subsequently, CTLL filed a new administrative litigation complaint against the Federal Government for contractual breach during the April 2016-October 2018 period. In the claim for the January 2016-March 2016 period, the call for judgment was suspended due to the connection with the claim filed later for the April 2016-October 2018 period, the latter being open to evidence.

- 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.

Civil and Commercial claims

- The Company has filed an international arbitration claim against Petrobras International Braspetro B.V. on account of fraudulent representations and omissions associated with certain export transactions under the share purchase agreement executed on May 13, 2016, whereby the Company acquired 67.2% of Petrobras Argentina S.A.’s capital stock. The arbitration was held pursuant to the ICC’s Arbitration Rules, the applicable law is New York State Law and the seat of arbitration is New York. Petrobras International Braspetro B.V. timely answered the request for arbitration and also filed a counterclaim seeking the payment of a percentage over the difference between the amount estimated for certain contingencies detected in the purchase process and the amount actually paid for them. On April 29, 2021, the Company filed its statement of claim and PIB BV filed its statement of counterclaim. On July 7, 2021, the Company and PIB BV filed their defense. On November 5, 2021, the Company and PIB BV filed their reply briefs and on December 20, 2021, they filed their rejoinders on the claims. After the proceedings were suspended by the Court at the request of the parties, the latter decided to continue with the procedure.

- Our subsidiary 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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- Our subsidiary Pampa Bloque18 filed claims against Petroecuador as a result of certain breaches to the transportation agreement entered into on December 31, 2008 whereby the Ecuadorian Government undertook the crude oil transportation commitment through the OCP, to be charged to the oil transportation capacity hired by Pampa Bloque18. On August 3, 2022, the Court of Arbitration issued the final award partially upholding the claim. Although the award was not subject for annulment, Petroecuador filed an extraordinary appeal for legal protection before the Constitutional Court. Such action does not suspend the enforcement of the award. As of the date of this report, Petroecuador partially complied with the award and paid US$ 20 million and Pampa Bloque 18 requested payment of the outstanding balance.

- The Company has initiated an international arbitration against High Luck Group Limited – Sucursal Argentina for certain breaches of the Farmout Agreement and the Joint Operating Agreement regarding Chirete Block entered into on April 1, 2015.

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 AFIP 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.

Notwithstanding, the Company and subsidiaries have applied for an exemption to pay the personal asset tax for the periods 2016 to 2018, in accordance with the benefits of Law 27,260.

We did not declare any dividends for the fiscal years ended on either December 31, 2018, December 31, 2019, December 31, 2020, December 31, 2021 or December 31, 2022.

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:

	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
2018(1)	57.60	35.05	50,765,767	72.98	24.93	18,015,650
2019(1)	64.50	29.15	50,179,161	39.89	12.01	16,258,128
2020(1)	86.25	32.00	56,576,326	16.69	8.72	4,380,259
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

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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
2021(1)
First Quarter	90.00	73.20	36,796,031	15.25	12.17	1,606,836
Second Quarter	120.00	82.30	46,594,045	17.95	13.14	2,089,367
Third Quarter	138.75	101.15	74,700,764	19.21	14.71	1,678,155
Fourth Quarter	171.50	133.50	88,948,139	21.28	16.35	3,134,025
2022(1)
First Quarter	198.60	152.00	66,734,088	24.66	17.97	3,203,112
Second Quarter	192.95	173.65	84,626,054	25.86	21.31	3,156,225
Third Quarter	317.90	205.00	125,585,316	27.95	19.25	2,895,283
Forth Quarter	440.70	273.15	180,757,574	32.00	21.93	3,358,042
2023(1)
First Quarter	540.00	425.00	284,781,804	36.87	26.86	6,187,672
Second Quarter(3)	670.80	533.70	408,704,418	38.23	32.78	4,154,856

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
2022(1)
November	382.00	300.00	159,365,553	29.40	24.61	2,965,647
December	440.70	333.00	249,925,672	32.00	24.87	4,430,701
2023(1)
January	525.00	425.00	376,478,291	36.87	30.21	8,186,701
February	515.00	460.00	223,345,123	34.75	31.38	3,960,121
March	540.00	427.70	243,351,693	34.45	26.86	6,289,537
April(3)	670.80	533.70	408,704,418	38.23	32.78	5,110,200

⁽¹⁾       Values provided by Bloomberg.

⁽²⁾       Values available for our ADSs from October 9, 2010, the first trading date on the NYSE.

⁽³⁾       Represents the average of the lowest and highest daily rates from April 1 through April 27, 2023.

Purchases of Pampa’s Shares

During fiscal year 2020, the Board of Directors approved Programs VI and VII for US$27 million and $3,600 million, with a maximum price of US$13 per ADR, which have been completed and for which all repurchased shares have been canceled.

The Repurchase Program VIII was approved on October 30, 2020 for a maximum amount of US$ 30 million and an initial term of 120 calendar days, with a maximum price of US$ 15 per ADR and Ps. 85.20 per common share, was in effect as of December 31, 2020, and has terminated as of the issuance of this annual report. As of December 31, 2020, there are no own shares held in treasury under the buyback programs.

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During 2021, the Board of Directors approved Programs IX and X for a maximum amount of US$ 30 million each, under which shares could be acquired up to a maximum price of US$16 and US$15.5 per ADR, respectively, which were terminated as of December 31, 2021, with the repurchased shares canceled in full.

As of December 31, 2021, Program XI, approved by the Board of Directors on December 1, 2021 for a maximum amount of US$30 million and an initial term of 120 calendar days; under this Program, shares could be acquired up to a maximum price of US$19 per ADR and $167 per common share. This program ended on March 2022.

Finally, on May 11, 2022, Program XII was approved by the Board of Directors for a maximum amount of US$30 million and an initial term of 120 calendar days. Under this program, shares could be acquired up to a maximum price of US$22 per ADR and $194 per common share.

During 2022, the Company indirectly acquired 0,9 million own ADRs for a value of US$18.2 million.

For more information, please see “Item 16.E—Purchases of Equity Securities by the Issuer and Affiliated Purchasers” and “Item 7. Major Shareholders and Related Party Transactions”.

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 Barclays Capital.

The ADS Depositary has informed us that, as of December 31, 2022, there were 15,405,328 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 Mercado Abierto Electrónico S.A., the Mercado de Valores de Córdoba S.A., the Mercado a Término de Rosario 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.

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On December 29, 2016, the CNV authorized BYMA and on January 2, 2017, IGJ and CNV authorized the creation and operation of BYMA. Seventy percent of its capital stock is held by free float and the other 30 percent is owned by BASE.

BYMA is the largest authorized market in Argentina. Pursuant to Resolution No. 18,629, the CNV authorized BYMA 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.

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 MAE, an electronic over-the-counter market reporting system that functions independently from BYMA. Under an agreement between the BASE and MAE, 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 S&P MERVAL/BASE (now BYMA) and the MAE. Trading in Argentine Government securities, which are not covered by the agreement, may be conducted on either or both of the BYMA and the MAE. 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. 677/2001, 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. 677/2001. However, CML incorporated most of the provisions established in those regulations. These provisions were regulated by the CNV through Resolution No. 622/2013 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.

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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.

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 Ministry of Economy 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 exceed in the aggregate (through one or more related transactions) Ps.300,000. 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 arms trafficking (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) Crime 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 terrorism (Articles 41quinquies and 306 of the Argentine Criminal Code); (ix) Crimes of extortion (Article 168 of the Argentine Criminal Code); (x) Tax crimes, related to social security and fiscal resources (pursuant to law 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 PROCELAC. As PROCELAC has no competence to apply sanctions, its main role is to collaborate with the Federal Prosecutors in the investigation of crimes and in receiving complaints in order to initiate preliminary investigations.

The UIF issued Resolution No. 229/2011, which was replaced by Resolution UIF No. 21/2018 and, subsequently amended by Resolutions No. 156/2018, No. 18/2019, No. 117/2019, No. 112/2021, No. 6/2022 and 50/2022 (“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.

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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.

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. 21/2018, 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, to 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 (“KYC”), 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.

In accordance with Annex I of the UIF Resolution No. 154/2018 (which established the supervision and inspection mechanism of the UIF), both the Central Bank and the CNV are considered “Specific Controllers”. Therefore, they must collaborate with the UIF in complying with the procedures for the prevention of money laundering and finance of terrorism implemented by the obligated subjects subject to its control. For these purposes, they are empowered to supervise, monitor and inspect such entities. The refusal to cooperate or obstruction of inspections by the obliged subjects may result in penalties by the UIF, CNV or the Central Bank. Both UIF Resolution No. 30/2017, as amended, as well as the Central Bank regulations require banks to take certain minimum precautions to prevent money laundering.

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. 135/2016, which strengthened the regulations regarding 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 Financial Information Unit or the Asset Recovery Network of the Financial Action Task Force of Latin American.

On January 11, 2017, the UIF published Resolution No. 4/2017, 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.

In addition, the Argentine tax amnesty law (Law 27,260 and its regulatory decree No. 895/16, as amended) (the “Tax Amnesty Law”) provided that the information that has been voluntarily disclosed may be used for investigating and sanctioning crimes of money laundering and finance of terrorism. To this end, the UIF is authorized to inform other public intelligence agencies about investigations, based on a previous resolution of the president of the UIF and provide those agencies with information that evidences crimes of money laundering and/or financing of terrorism. In the same way, the AFIP is obliged to report to the UIF any suspicious transactions detected in the context of the Tax Amnesty Law and to provide all the information that the UIF requires, not being able to invoke fiscal confidentiality.

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In November 2018, the UIF passed Resolution No. 134/2018, which updates the list of persons considered to be “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. Also, during 2019, the UIF issued Resolution No. 15/2019, which modified the PEP list and Resolution 128/19 established that foreign PEPs will be considered high risk and therefore subject to reinforced due diligence measures, with some exceptions.

On December 26, 2018, the UIF published UIF Resolution No. 154/2018, which amended the supervision procedures then in effect providing for new procedures consistent with and conforming to the international standards promoted by the Financial Action Task Force (“FATF”), which shall be applied in accordance with a risk-based approach.

In July 2019, by Decree No. 489/2019, the Executive Branch 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. RePET is empowered to provide public access and guarantee the exchange of information with the 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.

In turn, on November 14, 2019, by means of General 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 Law on Prevention of Money Laundering and in the Regulations on Money Laundering in the Capital Market Scope. Among the new obligated subjects were included crowdfunding platforms, global investment advisory agents and human or legal persons acting in the placement of mutual funds or other collective investment products.

On November 17, 2019, through Resolution No. 117/2019, the UIF updated the minimum thresholds above which reporting entities must carry out the enhanced control and due diligence requirements established by the applicable anti-money laundering and anti-terrorist financing regulations. This measure aims to "contribute to an efficient prevention of money laundering and terrorist financing" from a risk-based approach, in accordance with international standards promoted by the FATF.

On October 21, 2021, the UIF issued Resolution 112/2021, whereby it establishes the measures and procedures that the regulated entities listed in Article 20 of the Money Laundering Prevention Law must observe to identify the beneficial owner of the customer in question. In this sense, such Resolution 112/2021 established that the beneficial owner shall be considered the human 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 human person who by other means exercises the final control of the same.

On January 13, 2022, the UIF issued Resolution 6/2022. Pursuant to such resolution, the profile to be prepared by each obliged subject shall be based on the understanding of the purpose and expected nature of the commercial relationship, the transactional information and the documentation related to the economic, equity, financial and tax situation provided by the client or obtained by the obliged subject itself.

On April 11, 2022, pursuant to Resolution 50/2022, the UIF updated the thresholds for obliged subjects to perform due diligence measures on their clients and systematic transaction reports. Lastly, on February 1, 2023 the UIF issued Resolution 14/2023. Such resolution established the minimum requirements for the identification, evaluation, monitoring, administration and mitigation of money laundering and terrorist financing risks that the obliged subjects must adopt and apply, including the obligation to prepare a risk self-assessment technical report and a risk tolerance statement.

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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.gov.ar, the UIF’s website: www.uif.gov.ar and the Central Bank’s website: www.bcra.gov.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 offenses against the public administration and cross-border bribery committed by, among others, of their shareholders, 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 6, 2018, the executive branch of the Argentine Government 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 will establish the guidelines to comply with the Corporate Criminal Liability Law’s provisions related to the Integrity Program. On October 4, 2018, the Anticorruption Office issued Resolution No. 27/2018, 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

Pursuant to Article 4 of our by-laws, 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 hydrocarbons and any byproducts thereof belonging to the Company or to third parties, either liquid, solid or gaseous; 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 by-products. (b) Commercial: Commercial transactions by importing, exporting, selling and purchasing, transporting, storing and distributing products, subproducts and goods related to electric power, mining production, 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 personal 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 own name or for the benefit of third parties. To such end, we have full legal capacity to acquire rights and incur obligations and to carry out any such acts as are not prohibited by the laws or our bylaws, including, without limitation, guaranteeing any obligations of our company or any third party.

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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 BCL, 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 BCL, 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 BCL, 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 BCL.

  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 BCL 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 BCL 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 BCL 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.

Dividends

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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 BCL);

(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 BCL, 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. Is considered to be duly authorized: (i) the legal representative of the company in Argentina, (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 BCL, 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 BCL, 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 BCL), 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 physically 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 BCL. 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.

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.

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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.

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 such law. Additionally, pursuant to our audit committee charter, our audit committee is responsible for approving, by a vote of only its independent members, any proposal related to the remuneration and compensation of our directors and executive officers, before any proposal, which is always non-binding, is submitted by our Board of Directors to the shareholders for their consideration. Any proposal for remuneration or compensation that is not approved by our audit committee cannot be submitted by the Board of Directors to our shareholders. Annual compensations must comply with our Compensation Policy prior to its approval by the board.

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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” 7490 (as amended, the "FX Regulations”).

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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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 under which the foreign exchange regulations allow access to the MLC for the transfer abroad of foreign currency from profits and dividends;

(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 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 cases, (e) 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, including that the funds have been used to finance projects within the "Plan for the Promotion of Argentine Natural Gas Production - Supply and Demand Scheme 2020-2024" established in Article 2 of Decree No. 892/20 (as detailed below), (f) 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) 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, (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, (d) issues made beginning on October 9, 2020 of debt securities with public registration in the country, denominated in foreign currency and whose services are payable in foreign currency in the country, to the extent that their average life is not less than 2 (two) years and their delivery to creditors has allowed reaching the refinancing parameters set forth in point 3. 17. of the FX Regulations, (e) issues made beginning on January 7, 2021 of debt securities with public registration in the country denominated in foreign currency and whose services are payable in foreign currency in the country, as long as that they were delivered to creditors to refinance pre-existing debts with an extension of the average life, when it corresponds to the amount of capital refinanced, the interest accrued up to the refinancing date and, to the extent that the new debt securities do not mature before January 1, 2023, the amount equivalent to the interest that would accrue up to December 31, 2022 on the indebtedness that is refinanced early and/or on the deferral of the refinanced principal and/or on the interest that would accrue on the amounts refinanced in that way;

(v) 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;

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(vi) 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 paied with the income from financial indebtedness abroad, (c) pre-cancellation of interest within the framework of a debt security exchange process, (d) pre-cancellation within the framework of a refinancing process under the terms set forth in item 3.17. of the FX Regulations;

(vii) the computation of the amount of purchases of foreign currency made by individuals in order to cancel debts between residents, including the cancellation of financing granted by local financial entities for the consumption in foreign currency made through credit or purchase cards, as of the following calendar month and for the subsequent months that may be necessary to fulfill the amount acquired as from September 1, 2020, shall be deducted from the limit set forth in item 3.8. of the FX Regulations. FX Regulations for the purchase of foreign currency by individuals for the formation of foreign assets, the remittance of family assistance and for operations with derivatives;

(viii) the authorization for the payment of capital and interest services as of their maturity through the application of collections of exports of goods and services, to the extent that the requirements set forth in section 7.9. of the FX Regulations, of the issuance of debt securities with public registry in the country, denominated in foreign currency and whose services be payable in foreign currency in the country, are complied with;

(ix) 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;

(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; likewise, the same restriction was established for resident individuals when it exceeds the equivalent of US$200 per month under certain conditions and limitations; certain exceptions were included, such as the purchase of foreign currency by resident individuals to be applied simultaneously to the purchase of real estate in the country with mortgage loans or the purchase of foreign currency by residents with specific application; and the need for non-residents to obtain the prior approval of the BCRA for access to the foreign exchange market, except for certain cases;

(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) 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 by local central securities depositories for funds received in foreign currency for capital services and income from National Treasury securities, whose operation is part of the payment process at the request of the foreign central securities depositories, (c) transfer of foreign currency abroad by individuals from their local accounts in foreign currency to remittance accounts abroad for up to the equivalent of US$ 500 (five hundred Dollars) in the calendar month and in the group of entities, provided that the entities have a sworn statement from the customer that the purpose of the transfer is to collaborate with the maintenance of Argentine residents who have had to stay abroad due to the measures adopted within the framework of the Covid-19 pandemic, (d) 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, 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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(xiii) as regards the cancellation of foreign commercial lines of credit by financial entities, such entities will have access to the MLC for the cancellation as of the maturity date of commercial lines of credit granted by foreign financial entities and applied to the financing of export or import operations of residents; however, the cancellation of lines of credit for the financing of import operations of goods will be additionally subject to the specific conditions set forth in item 10. 7. of FX Regulations; likewise, they may also have access to precancel such credit lines to the extent that the financing granted by the local entity has been precanceled by the debtor, while the access to the MLC by the customers for the precancellation of such financing shall require the prior approval of the BCRA.

In turn, Section 3.16. of FX Regulations established complementary requirements in connection with outflows through the MLC, the most important provisions include:

(i) the informative regime of "Advance of Exchange Transaction" by means of which the entities must submit to the BCRA, at the close of each day and 2 business days in advance, the information on transactions to be carried out at the request of customers or own transactions of the entity as a customer, which imply an access to the MLC for a daily amount equal to or greater than the equivalent of US$ 10.000 (ten thousand Dollars) for each of the three business days counted as of the first reported day (without taking into account the accesses for the cancellation of financing from local entities for consumption in foreign currency by means of credit or purchase cards);

(ii) 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 have liquid foreign assets available at the beginning of the day on which it requests access to the market for an amount greater than US$ 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 in investment managers located abroad, crypto-assets, funds in accounts of payment service providers, etc.), and excluding those 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 in investment managers located abroad, crypto-assets, funds in accounts of payment service providers, etc.), and excluding those investments in accounts in financial institutions located abroad), 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 foreign debt contracts or funds constituted as guarantee for derivative transactions arranged abroad; provided that in the event that the client has liquid foreign assets available for an amount greater than the aforementioned amount, the entity may also accept a sworn statement from the client stating that such amount is not exceeded when considering that, partially or totally, such assets were used during that day to make payments that would have had access to the MLC, were transferred in favor of the client to a correspondent account of a local entity authorized to operate in foreign exchange, are funds deposited in foreign bank accounts originating from collections of exports of goods and/or services or advances, pre-financing or post-financing of exports of goods granted by non-residents, or from the sale of non-produced non-financial assets for which the period of 5 business days has not elapsed since their receipt, and/or are funds deposited in foreign bank accounts originated in financial indebtedness abroad and their amount does not exceed the equivalent to be paid for principal and interest in the next 365 calendar days, and the client must expressly state in this last affidavit the value of its liquid foreign assets available at the beginning of the day and the amounts assigned to each of the situations described above and that are applicable, and (b) it undertakes to settle in the MLC, within 5 business days of making them available, those funds it receives abroad originated from the collection of loans granted to third parties, the collection of a time deposit or the sale of any type of asset, when the asset has been acquired, the deposit constituted or the loan granted after May 28, 2020;

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(iii) the need for BCRA´s prior authorization to access the MLC, 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 or transfers thereof to depository institutions abroad or the acquisition in the country with settlement in pesos of securities issued by non-residents (settled as of October 29, 2021), and (b) undertakes not to arrange sales in the country with settlement in foreign currency of securities issued by residents or exchange of securities issued by residents for foreign assets or transfers thereof to depository institutions abroad or the acquisition in the country with settlement in pesos of securities issued by non-residents as of the time access is required and for 90 days thereafter. Also, in cases where the client is a legal entity, it requires the submission of an additional sworn statement stating: (1) the detail of the human or legal persons exercising direct control over the client, according to the Large Exposures to Credit Risk rules of the BCRA; and (2) that on the day on which access to the MLC is required and in the previous 90 running days no funds in local currency or other liquid local assets were delivered in Argentina, to any human or legal person exercising direct control, except those directly associated with habitual transactions for the acquisition of goods and/or services. The requirement indicated in item (2) may be deemed to be complied with if the customer submits a sworn statement regarding transactions with securities of each of those human or legal persons, pursuant to the exchange regulations in force;

(iv) the need for BCRA´s prior authorization in the event that the customer is a person or legal entity included by the AFIP in the base of invoices or equivalent documents qualified as apocryphal, this requirement not being applicable for the access to the MLC related to the cancellations of financing in foreign currency granted by local financial entities, including payments for consumption in foreign currency made through credit or purchase cards; and

(v) the obligation of individuals and legal entities considered obligated parties to complete the "Register of foreign exchange information of exporters and importers of goods" through the application established for such purpose, and the need for the entity to have the prior approval of the BCRA to grant access to the MLC to those obligated parties to complete the "Register of foreign exchange information of exporters and importers of goods" whose process is recorded as "NOT REGISTERED", This requirement does not apply to access to the MLC for the cancellation of foreign currency financing granted by local financial entities, including payments for foreign currency consumption made through credit or purchase cards. The Company has been declared by the BCRA as an obliged subject and as of the date of this annual report it has already completed its registration in such registry.

Likewise, in the FX Regulations, the BCRA established certain provisions regarding the refinancing of principal maturities of foreign currency liabilities until December 31, 2023 (this period has been extended by Communication “A” 7621). In this regard, and except for certain cases, (i) debtors that have scheduled principal maturities until December 31, 2023 for foreign financial indebtedness of the non-financial private sector with a creditor that is not a related counterparty of the debtor, foreign financial indebtedness for own operations of the entities, and issuances of debt securities with registration of the debtor, must submit to the BCRA a detail of a refinancing plan, (ii) the refinancing plan to be submitted must be based on certain criteria, which establish that the net amount for which the foreign exchange market will be accessed in the original terms shall not exceed 40% of the principal amount maturing, and that the remaining principal has been, at least, refinanced with a new foreign indebtedness with an average life of 2 years; (iii) the customer must select an entity authorized to carry out this type of transactions in the MLC to submit the refinancing plan in its name to the BCRA's front desk, stating that it is addressed to the Foreign Exchange and Foreign Exchange Main Management, (iv) the refinancing plan must be submitted to the BCRA at least 30 calendar days before the maturity of the principal to be refinanced, (v) the settlement requirement for the cancellation of principal and interest with access to the MLC will be considered fulfilled for the issuance of debt securities with public registration in the country, denominated in foreign currency and whose services are payable in foreign currency in the country, or with public registration abroad, to the extent that they have been issued as of October 9, 2020, with an average life of not less than 2 years and their delivery to the creditors has allowed reaching the refinancing parameters described herein, and (vi) to the extent that the parameters and conditions set forth in the applicable regulations have been met, the application of foreign currency collections for exports of goods and services of the following transactions will be allowed (a) issuances of debt securities with public registration in the country denominated in foreign currency and whose services are payable in foreign currency in the country or issuances of debt securities with public registration abroad, made as of October 9, 2020 with an average life of not less than 2 years and that were delivered to creditors of refinanced debts, (b) financial indebtedness abroad, whose funds have been paid in and settled through the foreign exchange market beginning on October 16, 2020, (c) issues of debt securities with public registration in the country denominated in foreign currency that comply with the conditions set forth in point 3. 6.1.3. of the FX Regulations and whose funds have been settled in the MLC as of October 16, 2020, and (c) repatriation of direct investments of non-residents in companies that are not controlling companies of local financial entities whose funds have been deposited and settled in the MLC as of October 16, 2020.

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On the other hand, the FX Regulations establishes other specific provisions related to (i) transactions with credit, purchase, debit and prepaid cards, (ii) transactions made through the Local Currency System (SML), and (iii) transactions with securities. In particular, with respect to item (iii) above, it establishes (a) that securities transactions arranged abroad may not be settled in Pesos in the country, and only those transactions arranged in the country may be settled in Pesos in the country, and (b) that the beneficiaries of refinancing of certain credits granted within the framework of the pandemic may not arrange sales in the country with settlement in foreign currency of securities issued by residents or exchanges of securities issued by residents for foreign assets or transfer them to depository institutions abroad or the acquisition in the country with settlement in Pesos of securities issued by non-residents, as well as beneficiaries of “Créditos a Tasa Cero”, “Créditos a Tasa Cero Cultura” or “Créditos a Tasa Subsidiada para Empresas” ( “Zero Rate Loans”, “Zero Rate Loans for Culture” or “Subsidized Rate Loans for Businesses”), or beneficiaries of financing in Pesos included in Communication “A” 6937, “A” 7006 and complementary rules, among others; until their total cancellation. The foregoing is not applicable to transfers of securities to foreign depositary entities made by the client in order to participate in an exchange of debt securities issued by the Argentine Government, local governments or resident issuers of the private sector.

In line line with the provisions of Decree No. 892/2020 with respect to transactions intended to finance projects under the Plan Gas.Ar, the BCRA issued Communication “A” 7168, which is currently part of the Official Gazette. The BCRA issued Communication "A" 7168, which is currently part of the FX Regulations, providing 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.

Additionally, the FX Regulations establishes that access to the MLC for the payment of imports of certain goods will require the prior authorization of the BCRA, unless certain situations are verified, such as the presentation of a sworn statement from the client that the total amount of payments associated to imports of goods processed through the MLC does not exceed US$ 250.000; or it is a deferred payment of imports of goods that correspond to operations that have been shipped as of July 1, 2020 or that having been shipped previously had not arrived in the country before that date; or it corresponds to a payment at sight of or of commercial debt without registration of customs entry for the import of inputs to be used in the manufacture of goods in the country.

The FX Regulations establishes that the certifications issued for liquidations of new financial indebtedness from abroad may be used to access the foreign exchange market for the payments of:

i. imports of goods without the prior approval of the BCRA;

ii. services provided to related counterparties without the prior approval of the BCRA, in cases in which the payment shall be made due to the maturity date of an obligation for a service given at least 180 calendar days before the access to MLC or derived from a contract signed with a similar anticipation; and

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iii. principal amounts, prior to the maturity date of commercial debts for the importation of goods and services contemplated in point 10.2.4., as long as the average life of the new financial indebtedness is at least 2 (two) years longer than the average life remaining of the prepaid indebtedness.

On July 14, 2022, the BCRA introduced some adjustments to FX Regulations. Among others, it reduced to 60 calendar days the deadline for payment of services contracted to non-residents by companies in the energy sector to meet their operational needs.

On July 21, 2022, the BCRA through Communication "A" 7552, modified the complementary requirements for foreign exchange outflows. The holding of Argentine Depositary Receipts (CEDEAR) was included in the availability limit of US$100,000 for those who wish to access the MLC. Likewise, it established that these instruments cannot be traded neither in the 90 days prior to, or the 90 days following the access to the foreign exchange market.

On August 5, 2022, the BCRA modified the deadlines for the entry and settlement of foreign currencies corresponding to advances, pre-financing and post-financing of foreign exports, adding that the term will be extended to 180 calendar days from the date of collection or disbursement abroad, provided that certain requirements are met.

On September 15, 2022, the Central Bank issued Communication "A" 7606. Through this communication, it was stipulated that users of public utilities who requested and obtained the subsidy on the tariffs derived from the supply of natural gas and/or electric energy through the network, as well as those that have obtained it automatically, and those that maintain the subsidy in the potable water tariffs, as long as they maintain the mentioned benefit, will not be able to: (i) access the foreign exchange market for purchases of foreign currency by individuals for the formation of foreign assets of residents, remittance of family assistance and derivative transactions; or (ii) carry out the transactions set forth in items 3.16.3.1. and 3.16.3.2. of the "Foreign Exchange" regulations pursuant to Communication "A" 7490.

By means of Joint General Resolution No. 5271/2022, dated as of October 11, 2022, the AFIP and the Trade Secretariat (i) implemented the Import System of the Argentine Republic (“Sistema de Importaciones de la República Argentina”, or “SIRA”) and the Import System of the Argentine Republic and Payment of Services Abroad (Sistema de Importaciones de la República Argentina y Pagos de Servicios al Exterior, or “SIRASE” and, together with SIRA, the "Systems"), (ii) terminated the Import Information and Monitoring System (“SIMI”) and the Integral System for Monitoring Foreign Payments of Services (“Sistema Integral de Monitoreo de Pagos al Exterior” or “SIMPES”); and (iii) created the Single Current Account for Foreign Trade (the “Account"). The Systems and Account became effective on October 12, 2022.

On the same date, the BCRA issued Communication "A" 7622 to adapt the FX Regulations to the new Systems and the Account. The BCRA provided that entities may access the MLC for the payments of import of goods to operations associated with a declaration in the Import System of the Argentine Republic (SIRA), to the extent that any of the following situations take place: (i) the payment is made once the term has expired in calendar days, counted from the date of registration of customs entry of the goods, which appears in the SIRA declaration, (ii) the payment is made through an exchange and/or arbitration against a local account in foreign currency of the client and in the SIRA declaration it has been recorded that such option would be used, or (iii) that the imported supplies correspond to the enumeration provided in Section 8 of Communication “A” 7622.

Likewise, entities may access the MLC to make payments of import of goods to operations associated with a SIRA declaration before the term established in said declaration expires, to the extent that the operation is validated in the Account; the remaining applicable regulatory requirements are met; and the payment falls under any of the situations detailed in Communication "A" 7622 (as amended by Communication “A” 7626 and Communication “A” 7629).

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.gov.ar. The information contained on these websites is not part and shall not be deemed incorporated into this annual report.

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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.

Argentine Tax Considerations Capital gains tax

Resident individuals

The 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 the 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 presumed net basis on which the 35% rate should apply is assessed at 90% (being the effective rate 31,5% on the gross sale price). The non-cooperating jurisdictions list is prepared and published by the executive branch. 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.

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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: (i) a first tier with a 25% rate for accumulated net income up to $5 million; (ii) the second tier of 30% for accumulated net income over $5,000,000 and up to $50,000,000, plus a fixed amount of $1,250,000; and (iii) a third tier of 35% for accumulated net income over $50,000,000, plus a fixed amount of $14,750,000. The new tax rate structure is aplicable for the fiscal year starting on January 1, 2021 and the amounts comprehended in the referred scale is adjusted annually since January 1st, 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.

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.

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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 AFIP the agreements supporting the transactions.

Equalization income tax

Equalization income tax -established by Income Law, art. 74- will not be applicable on profits generated on or after January 1, 2018.

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 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.

Tax and accounting revaluation

Tax Reform established the possibility of upgrading certain assets that are part of the assets of taxpayers, in order to update their value, since the period of acquisition until December 31, 2017.

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This revaluation was optional, and the amount of revaluation was taxable at special rate 8% to 15%, depending on the type of property to be revalued. We paid an special revaluation tax of Ps. 1.495 million and have updated the value of certain assets for an amount of Ps.15,311 million.

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.

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 6% 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.

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% and 9% 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.

The potential investors of the ADs should consult their own tax advisers about the effects of the aforementioned tax according to their particular circumstances.

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Solidarity and Extraordinary Contribution to help mitigate the effects of the pandemic

On an emergency basis and for only one time, the Argentine Government imposed an extraordinary, obligatory contribution which falls on the assets of certain individuals and undivided estates in existence at the date of entry into force of Law No. 27,605 (i.e. December 18, 2020) (the “Extraordinary Contribution”).

The aforementioned Extraordinary Contribution applies to:

a) Argentine resident individuals and undivided estates, for the totality of their assets located in the country and abroad. Also included are those individuals of Argentine nationality whose domicile or residence is in “non-cooperative jurisdictions” or “no tax-or-low-tax jurisdictions” according to the terms of the ITL (Income Tax Law)

b) Individuals and undivided estates residing abroad (except those mentioned in the previous point) for the totality of their assets located in the country.

For the purposes of this Extraordinary Contribution, the applicable residence is the subject’s residence as of December 31, 2019 according to the provisions of the ITL.

In both cases, these subjects will be exempted from this Extraordinary Contribution when the total value of their assets, included and valued according to the Personal Assets Tax Law terms, regardless of the treatment they have against such tax and without any non-taxable minimum threshold deduction, does not exceed Ps. 200,000,000, inclusive.

For those mentioned in point a), the taxable base of this Extraordinary Contribution will be determined considering the total value of their assets in the country and abroad, including contributions to trusts or foundations of private interest and other similar structures, participations in companies or other entities of any type without fiscal personality and direct or indirect participations in companies or other entities of any type, existing at the date of entry into force of this law.

The Extraordinary Contribution to be paid will be determined on the basis of a scale and rates varying from 2 to 5.25%, depending on (i) the total value of the assets and (ii) their location. The differential rate between assets located abroad and those located in the country shall be eliminated if part of these assets are repatriated within a certain period of time and to the extent those funds remain until December 31st, 2021 deposited in a bank account under the name of the holder or are affected, once this deposit is made, to one of the destinations established by the National Executive Branch and AFIP General Resolution No. 4930/2021.

Individuals, sole proprietorships or estates established in the country that possess, use, dispose, own, custody or keep assets subject to the Extraordinary Contribution pertaining to individuals and undivided states that reside abroad, must act as surrogate taxpayers for purposes of such contribution.

Note that although the Solidarity and Extraordinary Contribution was conceived as a one-time tax on assets existing as of December 18, 2020, it is important to mention that in Argentina there are several taxes that have been created on an exceptional basis and for a limited time, and were later extended for additional periods.

Holders of ADSs should consult with their own tax advisers on the Extraordinary Contribution considering 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, Germany, Italy, Mexico, Norway, Qatar, Russia, Spain, Sweden, Switzerland, The Netherlands, 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 with Turkey, China, Luxembourg, Japan and Austria, but they are still pending approval by the Argentine Congress. In turn, tax treaties are being negotiated with Colombia 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.

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Value Added Tax (VAT)

Investments Tax Returns

The return of tax credits originated in investments in fixed assets will be given, in cases that, six months after their payment, have not been absorbed by fiscal debits generated by the activity.

Tax on Fuels

The Fuel tax scheme is modified, incorporating a tax on carbon dioxide emissions. The same tax pressure existing before the reform will be maintained.

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 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:

· 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;

· 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;

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· 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 companies that are passive foreign investment companies (“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.

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 with respect to our 2021 and 2022 taxable years. 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 2023 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.

Except where otherwise noted, the remainder of this summary assumes that we were not a PFIC for our 2022 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. Subject to certain exceptions for short-term (60 days or less) positions, 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.” 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 passive foreign investment company (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 with respect to our 2021 and 2022 taxable years. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC in 2023 or future taxable years. See “—Passive Foreign Investment Company Rules,” above.

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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.

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 new requirements recently adopted by the U.S. Internal Revenue Service (“IRS”) 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. 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. 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. Under the new foreign tax credit requirements recently adopted by the IRS, any Argentine tax imposed on the sale or other disposition of the shares generally will not be treated as a creditable tax for U.S. foreign tax credit purposes. 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.

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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. U.S. holders should consult their own tax advisors regarding the application of these rules to their particular situations.

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 Internal Revenue Service 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 US$50,000 on the last day of the taxable year or US$75,000 at any time during the taxable year are generally required to file an information statement along with their tax returns, currently on 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 F-20, 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:
·       US$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
·       US$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
·       US$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, 2022.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, 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, 2022, 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).

Management has excluded Greenwind and VAR from its assessment of internal control over financial reporting as of December 31, 2022 because they were acquired by the Company during the year 2022. In the aggregate, the entities incorporated as business combinations constitute 5.8% of our consolidated assets and 0.6% of consolidated revenues as of and for the year ended December 31, 2022.

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Based on such evaluation, Management concluded that our internal control over financial reporting was effective as of December 31, 2022. The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by Price Waterhouse & Co S.R.L., an independent registered public accounting firm, as stated in their report which appears herein.

(c) Attestation Report of the Registered Public Accounting Firm

Reference is made to the report of the 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

Dario Epstein, 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

The Business Code of Conduct was approved and updated by our Board of Directors on December 20, 2021, which applies to all of 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”). Our Business Code of Conduct is posted, in both English and Spanish, on our website at https://ri.pampaenergia.com/en/corporate-governance/code-of-business-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, 2022 and 2021. 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,
	2022	2021
	(in million US$)
Audit Fees (1)	1.9	1.2
Audit-related Fees (2)	-	-
Tax Fees (3)	-	-
Other non-audit Fees	-	-
Total	1.9	1.2

(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.

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

199 

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 or any of its subsidiaries. The policy ensures that the external auditor preserves its independence and is applicable to the Company and its subsidiaries.

The Audit Committee has delegated to one of its members the authority to grant pre-approvals to auditors. The decision of that member to pre-approve a service is presented to the full audit committee at each of its scheduled 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 US$ 10,000 separately nor US$ 50,000 cumulatively per fiscal year and ii) tax services not exceeding US$5,000 separately nor US$25,000 cumulatively per fiscal year.

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

Not applicable.

200 

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
2022	ADS	Common Shares	ADS	Common Shares	Common Shares (*)
GASA
June	118,939	-	20.78	-	2,973,475	N/A1
CISA
June	273,300	-	20.23	-	6,832,500	N/A1
July	412,730	-	20.62	-	10,318,250	N/A1

(*) Each ADS represents 25 common shares.

1 Rule 10b-18 safe harbor protection

201 

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 BCL; (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:

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.

202 

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 Resolution UIF Nº 30/2011 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 BCL.

203 

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.
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 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.

204 

Section 303A.07	The audit committee must have at least three members, all of whom must qualify as independent. 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.
Section 303A.08	The shareholders must be given the opportunity to vote on 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 BCL). 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.pampaenergia.com.

205 

Section 303A.10	Listed companies must adopt and disclose to the market a Code of Ethics and Business Conduct which is applicable to their directors, officers and employees. 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.
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. Finally, listed companies must file an annual statement and updated reports with the NYSE disclosing any changes in the composition of their board of directors or any of the committees described in Section 302A of the NYSE LCM.	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.

206 

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. 22595514) on February 7, 2022 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
8.1	List of significant subsidiaries of Pampa
12.1	Certification of Gustavo Mariani, Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
12.2	Certification of Nicolás Mindlin, 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 Gaffney, Cline & Associates Inc., dated January 19, 2023.
13.3	Consent of Gaffney, Cline & Associates.
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.

207 

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/ Nicolás Mindlin
	Name: Nicolás Mindlin Title: Chief Financial Officer

Date: April 28, 2023

208 

CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2022 AND 2021

FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020

(In millions of U.S. dollar (“US$”))

F-1

INDEX TO FINANCIAL STATEMENTS

Pampa Energía S.A.

Consolidated Financial Statements as of December 31, 2022 and 2021, and for the Years Ended December 31, 2022, 2021 and 2020
Report of Independent Registered Public Accounting Firm (PCAOB ID 1349)	F-3
Consolidated Statement of Comprehensive Income	F-13
Consolidated Statement of Financial Position	F-15
Consolidated Statement of Changes in Equity	F-17
Consolidated Statement of Cash Flows	F-19
Notes to the Consolidated Financial Statements	F-20

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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with International Financial Reporting 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, 2022, 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, 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.

Price Waterhouse & Co. S.R.L., Bouchard 557, 8^th floor, C1106ABG - Autonomous City of Buenos Aires

T: +(54.11) 4850.0000, www.pwc.com/ar

F- 3

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Greenwind S.A. and Vientos de Arauco Renovables S.A.U. from its assessment of internal control over financial reporting as of December 31, 2022 because they were acquired by the Company in purchase business combinations during 2022. We have also excluded Greenwind S.A. and Vientos de Arauco Renovables S.A.U. from our audit of internal control over financial reporting. Greenwind S.A. and Vientos de Arauco Renovables S.A.U. are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 5.8%% and 0.6%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022.

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.

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.

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.

F-4

 

 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 and 11.2 to the consolidated financial statements, as of December 31, 2022, the Company’s consolidated net book value of property, plant and equipment balance of the oil and gas segment was $807 million, the goodwill balance allocated to the oil and gas segment was $35 million, and depreciation expense for the year ended December 31, 2022 was $125 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 the areas of oil and gas, 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 and 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. Periodic revisions to the estimated oil and gas reserves and related future net cash flows may be necessary as a result of changes in a number of factors, related to reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors. 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 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.

F-5

 

 Impairment of Non-Financial Long-Lived Assets Related to the Rincón del Mangrullo cash generating unit of the Oil and Gas Segment

As described in Note 7 to the consolidated financial statements, as of December 31, 2022, the Company’s consolidated property, plant and equipment balance of the oil and gas segment was $807 million. According to Notes 6.1.1. and 11.1.1.2, as of December 31, 2022 there were internal and external impairment indicators in relation to Rincón del Mangrullo cash generating unit (CGU). Management analyzes the recoverability of its non-financial long-lived assets on a periodic basis or when events or changes in circumstances indicate their recoverable amount may be below its carrying amount. In order to evaluate if there is evidence that a CGU could be affected, both external and internal sources of information are analyzed. The recoverable amount is the higher of value in use and fair value less costs of disposal. 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 on the CGU, using discount rates that considers 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 significant judgments and assumptions relating to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation and exchange rates, the discount rate, among others.

The principal considerations for our determination that performing procedures relating to the impairment of non-financial long-lived assets related to the Rincón del Mangrullo CGU of the oil and gas segment is a critical audit matter are the significant judgment by management when evaluating the existence 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 significant assumptions related to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation, exchange rates 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.

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 impairment assessment, including controls over the valuation of the Company’s non-financial long-lived assets. These procedures also included, among others, 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 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 significant assumptions used by management related to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation and exchange rates, 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 segments, (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.

F-6

 

Acquisitions of Vientos Solutions S.L.U. and Vientos de Arauco Renovables S.A.U. - Valuation of Identifiable Intangible Assets

As described in Notes 4.4.5, 5.1.3 and 5.1.5 to the consolidated financial statements, during the year ended December 31, 2022, the Company completed the acquisitions of (i) Vientos Solutions S.L.U. (“VS SLU”), a company whose principal asset is its 50% interest in the capital stock of Greenwind S.A. (“Greenwind”), for aggregate consideration of US$20.5 million, of which approximately $31.6 million was allocated to an identifiable intangible asset and (ii) Vientos de Arauco Renovables S.A.U. (“VAR”) for aggregate consideration of US$121.4, of which approximately $62.3 million was allocated to an identifiable intangible asset. Management applied significant judgment in estimating the fair value of the identifiable intangible assets acquired, which involved the use of significant estimates and assumptions with respect to the projected generation level and the discount rate.

The principal considerations for our determination that performing procedures relating to the acquisitions of VS SLU and VAR – valuation of identifiable intangible assets is a critical audit matter are: (i) the significant judgment by management in developing the fair value of the identifiable intangible assets acquired, which in turn led to a high degree of auditor judgment and subjectivity in applying procedures relating to management’s fair value estimate; (ii) the significant audit effort in evaluating management’s significant assumptions related to projected generation level and discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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 acquisition accounting,

F-7

 

including controls over management’s valuation of the identifiable intangible assets acquired and controls over development of the assumptions related to the projected generation level and discount rate. These procedures also included, among others, (i) reading the purchase agreement; (ii) testing management’s cash flow projections used to estimate the fair value of identifiable intangible assets, which included evaluating the reasonableness of significant assumptions used by management related to the projected generation level and the discount rate. Evaluating the reasonableness of the projected generation level involved considering the past performance of the acquired businesses, as well as economic and industry public information. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of valuation method and the reasonableness of the discount rate. The discount rate was evaluated by considering the cost of capital of comparable businesses and other industry factors. The procedures performed also included evaluating the sufficiency of the information disclosed in the consolidated financial statements regarding business combination.

/s/ PRICE WATERHOUSE & CO. S.R.L.

/s/ Carlos Martin Barbafina (Partner)

Autonomous City of Buenos Aires, Argentina, March 9, 2023.

We have served as the Company’s auditor since 2006.

F-8

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
AFIP	Federal Administration of Public Revenue
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.
CISA	Comercializadora e Inversora S.A
Citelec	Compañía Inversora en Transmisión Eléctrica Citelec S.A.
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
CTLL	Loma La Lata thermal power plant
EcuadorTLC / PB18	EcuadorTLC S.A. (currently Pampa Bloque 18)
Edenor	Empresa Distribuidora y Comercializadora Norte S.A.
EMESA	Empresa Mendocina de Energía S.A:
ENARGAS	National Regulator of Gas

F-9

 

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
ENARSA / IEASA	Integración Energética Argentina S.A. (before Energía Argentina S.A.)
ENRE	National Regulatory Authority of Electricity
GASA	Generación Argentina S.A.
Greenwind	Greenwind S.A.
GU	Large users
GU300	Large users with demand greater than 300 kW
GUDI	Distributors’ large users
GyP	Gas y Petróleo del Neuquén S.A.P.E.M.
HI	Hydroelectric
HIDISA	Hidroeléctrica Diamante S.A.
HINISA	Hidroeléctrica Los Nihuiles S.A.
IAS	International Accounting Standards
IASB	International Accounting Standards Board
IFRIC	International Financial Reporting Interpretations Committee
IFRS	International Financial Reporting Standards
INDEC	National Institute of Statistics and Censuses
IPIM	Wholesale Domestic Price Index
LGS	Argentine Business Organizations Law
LNG	Liquefied Natural Gas
MAT	WEM’s Forward Market
MATER	Renewable Energy Forward Market
MBTU	Millon of BTU
MEyM	Ministry of Energy and Mining
MLC	Foreign Exchange Market
MW	Megawatt
NYSE	New York Stock Exchange

F-10

 

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
OCP	Oleoductos de Crudos Pesados Ltd
OCPSA	Oleoductos de Crudos Pesados S.A.
Oldelval	Oleoductos del Valle S.A.
PE Arauco	Arauco Wind Farm
PEB	Pampa Energía Bolivia S.A. (formerly “PBI” - Petrobras Bolivia Internacional S.A.)
PEN	Federal Executive Branch
PEPE II	Pampa Energía II Wind Farm
PEPE III	Pampa Energía III Wind Farm
PEPE IV	Pampa Energía IV Wind Farm
PEPE VI	Pampa Energía VI Wind Farm
Petrobras	Petrobras Argentina S.A.
PISA	Pampa Inversiones S.A.
Refinor	Refinería del Norte S.A.
RTI	Tariff Structure Review
RTT	Transitional Tariff Regime
SACDE	Argentine Society of Construction and Strategic Development
SE	Secretary of Energy
SEC	Security and Exchange Commission
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.

F-11

 

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
TV	Vapor Turbine
US$	U.S. dollar
VAR	Vientos de Arauco Renovables S.A.U.
VAT	Value Added Tax
VRD	Debt securities
VS SLU	Vientos Solutions S.L.U.
WACC	Weighted Average Cost of Capital
WEM	Wholesale Electrical Market
YPF	YPF S.A.
$	Argentine Pesos

F-12

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

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

(In millions of US$ – unless otherwise stated)

	Note	12.31.2022	12.31.2021	12.31.2020
Revenue	8	1,829	1,508	1,073
Cost of sales	9	(1,148)	(955)	(663)
Gross profit		681	553	410
Selling expenses	10.1	(56)	(33)	(26)
Administrative expenses	10.2	(138)	(99)	(93)
Other operating income	10.3	131	105	51
Other operating expenses	10.3	(46)	(58)	(36)
Impairment of property, plant and equipment, intangible assets and inventories	11.1, 11.2 and 11.4	(38)	(4)	(139)
Impairment of financial assets		(8)	(2)	(9)
Share of profit from associates and joint ventures	5.2.2	105	117	85
Operating income		631	579	243
Financial income	10.4	5	10	9
Financial costs	10.4	(221)	(185)	(177)
Other financial results	10.4	166	(14)	84
Financial results, net		(50)	(189)	(84)
Profit before income tax		581	390	159
Income tax	10.5	(124)	(77)	(35)
Profit of the year from continuing operations		457	313	124
Loss of the year from discontinued operations	5.1.1	-	(75)	(592)
Profit (Loss) of the year		457	238	(468)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans		(9)	(3)	1
Income tax		3	1	-
Exchange differences on translation		21	22	(5)
Items that may be reclassified to profit or loss
Exchange differences on translation		39	70	(3)
Other comprehensive income (loss) of the year from continuing operations		54	90	(7)
Other comprehensive income (loss) of the year from discontinued operations	5.1.1	-	64	(33)
Other comprehensive income (loss) of the year		54	154	(40)
Total comprehensive income (loss) of the year		511	392	(508)

F-13

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Continuation)

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

(In millions of US$ – unless otherwise stated)

	Note	12.31.2022	12.31.2021	12.31.2020
Total income (loss) of the year attributable to:
Owners of the company		456	273	(367)
Non-controlling interest		1	(35)	(101)
Total income (loss) of the year		457	238	(468)
Total income (loss) of the year attributable to owners of the Company:
Continuing operations		456	312	132
Discontinued operations		-	(39)	(499)
Total income of the year attributable to owners of the company		456	273	(367)
Total comprehensive income (loss) of the year attributable to:
Owners of the Company		510	393	(393)
Non-controlling interest		1	(1)	(115)
Total comprehensive income of the year		511	392	(508)
Total comprehensive income (loss) of the year attributable to owners of the Company:
Continuing operations		510	402	124
Discontinued operations		-	(9)	(517)
Total comprehensive income (loss) of the year attributable to owners of the company		510	393	(393)
Earnings (Loss) per share attributable to equity holders of the Company
Basic and diluted earnings per share from continuing operations	13.2	0.33	0.22	0.08
Basic and diluted loss per share from discontinued operations	13.2	-	(0.03)	(0.32)
Total basic and diluted earning (loss) per share	13.2	0.33	0.19	(0.23)

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-14

 

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2022 and 2021

(In millions of US$ – unless otherwise stated)

	Note	12.31.2022	12.31.2021
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment	11.1	2,164	1,659
Intangible assets	11.2	138	38
Right-of-use assets	19.1.1	9	12
Deferred tax asset	11.3	36	84
Investments in associates and joint ventures	5.2.2	902	774
Financial assets at amortized cost	12.1	102	105
Financial assets at fair value through profit and loss	12.2	27	29
Other assets		1	1
Trade and other receivables	12.3	20	34
Total non-current assets		3,399	2,736
CURRENT ASSETS
Inventories	11.4	173	155
Financial assets at amortized cost	12.1	8	5
Financial assets at fair value through profit and loss	12.2	586	458
Trade and other receivables	12.3	470	397
Cash and cash equivalents	12.4	106	110
Total current assets		1,343	1,125
Total assets		4,742	3,861

F-15

 

CONSOLIDATED STATEMENT OF FINANCIAL POSITION (Continuation)

As of December 31, 2022 and 2021

(In millions of US$ – unless otherwise stated)

	Note	12.31.2022	12.31.2021
SHAREHOLDERS´ EQUITY
Share capital		36	36
Share capital adjustment		191	191
Share premium		516	516
Treasury shares adjustment		1	1
Treasury shares cost		(23)	(7)
Legal reserve		45	61
Voluntary reserve		968	659
Other reserves		(15)	(15)
Other comprehensive income		81	48
Retained earnings		477	295
Equity attributable to owners of the company		2,277	1,785
Non-controlling interest		7	6
Total equity		2,284	1,791
LIABILITIES
NON-CURRENT LIABILITIES
Investments in joint ventures	5.2.2	-	4
Provisions	11.5	147	141
Income tax and minimum notional income tax provision	11.6	179	188
Deferred tax liability	11.3	112	-
Defined benefit plans	11.8	28	24
Borrowings	12.5	1,340	1,359
Trade and other payables	12.6	21	12
Total non-current liabilities		1,827	1,728
CURRENT LIABILITIES
Provisions	11.5	4	5
Income tax liability	11.6	5	20
Tax liabilities	11.7	28	23
Defined benefit plans	11.8	6	5
Salaries and social security payable	11.9	32	28
Derivative financial instruments		2	-
Borrowings	12.5	273	79
Trade and other payables	12.6	281	182
Total current liabilities		631	342
Total liabilities		2,458	2,070
Total liabilities and equity		4,742	3,861

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-16

 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

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

(In millions of US$ – unless otherwise stated)

	Attributable to owners
	Equity holders of the company						Retained earnings
	Share capital	Share capital adjustment	Share premium	Treasury shares	Treasury shares adjustment	Treasury shares cost	Legal reserve	Voluntary reserve	Other reserves	Other comprehensive income / (loss)	Retained earnings (Accumulated losses)	Subtotal	Non-controlling interest	Total equity
Balance as of December 31, 2019	46	260	510	1	1	(44)	42	422	(18)	(29)	726	1,917	492	2,409
Legal and voluntary reserve constitution	-	-	-	-	-	-	19	707	-	-	(726)	-	-	-
Capital reduction	-	-	-	(9)	(59)	140	-	(72)	-	-	-	-	(19)	(19)
Treasury shares acquisition	(8)	(59)	6	8	59	(102)	-	-	-	-	-	(96)	(8)	(104)
Dividens ditribution	-	-	-	-	-	-	-	-	-	-	-	-	(9)	(9)
Loss of the year	-	-	-	-	-	-	-	-	-	-	(367)	(367)	(101)	(468)
Other comprehensive income of the year	-	-	-	-	-	-	-	-	-	(21)	(5)	(26)	(14)	(40)
Balance as of December 31, 2020	38	201	516	-	1	(6)	61	1,057	(18)	(50)	(372)	1,428	341	1,769
Legal and voluntary reserve constitution	-	-	-	-	-	-	-	(372)	-	-	372	-	-	-
Capital reduction	-	-	-	(2)	(10)	38	-	(26)	-	-	-	-	-	-
Treasury shares acquisition	(2)	(10)	-	2	10	(39)	-	-	-	-	-	(39)	-	(39)
Stock compensation plans	-	-	-	-	-	-	-	-	3	-	-	3	-	3
Sale of subsidiary	-	-	-	-	-	-	-	-	-	-	-	-	(334)	(334)
Profit (Loss) of the year	-	-	-	-	-	-	-	-	-	-	273	273	(35)	238
Other comprehensive income of the year	-	-	-	-	-	-	-	-	-	98	22	120	34	154
Balance as of December 31, 2021	36	191	516	-	1	(7)	61	659	(15)	48	295	1,785	6	1,791

F-17

 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Continuation)

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

(In millions of US$ – unless otherwise stated)

	Attributable to owners
	Equity holders of the company						Retained earnings
	Share capital	Share capital adjustment	Share premium	Treasury shares	Treasury shares adjustment	Treasury shares cost	Legal reserve	Voluntary reserve	Other reserves	Other comprehensive income	Retained earnings	Subtotal	Non-controlling interest	Total equity
Balance as of December 31, 2021	36	191	516	-	1	(7)	61	659	(15)	48	295	1,785	6	1,791
Legal and voluntary reserve constitution	-	-	-	-	-	-	(16)	311	-	-	(295)	-	-	-
Capital reduction	-	-	-	-	-	2	-	(2)	-	-	-	-	-	-
Treasury shares acquisition	-	-	-	-	-	(18)	-	-	-	-	-	(18)	-	(18)
Profit of the year	-	-	-	-	-	-	-	-	-	-	456	456	1	457
Other comprehensive income of the year	-	-	-	-	-	-	-	-	-	33	21	54	-	54
Balance as of December 31, 2022	36	191	516	-	1	(23)	45	968	(15)	81	477	2,277	7	2,284

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-18

 

CONSOLIDATED STATEMENT OF CASH FLOWS

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

(In millions of US$ – unless otherwise stated)

	Note	12.31.2022	12.31.2021	12.31.2020
Cash flows from operating activities:
Profit of the year from continuing operations		457	313	124
Adjustments to reconcile net profit to cash flows from operating activities:	14.1	307	365	380
Changes in operating assets and liabilities	14.2	(145)	(65)	(22)
Net cash generated by operating activities from discontinued operations	5.1.1	-	116	211
Net cash generated by operating activities		619	729	693
Cash flows from investing activities:
Payment for property, plant and equipment acquisitions		(416)	(206)	(124)
Payment for intangible assets acquisitions		(31)	(4)	-
Payment for public securities and shares acquisitions, net		(102)	(234)	(151)
(Subscription) Recovery of mutual funds, net		(1)	52	93
Payment for the acquisition of subsidiaries and associates		(111)	(17)	(3)
Early collection for sale of subsidiary		-	-	5
Collection for equity interests in companies sales		44	51	-
Collections for intangible assets sales		21	6	1
Dividends received		10	18	3
Collection of loans		11	26	7
Net cash used in investing activities from discontinued operations	5.1.1	-	(166)	(86)
Net cash used in investing activities		(575)	(474)	(255)
Cash flows from financing activities:
Proceeds from borrowings	12.5	308	188	353
Payment of  borrowings	12.5	(143)	(336)	(291)
Payment of  borrowings interests	12.5	(162)	(140)	(190)
Payment for treasury shares acquisition		(18)	(39)	(104)
Repurchase and redemption of corporate bonds	12.5	(28)	(3)	(110)
Payments of leases		(3)	(5)	(2)
Payments of dividends		-	-	(9)
Payments to third parties for capital reduction of subsidiaries		-	-	(19)
Net cash used in financing activities from discontinued operations	5.1.1	-	(7)	(73)
Net cash used in financing activities		(46)	(342)	(445)
Decrease in cash and cash equivalents		(2)	(87)	(7)
Cash and cash equivalents at the beginning of the year	12.4	110	141	225
Cash and cash equivalents at the beginning of the year reclasified to assets classified as held for sale	5.1.1	-	52	-
Exchange difference generated by cash and cash equivalents		(2)	4	(25)
Cash and cash equivalents at the end of the year reclasified to assets classified as held for sale	5.1.1	-	-	(52)
Decrease in cash and cash equivalents		(2)	(87)	(7)
Cash and cash equivalents at the end of the year	12.4	106	110	141

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-19

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

(In millions of US$ – unless otherwise stated)

NOTE 1: GENERAL INFORMATION

1.1 General information of the Company

The Company is a fully integrated power company in Argentina, which directly and through its subsidiaries, participates in the electric energy and gas value chains.

In the generation segment, the Company, directly and through its subsidiaries and joint ventures, has a 5,088 MW installed capacity as of December 31, 2022, which represents approximately 12% of Argentina’s installed capacity, and being one of the four largest independent generators in the country. Additionally, the Company is currently undergoing a process to expand its installed capacity by an additional 437.5 MW.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, with operations in 13 production areas and 5 exploratory areas reaching a production level of 9.8 million m3/day of natural gas and 5.3 thousand boe/day of oil in Argentina, as of December 31, 2022. Its main natural gas production blocks are located in the Provinces of Neuquén and Río Negro.

In the petrochemicals segment, operations are located in Argentina, where the Company operates 2 high-complexity plants producing styrene, synthetic rubber and polystyrene, with a domestic market share ranging between 94% and 100%.

Finally, through the holding and others segment, the Company participates in the electricity transmission and oil 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 21,697 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 9,233 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. Besides, the Company owns a 30.1% indirect interest in OCP, licensee company of an oil pipeline in Ecuador that has a transportation capacity of 450 thousand barrels/day. Additionally, the segment includes advisory services provided to related companies.

F-20

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 1: (Continuation)

1.2 Economic context

The Company operates in a complex economic context which main variables experience volatility as a result of political and economic events both in the domestic and international spheres.

At the domestic level, in the first quarter of 2022 Argentina and the International Monetary Fund reached an agreement defining tax and monetary goals for the country and agreeing on the refinancing of debt maturities. However, monthly inflation levels and depreciation of the peso against the U.S. dollar have remained high, and exchange restrictions have remained in force and even tightened (see Note 2.5), continuing to affect the foreign currency value.

At the international level, Russia’s invasion to Ukraine in early 2022 entailed an important global destabilization factor, which mainly resulted in lower growth expectations and increased inflation due to increased prices of food and energy (mainly oil and natural gas).

The increase in international energy prices may adversely affect Argentina’s fiscal balance. In this respect, it is worth highlighting that the Argentine Government, aiming to substitute fuel imports and strengthen the domestic supply, has promoted a project of the construction of the Néstor Kirchner Gas Pipeline, which would allow for increasing transportation capacity by 24 million cubic meters of gas per day through the installation and mounting of a total 1,020 km pipeline, in two stages: the first one, providing for the construction of 553 kilometers to supply the Buenos Aires metropolitan area, and the second, for the construction of 467 additional kilometers to supply large urban centers in central and northern Argentina with unconventional gas generated in the Vaca Muerta block, in the Province of Neuquén. In 2022, ENARSA tendered and awarded the different tranches making up the first stage of the gas pipeline to the companies in charge of its construction, with an estimated US$ 1,500 million cost to be financed with national treasury funds and the wealthiest segment’s solidarity contribution. As of the issuance of these Consolidated Financial Statements, the first construction stage is underway, and commissioning is expected for June 2023 —concurrently with the peak winter demand, with an associated transportation capacity of 11 million cubic meters of gas per day. In addition to the original scheme, ENARSA decided to incorporate the construction and installation of two turbochargers that would allow for increasing capacity to 20 million cubic meters of gas per day for the first stage. In parallel, the Government announced the extension of Gas Plan (see Note 2.2.4.1.2) to provide producing companies with the incentives and terms necessary to make investments allowing for the gas production increase required to inject and fill the pipeline from June 2023.

F-21

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 1: (Continuation)

Regarding the energy industry, the sustained inflation increase and increased political-economic uncertainty have affected the electricity distribution company’s payment chain, added to deferrals in the National Treasury contributions, as a result of which CAMMESA has recorded delays in payment terms to generators and hydrocarbon producers exceeding 90 days in August 2022. Moreover, on June 16, 2022, PEN Executive Order No. 332/22 established a subsidies segmentation system for electricity and natural gas utility residential customers. Under it, the Argentine Government, which currently covers an average of 70% of the cost of energy, has launched an initiative to reach fairer and more reasonable tariffs with a subsidies reduction and distribution scheme based on each household’s economic capacity, providing that the highest-income segment should verify a gradual subsidies’ reduction until fully covering the cost of energy by the end of 2022.

The Argentine economy registered a cumulative growth of 6.4% and 10.8% in the Gross Domestic Product in the third quarter of 2022 and 2021, respectively, a 94.8% and 50.9% cumulative inflation (CPI) for fiscal years 2022 and 2021, respectively, and a 72.5% and 22.1% depreciation of the peso against the U.S. dollar for 2022 and 2021, respectively, according to BNA’s exchange rate.

The context of volatility and uncertainty continues as of the date of issuance of these Consolidated Financial Statements.

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 financial statements should be read in the light of these circumstances.

NOTE 2: REGULATORY FRAMEWORK

2.1 Generation

2.1.1 Generation units

The Company’s revenues related to this segment come from: i) sales contracts with large users within the MAT (Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SE Resolution No. 31/20 as from February 2020, SE Resolution No. 440/21 as from February 2021, SE Resolution No. 238/22 as from February 2022 and SE Resolution No. 826/22 as from September 2022). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:

F-22

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

In operation as of 12.31.2022:
Generator	Generating unit	Tecnology	Power	Applicable regime (1)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1,281/06
CTG	GUEMTV11	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV12	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV13	TV	>100 MW	Resolution No. 826/22
Piquirenda	PIQIDI 01-10	MCI	30 MW	Resolution No. 826/22
CPB	BBLATV29	TV	>100 MW	Resolution No. 826/22
CPB	BBLATV30	TV	>100 MW	Resolution No. 826/22
CT Ing. White	BBLMD01-06	MCI	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	>150 MW	Resolution No. 826/22
CTLL	LDLATG04	TG	105 MW	Res. No 220/07 (75%)
CTLL	LDLATG05	TG	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	MCI	15 MW	Resolution No. 826/22
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	Resolution No. 826/22
CTGEBA	GEBATG03	TG	169 MW	Energy Plus Res. No. 1,281/06
CTGEBA	GEBATG03/TG04/TV02	CC	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	14 MW	Energy Plus Res. N° 1,281/06
CT Parque Pilar	PILBD01-06	MCI	100 MW	Resolution No. 21/16
CTB	EBARTG01 - TG02	TG	>50 MW	Resolution No. 826/22 (2)
HIDISA	AGUA DEL TORO	HI	HI – Media 120<P≤300	Resolution No. 826/22
HIDISA	EL TIGRE	HR	Renewable  ≤ 50	Resolution No. 826/22
HIDISA	LOS REYUNOS	HB	HB – Media 120<P≤300	Resolution No. 826/22
HINISA	NIHUIL I - II - III	HI	HI – Small  50<P≤120	Resolution No. 826/22
HPPL	PPLEHI	HI	HI – Media 120<P≤300	Resolution No. 826/22
P.E. M. Cebreiro	CORTEO	Wind	100 MW	Renovar
PEPE II	PAMEEO	Wind	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	53 MW	MATER Res. No. 281/17
PEPE IV	BAHIEO	Wind	18 MW	MATER Res. No. 281/17
PE Arauco	AR21EO	Wind	99.75 MW	Renovar

⁽¹⁾ Surplus power capacity and energy are remunerated in the spot market. 

⁽²⁾ During the month of April 2022 the contract under Resolution No. 220/07 of CTB have ended, since then, power and energy have been remunerated in the spot market.

In construction:
Generator	Tecnology	Capacity	Applicable regime
CTB	CC	280 MW	Resolution No. 220/07
PEPE IV	Wind	63 MW	MATER Res. No. 281/17
PEPE VI	Wind	94.5 MW	MATER Res. No. 281/17

F-23

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.2 Sales contracts with large users within the MAT

2.1.2.1 Energy Plus

Aiming to encourage new generation works, in 2006, the SE approved Resolution No. 1,281/06 in which established a specific regime which remunerates newly installed generation sold to a certain category of Large Users at higher prices.

The Energy Plus service consists of the offer of additional generation availability by generators, co-generators and self-generators which, as of the date of publication of SE Resolution No. 1,281/06, were not WEM agents or did not have facilities or an interconnection with the WEM. Considering that:

- These plants should have fuel supply and transportation facilities;

- The energy used by GU300 in excess of the base demand (energy consumption for 2005 year) qualifies for Energy Plus agreements within the MAT at a price negotiated between the parties; and

- For new GU300 entering the system, their base demand will equal zero.

If a generator cannot meet the power demand by an Energy Plus customer, it should purchase that power in the market at the operated marginal cost, or, alternatively, support the committed demand in case of unavailability through agreements with other Energía Plus generators.

Currently, the Company has Power Availability agreements in force with other generators whereby, in case of unavailability, it may purchase or sell power to support the contracts mutually.

Furthermore, the SE, through Note No. 567/07, as amended, established that GU300 not purchasing their surplus demand in the MAT should pay the Average Incremental Charge of Surplus Demand (“CMIDE”). As from the month of June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $1,200/MWh or the temporary dispatch surcharge.

Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 283 MW. The values of Energy Plus contracts are mostly denominated in U.S. dollars.

F-24

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.2.2 Renewable Energy Term Market (“MATER” Regime)

Pursuant to Resolution No. 281/17, the MEyM regulated the MATER Regime with the purpose of setting the conditions for large users within the WEM and WEM distributing agents’ large users covered by Section 9 of Law No. 27,191 to meet their demand supply obligation from renewable sources through the individual purchase within the MATER from renewable sources or self-generation from renewable sources.

Projects destined to the supply of electric power from renewable sources under the MATER Regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy is sold in the spot market.

Finally, contracts executed under the MATER Regime are administered and managed in accordance with the WEM procedures. The contractual terms —life, allocation priorities, prices and other conditions, notwithstanding the maximum price set forth in Section 9 of Law No. 27,191— are freely agreed between the parties, although the committed electricity volumes are limited by the electric power from renewable sources produced by the generator or supplied by other generators or suppliers with which it has purchase agreements in place.

Resolution No. 370/22 was passed on May 16, 2022, which expanded the MATER system allowing for the sale of renewable energy under this system to meet the GUDI and distribution utility company’s demand.

Under this resolution, the Company, through its PEPE II, III and IV wind farms, sells energy for up to 124 MW. Additionally, the Company has started selling third-party generators’ renewable energy for an approximate volume of 2 MW.

After the fiscal year closing, took place the commissioning of 4 additional wind turbines with an incremental capacity of 18 MW. For further information regarding PEPE IV project, see Note 17.1.

2.1.2.3 MATER dispatch priority

SE Resolution No. 551/21 published on June 16, 2021 modified the dispatch priority maintenance system established by Resolution No. 281/17. Overall, it replaces the granting of a security for the maintenance of the dispatch priority by the payment of a quarterly installment of US$ 500/MW until commissioning within the declared term or a maximum term of 24 months as from the priority assignment. It also established certain conditions for obtaining an extension in the committed commissioning date, which, according to the project development level and the requested extension term, requires a payment between 500 and 1,500 US$/MW/month.

Additionally, it allows projects with an assigned dispatch priority but not yet commissioned to continue their execution keeping the dispatch priority, or to waive such priority, thus releasing the transmission capacity.

F-25

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The Company, as owner of the Wind Farm project, located in Las Armas, Province of Buenos Aires, notified its decision to waive the timely granted dispatch priority, and recovered the security it had provided. As a result, CAMMESA notified that the already initiated execution of the security was determined to be moot as it had no further claim against the Company; therefore, as of September 30, 2021, the amount of US$ 12.5 million recorded for to such effect was recovered and disclosed under the item “Other operating income” of the Consolidated Statement of Comprehensive Income.

Under the MATER calls for tenders for the third quarter of 2021 and 2022, the Company was awarded a 36 MW and 41 MW dispatch priority, respectively, for the expansion of the PEPE III wind farm. For further information on the extension project aforementioned, see Note 17.1.

2.1.3 Supply Agreements with CAMMESA

2.1.3.1 SE Resolution No. 220/07

Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into 220 Agreement with WEM Generating Agents for the energy produced with new equipment. These will be long-term agreements and the price payable by CAMMESA should compensate for the investments made by the agent at a rate of return to be accepted by the SE.

Within the framework of this resolution, the Company has remunerated units under 220 agreements for 79 MW and 280 MW, through Loma la Lata thermal power plant and as from the closing to combined cycle’s commissioning at Ensenada de Barragán thermal power plant, owned by CTB, respectively (see Note 5.2.3).

2.1.3.2 SE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector, on March 22, 2016, the SE issued Resolution No. 21/16 calling for parties interested in offering new thermal power generation capacity with the commitment to making it available through the WEM for the 2016/2017 summer, 2017 winter, and 2017/2018 summer periods.

For the awarded projects, wholesale power purchase agreements were entered into with CAMMESA for a term of 10 years, with a remuneration made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if appropriate), less penalties and fuel surpluses. Surplus power capacity is sold in the spot market.

Pursuant to this resolution, the Company, through its Loma de la Lata, Ingeniero White and Pilar thermal power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW.

F-26

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.3.3 SE Resolution No. 287/17

On May 10, 2017 the SE issued Resolution No. 287/17 launching a call for tenders 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 with natural gas and 1,820 kcal/kWh with alternative liquid fuels), and the new capacity should not exceed the existing electric power transmission capacity; otherwise, the cost of the necessary extensions will be borne by the bidder.

Pursuant to this regulation, the Company, through its Genelba thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years.

2.1.3.4 Renovar Programs

In order to meet the objectives, set by Law No. 26,190 and Law No. 27,191 promoting the use of renewable sources of energy, the MEyM called for open rounds for the hiring of electric power from renewable sources (Renovar Programs, Rounds 1, 1.5 and 2) within the WEM. These calls aimed to assign power capacity contracts from different technologies (wind energy, solar energy, biomass, biogas and small hydraulic developments with a power capacity of up to 50 MW).

For the awarded projects, renewable electric power supply agreements were executed for the sale of an annual committed electric power block for a term of 20 years.

Additionally, several measures were established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, equipment’s accelerated depreciation in the income tax, import duty exemptions, etc.) and the creation of a fund for the development of renewable energies destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects.

On December 27, 2021, the SE passed Resolution No. 1,260/21 to address issues regarding the projects under the different Renovar rounds that did not meet committed commissioning terms. Upon satisfaction of certain conditions, the resolution gives project awardees the option to: i) terminate the current contract with CAMMESA against the payment of a sum of money; ii) amend the contract and extend the term for commissioning against a reduction in the contract price and term; iii) commission the project for a power capacity lower than that committed initially.

Under the Renovar programs, the Company, through Greenwind, has a supply contract in place with CAMMESA for a total of 100 MW, and in December 2022 it incorporated an additional 99.75 MW following the acquisition of Arauco wind farm (see Note 5.1.5).

F-27

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.3.5 RenMDI Call

SE Resolution No. 36/23 launched a national and international call for tenders to select renewable energy generation projects with a twofold objective: i) the substitution of forced generation (line 1) and ii) the diversification of the energy matrix (line 2). The tender form establishes the following maximum power capacities to be awarded: (i) 500 MW distributed among 6 regions for line 1 and (ii) 120 MW throughout the national territory for line 2. The projects under line 2 will have no priority over other renewable projects.

Projects will be remunerated under a supply agreement executed with CAMMESA for a term of 15 years from the project’s commissioning. Until commissioning, the tenderer will meet a payment scheme (an initial payment and quarterly payments), which will be allocated to a special account to be administered by CAMMESA through the the “Electricity Supply Transportation Works Fund” trust (“FOTAE”) for the transmission system’s expansion.

The tender submission deadline is April 27, 2023. As of the date of issuance of these Consolidated Financial Statements, Pampa is evaluating the possibility of participating in the call.

2.1.3.6 Remuneration for combined cycles

SE Resolution No. 59/23 dated February 7, 2023 established an opt-in system under which combined cycles’ owners could execute an availability and efficiency optimization agreement with CAMMESA. The agreement contemplates an availability commitment for 85% of the net power capacity for a maximum term of 5 years, and sets a US$ 2,000/Mw-month remuneration for the power capacity made available and the dollarization of the energy price based on the fuel used (US$ 3.5/MWh for natural gas and US$ 6.1/MWh for fuel oil and gas oil). Besides, it provides for a 35% and 15% reduction in the remuneration collectible for guaranteed power capacity for generators with availability commitments in the spot market for the summer-winter and autumn-spring periods, respectively.

The opt-in application form should be submitted to CAMMESA within a term of 90 calendar days. As of the date of issuance of these Consolidated Financial Statements, the Company is currently evaluating the resolution.

2.1.4 Remuneration at the Spot market

On February 27, 2020, SE Resolution No. 31/20 was published in the BO, applicable as from February 2020, established remunerative items based on technology and scale with prices in pesos and set an additional remuneration, in pesos, for the power capacity generated during the hours of maximum thermal demand of the month, taking into consideration the average power capacity generated by thermal generators and the average power capacity operated by hydroelectric generators.

Besides, SE Resolution No. 31/20 set a monthly remuneration update scheme with a factor contemplating a 60% CPI and 40% IPIM adjustment. However, on April 8, 2020, through Note No. 2020-24910606-APN-SE#MDP, the SE instructed CAMMESA to postpone the application of this automatic adjustment mechanism.

F-28

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in spot generation remuneration values, and repealed the automatic adjustment mechanism established by SE Resolution No. 31/20.

In November 2021, SE Resolution No. 1,037/21, instrumented through Note NO-2021-108163338-APN-SE#ME, provided for an additional transitional remuneration for generated energy and suspended the application of the utilization factor for economic transactions comprised between September 1, 2021 and February 28, 2022.

On April 21, 2022, SE Resolution No. 238/22 was published in the BO. This resolution provided a 30% increase in spot generation remuneration values from the February 2022 economic transaction, and an additional 10% increase from the June 2022 economic transaction. It also abrogated the application of the utilization factor and the additional transitional remuneration set by SE Resolution No. 1,037/21.

On December 14, 2022, through SE Resolution No. 826/22, the spot remuneration values were modified considering the following increases: i) 20% from the September 2022 economic transaction; ii) 10% from the December 2022 economic transaction; iii) 25% from the February 2023 economic transaction; and iv) 28% from the August 2023 economic transaction.

Additionally, SE Resolution No. 826/22 replaced the remuneration scheme at hours of maximum thermal demand with a differentiated remuneration scheme at peak hours from the November 2022 economic transaction.

The applicable remunerations, based on technology and resolution, are detailed below. The amounts reported under SE Resolution No. 238/22 and SE Resolution No. 826/22 correspond to tariffs applicable from the June 2022 and December 2022 economic transactions, respectively.

2.1.4.1 Remuneration for Available Power Capacity

2.1.4.1.1 Thermal Power Generators

A minimum remuneration for power capacity based on technology and scale was established, and generating, co-generating and self-generating agents owning conventional thermal power plants were allowed to offer guaranteed availability commitments for the energy and power capacity generated by their units and not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA.

Availability commitments are tendered for quarterly periods: a) summer (December through February); b) winter (June through August) and c) ‘other,’ which comprises two quarters (March through May, and September through November), the thermal generators’ remuneration for committed power capacity being proportional to their compliance.

F-29

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The minimum remuneration for generators with no availability commitments includes the following scales and prices:

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-month)	SE No. 826/22 ($ / MW-month)
Large CC Capacity > 150 MW	100,650	129,839	185,670	245,084
Large TV Capacity > 100 MW	143,550	185,180	264,807	349,546
Small TV Capacity ≤ 100 MW	171,600	221,364	316,551	417,847
Large GT Capacity > 50 MW	117,150	151,124	216,107	285,262

The remuneration for guaranteed power capacity to generators with availability commitments is:

Period	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No 238/22 ($ / MW-month)	SE No 826/22 ($ / MW-month)
Summer – Winter	360,000	464,400	664,092	876,601
Fall - Spring	270,000	348,300	498,069	657,451

In the case of thermal power plants with a power capacity equal to or lower than 42 MW in total, a differential remuneration was applied until its elimination on August 2022.

In the same way, a coefficient derived from the average utilization factor over the unit’s last twelve months was applied to the power capacity remuneration: with a minimum 70% of the utilization factor, 100% of the power capacity payment is collected; if the utilization is between 30% and 70%, the power capacity payment ranges from 70% to 100%; and if the utilization factor is lower than 30%, 70% of the power capacity payment was collected until January 2020 and 60% of the power capacity payment is collected as from February 2020. The application of this factor was suspended in 2021 and finally abrogated from February 2022 (see Note 2.1.4.3).

For the February 2020 to October 2022 period, an additional remuneration for the hours of maximum thermal requirement of the month (hmrt) was established, which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, applying the following prices to the average generated power:

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	45,000	22,500	58,050	29,025	83,012	41,506
Fall - Spring	7,500	-	9,675	-	13,835	-

F-30

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.4.1.2 Hydroelectric Generators

Power capacity availability is determined independently of the reservoir level, the contributions made, or the expenses incurred. Furthermore, in the case of pumping hydroelectric power plants, the operation as turbine and pump is considered to calculate availability.

The base remuneration includes the following scales and prices:

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-mes)	SE No. 826/22 ($ / MW-mes)
Medium HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Small HI Capacity > 50 ≤ 120 MW	181,500	234,135	334,813	441,953
Medium Pumped HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Renewable HI Capacity ≤ 50 MW	297,000	383,130	547,876	723,196

The payment for power capacity is determined by the actual capacity, hours of unavailability due to programmed and/or agreed maintenance are not computed for the calculation of the remuneration. However, to consider the incidence of programmed maintenance works in power plants, SME Note No. 46631495/19 provided for the application of a 1.05 factor over the power capacity payment.

In the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters.

Furthermore, for the February 2020 to October 2022 period, an additional remuneration was set for the hours of maximum thermal demand (hmrt), corresponding to the 50 hours with the largest dispatch of thermal generation in each month, divided into two blocks of 25 hours each:

Generation units > 50 MW and ≤ 300 MW

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	39,000	19,500	50,310	25,155	71,943	35,972
Fall - Spring	6,500	-	8,385	-	11,991	-

F-31

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

Generation units ≤ 50 MW

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	42,000	21,000	54,180	27,090	77,478	38,739
Fall – Spring	7,000	-	9,030	-	12,913	-

2.1.4.2 Remuneration for generated and operated energy

In the case of thermal power generators, a remuneration was set for generated energy, depending on the type of fuel used, and for operated energy, as shown below:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	Between 240 and 420	Between 310 and 542	Between 403 and 705	Between 585 and 1,023
Operated energy	84	108	154	204

It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognised at 60% of the installed net capacity, irrespective of the energy delivered by the unit.

In the case of hydroelectric plants, the following prices were established for generated and operated energy, irrespective of scale:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	210	271	388	512
Operated energy	84	108	154	204

The remuneration for operated energy should correspond with the grid’s optimal dispatch; however, the current resolution does not indicate which would be the consequence otherwise.

In the case of pumping hydroelectric power plants, both the generated energy and that used for pumping are considered. Besides, if it works as a synchronous condenser, 60 $/MVAr, and 77 $/MVAr, 110 $/MVAr and 145 $/MVAr are recognised under SE Resolution No. 31/20, and No. 440/21, No. 238/22 and No. 826/22, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy.

F-32

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

As from November 2022, a differentiated remuneration scheme applicable to thermal and hydroelectric generators for generated energy at peak hours, was established with a remuneration equivalent to twice the value of the generated energy’s current price at peak hours (18:00 to 23:00) every day in the months of December, January, February, June, July and August, and to one time that value for the same hours in the months of March, April, May, September, October and November.

As regards energy generated from unconventional sources, a single remuneration value was set irrespective of the source used:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	1,680	2,167	3,099	3,719

Energy generated before commissioning by the Agency in Charge of Dispatch, will be remunerated at 50% of the above-mentioned remuneration.

2.1.4.3 Transitory additional remuneration

On November 2, 2021, SE Resolution No. 1,037/21 provided as follows: (i) the creation of an exports account in the WEM’s stabilization fund for the accumulation of income from electricity export transactions conducted by CAMMESA, as from the economic transactions for the month of September 2021, for the financing of energy infrastructure works; and (ii) the transitory recognition of an additional remuneration to the one established by SE Resolution No. 440/21 for the economic transactions comprised between September 1, 2021 and February 28, 2022. On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that covered generators have a 70% utilization factor, therefore, 100% of the power capacity remuneration would be paid, and added an amount of $ 1,000/MWh for exported energy, which will be distributed proportionately to the energy generated monthly by each generator.

SE Resolution No. 238/22 canceled the detailed additional and transitory remuneration from the February 2022 economic transaction.

2.1.4.4 Suspension of contracts within the MAT

The suspension of contracts within the MAT (excluding those derived from a differential remuneration scheme) provided for by SE Resolution No. 95/13 remains in effect.

F-33

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.1.5 Fuel supply for thermal power plants

On December 27, 2019, the Ministry of Productive Development Resolution No. 12/19, restored the centralized scheme in CAMMESA for the supply of fuels for generation purposes (except for generators under the Energy Plus regime and with Wholesale Power Purchase Agreements under Resolution SE No. 287/17).

In December 2020, on account of the implementation of the GasAr Plan (see Note 2.2.4.1.2), SE Resolution No. 354/20 was passed, which established a new dispatch order for generation units based on the fuel supplied for their operation under a centralized dispatch scheme.

SE Resolution No. 354/20 established the gas volumes CAMMESA should prioritize in the electricity dispatch. In this sense, firm volumes to be used by CAMMESA were defined, including: i) volumes corresponding to contracts entered into by CAMMESA with producers acceding to the GasAr Plan; ii) volumes corresponding to contracts executed by adherent producers with generators acceding to the centralized dispatch (these volumes will be discounted by the adherent producers from the applicable quota for which they should enter into contracts with CAMMESA under the GasAr Plan) and; iii) volumes to meet the Take or Pay (“TOP”) obligations under the supply agreement entered into between IEASA and Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”).

Besides, an electricity dispatch priority scheme was set based on the allocation of the natural gas quota taking into consideration the TOP obligations. To this effect, the following priorities were set (within each priority level, the order of agents is set based on the generator’s production cost):

(i) Dispatch Priority 1: Generators, Self-generators and/or Co-generators supplied with a natural gas quota under a TOP Bolivia condition assigned by IEASA. If a generator with a fuel stocking obligation optionally acquires from IEASA natural gas from Bolivia, this volume will be included in this quota.

(ii) Dispatch Priority 2: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes up to the TOP of each contract.

(iii) Dispatch Priority 3: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes for the Daily Maximum Amount (DMA) less those corresponding to the TOP of each contract.

(iv) Dispatch Priority 4: Generators, Self-generators and/or Co-generators supplied by CAMMESA with natural gas or LNG coming from other firm commitments undertaken by CAMMESA.

(v) Dispatch Priority 5: Generators, Self-generators and/or Co-generators supplied with a gas quota from the unassigned, spot natural gas contracts from any source, acquired by CAMMESA and/or the Generator, according to the supply source. In the case of a generator with its own fuel, the maximum amount to be acknowledged will be the corresponding reference prices.

F-34

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

As regards the costs associated with the supply of these fuels, it was established that the electricity demand will bear, among others, the regulated transportation costs, the cost of natural gas and the applicable TOP obligations.

Generating agents that kept the possibility to purchase their fuel supply (agents under the Energy Plus regime or with Wholesale Purchase Agreements under Resolution SE No. 287/17) could opt in or out of CAMMESA’s unified dispatch, through the operating assignment of the contracted firm transportation and gas volumes, which impact the assigned priority order. Under such assignment, agents should waive all claims regarding the application of SE Resolution No. 354/20.

In the specific case of generators with wholesale power purchase agreements under SE Resolution No. 287/17, it was provided that they would have the option of canceling the self-supply obligation and the resulting recognition of its associated costs, having to maintain the respective transportation capacity for its management in the centralized dispatch.

The Company assigned the firm transportation and gas volumes committed to supplying Genelba Plus’ CC and Energy Plus contracts, setting certain guidelines for calculating fuel costs to support its Energy Plus contracts. In the case of the supply to Genelba Plus’ CC, the assignment will remain effective during the life of the GasAr Plan, and it may be revoked by the generator with a minimum advance notice of 30 business days. Within this framework, the parties agreed to enter into an addendum to the Wholesale Power Purchase Agreement to establish the modifications regarding this new supply scheme, which execution is pending as of the issuance of these Consolidated Financial Statements.

2.2 Oil and gas

2.2.1 Argentine Hydrocarbons Law

On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319 (enacted in 1967), which empowers the Government to grant exploration permits and concessions to the private sector. Additionally:

(i) Sets the terms for exploration permits:

- 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;

- Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years; and

- Continental shelf and off-shore exploitation: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

(ii) Sets the terms for exploitation concessions, extensible for 10-year terms:

- Conventional exploitation concession: 25 years;

- Unconventional exploitation concession: 35 years; and

- Continental shelf and off-shore exploitation concession: 30 years.

(iii) Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.

(iv) Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

(v) Establishes a 12% royalty payable by the exploitation concessionaire to the grantor on the proceeds derived from liquid hydrocarbons extracted at wellhead and the production of natural gas. In the case of extension, additional royalties for up to 3% over the applicable royalties at the time of the first extension, up to a total of 18%, will be paid for the following extensions.

(vi) Provides for two types of non-binding commitments between the National Government and the Provinces aiming to establish a uniform environmental legislation and to adopt a uniform tax treatment to encourage hydrocarbon activities.

(vii) Restricts the National Government and the Provinces from reserving new areas in the future in favor of public or mixed companies or entities, irrespective of their legal form.

On its part, the Ministry of Energy and Natural Resources of the Province of Neuquén established certain parameters for the granting of Hydrocarbons Unconventional Exploitations Concessions (“CENCH”) in this province, instrumented through Resolution No. 53/20 dated July 1, 2020 and Resolution No. 142/21 dated November 24, 2021, and later ratified by Provincial Executive Order No. 2,183/21 in December 2021. Companies may request a CENCH based on a development project that will include a pilot plan for a term of up to five years to demonstrate its technical and economic feasibility. Furthermore, if companies request the inclusion in the CENCH of a surface larger than that assigned to the approved pilot plan, the payment of a block extension bond should be included, which value will be associated with the resources expected to be recovered in the extended block, considering the basin’s average price over the last two years. Besides, while the CENCH is in effect, companies should submit continuous development plans and investment commitments, updated annually.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.2 Hydrocarbon exploration and exploitation levy

Law No. 27,007 set the levy values per km2 or fraction to be paid annually and in advance by the permit holder. Exploitation permits will amount to $ 4,500 and exploration permits, to $ 250 in the first period, $ 1,000 in the second period of the basic term, and $ 17,500 during the first year of the extension (with a 25% annual cumulative increase). It is worth highlighting that up to 10% of the levy value payable in the second period of the basic term and the extension may be offset with actual investments per km2.

On September 26, 2019, the Province of Neuquén, pursuant to Provincial Executive Order No. 2,032/19, published new levy values per km2 or fraction effective for this province from 2020. The exploitation levy was set at $ 22,410, and the exploration levy at $ 1,245 for the first period, $ 4,980 for the second period, $ 7,470 for the third period, and $ 87,150 for the extension period.

From 2021, PEN Executive Order No. 771/20 set a maximum levy in pesos equivalent to a certain volume of oil at the average price for the semester before settlement, at BNA’s exchange rate effective on the last business day before payment. This scheme is applicable nationwide (including the Province of Neuquén, which acceded to it under Provincial Executive Order No. 1,656/20). Exploitation permits amount to 8.28 barrels and exploration permits to 0.46 barrels in the first period, 1.84 barrels in the second period of the basic term, and 32.22 barrels in the extension period.

2.2.3. Currency access for incremental oil and natural gas production systems and regional and national supplier’s employment, labor and development promotion system

On May 28, 2022, PEN Executive Order No. 277/22 was published, which established currency access systems for the incremental production of oil (“RADPIP”) and natural gas (“RADPIGN”), as well as the regional and national supplier’s employment, labor and development promotion system (“RPEPNIH”). This executive order, later regulated by PEN Executive Order No. 484/22 dated August 12, 2022, mainly provided for eased access to the MLC for beneficiaries increasing their gas injection levels and/or oil production.

Beneficiaries must meet the following requirements to access the RADPIP and the RADPIGN: (i) be registered with the SE’s oil companies registry; (ii) accede to the system; (iii) attain an incremental oil production or natural gas incremental injection levels; (iv) comply with the RPEPNIH; and (v) be an awardee and fulfill the obligations provided under natural gas production promotion or stimulus programs (exclusively for the RADPIGN).

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

Beneficiaries under these systems may access the MLC to make principal and interest payments of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, and to pay earnings and dividends for closed and audited balance sheets and/or the repatriation of direct investments by non-residents. This benefit may be transmitted to direct suppliers. Moreover, access to the MLC under this system will not be subject to BCRA’s prior authorization requirement in case exchange regulations so require.

Currency access benefits for acceding the RADPIP and/or RADPIGN will be taken into consideration and timely discounted.

Regarding the RPEPNIH, supplier development plans guaranteeing regional and national integration will be controlled. Moreover, a hiring scheme is contemplated granting preferences to regional and national goods and/or services suppliers.

On January 16, 2023, SE Resolution No. 13/23 was published in the BO, which regulated the opt-in system and the procedure to obtain the currency access benefit created by PEN Executive Order No. 277/22.

On February 8, 2023, the Company requested the opt-in to both aforementioned regimes and the benefits for the third and fourth quarters of 2022.

2.2.4 Gas Market

2.2.4.1 Natural Gas Production Promotion or Stimulus Programs

2.2.4.1.1 Argentine Natural Gas Production Promotion Plan (“GasAr Plan”)

On November 16, 2020, Executive Order No. 892/20 was published in the BO, which approved the GasAr Plan to foster the development of the Argentine gas industry based on a bidding mechanism, and instructed the SE to instrument such plan and to set the applicable complementary and clarifying rules.

On November 23, 2020, the SE, through Resolution No. 317/20, launched the “National Public Call for Tenders for the Argentine Natural Gas Production Promotion Plan – 2020-2024 supply and demand scheme” for the award of a volume of 70 million m3 of natural gas per calendar year (CAMMESA plus distributors), which may be modified by the SE to guarantee an optimal domestic supply.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The contract samples stipulated a Deliver or Pay (“DOP”) obligation of 100% per day for producers and a Take or Pay (“TOP”) obligation of 75% per month for CAMMESA and per quarter for distributors. Regarding the payment of contracts with distributors, the Federal Government will bear the monthly difference between the price tendered and that resulting from the tariff schemes through a subsidy payable directly to producers. Under Law No. 27,591, payment of this subsidy is secured by Tax Credit Certificates, which were regulated by SE Resolution No. 125/21 and AFIP General Resolution No. 4,939/21.

Additionally, to access the GasAr Plan producers submitted a plan of investments necessary to maintain the committed production and a national added-value commitment providing for the development of direct local, regional and national suppliers.

On December 15, 2020, Resolution No. 391/20 was published in the BO, awarding the natural gas volumes tendered under GasAr Plan, Round 1. In this sense, out of a total natural gas base volume of 67.42 million m3/day to be purchased, in terms of tendered volume, the Company ranked third in the Neuquina Basin, with an awarded base volume of 4.9 million m3/day at an annual average price of US$ 3.60/MBTU for a term of four years effective as from January 1, 2021.

Additionally, the Company has been one of the three producers tendering an additional volume for the winter period, with the award of 1 million m3/day at US$ 4.68/MBTU, a volume deemed indispensable to accompany the high seasonality of the Argentine demand, reducing gas imports, the consumption of alternative fuels, and the use of foreign-currency reserves.

On March 9, 2021 Resolution No. 169/21 was published in the BO, which awarded natural gas volumes offered under the GasAr Plan, Round 2 Tender. In this sense, the Company was awarded a volume 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 meet the winter peak demand for the years 2022 through 2024, at a price of US$ 4.68/MBTU.

Under Resolution No. 984/21 dated October 19, 2021, the SE called for Round 3 under GasAr Plan for 2022 through 2024 inclusive, with injection starting in May 2022. The resolution determined that the cap price for tenders is the maximum price tendered under Round 1. The Company took part in this call, tendering 2 million m3/day for the Neuquina basin at a price of US$ 3.347/MBTU; on November 11, 2021, the SE issued Resolution No. 1,091/21, awarding the tendered volumes and prices.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.4.1.2 2023-2028 Plan to Reinsure and Encourage Federal Hydrocarbon Production, Domestic Self-Supply, Exports, Imports Substitution, and the Expansion of the Transportation System for all the Country’s Hydrocarbon Basins (“Reinsurance Plan”)

On November 3, 2022, Executive Order No. 730/22 was published in the BO, which amended the GasAr Plan’s scheme approved by Executive Order No. 892/20.

The Reinsurance Plan establishes a new term for the system until December 31, 2028, with the following main objectives: (i) consolidating a new 70 MMm3/d flat block (volumes awarded under GasAr Plan’s Round 1 and 3), excluding winter peaks; and (ii) developing the demand for the incremental volumes to be evacuated using the new transportation capacity following the construction of the Néstor Kirchner Gas Pipeline (TransportAr Program, SE Resolution No. 67/22).

Consequently, on November 14, 2022, SE Resolution No. 770/22 was published in the BO, calling for Tender Rounds 4 for the Neuquina Basin, and 5, for the Del Golfo and Austral Basins.

For the Neuquina Basin, the following calls were made:

(i) Round 4.1: for the extension of the commitments undertaken under Rounds 1 and 3 of the GasAr Plan for 4 additional years, from January 1, 2025 to December 31, 2028, for the same volumes, and with prices equal to or lower than the timely awarded price; and

(ii) Round 4.2: for the award of the following incremental volumes:

(a) Flat Gas: 11 MMm3/day from July 1, 2023 to December 31, 2028, and 3 MMm3/day from January 1, 2024 to December 31, 2028, with prices not exceeding US$ 4 MBTU; and

(b) Peak Gas: 7 MMm3/day from May 1 to September 30, for each of the 2024-2028 and 2025-2028 periods, with prices equal to or lower than US$ 6.9 MBTU and an applicable 1.3 adjustment factor.

The Company participated in Round 4.1, seeking to extend commitments under GasAr Plan’s Rounds 1 and 3 until December 2028 and keeping the originally tendered prices of US$ 3.6 MBTU and US$ 3.347 MBTU, respectively. Moreover, it submitted the following tenders under Round 4.2: (i) Flat Gas: 4.8 million m3/day at a price of US$ 3.485 MBTU from July 1, 2023 to December 31, 2028; (ii) Peak Gas: 3 million m3/day at a price of US$ 5.190 MBTU for the 2024-2028 period and 1.9 million m3/day at US$ 4.770 MBTU for the 2025-2028 period.

On December 22, 2022, through SE Resolution No. 860/22, the Company was awarded the extension of the commitments for Round 4.1 and a 4.8 million m3/day demand associated with flat gas under Round 4.2.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The awards granted to the Company and the contracts executed represent a production commitment of 15.7 million m3/day for winter periods and 13.8 million m3/day for summer periods in 2023-2024. Compared to 2022, this commitment represents a 44% increase in winter production, the period with the largest gas supply needs in the country. As from 2025, the commitment under the Reinsurance Plan will amount to 13.8 million m3/day.

Based on the gas demand curve projected by the SE, the Company will enter into new contracts with CAMMESA, IEASA and distributors.

2.2.4.2 Natural gas for the residential segment and CNG

On May 27, 2022, SE Resolution No. 403/22 provided for an update of new natural gas PIST prices under existing contracts executed within the framework of GasAr Plan’s promotion scheme, reducing the subsidy payable by the Federal Government from June 1, 2022.

Additionally, in the months of February, June and August 2022, public hearings were held to analyze the Plan Gas.Ar portion of the natural gas PIST price to be borne by the Federal Government. It is worth highlighting that SE Resolution No. 610/22 determined a gradual increase in the PIST price distributors will pay for unsubsidized residential consumptions, keeping the subsidized price for the remaining users.

On January 10, 2023, SE Resolution No. 6/23 was published, establishing updates of natural gas PIST prices for contracts executed under the GasAr Plan and the Reinsurance Plan based on the different types of users.

2.2.4.3 Acquisition of Natural Gas for Generation

From December 30, 2019, CAMMESA’s centralization scheme for the supply of fuels for generation was restored (except for generators with Energy Plus and SE Res. 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 GasAr Plan, for the volumes committed under this program over an initial term of 4 years.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

In addition to GasAr Plan, in 2021 CAMMESA continued calling for tenders on a monthly basis, at a maximum price of US$ 2.3/MBTU until April and US$ 3.5 until August, on an interruptible basis for GasAr Plan awardees and under a 30% DOP clause for the rest. However, from September 2021 these calls were declared unawarded. On the other hand, since mid-July 2021 CAMMESA launched biweekly calls for tenders by GasAr Plan awardees that may offer surplus volumes, with a maximum price equivalent to that awarded in the plan’s Round 1. In 2022, an average of 451 million m3/day were awarded at a price of US$ 3.5/MBTU (of which 276 million m3/day correspond to the Neuquina Basin).

2.2.4.4 Natural Gas Exports

On April 27, 2021, SE Resolution No. 360/21 regulated the new procedure for the authorization of natural gas exports. This resolution contemplates exports on a firm and preferential basis for GasAr Plan’s awardees, and sets a minimum sale price equivalent to the summer price awarded in Round 1. In this manner, the Company, as an awardee under GasAr Plan, 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 May and December 2021, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m3/day and 1.22 million m3/day for the October 2021 – April 2022 and January – April 2022 periods, respectively. Besides, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were added, with expirations between November 2022 and December 2024.

Under GasAr Plan, in August 2022 the Company was cleared to export gas to Chile on a firm basis for a maximum volume of 1,492 MMm3/d for the October 2022 – April 2023 period.

On November 17, 2022, SE Resolution No. 774/22, which supersedes SE Resolution No. 360/21, was published in the BO. This resolution establishes a new proceeding delimiting four export areas: the Neuquina Basin and the Austral Basin with summer quotas (October 2023-April 2024 period) of 9 MMm3/day and 2 MMm3/day, respectively, and the Noroeste Basin and other areas with no quota definition.

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.

The minimum reference price is set at the higher of the Brent quotation percentage determined by the SE and the average price awarded, adjusted by the seasonal index, with the authorization to withdraw volumes from the contracts executed under GasAr Plan and/or the Reinsurance Plan with CAMMESA and/or ENARSA.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

Additionally, for the Neuquina Basin, firm exports for 3 million m3/day will be authorized for the May-June 2023 period, to be apportioned among producers awarded under Round 4.2 - Flat Gas for the July 1, 2023-December 31, 2028 period.

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 as long as the international Brent price was equal to or below US$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 US$60/bbl. Since February 2021, the rate has remained at 8%.

2.2.4.5 “TransportAr National Production” Pipelines System Program

On February 9, 2022, SE Resolution No. 67/22 was published in the BO declaring the construction of “President Néstor Kirchner Pipeline” of national public interest. This pipeline will transport natural gas through the Province of Neuquén, the Province of Buenos Aires, and the Province of Santa Fe.

Moreover, it created the TransportAr Production Gas Pipelines System Program to execute the works necessary to expand the system’s transportation capacity including a list of pipeline works to be executed by IEASA or through third parties to promote development, production growth, and natural gas self-supply, among other objectives.

On August 10, 2022, Argentine authorities signed contracts for the Stage 1 Néstor Kirchner Gas Pipeline construction, that will connect the cities of Tratayén (Neuquén) with Salliqueló (Buenos Aires) and will cross the provinces of Río Negro and La Pampa. As of the issuance of these Consolidated Financial Statements, the aforementioned construction is underway, and commissioning is expected for June 2023.

Later, PEN Executive Order No. 76/22, published on February 14, 2022, granted IEASA a 35-year transportation concession of President Néstor Kirchner pipeline under Law No. 17,319 and the power to contract, plan, execute and call for tenders for the construction of the infrastructure works under the Program. IEASA may enter into transportation capacity freely-negotiated agreements with producers and/or carriers to construct or expand all or part of the pipeline. This transportation capacity will not be covered by tariffs approved by ENARGAS, which will apply to the remaining transportation capacity not committed under these agreements. This executive order grants YPF priority to hire the capacity that can be freely negotiated by IEASA. Moreover, IEASA may fully or partially assign ownership of its concession to YPF.

Besides, the “Argentine Gas Development Fund” administrative and financial trust was created, with IEASA as trustor and beneficiary, to finance works under the program, including the repayment of principal and interest services of the trust securities to be issued thereunder. The trust estate administrator and trustee will be Banco de Inversión y Comercio Exterior S.A.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.2.5 Oil market

2.2.5.1 Crude oil price

As of this date, there is no reference price for the sale of crude oil in the domestic market. However, considering pump prices for fuels, local refining companies are validating prices below the export parity.

Just as with natural gas exports, a crude oil export duty has been in effect since May 2020. PEN Executive Order 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 US$ 45/bbl, rising gradually as the international reference price increased until reaching 8%, the cap to be recognised when the reference price equals or exceeds US$ 60/bbl. Since February 2021, the rate has remained at 8%.

2.2.5.2 Oil transportation

In fiscal year 2022, Oldelval, as holder of the national liquid hydrocarbons transportation concession, launched a call for tenders to award and hire the firm transportation service for the Allen - Puerto Rosales oil pipeline tranche for a capacity of up to 50,000 m3/day.

This volume has been fully awarded, and the necessary execution contracts have been entered into, effective until the termination of the transportation concession term in 2037. Pampa was awarded 1,002 m3/day.

Under Oldelval’s call for tenders, the company Oiltanking Ebytem launched a call to increase the oil dispatch capacity for up to 50,000 m3/day and the storage capacity for up to 300,000 m3. These expansions will be allocated exclusively to oil exports. Pampa was awarded a 1,002 m3/day dispatch capacity and oil storage capacity for 6,008 m3.

2.3 Gas Transportation

2.3.1 TGS’s Tariff situation

On March 30, 2017, TGS executed the 2017 Integral Agreement which was ratified on March 27, 2018, through PEN Executive Order No. 250/18. This executive order represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS.

F-44

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The 2017 Integral Agreement set the guidelines for the provision of the natural gas transportation service until the end of the license, among these guidelines approved: (i) a tariff increase was granted in installments for TGS as from April 1, 2017; (ii) a Five-Year Investment Plan to be executed by TGS between April 2017 and March, 2022; and (iii) a non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments considering IPIM published by INDEC subject to ENARGAS’ approval.

In the public hearing held on September 4, 2018, in which TGS requested, based on the variation of the IPIM recorded for the period February - August 2018, a tariff increase of approximately 30%. Considering the hearing, on September 27, 2018, ENARGAS issued Resolution No. 265/18 which determined a 19.7% tariff increase effective as of October 1, 2018.

This increase was determined by ENARGAS based on the simple average of the IPIM, the construction cost index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018. ENARGAS supported the determination of the aforementioned tariff increase in the provisions of Resolution No. 4,362/17, which, among other issues, provided that under certain circumstances and macroeconomic conditions, such as the significant devaluation occurred after April 2018, ENARGAS may use other indexes than the IPIM to determine the tariff increase. TGS notified ENARGAS of its disagreement with respect to the methodology for calculating the semi-annual adjustment.

On March 29, 2019, ENARGAS issued Resolution No. 192/19 approved, effective as from April 1, 2019, a 26% increase in tariff schemes applicable to the natural gas transportation utility by TGS current as of March 31, 2019. In accordance with current regulations, ENARGAS considered the evolution of the IPIM update index between the months of August 2018 and February 2019 to define six-monthly adjustments to TGS’ tariffs.

As regards the semi-annual tariff update which should have become effective as from October 1, 2019, on September 3, 2019, the SE issued Resolution No. 521/19, later amended by Resolution No. 751/19, postponed its application until February 1, 2020. This deferral resulted in the revision and adjustment of the Five-Year Investment Plan execution, in the same proportion as the foregone income for TGS.

On December 16, 2020, PEN Executive Order No. 1,020/20 was passed within the framework of the Solidarity Law. This executive order launched the renegotiation of the RTI concluded in 2018 within a term of 2 years. During this term, renegotiation agreements in force are suspended. On December 7, 2022, PEN Executive Order No. 815/22 was published in the BO, extending the renegotiation term for 12 months until December 16, 2023.

Additionally, the Solidarity Law, PEN Executive Order No. 1,020/20 and PEN Executive Order No. 1815/22 provide for the administrative intervention of the ENARGAS.

F-45

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The public hearing called by ENARGAS to discuss the RTT pursuant to the provisions of PEN Executive Order No. 1,020/20 took place on March 16, 2021. In this respect, TGS, without waiving the whole of its percentage share of tariff recomposition, alternatively submitted in the hearing its tariff increase proposal, assessed at 58.6% as from April 1, 2021. This increase was assessed based on the financial needs to meet operating and financial costs, capital expenditures and taxes, which were calculated taking into consideration the evolution of the inflation rate over a 12-month period as from its beginning. The requested increase only contemplated the funds necessary to meet its obligations as licensee.

Additionally, TGS denied and dismissed the arguments raised in the public hearing, which considered that the current natural gas transportation tariff is not fair or reasonable given the alleged existence of serious flaws in the administrative acts resulting from the proceedings for the last RTI established for TGS.

On April 28, 2021, ENARGAS submitted to TGS the 2021 Transitional Agreement (“RTT 2021”), which: (i) does not grant a transitory tariff update, keeping unchanged the tariff schemes approved by ENARGAS in April 2019; (ii) provides that, as from May 2021 and until the Final Renegotiation Agreement enters into effect, ENARGAS will recalculate the transportation tariffs effective at the time, with validity as from April 1, 2022.; (iii) does not establish a mandatory investment plan; and (iv) establishes the prohibition to distribute dividends, early cancel financial and commercial debts taken on with shareholders, acquire other companies, or grant loans.

On April 30, 2021 and through a note sent to this body, TGS expressed that, given the context in which it develops its activities and the proposed terms and conditions, it is not feasible for TGS to enter into the RTT 2021.

On June 2, 2021, ENARGAS issued Resolution No. 149/21 approving an RTT 2021 for TGS effective as from that date. Moreover, the National Ministry of Economy and ENARGAS issued Joint Resolution No. 1/21 approving the proceedings under the renegotiation process developed by ENARGAS pursuant to PEN Executive Order No. 1,020/20, stating that it was not feasible to reach an agreement on a transitional tariff update.

Given this situation, in July 2021, TGS filed motions for reconsideration, subsidiarity filing a hierarchical appeal, before the PEN, the National Ministry of Economy and ENARGAS according to the respective jurisdictions of each of these bodies in the passing of the regulations associated with Resolution No. 149/21, requesting the declaration of nullity of the RTT 2021 and the reinstatement of the RTI.

F-46

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

The challenges are based on: (i) the illegality of Executive Order No. 1,020/20, as it does not observe the delegation lines provided for by Act No. 27,541 and, as it does not meet the requirements established by the Constitution for the dictation of this regulation; (ii) the extension of the emergency period beyond that established by the Congress; (iii) the tariff renegotiation under Act No. 24,076 is not performed; (iv) the disregard for the principle of fair and reasonable tariffs, and the rights acquired by TGS under the license, the Contractual Adjustment Memorandum of Understanding and the RTI; and (v) the suspension of the RTI for reasons of public interest, which merits the recognition of the compensations provided for by both the Administrative Procedures Act and the License Basic Rules.

In turn, the restrictions on the management and administration of TGS have been challenged for lacking legal justification, as the emergency declared by Act No. 27,541 only empowered the PEN to renegotiate the RTI, but not the License. The challenges and the request for reinstatement of the RTI have been filed notwithstanding TGS’s right to the payment of the compensations it is entitled to on account of the breach of the RTI as from April 2019.

On November 15, 2021, TGS filed a Prior Administrative Claim before ENARGAS and the Ministry of Economy. This presentation seeks to request compensation due to TGS for the non-application of the semi-annual adjustment methodology set by the RTI and approved by Resolution 4,362 between October 1, 2019 and June 1, 2021.

Moreover, TGS seeks compensation for the damages sustained by the freeze resulting from the failure to apply the semi-annual adjustment methodology set by the RTI for this period.

On January 19, 2022, a new public hearing was held within the framework of ENARGAS Resolution No. 518/21 to address the transition tariff update under PEN Executive Order No. 1020/20. In this hearing, aiming to reach a final agreement and restore the economic and financial equation, TGS requested a transition tariff adjustment in two stages for 2022 for a total of 106%, given the evolution of operating costs and the main macroeconomic indicators.

Later, on February 1, 2022, TGS received from ENARGAS the proposed Renegotiation Transition Agreement (the “RTT 2022”), which was approved by TGS’s Board of Directors on February 2, 2022, and by the applicable governmental bodies on February 18, 2022. The RTT 2022 included certain terms similar to the RTT 2021, with the specific provision that it granted TGS a 60% tariff increase effective from March 1, 2022.

The RTT 2022 was ratified through PEN Executive Order No. 91/22, effective from February 23, 2022. On February 25, 2022, ENARGAS Resolution No. 60/22 was published in the BO, launching the tariff schemes contemplated in the RTT 2022.

F-47

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

It is worth highlighting that, as provided in the RTT 2022, TGS undertook not to initiate new claims, remedies, lawsuits, or any kind of actions; and/or to suspend, keep suspended or extend the suspension of all claims and remedies associated in any way with the current RTI renegotiation, Law No. 27,541, Decrees No. 278/20 and No. 1,020/20.

On December 7, 2022, ENARGAS issued Resolution No. 523/22 calling for a public hearing, to be held on January 4, 2023, to consider the transitional tariff update for the natural gas transportation utility.

As of the issuance of these Consolidated Financial Statements, TGS is working jointly with ENARGAS to conduct the RTI process that will allow the company to receive a fair and reasonable tariff in line with the provided natural gas transportation utility service.

2.3.2 Regulatory framework of the segment of Production and Commercialization of Liquids

2.3.2.1 Domestic market

The production and commercialization of liquids segment is not subject to regulation by ENARGAS. However, over recent years, the Argentine Government enacted regulations which significantly impacted it.

GLP domestic sales prices are impacted by the provisions of Law No. 26,020 "Regime of the industry and commercialization of liquefied petroleum gas" and the Argentine Government through the public office in charge, that set forth LPG minimum volumes to be sold in the local market in order to guarantee domestic supply.

In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually. On March 30, 2015, the PEN issued Decree No. 470/15, regulated by SE Resolution No. 49/15, which created the “Household Plan” and sets a maximum reference price for the members of the commercialization chain in order to guarantee the supply to low-income residential user, by committing the GLP producers to supply at a fixed price with a quota assigned to each producer. Additionally, payment of compensation to the Household Plan participating producers was established.

TGS has filed various administrative and judicial claims challenging the general regulations of the program, as well as the administrative acts that determine the volumes of butane that must be sold in the domestic market, in order to safeguard its economic-financial situation and thus, preventing that this situation does not extend over time.

F-48

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

In addition, TGS is a party of the Propane Gas Supply Agreement for Induced Propane Gas Distribution Networks ("Propane for Networks Agreement") entered into with the Argentine Government and propane producers by which it undertakes to supply propane to induced propane gas distributors and sub- distributors through at a price lower than the market price. In compensation, TGS receives an economic compensation calculated as the difference between the sale price and the export parity determined by the SE.

As it has been previously mentioned, participation in the Household Plan results in economic and financial damage to TGS, since under certain circumstances products would be sold at prices below their production costs.

As of December 31, 2022, the Argentine Government owes TGS $ 3,768 million under these items.

2.3.2.2 Foreign market

Executive Order No. 488/20 regulated the rate applicable to the export duties for certain gas and oil derivatives, including the products produced and exported by TGS, which ranges between 0% and 8% depending on the price of the “ICE Brent first line” barrel. If this price is below US$ 45, the rate is 0%. Instead, if the price equals or exceeds US$ 60, an 8% rate is paid, and the rate is variable if the price is between US$ 45 and US$ 60.

2.4 Transmisión

2.4.1 Transener and Transba tariff situation

On February 25, 2022, the ENRE communicated Resolutions No. 68/22 and 69/22 approving the new hourly remuneration values effective from February 1, 2022, establishing a 25% and 23% increase compared to the values effective from 2019 for Transener and Transba, respectively. Considering the difference between the presented financial and economic projections and the values finally approved by the ENRE, a motion to review the records and the respective preliminary challenges was submitted. Moreover, on March 15, 2022, the applicable motions for reconsideration against these resolutions were filed. Consequently, under Resolutions No. 147/22 and 148/22, on May 9, 2022 the ENRE partially upheld the filed motions and modified the hourly remuneration values effective from February 1, 2022, establishing a 67% and 69% increase over the values effective from August 2019 for Transener and Transba, respectively.

F-49

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

Since August 2022, Transener and Transba filed notes and held meetings with the SE and the ENRE requesting an update to the transitional tariffs effective from September 2022, chargeable against the increase to be assessed for 2023. To this effect, the 2023 economic and financial projection was presented with an explanatory document and a detail of the projected investment plan. Moreover, a presentation was made to CAMMESA’s Board of Directors to put the criticality of the transportation sector on record.

Under Resolution No. 539/2022, on October 20, 2022 the ENRE called for a public hearing on November 30, 2022 to inform of and gather feedback on the electricity transmission utility concessionaires’ proposals towards a transitional tariff update under the RTI Renegotiation Process before defining the tariffs applicable by the concessionaires.

Furthermore, on December 6, 2022, PEN Executive Order No. 815/22 extended for one-year term PEN Executive Order No. 1,020/20 published on December 17, 2020, through which initiated RTI renegotiation within up to 2 years from its publication.

Later, on December 29, 2022, aiming to preserve in 2023 the purchasing power of the revenues established in Resolutions No. 147/22 and 148/22, the ENRE issued Resolutions No. 698/22 and 702/22 setting the hourly remuneration values effective from January 1, 2023, and establishing a 154.5% and 154.1% increase over the February 2022 values for Transener and Transba, respectively.

2.5 Regulations on access to the MLC

In 2020, BCRA introduced 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.

F-50

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

To access the MLC in terms of expenditures without BCRA’s prior authorization, it is necessary to file an affidavit certifying that all foreign-currency holdings in the country are deposited in accounts with local financial institutions and that it no available liquid foreign assets are held for an amount equivalent to or higher than US$ 100,000. In case such liquid foreign assets exceed the amount of US$ 100,000, an additional affidavit could be submitted according to the applicable provisions. To such effects, the term “liquid foreign assets” will comprise, among others: holdings of foreign currency notes and coins, availability of gold in the form of good delivery bars or coins, sight deposits in foreign financial entities, holding of Argentine certificates of deposit (“CEDEAR”) and other investments allowing for the immediate availability of foreign currency (for example, investments in foreign public securities, funds in investment accounts deposited with investment managers located abroad, crypto assets, funds deposited in payment service providers’ accounts, etc.). On the other hand, the following will not be considered available liquid foreign assets: funds deposited abroad that may not be used by the customer as they are reserve or guarantee funds created under foreign debt contracts, or funds kept as collateral for foreign transactions with derivatives entered into abroad.

Furthermore, in case access to the MLC has been requested, it is mandatory to enter and settle in the MLC, within a term of five business days after they become available, foreign funds originating from the collection of loans granted to third parties, the collection of time deposits or the sale of any kind of asset, in case the asset has been acquired, the deposit has been made or the loan has been granted after May 28, 2020.

As regards transactions with stock market assets is established: (i) the presentation of an affidavit declaring that, on the date of access to the MLC and in the previous 90 calendar days, no domestic sales of securities to be settled in foreign currency, exchanges of securities issued by foreign active residents, transfers of securities to foreign depositary entities, local acquisitions of securities issued by non-residents and settled in pesos, acquisitions of CEDEAR representing foreign shares (from July 22, 2022), acquisitions of private debt securities issued in a foreign jurisdiction, or deliveries of funds in domestic currency or other domestic assets (except for foreign-currency funds deposited with local financial entities) to any natural or legal, resident or non-resident person, and whether or not affiliated, receiving as prior or subsequent consideration, whether directly or indirectly, on its own or through any affiliate, controlled or controlling entity, foreign assets, crypto-assets or securities deposited abroad and, lastly, the commitment not to perform any of the detailed transactions for 90 calendar days following the request for access to the MLC should be evidenced; and (ii) that security transactions concerted abroad and securities acquired abroad may not be settled in pesos in the country. Moreover, if the customer is a legal entity, as an additional requirement to access the MLC, it also provided for an additional affidavit stating: (a) details of the individuals or legal entities exercising a direct control relationship over the customer, according to BCRA’s regulations; and (b) that on the day access to the MLC is requested and in the previous 90 calendar days, no local-currency funds or other liquid domestic assets have been delivered in Argentina to any individual or legal entity exercising a direct control relationship over it, except for those directly associated with regular transactions for the acquisition of goods and/or services. The requirement stated in item (b) will be deemed duly met if the customer submits an affidavit regarding transactions with securities of each individual or legal entity pursuant to the current exchange regulations.

F-51

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

BCRA’s prior authorization to access the MLC to cancel the principal of foreign financial debts with foreign affiliates is required up to and including December 31, 2023. Furthermore, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled until December 31, 2023, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, within the original term; and (ii) the refinancing of the principal balance, through new foreign indebtedness with an average life of 2 years. Within the framework of this refinancing process, access to the MLC is allowed for the early cancellation of principal, interest or debt swaps up to 45 calendar days before the maturity date, provided all requirements set forth by the regulation have been verified.

On October 2022, the Integral Import Monitoring System (“SIMI”) and the Integral Foreign Payments Monitoring System (“SIMPES”) were replaced by the Argentine Republic’s Imports System (“SIRA”) and the Argentine Republic’s Imports and Foreign Service Payments System (“SIRASE”), respectively. Moreover, BCRA established that no more advance, sight, or deferred without clearance payments may be made through these new mechanisms, except for certain cases contemplated in the regulation.

Regarding imports, BCRA’s prior authorization to access the MLC is required to make payments to import certain goods abroad or cancel the principal of debts originating from the import of goods by companies. Additionally, before executing payments for the import of goods, entities should verify that the affidavit requested from the customer is compatible with BCRA’s existing data. Additionally, the BCRA created a registry of foreign exchange information of goods exporters and importers as a requirement to access the MLC to perform forex outflow transactions, including swaps and arbitrations. The Company has been declared an obliged subject by the BCRA; it has completed its enrollment in this registry and is under a duty to report any change in the recorded information within 15 business days of its occurrence.

Additionally, in October 2022, the BCRA introduced adjustment to foreign exchange regulations, establishing, among other provisions, access to the MLC for subjects obtaining certifications under currency access systems for the incremental production of oil and/or natural gas pursuant to PEN Executive Order No. 277/22 (see Note 2.2.3), for up to the amount of each certification, to be allocated to the payment of: (i) principal and interest of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, (ii) earnings and dividends for closed and audited balance sheets; and/or (iii) the repatriation of direct investments by non-residents. RADPIP and/or RADPIGN beneficiaries should appoint a single domestic financial entity responsible for issuing such certifications and recording the amounts recognized by the SE and the applicable period.

More information on Argentina’s foreign exchange regulations can be found at the Central Bank’s website: www.bcra.gov.ar.

F-52

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

2.6 Tax regulations - Main tax reforms

Pursuant to Law No. 27,430, Law No. 27,541, Law No. 27,630, and Law No. 27,701 several modifications were introduced in the tax treatment, the key components of which are described below:

2.6.1 Income tax

2.6.1.1 Income tax rate

Pursuant to Law No. 27,430, the income tax rate for Argentine companies would be gradually reduced from 35% to 30% for fiscal years beginning from January 1, 2018 to December 31, 2019, and to 25% for fiscal years beginning on or after January 1, 2020. However, Law No. 27,541 suspended the tax rate reduction planned for fiscal year 2020, keeping the rate at 30%.

On June 16, 2021, Law No. 27,630 was published in the BO, which modified the income tax rate effective for fiscal years starting as from January 1, 2021 inclusive. This modification provides for the application of a tiered rate scheme and, if applicable, a fixed tax according to the accumulated net taxable income tier: (i) for accumulated net income of up to $ 5 million, it establishes a 25% rate; (ii) for accumulated net income between $ 5 and $ 50 million, it establishes a fixed tax of $1.25 million plus a 30% rate over the surplus of $ 5 million; and (iii) for accumulated net income above $ 50 million, it establishes a fixed tax of $ 14.75 million plus a 35% rate over the surplus of $50 million. The accumulated net income amount will be adjusted yearly, as from January 1, 2022, taking into consideration the annual CPI variation published by the INDEC.

The effect of the changes on deferred tax corresponding to comparative periods pursuant to the above-mentioned tax reform was recognised, considering the effective rate expected to be applicable at deferred assets and liabilities realization year, in “Effect of tax rate change in the deferred tax” under “Income tax” of the Consolidated Statement of Comprehensive Income (Note 10.5).

On August 16, 2022, AFIP’s General Resolution No. 5,248/22 was published in the BO, whereby the AFIP established a one-time income tax prepayment by taxpayers and responsible persons listed in Section 73 of Law No. 20,628, as amended, meeting the following parameters: (i) an assessed tax for the 2021 or 2022 tax period of at least $ 100 million, or (ii) taxable income, without deducting accumulated tax losses, of at least $ 300 million. As of issuance of these Consolidated Financial Statements, the Company and its subsidiaries paid an income tax prepayment for $ 1,863 million.

F-53

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, which be 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 will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax’ transition period) for all beneficiaries.

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; alternatively, for the first, second and third fiscal year as from its effective date, this proceeding will apply in case the accumulated variation in such price index, calculated from the beginning of the first fiscal year to the closing of each fiscal year, are higher than 55%, 30% and 15% for the years 2018, 2019 and 2020, respectively.

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. Failure to comply with this requirement will result in the loss of this benefit.

F-54

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 2: (Continuation)

As 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 (see Note 10.5).

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.

NOTE 3: BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS issued by IASB, are expressed in million dollars and were approved for their issuance by the Board of Directors on March 9, 2023. 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-55

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

4.1 New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2022 and adopted by the Company

The Company has applied the following standards and/or amendments for the first time as of January 1, 2022:

- IFRS 3 “Business combination” (amended in May 2020).

- Annual Improvements to IFRS Standards - 2018-2020 cycle (issued in May 2020).

- IAS 16 “Property, Plant and Equipment” (amended in May 2020).

- IAS 37 “Provisions, contingent liabilities and contingent assets” (amended in May 2020).

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

- IFRS 17 - “Insurance Contracts”: issued in May 2017 and modified in June 2020 and December 2021. It supersedes IFRS 4, introduced in 2004 as an interim standard, which gave companies dispensation to carry on accounting for insurance contracts using national accounting standards, thus resulting in several application approaches. IFRS 17 sets the principles for the recognition, measurement, presentation and disclosure of information associated with insurance contracts and is applicable as from January 1, 2023, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in February 2021. It incorporates amendments to the information to be disclosed on accounting policies. Amendments are applicable to fiscal years starting on or after January 1, 2023, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 8 - “Accounting Policies”: amended in February 2021. Clarifies the treatment of estimates required in the application of accounting policies. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

F-56

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

- IAS 12 - “Income Tax”: amended in May 2021. It incorporates modifications regarding the recognition of deferred tax related to assets and liabilities that arise from a single transaction, giving riso to equal taxable and deductible temporary differences. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

- IFRS 16 - “Leases”: amended in September 2022. It incorporates amendments on sale and leaseback transactions. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in January 2020, July 2020 and October 2022. It incorporates amendments to the classification of liabilities as current or non-current and provides clarification on the treatment to be given to liabilities with covenants. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company’s operating results or financial position.

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 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 IAS 29 adjustment mechanism for hyperinflationary economies, on the opening equity measured in functional currency are recognised 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.

F-57

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.4 Principles of consolidation and equity accounting

4.4.1 Subsidiaries

Subsidiaries are all entities over which the Group has control. 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. The Group 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 (see Note 4.4.5 below).

Intercompany transactions, balances and unrealized gains on transactions between Group entities are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the transferred asset. 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, Consolidated Statement of Changes in Equity and Consolidated Statement of Financial Position respectively.

4.4.2 Associates

Associates are all entities over which the group has significant influence but not control or joint control. This is generally the case where the Group holds between 20% and 50% of the voting rights. Investments in associates are accounted for using the equity method of accounting (see Note 4.4.4 below), after initially being recognised at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according to IFRS 11. The classification depends on the contractual rights and obligations of each investor, rather than the legal structure of the joint arrangement. The Company has both joint operations and joint ventures.

4.4.3.1 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. These have been incorporated in the Consolidated Financial Statements under the appropriate headings.

F-58

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.4.3.2 Joint ventures

Interests in joint ventures are accounted for using the equity method, after initially being recognised at cost (see Note 4.4.4 below).

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognised at cost and adjusted to recognize the Group’s share of the post-acquisition profits or losses of the investee in profit or loss, and the Group’s share of movements in other comprehensive income of the investee in other comprehensive income.

On acquisition of the investment, any difference between the cost of the investment and the entity’s share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as follows: (i) goodwill relating to an associate or a joint venture is included in the carrying amount of the investment and is not amortised, and (ii) any excess of the net fair value over the cost is included as income in the determination of the entity’s share of the associate or joint venture’s profit or loss.

Dividends received or receivable from associates and joint ventures are recognised as a reduction in the carrying amount of the investment.

When the Group’s share of losses in an equity-accounted investment equals or exceeds its interest in the entity, together with any long-term interests that, in substance, form part of the net investment, the Group does not recognize further losses, unless it has incurred obligations or made payments on behalf of the other entity.

Unrealized gains on transactions between the Group and its associates and joint ventures are eliminated to the extent of the group’s interest in these entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of equity accounted investees have been changed where necessary to ensure consistency with the policies adopted by the Group.

The carrying amount of equity accounted investments is tested for impairment in accordance with the policy described below in Note 4.9.

4.4.5 Business combinations

The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisitions comprises:

(i) the fair value of the transferred assets,

(ii) the liabilities incurred to the former owners of the acquired business,

(iii) the equity interests issued by the group,

(iv) the fair value of any asset or liability resulting from a contingent consideration arrangement, and

(v) the fair value of any pre-existing equity interest in the subsidiary.

F-59

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values in the acquisition date. The group recognises any non-controlling interest in the acquired entity on an acquisition-by-acquisition basis at the non-controlling interest’s proportionate share of the acquired entity’s net identifiable assets.

Acquisition-related costs are expensed as incurred. The value of the goodwill represents the excess of: i) the consideration transferred, ii) the amount of any non-controlling interest in the acquired entity, and iii) the acquisition-date fair value of any previous equity interest in the acquired entity, over the fair value of the net identifiable assets acquired is recorded as goodwill. If the fair value of the net identifiable assets of the business acquired exceeds those amounts, the gain on bargain purchase is recognised directly in profit or loss.

Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing could be obtained from an independent financier under comparable terms and conditions.

Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently remeasured to fair value with changes in fair value recognised in profit or loss.

If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit or loss.

The Group has up to 12 months to finalize the accounting for a business combination. Where the accounting for a business combination is not complete by the end of the year in which the business combination occurred, the Group reports provisional amounts.

4.4.6 Changes in ownership interests

The Group treats transactions with non-controlling interests that do not result in a loss of control as transactions with equity owners of the group. A change in ownership interest results in an adjustment between the carrying amounts of the controlling and non-controlling interests to reflect their relative interests in the subsidiary. Any difference between the amount of the adjustment to non-controlling interests and any consideration paid or received is recognised in “Other reserves” within equity attributable to owners of the Company.

F-60

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

When the Group ceases to consolidate or equity account for an investment because of a loss of control, joint control or significant influence, any retained interest in the entity is remeasured to its fair value with the change in carrying amount recognised in profit or loss. This fair value becomes the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities, this means that amounts previously recognised in other comprehensive income are reclassified to profit or loss.

If the ownership interest in a joint venture or an associate is reduced but joint control or significant influence is retained, only a proportionate share of the amounts previously recognised in other comprehensive income are reclassified to profit or loss where appropriate.

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 person 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.

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.

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.

F-61

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Works in progress are valued according to their degree of progress. Works in progress are recorded at cost less any loss due to impairment, if applicable.

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.

Gains and losses on disposals are determined by comparing the sale price with the carrying amount, stated in terms of the measuring unit current at the disposal date.

4.6.1 Depreciation methods and useful lives

The group depreciates productive wells, machinery and camps 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.

Machinery and generation equipment (including any significant identifiable component) are depreciated under the unit of production 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:

Buildings:	50 years
Vehicles:	3 - 5 years
Furniture, fittings and communication equipment:	5 years
Computer equipment and software:	3 years
Tools:	10 years
Equipment and machinery:	10 - 30 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

F-62

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.6.2 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 in wind farms, 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 the acquisition of subsidiaries. Goodwill represents the excess of the acquisition cost over the fair value of the equity interest in the acquired entity held by the company on the net identifiable assets acquired on the date of acquisition.

For impairment testing, goodwill acquired in a business combination is allocated from the acquisition date to each of the acquirer’s CGU or group of CGU that are expected to benefit from the synergies of the combination. Each unit or group of units that goodwill is allocated represents the lowest level within the entity at which the goodwill is monitored for internal management purposes.

4.7.2 Concession arrangements

Concession arrangements corresponding to hydroelectric generation plants Diamante and Nihuiles are not under the scope of the guidelines of IFRIC 12 “Service Concession Arrangements”.

These concession agreements meet the criteria set forth by the IFRSs for capitalization less depreciation a less any accumulated impairment. They are amortized following the straight-line method based on useful life, which corresponds to the life of each concession agreement.

F-63

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.7.3 Identified intangible assets in acquired investments

Corresponds to intangible assets identified in the moment of the acquisition of companies. Identified assets meet the criteria established in IFRS 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, considering the estimated way in which the benefits produced by the asset will be consumed.

4.7.4 Digital Assets

The Company accounts for digital assets (cryptocurrencies) as intangible assets with indefinite useful life under the cost model. They are recognised at acquisition cost less any accumulated impairment.

4.8 Assets for oil and gas exploration

The Company uses the successful efforts method of accounting for its oil and gas exploration and production activities. This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas exploration and production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of commercially recoverable reserves; (iii) the cost of drilling and equipping development wells, and (iv) the estimated asset retirement obligations (see Note 4.6.2).

According to the successful efforts method of accounting, exploration costs (including geological and geophysical costs), excluding exploratory well costs, are expensed during the period in which they are incurred. Drilling costs of exploratory wells are capitalized until it is determined that proved reserves exists and they justify the commercial development. If reserves are not found, such drilling costs are expensed. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is complete. In those cases, such costs continue to be capitalized insofar as the well has allowed determining the existence of sufficient reserves to warrant its completion as a production well and the Company is making sufficient progress in evaluating the economic and operating feasibility of the project.

F-64

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.9 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 impairment, 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.

4.10 Financial assets

4.10.1 Classification

The Group classifies its financial assets in the following categories:

(i) those that are subsequently measured at fair value, and

(ii) those that are subsequently measured at amortised cost.

The classification depends on the entity’s business model for managing the financial assets and the contractual cash flow characteristics.

Gains and losses from financial assets measured at fair value, will be recorded in the Statement of Comprehensive Income or in the Other Comprehensive Income.

Investments in equity instruments are measured at fair value. For those investments that are not held for trading, the Company may make an irrevocable election at initial recognition to present subsequent changes in other comprehensive income. The Company's election was to recognize changes in fair value through profit and loss.

The company reclassifies financial assets when and only when it changes its business model for managing those financial assets.

F-65

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.10.2 Recognition and derecognition

The conventional purchases and sales of financial assets are accounted for at settlement date. Financial assets are derecognised when contractual rights to the cash flows from the financial assets have expired or been transferred, and the Company has substantially transferred all risks and rewards of ownership of the asset.

4.10.3 Measurement

At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset.

A gain or loss on a debt investment that is subsequently measured at fair value and is not part of a hedging relationship is recognised in profit or loss and disclosed in “Changes in the fair value of financial instruments” within “Other financial Results. A gain or loss on a debt investment that is subsequently measured at amortized cost and is not part of a hedging relationship is recognised in profit or loss when the financial asset is derecognised or impaired and through the amortization process using the effective interest rate method.

The Group subsequently measures equity investments at fair value. Dividends from such investments continue to be recognised in profit or loss as long as they represent a return on investment.

4.10.4 Impairment of financial assets

The Company assesses the expected credit losses related to its financial instruments at amortized cost and financial instruments at fair value through other comprehensive income, if applicable.

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.

F-66

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.10.5 Offsetting of financial instruments

Financial assets and liabilities are offset, and the net amount reported in the consolidated statements of financial position, when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

4.11 Trade and other receivables

Trade receivables and other receivables are recognised at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognizes provisions for impairment on trade and other receivables based on expected credit loss model described in Note 4.10.4. Trade receivables are written off when there is no reasonable expectation of recovery. The Company considers the following default indicators: i) voluntary reorganization proceedings, bankruptcy or initiation of judicial demands; ii) insolvency implying a high impossibility of collection and iii) past due balances greater than 90 days.

Where 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.

4.12 Derivative financial instruments and hedging account

Derivative financial instruments are measured at fair value, determined as the amount of cash to be collected or paid to settle the instrument as of the measurement date, net of any prepayment collected or paid. Fair value of derivative financial instruments traded in active markets is disclosed based on their quoted market prices and fair value of instruments that are not traded in active markets is determined using different valuation techniques. Subsequent accounting of 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.

The Company may designate derivative financial instruments in the following categories:

(i) fair value hedge of recognised assets or liabilities or over firm commitment (fair value hedge);

(ii) cash flow hedges of a particular risk associated with recognised assets and liabilities and highly probable future transactions (cash flow hedges), or

(iii) net investment hedge in foreign operation (net investment hedges).

F-67

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

At the beginning of the hedge relationship, the Group documents the economic relationship between the hedging instruments and the hedged items, even if it is expected that changes in the cash flows of the hedging instruments offset changes in the cash flows of the hedged items. The Group documents its objective and risk management strategy to carry out its hedging operations.

Changes in the measurement of derivative financial instruments designated as cash flow hedge, which have been determined as effective, are recognised in equity. The gain or loss related to the ineffective portion is recognised immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognised in profit or loss.

The Company has not formally designated financial instruments as hedging instruments.

4.13 Inventories

This line item includes crude oil stock, raw materials, work in progress and finished products relating to Petrochemicals and Oil and Gas business segments as well as materials and spare parts relating to the Generation business segment.

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average price method. The cost of inventories 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 assessment of the recoverable value of these assets is made at each reporting date, and the resulting loss is recognised in the statement of income when the inventories are overstated.

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”.

4.14 Non-current assets (or disposal group) held for sale and discontinued operations

Non-current assets are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights from insurance contracts, which are specifically exempt from this requirement.

F-68

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

An impairment loss is recognized for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset (or disposal group), but not in excess of any cumulative impairment loss previously recognized. The gain or loss not previously recognized by the date of the sale of the non-current asset is recognized at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised.

Non-current assets or group of assets classified as held for sale are presented separately from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the balance sheet. These assets and liabilities are not offset.

If it is a discontinued operation, that is, an item which has been disposed of or classified as held for sale; and (i) it represents a significant business line or geographic area which may be considered separate from the rest; (ii) it is part of a single coordinated plan to dispose of a significant business line or operating geographic area which may be deemed separate from the rest; or (iii) it is a subsidiary entity acquired solely for the purpose of reselling it; a single amount is disclosed in the statement of comprehensive income, which shows results of discontinued operations, net of tax, including the result for the valuation at fair value less cost of sales or asset disposal costs, if applicable.

4.15 Cash and cash equivalents

For the purpose of presentation in the Consolidated Statement of Cash Flows, cash and cash equivalents includes 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 in the Consolidated Statement of Financial Position 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.

4.16 Shareholder´s equity

Equity’s movements accounted for in accordance with the pertinent decisions of shareholders' meetings and legal or regulatory standards.

F-69

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

All equity accounts have been restated in terms of the measuring unit current as of December 31, 2018, with the exception of Share capital and Treasury shares, which represent the subscribed and paid in, and the outstanding treasury capital, respectively. The adjustment resulting from its restatement as of December 31, 2018 is disclosed in the Comprehensive share capital adjustment and Comprehensive treasury shares adjustment lines, respectively.

As from the change in functional currency, on January 1, 2019 the Company discontinued the preparation and presentation of financial statements under IAS 29, and has considered equity figures expressed in terms of the measuring unit current as of December 31, 2018 as the basis for subsequent financial statements’ amounts. 

4.16.1 Share capital

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.

4.16.2 Share premium

It 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 or significant influence.

(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.

4.16.3 Legal reserve

In accordance with the Argentine Commercial Companies General Law, 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.

F-70

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.16.4 Voluntary reserve

This reserve results from an allocation made by the Shareholders’ Meeting, whereby a specific amount is set aside to cover for the funding needs of projects and situations associated with Company policies. 

4.16.5 Other reserves

It includes the result of operations with non-controlling interest that do not result in a loss of control and reserves for stock compensation plans. 

4.16.6 Retained earnings

Comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of Shareholders' meeting, as long as they are not subject to legal restrictions. Earnings comprise current earnings, prior years' earnings that were not distributed, translation differences which are directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4, the amounts transferred from other comprehensive income and prior years' adjustments, according to IFRS.

General Resolution No. 593/11 issued by the CNV provided that Shareholders in the Meetings at which they should decide upon the approval of financial statements in which the Retained earnings account has a positive balance, should adopt an express resolution as to the allocation of such balance, whether to dividend distribution, capitalization, setting up of reserves or a combination of these. The Company’s Shareholders have complied with these requirements.

4.16.7 Other comprehensive income

It 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 and actuarial gains and losses for defined benefit plans and the related tax effect.

4.16.8 Dividends distribution

Dividend distribution to Company shareholders is recognised 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-71

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.17 Compensation plans

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

4.17.1 Compensations payable in cash:

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 over the Company’s adjusted operating income. With the purpose of avoiding duplication, any analogous compensation paid to senior managers by any of the Company’s subsidiaries will be deducted from the compensation amount in proportion to the Company’s interests in such subsidiaries. 

The reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton financial valuation 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. 

4.17.2 Compensations payable in shares

Stock compensation plan by which certain officers and other key staff receive a certain number of the Company’s shares. The Company’s Board of Directors approves the market acquisition of own shares as a means of implementing the Plan (see Note 13.1.2).

The number of shares is calculated as from a percentage over the total annual remuneration, plus the bonus assigned to each covered employee, 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.

4.18 Trade payables and other payables

Trade payables and other payables are recognised initially at fair value and subsequently measured at amortized cost using the effective interest method.

F-72

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.19 Borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings, using the effective interest method.

Borrowings are removed from the statement of financial position when the obligation specified in the contract is discharged, canceled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in profit or loss as other income or finance costs.

If a debt contract is amended or swapped, the Company records the cancellation of the original liability and discloses 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. 

4.19.1 Borrowing costs

General and specific borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalized during the period of time that is required to complete and prepare the asset for its intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalization.

Other borrowing costs are expensed in the period in which they are incurred.

4.20 Employee benefits

4.20.1 Short-term obligations

Payroll liabilities, including non-monetary benefits and accumulated sick leave expected to be settled in full within 12 months after the end of the reporting period in which the employees provide the associated service are recognised for the amount expected to be paid when the liabilities are settled. The liabilities are disclosed as Salaries and social security payable in the consolidated statement of financial position.

F-73

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.20.2 Defined benefit plans

Labor costs liabilities are accrued in the periods in which the employees provide the services that trigger the consideration.

Additionally, the Company operates several 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).

4.21 Provisions, contingent liabilities and contingent assets

Provisions are recognised when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle that obligation, and the amount can be reliably estimated. Provisions are not recognised for future operating losses.

Provisions are measured at the present value of the expenditures expected to be required to settle the present obligation, taking into account the best available information as of the date of the Consolidated Financial Statements based on assumptions and methods considered appropriate and taking into account the opinion of Company’s legal advisors. As additional information becomes available to the Company, estimates are revised and adjusted periodically. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability, as of the date of the financial statements. The increase in the provision due to the passage of time is recognised within other financial results.

F-74

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Contingent liabilities are possible obligations that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity; or present obligations that arise from past events but it is not probable that an outflow of resources will be required to its settlement; or whose amount cannot be measured with sufficient reliability.

Contingent liabilities are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent liabilities.

Contingent liabilities, whose possibility of any outflow in settlement is remote, are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Contingent assets are possible assets that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity.

Contingent assets are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent assets, where the related inflows of economic benefits are estimated to be probable.

4.22 Revenue from contracts with customers

4.22.1 Generation segment:

4.22.1.1 Revenues from sales to the spot market (SE Resolution N°826/22)

The Company recognizes revenues from i) power availability on a monthly basis as the different power plants are available to generate; ii) power generated, operated energy and power generated in peak hours, when the delivery of energy is effective, based on the price applicable depending on the technology of each plant. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 42 days, which is consistent with market practice.

4.22.1.2 Revenues from supply agreements with CAMMESA (SE Resolution No. 220/07, SEE Resolution No. 21/16, SEE Resolution No. 287/17 and Renovar Programs)

The Company recognizes revenues from supply contracts with CAMMESA for i) power availability, when applicable, on a monthly basis, as the different power plants are available to generate and ii) energy generated when the delivery of energy is effective, 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 credit term of 42 days, which is consistent with market practice.

F-75

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.22.1.3 Revenues from sales contracts with large users within the MAT

The Company recognizes revenues from energy plus sales and renewable energy when the delivery of energy is effective 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 credit term of 30 days, which is consistent with market practice. 

4.22.2 Oil and gas segment

The Company recognizes revenues from the sale of oil and gas, to third parties and intersegment, 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 could affect the acceptance of the product by the client. In all cases the transport of the gas is in charge of the client. Revenues from these sales are recognised based on the price by product specified in each contract or agreement 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 credit term not exceeding 45 days, which is consistent with market practice.

4.22.3 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 products according to the sale contract, the acceptance provisions have expired, 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 credit term not exceeding 30 days, which is consistent with market practice.

F-76

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.22.4 Holding 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.

4.23 Other Income

4.23.1 Government grants

Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. The group did not benefit directly from any other forms of government assistance.

The Company recognizes revenues from natural gas production promotion or stimulus programs upon the actual delivery of gas and in accordance with the price established in the applicable regulation, only inasmuch as it is highly probable that there will be no significant reversal and the consideration is likely to be received, that is, to the extent that the procedure defined by the Government is formally complied with.

The recognition of revenues associated with Natural Gas Production Promotion or Stimulus Plans (see Note 2.2.4.1) falls within the scope of IAS 20 as it involves a compensation as a result of the maintenance or increase in the committed production volume.

Revenues from natural gas production or stimulus programs are disclosed under other operating income in the consolidated statement of comprehensive income. Furthermore, the fiscal costs of the above-mentioned programs are disclosed under Other operating expenses in the consolidated statement of comprehensive income. 

4.23.2 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 cost and financial assets at fair value through other comprehensive income 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.

F-77

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

4.23.3 Dividends

Dividends income are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognised as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

4.24 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, in which case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet. 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.

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. However, deferred tax liabilities are not recognised if they come from the initial recognition of goodwill; or if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at time of the transaction affects neither accounting nor taxable profit or loss.

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 Law No 27,701, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1).

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.

F-78

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Current and deferred tax assets and liabilities have not been discounted and are stated at their nominal value.

Income tax rates prevailing at year-end in Argentina (see Note 2.6.1), Ecuador, Bolivia and Uruguay are 35%, 25%, 25% and 25%, respectively. Additionally, a 3% surcharge is added to Ecuador’s income tax when the company’s shareholder residing in Ecuador is an entity established in a jurisdiction considered a tax haven under Ecuadorian laws.

In Bolivia, payment of Bolivian-source income to beneficiaries outside Bolivia is levied with a 12.5% withholding income tax. Furthermore, and pursuant to the last tax reform passed in Ecuador and effective as from January 1, 2020, dividends distributed to foreign shareholders will be subject to a 10% withholding.

In Uruguay, effective from January 1, 2023, the Income Tax on Economic Activities (“IRAE”) covers certain Uruguayan-source passive income derived by entities making up multinational groups.

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.

4.25 Leases

In leases where the Company is a lessee (Note 19.1), a right-of-use asset and a lease liability are recognised on the date on which the underlying asset is available for use by the Company.

At the commencement date the lease liability is measured at the present value of the payments that are not paid at that date, including:

- fixed payments, less any lease incentive receivable

- variable lease payments depending on an index or rate

- amounts that the Company expects to pay under residual value guarantee

- exercise price of a purchase option (if the Company is reasonably certain to exercise that option), and

- penalty payments for terminating the lease, if the lease term reflects the Company exercising that option.

F-79

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 4: (Continuation)

Lease payments are discounted using the Company’s incremental borrowing rate, which is the rate the Company would have to pay to borrow over a similar term, security and conditions, the funds necessary to acquire an asset of a similar value to the right-of-use asset in a similar economic environment, or by using the interest rate implicit in the lease, if that rate can be readily determined.

The lease liability is disclosed in “Trade and other payables”. Each lease payment is apportioned between the principal and the financial cost. The financial 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.

Right-of-use assets are measured at cost, which comprises:

- the amount of the initial measurement of the lease liability

- any lease payment made at or before the commencement date, less any lease incentive received

- any initial direct cost, and

- an estimate of costs to be incurred for decommissioning or restoring the underlying asset pursuant to the terms and conditions of the lease

Right-of-use assets are depreciated using the straight-line method over the asset’s useful life or, if shorter, during the lease term.

The Company recognizes lease payments associated with short-term leases (up to 12 months) and leases for which the underlying asset is of low value (IT equipment and office supplies) as an expense using the straight-line method over the lease term.

Leases in which the Company, as a lessor, has transferred all risks and rewards incidental to ownership of the underlying asset are classified as financial leases (Note 19.2.1). Financial leases are recognised at the commencement date 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”. Each lease payment received is allocated between income receivable and financial income. Financial income is recognised as a profit over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period. Property under financial leases is derecognised if there is reasonable certainty that the Company will transfer its ownership at the end of the lease term.

Leases in which the Company does not transfer a significant part of the risks and rewards incidental to ownership of the underlying asset are classified as operating leases. Revenues from associated leases are recognized in income using the straight-line method over the term of the lease (Note 19.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

F-80

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: GROUP STRUCTURE

5.1 Acquisition and sale of equity interests

5.1.1 Sale of equity interests of controlling stake in Edenor

On December 28, 2020, the Company entered into with Empresa de Energía del Cono Sur S.A. and Integra Capital S.A., Daniel Eduardo Vila, Mauricio Filiberti and José Luis Manzano (the “Purchaser”) a share purchase agreement whereby it agreed to sell its controlling interest in Edenor through the transfer of all Class A shares representing 51% of the capital stock and voting rights of said company (the “Transaction”). On February 17, 2021, Pampa’s shareholders meeting was held and the Transaction was approved.

On June 24, 2021, the ENRE approved the Transaction through Resolution No. 207/21, whereas, after meeting the precedent conditions, the transaction closing took place on June 30, 2021, with the transfer of shares and the change of controlling shareholder.

The agreed sales price consisted of: 21,876,856 Class B shares of Edenor, representing 2.41% of Edenor’s capital stock and voting rights, transferred upon the execution of the share purchase agreement; and US$ 95 million in cash, which was paid in 3 installments: (i) US$ 5 million upon the execution of the share purchase agreement; (ii) US$ 50 million on the closing date; and US$ 40 million, plus interest at a 10% fixed nominal annual rate (payable quarterly), between June and July 2022.

Within the previously described framework and pursuant to IFRS 5, and considering that the transaction involved loss of control over the subsidiary, all Edenor’s assets and liabilities had been classified as held for sale as of December 31, 2020 and had been measured at the lower between its fair value, net of costs associated with the sale, if applicable, and its book value, which involved the recognition of an impairment loss for US$ 589 million, included together with the results corresponding the Distribution of energy segment under “Discontinued operations” of the Consolidated Statement of Comprehensive Income for the years ended December 31, 2021 and 2020.

F-81

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The statement of comprehensive income associated with the discontinued operations is disclosed below:

	Distribution of Energy
	12.31.2021	12.31.2020
Revenue	493	1,085
Cost of sales	(398)	(926)
Gross profit	95	159
Selling expenses	(36)	(79)
Administrative expenses	(26)	(64)
Other operating income	21	29
Other operating expenses	(18)	(25)
Reversal of property, plant and equipment impairment	16	(589)
Impairment of financial assets	(11)	(50)
Operating income (loss)	41	(619)
Gain on monetary position, net	120	115
Financial income	-	1
Financial costs	(106)	(110)
Other financial results	8	(20)
Financial results, net	22	(14)
Profit (Loss) before income tax	63	(633)
Income tax	(138)	41
Loss of the year from discontinued operations	(75)	(592)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans	-	1
Exchange differences on translation	34	(15)
Items that may be reclassified to profit or loss
Exchange differences on translation (1)	30	(19)
Other comprehensive income (loss) of the year from discontinued operations	64	(33)
Total comprehensive loss of the year from discontinued operations	(11)	(625)
Total  (loss) profit of the year from discontinued operations attributable to:
Owners of the company	(39)	(499)
Non - controlling interest	(36)	(93)
	(75)	(592)
Total comprehensive loss of the year from discontinued operations attributable to:
Owners of the company	(9)	(517)
Non - controlling interest	(2)	(108)
	(11)	(625)

⁽¹⁾ As of December 31, 2021, corresponds to the reclassification adjustment for exchange differences losses included in profit or loss on Edenor disposal. No exchange differences losses on translation were reconized during 2021.

F-82

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The consolidated statement of cash flows related to discontinued operations as of December 21, 2021 and 2020 is presented below:

	Distribution of Energy
	12.31.2021	12.31.2020
Net cash generated by operating activities	116	211
Net cash used in investing activities	(166)	(86)
Net cash used in financing activities	(7)	(73)
(Decrease) Increase in cash and cash equivalents from discontinued operations	(57)	52
Cash and cash equivalents at the beginning of the year	52	9
Effect of devaluation and inflation on cash and cash equivalents	5	(9)
(Decrease) Increase in cash and cash equivalents	(57)	52
Cash and cash equivalents at the end of the year	-	52

5.1.2 Sale of equity interests in Refinor

On September 15, 2022, the Company entered into an agreement with Hidrocarburos del Norte S.A. for the sale of its Class A shares representing 28.5% of Refinor’s capital stock for a price of US$ 5.7 million, subject to the fulfillment of certain precedent conditions.

As of September 30, 2022, in accordance with IFRS 5 and since the transaction price was below the carrying amount, the Company recognised impairment losses, before taxes, for US$ 11 million, which are disclosed under “Share of profit from associates and joint ventures”.

On October 14, 2022, with the precedent conditions being met, the Company transferred such shares. As of the date of issuance of these Consolidated Financial Statements, the Company has collected US$ 1.7 million, and the amount of US$ 4 million is pending collection, to be financed over one year from the date of sale at an 8% nominal annual fixed interest rate in accordance with the share acquisition agreement.

F-83

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.1.3 Acquisition of an additional 50% interest in Greenwind

On August 12, 2022, Vientos Solutions L.L.C., Rio River Capital L.L.C and the Group entered into a share acquisition agreement whereby it acquired, for the amount of US$ 20.5 million, the whole equity interest in VS SLU, a Spanish company which main asset is its 50% interest in Greenwind’s capital stock.

On the acquisition date, the Company recorded profits of US$ 23.3 million to reflect the fair value of the 50% stake in Greenwind prior to the aforementioned acquisition, as this transaction is a business combination achieved in stages.

The following table details the fair value of the consideration transferred and the fair values of the assets acquired and the liabilities assumed as of August 12, 2022:

	In million US$
Consideration transferred	(20.5)
Fair value of the previous interest in Greenwind	(20.4)
Total	(40.9)
Property, plant and equipment (1)	127.7
Intangible assets - Customer contract (2)	31.6
Financial assets at fair value	24.4
Trade receivables (3)	6.3
Other assets	0.1
Cash and cash equivalents	3.1
Borrowings	(89.3)
Deferred tax liabilities	(54.3)
Income tax liabilities	(4.4)
Trade and other payables	(2.0)
Provisions	(1.4)
Tax liabilities	(0.9)
Total acquisition price allocation (4)	40.9

⁽¹⁾ Mario Cebreiro Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

F-84

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

Expenses related to the acquisition transaction were non-significant, therefore they were recognised as expenses in fiscal year result.

The acquisition contributed to the Group revenues from sales for US$ 11.3 million and net earnings for US$ 3.5 million for the August 12 - December 31, 2022 period.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,844 million and US$ 459 million, respectively. The pro forma information was calculated based on the Company and Greenwind’s results.

The Company paid US$ 20.5 million for the acquisition of the additional equity interest which, net of the cash and cash equivalents balance of US$ 3.1 million, results in a net cash flow of US$ 17.4 million, which is disclosed in the consolidated statement of cash flows in the item “Payment for the acquisition of subsidiaries and associates” under investment activities.

5.1.4 Acquisition of Autotrol Renovables S.A.

On September 30, 2022, the Company acquired 100% of the capital stock of Autotrol Renovables S.A., an entity holder of the “Wayra I Wind Farm” project (registered with the National Renewable Energy Projects Registry, “RENPER”) for a price of US$ 50 thousand.

5.1.5 Acquisition of VAR

On December 12, 2022, Parque Eólico Arauco S.A.P.E.M. (“PEA”) and the Company executed an agreement to acquire 100% of VAR’s capital stock. This company is exclusively engaged in electric power generation in the domestic market through the operation of Arauco II Wind Farm, with a 99.75 MW capacity, at a price of US$ 171 million, including the takeover of a US$ 46 million interest liability recorded in VAR and payable by PEA in 12 consecutive monthly installments as from transaction closing.

Upon the meeting of the precedent conditions, on December 16, 2022, PEA transferred VAR’s shares, and the Company paid US$ 128.1 million, an amount that considers the working capital adjustment estimated on that date. The amount paid is currently under review by the Company and PEA in accordance with the processes established in the share purchase agreement to assess the amount of VAR’s working capital adjustment as of closing. The following table details the fair value of the consideration transferred, and the fair values of the assets acquired and liabilities assumed as of, December 16, 2022:

F-85

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

	In million US$
Consideration transferred	(128.1)
Estimated price adjustment	6.7
Total	(121.4)
Property, plant and equipment (1)	167.7
Intangible assets - Customer contract (2)	62.3
Trade receivables (3)	4.9
Other receivables	1.2
Deferred tax liability	(60.2)
Income tax liability	(5.0)
Trade and other payables	(3.3)
Other payables	(46.0)
Tax liabilities	(0.2)
Total acquisition price allocation (4)	121.4

⁽¹⁾ Arauco Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Expenses related to the acquisition transaction were non-significant, therefore they were recognised as expenses in fiscal year result.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,858 million and US$ 448 million, respectively. The pro forma information was calculated based on the Company and VAR’s results.

The Company paid US$ 93.2 million for the acquisition of the equity interest, which is disclosed in the consolidated statement of cash flows in the item “Payment for the acquisition of subsidiaries and associates” under investment activities. In addition, the Company made a partial payment by delivering public securities for US$ 34.9 million which is disclosed in the consolidated statement of cash flows in the item “significant non-cash transactions” (see Note 14.3).

F-86

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2      Interest in subsidiaries, associates and joint ventures

5.2.1 Subsidiaries information

Unless otherwise indicated, the capital stock of the subsidiaries consists of common shares, each granting the right to one vote. The country of the registered office is also the principal place where the subsidiary develops its activities.

			12.31.2022	12.31.2021
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Autotrol Renovable S.A. (1)	Argentina	Generation	100.00%	-
GASA	Argentina	Generation	100.00%	100.00%
Enecor S.A.	Argentina	Electricity transportation	70.00%	70.00%
Fideicomiso CIESA	Argentina	Investment	100.00%	100.00%
Greenwind (3)	Argentina	Generation	100.00%	50.00%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
CISA	Argentina	Trader & investment	100.00%	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PB18	Ecuador	Oil	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Pampa Ecuador Inc	Ecuador	Investment	100.00%	100.00%
PE Energía Ecuador LTD	Gran Cayman	Investment	100.00%	100.00%
EISA	Uruguay	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
TGU	Uruguay	Gas transportation	51.00%	51.00%
Corod (3)	Venezuela	Oil	-	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
Vientos de Arauco Renovables S.A.U. (4)	Argentina	Generation	100.00%	-
Vientos Solutions Argentina S.A.U.	Argentina	Advisory services	100.00%	-
VS S.L. (2)	España	Investment	100.00%	-

⁽¹⁾ See Note 5.1.4.

⁽²⁾ See Note 5.1.3.

⁽³⁾ Interest assigned under the assignment of the indirect interest in the capital stock of mixed companies in Venezuela. See Note 5.3.2.

⁽⁴⁾ See Note 5.1.5.

F-87

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.2 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:

		Information about the issuer
	Main activity	Date	Share capital	Profit (loss) of the  year	Equity
Associates
OCP	Investment	12.31.2022	100	(4)	96
TGS (1)	Gas transportation	12.31.2022	4	182	1,508
Joint ventures
CIESA (1)	Investment	12.31.2022	4	93	770
Citelec (2)	Investment	12.31.2022	3	5	235
CTB	Generation	12.31.2022	48	53	536

⁽¹⁾ The Company holds a direct and indirect interest of 3.764% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, additionally the Company has an indirect participation of 25.50% in TGS.

As of December 31, 2022, the quotation of TGS's ordinary shares and ADR published on the Buenos Aires Stock Exchange and the NYSE was $ 811.05 and US$ 11.80, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of $ 188,568 million.

⁽²⁾ The Company holds a 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, 2022, Transener’s common share price listed at the Buenos Aires Stock Exchange was $ 184,50, conferring Pampa’s indirect interest an approximate $ 21,598 million market value.

F-88

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

	12.31.2022	12.31.2021
Disclosed in non-current assets
Associates
Refinor (1)	-	22
OCP	15	24
TGS	67	52
Total associates	82	98
Joint ventures
CIESA	435	347
Citelec	117	102
CTB	268	227
Total joint ventures	820	676
Total associates and joint ventures	902	774
Disclosed in non-current liabilities
Joint ventures
Greenwind	-	(4)
Total joint ventures	-	(4)

⁽¹⁾ See Note 5.1.2.

The following tables show the breakdown of the share of profit from associates and joint ventures:

	12.31.2022	12.31.2021	12.31.2020
Associates
Refinor	(12)	(2)	(2)
OCP	(1)	18	(5)
TGS	7	7	1
Total associates	(6)	23	(6)
Joint ventures
CIESA	43	50	11
CTB	41	49	64
Citelec	3	(3)	13
Greenwind (1)	24	(2)	3
Total joint ventures	111	94	91
Total associates and joint ventures	105	117	85

⁽¹⁾ See Note 5.1.3.

F-89

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

The evolution of investments in associates and joint ventures is as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	770	547	507
Compensation	-	-	(5)
Dividends	(8)	-	(34)
Increases	1	17	3
Decrease due to acquisition of control (1)	(20)	-	-
Decrease due to sale of equity interests  (2)	(6)	-	-
Share of profit	116	117	85
Impairment (2)	(11)	-	-
Exchange differences on translation	60	89	(9)
At the end of the year	902	770	547

⁽¹⁾    See Note 5.1.3.

⁽²⁾    See Note 5.1.2.

5.2.3 Investment in CTB

On June 26, 2019. the acquisition by CTB, a company co-controlled by YPF and Pampa, of CTEB's goodwill was perfected, which is located at the petrochemical complex of the town of Ensenada, Province of Buenos Aires, consists of two open-cycle gas turbines, and has a 567 MW installed capacity.

CTB committed to obtain the commissioning of the closing of the combined cycle increasing the installed power capacity to 847 MW.

Both the open and the closed cycle have effective power purchase agreements with CAMMESA under Resolution SE No. 220/07: the first one, entered into on March 26, 2009 which expired on April 27, 2022, and the second one dated March 26, 2013 for a term of 10 years as from the commercial operation of the combined cycle, which stared operations on February 22, 2022. Moreover, energy not committed under contracts with CAMMESA is remunerated at the spot market.

CTEB will be managed and operated by Pampa and YPF on a rotational basis over 4-year periods. Pampa is responsible for managing CTEB’s operations until mid-2023. And YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for the closing of the combined cycle.

F-90

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.3.1 Financial Trust Agreement

As a result of the award of CTEB’s goodwill, certain amendments were made to the Enarsa-Barragán Financial Trust Agreement entered into between BICE Fideicomisos S.A. (Nación Fideicomisos S.A.’ continuing company), acting as Trustee, and CTB, in its capacity as Trustor substituting IEASA (former ENARSA) (the “Trust Agreement” or the “Trust”).

Under the Trust, on April 25, 2011 publicly traded Series B VRD for a face value of 582,920,167 were issued. The Trust’s underlying flow is made up of the collection rights resulting from the power supply agreements originally entered into between ENARSA (currently IEASA) and CAMMESA.

On June 26, 2019 and October 16, 2020, CTB made a partial early redemption of 109,628,836 and 275,053,045 outstanding Series B VRD, which were canceled on October 29, 2019 and December 4, 2020, respectively.

Finally, on December 17, 2021, CTB performed the total early redemption of 198,238,286 VRD for a total amount of US$ 94 million. As of the issuance of these Consolidated Financial Statements, the VRD have been canceled and the Trust has been liquidated.

5.2.3.2 Syndicated loan

On June 25, 2019, in order to partially finance the obligations undertaken as a result of the award and execution of the works for the closing of the combined cycle at CTEB, Citibank, N.A., Banco de Galicia y Buenos Aires S.A.U., Banco Santander Río S.A., HSBC Bank Argentina S.A. and Industrial and Commercial Bank of China (Argentina) S.A., in their capacity as lenders (the “Lenders”), granted a syndicated loan to CTB in the amount of US$ 170 million maturing on June 26, 2022, with US$ 136 million accruing a fixed 10.25% interest rate and US$ 34 million accruing a variable LIBOR rate+6.25.

On March 25, 2022 CTB and the lenders executed a amendment to the agreement modifying the loan repayment scheme in its variable interest rate tranche, with a new maturity on October 1, 2022, and changing the reference rate from LIBOR to SOFR.

During the fiscal year ended December 31, 2022, CTB has repaid at maturity the amount of US$ 74,4 million of the syndicated loan´s remaining installments.

F-91

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.3.4 Global Program of CB

On July 23, 2020, CTB’s Extraordinary General Shareholders’ Meeting resolved to approve the creation of a global program of simple corporate bonds non-convertible into shares for up to US$ 200 million or its equivalent in other currencies or units of value, and the issuance of corporate bonds under such program up to its maximum amount, at any time, to be issued in one or more classes and/or series, which authorization was granted by the CNV on September 24, 2020.

5.2.3.5 Issuance of CB

On June 4, 2021, CTB issued: (i) Class 1 CB for a total amount of US$ 27.3 million, accruing interest at an annual fixed rate of 4% and maturing on June 4, 2023; and (ii) Class 2 CB for a total amount of 37,504,954 units of purchasing power (“UVA”), adjustable by the Reference Stabilization Coefficient (CER), equivalent to $2,928 million, accruing interest at a fixed 4% rate and maturing on June 4, 2024.

On August 18, 2021, CTB reopened (i) Class 1 CB for a total amount of US$ 15.6 million at an issue price of 101.7050%; and (ii) Class 2 CB for a total amount of 27.9 million UVA at an initial value of $84.76 per UVA at an issue price of 100.82%.

On November 26, 2021, CTB issued Class 4 CB for a total amount of US$ 96 million, accruing interest at an annual 0% fixed rate and maturing on November 26, 2024.

On May 16, 2022, CTB issued: (i) Class 6 CB for a total amount of US$ 25 million at a fixed annual 0% rate maturing on May 16, 2025; and (ii) Class 7 CB for a total amount of $ 1,754 million accruing interest at a variable BADLAR rate plus an annual 2.98% spread and maturing on November 16, 2023.

On August 22, 2022, CTB issued Class 8 CB for a total amount of $ 4,235 million, accruing interest at a variable BADLAR rate plus a 1.00% annual spread and maturing on February 22, 2024.

Finally, on December 12, 2022, CTB reopened additional Class 6 CB for a total amount of US$ 58.6 million accruing interest at an annual 0% fixed rate and maturing on May 16, 2025. With the reopening of Class 6 CB, which were subscribed and paid in cash and in-kind through the delivery of Class 1 CB, Class 1 CB with a fair value of US$ 10.7 million were partially canceled, with a US$ 32.2 million outstanding face value.

All CB are secured by a personal guarantee subject to a precedent and subsequent condition granted by YPF and Pampa.

As of the date of issuance of these Consolidated Financial Statements, CTB is in compliance with all the covenants under its debt agreements.

F-92

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.3.6 Closing to combined cycle project

CTB’s closing to combined cycle commitment to increase its installed capacity from 567 MW to 847 MW has been affected from its beginning by the evolution of the measures associated with the COVID-19 pandemic. The stiffening of social lockdown measures from July 1, 2020 excluded private infrastructure works from the exempted activities. Later on, pursuant to Resolutions No. 1197-MJGM-2020 and No. 1690-MJGM-2020 issued by the Buenos Aires Chief of the Cabinet of Ministers’ Office, as amended, CTB resumed the execution of construction works following their critical path from July 20, 2020.

Within this framework, on July 28, 2020, the Company and the Joint Venture made up of SACDE Sociedad Argentina de Construcción y Desarrollo Estratégico S.A. and Techint Compañía Técnica Internacional S.A.C.E.I. entered into an addendum to the construction agreement within the framework of the restrictions imposed as a result of the COVID-19 pandemic, reaching an agreement on the impact on costs and works’ execution terms, and launching a new stage for the execution of the closing to combined cycle.

The evolution of the Argentine Government’s measures to contain the spread of COVID-19 in 2020 and 2021 has affected the works execution progress, delaying the term initially planned for commissioning and generating several instances of review in the schedule and the scope of the tasks necessary to complete the works, with the resulting increase in associated costs. Moreover, exchange and customs restrictions have impacted costs and terms for the supply of foreign equipment.

Given the problems in the normal execution of the project affecting the works’ terms and costs, on July 1, 2022, CTB and the Joint Venture made up by SACDE and Techint Compañía Técnica Internacional S.A.C.E I. entered into a new addendum to the construction agreement, which mainly stipulated as follows: (i) a new work schedule to reach the combined cycle’s commissioning; and (ii) the recognition in favor of the Joint Venture of the right to an US$8 million compensation on account of the incurred term and cost variations.

On January 27, 2023, CTB has launched the CC and on February 22, 2023, it stared operations under the supply agreement with CAMMESA.

5.2.3.7 Impairment of non-financial assets

Spot market prices were modified in May 2021 by SE Resolution No. 440/21, which, although providing for a 29% increase in remuneration, permanently abrogated the application of the automatic adjustment mechanism. This impacted the future flows collectible by CTB after the termination, in the year 2022, of the supply agreement with CAMMESA that remunerates the units making up the open cycle. Additionally, in 2020 and 2021 the progress of works for CTB’s closing to combined cycle was affected by the measures implemented to contain the COVID-19 spread, delaying the scheduled term for commissioning and increasing the costs associated with the completion of the project.

F-93

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

In view of these indications, CTB determined the estimation of the recoverable amount as of December 31, 2022 and 2021.

The methodology used in the estimation of the recoverable amount consisted of calculating the present value of future net cash flows expected to be generated by the CGU, discounted with a rate reflecting the weighted average costs of the capital employed.

The projections used by CTB in the calculation of the recoverable amount as of December 31, 2022 take into consideration 2 scenarios that weigh: i) the entry into effect of the new supply agreement with CAMMESA for the combined cycle in the first quarter of 2023; ii) the periodic price update in line with inflation for the spot remuneration; iii) the recognition of a long-term differential remuneration allowing to make the investments necessary to maintain availability and improve the open cycle’s efficiency; iv) the regularization of the financing term granted to CAMMESA in 2024; and v) an 11.7% after-tax WACC rate.

As of December 31, 2022, and 2021, CTB has not recorded any impairment losses as a result of the performed recoverability assessment.

5.2.4 Investment in OCP

The Company, through PEB, has an equity interest in OCPSA, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.

On August 12, 2021, the Company, through its subsidiary PEB, executed an agreement with Occidental International Exploration and Production Company for the acquisition of all the shares of Occidental del Ecuador Inc. (currently Pampa Ecuador Inc.) for US$ 5 million. Pampa Ecuador Inc. holds a 14.15 % equity interest in OCP.

The closing of the transaction involved the recognition of profits for US$ 17.2 million, under IAS 28. The following table details the consideration, the fair value of the acquired assets, and the profit recorded by the Company as of August 12, 2021:

	In million US$
Acquisition cost	(5.0)
Total consideration	(5.0)
Share value of the interest in the fair value of OCP’s identifiable assets and liabilities (1)	12.7
OCP dividends to be received	9.5
Assets fair value	22.2
Profit (2)	17.2

⁽¹⁾ Calculated based on the present value of expected dividend flows.

⁽²⁾ Disclosed under “Share of profit from associates and joint ventures”.

F-94

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

On August 12, 2021, PEB recorded an impairment reversal of US$ 1.6 million, on the interest in OCP, prior to the aforementioned acquisitions, in relation to the estimation of the present value of the future cash flows that were expected to be obtained through the collection of dividends considering the concession term and a discount rate of 15.09 %.

The termination of the oil pipeline concession agreement is scheduled for January 12, 2024, considering the term extension resulting from the suspension of the contractual obligations due to force majeure events. On that date, OCP will transfer and deliver to the Ecuadorian Government or its designee all OCPSA’s shares at no cost, as well as the titles and rights over the oil pipeline’s assets. As of the issuance of these Consolidated Financial Statements, OCPSA is executing the actions defined in the contract to meet the transfer plan.

5.2.4.1 Recoverable value of the investment

The erosion process in the Quijos River course, in the San Rafael sector, on the border of the provinces of Sucumbíos and Napo, Ecuador, caused two force majeure events consisting of the rupture of different oil pipeline tranches and the resulting temporary suspension of the crude oil pumping in 2020 and 2021.

Additionally, on January 28, 2022, a new force majeure event occurred due to a stone landslide causing the pipeline’s rupture at KP96+526. OCPSA started the repairs of the affected pipeline and cleanup and remediation works. The crude oil transportation service was resumed on February 7, 2022.

PEB has performed recoverable amount tests for its investment in OCP as of December 31, 2021, considering the present value of the future cash flows it expects to obtain through the collection of dividends during the concession term, the term extension due to the suspension of contractual obligations resulting from the detailed Force Majeure events and a discount rate of 17.12%. PEB has not recorded any impairment losses as a result of the recoverability assessment performed as of December 31, 2021, and, as of December 31, 2022, has identified no additional indications that may impact the assumptions taken into consideration in the aforementioned assessment.

It is worth highlighting that on February 22, 2023, after the end of the fiscal year, a force majeure event occurred due to the collapse of the bridge over the Marker River, located in El Choco canton, Napo Province. In order to guarantee the continuity of the pipeline’s operations and avoid an environmental incident, OCPSA suspended crude oil pumping and started the complete drainage of the pipeline at KP96+075. Additionally, OCPSA notified the occurrence of the previously mentioned event to the Ministry of Energy and Mines. The crude oil transportation service was resumed on March 2, 2023.

F-95

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.4.2 Contingent liabilities in OCP

Several organizations and natural persons filed a constitutional protection proceeding against OCPSA, as well as the Ministry of Energy, the Ministry of the Environment and Water, Petroecuador and the Ministry of Health, alleging the infringement of several constitutional rights regarding the force majeure event consisting of the land subsidence and sliding at the Quijos River course, which resulted in the rupture of the pipeline at KP 93+469 in 2020. The safeguard action has been disallowed in the first and second instances by Orellana’s Provincial Court of Justice. As of the date of issuance of these Consolidated Financial Statements, the plaintiffs have filed a constitutional protection proceeding, which has been admitted to be heard by the Constitutional Court.

OCPSA's Management together with its legal advisors have classified an unfavorable ruling as remote, therefore, no provision has been recognized on this matter.

5.2.5 Investment in CITELEC

5.2.5.1 Impairment in the value of non-financial assets in Transener

The projections used by Transener in the calculation of the recoverable amount of long-lived non-financial assets considered 3 weighted alternatives associated with: (i) the status of negotiations with the ENRE; (ii) the Right-of-Use and Associated Maintenance contract; (iii) Transener’s management expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) Transener’s expectations on the timeliness and outcome of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2022 and 2021, the book value of Transener’s long-lived non-financial assets does not exceed their recoverable amount.

5.2.5.2 Distribution of earnings

Regarding the loan agreement executed in July 2021 between Transener and BNA in the amount of $ 1,000 million, for the tree-year term, Transener’s Board of Directors has committed, while the loan remains outstanding, to refrain from making any proposal to the Shareholders’ Meeting regarding the release of reserves for their distribution as dividends to shareholders or, in case there are negative results affecting reserves, from proposing the distribution of earnings until reserves have been replenished.

F-96

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.2.6 Investment in CIESA

Impairment of non-financial assets in TGS

Argentina’s main macroeconomic and business variables have deteriorated since August 2019. This situation worsened in 2020 due to the negative consequences of the COVID pandemic on the Argentine economic situation, which forced the Argentine Government to take a series of measures, even affecting the regulatory framework of the natural gas transportation segment. As a result, TGS has re-estimated the cash flows used in determining the recoverable value (value in use) of the CGU in the Natural Gas Transportation segment.

The projections used in the calculation of the recoverable amount considered 3 weighted alternatives associated with: (i) the status of negotiations with the Argentine Government; (ii) the contractual rights resulting from the license; (iii) expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) expectations on the result of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2022 and 2021, TGS has determined that it is not necessary to record an additional impairment charge, nor to reverse the recorded one.

5.3 Operations in oil and gas consortiums

5.3.1 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 in Argentina production, according to Law No.17,319, are paid royalties equivalent to 12% of the wellhead price of crude oil and natural gas. The wellhead price is calculated by deducting freight and other sales related expenses from the sale prices obtained from transactions with third parties. This rate may increase from 3% to 4% depending on the producing jurisdiction and market value of the product.

F-97

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.3.2 Oil and gas participation details

As of December 31, 2022, the Company and its associates are part of the joint operations and consortia for the exploration and production of oil and gas as indicated below:

		Participation			Duration Up To
Name	Location	Direct	Indirect	Operator
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
La Tapera - Puesto Quiroga	Chubut	35.67%	-	Tecpetrol	2027
El Tordillo	Chubut	35.67%	-	Tecpetrol	2027
Aguaragüe (1)	Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala	Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento (2)	Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro (3)	Río Negro	15.00%	-	YPF	2026
Río Limay este (Ex Senillosa) (4)	Neuquén	85.00%	-	PAMPA	2040
Veta Escondida y Rincón de Aranda	Neuquén	55.00%	-	PAMPA	2027
Rincón del Mangrullo	Neuquén	50.00%	-	YPF	2052
Los Blancos (ex Chirete)	Salta	50.00%	-	High Luck Group Limited	2045
Argentine exploration
Parva Negra Este (5)	Neuquén	42.50%	-	PAMPA	2019
Río Atuel (6)	Mendoza	33.33%	-	Petrolera El Trebol	2023
Borde del Limay (7)	Neuquén	85.00%	-	PAMPA	2015
Los Vértices (7)	Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte (8)	Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾ On February 3, 2023, an agreement for a 10-year extension of the concession was signed with the enforcement authority. The Provincial Executive Order ratifying this agreement is pending publication.

⁽²⁾ Direct participation in 9 wells. On January 19, 2023, the Company accepted Oilstone Energía S.A.’s offer to terminate its rights and obligations under the investment agreement, the Joint Venture and the operating agreement of the block, effective from January 1, 2023.

⁽³⁾ Direct participation in 13 wells.

⁽⁴⁾ On January 2, 2023, the environmental remediation plan was approved by the Province of Neuquén’s Subsecretariat of Environment, a necessary preliminary step to relinquish the block.

⁽⁵⁾ A contractual continuity plan was submitted (see details below).

⁽⁶⁾ Pursuant to Resolution No. 1,787/22 of the Province of Mendoza’s Ministry of Economy and Energy, the granting of a lot under evaluation, requested by Phoenix Global Resources —Petrolera El Trébol’s controlling company— and the Company on April 6, 2022, was approved until August 31, 2023.

⁽⁷⁾ Under process of relinquishment to the province.

⁽⁸⁾ On January 4, 2023, the exploration period terminated, and the Company’s rights and obligations over the area expired.

F-98

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

Continuity plan in the Parva Negra Este block

On December 14, 2022, the Company, ExxonMobil Exploration Argentina S.R.L. and GyP submitted to Enforcement Authority a proposal for a contractual continuity plan which included: (i) the granting of a Lot under Evaluation for the April-2022 through April-2025 period, (ii) a 50% reduction of the block’s surface, to a total surface of 143 km2, and (iii) the assignment of ExxonMobil Exploration Argentina S.R.L.’s 42.50% interest to the Company.

As of the issuance of these Consolidated Financial Statements, the Enforcement Authority’s decision is pending.

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.

F-99

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 5: (Continuation)

5.4 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2022, 2021 and 2020:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	42	50	33
Increases	2	8	24
Transferred to development	(6)	(16)	(7)
At the end of the year	38	42	50
Number of wells at the end of the year	7	10	12

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 subsidiary, 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.

F-100

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

In order to evaluate if there is evidence that a CGU could be affected, both external and internal sources of information are analyzed. Specific facts and circumstances are considered, which generally include the discount rate used in the estimates of the future cash flows of each CGU and the business condition as regards economic and market factors, such as the cost of inventories, oil and gas prices, international petrochemical product’s price, the regulatory framework for the energy industry, the projected capital investments and the evolution of the energy demand.

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 UGE. 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.

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.

F-101

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

6.1.3 Provision for contingencies

The Company is subject to various claims, lawsuits and other legal proceedings that arise during the ordinary course of its business. The Company’s liabilities with respect to such claims, lawsuits and other legal proceedings cannot be estimated with certainty. The Company reviews the status of each contingency and assesses potential financial liability, applying the criteria indicated in Note 4.21, for which elaborates the estimates mainly with the assistance of legal advisors, based on information available to the Management at Consolidated Financial Statements date, and taking into account the litigation and resolution/settlement strategies.

Contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company’s business, as well as third party claims arising from disputes concerning the interpretation of legislation.

The Company evaluates whether there would be additional expenses directly associated with the ultimate resolution of each contingency, which will be included in the provision if they may be reasonably estimated.

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.

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.

F-102

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

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.

F-103

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

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.

Periodic revisions and adjustments to the estimated oil and gas reserves and related future net cash flows may be necessary as a result of changes in a number of factors, related to reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors or at least once a year.

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 4.9).

6.1.8 Environmental remediation

The costs incurred to limit, neutralize or prevent environmental pollution are only capitalized if at least one of the following conditions is met: (a) such costs relate to improvements in safety; (b) the risk of environmental pollution is prevented or limited; or (c) the costs are incurred to prepare the assets for sale and the book value of such assets does not exceed their respective recoverable value.

Liabilities related to future remediation costs are recorded when, on the basis of environmental assessments, such liabilities are probable to materialize, and costs can be reasonably estimated. The actual recognition and amount of these provisions are generally based on the Company’s commitment to an action plan, such as an approved remediation plan or the sale or disposal of an asset. In general, the provision is recognised on the basis that a future remediation commitment may be required.

The Company measures liabilities based on its best estimation of present value of future costs, using currently available technology and applying current environmental laws and regulations as well as the Company’s own internal environmental policies.

F-104

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

6.1.9 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.

6.1.10 Business Combinations

The acquisition method involves the measurement at fair value of the identifiable assets acquired and the liabilities assumed in the business combination at the acquisition date.

For the purpose to determine the fair value of identifiable assets, the Company uses the valuation approach considered the most representative for each asset. These include: i) the income approach, through indirect cash flows (net present value of expected future cash flows) or through the multi-period excess earnings method, ii) the cost approach (replacement value of the good adjusted for loss due to physical deterioration, functional and economic obsolescence) and iii) the market approach through comparable transactions method.

Likewise, in order to determine the fair value of liabilities assumed, the Company’s Management considers the probability of cash outflows that will be required for each contingency, and elaborates the estimates with assistance of legal advisors, based on the information available and taking into account the strategy of litigation and resolution / liquidation.

Management critical judgment is required in selecting the approach to be used and estimating future cash flows. Actual cash flows and values may differ significantly from the expected future cash flows and related values obtained through the mentioned valuation techniques.

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.

F-105

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

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.

In fiscal year 2022, the U.S. dollar recorded an approximate 72.5% increase against the Argentine peso, from $ 102.72 in December 2021 to $ 177.16 in December 2022, and taking into consideration that during the year the Company mostly had a net passive position in Argentine pesos, as of December 31, 2022 the Company recorded net foreign exchange gain in the amount of US$ 80 million. Taking into account the net passive financial position in Argentine pesos as of December 31, 2021, 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 (decrease)/increase of US$ 23 million in the 2022 fiscal year’s income, before income tax.

The Group´s exposure to other foreign currency movements is not material.

F-106

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

6.2.1.1.2 Price risk

The Company’s financial instruments are not significantly exposed to hydrocarbon international price risks because the current regulatory, economic and governmental policies in force, prevent oil and gas domestic prices to be directly affected in the short-term due to variations in the international market.

Additionally, 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 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 12.2 to these Consolidated Financial Statements:

	Increase of the result for the year
Financial assets	12.31.2022	12.31.2021
Shares	19	15
Government securities	28	28
Corporate Bonds	12	2
Mutual funds	3	4
Variation of the result of the year	62	49

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.

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, 2022, 18% of the indebtedness was subject to variable interest rates. Furthermore, 52% of the Company’s debt accruing variable interest rates is denominated in U.S. dollars, mainly at Libor and SOFR rate plus an applicable spread. Regarding the replacement of the LIBOR reference interest rate effective from July 2023, the Company does not estimate any significant impacts on the current indebtedness subject to such reference rate.

F-107

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The Company seeks to mitigate its interest-rate risk exposure through the analysis and evaluation of: (i) the different liquidity sources available in the financial and capital market, both domestic and (if available) international; (ii) interest rates alternatives (fixed or variable), currencies and terms available for companies in a similar sector, industry and risk than the Company; (iii) the availability, access and cost of interest-rate hedge agreements. On doing this, the Company evaluates the impact on profits or losses resulting from each strategy over the obligations representing the main interest-bearing positions.

In the case of fixed rates and in view of the market’s current conditions, the Company considers that the risk of a significant decrease in interest rates is low and, therefore, does not foresee a substantial risk in its indebtedness at fixed rates.

As of the date of issuance of these Consolidated Financial Statements, the Company is not exposed to a significant risk of variable interest rate increases since most of the financial debt is subject to fixed rate.

The following table shows the breakdown of the Company’s borrowings classified by interest rate and the currency in which they are denominated:

	12.31.2022	12.31.2021
Fixed interest rate:
Argentine pesos	57	11
U.S. dollar	1,173	1,318
Subtotal loans obtained at a fixed interest rate	1,230	1,329
Floating interest rate:
Argentine pesos	140	-
U.S. dollar	149	87
Subtotal loans obtained at a floating interest rate	289	87
Non interest accrued
Argentine pesos	22	-
U.S. dollar	72	22
Subtotal loans no interest accrued	94	22
Total borrowings	1,613	1,438

Based on the conducted simulations, and provided all other variables remain constant, a 10% increase/decrease in variable interest rates would generate the following (decrease)/increase in the 2022 fiscal year's income, before income tax, of US$ 0.1 million.

F-108

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

6.2.1.2 Credit risk

The Company establishes individual credit limits according to the limits defined by the Board of Directors and approved by the Financial Department based on internal or external ratings. The Company makes constant credit assessments on its customers’ financial capacity, which minimizes the potential risk for bad debt losses.

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.

The credit risk is associated with the Company’s commercial activity through customer trade receivables, as well as available funds and deposits in banking and financial institutions.

The Company, in its ordinary course of business and in accordance with its credit policies, grants credits to a large customer base, mainly large sectors of the industry, including petrochemical companies, natural gas distributors and electricity large users.

As of December 31, 2022, the Company’s short-term trade receivables totaled US$ 305 million. With the exception of CAMMESA, which represents approximately 54% 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.

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 4.10.4.

F-109

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The expected credit loss on trade receivables and financial assets as of December 31, 2022, 2021 and 2020 amounts to US$ 1 million, US$ 1 million and US$ 12 million, respectively and was determined based on credit loss rates calculated for days past due detailed below:

12.31.2022	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.08%	0.26%	2.54%	7.11%	14.37%	21.39%	27.22%	33.01%
Oil and Gas	0.18%	0.48%	13.24%	31.50%	32.01%	32.09%	32.31%	32.38%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Holding	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
12.31.2021	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.06%	0.29%	2.08%	2.83%	4.67%	6.12%	6.24%	6.25%
Oil and Gas	0.04%	0.17%	0.77%	2.72%	6.88%	19.88%	21.97%	15.89%
Petrochemicals	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
Holding	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
12.31.2020	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.35%	1.11%	5.74%	9.78%	11.23%	19.77%	20.87%	22.71%
Oil and Gas	0.49%	0.72%	5.96%	16.21%	16.23%	17.74%	17.76%	17.79%
Petrochemicals	0.02%	0.06%	0.72%	2.26%	9.95%	23.84%	19.14%	36.92%
Holding	12.58%	0.94%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%

Finally, although cash, cash equivalents and financial assets are also subject to the impairment requirements of IFRS 9, the identified impairment loss is immaterial.

F-110

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

Allowance of impairment of financial assets and other credits evolution as of December 31, 2022, 2021 and 2020, 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$ 0.3 million (decrease)/increase in 2022 fiscal year’s results, before income tax.

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, if 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.

It should be noted that the Company operates in an economic context in which main variables experience volatility as a result of political and economic events both domestically and internationally, as described in Note 1.2.

F-111

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

The international instability resulting from the Russian invasion, added to the particular circumstances of the Argentine sovereign debt renegotiation, has impacted the international financial markets, increasing the cost of access to finance for emerging markets in general, and particularly for Argentina. As regards access to domestic financing, an increased liquidity in pesos and a reduced cost of financing have been verified, especially in the very short term.

All these impacts may potentially affect the Company’s capacity to obtain financing for its operations in a timely manner and under acceptable and efficient terms, costs and conditions in line with the Company’s business needs.

Furthermore, the restrictions imposed by the BCRA (see Note 2.5) with the purpose of regulating inflows and outflows in the MLC and other new restrictions which may be imposed in the future may affect the Company’s capacity to access the MLC to acquire the foreign currency necessary to meet its financial obligations, such as debt principal and interest payments (including the CBs debt), and other additional payments abroad, or otherwise affect the Company’s business and the results of its operations.

The Company’s Management permanently monitors the evolution of situations affecting its business to determine possible steps to take and identify potential impacts on its assets and financial position.

It is worth highlighting that the Company currently has a strong level of liquidity that allows it to properly face such volatility.

The determination of the Company’s liquidity index for fiscal years ended December 31, 2022 and 2021 is detailed below:

	12.31.2022	12.31.2021
Current assets	1,343	1,125
Current liabilities	631	342
Liquidity ratio	2.13	3.29

F-112

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

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 liabilities 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.

As of December 31, 2022	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	412	231	118
Three months to one year	19	50	304
One to two years	6	12	357
Two to five years	12	3	992
More than five years	-	6	332
No set maturity term	41	-	-
Total	490	302	2,103
As of December 31, 2021	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	304	178	56
Three months to one year	61	4	102
One to two years	6	5	557
Two to five years	18	3	256
More than five years	-	4	1,025
No set maturity term	42	-	-
Total	431	194	1,996

⁽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.

F-113

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 6: (Continuation)

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 (including current and non-current indebtedness) 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 at December 31, 2022 and 2021 were as follows:

	12.31.2022	12.31.2021
Total borrowings	1,613	1,438
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(692)	(568)
Net debt	921	870
Total capital	3,198	2,655
Leverage ratio	28.80%	32.77%

NOTE 7: SEGMENT INFORMATION

The Company is a fully integrated power company in Argentina, which participates in the electricity and oil and gas value chains.

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:

Electricity Generation, principally consisting of the Company’s direct and indirect interests in HINISA, HIDISA, Greenwind, VAR, CTB, TMB, TJSM and through its own electricity generation activities through thermal plants Güemes, Piedra Buena, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picún Leufú hydroelectric complex and PEPE II, PEPE III and PEPE IV wind farms. It is worth highlighting that the results of the segment’s operations reflect the effects of the consolidation with Greenwind and VAR as from August 12, 2022 and December 16, 2022, respectively; see Note 5.1.3 and Note 5.1.5.

Electricity Distribution, consisting of the Company’s direct interest in Edenor until its disposal. As of December, 31, 2021 and 2020, the Company has classified the results corresponding to the divestment mentioned in Note 5.1.1 as discontinued operations.

Oil and Gas, principally consisting of the Company’s interests in oil and gas areas and through its direct and indirect interest in CISA.

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in local plants.

Holding and Other Business, principally consisting of interests in joint businesses CITELEC and CIESA and their respective subsidiaries, which hold the concession over the high voltage electricity transmission nationwide and over gas transportation in the South of the country, respectively, interests in the associates OCP and Refinor (until its divestment detailed in Note 5.1.2), holding activities and financial investment transactions.

The Company manages its operating segment based on its individual net result in U.S. dollars.

F-114

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	663	370	425	20	-	1,478
Revenue - foreign market	-	159	192	-	-	351
Intersegment revenue	-	117	-	-	(117)	-
Cost of sales	(370)	(359)	(536)	-	117	(1,148)
Gross profit	293	287	81	20	-	681
Selling expenses	(3)	(36)	(17)	-	-	(56)
Administrative expenses	(39)	(60)	(5)	(34)	-	(138)
Other operating income	25	61	1	44	-	131
Other operating expenses	(5)	(26)	(6)	(9)	-	(46)
Impairment of property, plant and equipment, intangible assets and inventories	-	(30)	(2)	(6)	-	(38)
Impairment of financial assets	-	(2)	-	(6)	-	(8)
Share of profit from associates and joint ventures	65	-	-	40	-	105
Operating income	336	194	52	49	-	631
Financial income	1	2	-	9	(7)	5
Financial costs	(82)	(107)	(3)	(36)	7	(221)
Other financial results	72	(28)	6	116	-	166
Financial results, net	(9)	(133)	3	89	-	(50)
Profit before income tax	327	61	55	138	-	581
Income tax	(73)	(16)	(15)	(20)	-	(124)
Profit of the year	254	45	40	118	-	457
Depreciation and amortization	82	125	5	-	-	212

F-115

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit of the year attributable to:
Owners of the company	253	45	40	118	-	456
Non-controlling interest	1	-	-	-	-	1
Consolidated financial position information as of December 31, 2022
Assets	2,464	1,234	177	1,029	(162)	4,742
Liabilities	979	1,248	147	245	(161)	2,458
Net book values of property, plant and equipment	1,299	807	24	34	-	2,164
Additional consolidated information as of December 31, 2022
Increases in property, plant and equipment, intangible assets and right-of-use assets	115	324	7	36	-	482

F-116

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	656	-	282	310	22	-	1,270
Revenue - foreign market	-	-	58	180	-	-	238
Intersegment revenue	-	-	113	-	-	(113)	-
Cost of sales	(355)	-	(289)	(424)	-	113	(955)
Gross profit	301	-	164	66	22	-	553
Selling expenses	(2)	-	(18)	(13)	-	-	(33)
Administrative expenses	(31)	-	(46)	(4)	(18)	-	(99)
Other operating income	42	-	58	1	4	-	105
Other operating expenses	(5)	-	(28)	(3)	(22)	-	(58)
Impairment of intangible assets and inventories	(2)	-	-	(2)	-	-	(4)
Impairment of financial assets	-	-	-	-	(2)	-	(2)
Share of profit from associates and joint ventures	47	-	-	-	70	-	117
Operating income	350	-	130	45	54	-	579
Financial income	4	-	3	-	4	(1)	10
Financial costs	(46)	-	(103)	(3)	(34)	1	(185)
Other financial results	(14)	-	(16)	(2)	18	-	(14)
Financial results, net	(56)	-	(116)	(5)	(12)	-	(189)
Profit before income tax	294	-	14	40	42	-	390
Income tax	(75)	-	8	(12)	2	-	(77)
Profit of the year from continuing operations	219	-	22	28	44	-	313
Loss of the year from discontinued operations	-	(75)	-	-	-	-	(75)
Profit (Loss) of the year	219	(75)	22	28	44	-	238
Depreciation and amortization	88	-	114	3	-	-	205

F-117

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	218	(39)	22	28	44	-	273
Non-controlling interest	1	(36)	-	-	-	-	(35)
Consolidated financial position information as of December 31, 2021
Assets	1,670	-	1,157	176	1,067	(209)	3,861
Liabilities	525	-	1,324	166	264	(209)	2,070
Net book values of property, plant and equipment	969	-	636	22	32	-	1,659
Additional consolidated information as of December 31, 2021
Increases in property, plant and equipment, intangible assets and right-of-use assets	39	-	213	6	6	-	264

F-118

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	559	-	199	178	20	-	956
Revenue - foreign market	-	-	28	89	-	-	117
Intersegment revenue	-	-	67	-	-	(67)	-
Cost of sales	(254)	-	(243)	(233)	-	67	(663)
Gross profit	305	-	51	34	20	-	410
Selling expenses	(2)	-	(15)	(9)	-	-	(26)
Administrative expenses	(30)	-	(42)	(3)	(18)	-	(93)
Other operating income	35	-	9	-	7	-	51
Other operating expenses	(6)	-	(17)	(6)	(7)	-	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(128)	-	-	(11)	-	-	(139)
Impairment of financial assets	-	-	(13)	1	3	-	(9)
Share of profit from associates and joint ventures	67	-	-	-	18	-	85
Operating income (loss)	241	-	(27)	6	23	-	243
Financial income	3	-	7	-	1	(2)	9
Financial costs	(73)	-	(100)	(3)	(3)	2	(177)
Other financial results	1	-	44	5	34	-	84
Financial results, net	(69)	-	(49)	2	32	-	(84)
Profit (loss) before income tax	172	-	(76)	8	55	-	159
Income tax	(33)	-	23	(2)	(23)	-	(35)
Profit (loss) of the year from continuing operations	139	-	(53)	6	32	-	124
Loss of the year from discontinued operations	-	(592)	-	-	-	-	(592)
Profit (loss) of the year	139	(592)	(53)	6	32	-	(468)
Depreciation and amortization	95	81	108	2	-	-	286

F-119

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	147	(499)	(53)	6	32	-	(367)
Non-controlling interest	(8)	(93)	-	-	-	-	(101)
Consolidated financial position information as of December 31, 2020
Assets	1,595	1,356	1,085	107	832	(85)	4,890
Liabilities	707	1,021	1,174	126	178	(85)	3,121
Net book values of property, plant and equipment	1,015	-	543	19	33	-	1,610
Additional consolidated information as of December 31, 2020
Increases in property, plant and equipment and right-of-use assets	61	135	41	3	2	-	242

F-120

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 8: REVENUE

	12.31.2022	12.31.2021	12.31.2020
Energy sales in Spot Market	210	167	179
Energy sales by supply contracts	346	380	323
Fuel supply	103	104	54
Other sales	4	5	3
Generation sales subtotal	663	656	559
Gas sales	383	231	152
Oil sales	136	99	65
Other sales	10	10	10
Oil and gas sales subtotal	529	340	227
Products from catalytic reforming sales	270	185	98
Styrene sales	96	84	42
Synthetic rubber sales	106	99	49
Polystyrene sales	141	119	71
Other sales	4	3	7
Petrochemicals sales subtotal	617	490	267
Technical assistance and administration services sales	20	22	20
Other	-	-	-
Holding and others subtotal	20	22	20
Total revenue	1,829	1,508	1,073

F-121

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 9: COST OF SALES

	12.31.2022	12.31.2021	12.31.2020
Inventories at the beginning of the year	155	116	153
Plus: Charges of the year
Purchases of inventories, energy and gas	502	433	153
Salaries and social security charges	79	59	51
Employees benefits	15	13	11
Accrual of defined benefit plans	5	4	4
Works contracts, fees and compensation for services	87	68	55
Property, plant and equipment depreciation	202	194	194
Intangible assets amortization	1	1	5
Right-of-use assets amortization	3	5	1
Energy transportation	8	6	5
Transportation and freights	35	22	20
Consumption of materials	30	26	17
Penalties	1	2	-
Maintenance	61	52	26
Canons and royalties	89	65	42
Environmental control	5	4	4
Rental and insurance	31	27	23
Surveillance and security	4	3	2
Taxes, rates and contributions	5	4	3
Other	3	6	2
Total charges of the year	1,166	994	618
Exchange differences on translation	-	-	8
Less: Inventories at the end of the year	(173)	(155)	(116)
Total cost of sales	1,148	955	663

F-122

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	5	3	3
Employees benefits	1	-	-
Compensation agreements	-	-	1
Fees and compensation for services	4	3	3
Taxes, rates and contributions	14	11	8
Transportation and freights	31	14	9
Other	1	2	2
Total selling expenses	56	33	26

10.2   Administrative expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	50	34	34
Employees benefits	8	5	4
Accrual of defined benefit plans	9	7	7
Fees and compensation for services	30	32	26
Compensation agreements	19	2	-
Directors' and Sindycs' fees	7	6	7
Property, plant and equipment depreciation	6	5	5
Maintenance	2	2	1
Transport and per diem	2	1	1
Rental and insurance	1	1	1
Surveillance and security	1	-	1
Taxes, rates and contributions	2	2	2
Communications	1	1	1
Other	-	1	3
Total administrative expenses	138	99	93

F-123

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation)

10.3 Other operating income and expenses

	Note	12.31.2022	12.31.2021	12.31.2020
Other operating income
Insurance recovery		-	3	3
Services provided to third parties		1	2	4
Result from property, plant and equipment sale		2	1	1
Result from intangible assets sale		2	2	-
Dividends received		-	-	1
Contingencies recovery		-	13	2
Tax charges recovery		-	2	-
Contractual penalty		-	-	7
Commercial interests		27	27	30
Argentine Natural Gas Production Promotion Plan		56	51	-
Compensation for arbitration award	15.6	37	-	-
Other		6	4	3
Total other operating income		131	105	51
Other operating expenses
Provision for contingencies		(4)	(16)	(7)
Provision for environmental remediation		-	(15)	-
Derecognition of property, plant and equipment		-	-	(1)
Tax on bank transactions		(14)	(13)	(11)
Donations and contributions		(2)	(2)	(3)
Institutional promotion		(3)	(3)	(2)
Readjustment of investment plan (1)		(9)	-	-
Royalties of Argentine Natural Gas Production Promotion Plan		(8)	(5)	-
Other		(6)	(4)	(12)
Total other operating expenses		(46)	(58)	(36)

⁽¹⁾ Corresponding to the investment plan’s readjustment bond at the Sierra Chata block (see Note 17.2).

F-124

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation)

10.4 Financial results

	12.31.2022	12.31.2021	12.31.2020
Financial income
Financial interest	1	-	1
Other interest	4	10	8
Total financial income	5	10	9
Financial costs
Financial interests (1)	(172)	(137)	(164)
Commercial interests	(1)	-	-
Fiscal interests	(38)	(38)	(3)
Other interests	(5)	(3)	(3)
Bank and other financial expenses	(5)	(7)	(7)
Total financial costs	(221)	(185)	(177)
Other financial results
Foreign currency exchange difference, net	80	3	14
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement	(14)	(1)	2
Result from exchange of corporate bonds	(14)	-	-
Result from repurchase of corporate bonds	6	-	38
Other financial results	(2)	(1)	-
Total other financial results	166	(14)	84
Total financial results, net	(50)	(189)	(84)

⁽¹⁾ Net of US$ 11 million and US$ 10 million capitalized in property, plant and equipment for the years ended December 31, 2022 and 2020, respectively. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

F-125

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 10: (Continuation) 

10.5    Income tax

The breakdown of income tax charge is:

	12.31.2022	12.31.2021	12.31.2020
Current tax	99	67	13
Deferred tax	46	10	22
Difference between previous fiscal year income tax provision and the income tax statement	(21)	-	-
Total  income tax -  Loss	124	77	35

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2022	12.31.2021	12.31.2020
Profit before income tax	581	390	159
Current income tax rate	35%	35%	30%
Income tax at the statutary tax rate	203	138	48
Share of profit from companies	(37)	(40)	(26)
Non-taxable results	(3)	(1)	(5)
Effects of exchange differences and other results associated with the valuation of the currency, net	275	79	88
Effects of valuation of property, plant and equipment, intangible assets and financial assets	(575)	(269)	(156)
Effect of change in tax rate	-	(6)	19
Effect for tax inflation adjustment	253	169	74
Unrecognized deferred assets	-	4	-
Difference between previous fiscal year income tax provision and the income tax statement	2	1	(7)
Non-deductible cost	4	3	-
Impairment on deferred tax assets	2	-	-
Other	-	(1)	-
Total  income tax -  Loss	124	77	35

F-126

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 (2)	Transfers	Decreases	Impairment
							At the end
Lands	14	-	-	-	-	-	14
Buildings	140	-	3	-	-	-	143
Equipment and machinery	1,458	5	291	163	(1)	-	1,916
Wells	867	9	-	145	(1)	(28)	992
Mining property	253	-	-	-	-	(72)	181
Vehicles	8	2	-	-	-	-	10
Furniture and fixtures and software equipment	55	2	-	2	-	-	59
Communication equipments	3	-	-	-	-	-	3
Materials, spare parts and tools	30	43	-	(37)	-	-	36
Petrochemical industrial complex	23	-	-	6	-	-	29
Work in progress	135	352	-	(233)	-	-	254
Advances to suppliers	52	37	-	(46)	-	-	43
Other goods	2	-	1	-	-	-	3
Total at 12.31.2022	3,040	450	295	-	(2)	(100)	3,683
Total at 12.31.2021	2,792	253	-	-	(5)	-	3,040

⁽¹⁾ Includes US$ 11 million corresponding to capitalized financial costs in the fiscal year ended December 31, 2022. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

⁽²⁾ See Notes 5.1.3 and 5.1.5.

F-127

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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	Impairment	At the end	At 12.31.2022	At 12.31.2021
Lands	-	-	-	-	-	14	14
Buildings	(68)	-	(8)	-	(76)	67	72
Equipment and machinery	(536)	-	(103)	-	(639)	1,277	922
Wells	(532)	-	(77)	20	(589)	403	335
Mining property	(174)	-	(10)	50	(134)	47	79
Vehicles	(7)	-	(1)	-	(8)	2	1
Furniture and fixtures and software equipment	(48)	-	(4)	-	(52)	7	7
Communication equipments	(1)	-	-	-	(1)	2	2
Materials, spare parts and tools	(3)	-	-	-	(3)	33	27
Petrochemical industrial complex	(12)	-	(5)	-	(17)	12	11
Work in progress	-	-	-	-	-	254	135
Advances to suppliers	-	-	-	-	-	43	52
Other goods	-	-	-	-	-	3	2
Total at 12.31.2022	(1,381)	-	(208)	70	(1,519)	2,164
Total at 12.31.2021	(1,182)	-	(199)	-	(1,381)		1,659

F-128

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 which may indicate that the book value of property, plant and equipment may not be recoverable in accordance with the policy described in Notes 4.9 and 6.1.1.

In the Power Generation segment, in May 2021 spot market prices were modified by SE Resolution No. 440/21, which, although providing for a 29% increase in remuneration, permanently abrogated the application of the automatic adjustment mechanism, with an impact on the expected revenues update schedule (see Note 2.1). It is worth highlighting that the most significant share of revenues in the Power Generation segment comes from energy remunerated under a differential scheme (that is, supply agreements with large users in the MATER, Energy Plus or supply agreements entered into with CAMMESA), which have not been affected by the previously mentioned regulation.

In view of the above-mentioned indications, the Company determined the recoverable value of the CGUs that make up the Power Generation segment as of June 30, 2021. As of December 31, 2021 and 2022, the Company did not identify additional indications that could impact the assumptions considered in the aforementioned assessments.

As of June 30, 2022, due to Company’s strategic reasons and aiming to focus its investments in the development and exploitation of its unconventional gas reserves, and also in line with the Rincón del Mangrullo block’s Joint Venture members’ strategy, future drilling and workover activities were rescheduled for the next few years, which involves a 2.7 MMBoe recategorization of reserves to contingent resources.

In view of the above-mentioned indications of impairment, the Company has determined the recoverable amount of the CGU Rincón del Mangrullo making up the Oil & Gas segment as of June 30, 2022. As of December 31, 2022, the Company did not identify additional indications that could impact the assumptions considered in the aforementioned assessment.

The methodology used in the estimation of the recoverable amount consisted on calculating each CGU value in use on the present value of future net cash flows expected to be generated by the CGU, discounted with a rate reflecting the weighted average costs of the invested capital.

Cash flows were prepared based on estimates on the future behavior of certain variables that are sensitive in the determination of the value in use, including the following: (i) reference prices for products; (ii) demand projections per type of product; (iii) costs evolution; and; (iv) macroeconomic variables such as inflation and exchange rates, etc.

F-129

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.1.1.1 Generation segment

As of June 30, 2021, the value of the assets in the Power Generation segment does not exceed its recoverable amount, therefore, the Company has not recorded any impairment losses.

The projections used in the calculation of the recoverable amount of the CGUs of the Power Generation segment take into consideration 2 scenarios that weigh: i) the annual price update, ranging between 80% and 100% compared to the annual inflation; ii) the regularization of the financing term granted to CAMMESA in 2022/2023 and iii) a 10.3% WACC rate after taxes.

11.1.1.2 Oil & Gas segment

As of June 30, 2022, the recoverability assessment of the Rincón del Mangrullo CGU in the Oil and Gas segment has resulted in the recognition of impairment losses for US$ 30 million.

The key assumptions used to calculate the recoverable amount considered: i) the reprogramming of drilling and workover activities and ii) a 12.4% after-tax WACC rate.

Finally, it is important to highlight that as of December 31, 2022 and 2021, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value.

F-130

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.2 Intangible assets

	Original values
Type of good	At the beginning	Increases	Increases for incorporation (1)	Decreases	Impairment (2)	At the end
Concession agreements	2	-	-	-	-	2
Goodwill	35	-	-	-	-	35
Intangible identified in acquisitions of companies	7	-	94	-	-	101
Digital assets	-	31	-	(18)	(6)	7
Total at 12.31.2022	44	31	94	(18)	(6)	145
Total at 12.31.2021	62	4		(4)	(18)	44
	Amortization
Type of good	At the beginning	For the year	Impairment (2)	At the end
Concession agreements	(2)	-	-	(2)
Intangible identified in acquisitions of companies	(4)	(1)	-	(5)
Total at 12.31.2022	(6)	(1)	-	(7)
Total at 12.31.2021	(21)	(1)	16	(6)
	Net book values
Type of good	At 12.31.2022	At 12.31.2021
Goodwill	35	35
Intangible identified in acquisitions of companies	96	3
Digital assets	7
Total at 12.31.2022	138
Total at 12.31.2021		38

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

⁽²⁾ As of December 31, 2022, digital assets recoverability was affected by their closing market value, resulted in the recognition of impairment losses for US$ 6 million. Considering the assumptions detailed in Note 11.1, the assessment of recoverability for the Power Generation segment, resulted in the recognition of impairment losses for the Diamante hydroelectric power plant in an amount of US$ 2 million in 2021.

F-131

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

	12.31.2021	Profit (loss)	Increases for incorporation (1)	12.31.2022
Tax loss carryforwards	13	6	-	19
Property, plant and equipment	80	71	-	151
Financial assets at fair value through profit and loss	3	(3)	-	-
Trade and other receivables	5	(1)	-	4
Provisions	57	2	-	59
Salaries and social security payable	-	1	-	1
Defined benefit plans	9	(1)	-	8
Other	-	1	-	1
Deferred tax asset	167	76	-	243
Property, plant and equipment	-	-	(79)	(79)
Intangible assets	(13)	-	(22)	(35)
Investments in companies	(11)	3	-	(8)
Inventories	(10)	(9)	-	(19)
Financial assets at fair value through profit and loss	(14)	(1)	-	(15)
Trade and other receivables	(31)	8	-	(23)
Taxes payables	(3)	1	-	(2)
Tax inflation adjustment	(1)	(124)	(13)	(138)
Deferred tax liability	(83)	(122)	(114)	(319)
Deferred tax (liability) asset	84	(46)	(114)	(76)

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

F-132

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2020	Profit (loss) (1)	12.31.2021
Tax loss carryforwards	126	(113)	13
Property, plant and equipment	-	80	80
Intangible assets	3	(3)	-
Financial assets at fair value through profit and loss	-	3	3
Trade and other receivables	6	(1)	5
Provisions	28	29	57
Salaries and social security payable	3	(3)	-
Defined benefit plans	5	4	9
Trade and other payables	3	(3)	-
Tax inflation adjustment	4	(4)	-
Deferred tax asset	178	(11)	167
Property, plant and equipment	(13)	13	-
Intangible assets	(11)	(2)	(13)
Investments in companies	(25)	14	(11)
Inventories	(6)	(4)	(10)
Financial assets at fair value through profit and loss	(4)	(10)	(14)
Trade and other receivables	(7)	(24)	(31)
Taxes payables	(3)	-	(3)
Tax inflation adjustment	(2)	1	(1)
Deferred tax liability	(71)	(12)	(83)
Deferred tax asset (liability)	107	(23)	84

⁽¹⁾ Includes US$ 13 million corresponding to discontinued operations.

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:

	12.31.2022	12.31.2021
Deferred tax asset	36	84
Deferred tax liability	(112)	-
Deferred tax (liability) asset	(76)	84

F-133

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.4 Inventories

	12.31.2022	12.31.2021
Current
Materials and spare parts	104	87
Advances to suppliers	8	8
In process and finished products	61	60
Total (1)	173	155

⁽¹⁾ It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

11.5 Provisions

	12.31.2022	12.31.2021
Non-Current
Contingencies	107	106
Asset retirement obligation and wind turbines decommisioning	25	19
Environmental remediation	15	15
Other provisions	-	1
Total Non-Current	147	141
Current
Asset retirement obligation and wind turbines decommisioning	2	2
Environmental remediation	2	3
Total Current	4	5

F-134

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

The evolution of the provisions is set out below:

	12.31.2022
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	106	21	18
Increases	5	6	-
Increases for incorporation (1)	-	1	-
Decreases	(1)	-	(1)
Gain on monetary position, net	(2)	-	-
Reversal of unused amounts	(1)	(1)	-
At the end of the year	107	27	17

⁽¹⁾ See Note 5.1.3.

	12.31.2021
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	103	21	3
Increases	16	3	15
Decreases	-	(1)	-
Reversal of unused amounts (1)	(13)	(2)	-
At the end of the year	106	21	18

⁽¹⁾ Includes recovery of US$ 12.5 million related to waive the timely granted dispatch of Las Armas Wind Farm (see Note 2.1.2.3).

F-135

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2020
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	139	22	3
Increases	21	2	-
Decreases	(1)	-	-
Gain on monetary position, net	(15)	-	-
Reversal of unused amounts	(8)	(3)	-
Reclassified to liabilities associated to assets classified as held for sale	(33)	-	-
At the end of the year	103	21	3

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. Even though the province answered the complaint in the month of March 2021, the Company has started formal negotiations to resolve the dispute, agreeing on the suspension of procedural time limits. During 2021, regarding these claims and based on the progress of the ongoing negotiations, the Company recorded provisions 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.

F-136

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

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. The Company does not have legally restricted assets for the cancellation of these obligations.

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.

11.5.3 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.

The determination of estimates may change in the future due to new developments or unknown facts at the time of evaluation of the provision. As a consequence, the adverse resolution of the evaluated proceedings and claims could exceed the established provision.

As of December 31, 2022, the Company has recorded provisions for US$ 102 million in relation to the following processes:

- There are a significant number of files pending before the National Tax Court regarding gasoline exports, where the tax entity challenges the tariff heading assigned by Petrobras in 2008-2014. The Treasury’s position involves a higher export duty rate.

- 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 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 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 is 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 30, 2021, POSA filed its claim memorial, and on September 15, 2021, the Company submitted its answer to the claim memorial and counterclaim. On December 15, 2021, POSA submitted its answer to the counterclaim. As of the date of issuance of these Consolidated Financial Statements, the proceeding pursues according the schedule decided by the parties.

F-137

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

- The Company filed an international arbitration claim against Petrobras International Braspetro B.V. (“PIB BV”) on account of fraudulent representations and omissions associated with certain export transactions under the share purchase agreement executed on May 13, 2016, whereby the Company acquired 67.2% of Petrobras Argentina S.A.’s capital stock. The arbitration is held under the ICC Arbitration Rules; the applicable law is the one of the State of New York, and the seat of arbitration is New York. On April 29, 2021, the Company filed its claim memorial and PIB BV submitted its counter-memorial and counterclaim seeking the payment of a percentage over the difference between the amount estimated for certain contingencies detected in the purchase process and the amount actually paid for them. On July 7, 2021, the Company and PIB BV submitted their respective answers. On November 5, 2021, the Company and PIB BV submitted their replications, and on December 20, 2021, their rejoinders to the complaints. As of the date of issuance of these Consolidated Financial Statements, the proceeding pursues according the schedule decided by the parties.

Additionally, the Company has recorded provisions for civil, commercial, administrative, labor, tax and customs complaints brought against the Company corresponding to atomized claims with individual unsubstantial amounts, as well as charges for judicial costs and expenses which, as of December 31, 2022, amount to US$ 5 million.

11.6 Income tax and minimum notional income tax liability

	12.31.2022	12.31.2021
Non-current
Income tax, net of witholdings	161	158
Minimum notional income tax	18	30
Total non-current	179	188
Current
Income tax, net of witholdings and advances	5	20
Total current	5	20

F-138

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

Income tax liability

The cumulative CPI variation over the 36 months prior to December 31, 2022 and 2021 has exceeded the 100% condition established by Law No. 27,430; therefore, the effect of the tax inflation adjustment has been accrued in the calculation of the current and deferred income tax provision. Likewise, as of December 31, 2020, the cumulative variation in the CPI has exceeded the 15% condition set for the third transition year pursuant to Law No. 27,430 and, therefore, the effect of the tax inflation adjustment has been accrued in the calculation of the current and deferred income tax provision, except in the cases where, on account of being irregular fiscal years, the mentioned legal parameter has not been exceeded for each of the annual periods.

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.”, where the CSJN ordered the application of the inflation adjustment mechanism.

As of December 31, 2022, the Company and its subsidiaries hold a provision for the additional income tax liabilities which should have been assessed for the reasons mentioned above. The provision for the period, including compensatory interest, is disclosed under “Non-current Income tax and minimum notional income tax provision”.

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 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. This liability is disclosed under “Non-Current Income tax and minimum notional income tax provision”.

F-139

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.7 Tax liabilities

	12.31.2022	12.31.2021
Current
Value added tax	5	4
Personal assets tax provision	4	2
Tax withholdings to be deposited	5	6
Royalties	12	9
Other	2	2
Total current	28	23

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-140

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

As of December 31, 2022, 2021 and 2020, the most relevant actuarial information corresponding to the described benefit plans is the following:

	12.31.2022
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	33	(4)	29
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	15	(2)	13
Items classified in other comprehensive  income
Actuarial losses	9	-	9
Benefit payments	(3)	-	(3)
(Gain) Loss on monetary position, net	(17)	2	(15)
At the end of the year	38	(4)	34
	12.31.2021
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	25	(4)	21
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	13	(3)	10
Items classified in other comprehensive  income
Actuarial losses	1	2	3
Benefit payments	(2)	-	(2)
(Gain) Loss on monetary position, net	(5)	1	(4)
At the end of the year	33	(4)	29

F-141

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2020
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	36	(5)	31
Items classified in profit or loss
Current services cost	3	-	3
Interest cost	16	(2)	14
Items classified in other comprehensive  income
Actuarial (gains) losses	(3)	1	(2)
Benefit payments	(2)	-	(2)
Reclasification liabilities associated to assets classified as held for sale	(10)	-	(10)
(Gain) Loss on monetary position, net	(15)	2	(13)
At the end of the year	25	(4)	21

As of December 31, 2022, 2021 and 2020, the breakdown of net liabilities per type of plan is as follows: a) US$ 17 million, US$ 15 million and US$ 12 million correspond to the Pension and Retirement Benefits Plan and b) US$ 17 million, US$ 14 million and US$ 9 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.

	12.31.2022
Less than one year	6
One to two years	3
Two to three years	4
Three to four years	4
Four to five years	3
Six to ten years	14

F-142

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

Significant actuarial assumptions used were as follows:

	12.31.2022	12.31.2021	12.31.2020
Real discount rate	5%	5%	4%
Real wage increase rate	1%	1%	1%
Inflation rate	118%	54%	46%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount:

	12.31.2022
Discount rate: 4%
Obligation	41
Variation	3
	9%
Discount rate: 6%
Obligation	35
Variation	(3)
	(8%)
Real wage increase rate: 0%
Obligation	37
Variation	(1)
	(4%)
Real wage increase rate: 2%
Obligation	39
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-143

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 11: (Continuation)

11.9 Salaries and social security payable

	12.31.2022	12.31.2021
Current
Salaries and social security contributions	5	4
Provision for vacations	8	7
Provision for gratifications and annual bonus for efficiency	19	17
Total current	32	28

NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1   Financial assets at amortized cost

	12.31.2022	12.31.2021
Non-current
Term deposit	101	100
Notes receivable	1	5
Total non-current	102	105
Current
Notes receivable	8	5
Total current	8	5

F-144

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.2   Financial assets at fair value through profit and loss

	12.31.2022	12.31.2021
Non-current
Shares	27	29
Total non-current	27	29
Current
Government securities	279	278
Corporate bonds	116	19
Shares	160	120
Mutual funds	31	41
Total current	586	458

12.3   Trade and other receivables

	Note	12.31.2022	12.31.2021
Non-Current
Related parties	16	17	23
Tax credits		2	9
Prepaid expenses		-	1
Other		1	1
Other receivables		20	34
Total non-current		20	34

F-145

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

		12.31.2022	12.31.2021
Current
Receivables from MAT sales		21	24
CAMMESA		165	89
Receivables from oiland gas sales		55	69
Receivables from petrochemicals sales		62	71
Related parties	16	5	7
Other		3	5
Impairment of financial assets		(6)	(9)
Trade receivables, net		305	256
Current
Related parties	16	7	8
Tax credits		14	5
Receivables for complementary activities		-	2
Prepaid expenses		14	10
Financial credit		-	10
Guarantee deposits		27	30
Insurance to be recovered		-	1
Expenses to be recovered		15	-
Receivables for acquisition of subsidiary		7	-
Receivables for sale of subsidiary and associates		4	41
Receivables for financial instruments sale		1	6
Argentine Natural Gas Production Promotion Plan		32	14
Receivables for arbitration award	15.6	37	-
Other		7	14
Other receivables, net		165	141
Total current		470	397

Due to the short-term nature of trade and other receivables, its book value is not considered to differ from its fair value. For non-current trade and other receivables, fair values do not significantly differ from book values.

F-146

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

The movements in the impairment of trade receivables were as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	9	16	68
Impairment (1)	1	1	63
Utilization	(1)	-	(7)
Reversal of unused amounts	-	(6)	(3)
Gain on monetary position, net	(3)	(2)	(2)
Gain on monetary position, net	-	-	(28)
Reclasified to assets classified as held for sale	-	-	(75)
At the end of the year	6	9	16

⁽¹⁾ It includes US$ 26 million corresponding to discontinued operations for fiscal year 2020. As of December 31, 2020, it includes US$ 13 million corresponding to the receivable impairment related to the exchange difference between the price of gas purchased by distributors and the price of gas recognised in distributors´s final tariffs between April 2018 and March 2019 to be assumed by the Federal Government in accordance to PEN Executive Order No. 1,053/18 (see Note 15).

The movements in the impairment of other financial assets were as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	-	-	6
Impairment	-	-	2
Reversal of unused amounts	-	-	(7)
Reclasified to assets classified as held for sale	-	-	(1)
At the end of the year	-	-	-

12.4   Cash and cash equivalents

	12.31.2022	12.31.2021
Banks	11	26
Mutual funds	95	84
Total	106	110

F-147

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5   Borrowings

	12.31.2022	12.31.2021
Non-Current
Financial borrowings	108	58
Corporate bonds	1,232	1,301
Total non-current	1,340	1,359
Current
Bank overdrafts	59	11
Financial borrowings	51	29
Corporate bonds	163	39
Total current	273	79
Total	1,613	1,438

As of December 31, 2022 and 2021, the fair values of the Company’s Corporate Bonds amount approximately to US$ 1,435 million and US$ 1,233 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 and bank overdrafts 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.

F-148

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5.1 Movements in borrowings:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	1,438	1,614	1,947
Proceeds from borrowings	308	188	353
Payment of borrowings	(143)	(336)	(300)
Accrued interest	172	137	176
Payment of interests	(162)	(140)	(201)
Repurchase and redemption of corporate bonds	(28)	(3)	(155)
Result from exchange of corporate bonds	14	-	-
Result from repurchase of corporate bonds	(6)	-	(43)
Increases for incorporation (1)	89	-	-
Cancellation through dividend compensation	-	-	(12)
Gain on monetary position, net	-	-	(43)
Foreign currency exchange difference, net	(80)	(22)	(18)
Borrowing costs capitalized in property, plant and equipment	11	-	10
Reclassified to liabilities associated to assets classified as held for sale	-	-	(100)
At the end of the year	1,613	1,438	1,614

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

F-149

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 12.31.2022
Corporate bonds (1)
T Series CB	PAMPA	US$	93	Fixed	7.38%	Jul-23	95
Class 8 CB	PAMPA	$	18	Variable	Badlar + 2%	Jul-23	20
Class 11 CB	PAMPA	$	122	Variable	Badlar + 0%	Jan-24	140
Class 9 CB	PAMPA	US$	102	Fixed	9.50%	Dec-26	184
Class 1 CB	PAMPA	US$	501	Fixed	7.50%	Jan-27	616
Class 13 CB	PAMPA	US$	49	Fixed	0.00%	Dec-27	48
Class 3 CB	PAMPA	US$	285	Fixed	9.13%	Apr-29	292
							1,395
Financial loans (2)
	PAMPA	US$	15	Variable	Libor + 4.21%	Nov-24	16
	GW	US$	83	Variable	Libor + 5.75%	Sep-26	85
							101
Other financial loans (3)
	PAMPA	US$	22	Variable	SOFR + 0.35%	Jul-23	23
	PAMPA	US$	8	Fixed	Between 9.50% and 14.50%	Between Jan-23 and May-23	8
	PAMPA	US$	27	Variable	SOFR + 0%	Agu-24	27
							58
Bank overdrafts (3)
	PAMPA	$	57	Fixed	Between 54% and 54.50%	Jan-23	59
							59
							1,613

⁽¹⁾ Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

⁽²⁾ During the the fiscal year ended December 31, 2022, the Company took on new short-term financing with domestic financial entities, net of cancellations, for a total $ 8,618 million and import prefinancing for US$ 7.6 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million and US$ 10.4 million corresponding to the credit facility subscribed between IDB Invest and Greenwind, a Company that is consolidated since acquisition of an additional 50% interest in August 2022.

⁽³⁾ During the fiscal year ended December 31, 2022, the Company received disbursements in the amount of US$ 1.3 million under the credit facilities taken out with BNP Paribas S.A. in 2020. After the fiscal year closing, the Company repaid short-term bank loans with local financial entities for $ 10,065 million and import prefinancing for US$ 0.7 million.

F-150

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 12.31.2021
Corporate bonds (1)
T Series CB	PAMPA	US$	389	Fixed	7.38%	Jul-23	400
Class 1 CB	PAMPA	US$	636	Fixed	7.50%	Jan-27	648
Class 3 CB	PAMPA	US$	293	Fixed	9.13%	Apr-29	292
							1,340
Financial loans (2)
	PAMPA	US$	23	Variable	Libor + 4.21%	May-24	23
							23
Other financial loans (3)
	PAMPA	US$	22	Variable	Libor + 0.35%	Jul-22	22
	PAMPA	US$	43	Variable	Libor + 0%	Aug-23	42
							64
Bank overdrafts
	PAMPA	$	11	Fixed	33.00%	Jan-22	11
							11
							1,438

⁽¹⁾ Net of the following face value repurchases: US$ 110,4 million of ON 2023, US$ 114,0 million of ON 2027 and US$ 7,5 million of ON 2029.

On September 27, 2021, the Company repaid at maturity Class 6 CBs for $ 6,355 million.

⁽²⁾ During the fiscal year ended December 31, 2021, the Company canceled short-term financing with local financial entities, net of borrowings, for $ 8,158 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million.

⁽³⁾ During the fiscal year ended December 31, 2021, the Company received disbursements in the amount of US$ 27 million under the credit facilities taken out with BNP in 2020.

F-151

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5.3 New Global Program of CB

On September 30, 2021, the Company’s General Ordinary and Extraordinary Shareholders’ Meeting resolved to approve the creation of a new global corporate bonds program for an amount of up to US$ 2,000 million or its equivalent in other currencies or units of value, in the form of simple corporate bonds non-convertible into shares and/or corporate bonds convertible into shares, to renew the program expired on December 29, 2021. The public offering was authorized by the CNV on December 9, 2021.

12.5.4 Issuance of CB Class 8

On January 18, 2022, the Company issued Class 8 CB in the amount of $ 3,107 million at a Badlar rate + 2%, maturing in 18 months. This is the first green bond issued by Pampa, which reflects the commitment to finance projects with a positive impact on the environment and to diversify the country’s energy generation matrix. The issue was recognised by Fix Ratings, an affiliate of Fitch Ratings, with the rating of Green Bond (BV1), the best possible grade, since it is aligned with the four main components of ICMA’s (International Capital Market Association) Green Bond Principles (GBP). It was issued in observance of the “Guidelines for the Issuance of Social, Green and Sustainable Bonds in Argentina” of the CNV Rules and the provisions of BYMA’s Social, Green and Sustainable Guide and the BYMA Rules, and also makes up BYMA’s Social, Green and Sustainable Bonds Panel.

The Company will allocate the issue’s proceeds to finance the expansion of PEPE IV (see Note 17.1).

12.5.5 Issuance of Class 10, 11, 12, 13 and 15 CB

On July 15, 2022, the Company issued Class 11 CB for $ 12,690 million, accruing interest at a variable BADLAR rate plus an annual 0% spread and maturing on January 15, 2024. Class 10 and Class 12 CB were declared unawarded.

Additionally, on August 8, 2022 the Company reopened Class 11 CB for $ 8,963.9 million at an issuance price of 1.0305. The total face value of outstanding Class 11 CB amounted to $ 21,654.6 million.

Finally, on December 13, 2022, the Company issued Clase 13 US$-link CB for US$ 49.9 million at a fixed interest rate of 0% and maturing on December 2027.

After the closing of the fiscal year, on January 11, 2023, the Company issued Class 15 CB for $ 10,379 million accruing interest at a variable BADLAR rate plus an annual 2% spread and maturing on July 11, 2024. Additionally, on March 2, 2023, the Company reopened Class 13 and Class 15 CB for US$ 48.2 million and $ 7,885 million, respectively.

F-152

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.5.6 Series T CB Exchange Offer

On June 16, 2022, the Company launched an exchange offer for holders of Series T CB maturing in 2023 originally issued by Petrobras Argentina S.A. (currently merged with the la Company) dated July 21, 2016 for a face value of US$ 500 million, under its Global Program authorized pursuant to CNV Resolution No. 17,162 dated August 15, 2013.

Once the exchange offer expired on July 29, 2022, the information and exchange agent informed the Company that US$ 193.8 million and US$ 213.3 million, representing 38.8% and 42.7% of the Series T CB’ outstanding principal, had been validly tendered for exchange under Option A and Option B, respectively, totaling a US$ 407.1 million participation and representing approximately 81.4% of the outstanding Series T CB’ capital amount.

Consequently, on August 8, 2022, after meeting the conditions established in the exchange offer documents, Pampa issued Class 9 CB for a face value of US$ 292.8 million, accruing interest at an annual fixed 9.5% rate and maturing on December 8, 2026, payable in three consecutive annual installments starting in 2024, and paid US$ 122.1 million in cash. For each US$ 1,000 of Series T CB’s capital amount validly tendered and accepted for exchange, eligible holders received, together with the payment of interest accrued on Series T CB up to the settlement date: (i) Option A: approximately US$ 377.2 in Class 9 CB and US$ 630.2 in cash; and (ii) Option B: US$ 1,030 in Class 9 CB.

As a result of the debt swap, the Company disclosed losses for US$ 14 million under “Other financial results” to reflect the change in the payment estimates discounted at Series T CB’s original effective interest rate, since they were not deemed substantially different from the issuance conditions for Class 9 CB, in accordance with IFRS.

As of the date of issuance of these Consolidated Financial Statements, outstanding Series T CB amount to US$ 92.9 million.

F-153

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 12: (Continuation)

12.6   Trade and other payables

	Note	12.31.2022	12.31.2021
Non-Current
Compensation agreements		10	3
Finance leases liability		10	9
Other		1	-
Other payables		21	12
Total non-current		21	12
Current
Suppliers		198	154
Customer advances		3	4
Related parties	16	14	15
Trade payables		215	173
Compensation agreements		12	2
Liability for acquisition of companies		46	-
Finance leases liability		2	4
Other		6	3
Other payables		66	9
Total current		281	182

Due to the short-term nature of the trade payables and other payables, their carrying amount is considered to be the same as their fair value. For most other non-current debts, fair values are also not significantly different from their book values.

F-154

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

As of December 31, 2022	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 receivables and other receivables	437	22	459	31	490
Financial assets at amortized cost
Term deposit	101	-	101	-	101
Notes receivable	9	-	9	-	9
Financial assets at fair value through profit and loss
Government securities	-	279	279	-	279
Corporate bonds	-	116	116	-	116
Shares	-	187	187	-	187
Mutual funds	-	31	31	-	31
Cash and cash equivalents	11	95	106	-	106
Total	558	730	1,288	31	1,319
Liabilities
Trade and other liabilities	298	-	298	4	302
Borrowings	1,613	-	1,613	-	1,613
Derivative financial instruments	-	2	2	-	2
Total	1,911	2	1,913	4	1,917
As of December 31, 2021	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 receivables and other receivables	376	30	406	25	431
Financial assets at amortized cost
Term deposit	100	-	100	-	100
Notes receivable	10	-	10	-	10
Financial assets at fair value through profit and loss
Government securities	-	278	278	-	278
Corporate bonds	-	19	19	-	19
Shares	-	149	149	-	149
Mutual funds	-	41	41	-	41
Cash and cash equivalents	26	84	110	-	110
Total	512	601	1,113	25	1,138
Liabilities
Trade and other liabilities	190	-	190	4	194
Borrowings	1,438	-	1,438	-	1,438
Total	1,628	-	1,628	4	1,632

The categories of financial instruments have been determined according to IFRS 9.

F-155

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2022	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	5	-	5	-	5
Interest expenses	(175)	-	(175)	(41)	(216)
Foreign currency exchange difference, net	16	(85)	(69)	149	80
Changes in the fair value of financial instruments	-	110	110	-	110
Result from present value measurement	(1)	-	(1)	(13)	(14)
Other financial results	(15)	-	(15)	-	(15)
Total	(170)	25	(145)	95	(50)
As of December 31, 2021	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	10	-	10	-	10
Interest expenses	(138)	-	(138)	(40)	(178)
Foreign currency exchange difference, net	(11)	(19)	(30)	33	3
Changes in the fair value of financial instruments	-	(15)	(15)	-	(15)
Result from present value measurement	2	-	2	(3)	(1)
Other financial results	(4)	-	(4)	(4)	(8)
Total	(141)	(34)	(175)	(14)	(189)
As of December 31, 2020	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	9	-	9	-	9
Interest expenses	(164)	-	(164)	(6)	(170)
Foreign currency exchange difference, net	38	(35)	3	11	14
Changes in the fair value of financial instruments	-	30	30	-	30
Result from present value measurement	6	-	6	(4)	2
Other financial results	36	-	36	(5)	31
Total	(75)	(5)	(80)	(4)	(84)

F-156

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 and liabilities measured at fair value as of December 31, 2022 and 2021:

As of December 31, 2022	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	279	-	-	279
Corporate bonds	116	-	-	116
Mutual funds	31	-	-	31
Shares	160	-	27	187
Cash and cash equivalents
Mutual funds	95	-	-	95
Other receivables	22	-	-	22
Total assets	703	-	27	730
Liabilities
Derivative financial instruments	-	2	0	2
Total liabilities	-	2	-	2
As of December 31, 2021	Level 1	Level 3	Total
Assets
Financial assets at fair value through  profit and losss
Government securities	278	-	278
Corporate bonds	19	-	19
Mutual funds	41	-	41
Shares	120	29	149
Cash and cash equivalents
Mutual funds	84	-	84
Other receivables	30	-	30
Total assets	572	29	601

F-157

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 with changes in profit (loss), 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 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 direct equity interest of 2.84% and 3.19%, and the additional equity interest of 2.18% and 2.46% through HIDISA and HINISA, in TJSM and TMB, respectively, resulting from the Federal Government’s restructuring of assets in the energy sector. This restructuring resulted in TMB’s and TJSM’s share transfer from the Federal Government to IEASA, considering 16.4% and 13.7% discount rate as of December, 31 2022 and 2021, respectively. The key assumptions were prepared based on estimates on the future behavior of certain sensitive variables, including: (i) the dividend distribution policy; (ii) reference prices for energy sold in the spot market; (iii) projections of the availability and dispatch of power plants; (iv) the evolution of structural costs and expenses; (v) macroeconomic variables such as inflation and exchange rates, etc. The Company recognised losses for US$ 1.7 million and earnings for US$ 18 million as a result of changes in the fair value of financial instruments classified as level 3, under the item “Other financial results” of the Consolidated Statement of Comprehensive Income, as of December, 31 2022 and 2021, respectively. Current values may substantially differ from projections, mainly on account of: i) the timeliness and magnitude of the distribution of dividends, ii) the timeliness and magnitude of energy price updates, and/or iii) the evolution of costs. 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-158

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 13: EQUITY COMPONENTS

13.1 Share capital

As of December 31, 2022, the share capital amounts to 1,384 million shares, including approximately 4 million treasury shares.

13.1.1 Share buyback programs

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 buyback programs, considering in each case that treasury shares may not exceed the 10% capital stock capitalization.

During 2021, the Company’s Board of Directors approved Programs 9 and 10 for a maximum amount of US$ 30 million each, under which shares could be acquired up to a maximum price of US$ 16 and US$ 15.5 per ADR, respectively. The Company directly and indirectly acquired 2.7 million own ADRs for a value of US$ 38.7 million, and the repurchased shares canceled in full.

On December 1, 2021, the Company’s Board of Directors approved Program 11 for a maximum amount of US$ 30 million and an initial term of 120 calendar days; under this Program, shares may be acquired up to a maximum price of US$ 19 per ADR and $ 167 per common share. On March 10, 2022, the Board of Directors resolved to suspend Program 11, as the Company’s share and ADR prices exceeded the set repurchase limit values.

On May 11, 2022, the Board of Directors resolved to approve Program 12 for a maximum amount of US$ 30 million, an initial term of 120 calendar days, and a maximum price of US$ 22 per ADR and $ 194 per common share.

As of the issuance of these Consolidated Financial Statements, these programs have already expired.

During 2022, the Company indirectly acquired 0.9 million own ADRs for a value of US$ 18.2 million to an average price of US$ 20,3 per ADR.

13.1.2 Stock Compensation Plan

During fiscal year ended December 31, 2021, the Company delivered 0.5 million own shares as payments under the stock compensation plan for officers and other key staff, respectively. In addition, the Company acquired 6 million own shares, out of which 2 million were allocated to the compensation of senior managers. As of December, 31 2022 and 2021, 4 million remained in treasury to be delivered to employees under such plan (see Note 4.17).

F-159

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 13: (Continuation)

13.1.3 Capital reductions

During 2021, the capital stock reduction approved by the Company’s General Ordinary and Extraordinary Shareholders’ Meeting held on April 29, 2021 and September 30, 2021, which provided for the cancellation of 56.6 million shares and 12.5 million shares, respectively. These reductions are registered in the Public Registry.

On April 27, 2022, General Ordinary and Extraordinary Shareholders’ Meeting resolved to reduce the Company’s capital stock by canceling 2.8 million shares which took place during October 2022. This reduction was registered with the Public Registry on September 14, 2022.

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 period, no dilutive effect is recorded, being the diluted earnings per share equal to the basic. As of December 31, 2022, 2021 and 2020, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

	12.31.2022	12.31.2021	12.31.2020
Earning for continuing operations attributable to equity holders of the Company	456	312	132
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earnings per share from continued operations	0.33	0.22	0.08
Loss for discontinued operations attributable to equity holders of the Company	-	(39)	(499)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted loss per share from discontinued operations	-	(0.03)	(0.32)
Earning (Loss) attributable to equity holders of the Company	456	273	(367)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earning (loss) per share	0.33	0.19	(0.23)

F-160

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 13: (Continuation)

13.3 Profit distributions

Dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or 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.

NOTE 14: STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit to cash flows generated by operating activities

	Note	12.31.2022	12.31.2021	12.31.2020
Income tax	10.5	124	77	35
Accrued interest		185	141	132
Depreciations and amortizations	9 and 10.2	212	205	205
Share of profit of joint ventures and associates	5.2.2	(105)	(117)	(85)
Results for property, plant and equipment sale	10.3	(2)	(1)	-
Result for intangibles assets sale	10.3	(2)	(2)	-
Impairment of property, plant and equipment, intangible assets and inventories	10.1, 10.2 and 10.4	38	4	139
Impairment of financial assets		8	2	9
Result from measurement at present value	10.4	14	1	(2)
Changes in the fair value of financial instruments		(94)	24	(19)
Exchange differences, net		(85)	(3)	(14)
Result from exchange of corporate bonds	10.4	14	-	-
Result from repurchase of corporate bonds	10.4	(6)	-	(38)
Readjustment of investment plan	10.3	9	-	-
Compensation for arbitration award	10.3	(37)	-	-
Recovery of tax charges	10.3	-	(2)	-
Provision for contingecies, net	10.3	4	3	2
Provision for environmental remediation	10.3	-	15	-
Accrual of defined benefit plans	9 and 10.2	14	11	11
Dividends received	10.3	-	-	(1)
Compensation agreements	10.1 and 10.2	19	2	1
Other		(3)	5	5
Adjustments to reconcile net profit to cash flows from operating activities		307	365	380

F-161

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 14: (Continuation)

14.2 Changes in operating assets and liabilities

	12.31.2022	12.31.2021	12.31.2020
(Increase) Decrease in trade receivables and other receivables	(233)	(41)	19
Increase in inventories	(21)	(40)	(6)
Increase in trade payables and other payables	70	43	3
Increase (Decrease) in salaries and social security payable	15	8	(1)
Decrease in defined benefit plans	(3)	(2)	(2)
Increase (Decrease) in tax liabilities	36	(5)	(20)
Decrease in provisions	(1)	(3)	(5)
Income tax paid	(2)	(13)	(5)
Payments from derivative financial instruments, net	(6)	(12)	(5)
Changes in operating assets and liabilities	(145)	(65)	(22)

14.3 Significant non-cash transactions

	12.31.2022	12.31.2021	12.31.2020
Acquisition of property, plant and equipment through an increase in trade payables	(75)	(51)	(8)
Borrowing costs capitalized in property, plant and equipment	(11)	-	(10)
Acquisition of subsidiary by delivering financial assets at fair value through profit and loss	(35)	-	-
Receivables from sales of companies pending collection	-	40	-
Receivables for acquisition of subsidiary	7	-	-
Increase in investments in associates through a decrease in other receivables	-	(20)	-
Increase in right-of-use assets through an increase in other liabilities	(1)	(7)	-
Dividends pending collection	-	2	20
Compensation of loans through dividends assignment	-	-	12
Decrease on well abandonment provision, net, through property, plant and equipment	(1)	(1)	(3)

F-162

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2022, 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 by former employees not covered by the plan, seeking their inclusion. The Chamber of Appeals upheld the first-instance judgments that had dismissed the complaints filed in two claims by non-covered former employees seeking to be included in the plan. Both of these judgments are final and conclusive.

- Claims by former employees seeking compensation under the plan on account of terminations due to changes in shareholding control.

- Claims on considering that the index (CPI) used to update the plan benefits is ineffective to keep their “constant value”. In two of the causes, the Company obtained a favorable judgment, which has been appealed by the plaintiff. On the other hand, the Company received an adverse judgment in a claim, consequently, the Company has filed an appeal before the applicable Chamber.

- 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 filed an appeal, which was sustained by the Chamber. 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.

15.2 Tax claim

- Tax on Liquid Fuels and Natural Gas:

The AFIP 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.

F-163

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

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.

- 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 based on a United Nations Development Program report. The proceeding is in the complaint answer stage.

- Beatriz Mendoza and other 16 plaintiffs brought a complaint before the CSJN against the National Government, the Province of Buenos Aires, the Government of the Autonomous City of Buenos Aires and 44 companies, including the Company, conducting industrial activities along the Matanza-Riachuelo River Basin. The plaintiffs seek compensation for alleged damages sustained as a result of an alleged environmental impact, its cessation, the environmental recomposition and redress, for an estimated amount of US$ 500 million for the financing of the Matanza-Riachuelo River Basin Environmental Management Plan aiming at the restoration of the basin. The proceeding is in the third-party summoning stage.

- Inertis S.A. has filed a complaint against the Company for alleged damage to the environment in a lot owned by this company as a result of the activities conducted by the Dock Sud Plant seeking the redress of alleged damages for a nominal amount estimated at $ 1 million and US$ 1 million, or the difference between the value of the allegedly affected lot and its valuation. The proceeding is in the evidentiary 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 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 $ 200 million. The parties agreed on a stay of the procedural time limits until August 2022 to evaluate the possibility of reaching an agreement. The plaintiff reached an agreement with three co-defendants. The Chamber hearing the case referred it back to the first instance, and the Court ordered a series of information measures before serving notice of the agreement on the other co-defendants (including the Company).

F-164

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

- Some neighbors of the Dock Sud area brought a complaint against 14 oil companies, including the Company, petrochemical companies and waste incineration plants located in the Dock Sud Petrochemical Complex for an alleged damage to the environment and alleged individual damage to their goods, health and morale. The CSJN determined it had jurisdiction over the environmental issue and maintained the civil and commercial jurisdiction regarding the compensation for the alleged damages. The First-Instance Civil and Commercial Court opened the evidentiary stage.

- A neighbor of the Province of Salta owning a lot where a joint venture made up of the plaintiffs (the Company and other companies) conducted hydrocarbon activities seeks environmental protection and restoration for alleged damage caused by hydrocarbon prospecting, exploration and/or exploitation activities or, alternatively, a compensation in case such environmental restoration is not possible. The Province of Salta has been summoned as a third party. The proceeding is in the complaint answer stage and the Court of Justice of Salta declared that the First-Instance Administrative Litigation Court has jurisdiction over the claim.

- Owners of a lot in the town of Garín, Province of Buenos Aires, seek the performance of preliminary proceedings for alleged indications of damage to the environment in their place of residence which would result from an alleged leakage from the adjacent gas station under the Company’s branding. Preliminary measures are being conducted in this proceeding.

- Neighbors of the Province of Neuquén brought a proceeding against the Company for alleged environmental damage resulting from the hydrocarbon exploration, exploitation, transportation and well abandonment activities in which that plaintiff has been taking part. Should this not be feasible, they claim a compensation for alleged damages to support the Environmental Restoration Fund. Additionally, they request the redress of alleged moral damages to be allocated to the Environmental Restoration Fund. The presence of all involved parties has been properly verified, and the lawsuit has been referred to the administrative litigation jurisdiction.

- Plaintiff Martinez Lidia and other three plaintiffs claim financial compensation for alleged damage to their health and property caused by the alleged environmental affectation sustained as a result of living next to Puerto General San Martin petrochemical plant (Rosario-Santa Fe). The evidentiary stage is closed and the Public Defender for the deceased plaintiff’s heirs was appointed, and he accepted this appointment.

- A neighbor of the Province of Buenos Aires brought a complaint against the Company seeking the removal of three fuel storage tanks and pumps and the remediation and restoration of the soils where such tanks are located on account of an alleged environmental affectation. The proceeding is in the evidentiary stage.

- Neighbors of the Province of Santa Fe have brought a complaint against the Company for alleged environmental damage. The Company obtained a favorable judgment, which has been appealed by the plaintiff.

F-165

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

15.4 Civil and Commercial Claims

- The “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of US$ 3,650 million as compensation for damages, Pampa, Petrolera Pampa S.A. and certain Pampa directors in office during 2016 being 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, Petrolera Pampa S.A. 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 Chamber of Appeals in Commercial Matters upheld the filed extraordinary appeal. On its part, Petróleo Brasileiro S.A. filed an appearance, requested that the lack of substance of the filed appeal should be declared, and subsidiarily answered it. The Company was served notice of the upholding of the motion made by the Chamber of Appeals in Commercial Matters and filed a presentation in this respect. Later, the CSJN declared the nullity of the Chamber of Appeals in Commercial Matters’ decision upholding the extraordinary appeal and referred the court file back so that a new judgment should be rendered.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2022 where the related inflows of economic benefits are estimated to be probable by the Company.

15.5 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, subsidiarily, sustained damages should be redressed. Later on, CTLL filed a new contentious administrative litigation complaint against the Federal Government for contractual breach during the April 2016-October 2018 period. In the complaint for the January-March 2016 period, the closing of the evidentiary stage was suspended on account of the proceeding’s link with the complaint subsequently field for the April 2016- October 2018 period, proceeding which is currently in the evidentiary stage.

- 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. Both parties agreed to suspend the proceeding to pursue a private settlement, the rendering of judgment was requested and the CSJN has set a preliminary hearing, which was carried out. Currently, after the opinion rendered by the National Attorney General, the proceeding is pending judgment by the CSJN.

F-166

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 15: (Continuation)

- 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. On September 1, 2021 a request for an expedited procedure was filed. On September 1, 2021. a request for an expedited procedure was filed. On December 2, 2021, the Company filed a protective action (amparo) on the grounds of undue delay seeking that defendant should state its opinion in this respect. A judgment was rendered dismissing the amparo. The Company has filed an appeal against this decision, which was dismissed by the Chamber hearing the case. As MECON’s term to state its position on the RAP has expired, the Company has brought a complaint against the Federal Government.

15.6 Civil and Commercial Claims

- EcuadorTLC (currently Pampa Bloque 18), 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 —in both cases, as amended—. 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.

- Ecuador TLC (currently Pampa Bloque 18), brought an arbitration claim against Petroecuador before the arbitration and mediation center of the Chamber of Commerce of Quito as a result of certain breaches to the transportation agreement entered into on December 31, 2008 whereby the Ecuadorian Government undertook the crude oil transportation commitment through the OCP, to be charged to the oil transportation capacity hired by Pampa Bloque 18. On August 3, 2022, the Arbitration Court rendered a final and conclusive award partially upholding the complaint. Even though the award was not annulled, Petroecuador filed an extraordinary protection proceeding before the Constitutional Court. It is worth highlighting that this proceeding does not suspend the execution of the arbitration award. As of December 31, 2022, Pampa Bloque 18 recorded a US$ 37.4 million receivable as compensation for the arbitration complaint in Ecuador. As of the issuance of these Consolidated Financial Statements, Petroecuador has partially fulfilled the award and made a US$ 20 million payment.

- The Company has instituted an international arbitration proceeding against High Luck Group Limited - Argentina branch as a result of certain breaches to the Participation Assignment Agreement and the Joint Operation Agreement for the Chirete Block entered into on April 1, 2015.

F-167

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: RELATED PARTIES´ TRANSACTIONS

16.1 Balances with related parties

As of December 31, 2022	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
TGS	5	17	6	7
Other related parties
SACDE	-	-	-	7
Other	-	-	1	-
	5	17	7	14
As of December 31, 2021	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
OCP	-	-	2	-
Refinor	1	-	-	2
TGS	6	23	5	3
Other related parties
SACDE	-	-	-	10
Other	-	-	1	-
	7	23	8	15

F-168

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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 for services (3)			Other operating expenses and income (4)
	2022	2021	2020	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
CTB	2	2	2	-	-	-	-	-	-	-	-	-
Greenwind	-	1	1	-	-	-	-	-	-	-	-	-
Refinor	11	9	10	(11)	(6)	(5)	-	-	-	-	-	-
TGS	51	45	20	(53)	(43)	(24)	-	-	-	-	-	-
Other related parties
Fundación	-	-	-	-	-	-	-	-	-	(2)	(2)	(2)
SACDE	-	-	-	(203)	(48)	(6)	-	-	-	-	-	-
Salaverri, Dellatorre, Burgio & Wetzler	-	-	-	-	-	-	(1)	(1)	(1)	-	-	-
	64	57	33	(267)	(97)	(35)	(1)	(1)	(1)	(2)	(2)	(2)

⁽¹⁾ Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas and refined products.

⁽²⁾ Correspond to natural gas transportation services, purchases of refined products and other services imputed to cost of sales for US$ 191 million, US$ 50 million and US$ 29 million and infrastructure works contracted to SACDE imputed in property, plant and equipment for US$ 76 million, US$ 47 million and US$ 6 million, of which US$ 38 million, US$ 17 million and US$ 2 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, 2022, 2021 and 2020, respectively.

⁽³⁾ Disclosed within administrative expenses.

⁽⁴⁾ Corresponds mainly to donations.

Operations for the year	Finance income (1)			Dividends received			Payment of dividends
	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
Citelec	-	-	-	-	-	13	-	-	-
OCP	-	1	1	10	20	21	-	-	-
TGS	2	3	3	-	-	-	-	-	-
Other related parties
EMESA	-	-	-	-	-	-	-	-	(9)
Other	-	-	-	-	-	1	-	-	-
	2	4	4	10	20	35	-	-	(9)

⁽¹⁾ Corresponds mainly to financial leases and accrued interest on loans granted.

F-169

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 16: (Continuation)

16.3 Key management personnel remuneration

During the years ended December 31, 2022 2021 and 2020, the total remuneration to executive directors accrued amounts to US$ 26 million (US$ 7 million for Directors' and Sindycs' fees and US$ 19 million in the accrual of Stock-based Compensation Plans and Compensation Agreements), US$ 7 million (US$ 6 million for Directors' and Sindycs' fees and US$ 1 million in the accrual of Stock-based Compensation Plans and Compensation Agreements ), and US$ 7 million (US$ 6 million for Directors' and Sindycs' fees and US$ 1 million in the accrual of EBDA Compensation and Stock-based Compensation Plans), respectively.

It should be noted that, as stipulated in the compensation agreements (See Note 4.17.1), and considering that no compensation had been assigned in favor of the Company’s main officers over the last three fiscal years, on September 30, 2021 they exercised the right to set the Company’s ADR weighted average listed price over the 30 business exchange days before the closing of year 2020 as the new initial market value to calculate compensations as from fiscal year 2021. Following the exercise of this option, the officers have lost all their rights to accrued and uncollected compensations for the previous fiscal years, which generated the recognition of a profit of US$ 6.7 million as of December 31, 2021.

NOTE 17: INVESTMENT COMMITMENTS

17.1 New generation projects

Under the National Government’s call for the expansion of the generation offer, the Company participated in the following generation projects:

PEPE IV

In early 2022, works started for the expansion of PEPE III, inaugurated in 2019 and located in the town of Coronel Rosales, Province of Buenos Aires, which production is targeted at the large users’ segment, with 14 wind turbines and an installed capacity of 53.2 MW.

The project, with an estimated investment of US$ 128 million, will mainly consist of the mounting and installation (in stages) of 18 additional wind turbines, adding a capacity of 81 MW; therefore, once works are completed, PEPE III and PEPE IV will have an installed capacity of 134.2 MW. The expansion requires sophisticated works on the platforms and foundations, which will be conducted by SACDE, and the start-up is planned for the second quarter of 2023.

On December 29, 2022 took place the commissioning of 4 wind turbines which have a capacity of 18 MW, and on February 25, 2023, took place the commissioning of 4 additional wind turbines with an incremental capacity of 18 MW.

F-170

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 17: (Continuation)

17.2 Investment commitment for the exploration and exploitation of hydrocarbons

Regarding the investment project committed by CENCH for the Sierra Chata block, on June 29, 2022 was published Provincial Executive Order No. 1,262/22 approving the new investment schedule. Under it, the consortium made up by the Company and Mobil Argentina S.A. undertakes to execute 14 horizontal wells targeting the Vaca Muerta formation by July 26, 2023.

As of the issuance of these Consolidated Financial Statements, the Company has committed investments until 2024 for an estimated total amount of US$ 180 million, including commitments associated with the participations detailed in Note 5.3.

NOTE 18: INCIDENT AT GENELBA THERMAL POWER PLANT

On May 31, 2021 an incident occurred in the GEBATG03 (TG21) unit, which makes up Genelba thermal power plant’s Genelba Plus combined cycle, and damage was caused to the unit’s turbine. As a result of the incident, the combined-cycle generation capacity was reduced by approximately 50% (280 MW).

Jointly with the turbine’s manufacturer (SIEMENS), the Company performed the necessary works to dismantle and repair the failure, which were completed in July 2021.

Moreover, the Company is making all necessary filings before the insurance companies to collect the compensatory damages for the failure and minimize losses associated with the breach of availability commitments.

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, 2022 and 2021 is disclosed below:

F-171

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 19: (Continuation)

19.1.1 Right of use assets

	Original values
				Decrease
Type of good		At the beginning	Increase		At the end
Machinery and equipment		20	1	(1)	20
Total at 12.31.2022		20	1	(1)	20
Total at 12.31.2021		13	7	-	20
		Amortization
Type of good		At the beginning	For the year	At the end
Machinery and equipment		(8)	(3)	(11)
Total at 12.31.2022		(8)	(3)	(11)
Total at 12.31.2021		(3)	(5)	(8)
		Net book values
Type of good		At 12.31.2022	At 12.31.2021
Machinery and equipment		9	12
Total at 12.31.2022		9
Total at 12.31.2021			12

F-172

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 19: (Continuation)

19.1.2 Lease liabilities

	12.31.2022	12.31.2021
At the beginning of the year	13	12
Increases	1	6
Result from measurement at present value (1)	2	-
Reversal of unused amounts	(1)	-
Payments	(3)	(5)
At the end of the year	12	13

⁽¹⁾ Included in Other financial results.

As of December 31, 2022 and 2021, this liability is disclosed under Other current payables in the amount of US$ 2 million and US$ 4 million and Other non-current payables for US$ 10 million and US$ 9 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:

	12.31.2022
Three months to one year	1
One to two years	1
Two to three years	3
Three to four years	2
Four to five years	2
More than five years	14
Total	23

19.1.3 Short-term or low value leases

As of December 31, 2022 and 2021, the Company has recognised administrative costs and expenses in the amount of US$ 6 million on account of lease payments associated with short-term leases.

F-173

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (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, 2022 and 2021, this receivable is disclosed under Other current receivables in the amount of US$ 6 million and US$ 5 million, respectively and under Other non-current receivables for US$ 17 million and US$ 23 million, respectively.

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:

	12.31.2022
Less than three months	1
Three months to one year	5
One to two years	5
Two to three years	7
Three to four years	5
Total	23

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, 2022 are detailed below:

	12.31.2022
Three months to one year	1
One to two years	1
More than three years	1
Total	3

Total income from operating leases for the fiscal year ended December 31, 2022 amounts to US$ 1 million.

F-174

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

NOTE 20: TERMINATION OF HYDROELECTRIC CONCESSIONS

As the hydroelectric concessions timely granted by the Federal Government and, in some cases, by the Provinces approach expiration, on March 10, 2022, SE Resolution No. 130/22 was published, creating a Concessioned Hydroelectric Exploitations Team to evaluate the status of the hydropower concessions under national jurisdiction, including HIDISA, HINISA, and HPPL.

This team will be presided over by the Secretary of Energy (or the person appointed by him) and coordinated by a person with proven experience in the field. It will also be made up of representatives of the SE, CAMMESA, the ENRE, and IEASA. Furthermore, the Dam Safety Regulatory Body and water management and environmental protection authorities are invited to appoint a representative in the team.

The concessions' status report must be submitted within two years for the HIDISA and HINISA concessions, expiring in 2024, whereas the term for issuing the report for HPPL, which concession expires in 2029, will be later determined.

Finally, IEASA is entrusted with the technical audit of the power generation equipment.

NOTE 21: DOCUMENTATION KEEPING

On August 14, 2014, the CNV issued General Resolution No. 629, which introduced modifications to the provisions applicable to the keeping and conservation of corporate and accounting books and commercial documentation. To such effect, the Company, have 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 and in the Iron Mountain Argentina S.A.’s data warehouses located at the following addresses:

- Azara 1245 – C.A.B.A.

- Don Pedro de Mendoza 2163 – C.A.B.A.

- Amancio Alcorta 2482 - C.A.B.A.

- San Miguel de Tucumán 601, Carlos Spegazzini, Municipality of Ezeiza, 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.

F-175

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2022, 2021 and 2020 (Continuation)

(in millions of US$ – unless otherwise stated)

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, 2022.

	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	7,722	17,372	3,214	11,241	10,936	28,613
Total at 12.31.2022	7,722	17,372	3,214	11,241	10,936	28,613

⁽¹⁾ In thousands of barrels.

⁽²⁾ In millions of cubic meters.

NOTE 23: SUBSEQUENT EVENTS

PEPE VI

In February 2023, the Company started constructing Pampa Energía VI Wind Farm in Bahía Blanca, Province of Buenos Aires. The project will enable the installation of a 300 MW power capacity, in 3 stages, with an estimated US$ 500 million investment.

Stage 1 comprises the mounting and installation of 21 Vestas wind turbines, with their internal medium-voltage cable network, roads, a substation and a 500 KV line allowing for a 94.5 MW capacity addition, with an investment for US$ 186 million, expected to be operative in mid-2024.

The energy produced by this wind park allows for reduced carbon emissions and will be sold through the MATER to supply large companies in the country in compliance with the Renewable Energy Law.

F-176

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, 2022, 2021 and 2020. 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)
	12.31.2022	12.31.2021	12.31.2020
	(in million of US$)
Acquisition of properties
Proved	-	-	-
Unproved	-	-	-
Total property acquisition	-	-	-
Exploration	2	9	24
Development	322	197	17
Total costs incurred	324	206	41

Capitalized cost

The following table presents the capitalized costs as of December 31, 2022, 2021 and 2020, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.

	Consolidated companies (Argentina)
	12.31.2022	12.31.2021	12.31.2020
	(in million of US$)
Proved properties
Equipment, camps and other facilities	328	194	122
Mineral interests and wells	1,137	1,078	967
Other uncompleted projects	151	117	91
Unproved properties	36	42	50
Gross capitalized costs	1,652	1,431	1,230
Accumulated depreciation	(845)	(795)	(687)
Total net capitalized costs	807	636	543

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, 2022, 2021 and 2020. Income tax for the years presented was calculated utilizing the statutory tax rates.

	Consolidated companies (Argentina)
	12.31.2022	12.31.2021	12.31.2020
	(in million of US$)
Revenue	529	340	227
Intersegment sales	117	113	67
Argentine Natural Gas Production Promotion Plan	56	51	-
Production costs, excluding depreciation
Operating costs and others	(214)	(161)	(138)
Royalties	(87)	(63)	(39)
Total production costs	(301)	(224)	(177)
Exploration expenses	-	-	-
Depreciation, depletion and amortization	(125)	(114)	(108)
Results of operations before income tax	276	166	9
Income tax	(97)	(58)	(3)
Results of oil and gas operations	179	108	6

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, 2022 was audited by Gaffney, Cline & Associates. Gaffney, Cline & Associates is an independent petroleum engineering consulting firm. The independent audit covered 97% 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’s 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, 2022, 2021 and 2020:

	Reserves as of December 31, 2022		Reserves as of December 31, 2021		Reserves as of December 31, 2020
	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	7.7	613.5	8.0	527.9	7.8	372.0
PROVED Undeveloped	3.2	397.0	4.7	338.7	5.8	397.5
Total proved reseves (developed and undeveloped)	10.9	1,010.5	12.6	866.5	13.5	769.5

S-3

The following table sets forth the reconciliation of our reserves data between December 31, 2020, December 31, 2021 and December 31, 2022:

	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, 2019 (*)	13,551	731,082
Increase (decrease) attributable to:
Revisions of previous estimates	152	25,633
Improved recovery	44	57,119
Extension and discoveries	1,406	44,825
Year's production	(1,627)	(89,140)
Reserves as of December 31, 2020 (*)	13,526	769,519
Increase (decrease) attributable to:
Revisions of previous estimates	206	44,993
Improved recovery	2	7,696
Extension and discoveries	607	145,564
Year's production	(1,716)	(101,231)
Reserves as of December 31, 2021 (*)	12,625	866,541
Increase (decrease) attributable to:
Revisions of previous estimates	(466)	(72,518)
Improved recovery	272	84
Extension and discoveries	454	339,021
Year's production	(1,948)	(122,636)
Reserves as of December 31, 2022 (*)	10,937	1,010,492
(*) Includes proved developed reserves:
As of December 31, 2020	7,761	371,999
As of December 31, 2021	7,970	527,870
As of December 31, 2022	7,722	613,505

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 2022, 2021 and 2020 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.

	12.31.2022	12.31.2021	12.31.2020
	(in million of US$)
Future cash inflows	4,787	3,835	3,067
Future production costs	(1,838)	(1,412)	(1,256)
Future development and abandonment costs	(680)	(500)	(542)
Future income tax	(484)	(425)	(240)
Undiscounted future net cash flows	1,785	1,498	1,029
10% annual discount	(644)	(548)	(398)
Standarized measure of discounted future net cash flows	1,141	950	631

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, 2022, 2021 and 2020:

	Consolidated companies (Argentina)
	12.31.2022	12.31.2021	12.31.2020
	(in million of US$)
Standarized measure at the beginning of year	950	631	640
Changes related to Oil & Gas Activities:
Sales Net of Production costs	(401)	(280)	(117)
Net Change in sales prices, net of future production costs	201	281	(86)
Changes in future development costs	(454)	(131)	(51)
Extensions, discoveries and improved recovery, net of futures production and assocciated costs	595	228	170
Development costs incurred	322	197	17
Revisions of quantity estimates	(124)	77	44
Purchase of reserves in place	-	-	7
Net change in income tax	(59)	(118)	(42)
Accretion of discount	123	79	76
Changes in production rates	(21)	19	(29)
Other changes	9	(33)	2
Standarized measure at the end of year	1,141	950	631

S-6

EX-2.D

Exhibit 2(d)

Description of rights of each class of securities registered under Section 12 of the Securities Exchange Act of 1934

American Depositary Shares (“ADSs”) representing twenty five Common Shares, nominal value P$1.00 each (the “Shares”) of Pampa Energía S.A. (“Pampa” or the “Company”), are listed and trade on the New York Stock Exchange and, in connection with this listing (but not for trading), our Shares are registered under Section 12(b) of the Exchange Act. This exhibit contains a description of the rights of (i) the holders of our Shares and (ii) ADS holders. Shares underlying the ADSs are held by JPMorgan Chase Bank, N.A. (formerly Morgan Guaranty Trust Company of New York, “J.P. Morgan” and/or the “Depositary”), as depositary, and holders of ADSs will not be treated as holders of the shares of our Shares.

Disclosures under the following items are not applicable to us and have been omitted: debt securities (Item 12.A of Form 20-F), warrants and rights (Item 12.B of Form 20-F) and other securities (Item 12.C of Form 20-F).

Shares

Type and Class of Securities (Item 9.A.5 of Form 20-F)

Our capital stock is comprised 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 Mellon (“BONY”) as depositary. Each ADS represents 25 Shares.

Pursuant to the provisions of Deposit Agreement, on January 23, 2017, Pampa sent a notice to BONY stating that Pampa (i) removed BONY 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.

Preemptive Rights (Item 9.A.3 of Form 20-F)

See “Item 10 – Additional Information – Memorandum and Articles of Association – Preemptive and Accretion Rights” in the annual report to which this exhibit is attached.

Limitations or Qualifications (Item 9.A.6 of Form 20-F)

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See “Item 10 – Additional Information – Memorandum and Articles of Association – Preemptive and Accretion Rights” in the annual report to which this exhibit is attached.

Other rights (Item 9.A.7 of Form 20-F)

Not applicable.

Rights, preferences and restrictions (Item 10.B.3 of Form 20-F)

See “Item 10 – Additional Information – Memorandum and Articles of Association – Dividends”; “Item 10 – Additional Information – Memorandum and Articles of Association – Voting Rights”; “Item 10 – Additional Information – Memorandum and Articles of Association – Quorum and Voting Requirements”; “Item 10 – Additional Information – Memorandum and Articles of Association – Election of directors ”; “Item 10 – Additional Information – Memorandum and Articles of Association – Liquidation Rights” and “Item 10 – Additional Information – Memorandum and Articles of Association – Redemption and Withdrawal Rights” in the annual report to which this exhibit is attached.

Requirements for Amendments of Articles of Incorporation (Item 10.B.4 of Form 20-F)

See “Item 10 – Additional Information – Memorandum and Articles of Association – Amendment of Articles of Incorporation” in the annual report to which this exhibit is attached.

Limitations on the Rights to Own Our Shares (Item 10.B.6 of Form 20-F)

See “Item 10 – Additional Information – Exchange Controls” in the annual report to which this exhibit is attached.

Provisions Affecting Any Change of Control (Item 10.B.7 of Form 20-F)

See “Item 10 – Additional Information – Memorandum and Articles of Association - Mandatory Public Tender Offer Upon Acquisition of 35% of Our Voting Shares” and “Item 10 – Additional Information – Memorandum and Articles of Association - Mandatory Public Tender Offer Upon Acquisition of 50% of Our Voting Shares” in the annual report to which this exhibit is attached.

Ownership Threshold (Item 10.B.8 of Form 20-F)

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.

Under Argentine law, any person acquiring 5% or more of the voting stock of a public company must inform the CNV in writing of the acquisition of such voting stock. Additionally, such person must inform

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the CNV in writing of each additional acquisition of 5% of the voting stock of that particular company, until such person acquires control of that company.

Differences Between the Law of Different Jurisdictions (Item 10.B.9 of Form 20-F)

Not applicable.

Changes in Our Capital (Item 10.B.10 of Form 20-F)

Not applicable.

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DESCRIPTION OF ADSs

Name of Depositary and address of its principal executive office (Item 12.D.1 of Form 20-F).

J.P. Morgan, will deliver the American Depositary Shares, also referred to as ADSs. The depositary’s office at which the ADRs will be administered is located at 4 New York Plaza, Floor 12 New York, New York 10004.

Description of ADS (item 12.D.2 of Form 20-F)

The following description of the ADSs and certain material provisions of our corporate rules is a summary and does not purport to be complete. It is subject to, and qualified in its entirety by the Deposit Agreement (as defined below), the form of ADS, which contain the terms of the ADSs, and any applicable law, as amended from time to time. In the following description, a “Holder” is the person registered with the Depositary (as defined below).

Copies of the Deposit Agreement are available for inspection at the offices of our Depositary. We encourage you to read the Deposit Agreement (defined below), the ADS form and the applicable sections of our annual report for additional information.

Each ADS will represent 25 common shares (or a right to receive 25 common shares) deposited with the principal Buenos Aires office of Banco Santander Rio S.A., as custodian for the depositary in Argentina. Each ADS will also represent any other securities, cash or other property which may be held by the depositary.

Dividends and Other Distributions

The depositary has agreed to pay to the Holders the cash dividends or other distributions it or the custodian receives on common shares or other deposited securities, after deducting its fees and expenses. The Holders will receive these distributions in proportion to the number of common shares their ADSs represent.

·      Cash. The depositary will distribute any U.S. dollars available to it resulting from a cash dividend or other cash distribution or the net proceeds of sales of any other distribution or portion thereof (to the extent applicable), on an averaged or other practicable basis, subject to (i) appropriate adjustments for taxes withheld, (ii) such distribution being impermissible or impracticable with respect to certain ADR holders, and (iii) deduction of the depositary’s and/or its agents’ fees and expenses in (1) converting any cash received in foreign currency into U.S. dollars by sale or in such other manner as the depositary may determine to the extent that it determines that such conversion may be made on a reasonable basis, (2) transferring foreign currency or U.S. dollars to the United States by such means as the depositary may determine to the extent that it determines that such transfer may be made on a reasonable basis, (3) obtaining any approval or license of any governmental authority required for such conversion or transfer, which is obtainable at a reasonable cost and within a reasonable time and (4) making any sale by public or private means in any commercially reasonable manner.

·      Common Shares. In the case of a distribution in shares, the depositary will issue additional ADRs to evidence the number of ADSs representing such shares. Only whole ADSs will be issued. Any shares which would result in fractional ADSs will be sold and the net proceeds will be distributed

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in the same manner as cash to the ADR holders entitled thereto. Any fees, taxes and/or charges owing in connection with a common or preferred share distribution will be collected from and/or owing by registered holders of ADRs.

·      Rights. In the case of a distribution of rights to subscribe for additional shares or other rights, if we timely provide evidence satisfactory to the depositary that it may lawfully distribute such rights, the depositary will distribute warrants or other instruments in the discretion of the depositary representing such rights. However, if we do not timely furnish such evidence, the depositary may: (i) sell such rights if practicable and distribute the net proceeds in the same manner as cash to the ADR holders entitled thereto; or (ii) if it is not practicable to sell such rights by reason of the non-transferability of the rights, limited markets therefor, their short duration or otherwise, do nothing, in which case ADR holders will receive nothing and the rights may lapse.

·      Other Distributions. The depositary will send to the ADR holders any other securities or property we distribute on deposited securities by any means it thinks is equitable and practical. If it cannot make the distribution in that way, the depositary has a choice. It may decide to sell what we distributed and distribute the net proceeds, in the same way as it does with cash. The depositary may sell a portion of the distributed securities or property sufficient to pay any taxes or its fees and expenses in connection with that distribution.

The depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADS holders. We have no obligation to register ADSs, common shares, rights or other securities under the Securities Act. We also have no obligation to take any other action to permit the distribution of ADSs, common shares, rights or anything else to ADS holders. This means that ADS holders may not receive the distributions we make on our common shares or any value for them if it is illegal or impractical for us to make them available to them.

Withdrawal and Transfer

The holders have the right to surrender their ADRs and withdraw the underlying common shares at any time except:

·    when temporary delays arise because: the depositary has closed its transfer books or we have closed our transfer books; the transfer of common shares is blocked to permit voting at a shareholders’ meeting; or we are paying a dividend on our common shares;

·    when the holder owes money to pay fees, taxes and similar charges; or

·    when it is necessary to prohibit withdrawals in order to comply with any laws or governmental regulations that apply to ADRs or to the withdrawal of common shares or other deposited securities.

This right of withdrawal may not be limited by any other provision of the deposit agreement.

Title to the ADR (and to the Deposited Securities represented by the ADSs evidenced hereby), when properly endorsed (in the case of ADRs in certificated form) or upon delivery to the Depositary of proper instruments of transfer, is transferable by delivery with the same effect as in the case of negotiable instruments under the laws of the State of New York. Prior to the transfer of the ADR, the Company, the Depositary or the Custodian may require: (a) payment with respect thereto of (i) any stock transfer or other tax or other governmental charge, (ii) any stock transfer or registration fees in effect for the registration of

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transfers of Shares or other Deposited Securities upon any applicable register and (iii) any applicable charges as provided in paragraph (7) of the ADR form; (b) the production of proof satisfactory to it of (i) the identity of any signatory and genuineness of any signature and (ii) such other information, including without limitation, information as to citizenship, residence, exchange control approval, beneficial ownership of any securities, compliance with applicable law, regulations, provisions of or governing Deposited Securities and terms of the Deposit Agreement and the ADR, as it may deem necessary or proper; and (c) compliance with such regulations as the Depositary may establish consistent with the Deposit Agreement or as the Depositary reasonably believes are required in order to enable compliance with applicable laws, rules and regulations, including, without limitation, those of the Central Bank, BCBA and the CNV.

Voting Rights

Holders exercise the voting rights by providing instructions to the depositary through proxy voting cards. Holders may instruct the depositary to vote the common shares underlying their ADSs. As soon as practicable after receiving notice from us of any meeting at which the holders of shares are entitled to vote, or of our solicitation of consents or proxies from holders of shares, the depositary will notify the holder of the upcoming vote and arrange to deliver our voting materials to the holder. The materials will describe the matters to be voted on and explain how the holder may instruct the depositary to vote the common shares or other deposited securities underlying its ADSs as the holder directs by a specified date. For instructions to be valid, the depositary must receive them on or before the date specified. The depositary will try, as far as practical, subject to Argentine law and the provisions of our by-laws, to vote or to have its agents vote the common shares or other deposited securities as the holder instructs. Otherwise, the holder will not be able to exercise its right to vote unless the holder withdraws the common shares. However, the holder may not know about the meeting far enough in advance to withdraw the common shares. We will use our best efforts to request that the depositary notify the holder of upcoming votes, ask for the holder’s instructions and an indication whether or not each resolution to be voted upon has been proposed by the board of directors of the Company, not less than 30 days prior to the meeting date.

If the depositary does not receive voting instructions from the holder by the specified date, it will consider that the holder has authorized and directed it to vote the number of deposited securities represented by its ADSs in favor of all resolutions proposed by our board of directors or, in the case of a resolution not proposed by our board of directors, in the same manner as the majority of all other votes cast at the meeting in respect of that resolution.

Amendment and Termination

We may agree with the depositary to amend the deposit agreement and the ADSs without ADS holders’ consent for any reason. If an amendment adds or increases fees or charges, except for taxes and other governmental charges or expenses of the depositary for registration fees, facsimile costs, delivery charges or similar items, or prejudices a substantial right of ADS holders, it will not become effective for outstanding ADSs until 30 days after the depositary notifies ADS holders of the amendment. At the time an amendment becomes effective, the holders are considered, by continuing to hold their ADS, to agree to the amendment and to be bound by the ADSs and the deposit agreement as amended.

The depositary will terminate the deposit agreement if we ask it to do so. The depositary may also terminate the deposit agreement if the depositary has told us that it would like to resign and we have not appointed a new depositary bank within 60 days. In either case, the depositary must notify the holder at least 45 days before termination.

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After termination, the depositary and its agents will do the following under the deposit agreement but nothing else:

·      receive and hold (or sell) distributions on Deposited Securities and advise the holders that the deposit agreement is terminated,

·      deliver Deposited Securities being withdrawn.

Six months or more after termination, the depositary may sell any remaining deposited securities by public or private sale. After that, the depositary will hold the money it received on the sale, as well as any other cash it is holding under the deposit agreement for the pro rata benefit of the ADS holders that have not surrendered their ADSs. It will not invest the money and has no liability for interest. The depositary’s only obligations will be to account for the money and other cash. After termination, our only obligations will be to indemnify the depositary and to pay fees and expenses of the depositary that we agreed to pay.

Limitations on Obligations and Liability

The Deposit Agreement expressly limits the obligations and liability of the depositary, ourselves and each of our and the depositary’s respective agents, provided, however, that no provision of the Deposit Agreement is intended to constitute a waiver or limitation of any rights which ADR holders or beneficial owners of ADSs may have under the Securities Act of 1933 or the Exchange Act, to the extent applicable. In the Deposit Agreement it provides that we, the depositary and any such agent:

·   are not liable if either of us is prevented or delayed by law or circumstances beyond our control from performing our obligations under the deposit agreement;

·   are not liable if either of us exercises discretion permitted under the deposit agreement;

·   are only obligated to take the actions specifically set forth in the deposit agreement without negligence or bad faith;

·    have no obligation to become involved in a lawsuit or other proceeding related to the ADRs or the deposit agreement on the holder’s behalf or on behalf of any other person;

·    are not liable for the acts or omissions of any securities depository, clearing agency or settlement system; and

·     may rely upon any documents we believe in good faith to be genuine and to have been signed or presented by the proper party; or

·    are not liable for the inability of any ADR holder or beneficial owner of ADSs to benefit from, or participate in, any distribution, offering, right or other benefit which is made available to holders of shares but is not made available to ADR holders.

In the deposit agreement, we and the depositary agree to indemnify each other under certain circumstances.

Requirements for Depositary Actions

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Before the depositary will deliver or register a transfer of ADSs, make a distribution on ADSs, or permit withdrawal of common shares or other property, the depositary may require:

·      payment of stock transfer or other taxes or other governmental charges and transfer or registration fees charged by third parties for the transfer of any common shares or other deposited securities;

·      satisfactory proof of the identity and genuineness of any signature or other information it deems necessary; and

·      compliance with regulations it may establish, from time to time, consistent with the deposit agreement, including presentation of transfer documents.

The depositary may refuse to deliver ADSs or register transfers of ADSs when the transfer books of the depositary or our transfer books are closed or at any time if the depositary or we think it advisable to do so.

Reports and Other Communications

Will ADR holders be able to view our reports?

The depositary will make available for inspection by ADR holders at the offices of the depositary and the custodian the deposit agreement, the provisions of or governing deposited securities, and any written communications from us which are both received by the custodian or its nominee as a holder of deposited securities and made generally available to the holders of deposited securities.

Additionally, if we make any written communications generally available to holders of our shares, and we furnish copies thereof (or English translations or summaries) to the depositary, it will distribute the same to ADR holders.

Books of Depositary

The depositary will maintain in New York facilities for the delivery and surrender of ADSs. The ADS register may be closed from time to time when deemed expedient by the depositary or requested by us.

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EX-8.1

EXHIBIT 8.1

LIST OF SUBSIDIARIES, JOINT VENTURES AND ASSOCIATES OF PAMPA ENERGÍA S.A.

		12.31.2022
Subsidiaries	Country	Direct and indirect participation %
Autotrol Renovables S.A.	Argentina	100%
Comercializadora e Inversora S.A.  (former Pampa Comercializadora S.A)	Argentina	100%
Enecor S.A.	Argentina	70%
Energía e Inversiones S.A.	Uruguay	100%
Energía Operaciones ENOPSA S.A.	Ecuador	100%
Generación Argentina SAU	Argentina	100%
Greenwind S.A.	Argentina	100%
Hidroeléctrica Diamante S.A.	Argentina	61%
Hidroeléctrica Los Nihuiles S.A.	Argentina	52.04%
Pampa Bloque18 S.A.	Ecuador	100%
Pampa Ecuador Inc	Nevis	100%
Pampa Energía Bolivia S.A.	Bolivia	100%
Pampa Inversiones S.A.	Uruguay	100%
PE Energía Ecuador LTD	Grand Cayman	100%
Petrolera San Carlos S.A.	Venezuela	100%
Vientos de Arauco Renovables S.A.U.	Argentina	100%
Vientos Solutions S.A.U.	Argentina	100%
Vientos Solutions S.L.U.	España	100%
2) Joint Ventures
Citelec S.A.	Argentina	50%
Compañía de Inversiones de Energía S.A. (CIESA)	Argentina	50%
CT Barragán S.A. (former Parques Eólicos Argentinos S.A.)	Argentina	50%
Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires S.A. (Transba) (2)	Argentina	26.33%
Compañía de Transporte de Energía Eléctrica en Alta Tensión S.A. (Transener) (2)	Argentina	26.33%
Transportadora Gas del Sur S.A. (TGS)(3)	Argentina	29.264%
(2) Through a 50% interest, the company joint controls Citelec, company that controlled Transener with 52.65% of the shares and votes. As a result, the Company has an indirect participation of 26.33% in Transener. (3) The Company holds a direct and indirect interest of 3.764% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, the Company holds a direct and indirect participation of 29.264% in TGS.
3) Associates
Oleoducto de Crudos Pesados S.A.	Ecuador	15.91%
Oleoductos del Valle S.A.	Argentina	2.10%

EX-12.1

Exhibit 12.1

Chief Executive Officer Certification

I, Gustavo Mariani, certify that:

1. I have reviewed this annual report on Form 20-F of Pampa Energía S.A.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 28, 2023.

/s/ Gustavo Mariani

Chief Executive Officer

EX-12.2

Exhibit 12.2

Chief Financial Officer Certification

I, Nicolás Mindlin, certify that:

1. I have reviewed this annual report on Form 20 - F of Pampa Energía S.A.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 28, 2023.

/s/ Nicolás Mindlin

Chief Financial Officer

EX-13.1

Exhibit 13.1

Officer Certifications Pursuant to Section 906

of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Pampa Energía S.A., a sociedad anónima organized under the laws of Argentina (the “Company”), does hereby certify to such officer’s knowledge that:

The annual report on Form 20-F for the fiscal year ended December 31, 2022 (the “Form 20-F”) of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Form 20-F fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 28, 2023

	/s/ Gustavo Mariani
	Title: Chief Executive Officer
Date: April 28, 2023
	/s/ Nicolás Mindlin
	Title: Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-13.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EX-13.3

 

XML

Cover	12 Months Ended
	Dec. 31, 2022 shares
Entity Addresses [Line Items]
Document Type	20-F
Amendment Flag	false
Document Registration Statement	false
Document Annual Report	true
Document Transition Report	false
Document Shell Company Report	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
Current Fiscal Year End Date	--12-31
Entity File Number	001-34429
Entity Registrant Name	Pampa Energy Inc.
Entity Central Index Key	0001469395
Entity Incorporation, State or Country Code	C1
Entity Address, Address Line One	Maipú 1
Entity Address, City or Town	Buenos Aires
Entity Address, Country	AR
Entity Address, Postal Zip Code	C1084ABA
Title of 12(b) Security	Common Stock
Trading Symbol	PAM
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Document Accounting Standard	International Financial Reporting Standards
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	1,379,765,666
ICFR Auditor Attestation Flag	true
Auditor Firm ID	1349
Auditor Name	PRICE WATERHOUSE & CO. S.R.L.
Auditor Location	Buenos Aires
Business Contact [Member]
Entity Addresses [Line Items]
Entity Address, Address Line One	Maipú 1
Entity Address, City or Town	Buenos Aires
Entity Address, Country	AR
Entity Address, Postal Zip Code	C1084ABA
City Area Code	+ 54 11
Local Phone Number	4344 6000
Contact Personnel Name	María Carolina Sigwald
Contact Personnel Fax Number	54 11 4344 6473

XML

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Profit or loss [abstract]
Revenue	$ 1,829	$ 1,508	$ 1,073
Cost of sales	(1,148)	(955)	(663)
Gross profit	681	553	410
Selling expenses	(56)	(33)	(26)
Administrative expenses	(138)	(99)	(93)
Other operating income	131	105	51
Other operating expenses	(46)	(58)	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(38)	(4)	(139)
Impairment of financial assets	(8)	(2)	(9)
Share of profit from associates and joint ventures	105	117	85
Operating income	631	579	243
Financial income	5	10	9
Financial costs	(221)	(185)	(177)
Other financial results	166	(14)	84
Financial results, net	(50)	(189)	(84)
Profit before income tax	581	390	159
Income tax	(124)	(77)	(35)
Profit of the year from continuing operations	457	313	124
Loss of the year from discontinued operations		(75)	(592)
Total income (loss) of the year	457	238	(468)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans	(9)	(3)	1
Income tax	3	1
Exchange differences on translation	21	22	(5)
Items that may be reclassified to profit or loss
Exchange differences on translation	39	70	(3)
Other comprehensive income (loss) of the year from continuing operations	54	90	(7)
Other comprehensive income (loss) of the year from discontinued operations		64	(33)
Other comprehensive income (loss) of the year	54	154	(40)
Total comprehensive income of the year	511	392	(508)
Total income (loss) of the year attributable to:
Owners of the company	456	273	(367)
Non-controlling interest	1	(35)	(101)
Total income (loss) of the year attributable to owners of the Company:
Continuing operations	456	312	132
Discontinued operations		(39)	(499)
Total income of the year attributable to owners of the company	456	273	(367)
Total comprehensive income (loss) of the year attributable to:
Owners of the Company	510	393	(393)
Non-controlling interest	1	(1)	(115)
Total comprehensive income (loss) of the year attributable to owners of the Company:
Continuing operations	510	402	124
Discontinued operations		(9)	(517)
Total comprehensive income (loss) of the year attributable to owners of the company	$ 510	$ 393	$ (393)
Earnings (Loss) per share attributable to equity holders of the Company
Basic and diluted earnings per share from continuing operations	$ 0.33	$ 0.22	$ 0.08
Basic and diluted loss per share from discontinued operations		(0.03)	(0.32)
Total basic and diluted earning (loss) per share	$ 0.33	$ 0.19	$ (0.23)

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CONSOLIDATED STATEMENT OF FINANCIAL POSITION - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
NON-CURRENT ASSETS
Property, plant and equipment		$ 2,164	$ 1,659
Intangible assets		138	38
Right-of-use assets		9	12
Deferred tax asset		36	84
Investments in associates and joint ventures		902	774
Financial assets at amortized cost		102	105
Financial assets at fair value through profit and loss		27	29
Other assets		1	1
Trade and other receivables		20	34
Total non-current assets		3,399	2,736
CURRENT ASSETS
Inventories	[1]	173	155
Financial assets at amortized cost		8	5
Financial assets at fair value through profit and loss		586	458
Trade and other receivables		470	397
Cash and cash equivalents		106	110
Total current assets		1,343	1,125
Total assets		4,742	3,861
SHAREHOLDERS´ EQUITY
Share capital		36	36
Share capital adjustment		191	191
Share premium		516	516
Treasury shares adjustment		1	1
Treasury shares cost		(23)	(7)
Legal reserve		45	61
Voluntary reserve		968	659
Other reserves		(15)	(15)
Other comprehensive income		81	48
Retained earnings		477	295
Equity attributable to owners of the company		2,277	1,785
Non-controlling interest		7	6
Total equity		2,284	1,791
NON-CURRENT LIABILITIES
Investments in joint ventures			4
Provisions		147	141
Income tax and minimum notional income tax provision		179	188
Deferred tax liability		112
Defined benefit plans		28	24
Borrowings		1,340	1,359
Trade and other payables		21	12
Total non-current liabilities		1,827	1,728
CURRENT LIABILITIES
Provisions		4	5
Income tax liability		5	20
Tax liabilities		28	23
Defined benefit plans		6	5
Salaries and social security payable		32	28
Derivative financial instruments		2
Borrowings		273	79
Trade and other payables		281	182
Total current liabilities		631	342
Total liabilities		2,458	2,070
Total liabilities and equity		$ 4,742	$ 3,861

[1] It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Millions	Issued capital [member]	Issued Capital Adjustment [Member]	Share premium [member]	Treasury shares [member]	Treasury Shares Adjustment [Member]	Treasury Shares Cost [Member]	Statutory reserve [member]	Voluntary Reserve [Member]	Other reserves [member]	Accumulated other comprehensive income [member]	Retained earnings [member]	Equity Subtotal [Member]	Non-controlling interests [member]	Total
Beginning balance, value at Dec. 31, 2019	$ 46	$ 260	$ 510	$ 1	$ 1	$ (44)	$ 42	$ 422	$ (18)	$ (29)	$ 726	$ 1,917	$ 492	$ 2,409
IfrsStatementLineItems [Line Items]
Legal and voluntary reserve constitution							19	707			(726)
Capital reduction				(9)	(59)	140		(72)					(19)	(19)
Treasury shares acquisition	(8)	(59)	6	8	59	(102)						(96)	(8)	(104)
Dividens ditribution													(9)	(9)
Profit of the year											(367)	(367)	(101)	(468)
Other comprehensive income of the year										(21)	(5)	(26)	(14)	(40)
Ending balance, value at Dec. 31, 2020	38	201	516		1	(6)	61	1,057	(18)	(50)	(372)	1,428	341	1,769
IfrsStatementLineItems [Line Items]
Legal and voluntary reserve constitution								(372)			372
Capital reduction				(2)	(10)	38		(26)
Treasury shares acquisition	(2)	(10)		2	10	(39)						(39)		(39)
Stock compensation plans									3			3		3
Sale of subsidiary													(334)	(334)
Profit of the year											273	273	(35)	238
Other comprehensive income of the year										98	22	120	34	154
Ending balance, value at Dec. 31, 2021	36	191	516		1	(7)	61	659	(15)	48	295	1,785	6	1,791
IfrsStatementLineItems [Line Items]
Legal and voluntary reserve constitution							(16)	311			(295)
Capital reduction						2		(2)
Treasury shares acquisition						(18)						(18)		(18)
Profit of the year											456	456	1	457
Other comprehensive income of the year										33	21	54		54
Ending balance, value at Dec. 31, 2022	$ 36	$ 191	$ 516		$ 1	$ (23)	$ 45	$ 968	$ (15)	$ 81	$ 477	$ 2,277	$ 7	$ 2,284

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CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Profit of the year from continuing operations	$ 457	$ 313	$ 124
Adjustments to reconcile net profit to cash flows from operating activities:	307	365	380
Changes in operating assets and liabilities	(145)	(65)	(22)
Net cash generated by operating activities from discontinued operations		116	211
Net cash generated by operating activities	619	729	693
Cash flows from investing activities:
Payment for property, plant and equipment acquisitions	(416)	(206)	(124)
Payment for intangible assets acquisitions	(31)	(4)
Payment for public securities and shares acquisitions, net	(102)	(234)	(151)
(Subscription) Recovery of mutual funds, net	(1)	52	93
Payment for the acquisition of subsidiaries and associates	(111)	(17)	(3)
Early collection for sale of subsidiary			5
Collection for equity interests in companies sales	44	51
Collections for intangible assets sales	21	6	1
Dividends received	10	18	3
Collection of loans	11	26	7
Net cash used in investing activities from discontinued operations		(166)	(86)
Net cash used in investing activities	(575)	(474)	(255)
Cash flows from financing activities:
Proceeds from borrowings	308	188	353
Payment of  borrowings	(143)	(336)	(291)
Payment of  borrowings interests	(162)	(140)	(190)
Payment for treasury shares acquisition	(18)	(39)	(104)
Repurchase and redemption of corporate bonds	(28)	(3)	(110)
Payments of leases	(3)	(5)	(2)
Payments of dividends			(9)
Payments to third parties for capital reduction of subsidiaries			(19)
Net cash used in financing activities from discontinued operations		(7)	(73)
Net cash used in financing activities	(46)	(342)	(445)
Decrease in cash and cash equivalents	(2)	(87)	(7)
Cash and cash equivalents at the beginning of the year	110	141	225
Cash and cash equivalents at the beginning of the year reclasified to assets classified as held for sale		52
Exchange difference generated by cash and cash equivalents	(2)	4	(25)
Cash and cash equivalents at the end of the year reclasified to assets classified as held for sale			(52)
Decrease in cash and cash equivalents	(2)	(87)	(7)
Cash and cash equivalents at the end of the year	$ 106	$ 110	$ 141

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GENERAL INFORMATION

12 Months Ended

Dec. 31, 2022

General Information

GENERAL INFORMATION

NOTE 1: GENERAL INFORMATION

1.1 General information of the Company

The Company is a fully integrated power company in Argentina, which directly and through its subsidiaries, participates in the electric energy and gas value chains.

In the generation segment, the Company, directly and through its subsidiaries and joint ventures, has a 5,088 MW installed capacity as of December 31, 2022, which represents approximately 12% of Argentina’s installed capacity, and being one of the four largest independent generators in the country. Additionally, the Company is currently undergoing a process to expand its installed capacity by an additional 437.5 MW.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, with operations in 13 production areas and 5 exploratory areas reaching a production level of 9.8 million m3/day of natural gas and 5.3 thousand boe/day of oil in Argentina, as of December 31, 2022. Its main natural gas production blocks are located in the Provinces of Neuquén and Río Negro.

In the petrochemicals segment, operations are located in Argentina, where the Company operates 2 high-complexity plants producing styrene, synthetic rubber and polystyrene, with a domestic market share ranging between 94% and 100%.

Finally, through the holding and others segment, the Company participates in the electricity transmission and oil 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 21,697 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 9,233 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. Besides, the Company owns a 30.1% indirect interest in OCP, licensee company of an oil pipeline in Ecuador that has a transportation capacity of 450 thousand barrels/day. Additionally, the segment includes advisory services provided to related companies.

1.2 Economic context

The Company operates in a complex economic context which main variables experience volatility as a result of political and economic events both in the domestic and international spheres.

At the domestic level, in the first quarter of 2022 Argentina and the International Monetary Fund reached an agreement defining tax and monetary goals for the country and agreeing on the refinancing of debt maturities. However, monthly inflation levels and depreciation of the peso against the U.S. dollar have remained high, and exchange restrictions have remained in force and even tightened (see Note 2.5), continuing to affect the foreign currency value.

At the international level, Russia’s invasion to Ukraine in early 2022 entailed an important global destabilization factor, which mainly resulted in lower growth expectations and increased inflation due to increased prices of food and energy (mainly oil and natural gas).

The increase in international energy prices may adversely affect Argentina’s fiscal balance. In this respect, it is worth highlighting that the Argentine Government, aiming to substitute fuel imports and strengthen the domestic supply, has promoted a project of the construction of the Néstor Kirchner Gas Pipeline, which would allow for increasing transportation capacity by 24 million cubic meters of gas per day through the installation and mounting of a total 1,020 km pipeline, in two stages: the first one, providing for the construction of 553 kilometers to supply the Buenos Aires metropolitan area, and the second, for the construction of 467 additional kilometers to supply large urban centers in central and northern Argentina with unconventional gas generated in the Vaca Muerta block, in the Province of Neuquén. In 2022, ENARSA tendered and awarded the different tranches making up the first stage of the gas pipeline to the companies in charge of its construction, with an estimated US$ 1,500 million cost to be financed with national treasury funds and the wealthiest segment’s solidarity contribution. As of the issuance of these Consolidated Financial Statements, the first construction stage is underway, and commissioning is expected for June 2023 —concurrently with the peak winter demand, with an associated transportation capacity of 11 million cubic meters of gas per day. In addition to the original scheme, ENARSA decided to incorporate the construction and installation of two turbochargers that would allow for increasing capacity to 20 million cubic meters of gas per day for the first stage. In parallel, the Government announced the extension of Gas Plan (see Note 2.2.4.1.2) to provide producing companies with the incentives and terms necessary to make investments allowing for the gas production increase required to inject and fill the pipeline from June 2023.

Regarding the energy industry, the sustained inflation increase and increased political-economic uncertainty have affected the electricity distribution company’s payment chain, added to deferrals in the National Treasury contributions, as a result of which CAMMESA has recorded delays in payment terms to generators and hydrocarbon producers exceeding 90 days in August 2022. Moreover, on June 16, 2022, PEN Executive Order No. 332/22 established a subsidies segmentation system for electricity and natural gas utility residential customers. Under it, the Argentine Government, which currently covers an average of 70% of the cost of energy, has launched an initiative to reach fairer and more reasonable tariffs with a subsidies reduction and distribution scheme based on each household’s economic capacity, providing that the highest-income segment should verify a gradual subsidies’ reduction until fully covering the cost of energy by the end of 2022.

The Argentine economy registered a cumulative growth of 6.4% and 10.8% in the Gross Domestic Product in the third quarter of 2022 and 2021, respectively, a 94.8% and 50.9% cumulative inflation (CPI) for fiscal years 2022 and 2021, respectively, and a 72.5% and 22.1% depreciation of the peso against the U.S. dollar for 2022 and 2021, respectively, according to BNA’s exchange rate.

The context of volatility and uncertainty continues as of the date of issuance of these Consolidated Financial Statements.

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 financial statements should be read in the light of these circumstances.

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REGULATORY FRAMEWORK

12 Months Ended

Dec. 31, 2022

Regulatory Framework

REGULATORY FRAMEWORK

NOTE 2: REGULATORY FRAMEWORK

2.1 Generation

2.1.1 Generation units

The Company’s revenues related to this segment come from: i) sales contracts with large users within the MAT (Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SE Resolution No. 31/20 as from February 2020, SE Resolution No. 440/21 as from February 2021, SE Resolution No. 238/22 as from February 2022 and SE Resolution No. 826/22 as from September 2022). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:

In operation as of 12.31.2022:
Generator	Generating unit	Tecnology	Power	Applicable regime (1)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1,281/06
CTG	GUEMTV11	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV12	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV13	TV	>100 MW	Resolution No. 826/22
Piquirenda	PIQIDI 01-10	MCI	30 MW	Resolution No. 826/22
CPB	BBLATV29	TV	>100 MW	Resolution No. 826/22
CPB	BBLATV30	TV	>100 MW	Resolution No. 826/22
CT Ing. White	BBLMD01-06	MCI	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	>150 MW	Resolution No. 826/22
CTLL	LDLATG04	TG	105 MW	Res. No 220/07 (75%)
CTLL	LDLATG05	TG	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	MCI	15 MW	Resolution No. 826/22
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	Resolution No. 826/22
CTGEBA	GEBATG03	TG	169 MW	Energy Plus Res. No. 1,281/06
CTGEBA	GEBATG03/TG04/TV02	CC	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	14 MW	Energy Plus Res. N° 1,281/06
CT Parque Pilar	PILBD01-06	MCI	100 MW	Resolution No. 21/16
CTB	EBARTG01 - TG02	TG	>50 MW	Resolution No. 826/22 (2)
HIDISA	AGUA DEL TORO	HI	HI – Media 120<P≤300	Resolution No. 826/22
HIDISA	EL TIGRE	HR	Renewable  ≤ 50	Resolution No. 826/22
HIDISA	LOS REYUNOS	HB	HB – Media 120<P≤300	Resolution No. 826/22
HINISA	NIHUIL I - II - III	HI	HI – Small  50<P≤120	Resolution No. 826/22
HPPL	PPLEHI	HI	HI – Media 120<P≤300	Resolution No. 826/22
P.E. M. Cebreiro	CORTEO	Wind	100 MW	Renovar
PEPE II	PAMEEO	Wind	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	53 MW	MATER Res. No. 281/17
PEPE IV	BAHIEO	Wind	18 MW	MATER Res. No. 281/17
PE Arauco	AR21EO	Wind	99.75 MW	Renovar

⁽¹⁾ Surplus power capacity and energy are remunerated in the spot market. 

⁽²⁾ During the month of April 2022 the contract under Resolution No. 220/07 of CTB have ended, since then, power and energy have been remunerated in the spot market.

In construction:
Generator	Tecnology	Capacity	Applicable regime
CTB	CC	280 MW	Resolution No. 220/07
PEPE IV	Wind	63 MW	MATER Res. No. 281/17
PEPE VI	Wind	94.5 MW	MATER Res. No. 281/17

2.1.2 Sales contracts with large users within the MAT

2.1.2.1 Energy Plus

Aiming to encourage new generation works, in 2006, the SE approved Resolution No. 1,281/06 in which established a specific regime which remunerates newly installed generation sold to a certain category of Large Users at higher prices.

The Energy Plus service consists of the offer of additional generation availability by generators, co-generators and self-generators which, as of the date of publication of SE Resolution No. 1,281/06, were not WEM agents or did not have facilities or an interconnection with the WEM. Considering that:

- These plants should have fuel supply and transportation facilities;

- The energy used by GU300 in excess of the base demand (energy consumption for 2005 year) qualifies for Energy Plus agreements within the MAT at a price negotiated between the parties; and

- For new GU300 entering the system, their base demand will equal zero.

If a generator cannot meet the power demand by an Energy Plus customer, it should purchase that power in the market at the operated marginal cost, or, alternatively, support the committed demand in case of unavailability through agreements with other Energía Plus generators.

Currently, the Company has Power Availability agreements in force with other generators whereby, in case of unavailability, it may purchase or sell power to support the contracts mutually.

Furthermore, the SE, through Note No. 567/07, as amended, established that GU300 not purchasing their surplus demand in the MAT should pay the Average Incremental Charge of Surplus Demand (“CMIDE”). As from the month of June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $1,200/MWh or the temporary dispatch surcharge.

Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 283 MW. The values of Energy Plus contracts are mostly denominated in U.S. dollars.

2.1.2.2 Renewable Energy Term Market (“MATER” Regime)

Pursuant to Resolution No. 281/17, the MEyM regulated the MATER Regime with the purpose of setting the conditions for large users within the WEM and WEM distributing agents’ large users covered by Section 9 of Law No. 27,191 to meet their demand supply obligation from renewable sources through the individual purchase within the MATER from renewable sources or self-generation from renewable sources.

Projects destined to the supply of electric power from renewable sources under the MATER Regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy is sold in the spot market.

Finally, contracts executed under the MATER Regime are administered and managed in accordance with the WEM procedures. The contractual terms —life, allocation priorities, prices and other conditions, notwithstanding the maximum price set forth in Section 9 of Law No. 27,191— are freely agreed between the parties, although the committed electricity volumes are limited by the electric power from renewable sources produced by the generator or supplied by other generators or suppliers with which it has purchase agreements in place.

Resolution No. 370/22 was passed on May 16, 2022, which expanded the MATER system allowing for the sale of renewable energy under this system to meet the GUDI and distribution utility company’s demand.

Under this resolution, the Company, through its PEPE II, III and IV wind farms, sells energy for up to 124 MW. Additionally, the Company has started selling third-party generators’ renewable energy for an approximate volume of 2 MW.

After the fiscal year closing, took place the commissioning of 4 additional wind turbines with an incremental capacity of 18 MW. For further information regarding PEPE IV project, see Note 17.1.

2.1.2.3 MATER dispatch priority

SE Resolution No. 551/21 published on June 16, 2021 modified the dispatch priority maintenance system established by Resolution No. 281/17. Overall, it replaces the granting of a security for the maintenance of the dispatch priority by the payment of a quarterly installment of US$ 500/MW until commissioning within the declared term or a maximum term of 24 months as from the priority assignment. It also established certain conditions for obtaining an extension in the committed commissioning date, which, according to the project development level and the requested extension term, requires a payment between 500 and 1,500 US$/MW/month.

Additionally, it allows projects with an assigned dispatch priority but not yet commissioned to continue their execution keeping the dispatch priority, or to waive such priority, thus releasing the transmission capacity.

The Company, as owner of the Wind Farm project, located in Las Armas, Province of Buenos Aires, notified its decision to waive the timely granted dispatch priority, and recovered the security it had provided. As a result, CAMMESA notified that the already initiated execution of the security was determined to be moot as it had no further claim against the Company; therefore, as of September 30, 2021, the amount of US$ 12.5 million recorded for to such effect was recovered and disclosed under the item “Other operating income” of the Consolidated Statement of Comprehensive Income.

Under the MATER calls for tenders for the third quarter of 2021 and 2022, the Company was awarded a 36 MW and 41 MW dispatch priority, respectively, for the expansion of the PEPE III wind farm. For further information on the extension project aforementioned, see Note 17.1.

2.1.3 Supply Agreements with CAMMESA

2.1.3.1 SE Resolution No. 220/07

Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into 220 Agreement with WEM Generating Agents for the energy produced with new equipment. These will be long-term agreements and the price payable by CAMMESA should compensate for the investments made by the agent at a rate of return to be accepted by the SE.

Within the framework of this resolution, the Company has remunerated units under 220 agreements for 79 MW and 280 MW, through Loma la Lata thermal power plant and as from the closing to combined cycle’s commissioning at Ensenada de Barragán thermal power plant, owned by CTB, respectively (see Note 5.2.3).

2.1.3.2 SE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector, on March 22, 2016, the SE issued Resolution No. 21/16 calling for parties interested in offering new thermal power generation capacity with the commitment to making it available through the WEM for the 2016/2017 summer, 2017 winter, and 2017/2018 summer periods.

For the awarded projects, wholesale power purchase agreements were entered into with CAMMESA for a term of 10 years, with a remuneration made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if appropriate), less penalties and fuel surpluses. Surplus power capacity is sold in the spot market.

Pursuant to this resolution, the Company, through its Loma de la Lata, Ingeniero White and Pilar thermal power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW.

2.1.3.3 SE Resolution No. 287/17

On May 10, 2017 the SE issued Resolution No. 287/17 launching a call for tenders 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 with natural gas and 1,820 kcal/kWh with alternative liquid fuels), and the new capacity should not exceed the existing electric power transmission capacity; otherwise, the cost of the necessary extensions will be borne by the bidder.

Pursuant to this regulation, the Company, through its Genelba thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years.

2.1.3.4 Renovar Programs

In order to meet the objectives, set by Law No. 26,190 and Law No. 27,191 promoting the use of renewable sources of energy, the MEyM called for open rounds for the hiring of electric power from renewable sources (Renovar Programs, Rounds 1, 1.5 and 2) within the WEM. These calls aimed to assign power capacity contracts from different technologies (wind energy, solar energy, biomass, biogas and small hydraulic developments with a power capacity of up to 50 MW).

For the awarded projects, renewable electric power supply agreements were executed for the sale of an annual committed electric power block for a term of 20 years.

Additionally, several measures were established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, equipment’s accelerated depreciation in the income tax, import duty exemptions, etc.) and the creation of a fund for the development of renewable energies destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects.

On December 27, 2021, the SE passed Resolution No. 1,260/21 to address issues regarding the projects under the different Renovar rounds that did not meet committed commissioning terms. Upon satisfaction of certain conditions, the resolution gives project awardees the option to: i) terminate the current contract with CAMMESA against the payment of a sum of money; ii) amend the contract and extend the term for commissioning against a reduction in the contract price and term; iii) commission the project for a power capacity lower than that committed initially.

Under the Renovar programs, the Company, through Greenwind, has a supply contract in place with CAMMESA for a total of 100 MW, and in December 2022 it incorporated an additional 99.75 MW following the acquisition of Arauco wind farm (see Note 5.1.5).

2.1.3.5 RenMDI Call

SE Resolution No. 36/23 launched a national and international call for tenders to select renewable energy generation projects with a twofold objective: i) the substitution of forced generation (line 1) and ii) the diversification of the energy matrix (line 2). The tender form establishes the following maximum power capacities to be awarded: (i) 500 MW distributed among 6 regions for line 1 and (ii) 120 MW throughout the national territory for line 2. The projects under line 2 will have no priority over other renewable projects.

Projects will be remunerated under a supply agreement executed with CAMMESA for a term of 15 years from the project’s commissioning. Until commissioning, the tenderer will meet a payment scheme (an initial payment and quarterly payments), which will be allocated to a special account to be administered by CAMMESA through the the “Electricity Supply Transportation Works Fund” trust (“FOTAE”) for the transmission system’s expansion.

The tender submission deadline is April 27, 2023. As of the date of issuance of these Consolidated Financial Statements, Pampa is evaluating the possibility of participating in the call.

2.1.3.6 Remuneration for combined cycles

SE Resolution No. 59/23 dated February 7, 2023 established an opt-in system under which combined cycles’ owners could execute an availability and efficiency optimization agreement with CAMMESA. The agreement contemplates an availability commitment for 85% of the net power capacity for a maximum term of 5 years, and sets a US$ 2,000/Mw-month remuneration for the power capacity made available and the dollarization of the energy price based on the fuel used (US$ 3.5/MWh for natural gas and US$ 6.1/MWh for fuel oil and gas oil). Besides, it provides for a 35% and 15% reduction in the remuneration collectible for guaranteed power capacity for generators with availability commitments in the spot market for the summer-winter and autumn-spring periods, respectively.

The opt-in application form should be submitted to CAMMESA within a term of 90 calendar days. As of the date of issuance of these Consolidated Financial Statements, the Company is currently evaluating the resolution.

2.1.4 Remuneration at the Spot market

On February 27, 2020, SE Resolution No. 31/20 was published in the BO, applicable as from February 2020, established remunerative items based on technology and scale with prices in pesos and set an additional remuneration, in pesos, for the power capacity generated during the hours of maximum thermal demand of the month, taking into consideration the average power capacity generated by thermal generators and the average power capacity operated by hydroelectric generators.

Besides, SE Resolution No. 31/20 set a monthly remuneration update scheme with a factor contemplating a 60% CPI and 40% IPIM adjustment. However, on April 8, 2020, through Note No. 2020-24910606-APN-SE#MDP, the SE instructed CAMMESA to postpone the application of this automatic adjustment mechanism.

On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in spot generation remuneration values, and repealed the automatic adjustment mechanism established by SE Resolution No. 31/20.

In November 2021, SE Resolution No. 1,037/21, instrumented through Note NO-2021-108163338-APN-SE#ME, provided for an additional transitional remuneration for generated energy and suspended the application of the utilization factor for economic transactions comprised between September 1, 2021 and February 28, 2022.

On April 21, 2022, SE Resolution No. 238/22 was published in the BO. This resolution provided a 30% increase in spot generation remuneration values from the February 2022 economic transaction, and an additional 10% increase from the June 2022 economic transaction. It also abrogated the application of the utilization factor and the additional transitional remuneration set by SE Resolution No. 1,037/21.

On December 14, 2022, through SE Resolution No. 826/22, the spot remuneration values were modified considering the following increases: i) 20% from the September 2022 economic transaction; ii) 10% from the December 2022 economic transaction; iii) 25% from the February 2023 economic transaction; and iv) 28% from the August 2023 economic transaction.

Additionally, SE Resolution No. 826/22 replaced the remuneration scheme at hours of maximum thermal demand with a differentiated remuneration scheme at peak hours from the November 2022 economic transaction.

The applicable remunerations, based on technology and resolution, are detailed below. The amounts reported under SE Resolution No. 238/22 and SE Resolution No. 826/22 correspond to tariffs applicable from the June 2022 and December 2022 economic transactions, respectively.

2.1.4.1 Remuneration for Available Power Capacity

2.1.4.1.1 Thermal Power Generators

A minimum remuneration for power capacity based on technology and scale was established, and generating, co-generating and self-generating agents owning conventional thermal power plants were allowed to offer guaranteed availability commitments for the energy and power capacity generated by their units and not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA.

Availability commitments are tendered for quarterly periods: a) summer (December through February); b) winter (June through August) and c) ‘other,’ which comprises two quarters (March through May, and September through November), the thermal generators’ remuneration for committed power capacity being proportional to their compliance.

The minimum remuneration for generators with no availability commitments includes the following scales and prices:

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-month)	SE No. 826/22 ($ / MW-month)
Large CC Capacity > 150 MW	100,650	129,839	185,670	245,084
Large TV Capacity > 100 MW	143,550	185,180	264,807	349,546
Small TV Capacity ≤ 100 MW	171,600	221,364	316,551	417,847
Large GT Capacity > 50 MW	117,150	151,124	216,107	285,262

The remuneration for guaranteed power capacity to generators with availability commitments is:

Period	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No 238/22 ($ / MW-month)	SE No 826/22 ($ / MW-month)
Summer – Winter	360,000	464,400	664,092	876,601
Fall - Spring	270,000	348,300	498,069	657,451

In the case of thermal power plants with a power capacity equal to or lower than 42 MW in total, a differential remuneration was applied until its elimination on August 2022.

In the same way, a coefficient derived from the average utilization factor over the unit’s last twelve months was applied to the power capacity remuneration: with a minimum 70% of the utilization factor, 100% of the power capacity payment is collected; if the utilization is between 30% and 70%, the power capacity payment ranges from 70% to 100%; and if the utilization factor is lower than 30%, 70% of the power capacity payment was collected until January 2020 and 60% of the power capacity payment is collected as from February 2020. The application of this factor was suspended in 2021 and finally abrogated from February 2022 (see Note 2.1.4.3).

For the February 2020 to October 2022 period, an additional remuneration for the hours of maximum thermal requirement of the month (hmrt) was established, which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, applying the following prices to the average generated power:

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	45,000	22,500	58,050	29,025	83,012	41,506
Fall - Spring	7,500	-	9,675	-	13,835	-

2.1.4.1.2 Hydroelectric Generators

Power capacity availability is determined independently of the reservoir level, the contributions made, or the expenses incurred. Furthermore, in the case of pumping hydroelectric power plants, the operation as turbine and pump is considered to calculate availability.

The base remuneration includes the following scales and prices:

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-mes)	SE No. 826/22 ($ / MW-mes)
Medium HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Small HI Capacity > 50 ≤ 120 MW	181,500	234,135	334,813	441,953
Medium Pumped HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Renewable HI Capacity ≤ 50 MW	297,000	383,130	547,876	723,196

The payment for power capacity is determined by the actual capacity, hours of unavailability due to programmed and/or agreed maintenance are not computed for the calculation of the remuneration. However, to consider the incidence of programmed maintenance works in power plants, SME Note No. 46631495/19 provided for the application of a 1.05 factor over the power capacity payment.

In the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters.

Furthermore, for the February 2020 to October 2022 period, an additional remuneration was set for the hours of maximum thermal demand (hmrt), corresponding to the 50 hours with the largest dispatch of thermal generation in each month, divided into two blocks of 25 hours each:

Generation units > 50 MW and ≤ 300 MW

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	39,000	19,500	50,310	25,155	71,943	35,972
Fall - Spring	6,500	-	8,385	-	11,991	-

Generation units ≤ 50 MW

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	42,000	21,000	54,180	27,090	77,478	38,739
Fall – Spring	7,000	-	9,030	-	12,913	-

2.1.4.2 Remuneration for generated and operated energy

In the case of thermal power generators, a remuneration was set for generated energy, depending on the type of fuel used, and for operated energy, as shown below:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	Between 240 and 420	Between 310 and 542	Between 403 and 705	Between 585 and 1,023
Operated energy	84	108	154	204

It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognised at 60% of the installed net capacity, irrespective of the energy delivered by the unit.

In the case of hydroelectric plants, the following prices were established for generated and operated energy, irrespective of scale:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	210	271	388	512
Operated energy	84	108	154	204

The remuneration for operated energy should correspond with the grid’s optimal dispatch; however, the current resolution does not indicate which would be the consequence otherwise.

In the case of pumping hydroelectric power plants, both the generated energy and that used for pumping are considered. Besides, if it works as a synchronous condenser, 60 $/MVAr, and 77 $/MVAr, 110 $/MVAr and 145 $/MVAr are recognised under SE Resolution No. 31/20, and No. 440/21, No. 238/22 and No. 826/22, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy.

As from November 2022, a differentiated remuneration scheme applicable to thermal and hydroelectric generators for generated energy at peak hours, was established with a remuneration equivalent to twice the value of the generated energy’s current price at peak hours (18:00 to 23:00) every day in the months of December, January, February, June, July and August, and to one time that value for the same hours in the months of March, April, May, September, October and November.

As regards energy generated from unconventional sources, a single remuneration value was set irrespective of the source used:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	1,680	2,167	3,099	3,719

Energy generated before commissioning by the Agency in Charge of Dispatch, will be remunerated at 50% of the above-mentioned remuneration.

2.1.4.3 Transitory additional remuneration

On November 2, 2021, SE Resolution No. 1,037/21 provided as follows: (i) the creation of an exports account in the WEM’s stabilization fund for the accumulation of income from electricity export transactions conducted by CAMMESA, as from the economic transactions for the month of September 2021, for the financing of energy infrastructure works; and (ii) the transitory recognition of an additional remuneration to the one established by SE Resolution No. 440/21 for the economic transactions comprised between September 1, 2021 and February 28, 2022. On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that covered generators have a 70% utilization factor, therefore, 100% of the power capacity remuneration would be paid, and added an amount of $ 1,000/MWh for exported energy, which will be distributed proportionately to the energy generated monthly by each generator.

SE Resolution No. 238/22 canceled the detailed additional and transitory remuneration from the February 2022 economic transaction.

2.1.4.4 Suspension of contracts within the MAT

The suspension of contracts within the MAT (excluding those derived from a differential remuneration scheme) provided for by SE Resolution No. 95/13 remains in effect.

2.1.5 Fuel supply for thermal power plants

On December 27, 2019, the Ministry of Productive Development Resolution No. 12/19, restored the centralized scheme in CAMMESA for the supply of fuels for generation purposes (except for generators under the Energy Plus regime and with Wholesale Power Purchase Agreements under Resolution SE No. 287/17).

In December 2020, on account of the implementation of the GasAr Plan (see Note 2.2.4.1.2), SE Resolution No. 354/20 was passed, which established a new dispatch order for generation units based on the fuel supplied for their operation under a centralized dispatch scheme.

SE Resolution No. 354/20 established the gas volumes CAMMESA should prioritize in the electricity dispatch. In this sense, firm volumes to be used by CAMMESA were defined, including: i) volumes corresponding to contracts entered into by CAMMESA with producers acceding to the GasAr Plan; ii) volumes corresponding to contracts executed by adherent producers with generators acceding to the centralized dispatch (these volumes will be discounted by the adherent producers from the applicable quota for which they should enter into contracts with CAMMESA under the GasAr Plan) and; iii) volumes to meet the Take or Pay (“TOP”) obligations under the supply agreement entered into between IEASA and Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”).

Besides, an electricity dispatch priority scheme was set based on the allocation of the natural gas quota taking into consideration the TOP obligations. To this effect, the following priorities were set (within each priority level, the order of agents is set based on the generator’s production cost):

(i) Dispatch Priority 1: Generators, Self-generators and/or Co-generators supplied with a natural gas quota under a TOP Bolivia condition assigned by IEASA. If a generator with a fuel stocking obligation optionally acquires from IEASA natural gas from Bolivia, this volume will be included in this quota.

(ii) Dispatch Priority 2: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes up to the TOP of each contract.

(iii) Dispatch Priority 3: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes for the Daily Maximum Amount (DMA) less those corresponding to the TOP of each contract.

(iv) Dispatch Priority 4: Generators, Self-generators and/or Co-generators supplied by CAMMESA with natural gas or LNG coming from other firm commitments undertaken by CAMMESA.

(v) Dispatch Priority 5: Generators, Self-generators and/or Co-generators supplied with a gas quota from the unassigned, spot natural gas contracts from any source, acquired by CAMMESA and/or the Generator, according to the supply source. In the case of a generator with its own fuel, the maximum amount to be acknowledged will be the corresponding reference prices.

As regards the costs associated with the supply of these fuels, it was established that the electricity demand will bear, among others, the regulated transportation costs, the cost of natural gas and the applicable TOP obligations.

Generating agents that kept the possibility to purchase their fuel supply (agents under the Energy Plus regime or with Wholesale Purchase Agreements under Resolution SE No. 287/17) could opt in or out of CAMMESA’s unified dispatch, through the operating assignment of the contracted firm transportation and gas volumes, which impact the assigned priority order. Under such assignment, agents should waive all claims regarding the application of SE Resolution No. 354/20.

In the specific case of generators with wholesale power purchase agreements under SE Resolution No. 287/17, it was provided that they would have the option of canceling the self-supply obligation and the resulting recognition of its associated costs, having to maintain the respective transportation capacity for its management in the centralized dispatch.

The Company assigned the firm transportation and gas volumes committed to supplying Genelba Plus’ CC and Energy Plus contracts, setting certain guidelines for calculating fuel costs to support its Energy Plus contracts. In the case of the supply to Genelba Plus’ CC, the assignment will remain effective during the life of the GasAr Plan, and it may be revoked by the generator with a minimum advance notice of 30 business days. Within this framework, the parties agreed to enter into an addendum to the Wholesale Power Purchase Agreement to establish the modifications regarding this new supply scheme, which execution is pending as of the issuance of these Consolidated Financial Statements.

2.2 Oil and gas

2.2.1 Argentine Hydrocarbons Law

On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319 (enacted in 1967), which empowers the Government to grant exploration permits and concessions to the private sector. Additionally:

(i) Sets the terms for exploration permits:

- 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;

- Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years; and

- Continental shelf and off-shore exploitation: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

(ii) Sets the terms for exploitation concessions, extensible for 10-year terms:

- Conventional exploitation concession: 25 years;

- Unconventional exploitation concession: 35 years; and

- Continental shelf and off-shore exploitation concession: 30 years.

(iii) Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.

(iv) Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

(v) Establishes a 12% royalty payable by the exploitation concessionaire to the grantor on the proceeds derived from liquid hydrocarbons extracted at wellhead and the production of natural gas. In the case of extension, additional royalties for up to 3% over the applicable royalties at the time of the first extension, up to a total of 18%, will be paid for the following extensions.

(vi) Provides for two types of non-binding commitments between the National Government and the Provinces aiming to establish a uniform environmental legislation and to adopt a uniform tax treatment to encourage hydrocarbon activities.

(vii) Restricts the National Government and the Provinces from reserving new areas in the future in favor of public or mixed companies or entities, irrespective of their legal form.

On its part, the Ministry of Energy and Natural Resources of the Province of Neuquén established certain parameters for the granting of Hydrocarbons Unconventional Exploitations Concessions (“CENCH”) in this province, instrumented through Resolution No. 53/20 dated July 1, 2020 and Resolution No. 142/21 dated November 24, 2021, and later ratified by Provincial Executive Order No. 2,183/21 in December 2021. Companies may request a CENCH based on a development project that will include a pilot plan for a term of up to five years to demonstrate its technical and economic feasibility. Furthermore, if companies request the inclusion in the CENCH of a surface larger than that assigned to the approved pilot plan, the payment of a block extension bond should be included, which value will be associated with the resources expected to be recovered in the extended block, considering the basin’s average price over the last two years. Besides, while the CENCH is in effect, companies should submit continuous development plans and investment commitments, updated annually.

2.2.2 Hydrocarbon exploration and exploitation levy

Law No. 27,007 set the levy values per km2 or fraction to be paid annually and in advance by the permit holder. Exploitation permits will amount to $ 4,500 and exploration permits, to $ 250 in the first period, $ 1,000 in the second period of the basic term, and $ 17,500 during the first year of the extension (with a 25% annual cumulative increase). It is worth highlighting that up to 10% of the levy value payable in the second period of the basic term and the extension may be offset with actual investments per km2.

On September 26, 2019, the Province of Neuquén, pursuant to Provincial Executive Order No. 2,032/19, published new levy values per km2 or fraction effective for this province from 2020. The exploitation levy was set at $ 22,410, and the exploration levy at $ 1,245 for the first period, $ 4,980 for the second period, $ 7,470 for the third period, and $ 87,150 for the extension period.

From 2021, PEN Executive Order No. 771/20 set a maximum levy in pesos equivalent to a certain volume of oil at the average price for the semester before settlement, at BNA’s exchange rate effective on the last business day before payment. This scheme is applicable nationwide (including the Province of Neuquén, which acceded to it under Provincial Executive Order No. 1,656/20). Exploitation permits amount to 8.28 barrels and exploration permits to 0.46 barrels in the first period, 1.84 barrels in the second period of the basic term, and 32.22 barrels in the extension period.

2.2.3. Currency access for incremental oil and natural gas production systems and regional and national supplier’s employment, labor and development promotion system

On May 28, 2022, PEN Executive Order No. 277/22 was published, which established currency access systems for the incremental production of oil (“RADPIP”) and natural gas (“RADPIGN”), as well as the regional and national supplier’s employment, labor and development promotion system (“RPEPNIH”). This executive order, later regulated by PEN Executive Order No. 484/22 dated August 12, 2022, mainly provided for eased access to the MLC for beneficiaries increasing their gas injection levels and/or oil production.

Beneficiaries must meet the following requirements to access the RADPIP and the RADPIGN: (i) be registered with the SE’s oil companies registry; (ii) accede to the system; (iii) attain an incremental oil production or natural gas incremental injection levels; (iv) comply with the RPEPNIH; and (v) be an awardee and fulfill the obligations provided under natural gas production promotion or stimulus programs (exclusively for the RADPIGN).

Beneficiaries under these systems may access the MLC to make principal and interest payments of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, and to pay earnings and dividends for closed and audited balance sheets and/or the repatriation of direct investments by non-residents. This benefit may be transmitted to direct suppliers. Moreover, access to the MLC under this system will not be subject to BCRA’s prior authorization requirement in case exchange regulations so require.

Currency access benefits for acceding the RADPIP and/or RADPIGN will be taken into consideration and timely discounted.

Regarding the RPEPNIH, supplier development plans guaranteeing regional and national integration will be controlled. Moreover, a hiring scheme is contemplated granting preferences to regional and national goods and/or services suppliers.

On January 16, 2023, SE Resolution No. 13/23 was published in the BO, which regulated the opt-in system and the procedure to obtain the currency access benefit created by PEN Executive Order No. 277/22.

On February 8, 2023, the Company requested the opt-in to both aforementioned regimes and the benefits for the third and fourth quarters of 2022.

2.2.4 Gas Market

2.2.4.1 Natural Gas Production Promotion or Stimulus Programs

2.2.4.1.1 Argentine Natural Gas Production Promotion Plan (“GasAr Plan”)

On November 16, 2020, Executive Order No. 892/20 was published in the BO, which approved the GasAr Plan to foster the development of the Argentine gas industry based on a bidding mechanism, and instructed the SE to instrument such plan and to set the applicable complementary and clarifying rules.

On November 23, 2020, the SE, through Resolution No. 317/20, launched the “National Public Call for Tenders for the Argentine Natural Gas Production Promotion Plan – 2020-2024 supply and demand scheme” for the award of a volume of 70 million m3 of natural gas per calendar year (CAMMESA plus distributors), which may be modified by the SE to guarantee an optimal domestic supply.

The contract samples stipulated a Deliver or Pay (“DOP”) obligation of 100% per day for producers and a Take or Pay (“TOP”) obligation of 75% per month for CAMMESA and per quarter for distributors. Regarding the payment of contracts with distributors, the Federal Government will bear the monthly difference between the price tendered and that resulting from the tariff schemes through a subsidy payable directly to producers. Under Law No. 27,591, payment of this subsidy is secured by Tax Credit Certificates, which were regulated by SE Resolution No. 125/21 and AFIP General Resolution No. 4,939/21.

Additionally, to access the GasAr Plan producers submitted a plan of investments necessary to maintain the committed production and a national added-value commitment providing for the development of direct local, regional and national suppliers.

On December 15, 2020, Resolution No. 391/20 was published in the BO, awarding the natural gas volumes tendered under GasAr Plan, Round 1. In this sense, out of a total natural gas base volume of 67.42 million m3/day to be purchased, in terms of tendered volume, the Company ranked third in the Neuquina Basin, with an awarded base volume of 4.9 million m3/day at an annual average price of US$ 3.60/MBTU for a term of four years effective as from January 1, 2021.

Additionally, the Company has been one of the three producers tendering an additional volume for the winter period, with the award of 1 million m3/day at US$ 4.68/MBTU, a volume deemed indispensable to accompany the high seasonality of the Argentine demand, reducing gas imports, the consumption of alternative fuels, and the use of foreign-currency reserves.

On March 9, 2021 Resolution No. 169/21 was published in the BO, which awarded natural gas volumes offered under the GasAr Plan, Round 2 Tender. In this sense, the Company was awarded a volume 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 meet the winter peak demand for the years 2022 through 2024, at a price of US$ 4.68/MBTU.

Under Resolution No. 984/21 dated October 19, 2021, the SE called for Round 3 under GasAr Plan for 2022 through 2024 inclusive, with injection starting in May 2022. The resolution determined that the cap price for tenders is the maximum price tendered under Round 1. The Company took part in this call, tendering 2 million m3/day for the Neuquina basin at a price of US$ 3.347/MBTU; on November 11, 2021, the SE issued Resolution No. 1,091/21, awarding the tendered volumes and prices.

2.2.4.1.2 2023-2028 Plan to Reinsure and Encourage Federal Hydrocarbon Production, Domestic Self-Supply, Exports, Imports Substitution, and the Expansion of the Transportation System for all the Country’s Hydrocarbon Basins (“Reinsurance Plan”)

On November 3, 2022, Executive Order No. 730/22 was published in the BO, which amended the GasAr Plan’s scheme approved by Executive Order No. 892/20.

The Reinsurance Plan establishes a new term for the system until December 31, 2028, with the following main objectives: (i) consolidating a new 70 MMm3/d flat block (volumes awarded under GasAr Plan’s Round 1 and 3), excluding winter peaks; and (ii) developing the demand for the incremental volumes to be evacuated using the new transportation capacity following the construction of the Néstor Kirchner Gas Pipeline (TransportAr Program, SE Resolution No. 67/22).

Consequently, on November 14, 2022, SE Resolution No. 770/22 was published in the BO, calling for Tender Rounds 4 for the Neuquina Basin, and 5, for the Del Golfo and Austral Basins.

For the Neuquina Basin, the following calls were made:

(i) Round 4.1: for the extension of the commitments undertaken under Rounds 1 and 3 of the GasAr Plan for 4 additional years, from January 1, 2025 to December 31, 2028, for the same volumes, and with prices equal to or lower than the timely awarded price; and

(ii) Round 4.2: for the award of the following incremental volumes:

(a) Flat Gas: 11 MMm3/day from July 1, 2023 to December 31, 2028, and 3 MMm3/day from January 1, 2024 to December 31, 2028, with prices not exceeding US$ 4 MBTU; and

(b) Peak Gas: 7 MMm3/day from May 1 to September 30, for each of the 2024-2028 and 2025-2028 periods, with prices equal to or lower than US$ 6.9 MBTU and an applicable 1.3 adjustment factor.

The Company participated in Round 4.1, seeking to extend commitments under GasAr Plan’s Rounds 1 and 3 until December 2028 and keeping the originally tendered prices of US$ 3.6 MBTU and US$ 3.347 MBTU, respectively. Moreover, it submitted the following tenders under Round 4.2: (i) Flat Gas: 4.8 million m3/day at a price of US$ 3.485 MBTU from July 1, 2023 to December 31, 2028; (ii) Peak Gas: 3 million m3/day at a price of US$ 5.190 MBTU for the 2024-2028 period and 1.9 million m3/day at US$ 4.770 MBTU for the 2025-2028 period.

On December 22, 2022, through SE Resolution No. 860/22, the Company was awarded the extension of the commitments for Round 4.1 and a 4.8 million m3/day demand associated with flat gas under Round 4.2.

The awards granted to the Company and the contracts executed represent a production commitment of 15.7 million m3/day for winter periods and 13.8 million m3/day for summer periods in 2023-2024. Compared to 2022, this commitment represents a 44% increase in winter production, the period with the largest gas supply needs in the country. As from 2025, the commitment under the Reinsurance Plan will amount to 13.8 million m3/day.

Based on the gas demand curve projected by the SE, the Company will enter into new contracts with CAMMESA, IEASA and distributors.

2.2.4.2 Natural gas for the residential segment and CNG

On May 27, 2022, SE Resolution No. 403/22 provided for an update of new natural gas PIST prices under existing contracts executed within the framework of GasAr Plan’s promotion scheme, reducing the subsidy payable by the Federal Government from June 1, 2022.

Additionally, in the months of February, June and August 2022, public hearings were held to analyze the Plan Gas.Ar portion of the natural gas PIST price to be borne by the Federal Government. It is worth highlighting that SE Resolution No. 610/22 determined a gradual increase in the PIST price distributors will pay for unsubsidized residential consumptions, keeping the subsidized price for the remaining users.

On January 10, 2023, SE Resolution No. 6/23 was published, establishing updates of natural gas PIST prices for contracts executed under the GasAr Plan and the Reinsurance Plan based on the different types of users.

2.2.4.3 Acquisition of Natural Gas for Generation

From December 30, 2019, CAMMESA’s centralization scheme for the supply of fuels for generation was restored (except for generators with Energy Plus and SE Res. 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 GasAr Plan, for the volumes committed under this program over an initial term of 4 years.

In addition to GasAr Plan, in 2021 CAMMESA continued calling for tenders on a monthly basis, at a maximum price of US$ 2.3/MBTU until April and US$ 3.5 until August, on an interruptible basis for GasAr Plan awardees and under a 30% DOP clause for the rest. However, from September 2021 these calls were declared unawarded. On the other hand, since mid-July 2021 CAMMESA launched biweekly calls for tenders by GasAr Plan awardees that may offer surplus volumes, with a maximum price equivalent to that awarded in the plan’s Round 1. In 2022, an average of 451 million m3/day were awarded at a price of US$ 3.5/MBTU (of which 276 million m3/day correspond to the Neuquina Basin).

2.2.4.4 Natural Gas Exports

On April 27, 2021, SE Resolution No. 360/21 regulated the new procedure for the authorization of natural gas exports. This resolution contemplates exports on a firm and preferential basis for GasAr Plan’s awardees, and sets a minimum sale price equivalent to the summer price awarded in Round 1. In this manner, the Company, as an awardee under GasAr Plan, 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 May and December 2021, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m3/day and 1.22 million m3/day for the October 2021 – April 2022 and January – April 2022 periods, respectively. Besides, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were added, with expirations between November 2022 and December 2024.

Under GasAr Plan, in August 2022 the Company was cleared to export gas to Chile on a firm basis for a maximum volume of 1,492 MMm3/d for the October 2022 – April 2023 period.

On November 17, 2022, SE Resolution No. 774/22, which supersedes SE Resolution No. 360/21, was published in the BO. This resolution establishes a new proceeding delimiting four export areas: the Neuquina Basin and the Austral Basin with summer quotas (October 2023-April 2024 period) of 9 MMm3/day and 2 MMm3/day, respectively, and the Noroeste Basin and other areas with no quota definition.

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.

The minimum reference price is set at the higher of the Brent quotation percentage determined by the SE and the average price awarded, adjusted by the seasonal index, with the authorization to withdraw volumes from the contracts executed under GasAr Plan and/or the Reinsurance Plan with CAMMESA and/or ENARSA.

Additionally, for the Neuquina Basin, firm exports for 3 million m3/day will be authorized for the May-June 2023 period, to be apportioned among producers awarded under Round 4.2 - Flat Gas for the July 1, 2023-December 31, 2028 period.

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 as long as the international Brent price was equal to or below US$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 US$60/bbl. Since February 2021, the rate has remained at 8%.

2.2.4.5 “TransportAr National Production” Pipelines System Program

On February 9, 2022, SE Resolution No. 67/22 was published in the BO declaring the construction of “President Néstor Kirchner Pipeline” of national public interest. This pipeline will transport natural gas through the Province of Neuquén, the Province of Buenos Aires, and the Province of Santa Fe.

Moreover, it created the TransportAr Production Gas Pipelines System Program to execute the works necessary to expand the system’s transportation capacity including a list of pipeline works to be executed by IEASA or through third parties to promote development, production growth, and natural gas self-supply, among other objectives.

On August 10, 2022, Argentine authorities signed contracts for the Stage 1 Néstor Kirchner Gas Pipeline construction, that will connect the cities of Tratayén (Neuquén) with Salliqueló (Buenos Aires) and will cross the provinces of Río Negro and La Pampa. As of the issuance of these Consolidated Financial Statements, the aforementioned construction is underway, and commissioning is expected for June 2023.

Later, PEN Executive Order No. 76/22, published on February 14, 2022, granted IEASA a 35-year transportation concession of President Néstor Kirchner pipeline under Law No. 17,319 and the power to contract, plan, execute and call for tenders for the construction of the infrastructure works under the Program. IEASA may enter into transportation capacity freely-negotiated agreements with producers and/or carriers to construct or expand all or part of the pipeline. This transportation capacity will not be covered by tariffs approved by ENARGAS, which will apply to the remaining transportation capacity not committed under these agreements. This executive order grants YPF priority to hire the capacity that can be freely negotiated by IEASA. Moreover, IEASA may fully or partially assign ownership of its concession to YPF.

Besides, the “Argentine Gas Development Fund” administrative and financial trust was created, with IEASA as trustor and beneficiary, to finance works under the program, including the repayment of principal and interest services of the trust securities to be issued thereunder. The trust estate administrator and trustee will be Banco de Inversión y Comercio Exterior S.A.

2.2.5 Oil market

2.2.5.1 Crude oil price

As of this date, there is no reference price for the sale of crude oil in the domestic market. However, considering pump prices for fuels, local refining companies are validating prices below the export parity.

Just as with natural gas exports, a crude oil export duty has been in effect since May 2020. PEN Executive Order 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 US$ 45/bbl, rising gradually as the international reference price increased until reaching 8%, the cap to be recognised when the reference price equals or exceeds US$ 60/bbl. Since February 2021, the rate has remained at 8%.

2.2.5.2 Oil transportation

In fiscal year 2022, Oldelval, as holder of the national liquid hydrocarbons transportation concession, launched a call for tenders to award and hire the firm transportation service for the Allen - Puerto Rosales oil pipeline tranche for a capacity of up to 50,000 m3/day.

This volume has been fully awarded, and the necessary execution contracts have been entered into, effective until the termination of the transportation concession term in 2037. Pampa was awarded 1,002 m3/day.

Under Oldelval’s call for tenders, the company Oiltanking Ebytem launched a call to increase the oil dispatch capacity for up to 50,000 m3/day and the storage capacity for up to 300,000 m3. These expansions will be allocated exclusively to oil exports. Pampa was awarded a 1,002 m3/day dispatch capacity and oil storage capacity for 6,008 m3.

2.3 Gas Transportation

2.3.1 TGS’s Tariff situation

On March 30, 2017, TGS executed the 2017 Integral Agreement which was ratified on March 27, 2018, through PEN Executive Order No. 250/18. This executive order represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS.

The 2017 Integral Agreement set the guidelines for the provision of the natural gas transportation service until the end of the license, among these guidelines approved: (i) a tariff increase was granted in installments for TGS as from April 1, 2017; (ii) a Five-Year Investment Plan to be executed by TGS between April 2017 and March, 2022; and (iii) a non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments considering IPIM published by INDEC subject to ENARGAS’ approval.

In the public hearing held on September 4, 2018, in which TGS requested, based on the variation of the IPIM recorded for the period February - August 2018, a tariff increase of approximately 30%. Considering the hearing, on September 27, 2018, ENARGAS issued Resolution No. 265/18 which determined a 19.7% tariff increase effective as of October 1, 2018.

This increase was determined by ENARGAS based on the simple average of the IPIM, the construction cost index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018. ENARGAS supported the determination of the aforementioned tariff increase in the provisions of Resolution No. 4,362/17, which, among other issues, provided that under certain circumstances and macroeconomic conditions, such as the significant devaluation occurred after April 2018, ENARGAS may use other indexes than the IPIM to determine the tariff increase. TGS notified ENARGAS of its disagreement with respect to the methodology for calculating the semi-annual adjustment.

On March 29, 2019, ENARGAS issued Resolution No. 192/19 approved, effective as from April 1, 2019, a 26% increase in tariff schemes applicable to the natural gas transportation utility by TGS current as of March 31, 2019. In accordance with current regulations, ENARGAS considered the evolution of the IPIM update index between the months of August 2018 and February 2019 to define six-monthly adjustments to TGS’ tariffs.

As regards the semi-annual tariff update which should have become effective as from October 1, 2019, on September 3, 2019, the SE issued Resolution No. 521/19, later amended by Resolution No. 751/19, postponed its application until February 1, 2020. This deferral resulted in the revision and adjustment of the Five-Year Investment Plan execution, in the same proportion as the foregone income for TGS.

On December 16, 2020, PEN Executive Order No. 1,020/20 was passed within the framework of the Solidarity Law. This executive order launched the renegotiation of the RTI concluded in 2018 within a term of 2 years. During this term, renegotiation agreements in force are suspended. On December 7, 2022, PEN Executive Order No. 815/22 was published in the BO, extending the renegotiation term for 12 months until December 16, 2023.

Additionally, the Solidarity Law, PEN Executive Order No. 1,020/20 and PEN Executive Order No. 1815/22 provide for the administrative intervention of the ENARGAS.

The public hearing called by ENARGAS to discuss the RTT pursuant to the provisions of PEN Executive Order No. 1,020/20 took place on March 16, 2021. In this respect, TGS, without waiving the whole of its percentage share of tariff recomposition, alternatively submitted in the hearing its tariff increase proposal, assessed at 58.6% as from April 1, 2021. This increase was assessed based on the financial needs to meet operating and financial costs, capital expenditures and taxes, which were calculated taking into consideration the evolution of the inflation rate over a 12-month period as from its beginning. The requested increase only contemplated the funds necessary to meet its obligations as licensee.

Additionally, TGS denied and dismissed the arguments raised in the public hearing, which considered that the current natural gas transportation tariff is not fair or reasonable given the alleged existence of serious flaws in the administrative acts resulting from the proceedings for the last RTI established for TGS.

On April 28, 2021, ENARGAS submitted to TGS the 2021 Transitional Agreement (“RTT 2021”), which: (i) does not grant a transitory tariff update, keeping unchanged the tariff schemes approved by ENARGAS in April 2019; (ii) provides that, as from May 2021 and until the Final Renegotiation Agreement enters into effect, ENARGAS will recalculate the transportation tariffs effective at the time, with validity as from April 1, 2022.; (iii) does not establish a mandatory investment plan; and (iv) establishes the prohibition to distribute dividends, early cancel financial and commercial debts taken on with shareholders, acquire other companies, or grant loans.

On April 30, 2021 and through a note sent to this body, TGS expressed that, given the context in which it develops its activities and the proposed terms and conditions, it is not feasible for TGS to enter into the RTT 2021.

On June 2, 2021, ENARGAS issued Resolution No. 149/21 approving an RTT 2021 for TGS effective as from that date. Moreover, the National Ministry of Economy and ENARGAS issued Joint Resolution No. 1/21 approving the proceedings under the renegotiation process developed by ENARGAS pursuant to PEN Executive Order No. 1,020/20, stating that it was not feasible to reach an agreement on a transitional tariff update.

Given this situation, in July 2021, TGS filed motions for reconsideration, subsidiarity filing a hierarchical appeal, before the PEN, the National Ministry of Economy and ENARGAS according to the respective jurisdictions of each of these bodies in the passing of the regulations associated with Resolution No. 149/21, requesting the declaration of nullity of the RTT 2021 and the reinstatement of the RTI.

The challenges are based on: (i) the illegality of Executive Order No. 1,020/20, as it does not observe the delegation lines provided for by Act No. 27,541 and, as it does not meet the requirements established by the Constitution for the dictation of this regulation; (ii) the extension of the emergency period beyond that established by the Congress; (iii) the tariff renegotiation under Act No. 24,076 is not performed; (iv) the disregard for the principle of fair and reasonable tariffs, and the rights acquired by TGS under the license, the Contractual Adjustment Memorandum of Understanding and the RTI; and (v) the suspension of the RTI for reasons of public interest, which merits the recognition of the compensations provided for by both the Administrative Procedures Act and the License Basic Rules.

In turn, the restrictions on the management and administration of TGS have been challenged for lacking legal justification, as the emergency declared by Act No. 27,541 only empowered the PEN to renegotiate the RTI, but not the License. The challenges and the request for reinstatement of the RTI have been filed notwithstanding TGS’s right to the payment of the compensations it is entitled to on account of the breach of the RTI as from April 2019.

On November 15, 2021, TGS filed a Prior Administrative Claim before ENARGAS and the Ministry of Economy. This presentation seeks to request compensation due to TGS for the non-application of the semi-annual adjustment methodology set by the RTI and approved by Resolution 4,362 between October 1, 2019 and June 1, 2021.

Moreover, TGS seeks compensation for the damages sustained by the freeze resulting from the failure to apply the semi-annual adjustment methodology set by the RTI for this period.

On January 19, 2022, a new public hearing was held within the framework of ENARGAS Resolution No. 518/21 to address the transition tariff update under PEN Executive Order No. 1020/20. In this hearing, aiming to reach a final agreement and restore the economic and financial equation, TGS requested a transition tariff adjustment in two stages for 2022 for a total of 106%, given the evolution of operating costs and the main macroeconomic indicators.

Later, on February 1, 2022, TGS received from ENARGAS the proposed Renegotiation Transition Agreement (the “RTT 2022”), which was approved by TGS’s Board of Directors on February 2, 2022, and by the applicable governmental bodies on February 18, 2022. The RTT 2022 included certain terms similar to the RTT 2021, with the specific provision that it granted TGS a 60% tariff increase effective from March 1, 2022.

The RTT 2022 was ratified through PEN Executive Order No. 91/22, effective from February 23, 2022. On February 25, 2022, ENARGAS Resolution No. 60/22 was published in the BO, launching the tariff schemes contemplated in the RTT 2022.

It is worth highlighting that, as provided in the RTT 2022, TGS undertook not to initiate new claims, remedies, lawsuits, or any kind of actions; and/or to suspend, keep suspended or extend the suspension of all claims and remedies associated in any way with the current RTI renegotiation, Law No. 27,541, Decrees No. 278/20 and No. 1,020/20.

On December 7, 2022, ENARGAS issued Resolution No. 523/22 calling for a public hearing, to be held on January 4, 2023, to consider the transitional tariff update for the natural gas transportation utility.

As of the issuance of these Consolidated Financial Statements, TGS is working jointly with ENARGAS to conduct the RTI process that will allow the company to receive a fair and reasonable tariff in line with the provided natural gas transportation utility service.

2.3.2 Regulatory framework of the segment of Production and Commercialization of Liquids

2.3.2.1 Domestic market

The production and commercialization of liquids segment is not subject to regulation by ENARGAS. However, over recent years, the Argentine Government enacted regulations which significantly impacted it.

GLP domestic sales prices are impacted by the provisions of Law No. 26,020 "Regime of the industry and commercialization of liquefied petroleum gas" and the Argentine Government through the public office in charge, that set forth LPG minimum volumes to be sold in the local market in order to guarantee domestic supply.

In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually. On March 30, 2015, the PEN issued Decree No. 470/15, regulated by SE Resolution No. 49/15, which created the “Household Plan” and sets a maximum reference price for the members of the commercialization chain in order to guarantee the supply to low-income residential user, by committing the GLP producers to supply at a fixed price with a quota assigned to each producer. Additionally, payment of compensation to the Household Plan participating producers was established.

TGS has filed various administrative and judicial claims challenging the general regulations of the program, as well as the administrative acts that determine the volumes of butane that must be sold in the domestic market, in order to safeguard its economic-financial situation and thus, preventing that this situation does not extend over time.

In addition, TGS is a party of the Propane Gas Supply Agreement for Induced Propane Gas Distribution Networks ("Propane for Networks Agreement") entered into with the Argentine Government and propane producers by which it undertakes to supply propane to induced propane gas distributors and sub- distributors through at a price lower than the market price. In compensation, TGS receives an economic compensation calculated as the difference between the sale price and the export parity determined by the SE.

As it has been previously mentioned, participation in the Household Plan results in economic and financial damage to TGS, since under certain circumstances products would be sold at prices below their production costs.

As of December 31, 2022, the Argentine Government owes TGS $ 3,768 million under these items.

2.3.2.2 Foreign market

Executive Order No. 488/20 regulated the rate applicable to the export duties for certain gas and oil derivatives, including the products produced and exported by TGS, which ranges between 0% and 8% depending on the price of the “ICE Brent first line” barrel. If this price is below US$ 45, the rate is 0%. Instead, if the price equals or exceeds US$ 60, an 8% rate is paid, and the rate is variable if the price is between US$ 45 and US$ 60.

2.4 Transmisión

2.4.1 Transener and Transba tariff situation

On February 25, 2022, the ENRE communicated Resolutions No. 68/22 and 69/22 approving the new hourly remuneration values effective from February 1, 2022, establishing a 25% and 23% increase compared to the values effective from 2019 for Transener and Transba, respectively. Considering the difference between the presented financial and economic projections and the values finally approved by the ENRE, a motion to review the records and the respective preliminary challenges was submitted. Moreover, on March 15, 2022, the applicable motions for reconsideration against these resolutions were filed. Consequently, under Resolutions No. 147/22 and 148/22, on May 9, 2022 the ENRE partially upheld the filed motions and modified the hourly remuneration values effective from February 1, 2022, establishing a 67% and 69% increase over the values effective from August 2019 for Transener and Transba, respectively.

Since August 2022, Transener and Transba filed notes and held meetings with the SE and the ENRE requesting an update to the transitional tariffs effective from September 2022, chargeable against the increase to be assessed for 2023. To this effect, the 2023 economic and financial projection was presented with an explanatory document and a detail of the projected investment plan. Moreover, a presentation was made to CAMMESA’s Board of Directors to put the criticality of the transportation sector on record.

Under Resolution No. 539/2022, on October 20, 2022 the ENRE called for a public hearing on November 30, 2022 to inform of and gather feedback on the electricity transmission utility concessionaires’ proposals towards a transitional tariff update under the RTI Renegotiation Process before defining the tariffs applicable by the concessionaires.

Furthermore, on December 6, 2022, PEN Executive Order No. 815/22 extended for one-year term PEN Executive Order No. 1,020/20 published on December 17, 2020, through which initiated RTI renegotiation within up to 2 years from its publication.

Later, on December 29, 2022, aiming to preserve in 2023 the purchasing power of the revenues established in Resolutions No. 147/22 and 148/22, the ENRE issued Resolutions No. 698/22 and 702/22 setting the hourly remuneration values effective from January 1, 2023, and establishing a 154.5% and 154.1% increase over the February 2022 values for Transener and Transba, respectively.

2.5 Regulations on access to the MLC

In 2020, BCRA introduced 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.

To access the MLC in terms of expenditures without BCRA’s prior authorization, it is necessary to file an affidavit certifying that all foreign-currency holdings in the country are deposited in accounts with local financial institutions and that it no available liquid foreign assets are held for an amount equivalent to or higher than US$ 100,000. In case such liquid foreign assets exceed the amount of US$ 100,000, an additional affidavit could be submitted according to the applicable provisions. To such effects, the term “liquid foreign assets” will comprise, among others: holdings of foreign currency notes and coins, availability of gold in the form of good delivery bars or coins, sight deposits in foreign financial entities, holding of Argentine certificates of deposit (“CEDEAR”) and other investments allowing for the immediate availability of foreign currency (for example, investments in foreign public securities, funds in investment accounts deposited with investment managers located abroad, crypto assets, funds deposited in payment service providers’ accounts, etc.). On the other hand, the following will not be considered available liquid foreign assets: funds deposited abroad that may not be used by the customer as they are reserve or guarantee funds created under foreign debt contracts, or funds kept as collateral for foreign transactions with derivatives entered into abroad.

Furthermore, in case access to the MLC has been requested, it is mandatory to enter and settle in the MLC, within a term of five business days after they become available, foreign funds originating from the collection of loans granted to third parties, the collection of time deposits or the sale of any kind of asset, in case the asset has been acquired, the deposit has been made or the loan has been granted after May 28, 2020.

As regards transactions with stock market assets is established: (i) the presentation of an affidavit declaring that, on the date of access to the MLC and in the previous 90 calendar days, no domestic sales of securities to be settled in foreign currency, exchanges of securities issued by foreign active residents, transfers of securities to foreign depositary entities, local acquisitions of securities issued by non-residents and settled in pesos, acquisitions of CEDEAR representing foreign shares (from July 22, 2022), acquisitions of private debt securities issued in a foreign jurisdiction, or deliveries of funds in domestic currency or other domestic assets (except for foreign-currency funds deposited with local financial entities) to any natural or legal, resident or non-resident person, and whether or not affiliated, receiving as prior or subsequent consideration, whether directly or indirectly, on its own or through any affiliate, controlled or controlling entity, foreign assets, crypto-assets or securities deposited abroad and, lastly, the commitment not to perform any of the detailed transactions for 90 calendar days following the request for access to the MLC should be evidenced; and (ii) that security transactions concerted abroad and securities acquired abroad may not be settled in pesos in the country. Moreover, if the customer is a legal entity, as an additional requirement to access the MLC, it also provided for an additional affidavit stating: (a) details of the individuals or legal entities exercising a direct control relationship over the customer, according to BCRA’s regulations; and (b) that on the day access to the MLC is requested and in the previous 90 calendar days, no local-currency funds or other liquid domestic assets have been delivered in Argentina to any individual or legal entity exercising a direct control relationship over it, except for those directly associated with regular transactions for the acquisition of goods and/or services. The requirement stated in item (b) will be deemed duly met if the customer submits an affidavit regarding transactions with securities of each individual or legal entity pursuant to the current exchange regulations.

BCRA’s prior authorization to access the MLC to cancel the principal of foreign financial debts with foreign affiliates is required up to and including December 31, 2023. Furthermore, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled until December 31, 2023, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, within the original term; and (ii) the refinancing of the principal balance, through new foreign indebtedness with an average life of 2 years. Within the framework of this refinancing process, access to the MLC is allowed for the early cancellation of principal, interest or debt swaps up to 45 calendar days before the maturity date, provided all requirements set forth by the regulation have been verified.

On October 2022, the Integral Import Monitoring System (“SIMI”) and the Integral Foreign Payments Monitoring System (“SIMPES”) were replaced by the Argentine Republic’s Imports System (“SIRA”) and the Argentine Republic’s Imports and Foreign Service Payments System (“SIRASE”), respectively. Moreover, BCRA established that no more advance, sight, or deferred without clearance payments may be made through these new mechanisms, except for certain cases contemplated in the regulation.

Regarding imports, BCRA’s prior authorization to access the MLC is required to make payments to import certain goods abroad or cancel the principal of debts originating from the import of goods by companies. Additionally, before executing payments for the import of goods, entities should verify that the affidavit requested from the customer is compatible with BCRA’s existing data. Additionally, the BCRA created a registry of foreign exchange information of goods exporters and importers as a requirement to access the MLC to perform forex outflow transactions, including swaps and arbitrations. The Company has been declared an obliged subject by the BCRA; it has completed its enrollment in this registry and is under a duty to report any change in the recorded information within 15 business days of its occurrence.

Additionally, in October 2022, the BCRA introduced adjustment to foreign exchange regulations, establishing, among other provisions, access to the MLC for subjects obtaining certifications under currency access systems for the incremental production of oil and/or natural gas pursuant to PEN Executive Order No. 277/22 (see Note 2.2.3), for up to the amount of each certification, to be allocated to the payment of: (i) principal and interest of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, (ii) earnings and dividends for closed and audited balance sheets; and/or (iii) the repatriation of direct investments by non-residents. RADPIP and/or RADPIGN beneficiaries should appoint a single domestic financial entity responsible for issuing such certifications and recording the amounts recognized by the SE and the applicable period.

More information on Argentina’s foreign exchange regulations can be found at the Central Bank’s website: www.bcra.gov.ar.

2.6 Tax regulations - Main tax reforms

Pursuant to Law No. 27,430, Law No. 27,541, Law No. 27,630, and Law No. 27,701 several modifications were introduced in the tax treatment, the key components of which are described below:

2.6.1 Income tax

2.6.1.1 Income tax rate

Pursuant to Law No. 27,430, the income tax rate for Argentine companies would be gradually reduced from 35% to 30% for fiscal years beginning from January 1, 2018 to December 31, 2019, and to 25% for fiscal years beginning on or after January 1, 2020. However, Law No. 27,541 suspended the tax rate reduction planned for fiscal year 2020, keeping the rate at 30%.

On June 16, 2021, Law No. 27,630 was published in the BO, which modified the income tax rate effective for fiscal years starting as from January 1, 2021 inclusive. This modification provides for the application of a tiered rate scheme and, if applicable, a fixed tax according to the accumulated net taxable income tier: (i) for accumulated net income of up to $ 5 million, it establishes a 25% rate; (ii) for accumulated net income between $ 5 and $ 50 million, it establishes a fixed tax of $1.25 million plus a 30% rate over the surplus of $ 5 million; and (iii) for accumulated net income above $ 50 million, it establishes a fixed tax of $ 14.75 million plus a 35% rate over the surplus of $50 million. The accumulated net income amount will be adjusted yearly, as from January 1, 2022, taking into consideration the annual CPI variation published by the INDEC.

The effect of the changes on deferred tax corresponding to comparative periods pursuant to the above-mentioned tax reform was recognised, considering the effective rate expected to be applicable at deferred assets and liabilities realization year, in “Effect of tax rate change in the deferred tax” under “Income tax” of the Consolidated Statement of Comprehensive Income (Note 10.5).

On August 16, 2022, AFIP’s General Resolution No. 5,248/22 was published in the BO, whereby the AFIP established a one-time income tax prepayment by taxpayers and responsible persons listed in Section 73 of Law No. 20,628, as amended, meeting the following parameters: (i) an assessed tax for the 2021 or 2022 tax period of at least $ 100 million, or (ii) taxable income, without deducting accumulated tax losses, of at least $ 300 million. As of issuance of these Consolidated Financial Statements, the Company and its subsidiaries paid an income tax prepayment for $ 1,863 million.

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, which be 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 will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax’ transition period) for all beneficiaries.

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; alternatively, for the first, second and third fiscal year as from its effective date, this proceeding will apply in case the accumulated variation in such price index, calculated from the beginning of the first fiscal year to the closing of each fiscal year, are higher than 55%, 30% and 15% for the years 2018, 2019 and 2020, respectively.

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. Failure to comply with this requirement will result in the loss of this benefit.

As 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 (see Note 10.5).

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.

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BASIS OF PREPARATION

12 Months Ended

Dec. 31, 2022

Basis Of Preparation

BASIS OF PREPARATION

NOTE 3: BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS issued by IASB, are expressed in million dollars and were approved for their issuance by the Board of Directors on March 9, 2023. 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.

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ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2022

Accounting Policies

ACCOUNTING POLICIES

NOTE 4: ACCOUNTING POLICIES

The main accounting policies used in the preparation of these Consolidated Financial Statements are explained below.

4.1 New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2022 and adopted by the Company

The Company has applied the following standards and/or amendments for the first time as of January 1, 2022:

- IFRS 3 “Business combination” (amended in May 2020).

- Annual Improvements to IFRS Standards - 2018-2020 cycle (issued in May 2020).

- IAS 16 “Property, Plant and Equipment” (amended in May 2020).

- IAS 37 “Provisions, contingent liabilities and contingent assets” (amended in May 2020).

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

- IFRS 17 - “Insurance Contracts”: issued in May 2017 and modified in June 2020 and December 2021. It supersedes IFRS 4, introduced in 2004 as an interim standard, which gave companies dispensation to carry on accounting for insurance contracts using national accounting standards, thus resulting in several application approaches. IFRS 17 sets the principles for the recognition, measurement, presentation and disclosure of information associated with insurance contracts and is applicable as from January 1, 2023, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in February 2021. It incorporates amendments to the information to be disclosed on accounting policies. Amendments are applicable to fiscal years starting on or after January 1, 2023, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 8 - “Accounting Policies”: amended in February 2021. Clarifies the treatment of estimates required in the application of accounting policies. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

- IAS 12 - “Income Tax”: amended in May 2021. It incorporates modifications regarding the recognition of deferred tax related to assets and liabilities that arise from a single transaction, giving riso to equal taxable and deductible temporary differences. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

- IFRS 16 - “Leases”: amended in September 2022. It incorporates amendments on sale and leaseback transactions. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in January 2020, July 2020 and October 2022. It incorporates amendments to the classification of liabilities as current or non-current and provides clarification on the treatment to be given to liabilities with covenants. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company’s operating results or financial position.

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 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 IAS 29 adjustment mechanism for hyperinflationary economies, on the opening equity measured in functional currency are recognised 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 Principles of consolidation and equity accounting

4.4.1 Subsidiaries

Subsidiaries are all entities over which the Group has control. 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. The Group 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 (see Note 4.4.5 below).

Intercompany transactions, balances and unrealized gains on transactions between Group entities are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the transferred asset. 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, Consolidated Statement of Changes in Equity and Consolidated Statement of Financial Position respectively.

4.4.2 Associates

Associates are all entities over which the group has significant influence but not control or joint control. This is generally the case where the Group holds between 20% and 50% of the voting rights. Investments in associates are accounted for using the equity method of accounting (see Note 4.4.4 below), after initially being recognised at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according to IFRS 11. The classification depends on the contractual rights and obligations of each investor, rather than the legal structure of the joint arrangement. The Company has both joint operations and joint ventures.

4.4.3.1 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. These have been incorporated in the Consolidated Financial Statements under the appropriate headings.

4.4.3.2 Joint ventures

Interests in joint ventures are accounted for using the equity method, after initially being recognised at cost (see Note 4.4.4 below).

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognised at cost and adjusted to recognize the Group’s share of the post-acquisition profits or losses of the investee in profit or loss, and the Group’s share of movements in other comprehensive income of the investee in other comprehensive income.

On acquisition of the investment, any difference between the cost of the investment and the entity’s share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as follows: (i) goodwill relating to an associate or a joint venture is included in the carrying amount of the investment and is not amortised, and (ii) any excess of the net fair value over the cost is included as income in the determination of the entity’s share of the associate or joint venture’s profit or loss.

Dividends received or receivable from associates and joint ventures are recognised as a reduction in the carrying amount of the investment.

When the Group’s share of losses in an equity-accounted investment equals or exceeds its interest in the entity, together with any long-term interests that, in substance, form part of the net investment, the Group does not recognize further losses, unless it has incurred obligations or made payments on behalf of the other entity.

Unrealized gains on transactions between the Group and its associates and joint ventures are eliminated to the extent of the group’s interest in these entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of equity accounted investees have been changed where necessary to ensure consistency with the policies adopted by the Group.

The carrying amount of equity accounted investments is tested for impairment in accordance with the policy described below in Note 4.9.

4.4.5 Business combinations

The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisitions comprises:

(i) the fair value of the transferred assets,

(ii) the liabilities incurred to the former owners of the acquired business,

(iii) the equity interests issued by the group,

(iv) the fair value of any asset or liability resulting from a contingent consideration arrangement, and

(v) the fair value of any pre-existing equity interest in the subsidiary.

Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values in the acquisition date. The group recognises any non-controlling interest in the acquired entity on an acquisition-by-acquisition basis at the non-controlling interest’s proportionate share of the acquired entity’s net identifiable assets.

Acquisition-related costs are expensed as incurred. The value of the goodwill represents the excess of: i) the consideration transferred, ii) the amount of any non-controlling interest in the acquired entity, and iii) the acquisition-date fair value of any previous equity interest in the acquired entity, over the fair value of the net identifiable assets acquired is recorded as goodwill. If the fair value of the net identifiable assets of the business acquired exceeds those amounts, the gain on bargain purchase is recognised directly in profit or loss.

Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing could be obtained from an independent financier under comparable terms and conditions.

Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently remeasured to fair value with changes in fair value recognised in profit or loss.

If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit or loss.

The Group has up to 12 months to finalize the accounting for a business combination. Where the accounting for a business combination is not complete by the end of the year in which the business combination occurred, the Group reports provisional amounts.

4.4.6 Changes in ownership interests

The Group treats transactions with non-controlling interests that do not result in a loss of control as transactions with equity owners of the group. A change in ownership interest results in an adjustment between the carrying amounts of the controlling and non-controlling interests to reflect their relative interests in the subsidiary. Any difference between the amount of the adjustment to non-controlling interests and any consideration paid or received is recognised in “Other reserves” within equity attributable to owners of the Company.

When the Group ceases to consolidate or equity account for an investment because of a loss of control, joint control or significant influence, any retained interest in the entity is remeasured to its fair value with the change in carrying amount recognised in profit or loss. This fair value becomes the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities, this means that amounts previously recognised in other comprehensive income are reclassified to profit or loss.

If the ownership interest in a joint venture or an associate is reduced but joint control or significant influence is retained, only a proportionate share of the amounts previously recognised in other comprehensive income are reclassified to profit or loss where appropriate.

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 person 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.

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.

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.

Works in progress are valued according to their degree of progress. Works in progress are recorded at cost less any loss due to impairment, if applicable.

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.

Gains and losses on disposals are determined by comparing the sale price with the carrying amount, stated in terms of the measuring unit current at the disposal date.

4.6.1 Depreciation methods and useful lives

The group depreciates productive wells, machinery and camps 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.

Machinery and generation equipment (including any significant identifiable component) are depreciated under the unit of production 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:

Buildings:	50 years
Vehicles:	3 - 5 years
Furniture, fittings and communication equipment:	5 years
Computer equipment and software:	3 years
Tools:	10 years
Equipment and machinery:	10 - 30 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 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 in wind farms, 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 the acquisition of subsidiaries. Goodwill represents the excess of the acquisition cost over the fair value of the equity interest in the acquired entity held by the company on the net identifiable assets acquired on the date of acquisition.

For impairment testing, goodwill acquired in a business combination is allocated from the acquisition date to each of the acquirer’s CGU or group of CGU that are expected to benefit from the synergies of the combination. Each unit or group of units that goodwill is allocated represents the lowest level within the entity at which the goodwill is monitored for internal management purposes.

4.7.2 Concession arrangements

Concession arrangements corresponding to hydroelectric generation plants Diamante and Nihuiles are not under the scope of the guidelines of IFRIC 12 “Service Concession Arrangements”.

These concession agreements meet the criteria set forth by the IFRSs for capitalization less depreciation a less any accumulated impairment. They are amortized following the straight-line method based on useful life, which corresponds to the life 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. Identified assets meet the criteria established in IFRS 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, considering the estimated way in which the benefits produced by the asset will be consumed.

4.7.4 Digital Assets

The Company accounts for digital assets (cryptocurrencies) as intangible assets with indefinite useful life under the cost model. They are recognised at acquisition cost less any accumulated impairment.

4.8 Assets for oil and gas exploration

The Company uses the successful efforts method of accounting for its oil and gas exploration and production activities. This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas exploration and production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of commercially recoverable reserves; (iii) the cost of drilling and equipping development wells, and (iv) the estimated asset retirement obligations (see Note 4.6.2).

According to the successful efforts method of accounting, exploration costs (including geological and geophysical costs), excluding exploratory well costs, are expensed during the period in which they are incurred. Drilling costs of exploratory wells are capitalized until it is determined that proved reserves exists and they justify the commercial development. If reserves are not found, such drilling costs are expensed. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is complete. In those cases, such costs continue to be capitalized insofar as the well has allowed determining the existence of sufficient reserves to warrant its completion as a production well and the Company is making sufficient progress in evaluating the economic and operating feasibility of the project.

4.9 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 impairment, 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.

4.10 Financial assets

4.10.1 Classification

The Group classifies its financial assets in the following categories:

(i) those that are subsequently measured at fair value, and

(ii) those that are subsequently measured at amortised cost.

The classification depends on the entity’s business model for managing the financial assets and the contractual cash flow characteristics.

Gains and losses from financial assets measured at fair value, will be recorded in the Statement of Comprehensive Income or in the Other Comprehensive Income.

Investments in equity instruments are measured at fair value. For those investments that are not held for trading, the Company may make an irrevocable election at initial recognition to present subsequent changes in other comprehensive income. The Company's election was to recognize changes in fair value through profit and loss.

The company reclassifies financial assets when and only when it changes its business model for managing those financial assets.

4.10.2 Recognition and derecognition

The conventional purchases and sales of financial assets are accounted for at settlement date. Financial assets are derecognised when contractual rights to the cash flows from the financial assets have expired or been transferred, and the Company has substantially transferred all risks and rewards of ownership of the asset.

4.10.3 Measurement

At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset.

A gain or loss on a debt investment that is subsequently measured at fair value and is not part of a hedging relationship is recognised in profit or loss and disclosed in “Changes in the fair value of financial instruments” within “Other financial Results. A gain or loss on a debt investment that is subsequently measured at amortized cost and is not part of a hedging relationship is recognised in profit or loss when the financial asset is derecognised or impaired and through the amortization process using the effective interest rate method.

The Group subsequently measures equity investments at fair value. Dividends from such investments continue to be recognised in profit or loss as long as they represent a return on investment.

4.10.4 Impairment of financial assets

The Company assesses the expected credit losses related to its financial instruments at amortized cost and financial instruments at fair value through other comprehensive income, if applicable.

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.

4.10.5 Offsetting of financial instruments

Financial assets and liabilities are offset, and the net amount reported in the consolidated statements of financial position, when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

4.11 Trade and other receivables

Trade receivables and other receivables are recognised at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognizes provisions for impairment on trade and other receivables based on expected credit loss model described in Note 4.10.4. Trade receivables are written off when there is no reasonable expectation of recovery. The Company considers the following default indicators: i) voluntary reorganization proceedings, bankruptcy or initiation of judicial demands; ii) insolvency implying a high impossibility of collection and iii) past due balances greater than 90 days.

Where 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.

4.12 Derivative financial instruments and hedging account

Derivative financial instruments are measured at fair value, determined as the amount of cash to be collected or paid to settle the instrument as of the measurement date, net of any prepayment collected or paid. Fair value of derivative financial instruments traded in active markets is disclosed based on their quoted market prices and fair value of instruments that are not traded in active markets is determined using different valuation techniques. Subsequent accounting of 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.

The Company may designate derivative financial instruments in the following categories:

(i) fair value hedge of recognised assets or liabilities or over firm commitment (fair value hedge);

(ii) cash flow hedges of a particular risk associated with recognised assets and liabilities and highly probable future transactions (cash flow hedges), or

(iii) net investment hedge in foreign operation (net investment hedges).

At the beginning of the hedge relationship, the Group documents the economic relationship between the hedging instruments and the hedged items, even if it is expected that changes in the cash flows of the hedging instruments offset changes in the cash flows of the hedged items. The Group documents its objective and risk management strategy to carry out its hedging operations.

Changes in the measurement of derivative financial instruments designated as cash flow hedge, which have been determined as effective, are recognised in equity. The gain or loss related to the ineffective portion is recognised immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognised in profit or loss.

The Company has not formally designated financial instruments as hedging instruments.

4.13 Inventories

This line item includes crude oil stock, raw materials, work in progress and finished products relating to Petrochemicals and Oil and Gas business segments as well as materials and spare parts relating to the Generation business segment.

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average price method. The cost of inventories 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 assessment of the recoverable value of these assets is made at each reporting date, and the resulting loss is recognised in the statement of income when the inventories are overstated.

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”.

4.14 Non-current assets (or disposal group) held for sale and discontinued operations

Non-current assets are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights from insurance contracts, which are specifically exempt from this requirement.

An impairment loss is recognized for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset (or disposal group), but not in excess of any cumulative impairment loss previously recognized. The gain or loss not previously recognized by the date of the sale of the non-current asset is recognized at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised.

Non-current assets or group of assets classified as held for sale are presented separately from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the balance sheet. These assets and liabilities are not offset.

If it is a discontinued operation, that is, an item which has been disposed of or classified as held for sale; and (i) it represents a significant business line or geographic area which may be considered separate from the rest; (ii) it is part of a single coordinated plan to dispose of a significant business line or operating geographic area which may be deemed separate from the rest; or (iii) it is a subsidiary entity acquired solely for the purpose of reselling it; a single amount is disclosed in the statement of comprehensive income, which shows results of discontinued operations, net of tax, including the result for the valuation at fair value less cost of sales or asset disposal costs, if applicable.

4.15 Cash and cash equivalents

For the purpose of presentation in the Consolidated Statement of Cash Flows, cash and cash equivalents includes 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 in the Consolidated Statement of Financial Position 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.

4.16 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 have been restated in terms of the measuring unit current as of December 31, 2018, with the exception of Share capital and Treasury shares, which represent the subscribed and paid in, and the outstanding treasury capital, respectively. The adjustment resulting from its restatement as of December 31, 2018 is disclosed in the Comprehensive share capital adjustment and Comprehensive treasury shares adjustment lines, respectively.

As from the change in functional currency, on January 1, 2019 the Company discontinued the preparation and presentation of financial statements under IAS 29, and has considered equity figures expressed in terms of the measuring unit current as of December 31, 2018 as the basis for subsequent financial statements’ amounts. 

4.16.1 Share capital

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.

4.16.2 Share premium

It 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 or significant influence.

(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.

4.16.3 Legal reserve

In accordance with the Argentine Commercial Companies General Law, 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.

4.16.4 Voluntary reserve

This reserve results from an allocation made by the Shareholders’ Meeting, whereby a specific amount is set aside to cover for the funding needs of projects and situations associated with Company policies. 

4.16.5 Other reserves

It includes the result of operations with non-controlling interest that do not result in a loss of control and reserves for stock compensation plans. 

4.16.6 Retained earnings

Comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of Shareholders' meeting, as long as they are not subject to legal restrictions. Earnings comprise current earnings, prior years' earnings that were not distributed, translation differences which are directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4, the amounts transferred from other comprehensive income and prior years' adjustments, according to IFRS.

General Resolution No. 593/11 issued by the CNV provided that Shareholders in the Meetings at which they should decide upon the approval of financial statements in which the Retained earnings account has a positive balance, should adopt an express resolution as to the allocation of such balance, whether to dividend distribution, capitalization, setting up of reserves or a combination of these. The Company’s Shareholders have complied with these requirements.

4.16.7 Other comprehensive income

It 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 and actuarial gains and losses for defined benefit plans and the related tax effect.

4.16.8 Dividends distribution

Dividend distribution to Company shareholders is recognised 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.

4.17 Compensation plans

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

4.17.1 Compensations payable in cash:

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 over the Company’s adjusted operating income. With the purpose of avoiding duplication, any analogous compensation paid to senior managers by any of the Company’s subsidiaries will be deducted from the compensation amount in proportion to the Company’s interests in such subsidiaries. 

The reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton financial valuation 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. 

4.17.2 Compensations payable in shares

Stock compensation plan by which certain officers and other key staff receive a certain number of the Company’s shares. The Company’s Board of Directors approves the market acquisition of own shares as a means of implementing the Plan (see Note 13.1.2).

The number of shares is calculated as from a percentage over the total annual remuneration, plus the bonus assigned to each covered employee, 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.

4.18 Trade payables and other payables

Trade payables and other payables are recognised initially at fair value and subsequently measured at amortized cost using the effective interest method.

4.19 Borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings, using the effective interest method.

Borrowings are removed from the statement of financial position when the obligation specified in the contract is discharged, canceled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in profit or loss as other income or finance costs.

If a debt contract is amended or swapped, the Company records the cancellation of the original liability and discloses 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. 

4.19.1 Borrowing costs

General and specific borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalized during the period of time that is required to complete and prepare the asset for its intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalization.

Other borrowing costs are expensed in the period in which they are incurred.

4.20 Employee benefits

4.20.1 Short-term obligations

Payroll liabilities, including non-monetary benefits and accumulated sick leave expected to be settled in full within 12 months after the end of the reporting period in which the employees provide the associated service are recognised for the amount expected to be paid when the liabilities are settled. The liabilities are disclosed as Salaries and social security payable in the consolidated statement of financial position.

4.20.2 Defined benefit plans

Labor costs liabilities are accrued in the periods in which the employees provide the services that trigger the consideration.

Additionally, the Company operates several 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).

4.21 Provisions, contingent liabilities and contingent assets

Provisions are recognised when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle that obligation, and the amount can be reliably estimated. Provisions are not recognised for future operating losses.

Provisions are measured at the present value of the expenditures expected to be required to settle the present obligation, taking into account the best available information as of the date of the Consolidated Financial Statements based on assumptions and methods considered appropriate and taking into account the opinion of Company’s legal advisors. As additional information becomes available to the Company, estimates are revised and adjusted periodically. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability, as of the date of the financial statements. The increase in the provision due to the passage of time is recognised within other financial results.

Contingent liabilities are possible obligations that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity; or present obligations that arise from past events but it is not probable that an outflow of resources will be required to its settlement; or whose amount cannot be measured with sufficient reliability.

Contingent liabilities are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent liabilities.

Contingent liabilities, whose possibility of any outflow in settlement is remote, are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Contingent assets are possible assets that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity.

Contingent assets are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent assets, where the related inflows of economic benefits are estimated to be probable.

4.22 Revenue from contracts with customers

4.22.1 Generation segment:

4.22.1.1 Revenues from sales to the spot market (SE Resolution N°826/22)

The Company recognizes revenues from i) power availability on a monthly basis as the different power plants are available to generate; ii) power generated, operated energy and power generated in peak hours, when the delivery of energy is effective, based on the price applicable depending on the technology of each plant. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 42 days, which is consistent with market practice.

4.22.1.2 Revenues from supply agreements with CAMMESA (SE Resolution No. 220/07, SEE Resolution No. 21/16, SEE Resolution No. 287/17 and Renovar Programs)

The Company recognizes revenues from supply contracts with CAMMESA for i) power availability, when applicable, on a monthly basis, as the different power plants are available to generate and ii) energy generated when the delivery of energy is effective, 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 credit term of 42 days, which is consistent with market practice.

4.22.1.3 Revenues from sales contracts with large users within the MAT

The Company recognizes revenues from energy plus sales and renewable energy when the delivery of energy is effective 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 credit term of 30 days, which is consistent with market practice. 

4.22.2 Oil and gas segment

The Company recognizes revenues from the sale of oil and gas, to third parties and intersegment, 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 could affect the acceptance of the product by the client. In all cases the transport of the gas is in charge of the client. Revenues from these sales are recognised based on the price by product specified in each contract or agreement 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 credit term not exceeding 45 days, which is consistent with market practice.

4.22.3 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 products according to the sale contract, the acceptance provisions have expired, 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 credit term not exceeding 30 days, which is consistent with market practice.

4.22.4 Holding 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.

4.23 Other Income

4.23.1 Government grants

Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. The group did not benefit directly from any other forms of government assistance.

The Company recognizes revenues from natural gas production promotion or stimulus programs upon the actual delivery of gas and in accordance with the price established in the applicable regulation, only inasmuch as it is highly probable that there will be no significant reversal and the consideration is likely to be received, that is, to the extent that the procedure defined by the Government is formally complied with.

The recognition of revenues associated with Natural Gas Production Promotion or Stimulus Plans (see Note 2.2.4.1) falls within the scope of IAS 20 as it involves a compensation as a result of the maintenance or increase in the committed production volume.

Revenues from natural gas production or stimulus programs are disclosed under other operating income in the consolidated statement of comprehensive income. Furthermore, the fiscal costs of the above-mentioned programs are disclosed under Other operating expenses in the consolidated statement of comprehensive income. 

4.23.2 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 cost and financial assets at fair value through other comprehensive income 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.

4.23.3 Dividends

Dividends income are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognised as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

4.24 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, in which case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet. 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.

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. However, deferred tax liabilities are not recognised if they come from the initial recognition of goodwill; or if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at time of the transaction affects neither accounting nor taxable profit or loss.

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 Law No 27,701, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1).

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 have not been discounted and are stated at their nominal value.

Income tax rates prevailing at year-end in Argentina (see Note 2.6.1), Ecuador, Bolivia and Uruguay are 35%, 25%, 25% and 25%, respectively. Additionally, a 3% surcharge is added to Ecuador’s income tax when the company’s shareholder residing in Ecuador is an entity established in a jurisdiction considered a tax haven under Ecuadorian laws.

In Bolivia, payment of Bolivian-source income to beneficiaries outside Bolivia is levied with a 12.5% withholding income tax. Furthermore, and pursuant to the last tax reform passed in Ecuador and effective as from January 1, 2020, dividends distributed to foreign shareholders will be subject to a 10% withholding.

In Uruguay, effective from January 1, 2023, the Income Tax on Economic Activities (“IRAE”) covers certain Uruguayan-source passive income derived by entities making up multinational groups.

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.

4.25 Leases

In leases where the Company is a lessee (Note 19.1), a right-of-use asset and a lease liability are recognised on the date on which the underlying asset is available for use by the Company.

At the commencement date the lease liability is measured at the present value of the payments that are not paid at that date, including:

- fixed payments, less any lease incentive receivable

- variable lease payments depending on an index or rate

- amounts that the Company expects to pay under residual value guarantee

- exercise price of a purchase option (if the Company is reasonably certain to exercise that option), and

- penalty payments for terminating the lease, if the lease term reflects the Company exercising that option.

Lease payments are discounted using the Company’s incremental borrowing rate, which is the rate the Company would have to pay to borrow over a similar term, security and conditions, the funds necessary to acquire an asset of a similar value to the right-of-use asset in a similar economic environment, or by using the interest rate implicit in the lease, if that rate can be readily determined.

The lease liability is disclosed in “Trade and other payables”. Each lease payment is apportioned between the principal and the financial cost. The financial 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.

Right-of-use assets are measured at cost, which comprises:

- the amount of the initial measurement of the lease liability

- any lease payment made at or before the commencement date, less any lease incentive received

- any initial direct cost, and

- an estimate of costs to be incurred for decommissioning or restoring the underlying asset pursuant to the terms and conditions of the lease

Right-of-use assets are depreciated using the straight-line method over the asset’s useful life or, if shorter, during the lease term.

The Company recognizes lease payments associated with short-term leases (up to 12 months) and leases for which the underlying asset is of low value (IT equipment and office supplies) as an expense using the straight-line method over the lease term.

Leases in which the Company, as a lessor, has transferred all risks and rewards incidental to ownership of the underlying asset are classified as financial leases (Note 19.2.1). Financial leases are recognised at the commencement date 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”. Each lease payment received is allocated between income receivable and financial income. Financial income is recognised as a profit over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period. Property under financial leases is derecognised if there is reasonable certainty that the Company will transfer its ownership at the end of the lease term.

Leases in which the Company does not transfer a significant part of the risks and rewards incidental to ownership of the underlying asset are classified as operating leases. Revenues from associated leases are recognized in income using the straight-line method over the term of the lease (Note 19.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

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GROUP STRUCTURE

12 Months Ended

Dec. 31, 2022

Group Structure

GROUP STRUCTURE

NOTE 5: GROUP STRUCTURE

5.1 Acquisition and sale of equity interests

5.1.1 Sale of equity interests of controlling stake in Edenor

On December 28, 2020, the Company entered into with Empresa de Energía del Cono Sur S.A. and Integra Capital S.A., Daniel Eduardo Vila, Mauricio Filiberti and José Luis Manzano (the “Purchaser”) a share purchase agreement whereby it agreed to sell its controlling interest in Edenor through the transfer of all Class A shares representing 51% of the capital stock and voting rights of said company (the “Transaction”). On February 17, 2021, Pampa’s shareholders meeting was held and the Transaction was approved.

On June 24, 2021, the ENRE approved the Transaction through Resolution No. 207/21, whereas, after meeting the precedent conditions, the transaction closing took place on June 30, 2021, with the transfer of shares and the change of controlling shareholder.

The agreed sales price consisted of: 21,876,856 Class B shares of Edenor, representing 2.41% of Edenor’s capital stock and voting rights, transferred upon the execution of the share purchase agreement; and US$ 95 million in cash, which was paid in 3 installments: (i) US$ 5 million upon the execution of the share purchase agreement; (ii) US$ 50 million on the closing date; and US$ 40 million, plus interest at a 10% fixed nominal annual rate (payable quarterly), between June and July 2022.

Within the previously described framework and pursuant to IFRS 5, and considering that the transaction involved loss of control over the subsidiary, all Edenor’s assets and liabilities had been classified as held for sale as of December 31, 2020 and had been measured at the lower between its fair value, net of costs associated with the sale, if applicable, and its book value, which involved the recognition of an impairment loss for US$ 589 million, included together with the results corresponding the Distribution of energy segment under “Discontinued operations” of the Consolidated Statement of Comprehensive Income for the years ended December 31, 2021 and 2020.

The statement of comprehensive income associated with the discontinued operations is disclosed below:

	Distribution of Energy
	12.31.2021	12.31.2020
Revenue	493	1,085
Cost of sales	(398)	(926)
Gross profit	95	159
Selling expenses	(36)	(79)
Administrative expenses	(26)	(64)
Other operating income	21	29
Other operating expenses	(18)	(25)
Reversal of property, plant and equipment impairment	16	(589)
Impairment of financial assets	(11)	(50)
Operating income (loss)	41	(619)
Gain on monetary position, net	120	115
Financial income	-	1
Financial costs	(106)	(110)
Other financial results	8	(20)
Financial results, net	22	(14)
Profit (Loss) before income tax	63	(633)
Income tax	(138)	41
Loss of the year from discontinued operations	(75)	(592)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans	-	1
Exchange differences on translation	34	(15)
Items that may be reclassified to profit or loss
Exchange differences on translation (1)	30	(19)
Other comprehensive income (loss) of the year from discontinued operations	64	(33)
Total comprehensive loss of the year from discontinued operations	(11)	(625)
Total  (loss) profit of the year from discontinued operations attributable to:
Owners of the company	(39)	(499)
Non - controlling interest	(36)	(93)
	(75)	(592)
Total comprehensive loss of the year from discontinued operations attributable to:
Owners of the company	(9)	(517)
Non - controlling interest	(2)	(108)
	(11)	(625)

⁽¹⁾ As of December 31, 2021, corresponds to the reclassification adjustment for exchange differences losses included in profit or loss on Edenor disposal. No exchange differences losses on translation were reconized during 2021.

The consolidated statement of cash flows related to discontinued operations as of December 21, 2021 and 2020 is presented below:

	Distribution of Energy
	12.31.2021	12.31.2020
Net cash generated by operating activities	116	211
Net cash used in investing activities	(166)	(86)
Net cash used in financing activities	(7)	(73)
(Decrease) Increase in cash and cash equivalents from discontinued operations	(57)	52
Cash and cash equivalents at the beginning of the year	52	9
Effect of devaluation and inflation on cash and cash equivalents	5	(9)
(Decrease) Increase in cash and cash equivalents	(57)	52
Cash and cash equivalents at the end of the year	-	52

5.1.2 Sale of equity interests in Refinor

On September 15, 2022, the Company entered into an agreement with Hidrocarburos del Norte S.A. for the sale of its Class A shares representing 28.5% of Refinor’s capital stock for a price of US$ 5.7 million, subject to the fulfillment of certain precedent conditions.

As of September 30, 2022, in accordance with IFRS 5 and since the transaction price was below the carrying amount, the Company recognised impairment losses, before taxes, for US$ 11 million, which are disclosed under “Share of profit from associates and joint ventures”.

On October 14, 2022, with the precedent conditions being met, the Company transferred such shares. As of the date of issuance of these Consolidated Financial Statements, the Company has collected US$ 1.7 million, and the amount of US$ 4 million is pending collection, to be financed over one year from the date of sale at an 8% nominal annual fixed interest rate in accordance with the share acquisition agreement.

5.1.3 Acquisition of an additional 50% interest in Greenwind

On August 12, 2022, Vientos Solutions L.L.C., Rio River Capital L.L.C and the Group entered into a share acquisition agreement whereby it acquired, for the amount of US$ 20.5 million, the whole equity interest in VS SLU, a Spanish company which main asset is its 50% interest in Greenwind’s capital stock.

On the acquisition date, the Company recorded profits of US$ 23.3 million to reflect the fair value of the 50% stake in Greenwind prior to the aforementioned acquisition, as this transaction is a business combination achieved in stages.

The following table details the fair value of the consideration transferred and the fair values of the assets acquired and the liabilities assumed as of August 12, 2022:

	In million US$
Consideration transferred	(20.5)
Fair value of the previous interest in Greenwind	(20.4)
Total	(40.9)
Property, plant and equipment (1)	127.7
Intangible assets - Customer contract (2)	31.6
Financial assets at fair value	24.4
Trade receivables (3)	6.3
Other assets	0.1
Cash and cash equivalents	3.1
Borrowings	(89.3)
Deferred tax liabilities	(54.3)
Income tax liabilities	(4.4)
Trade and other payables	(2.0)
Provisions	(1.4)
Tax liabilities	(0.9)
Total acquisition price allocation (4)	40.9

⁽¹⁾ Mario Cebreiro Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Expenses related to the acquisition transaction were non-significant, therefore they were recognised as expenses in fiscal year result.

The acquisition contributed to the Group revenues from sales for US$ 11.3 million and net earnings for US$ 3.5 million for the August 12 - December 31, 2022 period.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,844 million and US$ 459 million, respectively. The pro forma information was calculated based on the Company and Greenwind’s results.

The Company paid US$ 20.5 million for the acquisition of the additional equity interest which, net of the cash and cash equivalents balance of US$ 3.1 million, results in a net cash flow of US$ 17.4 million, which is disclosed in the consolidated statement of cash flows in the item “Payment for the acquisition of subsidiaries and associates” under investment activities.

5.1.4 Acquisition of Autotrol Renovables S.A.

On September 30, 2022, the Company acquired 100% of the capital stock of Autotrol Renovables S.A., an entity holder of the “Wayra I Wind Farm” project (registered with the National Renewable Energy Projects Registry, “RENPER”) for a price of US$ 50 thousand.

5.1.5 Acquisition of VAR

On December 12, 2022, Parque Eólico Arauco S.A.P.E.M. (“PEA”) and the Company executed an agreement to acquire 100% of VAR’s capital stock. This company is exclusively engaged in electric power generation in the domestic market through the operation of Arauco II Wind Farm, with a 99.75 MW capacity, at a price of US$ 171 million, including the takeover of a US$ 46 million interest liability recorded in VAR and payable by PEA in 12 consecutive monthly installments as from transaction closing.

Upon the meeting of the precedent conditions, on December 16, 2022, PEA transferred VAR’s shares, and the Company paid US$ 128.1 million, an amount that considers the working capital adjustment estimated on that date. The amount paid is currently under review by the Company and PEA in accordance with the processes established in the share purchase agreement to assess the amount of VAR’s working capital adjustment as of closing. The following table details the fair value of the consideration transferred, and the fair values of the assets acquired and liabilities assumed as of, December 16, 2022:

	In million US$
Consideration transferred	(128.1)
Estimated price adjustment	6.7
Total	(121.4)
Property, plant and equipment (1)	167.7
Intangible assets - Customer contract (2)	62.3
Trade receivables (3)	4.9
Other receivables	1.2
Deferred tax liability	(60.2)
Income tax liability	(5.0)
Trade and other payables	(3.3)
Other payables	(46.0)
Tax liabilities	(0.2)
Total acquisition price allocation (4)	121.4

⁽¹⁾ Arauco Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Expenses related to the acquisition transaction were non-significant, therefore they were recognised as expenses in fiscal year result.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,858 million and US$ 448 million, respectively. The pro forma information was calculated based on the Company and VAR’s results.

The Company paid US$ 93.2 million for the acquisition of the equity interest, which is disclosed in the consolidated statement of cash flows in the item “Payment for the acquisition of subsidiaries and associates” under investment activities. In addition, the Company made a partial payment by delivering public securities for US$ 34.9 million which is disclosed in the consolidated statement of cash flows in the item “significant non-cash transactions” (see Note 14.3).

5.2      Interest in subsidiaries, associates and joint ventures

5.2.1 Subsidiaries information

Unless otherwise indicated, the capital stock of the subsidiaries consists of common shares, each granting the right to one vote. The country of the registered office is also the principal place where the subsidiary develops its activities.

			12.31.2022	12.31.2021
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Autotrol Renovable S.A. (1)	Argentina	Generation	100.00%	-
GASA	Argentina	Generation	100.00%	100.00%
Enecor S.A.	Argentina	Electricity transportation	70.00%	70.00%
Fideicomiso CIESA	Argentina	Investment	100.00%	100.00%
Greenwind (3)	Argentina	Generation	100.00%	50.00%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
CISA	Argentina	Trader & investment	100.00%	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PB18	Ecuador	Oil	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Pampa Ecuador Inc	Ecuador	Investment	100.00%	100.00%
PE Energía Ecuador LTD	Gran Cayman	Investment	100.00%	100.00%
EISA	Uruguay	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
TGU	Uruguay	Gas transportation	51.00%	51.00%
Corod (3)	Venezuela	Oil	-	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
Vientos de Arauco Renovables S.A.U. (4)	Argentina	Generation	100.00%	-
Vientos Solutions Argentina S.A.U.	Argentina	Advisory services	100.00%	-
VS S.L. (2)	España	Investment	100.00%	-

⁽¹⁾ See Note 5.1.4.

⁽²⁾ See Note 5.1.3.

⁽³⁾ Interest assigned under the assignment of the indirect interest in the capital stock of mixed companies in Venezuela. See Note 5.3.2.

⁽⁴⁾ See Note 5.1.5.

5.2.2 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:

		Information about the issuer
	Main activity	Date	Share capital	Profit (loss) of the  year	Equity
Associates
OCP	Investment	12.31.2022	100	(4)	96
TGS (1)	Gas transportation	12.31.2022	4	182	1,508
Joint ventures
CIESA (1)	Investment	12.31.2022	4	93	770
Citelec (2)	Investment	12.31.2022	3	5	235
CTB	Generation	12.31.2022	48	53	536

⁽¹⁾ The Company holds a direct and indirect interest of 3.764% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, additionally the Company has an indirect participation of 25.50% in TGS.

As of December 31, 2022, the quotation of TGS's ordinary shares and ADR published on the Buenos Aires Stock Exchange and the NYSE was $ 811.05 and US$ 11.80, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of $ 188,568 million.

⁽²⁾ The Company holds a 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, 2022, Transener’s common share price listed at the Buenos Aires Stock Exchange was $ 184,50, conferring Pampa’s indirect interest an approximate $ 21,598 million market value.

The details of the balances of investments in associates and joint ventures are as follows:

	12.31.2022	12.31.2021
Disclosed in non-current assets
Associates
Refinor (1)	-	22
OCP	15	24
TGS	67	52
Total associates	82	98
Joint ventures
CIESA	435	347
Citelec	117	102
CTB	268	227
Total joint ventures	820	676
Total associates and joint ventures	902	774
Disclosed in non-current liabilities
Joint ventures
Greenwind	-	(4)
Total joint ventures	-	(4)

⁽¹⁾ See Note 5.1.2.

The following tables show the breakdown of the share of profit from associates and joint ventures:

	12.31.2022	12.31.2021	12.31.2020
Associates
Refinor	(12)	(2)	(2)
OCP	(1)	18	(5)
TGS	7	7	1
Total associates	(6)	23	(6)
Joint ventures
CIESA	43	50	11
CTB	41	49	64
Citelec	3	(3)	13
Greenwind (1)	24	(2)	3
Total joint ventures	111	94	91
Total associates and joint ventures	105	117	85

⁽¹⁾ See Note 5.1.3.

The evolution of investments in associates and joint ventures is as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	770	547	507
Compensation	-	-	(5)
Dividends	(8)	-	(34)
Increases	1	17	3
Decrease due to acquisition of control (1)	(20)	-	-
Decrease due to sale of equity interests  (2)	(6)	-	-
Share of profit	116	117	85
Impairment (2)	(11)	-	-
Exchange differences on translation	60	89	(9)
At the end of the year	902	770	547

⁽¹⁾    See Note 5.1.3.

⁽²⁾    See Note 5.1.2.

5.2.3 Investment in CTB

On June 26, 2019. the acquisition by CTB, a company co-controlled by YPF and Pampa, of CTEB's goodwill was perfected, which is located at the petrochemical complex of the town of Ensenada, Province of Buenos Aires, consists of two open-cycle gas turbines, and has a 567 MW installed capacity.

CTB committed to obtain the commissioning of the closing of the combined cycle increasing the installed power capacity to 847 MW.

Both the open and the closed cycle have effective power purchase agreements with CAMMESA under Resolution SE No. 220/07: the first one, entered into on March 26, 2009 which expired on April 27, 2022, and the second one dated March 26, 2013 for a term of 10 years as from the commercial operation of the combined cycle, which stared operations on February 22, 2022. Moreover, energy not committed under contracts with CAMMESA is remunerated at the spot market.

CTEB will be managed and operated by Pampa and YPF on a rotational basis over 4-year periods. Pampa is responsible for managing CTEB’s operations until mid-2023. And YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for the closing of the combined cycle.

5.2.3.1 Financial Trust Agreement

As a result of the award of CTEB’s goodwill, certain amendments were made to the Enarsa-Barragán Financial Trust Agreement entered into between BICE Fideicomisos S.A. (Nación Fideicomisos S.A.’ continuing company), acting as Trustee, and CTB, in its capacity as Trustor substituting IEASA (former ENARSA) (the “Trust Agreement” or the “Trust”).

Under the Trust, on April 25, 2011 publicly traded Series B VRD for a face value of 582,920,167 were issued. The Trust’s underlying flow is made up of the collection rights resulting from the power supply agreements originally entered into between ENARSA (currently IEASA) and CAMMESA.

On June 26, 2019 and October 16, 2020, CTB made a partial early redemption of 109,628,836 and 275,053,045 outstanding Series B VRD, which were canceled on October 29, 2019 and December 4, 2020, respectively.

Finally, on December 17, 2021, CTB performed the total early redemption of 198,238,286 VRD for a total amount of US$ 94 million. As of the issuance of these Consolidated Financial Statements, the VRD have been canceled and the Trust has been liquidated.

5.2.3.2 Syndicated loan

On June 25, 2019, in order to partially finance the obligations undertaken as a result of the award and execution of the works for the closing of the combined cycle at CTEB, Citibank, N.A., Banco de Galicia y Buenos Aires S.A.U., Banco Santander Río S.A., HSBC Bank Argentina S.A. and Industrial and Commercial Bank of China (Argentina) S.A., in their capacity as lenders (the “Lenders”), granted a syndicated loan to CTB in the amount of US$ 170 million maturing on June 26, 2022, with US$ 136 million accruing a fixed 10.25% interest rate and US$ 34 million accruing a variable LIBOR rate+6.25.

On March 25, 2022 CTB and the lenders executed a amendment to the agreement modifying the loan repayment scheme in its variable interest rate tranche, with a new maturity on October 1, 2022, and changing the reference rate from LIBOR to SOFR.

During the fiscal year ended December 31, 2022, CTB has repaid at maturity the amount of US$ 74,4 million of the syndicated loan´s remaining installments.

5.2.3.4 Global Program of CB

On July 23, 2020, CTB’s Extraordinary General Shareholders’ Meeting resolved to approve the creation of a global program of simple corporate bonds non-convertible into shares for up to US$ 200 million or its equivalent in other currencies or units of value, and the issuance of corporate bonds under such program up to its maximum amount, at any time, to be issued in one or more classes and/or series, which authorization was granted by the CNV on September 24, 2020.

5.2.3.5 Issuance of CB

On June 4, 2021, CTB issued: (i) Class 1 CB for a total amount of US$ 27.3 million, accruing interest at an annual fixed rate of 4% and maturing on June 4, 2023; and (ii) Class 2 CB for a total amount of 37,504,954 units of purchasing power (“UVA”), adjustable by the Reference Stabilization Coefficient (CER), equivalent to $2,928 million, accruing interest at a fixed 4% rate and maturing on June 4, 2024.

On August 18, 2021, CTB reopened (i) Class 1 CB for a total amount of US$ 15.6 million at an issue price of 101.7050%; and (ii) Class 2 CB for a total amount of 27.9 million UVA at an initial value of $84.76 per UVA at an issue price of 100.82%.

On November 26, 2021, CTB issued Class 4 CB for a total amount of US$ 96 million, accruing interest at an annual 0% fixed rate and maturing on November 26, 2024.

On May 16, 2022, CTB issued: (i) Class 6 CB for a total amount of US$ 25 million at a fixed annual 0% rate maturing on May 16, 2025; and (ii) Class 7 CB for a total amount of $ 1,754 million accruing interest at a variable BADLAR rate plus an annual 2.98% spread and maturing on November 16, 2023.

On August 22, 2022, CTB issued Class 8 CB for a total amount of $ 4,235 million, accruing interest at a variable BADLAR rate plus a 1.00% annual spread and maturing on February 22, 2024.

Finally, on December 12, 2022, CTB reopened additional Class 6 CB for a total amount of US$ 58.6 million accruing interest at an annual 0% fixed rate and maturing on May 16, 2025. With the reopening of Class 6 CB, which were subscribed and paid in cash and in-kind through the delivery of Class 1 CB, Class 1 CB with a fair value of US$ 10.7 million were partially canceled, with a US$ 32.2 million outstanding face value.

All CB are secured by a personal guarantee subject to a precedent and subsequent condition granted by YPF and Pampa.

As of the date of issuance of these Consolidated Financial Statements, CTB is in compliance with all the covenants under its debt agreements.

5.2.3.6 Closing to combined cycle project

CTB’s closing to combined cycle commitment to increase its installed capacity from 567 MW to 847 MW has been affected from its beginning by the evolution of the measures associated with the COVID-19 pandemic. The stiffening of social lockdown measures from July 1, 2020 excluded private infrastructure works from the exempted activities. Later on, pursuant to Resolutions No. 1197-MJGM-2020 and No. 1690-MJGM-2020 issued by the Buenos Aires Chief of the Cabinet of Ministers’ Office, as amended, CTB resumed the execution of construction works following their critical path from July 20, 2020.

Within this framework, on July 28, 2020, the Company and the Joint Venture made up of SACDE Sociedad Argentina de Construcción y Desarrollo Estratégico S.A. and Techint Compañía Técnica Internacional S.A.C.E.I. entered into an addendum to the construction agreement within the framework of the restrictions imposed as a result of the COVID-19 pandemic, reaching an agreement on the impact on costs and works’ execution terms, and launching a new stage for the execution of the closing to combined cycle.

The evolution of the Argentine Government’s measures to contain the spread of COVID-19 in 2020 and 2021 has affected the works execution progress, delaying the term initially planned for commissioning and generating several instances of review in the schedule and the scope of the tasks necessary to complete the works, with the resulting increase in associated costs. Moreover, exchange and customs restrictions have impacted costs and terms for the supply of foreign equipment.

Given the problems in the normal execution of the project affecting the works’ terms and costs, on July 1, 2022, CTB and the Joint Venture made up by SACDE and Techint Compañía Técnica Internacional S.A.C.E I. entered into a new addendum to the construction agreement, which mainly stipulated as follows: (i) a new work schedule to reach the combined cycle’s commissioning; and (ii) the recognition in favor of the Joint Venture of the right to an US$8 million compensation on account of the incurred term and cost variations.

On January 27, 2023, CTB has launched the CC and on February 22, 2023, it stared operations under the supply agreement with CAMMESA.

5.2.3.7 Impairment of non-financial assets

Spot market prices were modified in May 2021 by SE Resolution No. 440/21, which, although providing for a 29% increase in remuneration, permanently abrogated the application of the automatic adjustment mechanism. This impacted the future flows collectible by CTB after the termination, in the year 2022, of the supply agreement with CAMMESA that remunerates the units making up the open cycle. Additionally, in 2020 and 2021 the progress of works for CTB’s closing to combined cycle was affected by the measures implemented to contain the COVID-19 spread, delaying the scheduled term for commissioning and increasing the costs associated with the completion of the project.

In view of these indications, CTB determined the estimation of the recoverable amount as of December 31, 2022 and 2021.

The methodology used in the estimation of the recoverable amount consisted of calculating the present value of future net cash flows expected to be generated by the CGU, discounted with a rate reflecting the weighted average costs of the capital employed.

The projections used by CTB in the calculation of the recoverable amount as of December 31, 2022 take into consideration 2 scenarios that weigh: i) the entry into effect of the new supply agreement with CAMMESA for the combined cycle in the first quarter of 2023; ii) the periodic price update in line with inflation for the spot remuneration; iii) the recognition of a long-term differential remuneration allowing to make the investments necessary to maintain availability and improve the open cycle’s efficiency; iv) the regularization of the financing term granted to CAMMESA in 2024; and v) an 11.7% after-tax WACC rate.

As of December 31, 2022, and 2021, CTB has not recorded any impairment losses as a result of the performed recoverability assessment.

5.2.4 Investment in OCP

The Company, through PEB, has an equity interest in OCPSA, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.

On August 12, 2021, the Company, through its subsidiary PEB, executed an agreement with Occidental International Exploration and Production Company for the acquisition of all the shares of Occidental del Ecuador Inc. (currently Pampa Ecuador Inc.) for US$ 5 million. Pampa Ecuador Inc. holds a 14.15 % equity interest in OCP.

The closing of the transaction involved the recognition of profits for US$ 17.2 million, under IAS 28. The following table details the consideration, the fair value of the acquired assets, and the profit recorded by the Company as of August 12, 2021:

	In million US$
Acquisition cost	(5.0)
Total consideration	(5.0)
Share value of the interest in the fair value of OCP’s identifiable assets and liabilities (1)	12.7
OCP dividends to be received	9.5
Assets fair value	22.2
Profit (2)	17.2

⁽¹⁾ Calculated based on the present value of expected dividend flows.

⁽²⁾ Disclosed under “Share of profit from associates and joint ventures”.

On August 12, 2021, PEB recorded an impairment reversal of US$ 1.6 million, on the interest in OCP, prior to the aforementioned acquisitions, in relation to the estimation of the present value of the future cash flows that were expected to be obtained through the collection of dividends considering the concession term and a discount rate of 15.09 %.

The termination of the oil pipeline concession agreement is scheduled for January 12, 2024, considering the term extension resulting from the suspension of the contractual obligations due to force majeure events. On that date, OCP will transfer and deliver to the Ecuadorian Government or its designee all OCPSA’s shares at no cost, as well as the titles and rights over the oil pipeline’s assets. As of the issuance of these Consolidated Financial Statements, OCPSA is executing the actions defined in the contract to meet the transfer plan.

5.2.4.1 Recoverable value of the investment

The erosion process in the Quijos River course, in the San Rafael sector, on the border of the provinces of Sucumbíos and Napo, Ecuador, caused two force majeure events consisting of the rupture of different oil pipeline tranches and the resulting temporary suspension of the crude oil pumping in 2020 and 2021.

Additionally, on January 28, 2022, a new force majeure event occurred due to a stone landslide causing the pipeline’s rupture at KP96+526. OCPSA started the repairs of the affected pipeline and cleanup and remediation works. The crude oil transportation service was resumed on February 7, 2022.

PEB has performed recoverable amount tests for its investment in OCP as of December 31, 2021, considering the present value of the future cash flows it expects to obtain through the collection of dividends during the concession term, the term extension due to the suspension of contractual obligations resulting from the detailed Force Majeure events and a discount rate of 17.12%. PEB has not recorded any impairment losses as a result of the recoverability assessment performed as of December 31, 2021, and, as of December 31, 2022, has identified no additional indications that may impact the assumptions taken into consideration in the aforementioned assessment.

It is worth highlighting that on February 22, 2023, after the end of the fiscal year, a force majeure event occurred due to the collapse of the bridge over the Marker River, located in El Choco canton, Napo Province. In order to guarantee the continuity of the pipeline’s operations and avoid an environmental incident, OCPSA suspended crude oil pumping and started the complete drainage of the pipeline at KP96+075. Additionally, OCPSA notified the occurrence of the previously mentioned event to the Ministry of Energy and Mines. The crude oil transportation service was resumed on March 2, 2023.

5.2.4.2 Contingent liabilities in OCP

Several organizations and natural persons filed a constitutional protection proceeding against OCPSA, as well as the Ministry of Energy, the Ministry of the Environment and Water, Petroecuador and the Ministry of Health, alleging the infringement of several constitutional rights regarding the force majeure event consisting of the land subsidence and sliding at the Quijos River course, which resulted in the rupture of the pipeline at KP 93+469 in 2020. The safeguard action has been disallowed in the first and second instances by Orellana’s Provincial Court of Justice. As of the date of issuance of these Consolidated Financial Statements, the plaintiffs have filed a constitutional protection proceeding, which has been admitted to be heard by the Constitutional Court.

OCPSA's Management together with its legal advisors have classified an unfavorable ruling as remote, therefore, no provision has been recognized on this matter.

5.2.5 Investment in CITELEC

5.2.5.1 Impairment in the value of non-financial assets in Transener

The projections used by Transener in the calculation of the recoverable amount of long-lived non-financial assets considered 3 weighted alternatives associated with: (i) the status of negotiations with the ENRE; (ii) the Right-of-Use and Associated Maintenance contract; (iii) Transener’s management expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) Transener’s expectations on the timeliness and outcome of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2022 and 2021, the book value of Transener’s long-lived non-financial assets does not exceed their recoverable amount.

5.2.5.2 Distribution of earnings

Regarding the loan agreement executed in July 2021 between Transener and BNA in the amount of $ 1,000 million, for the tree-year term, Transener’s Board of Directors has committed, while the loan remains outstanding, to refrain from making any proposal to the Shareholders’ Meeting regarding the release of reserves for their distribution as dividends to shareholders or, in case there are negative results affecting reserves, from proposing the distribution of earnings until reserves have been replenished.

5.2.6 Investment in CIESA

Impairment of non-financial assets in TGS

Argentina’s main macroeconomic and business variables have deteriorated since August 2019. This situation worsened in 2020 due to the negative consequences of the COVID pandemic on the Argentine economic situation, which forced the Argentine Government to take a series of measures, even affecting the regulatory framework of the natural gas transportation segment. As a result, TGS has re-estimated the cash flows used in determining the recoverable value (value in use) of the CGU in the Natural Gas Transportation segment.

The projections used in the calculation of the recoverable amount considered 3 weighted alternatives associated with: (i) the status of negotiations with the Argentine Government; (ii) the contractual rights resulting from the license; (iii) expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) expectations on the result of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2022 and 2021, TGS has determined that it is not necessary to record an additional impairment charge, nor to reverse the recorded one.

5.3 Operations in oil and gas consortiums

5.3.1 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 in Argentina production, according to Law No.17,319, are paid royalties equivalent to 12% of the wellhead price of crude oil and natural gas. The wellhead price is calculated by deducting freight and other sales related expenses from the sale prices obtained from transactions with third parties. This rate may increase from 3% to 4% depending on the producing jurisdiction and market value of the product.

5.3.2 Oil and gas participation details

As of December 31, 2022, the Company and its associates are part of the joint operations and consortia for the exploration and production of oil and gas as indicated below:

		Participation			Duration Up To
Name	Location	Direct	Indirect	Operator
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
La Tapera - Puesto Quiroga	Chubut	35.67%	-	Tecpetrol	2027
El Tordillo	Chubut	35.67%	-	Tecpetrol	2027
Aguaragüe (1)	Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala	Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento (2)	Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro (3)	Río Negro	15.00%	-	YPF	2026
Río Limay este (Ex Senillosa) (4)	Neuquén	85.00%	-	PAMPA	2040
Veta Escondida y Rincón de Aranda	Neuquén	55.00%	-	PAMPA	2027
Rincón del Mangrullo	Neuquén	50.00%	-	YPF	2052
Los Blancos (ex Chirete)	Salta	50.00%	-	High Luck Group Limited	2045
Argentine exploration
Parva Negra Este (5)	Neuquén	42.50%	-	PAMPA	2019
Río Atuel (6)	Mendoza	33.33%	-	Petrolera El Trebol	2023
Borde del Limay (7)	Neuquén	85.00%	-	PAMPA	2015
Los Vértices (7)	Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte (8)	Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾ On February 3, 2023, an agreement for a 10-year extension of the concession was signed with the enforcement authority. The Provincial Executive Order ratifying this agreement is pending publication.

⁽²⁾ Direct participation in 9 wells. On January 19, 2023, the Company accepted Oilstone Energía S.A.’s offer to terminate its rights and obligations under the investment agreement, the Joint Venture and the operating agreement of the block, effective from January 1, 2023.

⁽³⁾ Direct participation in 13 wells.

⁽⁴⁾ On January 2, 2023, the environmental remediation plan was approved by the Province of Neuquén’s Subsecretariat of Environment, a necessary preliminary step to relinquish the block.

⁽⁵⁾ A contractual continuity plan was submitted (see details below).

⁽⁶⁾ Pursuant to Resolution No. 1,787/22 of the Province of Mendoza’s Ministry of Economy and Energy, the granting of a lot under evaluation, requested by Phoenix Global Resources —Petrolera El Trébol’s controlling company— and the Company on April 6, 2022, was approved until August 31, 2023.

⁽⁷⁾ Under process of relinquishment to the province.

⁽⁸⁾ On January 4, 2023, the exploration period terminated, and the Company’s rights and obligations over the area expired.

Continuity plan in the Parva Negra Este block

On December 14, 2022, the Company, ExxonMobil Exploration Argentina S.R.L. and GyP submitted to Enforcement Authority a proposal for a contractual continuity plan which included: (i) the granting of a Lot under Evaluation for the April-2022 through April-2025 period, (ii) a 50% reduction of the block’s surface, to a total surface of 143 km2, and (iii) the assignment of ExxonMobil Exploration Argentina S.R.L.’s 42.50% interest to the Company.

As of the issuance of these Consolidated Financial Statements, the Enforcement Authority’s decision is pending.

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.

5.4 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2022, 2021 and 2020:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	42	50	33
Increases	2	8	24
Transferred to development	(6)	(16)	(7)
At the end of the year	38	42	50
Number of wells at the end of the year	7	10	12

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RISKS

12 Months Ended

Dec. 31, 2022

Risks

RISKS

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 subsidiary, 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.

In order to evaluate if there is evidence that a CGU could be affected, both external and internal sources of information are analyzed. Specific facts and circumstances are considered, which generally include the discount rate used in the estimates of the future cash flows of each CGU and the business condition as regards economic and market factors, such as the cost of inventories, oil and gas prices, international petrochemical product’s price, the regulatory framework for the energy industry, the projected capital investments and the evolution of the energy demand.

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 UGE. 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.

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

The Company is subject to various claims, lawsuits and other legal proceedings that arise during the ordinary course of its business. The Company’s liabilities with respect to such claims, lawsuits and other legal proceedings cannot be estimated with certainty. The Company reviews the status of each contingency and assesses potential financial liability, applying the criteria indicated in Note 4.21, for which elaborates the estimates mainly with the assistance of legal advisors, based on information available to the Management at Consolidated Financial Statements date, and taking into account the litigation and resolution/settlement strategies.

Contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company’s business, as well as third party claims arising from disputes concerning the interpretation of legislation.

The Company evaluates whether there would be additional expenses directly associated with the ultimate resolution of each contingency, which will be included in the provision if they may be reasonably estimated.

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.

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.

Periodic revisions and adjustments to the estimated oil and gas reserves and related future net cash flows may be necessary as a result of changes in a number of factors, related to reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors or at least once a year.

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 4.9).

6.1.8 Environmental remediation

The costs incurred to limit, neutralize or prevent environmental pollution are only capitalized if at least one of the following conditions is met: (a) such costs relate to improvements in safety; (b) the risk of environmental pollution is prevented or limited; or (c) the costs are incurred to prepare the assets for sale and the book value of such assets does not exceed their respective recoverable value.

Liabilities related to future remediation costs are recorded when, on the basis of environmental assessments, such liabilities are probable to materialize, and costs can be reasonably estimated. The actual recognition and amount of these provisions are generally based on the Company’s commitment to an action plan, such as an approved remediation plan or the sale or disposal of an asset. In general, the provision is recognised on the basis that a future remediation commitment may be required.

The Company measures liabilities based on its best estimation of present value of future costs, using currently available technology and applying current environmental laws and regulations as well as the Company’s own internal environmental policies.

6.1.9 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.

6.1.10 Business Combinations

The acquisition method involves the measurement at fair value of the identifiable assets acquired and the liabilities assumed in the business combination at the acquisition date.

For the purpose to determine the fair value of identifiable assets, the Company uses the valuation approach considered the most representative for each asset. These include: i) the income approach, through indirect cash flows (net present value of expected future cash flows) or through the multi-period excess earnings method, ii) the cost approach (replacement value of the good adjusted for loss due to physical deterioration, functional and economic obsolescence) and iii) the market approach through comparable transactions method.

Likewise, in order to determine the fair value of liabilities assumed, the Company’s Management considers the probability of cash outflows that will be required for each contingency, and elaborates the estimates with assistance of legal advisors, based on the information available and taking into account the strategy of litigation and resolution / liquidation.

Management critical judgment is required in selecting the approach to be used and estimating future cash flows. Actual cash flows and values may differ significantly from the expected future cash flows and related values obtained through the mentioned valuation techniques.

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.

In fiscal year 2022, the U.S. dollar recorded an approximate 72.5% increase against the Argentine peso, from $ 102.72 in December 2021 to $ 177.16 in December 2022, and taking into consideration that during the year the Company mostly had a net passive position in Argentine pesos, as of December 31, 2022 the Company recorded net foreign exchange gain in the amount of US$ 80 million. Taking into account the net passive financial position in Argentine pesos as of December 31, 2021, 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 (decrease)/increase of US$ 23 million in the 2022 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 financial instruments are not significantly exposed to hydrocarbon international price risks because the current regulatory, economic and governmental policies in force, prevent oil and gas domestic prices to be directly affected in the short-term due to variations in the international market.

Additionally, 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 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 12.2 to these Consolidated Financial Statements:

	Increase of the result for the year
Financial assets	12.31.2022	12.31.2021
Shares	19	15
Government securities	28	28
Corporate Bonds	12	2
Mutual funds	3	4
Variation of the result of the year	62	49

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.

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, 2022, 18% of the indebtedness was subject to variable interest rates. Furthermore, 52% of the Company’s debt accruing variable interest rates is denominated in U.S. dollars, mainly at Libor and SOFR rate plus an applicable spread. Regarding the replacement of the LIBOR reference interest rate effective from July 2023, the Company does not estimate any significant impacts on the current indebtedness subject to such reference rate.

The Company seeks to mitigate its interest-rate risk exposure through the analysis and evaluation of: (i) the different liquidity sources available in the financial and capital market, both domestic and (if available) international; (ii) interest rates alternatives (fixed or variable), currencies and terms available for companies in a similar sector, industry and risk than the Company; (iii) the availability, access and cost of interest-rate hedge agreements. On doing this, the Company evaluates the impact on profits or losses resulting from each strategy over the obligations representing the main interest-bearing positions.

In the case of fixed rates and in view of the market’s current conditions, the Company considers that the risk of a significant decrease in interest rates is low and, therefore, does not foresee a substantial risk in its indebtedness at fixed rates.

As of the date of issuance of these Consolidated Financial Statements, the Company is not exposed to a significant risk of variable interest rate increases since most of the financial debt is subject to fixed rate.

The following table shows the breakdown of the Company’s borrowings classified by interest rate and the currency in which they are denominated:

	12.31.2022	12.31.2021
Fixed interest rate:
Argentine pesos	57	11
U.S. dollar	1,173	1,318
Subtotal loans obtained at a fixed interest rate	1,230	1,329
Floating interest rate:
Argentine pesos	140	-
U.S. dollar	149	87
Subtotal loans obtained at a floating interest rate	289	87
Non interest accrued
Argentine pesos	22	-
U.S. dollar	72	22
Subtotal loans no interest accrued	94	22
Total borrowings	1,613	1,438

Based on the conducted simulations, and provided all other variables remain constant, a 10% increase/decrease in variable interest rates would generate the following (decrease)/increase in the 2022 fiscal year's income, before income tax, of US$ 0.1 million.

6.2.1.2 Credit risk

The Company establishes individual credit limits according to the limits defined by the Board of Directors and approved by the Financial Department based on internal or external ratings. The Company makes constant credit assessments on its customers’ financial capacity, which minimizes the potential risk for bad debt losses.

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.

The credit risk is associated with the Company’s commercial activity through customer trade receivables, as well as available funds and deposits in banking and financial institutions.

The Company, in its ordinary course of business and in accordance with its credit policies, grants credits to a large customer base, mainly large sectors of the industry, including petrochemical companies, natural gas distributors and electricity large users.

As of December 31, 2022, the Company’s short-term trade receivables totaled US$ 305 million. With the exception of CAMMESA, which represents approximately 54% 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.

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 4.10.4.

The expected credit loss on trade receivables and financial assets as of December 31, 2022, 2021 and 2020 amounts to US$ 1 million, US$ 1 million and US$ 12 million, respectively and was determined based on credit loss rates calculated for days past due detailed below:

12.31.2022	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.08%	0.26%	2.54%	7.11%	14.37%	21.39%	27.22%	33.01%
Oil and Gas	0.18%	0.48%	13.24%	31.50%	32.01%	32.09%	32.31%	32.38%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Holding	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
12.31.2021	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.06%	0.29%	2.08%	2.83%	4.67%	6.12%	6.24%	6.25%
Oil and Gas	0.04%	0.17%	0.77%	2.72%	6.88%	19.88%	21.97%	15.89%
Petrochemicals	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
Holding	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
12.31.2020	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.35%	1.11%	5.74%	9.78%	11.23%	19.77%	20.87%	22.71%
Oil and Gas	0.49%	0.72%	5.96%	16.21%	16.23%	17.74%	17.76%	17.79%
Petrochemicals	0.02%	0.06%	0.72%	2.26%	9.95%	23.84%	19.14%	36.92%
Holding	12.58%	0.94%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%

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, 2022, 2021 and 2020, 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$ 0.3 million (decrease)/increase in 2022 fiscal year’s results, before income tax.

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, if 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.

It should be noted that the Company operates in an economic context in which main variables experience volatility as a result of political and economic events both domestically and internationally, as described in Note 1.2.

The international instability resulting from the Russian invasion, added to the particular circumstances of the Argentine sovereign debt renegotiation, has impacted the international financial markets, increasing the cost of access to finance for emerging markets in general, and particularly for Argentina. As regards access to domestic financing, an increased liquidity in pesos and a reduced cost of financing have been verified, especially in the very short term.

All these impacts may potentially affect the Company’s capacity to obtain financing for its operations in a timely manner and under acceptable and efficient terms, costs and conditions in line with the Company’s business needs.

Furthermore, the restrictions imposed by the BCRA (see Note 2.5) with the purpose of regulating inflows and outflows in the MLC and other new restrictions which may be imposed in the future may affect the Company’s capacity to access the MLC to acquire the foreign currency necessary to meet its financial obligations, such as debt principal and interest payments (including the CBs debt), and other additional payments abroad, or otherwise affect the Company’s business and the results of its operations.

The Company’s Management permanently monitors the evolution of situations affecting its business to determine possible steps to take and identify potential impacts on its assets and financial position.

It is worth highlighting that the Company currently has a strong level of liquidity that allows it to properly face such volatility.

The determination of the Company’s liquidity index for fiscal years ended December 31, 2022 and 2021 is detailed below:

	12.31.2022	12.31.2021
Current assets	1,343	1,125
Current liabilities	631	342
Liquidity ratio	2.13	3.29

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 liabilities 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.

As of December 31, 2022	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	412	231	118
Three months to one year	19	50	304
One to two years	6	12	357
Two to five years	12	3	992
More than five years	-	6	332
No set maturity term	41	-	-
Total	490	302	2,103
As of December 31, 2021	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	304	178	56
Three months to one year	61	4	102
One to two years	6	5	557
Two to five years	18	3	256
More than five years	-	4	1,025
No set maturity term	42	-	-
Total	431	194	1,996

⁽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 (including current and non-current indebtedness) 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 at December 31, 2022 and 2021 were as follows:

	12.31.2022	12.31.2021
Total borrowings	1,613	1,438
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(692)	(568)
Net debt	921	870
Total capital	3,198	2,655
Leverage ratio	28.80%	32.77%

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SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2022

Segment Information

SEGMENT INFORMATION

NOTE 7: SEGMENT INFORMATION

The Company is a fully integrated power company in Argentina, which participates in the electricity and oil and gas value chains.

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:

Electricity Generation, principally consisting of the Company’s direct and indirect interests in HINISA, HIDISA, Greenwind, VAR, CTB, TMB, TJSM and through its own electricity generation activities through thermal plants Güemes, Piedra Buena, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picún Leufú hydroelectric complex and PEPE II, PEPE III and PEPE IV wind farms. It is worth highlighting that the results of the segment’s operations reflect the effects of the consolidation with Greenwind and VAR as from August 12, 2022 and December 16, 2022, respectively; see Note 5.1.3 and Note 5.1.5.

Electricity Distribution, consisting of the Company’s direct interest in Edenor until its disposal. As of December, 31, 2021 and 2020, the Company has classified the results corresponding to the divestment mentioned in Note 5.1.1 as discontinued operations.

Oil and Gas, principally consisting of the Company’s interests in oil and gas areas and through its direct and indirect interest in CISA.

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in local plants.

Holding and Other Business, principally consisting of interests in joint businesses CITELEC and CIESA and their respective subsidiaries, which hold the concession over the high voltage electricity transmission nationwide and over gas transportation in the South of the country, respectively, interests in the associates OCP and Refinor (until its divestment detailed in Note 5.1.2), holding activities and financial investment transactions.

The Company manages its operating segment based on its individual net result in U.S. dollars.

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	663	370	425	20	-	1,478
Revenue - foreign market	-	159	192	-	-	351
Intersegment revenue	-	117	-	-	(117)	-
Cost of sales	(370)	(359)	(536)	-	117	(1,148)
Gross profit	293	287	81	20	-	681
Selling expenses	(3)	(36)	(17)	-	-	(56)
Administrative expenses	(39)	(60)	(5)	(34)	-	(138)
Other operating income	25	61	1	44	-	131
Other operating expenses	(5)	(26)	(6)	(9)	-	(46)
Impairment of property, plant and equipment, intangible assets and inventories	-	(30)	(2)	(6)	-	(38)
Impairment of financial assets	-	(2)	-	(6)	-	(8)
Share of profit from associates and joint ventures	65	-	-	40	-	105
Operating income	336	194	52	49	-	631
Financial income	1	2	-	9	(7)	5
Financial costs	(82)	(107)	(3)	(36)	7	(221)
Other financial results	72	(28)	6	116	-	166
Financial results, net	(9)	(133)	3	89	-	(50)
Profit before income tax	327	61	55	138	-	581
Income tax	(73)	(16)	(15)	(20)	-	(124)
Profit of the year	254	45	40	118	-	457
Depreciation and amortization	82	125	5	-	-	212

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit of the year attributable to:
Owners of the company	253	45	40	118	-	456
Non-controlling interest	1	-	-	-	-	1
Consolidated financial position information as of December 31, 2022
Assets	2,464	1,234	177	1,029	(162)	4,742
Liabilities	979	1,248	147	245	(161)	2,458
Net book values of property, plant and equipment	1,299	807	24	34	-	2,164
Additional consolidated information as of December 31, 2022
Increases in property, plant and equipment, intangible assets and right-of-use assets	115	324	7	36	-	482

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	656	-	282	310	22	-	1,270
Revenue - foreign market	-	-	58	180	-	-	238
Intersegment revenue	-	-	113	-	-	(113)	-
Cost of sales	(355)	-	(289)	(424)	-	113	(955)
Gross profit	301	-	164	66	22	-	553
Selling expenses	(2)	-	(18)	(13)	-	-	(33)
Administrative expenses	(31)	-	(46)	(4)	(18)	-	(99)
Other operating income	42	-	58	1	4	-	105
Other operating expenses	(5)	-	(28)	(3)	(22)	-	(58)
Impairment of intangible assets and inventories	(2)	-	-	(2)	-	-	(4)
Impairment of financial assets	-	-	-	-	(2)	-	(2)
Share of profit from associates and joint ventures	47	-	-	-	70	-	117
Operating income	350	-	130	45	54	-	579
Financial income	4	-	3	-	4	(1)	10
Financial costs	(46)	-	(103)	(3)	(34)	1	(185)
Other financial results	(14)	-	(16)	(2)	18	-	(14)
Financial results, net	(56)	-	(116)	(5)	(12)	-	(189)
Profit before income tax	294	-	14	40	42	-	390
Income tax	(75)	-	8	(12)	2	-	(77)
Profit of the year from continuing operations	219	-	22	28	44	-	313
Loss of the year from discontinued operations	-	(75)	-	-	-	-	(75)
Profit (Loss) of the year	219	(75)	22	28	44	-	238
Depreciation and amortization	88	-	114	3	-	-	205

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	218	(39)	22	28	44	-	273
Non-controlling interest	1	(36)	-	-	-	-	(35)
Consolidated financial position information as of December 31, 2021
Assets	1,670	-	1,157	176	1,067	(209)	3,861
Liabilities	525	-	1,324	166	264	(209)	2,070
Net book values of property, plant and equipment	969	-	636	22	32	-	1,659
Additional consolidated information as of December 31, 2021
Increases in property, plant and equipment, intangible assets and right-of-use assets	39	-	213	6	6	-	264

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	559	-	199	178	20	-	956
Revenue - foreign market	-	-	28	89	-	-	117
Intersegment revenue	-	-	67	-	-	(67)	-
Cost of sales	(254)	-	(243)	(233)	-	67	(663)
Gross profit	305	-	51	34	20	-	410
Selling expenses	(2)	-	(15)	(9)	-	-	(26)
Administrative expenses	(30)	-	(42)	(3)	(18)	-	(93)
Other operating income	35	-	9	-	7	-	51
Other operating expenses	(6)	-	(17)	(6)	(7)	-	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(128)	-	-	(11)	-	-	(139)
Impairment of financial assets	-	-	(13)	1	3	-	(9)
Share of profit from associates and joint ventures	67	-	-	-	18	-	85
Operating income (loss)	241	-	(27)	6	23	-	243
Financial income	3	-	7	-	1	(2)	9
Financial costs	(73)	-	(100)	(3)	(3)	2	(177)
Other financial results	1	-	44	5	34	-	84
Financial results, net	(69)	-	(49)	2	32	-	(84)
Profit (loss) before income tax	172	-	(76)	8	55	-	159
Income tax	(33)	-	23	(2)	(23)	-	(35)
Profit (loss) of the year from continuing operations	139	-	(53)	6	32	-	124
Loss of the year from discontinued operations	-	(592)	-	-	-	-	(592)
Profit (loss) of the year	139	(592)	(53)	6	32	-	(468)
Depreciation and amortization	95	81	108	2	-	-	286

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	147	(499)	(53)	6	32	-	(367)
Non-controlling interest	(8)	(93)	-	-	-	-	(101)
Consolidated financial position information as of December 31, 2020
Assets	1,595	1,356	1,085	107	832	(85)	4,890
Liabilities	707	1,021	1,174	126	178	(85)	3,121
Net book values of property, plant and equipment	1,015	-	543	19	33	-	1,610
Additional consolidated information as of December 31, 2020
Increases in property, plant and equipment and right-of-use assets	61	135	41	3	2	-	242

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REVENUE

12 Months Ended

Dec. 31, 2022

Revenue [abstract]

REVENUE

NOTE 8: REVENUE

	12.31.2022	12.31.2021	12.31.2020
Energy sales in Spot Market	210	167	179
Energy sales by supply contracts	346	380	323
Fuel supply	103	104	54
Other sales	4	5	3
Generation sales subtotal	663	656	559
Gas sales	383	231	152
Oil sales	136	99	65
Other sales	10	10	10
Oil and gas sales subtotal	529	340	227
Products from catalytic reforming sales	270	185	98
Styrene sales	96	84	42
Synthetic rubber sales	106	99	49
Polystyrene sales	141	119	71
Other sales	4	3	7
Petrochemicals sales subtotal	617	490	267
Technical assistance and administration services sales	20	22	20
Other	-	-	-
Holding and others subtotal	20	22	20
Total revenue	1,829	1,508	1,073

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COST OF SALES

12 Months Ended

Dec. 31, 2022

Cost Of Sales

COST OF SALES

NOTE 9: COST OF SALES

	12.31.2022	12.31.2021	12.31.2020
Inventories at the beginning of the year	155	116	153
Plus: Charges of the year
Purchases of inventories, energy and gas	502	433	153
Salaries and social security charges	79	59	51
Employees benefits	15	13	11
Accrual of defined benefit plans	5	4	4
Works contracts, fees and compensation for services	87	68	55
Property, plant and equipment depreciation	202	194	194
Intangible assets amortization	1	1	5
Right-of-use assets amortization	3	5	1
Energy transportation	8	6	5
Transportation and freights	35	22	20
Consumption of materials	30	26	17
Penalties	1	2	-
Maintenance	61	52	26
Canons and royalties	89	65	42
Environmental control	5	4	4
Rental and insurance	31	27	23
Surveillance and security	4	3	2
Taxes, rates and contributions	5	4	3
Other	3	6	2
Total charges of the year	1,166	994	618
Exchange differences on translation	-	-	8
Less: Inventories at the end of the year	(173)	(155)	(116)
Total cost of sales	1,148	955	663

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2022

Other Items Of Statement Of Comprehensive Income

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

NOTE 10: OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	5	3	3
Employees benefits	1	-	-
Compensation agreements	-	-	1
Fees and compensation for services	4	3	3
Taxes, rates and contributions	14	11	8
Transportation and freights	31	14	9
Other	1	2	2
Total selling expenses	56	33	26

10.2   Administrative expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	50	34	34
Employees benefits	8	5	4
Accrual of defined benefit plans	9	7	7
Fees and compensation for services	30	32	26
Compensation agreements	19	2	-
Directors' and Sindycs' fees	7	6	7
Property, plant and equipment depreciation	6	5	5
Maintenance	2	2	1
Transport and per diem	2	1	1
Rental and insurance	1	1	1
Surveillance and security	1	-	1
Taxes, rates and contributions	2	2	2
Communications	1	1	1
Other	-	1	3
Total administrative expenses	138	99	93

10.3 Other operating income and expenses

	Note	12.31.2022	12.31.2021	12.31.2020
Other operating income
Insurance recovery		-	3	3
Services provided to third parties		1	2	4
Result from property, plant and equipment sale		2	1	1
Result from intangible assets sale		2	2	-
Dividends received		-	-	1
Contingencies recovery		-	13	2
Tax charges recovery		-	2	-
Contractual penalty		-	-	7
Commercial interests		27	27	30
Argentine Natural Gas Production Promotion Plan		56	51	-
Compensation for arbitration award	15.6	37	-	-
Other		6	4	3
Total other operating income		131	105	51
Other operating expenses
Provision for contingencies		(4)	(16)	(7)
Provision for environmental remediation		-	(15)	-
Derecognition of property, plant and equipment		-	-	(1)
Tax on bank transactions		(14)	(13)	(11)
Donations and contributions		(2)	(2)	(3)
Institutional promotion		(3)	(3)	(2)
Readjustment of investment plan (1)		(9)	-	-
Royalties of Argentine Natural Gas Production Promotion Plan		(8)	(5)	-
Other		(6)	(4)	(12)
Total other operating expenses		(46)	(58)	(36)

⁽¹⁾ Corresponding to the investment plan’s readjustment bond at the Sierra Chata block (see Note 17.2).

10.4 Financial results

	12.31.2022	12.31.2021	12.31.2020
Financial income
Financial interest	1	-	1
Other interest	4	10	8
Total financial income	5	10	9
Financial costs
Financial interests (1)	(172)	(137)	(164)
Commercial interests	(1)	-	-
Fiscal interests	(38)	(38)	(3)
Other interests	(5)	(3)	(3)
Bank and other financial expenses	(5)	(7)	(7)
Total financial costs	(221)	(185)	(177)
Other financial results
Foreign currency exchange difference, net	80	3	14
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement	(14)	(1)	2
Result from exchange of corporate bonds	(14)	-	-
Result from repurchase of corporate bonds	6	-	38
Other financial results	(2)	(1)	-
Total other financial results	166	(14)	84
Total financial results, net	(50)	(189)	(84)

⁽¹⁾ Net of US$ 11 million and US$ 10 million capitalized in property, plant and equipment for the years ended December 31, 2022 and 2020, respectively. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

10.5    Income tax

The breakdown of income tax charge is:

	12.31.2022	12.31.2021	12.31.2020
Current tax	99	67	13
Deferred tax	46	10	22
Difference between previous fiscal year income tax provision and the income tax statement	(21)	-	-
Total  income tax -  Loss	124	77	35

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2022	12.31.2021	12.31.2020
Profit before income tax	581	390	159
Current income tax rate	35%	35%	30%
Income tax at the statutary tax rate	203	138	48
Share of profit from companies	(37)	(40)	(26)
Non-taxable results	(3)	(1)	(5)
Effects of exchange differences and other results associated with the valuation of the currency, net	275	79	88
Effects of valuation of property, plant and equipment, intangible assets and financial assets	(575)	(269)	(156)
Effect of change in tax rate	-	(6)	19
Effect for tax inflation adjustment	253	169	74
Unrecognized deferred assets	-	4	-
Difference between previous fiscal year income tax provision and the income tax statement	2	1	(7)
Non-deductible cost	4	3	-
Impairment on deferred tax assets	2	-	-
Other	-	(1)	-
Total  income tax -  Loss	124	77	35

XML

NON-FINANCIAL ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2022

Non-financial Assets And Liabilities

NON-FINANCIAL ASSETS AND LIABILITIES

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 (2)	Transfers	Decreases	Impairment
							At the end
Lands	14	-	-	-	-	-	14
Buildings	140	-	3	-	-	-	143
Equipment and machinery	1,458	5	291	163	(1)	-	1,916
Wells	867	9	-	145	(1)	(28)	992
Mining property	253	-	-	-	-	(72)	181
Vehicles	8	2	-	-	-	-	10
Furniture and fixtures and software equipment	55	2	-	2	-	-	59
Communication equipments	3	-	-	-	-	-	3
Materials, spare parts and tools	30	43	-	(37)	-	-	36
Petrochemical industrial complex	23	-	-	6	-	-	29
Work in progress	135	352	-	(233)	-	-	254
Advances to suppliers	52	37	-	(46)	-	-	43
Other goods	2	-	1	-	-	-	3
Total at 12.31.2022	3,040	450	295	-	(2)	(100)	3,683
Total at 12.31.2021	2,792	253	-	-	(5)	-	3,040

⁽¹⁾ Includes US$ 11 million corresponding to capitalized financial costs in the fiscal year ended December 31, 2022. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

⁽²⁾ See Notes 5.1.3 and 5.1.5.

	Depreciation					Net book values
Type of good	At the beginning	Decreases	For the year	Impairment	At the end	At 12.31.2022	At 12.31.2021
Lands	-	-	-	-	-	14	14
Buildings	(68)	-	(8)	-	(76)	67	72
Equipment and machinery	(536)	-	(103)	-	(639)	1,277	922
Wells	(532)	-	(77)	20	(589)	403	335
Mining property	(174)	-	(10)	50	(134)	47	79
Vehicles	(7)	-	(1)	-	(8)	2	1
Furniture and fixtures and software equipment	(48)	-	(4)	-	(52)	7	7
Communication equipments	(1)	-	-	-	(1)	2	2
Materials, spare parts and tools	(3)	-	-	-	(3)	33	27
Petrochemical industrial complex	(12)	-	(5)	-	(17)	12	11
Work in progress	-	-	-	-	-	254	135
Advances to suppliers	-	-	-	-	-	43	52
Other goods	-	-	-	-	-	3	2
Total at 12.31.2022	(1,381)	-	(208)	70	(1,519)	2,164
Total at 12.31.2021	(1,182)	-	(199)	-	(1,381)		1,659

11.1.1 Impairment of Property, plant and equipment

The Company regularly monitors the existence of events or changes in circumstances which may indicate that the book value of property, plant and equipment may not be recoverable in accordance with the policy described in Notes 4.9 and 6.1.1.

In the Power Generation segment, in May 2021 spot market prices were modified by SE Resolution No. 440/21, which, although providing for a 29% increase in remuneration, permanently abrogated the application of the automatic adjustment mechanism, with an impact on the expected revenues update schedule (see Note 2.1). It is worth highlighting that the most significant share of revenues in the Power Generation segment comes from energy remunerated under a differential scheme (that is, supply agreements with large users in the MATER, Energy Plus or supply agreements entered into with CAMMESA), which have not been affected by the previously mentioned regulation.

In view of the above-mentioned indications, the Company determined the recoverable value of the CGUs that make up the Power Generation segment as of June 30, 2021. As of December 31, 2021 and 2022, the Company did not identify additional indications that could impact the assumptions considered in the aforementioned assessments.

As of June 30, 2022, due to Company’s strategic reasons and aiming to focus its investments in the development and exploitation of its unconventional gas reserves, and also in line with the Rincón del Mangrullo block’s Joint Venture members’ strategy, future drilling and workover activities were rescheduled for the next few years, which involves a 2.7 MMBoe recategorization of reserves to contingent resources.

In view of the above-mentioned indications of impairment, the Company has determined the recoverable amount of the CGU Rincón del Mangrullo making up the Oil & Gas segment as of June 30, 2022. As of December 31, 2022, the Company did not identify additional indications that could impact the assumptions considered in the aforementioned assessment.

The methodology used in the estimation of the recoverable amount consisted on calculating each CGU value in use on the present value of future net cash flows expected to be generated by the CGU, discounted with a rate reflecting the weighted average costs of the invested capital.

Cash flows were prepared based on estimates on the future behavior of certain variables that are sensitive in the determination of the value in use, including the following: (i) reference prices for products; (ii) demand projections per type of product; (iii) costs evolution; and; (iv) macroeconomic variables such as inflation and exchange rates, etc.

11.1.1.1 Generation segment

As of June 30, 2021, the value of the assets in the Power Generation segment does not exceed its recoverable amount, therefore, the Company has not recorded any impairment losses.

The projections used in the calculation of the recoverable amount of the CGUs of the Power Generation segment take into consideration 2 scenarios that weigh: i) the annual price update, ranging between 80% and 100% compared to the annual inflation; ii) the regularization of the financing term granted to CAMMESA in 2022/2023 and iii) a 10.3% WACC rate after taxes.

11.1.1.2 Oil & Gas segment

As of June 30, 2022, the recoverability assessment of the Rincón del Mangrullo CGU in the Oil and Gas segment has resulted in the recognition of impairment losses for US$ 30 million.

The key assumptions used to calculate the recoverable amount considered: i) the reprogramming of drilling and workover activities and ii) a 12.4% after-tax WACC rate.

Finally, it is important to highlight that as of December 31, 2022 and 2021, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value.

11.2 Intangible assets

	Original values
Type of good	At the beginning	Increases	Increases for incorporation (1)	Decreases	Impairment (2)	At the end
Concession agreements	2	-	-	-	-	2
Goodwill	35	-	-	-	-	35
Intangible identified in acquisitions of companies	7	-	94	-	-	101
Digital assets	-	31	-	(18)	(6)	7
Total at 12.31.2022	44	31	94	(18)	(6)	145
Total at 12.31.2021	62	4		(4)	(18)	44
	Amortization
Type of good	At the beginning	For the year	Impairment (2)	At the end
Concession agreements	(2)	-	-	(2)
Intangible identified in acquisitions of companies	(4)	(1)	-	(5)
Total at 12.31.2022	(6)	(1)	-	(7)
Total at 12.31.2021	(21)	(1)	16	(6)
	Net book values
Type of good	At 12.31.2022	At 12.31.2021
Goodwill	35	35
Intangible identified in acquisitions of companies	96	3
Digital assets	7
Total at 12.31.2022	138
Total at 12.31.2021		38

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

⁽²⁾ As of December 31, 2022, digital assets recoverability was affected by their closing market value, resulted in the recognition of impairment losses for US$ 6 million. Considering the assumptions detailed in Note 11.1, the assessment of recoverability for the Power Generation segment, resulted in the recognition of impairment losses for the Diamante hydroelectric power plant in an amount of US$ 2 million in 2021.

11.3 Deferred tax assets and liabilities

The composition of the deferred tax assets and liabilities is as follows:

	12.31.2021	Profit (loss)	Increases for incorporation (1)	12.31.2022
Tax loss carryforwards	13	6	-	19
Property, plant and equipment	80	71	-	151
Financial assets at fair value through profit and loss	3	(3)	-	-
Trade and other receivables	5	(1)	-	4
Provisions	57	2	-	59
Salaries and social security payable	-	1	-	1
Defined benefit plans	9	(1)	-	8
Other	-	1	-	1
Deferred tax asset	167	76	-	243
Property, plant and equipment	-	-	(79)	(79)
Intangible assets	(13)	-	(22)	(35)
Investments in companies	(11)	3	-	(8)
Inventories	(10)	(9)	-	(19)
Financial assets at fair value through profit and loss	(14)	(1)	-	(15)
Trade and other receivables	(31)	8	-	(23)
Taxes payables	(3)	1	-	(2)
Tax inflation adjustment	(1)	(124)	(13)	(138)
Deferred tax liability	(83)	(122)	(114)	(319)
Deferred tax (liability) asset	84	(46)	(114)	(76)

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

	12.31.2020	Profit (loss) (1)	12.31.2021
Tax loss carryforwards	126	(113)	13
Property, plant and equipment	-	80	80
Intangible assets	3	(3)	-
Financial assets at fair value through profit and loss	-	3	3
Trade and other receivables	6	(1)	5
Provisions	28	29	57
Salaries and social security payable	3	(3)	-
Defined benefit plans	5	4	9
Trade and other payables	3	(3)	-
Tax inflation adjustment	4	(4)	-
Deferred tax asset	178	(11)	167
Property, plant and equipment	(13)	13	-
Intangible assets	(11)	(2)	(13)
Investments in companies	(25)	14	(11)
Inventories	(6)	(4)	(10)
Financial assets at fair value through profit and loss	(4)	(10)	(14)
Trade and other receivables	(7)	(24)	(31)
Taxes payables	(3)	-	(3)
Tax inflation adjustment	(2)	1	(1)
Deferred tax liability	(71)	(12)	(83)
Deferred tax asset (liability)	107	(23)	84

⁽¹⁾ Includes US$ 13 million corresponding to discontinued operations.

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:

	12.31.2022	12.31.2021
Deferred tax asset	36	84
Deferred tax liability	(112)	-
Deferred tax (liability) asset	(76)	84

11.4 Inventories

	12.31.2022	12.31.2021
Current
Materials and spare parts	104	87
Advances to suppliers	8	8
In process and finished products	61	60
Total (1)	173	155

⁽¹⁾ It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

11.5 Provisions

	12.31.2022	12.31.2021
Non-Current
Contingencies	107	106
Asset retirement obligation and wind turbines decommisioning	25	19
Environmental remediation	15	15
Other provisions	-	1
Total Non-Current	147	141
Current
Asset retirement obligation and wind turbines decommisioning	2	2
Environmental remediation	2	3
Total Current	4	5

The evolution of the provisions is set out below:

	12.31.2022
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	106	21	18
Increases	5	6	-
Increases for incorporation (1)	-	1	-
Decreases	(1)	-	(1)
Gain on monetary position, net	(2)	-	-
Reversal of unused amounts	(1)	(1)	-
At the end of the year	107	27	17

⁽¹⁾ See Note 5.1.3.

	12.31.2021
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	103	21	3
Increases	16	3	15
Decreases	-	(1)	-
Reversal of unused amounts (1)	(13)	(2)	-
At the end of the year	106	21	18

⁽¹⁾ Includes recovery of US$ 12.5 million related to waive the timely granted dispatch of Las Armas Wind Farm (see Note 2.1.2.3).

	12.31.2020
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	139	22	3
Increases	21	2	-
Decreases	(1)	-	-
Gain on monetary position, net	(15)	-	-
Reversal of unused amounts	(8)	(3)	-
Reclassified to liabilities associated to assets classified as held for sale	(33)	-	-
At the end of the year	103	21	3

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. Even though the province answered the complaint in the month of March 2021, the Company has started formal negotiations to resolve the dispute, agreeing on the suspension of procedural time limits. During 2021, regarding these claims and based on the progress of the ongoing negotiations, the Company recorded provisions 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. The Company does not have legally restricted assets for the cancellation of these obligations.

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.

11.5.3 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.

The determination of estimates may change in the future due to new developments or unknown facts at the time of evaluation of the provision. As a consequence, the adverse resolution of the evaluated proceedings and claims could exceed the established provision.

As of December 31, 2022, the Company has recorded provisions for US$ 102 million in relation to the following processes:

- There are a significant number of files pending before the National Tax Court regarding gasoline exports, where the tax entity challenges the tariff heading assigned by Petrobras in 2008-2014. The Treasury’s position involves a higher export duty rate.

- 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 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 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 is 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 30, 2021, POSA filed its claim memorial, and on September 15, 2021, the Company submitted its answer to the claim memorial and counterclaim. On December 15, 2021, POSA submitted its answer to the counterclaim. As of the date of issuance of these Consolidated Financial Statements, the proceeding pursues according the schedule decided by the parties.

- The Company filed an international arbitration claim against Petrobras International Braspetro B.V. (“PIB BV”) on account of fraudulent representations and omissions associated with certain export transactions under the share purchase agreement executed on May 13, 2016, whereby the Company acquired 67.2% of Petrobras Argentina S.A.’s capital stock. The arbitration is held under the ICC Arbitration Rules; the applicable law is the one of the State of New York, and the seat of arbitration is New York. On April 29, 2021, the Company filed its claim memorial and PIB BV submitted its counter-memorial and counterclaim seeking the payment of a percentage over the difference between the amount estimated for certain contingencies detected in the purchase process and the amount actually paid for them. On July 7, 2021, the Company and PIB BV submitted their respective answers. On November 5, 2021, the Company and PIB BV submitted their replications, and on December 20, 2021, their rejoinders to the complaints. As of the date of issuance of these Consolidated Financial Statements, the proceeding pursues according the schedule decided by the parties.

Additionally, the Company has recorded provisions for civil, commercial, administrative, labor, tax and customs complaints brought against the Company corresponding to atomized claims with individual unsubstantial amounts, as well as charges for judicial costs and expenses which, as of December 31, 2022, amount to US$ 5 million.

11.6 Income tax and minimum notional income tax liability

	12.31.2022	12.31.2021
Non-current
Income tax, net of witholdings	161	158
Minimum notional income tax	18	30
Total non-current	179	188
Current
Income tax, net of witholdings and advances	5	20
Total current	5	20

Income tax liability

The cumulative CPI variation over the 36 months prior to December 31, 2022 and 2021 has exceeded the 100% condition established by Law No. 27,430; therefore, the effect of the tax inflation adjustment has been accrued in the calculation of the current and deferred income tax provision. Likewise, as of December 31, 2020, the cumulative variation in the CPI has exceeded the 15% condition set for the third transition year pursuant to Law No. 27,430 and, therefore, the effect of the tax inflation adjustment has been accrued in the calculation of the current and deferred income tax provision, except in the cases where, on account of being irregular fiscal years, the mentioned legal parameter has not been exceeded for each of the annual periods.

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.”, where the CSJN ordered the application of the inflation adjustment mechanism.

As of December 31, 2022, the Company and its subsidiaries hold a provision for the additional income tax liabilities which should have been assessed for the reasons mentioned above. The provision for the period, including compensatory interest, is disclosed under “Non-current Income tax and minimum notional income tax provision”.

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 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. This liability is disclosed under “Non-Current Income tax and minimum notional income tax provision”.

11.7 Tax liabilities

	12.31.2022	12.31.2021
Current
Value added tax	5	4
Personal assets tax provision	4	2
Tax withholdings to be deposited	5	6
Royalties	12	9
Other	2	2
Total current	28	23

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.

As of December 31, 2022, 2021 and 2020, the most relevant actuarial information corresponding to the described benefit plans is the following:

	12.31.2022
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	33	(4)	29
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	15	(2)	13
Items classified in other comprehensive  income
Actuarial losses	9	-	9
Benefit payments	(3)	-	(3)
(Gain) Loss on monetary position, net	(17)	2	(15)
At the end of the year	38	(4)	34
	12.31.2021
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	25	(4)	21
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	13	(3)	10
Items classified in other comprehensive  income
Actuarial losses	1	2	3
Benefit payments	(2)	-	(2)
(Gain) Loss on monetary position, net	(5)	1	(4)
At the end of the year	33	(4)	29

	12.31.2020
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	36	(5)	31
Items classified in profit or loss
Current services cost	3	-	3
Interest cost	16	(2)	14
Items classified in other comprehensive  income
Actuarial (gains) losses	(3)	1	(2)
Benefit payments	(2)	-	(2)
Reclasification liabilities associated to assets classified as held for sale	(10)	-	(10)
(Gain) Loss on monetary position, net	(15)	2	(13)
At the end of the year	25	(4)	21

As of December 31, 2022, 2021 and 2020, the breakdown of net liabilities per type of plan is as follows: a) US$ 17 million, US$ 15 million and US$ 12 million correspond to the Pension and Retirement Benefits Plan and b) US$ 17 million, US$ 14 million and US$ 9 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.

	12.31.2022
Less than one year	6
One to two years	3
Two to three years	4
Three to four years	4
Four to five years	3
Six to ten years	14

Significant actuarial assumptions used were as follows:

	12.31.2022	12.31.2021	12.31.2020
Real discount rate	5%	5%	4%
Real wage increase rate	1%	1%	1%
Inflation rate	118%	54%	46%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount:

	12.31.2022
Discount rate: 4%
Obligation	41
Variation	3
	9%
Discount rate: 6%
Obligation	35
Variation	(3)
	(8%)
Real wage increase rate: 0%
Obligation	37
Variation	(1)
	(4%)
Real wage increase rate: 2%
Obligation	39
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.

11.9 Salaries and social security payable

	12.31.2022	12.31.2021
Current
Salaries and social security contributions	5	4
Provision for vacations	8	7
Provision for gratifications and annual bonus for efficiency	19	17
Total current	32	28

XML

FINANCIAL ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2022

Financial Assets And Liabilities

FINANCIAL ASSETS AND LIABILITIES

NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1   Financial assets at amortized cost

	12.31.2022	12.31.2021
Non-current
Term deposit	101	100
Notes receivable	1	5
Total non-current	102	105
Current
Notes receivable	8	5
Total current	8	5

12.2   Financial assets at fair value through profit and loss

	12.31.2022	12.31.2021
Non-current
Shares	27	29
Total non-current	27	29
Current
Government securities	279	278
Corporate bonds	116	19
Shares	160	120
Mutual funds	31	41
Total current	586	458

12.3   Trade and other receivables

	Note	12.31.2022	12.31.2021
Non-Current
Related parties	16	17	23
Tax credits		2	9
Prepaid expenses		-	1
Other		1	1
Other receivables		20	34
Total non-current		20	34

		12.31.2022	12.31.2021
Current
Receivables from MAT sales		21	24
CAMMESA		165	89
Receivables from oiland gas sales		55	69
Receivables from petrochemicals sales		62	71
Related parties	16	5	7
Other		3	5
Impairment of financial assets		(6)	(9)
Trade receivables, net		305	256
Current
Related parties	16	7	8
Tax credits		14	5
Receivables for complementary activities		-	2
Prepaid expenses		14	10
Financial credit		-	10
Guarantee deposits		27	30
Insurance to be recovered		-	1
Expenses to be recovered		15	-
Receivables for acquisition of subsidiary		7	-
Receivables for sale of subsidiary and associates		4	41
Receivables for financial instruments sale		1	6
Argentine Natural Gas Production Promotion Plan		32	14
Receivables for arbitration award	15.6	37	-
Other		7	14
Other receivables, net		165	141
Total current		470	397

Due to the short-term nature of trade and other receivables, its book value is not considered to differ from its fair value. For non-current trade and other receivables, fair values do not significantly differ from book values.

The movements in the impairment of trade receivables were as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	9	16	68
Impairment (1)	1	1	63
Utilization	(1)	-	(7)
Reversal of unused amounts	-	(6)	(3)
Gain on monetary position, net	(3)	(2)	(2)
Gain on monetary position, net	-	-	(28)
Reclasified to assets classified as held for sale	-	-	(75)
At the end of the year	6	9	16

⁽¹⁾ It includes US$ 26 million corresponding to discontinued operations for fiscal year 2020. As of December 31, 2020, it includes US$ 13 million corresponding to the receivable impairment related to the exchange difference between the price of gas purchased by distributors and the price of gas recognised in distributors´s final tariffs between April 2018 and March 2019 to be assumed by the Federal Government in accordance to PEN Executive Order No. 1,053/18 (see Note 15).

The movements in the impairment of other financial assets were as follows:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	-	-	6
Impairment	-	-	2
Reversal of unused amounts	-	-	(7)
Reclasified to assets classified as held for sale	-	-	(1)
At the end of the year	-	-	-

12.4   Cash and cash equivalents

	12.31.2022	12.31.2021
Banks	11	26
Mutual funds	95	84
Total	106	110

12.5   Borrowings

	12.31.2022	12.31.2021
Non-Current
Financial borrowings	108	58
Corporate bonds	1,232	1,301
Total non-current	1,340	1,359
Current
Bank overdrafts	59	11
Financial borrowings	51	29
Corporate bonds	163	39
Total current	273	79
Total	1,613	1,438

As of December 31, 2022 and 2021, the fair values of the Company’s Corporate Bonds amount approximately to US$ 1,435 million and US$ 1,233 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 and bank overdrafts 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:

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	1,438	1,614	1,947
Proceeds from borrowings	308	188	353
Payment of borrowings	(143)	(336)	(300)
Accrued interest	172	137	176
Payment of interests	(162)	(140)	(201)
Repurchase and redemption of corporate bonds	(28)	(3)	(155)
Result from exchange of corporate bonds	14	-	-
Result from repurchase of corporate bonds	(6)	-	(43)
Increases for incorporation (1)	89	-	-
Cancellation through dividend compensation	-	-	(12)
Gain on monetary position, net	-	-	(43)
Foreign currency exchange difference, net	(80)	(22)	(18)
Borrowing costs capitalized in property, plant and equipment	11	-	10
Reclassified to liabilities associated to assets classified as held for sale	-	-	(100)
At the end of the year	1,613	1,438	1,614

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

12.5.2 Details of borrowings:

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2022
Corporate bonds (1)
T Series CB	PAMPA	US$	93	Fixed	7.38%	Jul-23	95
Class 8 CB	PAMPA	$	18	Variable	Badlar + 2%	Jul-23	20
Class 11 CB	PAMPA	$	122	Variable	Badlar + 0%	Jan-24	140
Class 9 CB	PAMPA	US$	102	Fixed	9.50%	Dec-26	184
Class 1 CB	PAMPA	US$	501	Fixed	7.50%	Jan-27	616
Class 13 CB	PAMPA	US$	49	Fixed	0.00%	Dec-27	48
Class 3 CB	PAMPA	US$	285	Fixed	9.13%	Apr-29	292
							1,395
Financial loans (2)
	PAMPA	US$	15	Variable	Libor + 4.21%	Nov-24	16
	GW	US$	83	Variable	Libor + 5.75%	Sep-26	85
							101
Other financial loans (3)
	PAMPA	US$	22	Variable	SOFR + 0.35%	Jul-23	23
	PAMPA	US$	8	Fixed	Between 9.50% and 14.50%	Between Jan-23 and May-23	8
	PAMPA	US$	27	Variable	SOFR + 0%	Agu-24	27
							58
Bank overdrafts (3)
	PAMPA	$	57	Fixed	Between 54% and 54.50%	Jan-23	59
							59
							1,613

⁽¹⁾ Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

⁽²⁾ During the the fiscal year ended December 31, 2022, the Company took on new short-term financing with domestic financial entities, net of cancellations, for a total $ 8,618 million and import prefinancing for US$ 7.6 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million and US$ 10.4 million corresponding to the credit facility subscribed between IDB Invest and Greenwind, a Company that is consolidated since acquisition of an additional 50% interest in August 2022.

⁽³⁾ During the fiscal year ended December 31, 2022, the Company received disbursements in the amount of US$ 1.3 million under the credit facilities taken out with BNP Paribas S.A. in 2020. After the fiscal year closing, the Company repaid short-term bank loans with local financial entities for $ 10,065 million and import prefinancing for US$ 0.7 million.

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2021
Corporate bonds (1)
T Series CB	PAMPA	US$	389	Fixed	7.38%	Jul-23	400
Class 1 CB	PAMPA	US$	636	Fixed	7.50%	Jan-27	648
Class 3 CB	PAMPA	US$	293	Fixed	9.13%	Apr-29	292
							1,340
Financial loans (2)
	PAMPA	US$	23	Variable	Libor + 4.21%	May-24	23
							23
Other financial loans (3)
	PAMPA	US$	22	Variable	Libor + 0.35%	Jul-22	22
	PAMPA	US$	43	Variable	Libor + 0%	Aug-23	42
							64
Bank overdrafts
	PAMPA	$	11	Fixed	33.00%	Jan-22	11
							11
							1,438

⁽¹⁾ Net of the following face value repurchases: US$ 110,4 million of ON 2023, US$ 114,0 million of ON 2027 and US$ 7,5 million of ON 2029.

On September 27, 2021, the Company repaid at maturity Class 6 CBs for $ 6,355 million.

⁽²⁾ During the fiscal year ended December 31, 2021, the Company canceled short-term financing with local financial entities, net of borrowings, for $ 8,158 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million.

⁽³⁾ During the fiscal year ended December 31, 2021, the Company received disbursements in the amount of US$ 27 million under the credit facilities taken out with BNP in 2020.

12.5.3 New Global Program of CB

On September 30, 2021, the Company’s General Ordinary and Extraordinary Shareholders’ Meeting resolved to approve the creation of a new global corporate bonds program for an amount of up to US$ 2,000 million or its equivalent in other currencies or units of value, in the form of simple corporate bonds non-convertible into shares and/or corporate bonds convertible into shares, to renew the program expired on December 29, 2021. The public offering was authorized by the CNV on December 9, 2021.

12.5.4 Issuance of CB Class 8

On January 18, 2022, the Company issued Class 8 CB in the amount of $ 3,107 million at a Badlar rate + 2%, maturing in 18 months. This is the first green bond issued by Pampa, which reflects the commitment to finance projects with a positive impact on the environment and to diversify the country’s energy generation matrix. The issue was recognised by Fix Ratings, an affiliate of Fitch Ratings, with the rating of Green Bond (BV1), the best possible grade, since it is aligned with the four main components of ICMA’s (International Capital Market Association) Green Bond Principles (GBP). It was issued in observance of the “Guidelines for the Issuance of Social, Green and Sustainable Bonds in Argentina” of the CNV Rules and the provisions of BYMA’s Social, Green and Sustainable Guide and the BYMA Rules, and also makes up BYMA’s Social, Green and Sustainable Bonds Panel.

The Company will allocate the issue’s proceeds to finance the expansion of PEPE IV (see Note 17.1).

12.5.5 Issuance of Class 10, 11, 12, 13 and 15 CB

On July 15, 2022, the Company issued Class 11 CB for $ 12,690 million, accruing interest at a variable BADLAR rate plus an annual 0% spread and maturing on January 15, 2024. Class 10 and Class 12 CB were declared unawarded.

Additionally, on August 8, 2022 the Company reopened Class 11 CB for $ 8,963.9 million at an issuance price of 1.0305. The total face value of outstanding Class 11 CB amounted to $ 21,654.6 million.

Finally, on December 13, 2022, the Company issued Clase 13 US$-link CB for US$ 49.9 million at a fixed interest rate of 0% and maturing on December 2027.

After the closing of the fiscal year, on January 11, 2023, the Company issued Class 15 CB for $ 10,379 million accruing interest at a variable BADLAR rate plus an annual 2% spread and maturing on July 11, 2024. Additionally, on March 2, 2023, the Company reopened Class 13 and Class 15 CB for US$ 48.2 million and $ 7,885 million, respectively.

12.5.6 Series T CB Exchange Offer

On June 16, 2022, the Company launched an exchange offer for holders of Series T CB maturing in 2023 originally issued by Petrobras Argentina S.A. (currently merged with the la Company) dated July 21, 2016 for a face value of US$ 500 million, under its Global Program authorized pursuant to CNV Resolution No. 17,162 dated August 15, 2013.

Once the exchange offer expired on July 29, 2022, the information and exchange agent informed the Company that US$ 193.8 million and US$ 213.3 million, representing 38.8% and 42.7% of the Series T CB’ outstanding principal, had been validly tendered for exchange under Option A and Option B, respectively, totaling a US$ 407.1 million participation and representing approximately 81.4% of the outstanding Series T CB’ capital amount.

Consequently, on August 8, 2022, after meeting the conditions established in the exchange offer documents, Pampa issued Class 9 CB for a face value of US$ 292.8 million, accruing interest at an annual fixed 9.5% rate and maturing on December 8, 2026, payable in three consecutive annual installments starting in 2024, and paid US$ 122.1 million in cash. For each US$ 1,000 of Series T CB’s capital amount validly tendered and accepted for exchange, eligible holders received, together with the payment of interest accrued on Series T CB up to the settlement date: (i) Option A: approximately US$ 377.2 in Class 9 CB and US$ 630.2 in cash; and (ii) Option B: US$ 1,030 in Class 9 CB.

As a result of the debt swap, the Company disclosed losses for US$ 14 million under “Other financial results” to reflect the change in the payment estimates discounted at Series T CB’s original effective interest rate, since they were not deemed substantially different from the issuance conditions for Class 9 CB, in accordance with IFRS.

As of the date of issuance of these Consolidated Financial Statements, outstanding Series T CB amount to US$ 92.9 million.

12.6   Trade and other payables

	Note	12.31.2022	12.31.2021
Non-Current
Compensation agreements		10	3
Finance leases liability		10	9
Other		1	-
Other payables		21	12
Total non-current		21	12
Current
Suppliers		198	154
Customer advances		3	4
Related parties	16	14	15
Trade payables		215	173
Compensation agreements		12	2
Liability for acquisition of companies		46	-
Finance leases liability		2	4
Other		6	3
Other payables		66	9
Total current		281	182

Due to the short-term nature of the trade payables and other payables, their carrying amount is considered to be the same as their fair value. For most other non-current debts, fair values are also not significantly different from their book values.

12.7   Financial instruments by category

The following table presents financial instruments by category:

As of December 31, 2022	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 receivables and other receivables	437	22	459	31	490
Financial assets at amortized cost
Term deposit	101	-	101	-	101
Notes receivable	9	-	9	-	9
Financial assets at fair value through profit and loss
Government securities	-	279	279	-	279
Corporate bonds	-	116	116	-	116
Shares	-	187	187	-	187
Mutual funds	-	31	31	-	31
Cash and cash equivalents	11	95	106	-	106
Total	558	730	1,288	31	1,319
Liabilities
Trade and other liabilities	298	-	298	4	302
Borrowings	1,613	-	1,613	-	1,613
Derivative financial instruments	-	2	2	-	2
Total	1,911	2	1,913	4	1,917
As of December 31, 2021	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 receivables and other receivables	376	30	406	25	431
Financial assets at amortized cost
Term deposit	100	-	100	-	100
Notes receivable	10	-	10	-	10
Financial assets at fair value through profit and loss
Government securities	-	278	278	-	278
Corporate bonds	-	19	19	-	19
Shares	-	149	149	-	149
Mutual funds	-	41	41	-	41
Cash and cash equivalents	26	84	110	-	110
Total	512	601	1,113	25	1,138
Liabilities
Trade and other liabilities	190	-	190	4	194
Borrowings	1,438	-	1,438	-	1,438
Total	1,628	-	1,628	4	1,632

The categories of financial instruments have been determined according to IFRS 9.

The income, expenses, gains and losses derived from each of the financial instrument categories are indicated below:

As of December 31, 2022	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	5	-	5	-	5
Interest expenses	(175)	-	(175)	(41)	(216)
Foreign currency exchange difference, net	16	(85)	(69)	149	80
Changes in the fair value of financial instruments	-	110	110	-	110
Result from present value measurement	(1)	-	(1)	(13)	(14)
Other financial results	(15)	-	(15)	-	(15)
Total	(170)	25	(145)	95	(50)
As of December 31, 2021	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	10	-	10	-	10
Interest expenses	(138)	-	(138)	(40)	(178)
Foreign currency exchange difference, net	(11)	(19)	(30)	33	3
Changes in the fair value of financial instruments	-	(15)	(15)	-	(15)
Result from present value measurement	2	-	2	(3)	(1)
Other financial results	(4)	-	(4)	(4)	(8)
Total	(141)	(34)	(175)	(14)	(189)
As of December 31, 2020	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	9	-	9	-	9
Interest expenses	(164)	-	(164)	(6)	(170)
Foreign currency exchange difference, net	38	(35)	3	11	14
Changes in the fair value of financial instruments	-	30	30	-	30
Result from present value measurement	6	-	6	(4)	2
Other financial results	36	-	36	(5)	31
Total	(75)	(5)	(80)	(4)	(84)

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 and liabilities measured at fair value as of December 31, 2022 and 2021:

As of December 31, 2022	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	279	-	-	279
Corporate bonds	116	-	-	116
Mutual funds	31	-	-	31
Shares	160	-	27	187
Cash and cash equivalents
Mutual funds	95	-	-	95
Other receivables	22	-	-	22
Total assets	703	-	27	730
Liabilities
Derivative financial instruments	-	2	0	2
Total liabilities	-	2	-	2
As of December 31, 2021	Level 1	Level 3	Total
Assets
Financial assets at fair value through  profit and losss
Government securities	278	-	278
Corporate bonds	19	-	19
Mutual funds	41	-	41
Shares	120	29	149
Cash and cash equivalents
Mutual funds	84	-	84
Other receivables	30	-	30
Total assets	572	29	601

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 with changes in profit (loss), 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 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 direct equity interest of 2.84% and 3.19%, and the additional equity interest of 2.18% and 2.46% through HIDISA and HINISA, in TJSM and TMB, respectively, resulting from the Federal Government’s restructuring of assets in the energy sector. This restructuring resulted in TMB’s and TJSM’s share transfer from the Federal Government to IEASA, considering 16.4% and 13.7% discount rate as of December, 31 2022 and 2021, respectively. The key assumptions were prepared based on estimates on the future behavior of certain sensitive variables, including: (i) the dividend distribution policy; (ii) reference prices for energy sold in the spot market; (iii) projections of the availability and dispatch of power plants; (iv) the evolution of structural costs and expenses; (v) macroeconomic variables such as inflation and exchange rates, etc. The Company recognised losses for US$ 1.7 million and earnings for US$ 18 million as a result of changes in the fair value of financial instruments classified as level 3, under the item “Other financial results” of the Consolidated Statement of Comprehensive Income, as of December, 31 2022 and 2021, respectively. Current values may substantially differ from projections, mainly on account of: i) the timeliness and magnitude of the distribution of dividends, ii) the timeliness and magnitude of energy price updates, and/or iii) the evolution of costs. 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.

XML

EQUITY COMPONENTS

12 Months Ended

Dec. 31, 2022

Equity Components

EQUITY COMPONENTS

NOTE 13: EQUITY COMPONENTS

13.1 Share capital

As of December 31, 2022, the share capital amounts to 1,384 million shares, including approximately 4 million treasury shares.

13.1.1 Share buyback programs

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 buyback programs, considering in each case that treasury shares may not exceed the 10% capital stock capitalization.

During 2021, the Company’s Board of Directors approved Programs 9 and 10 for a maximum amount of US$ 30 million each, under which shares could be acquired up to a maximum price of US$ 16 and US$ 15.5 per ADR, respectively. The Company directly and indirectly acquired 2.7 million own ADRs for a value of US$ 38.7 million, and the repurchased shares canceled in full.

On December 1, 2021, the Company’s Board of Directors approved Program 11 for a maximum amount of US$ 30 million and an initial term of 120 calendar days; under this Program, shares may be acquired up to a maximum price of US$ 19 per ADR and $ 167 per common share. On March 10, 2022, the Board of Directors resolved to suspend Program 11, as the Company’s share and ADR prices exceeded the set repurchase limit values.

On May 11, 2022, the Board of Directors resolved to approve Program 12 for a maximum amount of US$ 30 million, an initial term of 120 calendar days, and a maximum price of US$ 22 per ADR and $ 194 per common share.

As of the issuance of these Consolidated Financial Statements, these programs have already expired.

During 2022, the Company indirectly acquired 0.9 million own ADRs for a value of US$ 18.2 million to an average price of US$ 20,3 per ADR.

13.1.2 Stock Compensation Plan

During fiscal year ended December 31, 2021, the Company delivered 0.5 million own shares as payments under the stock compensation plan for officers and other key staff, respectively. In addition, the Company acquired 6 million own shares, out of which 2 million were allocated to the compensation of senior managers. As of December, 31 2022 and 2021, 4 million remained in treasury to be delivered to employees under such plan (see Note 4.17).

13.1.3 Capital reductions

During 2021, the capital stock reduction approved by the Company’s General Ordinary and Extraordinary Shareholders’ Meeting held on April 29, 2021 and September 30, 2021, which provided for the cancellation of 56.6 million shares and 12.5 million shares, respectively. These reductions are registered in the Public Registry.

On April 27, 2022, General Ordinary and Extraordinary Shareholders’ Meeting resolved to reduce the Company’s capital stock by canceling 2.8 million shares which took place during October 2022. This reduction was registered with the Public Registry on September 14, 2022.

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 period, no dilutive effect is recorded, being the diluted earnings per share equal to the basic. As of December 31, 2022, 2021 and 2020, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

	12.31.2022	12.31.2021	12.31.2020
Earning for continuing operations attributable to equity holders of the Company	456	312	132
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earnings per share from continued operations	0.33	0.22	0.08
Loss for discontinued operations attributable to equity holders of the Company	-	(39)	(499)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted loss per share from discontinued operations	-	(0.03)	(0.32)
Earning (Loss) attributable to equity holders of the Company	456	273	(367)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earning (loss) per share	0.33	0.19	(0.23)

13.3 Profit distributions

Dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or 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.

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STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

12 Months Ended

Dec. 31, 2022

Statement Of Cash Flows Complementary Information

STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

NOTE 14: STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit to cash flows generated by operating activities

	Note	12.31.2022	12.31.2021	12.31.2020
Income tax	10.5	124	77	35
Accrued interest		185	141	132
Depreciations and amortizations	9 and 10.2	212	205	205
Share of profit of joint ventures and associates	5.2.2	(105)	(117)	(85)
Results for property, plant and equipment sale	10.3	(2)	(1)	-
Result for intangibles assets sale	10.3	(2)	(2)	-
Impairment of property, plant and equipment, intangible assets and inventories	10.1, 10.2 and 10.4	38	4	139
Impairment of financial assets		8	2	9
Result from measurement at present value	10.4	14	1	(2)
Changes in the fair value of financial instruments		(94)	24	(19)
Exchange differences, net		(85)	(3)	(14)
Result from exchange of corporate bonds	10.4	14	-	-
Result from repurchase of corporate bonds	10.4	(6)	-	(38)
Readjustment of investment plan	10.3	9	-	-
Compensation for arbitration award	10.3	(37)	-	-
Recovery of tax charges	10.3	-	(2)	-
Provision for contingecies, net	10.3	4	3	2
Provision for environmental remediation	10.3	-	15	-
Accrual of defined benefit plans	9 and 10.2	14	11	11
Dividends received	10.3	-	-	(1)
Compensation agreements	10.1 and 10.2	19	2	1
Other		(3)	5	5
Adjustments to reconcile net profit to cash flows from operating activities		307	365	380

14.2 Changes in operating assets and liabilities

	12.31.2022	12.31.2021	12.31.2020
(Increase) Decrease in trade receivables and other receivables	(233)	(41)	19
Increase in inventories	(21)	(40)	(6)
Increase in trade payables and other payables	70	43	3
Increase (Decrease) in salaries and social security payable	15	8	(1)
Decrease in defined benefit plans	(3)	(2)	(2)
Increase (Decrease) in tax liabilities	36	(5)	(20)
Decrease in provisions	(1)	(3)	(5)
Income tax paid	(2)	(13)	(5)
Payments from derivative financial instruments, net	(6)	(12)	(5)
Changes in operating assets and liabilities	(145)	(65)	(22)

14.3 Significant non-cash transactions

	12.31.2022	12.31.2021	12.31.2020
Acquisition of property, plant and equipment through an increase in trade payables	(75)	(51)	(8)
Borrowing costs capitalized in property, plant and equipment	(11)	-	(10)
Acquisition of subsidiary by delivering financial assets at fair value through profit and loss	(35)	-	-
Receivables from sales of companies pending collection	-	40	-
Receivables for acquisition of subsidiary	7	-	-
Increase in investments in associates through a decrease in other receivables	-	(20)	-
Increase in right-of-use assets through an increase in other liabilities	(1)	(7)	-
Dividends pending collection	-	2	20
Compensation of loans through dividends assignment	-	-	12
Decrease on well abandonment provision, net, through property, plant and equipment	(1)	(1)	(3)

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CONTINGENT LIABILITIES AND ASSETS

12 Months Ended

Dec. 31, 2022

Contingent Liabilities And Assets

CONTINGENT LIABILITIES AND ASSETS

NOTE 15: CONTINGENT LIABILITIES AND ASSETS

We hereinafter detail the nature of significant proceedings as of December 31, 2022, 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 by former employees not covered by the plan, seeking their inclusion. The Chamber of Appeals upheld the first-instance judgments that had dismissed the complaints filed in two claims by non-covered former employees seeking to be included in the plan. Both of these judgments are final and conclusive.

- Claims by former employees seeking compensation under the plan on account of terminations due to changes in shareholding control.

- Claims on considering that the index (CPI) used to update the plan benefits is ineffective to keep their “constant value”. In two of the causes, the Company obtained a favorable judgment, which has been appealed by the plaintiff. On the other hand, the Company received an adverse judgment in a claim, consequently, the Company has filed an appeal before the applicable Chamber.

- 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 filed an appeal, which was sustained by the Chamber. 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.

15.2 Tax claim

- Tax on Liquid Fuels and Natural Gas:

The AFIP 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.

- 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 based on a United Nations Development Program report. The proceeding is in the complaint answer stage.

- Beatriz Mendoza and other 16 plaintiffs brought a complaint before the CSJN against the National Government, the Province of Buenos Aires, the Government of the Autonomous City of Buenos Aires and 44 companies, including the Company, conducting industrial activities along the Matanza-Riachuelo River Basin. The plaintiffs seek compensation for alleged damages sustained as a result of an alleged environmental impact, its cessation, the environmental recomposition and redress, for an estimated amount of US$ 500 million for the financing of the Matanza-Riachuelo River Basin Environmental Management Plan aiming at the restoration of the basin. The proceeding is in the third-party summoning stage.

- Inertis S.A. has filed a complaint against the Company for alleged damage to the environment in a lot owned by this company as a result of the activities conducted by the Dock Sud Plant seeking the redress of alleged damages for a nominal amount estimated at $ 1 million and US$ 1 million, or the difference between the value of the allegedly affected lot and its valuation. The proceeding is in the evidentiary 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 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 $ 200 million. The parties agreed on a stay of the procedural time limits until August 2022 to evaluate the possibility of reaching an agreement. The plaintiff reached an agreement with three co-defendants. The Chamber hearing the case referred it back to the first instance, and the Court ordered a series of information measures before serving notice of the agreement on the other co-defendants (including the Company).

- Some neighbors of the Dock Sud area brought a complaint against 14 oil companies, including the Company, petrochemical companies and waste incineration plants located in the Dock Sud Petrochemical Complex for an alleged damage to the environment and alleged individual damage to their goods, health and morale. The CSJN determined it had jurisdiction over the environmental issue and maintained the civil and commercial jurisdiction regarding the compensation for the alleged damages. The First-Instance Civil and Commercial Court opened the evidentiary stage.

- A neighbor of the Province of Salta owning a lot where a joint venture made up of the plaintiffs (the Company and other companies) conducted hydrocarbon activities seeks environmental protection and restoration for alleged damage caused by hydrocarbon prospecting, exploration and/or exploitation activities or, alternatively, a compensation in case such environmental restoration is not possible. The Province of Salta has been summoned as a third party. The proceeding is in the complaint answer stage and the Court of Justice of Salta declared that the First-Instance Administrative Litigation Court has jurisdiction over the claim.

- Owners of a lot in the town of Garín, Province of Buenos Aires, seek the performance of preliminary proceedings for alleged indications of damage to the environment in their place of residence which would result from an alleged leakage from the adjacent gas station under the Company’s branding. Preliminary measures are being conducted in this proceeding.

- Neighbors of the Province of Neuquén brought a proceeding against the Company for alleged environmental damage resulting from the hydrocarbon exploration, exploitation, transportation and well abandonment activities in which that plaintiff has been taking part. Should this not be feasible, they claim a compensation for alleged damages to support the Environmental Restoration Fund. Additionally, they request the redress of alleged moral damages to be allocated to the Environmental Restoration Fund. The presence of all involved parties has been properly verified, and the lawsuit has been referred to the administrative litigation jurisdiction.

- Plaintiff Martinez Lidia and other three plaintiffs claim financial compensation for alleged damage to their health and property caused by the alleged environmental affectation sustained as a result of living next to Puerto General San Martin petrochemical plant (Rosario-Santa Fe). The evidentiary stage is closed and the Public Defender for the deceased plaintiff’s heirs was appointed, and he accepted this appointment.

- A neighbor of the Province of Buenos Aires brought a complaint against the Company seeking the removal of three fuel storage tanks and pumps and the remediation and restoration of the soils where such tanks are located on account of an alleged environmental affectation. The proceeding is in the evidentiary stage.

- Neighbors of the Province of Santa Fe have brought a complaint against the Company for alleged environmental damage. The Company obtained a favorable judgment, which has been appealed by the plaintiff.

15.4 Civil and Commercial Claims

- The “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of US$ 3,650 million as compensation for damages, Pampa, Petrolera Pampa S.A. and certain Pampa directors in office during 2016 being 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, Petrolera Pampa S.A. 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 Chamber of Appeals in Commercial Matters upheld the filed extraordinary appeal. On its part, Petróleo Brasileiro S.A. filed an appearance, requested that the lack of substance of the filed appeal should be declared, and subsidiarily answered it. The Company was served notice of the upholding of the motion made by the Chamber of Appeals in Commercial Matters and filed a presentation in this respect. Later, the CSJN declared the nullity of the Chamber of Appeals in Commercial Matters’ decision upholding the extraordinary appeal and referred the court file back so that a new judgment should be rendered.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2022 where the related inflows of economic benefits are estimated to be probable by the Company.

15.5 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, subsidiarily, sustained damages should be redressed. Later on, CTLL filed a new contentious administrative litigation complaint against the Federal Government for contractual breach during the April 2016-October 2018 period. In the complaint for the January-March 2016 period, the closing of the evidentiary stage was suspended on account of the proceeding’s link with the complaint subsequently field for the April 2016- October 2018 period, proceeding which is currently in the evidentiary stage.

- 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. Both parties agreed to suspend the proceeding to pursue a private settlement, the rendering of judgment was requested and the CSJN has set a preliminary hearing, which was carried out. 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. On September 1, 2021 a request for an expedited procedure was filed. On September 1, 2021. a request for an expedited procedure was filed. On December 2, 2021, the Company filed a protective action (amparo) on the grounds of undue delay seeking that defendant should state its opinion in this respect. A judgment was rendered dismissing the amparo. The Company has filed an appeal against this decision, which was dismissed by the Chamber hearing the case. As MECON’s term to state its position on the RAP has expired, the Company has brought a complaint against the Federal Government.

15.6 Civil and Commercial Claims

- EcuadorTLC (currently Pampa Bloque 18), 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 —in both cases, as amended—. 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.

- Ecuador TLC (currently Pampa Bloque 18), brought an arbitration claim against Petroecuador before the arbitration and mediation center of the Chamber of Commerce of Quito as a result of certain breaches to the transportation agreement entered into on December 31, 2008 whereby the Ecuadorian Government undertook the crude oil transportation commitment through the OCP, to be charged to the oil transportation capacity hired by Pampa Bloque 18. On August 3, 2022, the Arbitration Court rendered a final and conclusive award partially upholding the complaint. Even though the award was not annulled, Petroecuador filed an extraordinary protection proceeding before the Constitutional Court. It is worth highlighting that this proceeding does not suspend the execution of the arbitration award. As of December 31, 2022, Pampa Bloque 18 recorded a US$ 37.4 million receivable as compensation for the arbitration complaint in Ecuador. As of the issuance of these Consolidated Financial Statements, Petroecuador has partially fulfilled the award and made a US$ 20 million payment.

- The Company has instituted an international arbitration proceeding against High Luck Group Limited - Argentina branch as a result of certain breaches to the Participation Assignment Agreement and the Joint Operation Agreement for the Chirete Block entered into on April 1, 2015.

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RELATED PARTIES´ TRANSACTIONS

12 Months Ended

Dec. 31, 2022

Related Parties Transactions

RELATED PARTIES´ TRANSACTIONS

NOTE 16: RELATED PARTIES´ TRANSACTIONS

16.1 Balances with related parties

As of December 31, 2022	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
TGS	5	17	6	7
Other related parties
SACDE	-	-	-	7
Other	-	-	1	-
	5	17	7	14
As of December 31, 2021	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
OCP	-	-	2	-
Refinor	1	-	-	2
TGS	6	23	5	3
Other related parties
SACDE	-	-	-	10
Other	-	-	1	-
	7	23	8	15

16.2 Operations with related parties

Operations for the year	Sales of goods and services (1)			Purchases of goods and services (2)			Fees for services (3)			Other operating expenses and income (4)
	2022	2021	2020	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
CTB	2	2	2	-	-	-	-	-	-	-	-	-
Greenwind	-	1	1	-	-	-	-	-	-	-	-	-
Refinor	11	9	10	(11)	(6)	(5)	-	-	-	-	-	-
TGS	51	45	20	(53)	(43)	(24)	-	-	-	-	-	-
Other related parties
Fundación	-	-	-	-	-	-	-	-	-	(2)	(2)	(2)
SACDE	-	-	-	(203)	(48)	(6)	-	-	-	-	-	-
Salaverri, Dellatorre, Burgio & Wetzler	-	-	-	-	-	-	(1)	(1)	(1)	-	-	-
	64	57	33	(267)	(97)	(35)	(1)	(1)	(1)	(2)	(2)	(2)

⁽¹⁾ Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas and refined products.

⁽²⁾ Correspond to natural gas transportation services, purchases of refined products and other services imputed to cost of sales for US$ 191 million, US$ 50 million and US$ 29 million and infrastructure works contracted to SACDE imputed in property, plant and equipment for US$ 76 million, US$ 47 million and US$ 6 million, of which US$ 38 million, US$ 17 million and US$ 2 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, 2022, 2021 and 2020, respectively.

⁽³⁾ Disclosed within administrative expenses.

⁽⁴⁾ Corresponds mainly to donations.

Operations for the year	Finance income (1)			Dividends received			Payment of dividends
	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
Citelec	-	-	-	-	-	13	-	-	-
OCP	-	1	1	10	20	21	-	-	-
TGS	2	3	3	-	-	-	-	-	-
Other related parties
EMESA	-	-	-	-	-	-	-	-	(9)
Other	-	-	-	-	-	1	-	-	-
	2	4	4	10	20	35	-	-	(9)

⁽¹⁾ Corresponds mainly to financial leases and accrued interest on loans granted.

16.3 Key management personnel remuneration

During the years ended December 31, 2022 2021 and 2020, the total remuneration to executive directors accrued amounts to US$ 26 million (US$ 7 million for Directors' and Sindycs' fees and US$ 19 million in the accrual of Stock-based Compensation Plans and Compensation Agreements), US$ 7 million (US$ 6 million for Directors' and Sindycs' fees and US$ 1 million in the accrual of Stock-based Compensation Plans and Compensation Agreements ), and US$ 7 million (US$ 6 million for Directors' and Sindycs' fees and US$ 1 million in the accrual of EBDA Compensation and Stock-based Compensation Plans), respectively.

It should be noted that, as stipulated in the compensation agreements (See Note 4.17.1), and considering that no compensation had been assigned in favor of the Company’s main officers over the last three fiscal years, on September 30, 2021 they exercised the right to set the Company’s ADR weighted average listed price over the 30 business exchange days before the closing of year 2020 as the new initial market value to calculate compensations as from fiscal year 2021. Following the exercise of this option, the officers have lost all their rights to accrued and uncollected compensations for the previous fiscal years, which generated the recognition of a profit of US$ 6.7 million as of December 31, 2021.

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INVESTMENT COMMITMENTS

12 Months Ended

Dec. 31, 2022

Investment Commitments

INVESTMENT COMMITMENTS

NOTE 17: INVESTMENT COMMITMENTS

17.1 New generation projects

Under the National Government’s call for the expansion of the generation offer, the Company participated in the following generation projects:

PEPE IV

In early 2022, works started for the expansion of PEPE III, inaugurated in 2019 and located in the town of Coronel Rosales, Province of Buenos Aires, which production is targeted at the large users’ segment, with 14 wind turbines and an installed capacity of 53.2 MW.

The project, with an estimated investment of US$ 128 million, will mainly consist of the mounting and installation (in stages) of 18 additional wind turbines, adding a capacity of 81 MW; therefore, once works are completed, PEPE III and PEPE IV will have an installed capacity of 134.2 MW. The expansion requires sophisticated works on the platforms and foundations, which will be conducted by SACDE, and the start-up is planned for the second quarter of 2023.

On December 29, 2022 took place the commissioning of 4 wind turbines which have a capacity of 18 MW, and on February 25, 2023, took place the commissioning of 4 additional wind turbines with an incremental capacity of 18 MW.

17.2 Investment commitment for the exploration and exploitation of hydrocarbons

Regarding the investment project committed by CENCH for the Sierra Chata block, on June 29, 2022 was published Provincial Executive Order No. 1,262/22 approving the new investment schedule. Under it, the consortium made up by the Company and Mobil Argentina S.A. undertakes to execute 14 horizontal wells targeting the Vaca Muerta formation by July 26, 2023.

As of the issuance of these Consolidated Financial Statements, the Company has committed investments until 2024 for an estimated total amount of US$ 180 million, including commitments associated with the participations detailed in Note 5.3.

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INCIDENT AT GENELBA THERMAL POWER PLANT

12 Months Ended

Dec. 31, 2022

Incident At Genelba Thermal Power Plant

INCIDENT AT GENELBA THERMAL POWER PLANT

NOTE 18: INCIDENT AT GENELBA THERMAL POWER PLANT

On May 31, 2021 an incident occurred in the GEBATG03 (TG21) unit, which makes up Genelba thermal power plant’s Genelba Plus combined cycle, and damage was caused to the unit’s turbine. As a result of the incident, the combined-cycle generation capacity was reduced by approximately 50% (280 MW).

Jointly with the turbine’s manufacturer (SIEMENS), the Company performed the necessary works to dismantle and repair the failure, which were completed in July 2021.

Moreover, the Company is making all necessary filings before the insurance companies to collect the compensatory damages for the failure and minimize losses associated with the breach of availability commitments.

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LEASES

12 Months Ended

Dec. 31, 2022

Leases

LEASES

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, 2022 and 2021 is disclosed below:

19.1.1 Right of use assets

	Original values
				Decrease
Type of good		At the beginning	Increase		At the end
Machinery and equipment		20	1	(1)	20
Total at 12.31.2022		20	1	(1)	20
Total at 12.31.2021		13	7	-	20
		Amortization
Type of good		At the beginning	For the year	At the end
Machinery and equipment		(8)	(3)	(11)
Total at 12.31.2022		(8)	(3)	(11)
Total at 12.31.2021		(3)	(5)	(8)
		Net book values
Type of good		At 12.31.2022	At 12.31.2021
Machinery and equipment		9	12
Total at 12.31.2022		9
Total at 12.31.2021			12

19.1.2 Lease liabilities

	12.31.2022	12.31.2021
At the beginning of the year	13	12
Increases	1	6
Result from measurement at present value (1)	2	-
Reversal of unused amounts	(1)	-
Payments	(3)	(5)
At the end of the year	12	13

⁽¹⁾ Included in Other financial results.

As of December 31, 2022 and 2021, this liability is disclosed under Other current payables in the amount of US$ 2 million and US$ 4 million and Other non-current payables for US$ 10 million and US$ 9 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:

	12.31.2022
Three months to one year	1
One to two years	1
Two to three years	3
Three to four years	2
Four to five years	2
More than five years	14
Total	23

19.1.3 Short-term or low value leases

As of December 31, 2022 and 2021, the Company has recognised administrative costs and expenses in the amount of US$ 6 million on account of lease payments associated with short-term leases.

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, 2022 and 2021, this receivable is disclosed under Other current receivables in the amount of US$ 6 million and US$ 5 million, respectively and under Other non-current receivables for US$ 17 million and US$ 23 million, respectively.

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:

	12.31.2022
Less than three months	1
Three months to one year	5
One to two years	5
Two to three years	7
Three to four years	5
Total	23

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, 2022 are detailed below:

	12.31.2022
Three months to one year	1
One to two years	1
More than three years	1
Total	3

Total income from operating leases for the fiscal year ended December 31, 2022 amounts to US$ 1 million.

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TERMINATION OF HYDROELECTRIC CONCESSIONS

12 Months Ended

Dec. 31, 2022

Termination Of Hydroelectric Concessions

TERMINATION OF HYDROELECTRIC CONCESSIONS

NOTE 20: TERMINATION OF HYDROELECTRIC CONCESSIONS

As the hydroelectric concessions timely granted by the Federal Government and, in some cases, by the Provinces approach expiration, on March 10, 2022, SE Resolution No. 130/22 was published, creating a Concessioned Hydroelectric Exploitations Team to evaluate the status of the hydropower concessions under national jurisdiction, including HIDISA, HINISA, and HPPL.

This team will be presided over by the Secretary of Energy (or the person appointed by him) and coordinated by a person with proven experience in the field. It will also be made up of representatives of the SE, CAMMESA, the ENRE, and IEASA. Furthermore, the Dam Safety Regulatory Body and water management and environmental protection authorities are invited to appoint a representative in the team.

The concessions' status report must be submitted within two years for the HIDISA and HINISA concessions, expiring in 2024, whereas the term for issuing the report for HPPL, which concession expires in 2029, will be later determined.

Finally, IEASA is entrusted with the technical audit of the power generation equipment.

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DOCUMENTATION KEEPING

12 Months Ended

Dec. 31, 2022

Documentation Keeping

DOCUMENTATION KEEPING

NOTE 21: DOCUMENTATION KEEPING

On August 14, 2014, the CNV issued General Resolution No. 629, which introduced modifications to the provisions applicable to the keeping and conservation of corporate and accounting books and commercial documentation. To such effect, the Company, have 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 and in the Iron Mountain Argentina S.A.’s data warehouses located at the following addresses:

- Azara 1245 – C.A.B.A.

- Don Pedro de Mendoza 2163 – C.A.B.A.

- Amancio Alcorta 2482 - C.A.B.A.

- San Miguel de Tucumán 601, Carlos Spegazzini, Municipality of Ezeiza, 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.

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OIL AND GAS RESERVES (Information not covered by the auditors’ report)

12 Months Ended

Dec. 31, 2022

Oil And Gas Reserves

OIL AND GAS RESERVES (Information not covered by the auditors’ report)

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, 2022.

	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	7,722	17,372	3,214	11,241	10,936	28,613
Total at 12.31.2022	7,722	17,372	3,214	11,241	10,936	28,613

⁽¹⁾ In thousands of barrels.

⁽²⁾ In millions of cubic meters.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2022

Subsequent Events

SUBSEQUENT EVENTS

NOTE 23: SUBSEQUENT EVENTS

PEPE VI

In February 2023, the Company started constructing Pampa Energía VI Wind Farm in Bahía Blanca, Province of Buenos Aires. The project will enable the installation of a 300 MW power capacity, in 3 stages, with an estimated US$ 500 million investment.

Stage 1 comprises the mounting and installation of 21 Vestas wind turbines, with their internal medium-voltage cable network, roads, a substation and a 500 KV line allowing for a 94.5 MW capacity addition, with an investment for US$ 186 million, expected to be operative in mid-2024.

The energy produced by this wind park allows for reduced carbon emissions and will be sold through the MATER to supply large companies in the country in compliance with the Renewable Energy Law.

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ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies

New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2022 and adopted by the Company

4.1 New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2022 and adopted by the Company

The Company has applied the following standards and/or amendments for the first time as of January 1, 2022:

- IFRS 3 “Business combination” (amended in May 2020).

- Annual Improvements to IFRS Standards - 2018-2020 cycle (issued in May 2020).

- IAS 16 “Property, Plant and Equipment” (amended in May 2020).

- IAS 37 “Provisions, contingent liabilities and contingent assets” (amended in May 2020).

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.

New standards, amendments and interpretations issued by the IASB not yet effective and which have not been early adopted by 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

- IFRS 17 - “Insurance Contracts”: issued in May 2017 and modified in June 2020 and December 2021. It supersedes IFRS 4, introduced in 2004 as an interim standard, which gave companies dispensation to carry on accounting for insurance contracts using national accounting standards, thus resulting in several application approaches. IFRS 17 sets the principles for the recognition, measurement, presentation and disclosure of information associated with insurance contracts and is applicable as from January 1, 2023, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in February 2021. It incorporates amendments to the information to be disclosed on accounting policies. Amendments are applicable to fiscal years starting on or after January 1, 2023, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 8 - “Accounting Policies”: amended in February 2021. Clarifies the treatment of estimates required in the application of accounting policies. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

- IAS 12 - “Income Tax”: amended in May 2021. It incorporates modifications regarding the recognition of deferred tax related to assets and liabilities that arise from a single transaction, giving riso to equal taxable and deductible temporary differences. Amendments are applicable to fiscal years beginning on or after January 1, 2023, allowing for early adoption. Their application will not have an impact on the Company’s operating results or financial position.

- IFRS 16 - “Leases”: amended in September 2022. It incorporates amendments on sale and leaseback transactions. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Its application will not have a significant impact on the Company’s operating results or financial position.

- IAS 1 - “Presentation of financial statements”: amended in January 2020, July 2020 and October 2022. It incorporates amendments to the classification of liabilities as current or non-current and provides clarification on the treatment to be given to liabilities with covenants. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company’s operating results or financial position.

Effects of changes in foreign exchange rates

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 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 IAS 29 adjustment mechanism for hyperinflationary economies, on the opening equity measured in functional currency are recognised 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.

Principles of consolidation and equity accounting

4.4 Principles of consolidation and equity accounting

4.4.1 Subsidiaries

Subsidiaries are all entities over which the Group has control. 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. The Group 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 (see Note 4.4.5 below).

Intercompany transactions, balances and unrealized gains on transactions between Group entities are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the transferred asset. 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, Consolidated Statement of Changes in Equity and Consolidated Statement of Financial Position respectively.

4.4.2 Associates

Associates are all entities over which the group has significant influence but not control or joint control. This is generally the case where the Group holds between 20% and 50% of the voting rights. Investments in associates are accounted for using the equity method of accounting (see Note 4.4.4 below), after initially being recognised at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according to IFRS 11. The classification depends on the contractual rights and obligations of each investor, rather than the legal structure of the joint arrangement. The Company has both joint operations and joint ventures.

4.4.3.1 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. These have been incorporated in the Consolidated Financial Statements under the appropriate headings.

4.4.3.2 Joint ventures

Interests in joint ventures are accounted for using the equity method, after initially being recognised at cost (see Note 4.4.4 below).

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognised at cost and adjusted to recognize the Group’s share of the post-acquisition profits or losses of the investee in profit or loss, and the Group’s share of movements in other comprehensive income of the investee in other comprehensive income.

On acquisition of the investment, any difference between the cost of the investment and the entity’s share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as follows: (i) goodwill relating to an associate or a joint venture is included in the carrying amount of the investment and is not amortised, and (ii) any excess of the net fair value over the cost is included as income in the determination of the entity’s share of the associate or joint venture’s profit or loss.

Dividends received or receivable from associates and joint ventures are recognised as a reduction in the carrying amount of the investment.

When the Group’s share of losses in an equity-accounted investment equals or exceeds its interest in the entity, together with any long-term interests that, in substance, form part of the net investment, the Group does not recognize further losses, unless it has incurred obligations or made payments on behalf of the other entity.

Unrealized gains on transactions between the Group and its associates and joint ventures are eliminated to the extent of the group’s interest in these entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of equity accounted investees have been changed where necessary to ensure consistency with the policies adopted by the Group.

The carrying amount of equity accounted investments is tested for impairment in accordance with the policy described below in Note 4.9.

4.4.5 Business combinations

The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisitions comprises:

(i) the fair value of the transferred assets,

(ii) the liabilities incurred to the former owners of the acquired business,

(iii) the equity interests issued by the group,

(iv) the fair value of any asset or liability resulting from a contingent consideration arrangement, and

(v) the fair value of any pre-existing equity interest in the subsidiary.

Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values in the acquisition date. The group recognises any non-controlling interest in the acquired entity on an acquisition-by-acquisition basis at the non-controlling interest’s proportionate share of the acquired entity’s net identifiable assets.

Acquisition-related costs are expensed as incurred. The value of the goodwill represents the excess of: i) the consideration transferred, ii) the amount of any non-controlling interest in the acquired entity, and iii) the acquisition-date fair value of any previous equity interest in the acquired entity, over the fair value of the net identifiable assets acquired is recorded as goodwill. If the fair value of the net identifiable assets of the business acquired exceeds those amounts, the gain on bargain purchase is recognised directly in profit or loss.

Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing could be obtained from an independent financier under comparable terms and conditions.

Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently remeasured to fair value with changes in fair value recognised in profit or loss.

If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit or loss.

The Group has up to 12 months to finalize the accounting for a business combination. Where the accounting for a business combination is not complete by the end of the year in which the business combination occurred, the Group reports provisional amounts.

4.4.6 Changes in ownership interests

The Group treats transactions with non-controlling interests that do not result in a loss of control as transactions with equity owners of the group. A change in ownership interest results in an adjustment between the carrying amounts of the controlling and non-controlling interests to reflect their relative interests in the subsidiary. Any difference between the amount of the adjustment to non-controlling interests and any consideration paid or received is recognised in “Other reserves” within equity attributable to owners of the Company.

When the Group ceases to consolidate or equity account for an investment because of a loss of control, joint control or significant influence, any retained interest in the entity is remeasured to its fair value with the change in carrying amount recognised in profit or loss. This fair value becomes the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities, this means that amounts previously recognised in other comprehensive income are reclassified to profit or loss.

If the ownership interest in a joint venture or an associate is reduced but joint control or significant influence is retained, only a proportionate share of the amounts previously recognised in other comprehensive income are reclassified to profit or loss where appropriate.

Segment reporting

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 person 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.

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.

Property, plant and equipment

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.

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.

Works in progress are valued according to their degree of progress. Works in progress are recorded at cost less any loss due to impairment, if applicable.

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.

Gains and losses on disposals are determined by comparing the sale price with the carrying amount, stated in terms of the measuring unit current at the disposal date.

4.6.1 Depreciation methods and useful lives

The group depreciates productive wells, machinery and camps 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.

Machinery and generation equipment (including any significant identifiable component) are depreciated under the unit of production 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:

Buildings:	50 years
Vehicles:	3 - 5 years
Furniture, fittings and communication equipment:	5 years
Computer equipment and software:	3 years
Tools:	10 years
Equipment and machinery:	10 - 30 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 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 in wind farms, 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.

Intangible assets

4.7 Intangible assets

4.7.1 Goodwill

Goodwill is the result of the acquisition of subsidiaries. Goodwill represents the excess of the acquisition cost over the fair value of the equity interest in the acquired entity held by the company on the net identifiable assets acquired on the date of acquisition.

For impairment testing, goodwill acquired in a business combination is allocated from the acquisition date to each of the acquirer’s CGU or group of CGU that are expected to benefit from the synergies of the combination. Each unit or group of units that goodwill is allocated represents the lowest level within the entity at which the goodwill is monitored for internal management purposes.

4.7.2 Concession arrangements

Concession arrangements corresponding to hydroelectric generation plants Diamante and Nihuiles are not under the scope of the guidelines of IFRIC 12 “Service Concession Arrangements”.

These concession agreements meet the criteria set forth by the IFRSs for capitalization less depreciation a less any accumulated impairment. They are amortized following the straight-line method based on useful life, which corresponds to the life 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. Identified assets meet the criteria established in IFRS 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, considering the estimated way in which the benefits produced by the asset will be consumed.

4.7.4 Digital Assets

The Company accounts for digital assets (cryptocurrencies) as intangible assets with indefinite useful life under the cost model. They are recognised at acquisition cost less any accumulated impairment.

Assets for oil and gas exploration

4.8 Assets for oil and gas exploration

The Company uses the successful efforts method of accounting for its oil and gas exploration and production activities. This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas exploration and production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of commercially recoverable reserves; (iii) the cost of drilling and equipping development wells, and (iv) the estimated asset retirement obligations (see Note 4.6.2).

According to the successful efforts method of accounting, exploration costs (including geological and geophysical costs), excluding exploratory well costs, are expensed during the period in which they are incurred. Drilling costs of exploratory wells are capitalized until it is determined that proved reserves exists and they justify the commercial development. If reserves are not found, such drilling costs are expensed. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is complete. In those cases, such costs continue to be capitalized insofar as the well has allowed determining the existence of sufficient reserves to warrant its completion as a production well and the Company is making sufficient progress in evaluating the economic and operating feasibility of the project.

Impairment of non-financial long-lived assets

4.9 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 impairment, 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.

Financial assets

4.10 Financial assets

4.10.1 Classification

The Group classifies its financial assets in the following categories:

(i) those that are subsequently measured at fair value, and

(ii) those that are subsequently measured at amortised cost.

The classification depends on the entity’s business model for managing the financial assets and the contractual cash flow characteristics.

Gains and losses from financial assets measured at fair value, will be recorded in the Statement of Comprehensive Income or in the Other Comprehensive Income.

Investments in equity instruments are measured at fair value. For those investments that are not held for trading, the Company may make an irrevocable election at initial recognition to present subsequent changes in other comprehensive income. The Company's election was to recognize changes in fair value through profit and loss.

The company reclassifies financial assets when and only when it changes its business model for managing those financial assets.

4.10.2 Recognition and derecognition

The conventional purchases and sales of financial assets are accounted for at settlement date. Financial assets are derecognised when contractual rights to the cash flows from the financial assets have expired or been transferred, and the Company has substantially transferred all risks and rewards of ownership of the asset.

4.10.3 Measurement

At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset.

A gain or loss on a debt investment that is subsequently measured at fair value and is not part of a hedging relationship is recognised in profit or loss and disclosed in “Changes in the fair value of financial instruments” within “Other financial Results. A gain or loss on a debt investment that is subsequently measured at amortized cost and is not part of a hedging relationship is recognised in profit or loss when the financial asset is derecognised or impaired and through the amortization process using the effective interest rate method.

The Group subsequently measures equity investments at fair value. Dividends from such investments continue to be recognised in profit or loss as long as they represent a return on investment.

4.10.4 Impairment of financial assets

The Company assesses the expected credit losses related to its financial instruments at amortized cost and financial instruments at fair value through other comprehensive income, if applicable.

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.

4.10.5 Offsetting of financial instruments

Financial assets and liabilities are offset, and the net amount reported in the consolidated statements of financial position, when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

Trade and other receivables

4.11 Trade and other receivables

Trade receivables and other receivables are recognised at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognizes provisions for impairment on trade and other receivables based on expected credit loss model described in Note 4.10.4. Trade receivables are written off when there is no reasonable expectation of recovery. The Company considers the following default indicators: i) voluntary reorganization proceedings, bankruptcy or initiation of judicial demands; ii) insolvency implying a high impossibility of collection and iii) past due balances greater than 90 days.

Where 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.

Derivative financial instruments and hedging account

4.12 Derivative financial instruments and hedging account

Derivative financial instruments are measured at fair value, determined as the amount of cash to be collected or paid to settle the instrument as of the measurement date, net of any prepayment collected or paid. Fair value of derivative financial instruments traded in active markets is disclosed based on their quoted market prices and fair value of instruments that are not traded in active markets is determined using different valuation techniques. Subsequent accounting of 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.

The Company may designate derivative financial instruments in the following categories:

(i) fair value hedge of recognised assets or liabilities or over firm commitment (fair value hedge);

(ii) cash flow hedges of a particular risk associated with recognised assets and liabilities and highly probable future transactions (cash flow hedges), or

(iii) net investment hedge in foreign operation (net investment hedges).

At the beginning of the hedge relationship, the Group documents the economic relationship between the hedging instruments and the hedged items, even if it is expected that changes in the cash flows of the hedging instruments offset changes in the cash flows of the hedged items. The Group documents its objective and risk management strategy to carry out its hedging operations.

Changes in the measurement of derivative financial instruments designated as cash flow hedge, which have been determined as effective, are recognised in equity. The gain or loss related to the ineffective portion is recognised immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognised in profit or loss.

The Company has not formally designated financial instruments as hedging instruments.

Inventories

4.13 Inventories

This line item includes crude oil stock, raw materials, work in progress and finished products relating to Petrochemicals and Oil and Gas business segments as well as materials and spare parts relating to the Generation business segment.

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average price method. The cost of inventories 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 assessment of the recoverable value of these assets is made at each reporting date, and the resulting loss is recognised in the statement of income when the inventories are overstated.

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”.

Non-current assets (or disposal group) held for sale and discontinued operations

4.14 Non-current assets (or disposal group) held for sale and discontinued operations

Non-current assets are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights from insurance contracts, which are specifically exempt from this requirement.

An impairment loss is recognized for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset (or disposal group), but not in excess of any cumulative impairment loss previously recognized. The gain or loss not previously recognized by the date of the sale of the non-current asset is recognized at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised.

Non-current assets or group of assets classified as held for sale are presented separately from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the balance sheet. These assets and liabilities are not offset.

If it is a discontinued operation, that is, an item which has been disposed of or classified as held for sale; and (i) it represents a significant business line or geographic area which may be considered separate from the rest; (ii) it is part of a single coordinated plan to dispose of a significant business line or operating geographic area which may be deemed separate from the rest; or (iii) it is a subsidiary entity acquired solely for the purpose of reselling it; a single amount is disclosed in the statement of comprehensive income, which shows results of discontinued operations, net of tax, including the result for the valuation at fair value less cost of sales or asset disposal costs, if applicable.

Cash and cash equivalents

4.15 Cash and cash equivalents

For the purpose of presentation in the Consolidated Statement of Cash Flows, cash and cash equivalents includes 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 in the Consolidated Statement of Financial Position 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.

Shareholder´s equity

4.16 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 have been restated in terms of the measuring unit current as of December 31, 2018, with the exception of Share capital and Treasury shares, which represent the subscribed and paid in, and the outstanding treasury capital, respectively. The adjustment resulting from its restatement as of December 31, 2018 is disclosed in the Comprehensive share capital adjustment and Comprehensive treasury shares adjustment lines, respectively.

As from the change in functional currency, on January 1, 2019 the Company discontinued the preparation and presentation of financial statements under IAS 29, and has considered equity figures expressed in terms of the measuring unit current as of December 31, 2018 as the basis for subsequent financial statements’ amounts. 

4.16.1 Share capital

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.

4.16.2 Share premium

It 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 or significant influence.

(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.

4.16.3 Legal reserve

In accordance with the Argentine Commercial Companies General Law, 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.

4.16.4 Voluntary reserve

This reserve results from an allocation made by the Shareholders’ Meeting, whereby a specific amount is set aside to cover for the funding needs of projects and situations associated with Company policies. 

4.16.5 Other reserves

It includes the result of operations with non-controlling interest that do not result in a loss of control and reserves for stock compensation plans. 

4.16.6 Retained earnings

Comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of Shareholders' meeting, as long as they are not subject to legal restrictions. Earnings comprise current earnings, prior years' earnings that were not distributed, translation differences which are directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4, the amounts transferred from other comprehensive income and prior years' adjustments, according to IFRS.

General Resolution No. 593/11 issued by the CNV provided that Shareholders in the Meetings at which they should decide upon the approval of financial statements in which the Retained earnings account has a positive balance, should adopt an express resolution as to the allocation of such balance, whether to dividend distribution, capitalization, setting up of reserves or a combination of these. The Company’s Shareholders have complied with these requirements.

4.16.7 Other comprehensive income

It 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 and actuarial gains and losses for defined benefit plans and the related tax effect.

4.16.8 Dividends distribution

Dividend distribution to Company shareholders is recognised 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.

Compensation plans

4.17 Compensation plans

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

4.17.1 Compensations payable in cash:

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 over the Company’s adjusted operating income. With the purpose of avoiding duplication, any analogous compensation paid to senior managers by any of the Company’s subsidiaries will be deducted from the compensation amount in proportion to the Company’s interests in such subsidiaries. 

The reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton financial valuation 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. 

4.17.2 Compensations payable in shares

Stock compensation plan by which certain officers and other key staff receive a certain number of the Company’s shares. The Company’s Board of Directors approves the market acquisition of own shares as a means of implementing the Plan (see Note 13.1.2).

The number of shares is calculated as from a percentage over the total annual remuneration, plus the bonus assigned to each covered employee, 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.

Trade payables and other payables

4.18 Trade payables and other payables

Trade payables and other payables are recognised initially at fair value and subsequently measured at amortized cost using the effective interest method.

Borrowings

4.19 Borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings, using the effective interest method.

Borrowings are removed from the statement of financial position when the obligation specified in the contract is discharged, canceled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in profit or loss as other income or finance costs.

If a debt contract is amended or swapped, the Company records the cancellation of the original liability and discloses 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. 

4.19.1 Borrowing costs

General and specific borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset are capitalized during the period of time that is required to complete and prepare the asset for its intended use or sale. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalization.

Other borrowing costs are expensed in the period in which they are incurred.

Employee benefits

4.20 Employee benefits

4.20.1 Short-term obligations

Payroll liabilities, including non-monetary benefits and accumulated sick leave expected to be settled in full within 12 months after the end of the reporting period in which the employees provide the associated service are recognised for the amount expected to be paid when the liabilities are settled. The liabilities are disclosed as Salaries and social security payable in the consolidated statement of financial position.

4.20.2 Defined benefit plans

Labor costs liabilities are accrued in the periods in which the employees provide the services that trigger the consideration.

Additionally, the Company operates several 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).

Provisions, contingent liabilities and contingent assets

4.21 Provisions, contingent liabilities and contingent assets

Provisions are recognised when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle that obligation, and the amount can be reliably estimated. Provisions are not recognised for future operating losses.

Provisions are measured at the present value of the expenditures expected to be required to settle the present obligation, taking into account the best available information as of the date of the Consolidated Financial Statements based on assumptions and methods considered appropriate and taking into account the opinion of Company’s legal advisors. As additional information becomes available to the Company, estimates are revised and adjusted periodically. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability, as of the date of the financial statements. The increase in the provision due to the passage of time is recognised within other financial results.

Contingent liabilities are possible obligations that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity; or present obligations that arise from past events but it is not probable that an outflow of resources will be required to its settlement; or whose amount cannot be measured with sufficient reliability.

Contingent liabilities are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent liabilities.

Contingent liabilities, whose possibility of any outflow in settlement is remote, are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Contingent assets are possible assets that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity.

Contingent assets are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent assets, where the related inflows of economic benefits are estimated to be probable.

Revenue from contracts with customers

4.22 Revenue from contracts with customers

4.22.1 Generation segment:

4.22.1.1 Revenues from sales to the spot market (SE Resolution N°826/22)

The Company recognizes revenues from i) power availability on a monthly basis as the different power plants are available to generate; ii) power generated, operated energy and power generated in peak hours, when the delivery of energy is effective, based on the price applicable depending on the technology of each plant. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 42 days, which is consistent with market practice.

4.22.1.2 Revenues from supply agreements with CAMMESA (SE Resolution No. 220/07, SEE Resolution No. 21/16, SEE Resolution No. 287/17 and Renovar Programs)

The Company recognizes revenues from supply contracts with CAMMESA for i) power availability, when applicable, on a monthly basis, as the different power plants are available to generate and ii) energy generated when the delivery of energy is effective, 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 credit term of 42 days, which is consistent with market practice.

4.22.1.3 Revenues from sales contracts with large users within the MAT

The Company recognizes revenues from energy plus sales and renewable energy when the delivery of energy is effective 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 credit term of 30 days, which is consistent with market practice. 

4.22.2 Oil and gas segment

The Company recognizes revenues from the sale of oil and gas, to third parties and intersegment, 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 could affect the acceptance of the product by the client. In all cases the transport of the gas is in charge of the client. Revenues from these sales are recognised based on the price by product specified in each contract or agreement 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 credit term not exceeding 45 days, which is consistent with market practice.

4.22.3 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 products according to the sale contract, the acceptance provisions have expired, 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 credit term not exceeding 30 days, which is consistent with market practice.

4.22.4 Holding 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.

Other Income

4.23 Other Income

4.23.1 Government grants

Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. The group did not benefit directly from any other forms of government assistance.

The Company recognizes revenues from natural gas production promotion or stimulus programs upon the actual delivery of gas and in accordance with the price established in the applicable regulation, only inasmuch as it is highly probable that there will be no significant reversal and the consideration is likely to be received, that is, to the extent that the procedure defined by the Government is formally complied with.

The recognition of revenues associated with Natural Gas Production Promotion or Stimulus Plans (see Note 2.2.4.1) falls within the scope of IAS 20 as it involves a compensation as a result of the maintenance or increase in the committed production volume.

Revenues from natural gas production or stimulus programs are disclosed under other operating income in the consolidated statement of comprehensive income. Furthermore, the fiscal costs of the above-mentioned programs are disclosed under Other operating expenses in the consolidated statement of comprehensive income. 

4.23.2 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 cost and financial assets at fair value through other comprehensive income 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.

4.23.3 Dividends

Dividends income are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognised as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

Income tax

4.24 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, in which case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet. 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.

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. However, deferred tax liabilities are not recognised if they come from the initial recognition of goodwill; or if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at time of the transaction affects neither accounting nor taxable profit or loss.

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 Law No 27,701, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1).

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 have not been discounted and are stated at their nominal value.

Income tax rates prevailing at year-end in Argentina (see Note 2.6.1), Ecuador, Bolivia and Uruguay are 35%, 25%, 25% and 25%, respectively. Additionally, a 3% surcharge is added to Ecuador’s income tax when the company’s shareholder residing in Ecuador is an entity established in a jurisdiction considered a tax haven under Ecuadorian laws.

In Bolivia, payment of Bolivian-source income to beneficiaries outside Bolivia is levied with a 12.5% withholding income tax. Furthermore, and pursuant to the last tax reform passed in Ecuador and effective as from January 1, 2020, dividends distributed to foreign shareholders will be subject to a 10% withholding.

In Uruguay, effective from January 1, 2023, the Income Tax on Economic Activities (“IRAE”) covers certain Uruguayan-source passive income derived by entities making up multinational groups.

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.

Leases

4.25 Leases

In leases where the Company is a lessee (Note 19.1), a right-of-use asset and a lease liability are recognised on the date on which the underlying asset is available for use by the Company.

At the commencement date the lease liability is measured at the present value of the payments that are not paid at that date, including:

- fixed payments, less any lease incentive receivable

- variable lease payments depending on an index or rate

- amounts that the Company expects to pay under residual value guarantee

- exercise price of a purchase option (if the Company is reasonably certain to exercise that option), and

- penalty payments for terminating the lease, if the lease term reflects the Company exercising that option.

Lease payments are discounted using the Company’s incremental borrowing rate, which is the rate the Company would have to pay to borrow over a similar term, security and conditions, the funds necessary to acquire an asset of a similar value to the right-of-use asset in a similar economic environment, or by using the interest rate implicit in the lease, if that rate can be readily determined.

The lease liability is disclosed in “Trade and other payables”. Each lease payment is apportioned between the principal and the financial cost. The financial 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.

Right-of-use assets are measured at cost, which comprises:

- the amount of the initial measurement of the lease liability

- any lease payment made at or before the commencement date, less any lease incentive received

- any initial direct cost, and

- an estimate of costs to be incurred for decommissioning or restoring the underlying asset pursuant to the terms and conditions of the lease

Right-of-use assets are depreciated using the straight-line method over the asset’s useful life or, if shorter, during the lease term.

The Company recognizes lease payments associated with short-term leases (up to 12 months) and leases for which the underlying asset is of low value (IT equipment and office supplies) as an expense using the straight-line method over the lease term.

Leases in which the Company, as a lessor, has transferred all risks and rewards incidental to ownership of the underlying asset are classified as financial leases (Note 19.2.1). Financial leases are recognised at the commencement date 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”. Each lease payment received is allocated between income receivable and financial income. Financial income is recognised as a profit over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period. Property under financial leases is derecognised if there is reasonable certainty that the Company will transfer its ownership at the end of the lease term.

Leases in which the Company does not transfer a significant part of the risks and rewards incidental to ownership of the underlying asset are classified as operating leases. Revenues from associated leases are recognized in income using the straight-line method over the term of the lease (Note 19.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

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REGULATORY FRAMEWORK (Tables)

12 Months Ended

Dec. 31, 2022

Regulatory Framework

Schedule of generating units in operation

In operation as of 12.31.2022:
Generator	Generating unit	Tecnology	Power	Applicable regime (1)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1,281/06
CTG	GUEMTV11	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV12	TV	≤100 MW	Resolution No. 826/22
CTG	GUEMTV13	TV	>100 MW	Resolution No. 826/22
Piquirenda	PIQIDI 01-10	MCI	30 MW	Resolution No. 826/22
CPB	BBLATV29	TV	>100 MW	Resolution No. 826/22
CPB	BBLATV30	TV	>100 MW	Resolution No. 826/22
CT Ing. White	BBLMD01-06	MCI	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	>150 MW	Resolution No. 826/22
CTLL	LDLATG04	TG	105 MW	Res. No 220/07 (75%)
CTLL	LDLATG05	TG	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	MCI	15 MW	Resolution No. 826/22
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	Resolution No. 826/22
CTGEBA	GEBATG03	TG	169 MW	Energy Plus Res. No. 1,281/06
CTGEBA	GEBATG03/TG04/TV02	CC	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	14 MW	Energy Plus Res. N° 1,281/06
CT Parque Pilar	PILBD01-06	MCI	100 MW	Resolution No. 21/16
CTB	EBARTG01 - TG02	TG	>50 MW	Resolution No. 826/22 (2)
HIDISA	AGUA DEL TORO	HI	HI – Media 120<P≤300	Resolution No. 826/22
HIDISA	EL TIGRE	HR	Renewable  ≤ 50	Resolution No. 826/22
HIDISA	LOS REYUNOS	HB	HB – Media 120<P≤300	Resolution No. 826/22
HINISA	NIHUIL I - II - III	HI	HI – Small  50<P≤120	Resolution No. 826/22
HPPL	PPLEHI	HI	HI – Media 120<P≤300	Resolution No. 826/22
P.E. M. Cebreiro	CORTEO	Wind	100 MW	Renovar
PEPE II	PAMEEO	Wind	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	53 MW	MATER Res. No. 281/17
PEPE IV	BAHIEO	Wind	18 MW	MATER Res. No. 281/17
PE Arauco	AR21EO	Wind	99.75 MW	Renovar

⁽¹⁾ Surplus power capacity and energy are remunerated in the spot market. 

⁽²⁾ During the month of April 2022 the contract under Resolution No. 220/07 of CTB have ended, since then, power and energy have been remunerated in the spot market.

Schedule of generating units in construction

In construction:
Generator	Tecnology	Capacity	Applicable regime
CTB	CC	280 MW	Resolution No. 220/07
PEPE IV	Wind	63 MW	MATER Res. No. 281/17
PEPE VI	Wind	94.5 MW	MATER Res. No. 281/17

Schedule of minimum remuneration to thermal generators

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-month)	SE No. 826/22 ($ / MW-month)
Large CC Capacity > 150 MW	100,650	129,839	185,670	245,084
Large TV Capacity > 100 MW	143,550	185,180	264,807	349,546
Small TV Capacity ≤ 100 MW	171,600	221,364	316,551	417,847
Large GT Capacity > 50 MW	117,150	151,124	216,107	285,262

Schedule of remuneration for thermal generators with guaranteed power capacity

Period	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No 238/22 ($ / MW-month)	SE No 826/22 ($ / MW-month)
Summer – Winter	360,000	464,400	664,092	876,601
Fall - Spring	270,000	348,300	498,069	657,451

Schedule of additional remuneration to thermal generators

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	45,000	22,500	58,050	29,025	83,012	41,506
Fall - Spring	7,500	-	9,675	-	13,835	-

Schedule of hydroelectric generators by technology and scales values

Technology / Scale	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)	SE No. 238/22 ($ / MW-mes)	SE No. 826/22 ($ / MW-mes)
Medium HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Small HI Capacity > 50 ≤ 120 MW	181,500	234,135	334,813	441,953
Medium Pumped HI Capacity > 120 ≤ 300 MW	132,000	170,280	243,500	321,421
Renewable HI Capacity ≤ 50 MW	297,000	383,130	547,876	723,196

Schedule of hydroelectric generators by technology and scales values

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	39,000	19,500	50,310	25,155	71,943	35,972
Fall - Spring	6,500	-	8,385	-	11,991	-

Generation units ≤ 50 MW

Period	SE No. 31/20		SE No. 440/21		SE No. 238/22
	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	42,000	21,000	54,180	27,090	77,478	38,739
Fall – Spring	7,000	-	9,030	-	12,913	-

Generated and operated energy hydroelectic units remuneration

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	Between 240 and 420	Between 310 and 542	Between 403 and 705	Between 585 and 1,023
Operated energy	84	108	154	204

It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognised at 60% of the installed net capacity, irrespective of the energy delivered by the unit.

In the case of hydroelectric plants, the following prices were established for generated and operated energy, irrespective of scale:

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	210	271	388	512
Operated energy	84	108	154	204

Generated and operated energy hydroelectic units remuneration

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	210	271	388	512
Operated energy	84	108	154	204

Unconventional sources remuneration

Remuneration	SE No. 31/20 ($ / MWh)	SE No. 440/21 ($ / MWh)	SE No. 238/22 ($ / MWh)	SE No. 826/22 ($ / MWh)
Generated energy	1,680	2,167	3,099	3,719

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ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2022

Accounting Policies

Schedule of estimated useful lives

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GROUP STRUCTURE (Tables)

12 Months Ended

Dec. 31, 2022

Group Structure

Schedule of consolidated statement of comprehensive income related to discontinued operations

	Distribution of Energy
	12.31.2021	12.31.2020
Revenue	493	1,085
Cost of sales	(398)	(926)
Gross profit	95	159
Selling expenses	(36)	(79)
Administrative expenses	(26)	(64)
Other operating income	21	29
Other operating expenses	(18)	(25)
Reversal of property, plant and equipment impairment	16	(589)
Impairment of financial assets	(11)	(50)
Operating income (loss)	41	(619)
Gain on monetary position, net	120	115
Financial income	-	1
Financial costs	(106)	(110)
Other financial results	8	(20)
Financial results, net	22	(14)
Profit (Loss) before income tax	63	(633)
Income tax	(138)	41
Loss of the year from discontinued operations	(75)	(592)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans	-	1
Exchange differences on translation	34	(15)
Items that may be reclassified to profit or loss
Exchange differences on translation (1)	30	(19)
Other comprehensive income (loss) of the year from discontinued operations	64	(33)
Total comprehensive loss of the year from discontinued operations	(11)	(625)
Total  (loss) profit of the year from discontinued operations attributable to:
Owners of the company	(39)	(499)
Non - controlling interest	(36)	(93)
	(75)	(592)
Total comprehensive loss of the year from discontinued operations attributable to:
Owners of the company	(9)	(517)
Non - controlling interest	(2)	(108)
	(11)	(625)

⁽¹⁾ As of December 31, 2021, corresponds to the reclassification adjustment for exchange differences losses included in profit or loss on Edenor disposal. No exchange differences losses on translation were reconized during 2021.

Schedule of consolidated statement of cash flows related to discontinued operations

	Distribution of Energy
	12.31.2021	12.31.2020
Net cash generated by operating activities	116	211
Net cash used in investing activities	(166)	(86)
Net cash used in financing activities	(7)	(73)
(Decrease) Increase in cash and cash equivalents from discontinued operations	(57)	52
Cash and cash equivalents at the beginning of the year	52	9
Effect of devaluation and inflation on cash and cash equivalents	5	(9)
(Decrease) Increase in cash and cash equivalents	(57)	52
Cash and cash equivalents at the end of the year	-	52

Schedule of fair value of the consideration transferred

	In million US$
Consideration transferred	(20.5)
Fair value of the previous interest in Greenwind	(20.4)
Total	(40.9)
Property, plant and equipment (1)	127.7
Intangible assets - Customer contract (2)	31.6
Financial assets at fair value	24.4
Trade receivables (3)	6.3
Other assets	0.1
Cash and cash equivalents	3.1
Borrowings	(89.3)
Deferred tax liabilities	(54.3)
Income tax liabilities	(4.4)
Trade and other payables	(2.0)
Provisions	(1.4)
Tax liabilities	(0.9)
Total acquisition price allocation (4)	40.9

⁽¹⁾ Mario Cebreiro Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Schedule of fair values of assets acquired and liabilities assumed

	In million US$
Consideration transferred	(128.1)
Estimated price adjustment	6.7
Total	(121.4)
Property, plant and equipment (1)	167.7
Intangible assets - Customer contract (2)	62.3
Trade receivables (3)	4.9
Other receivables	1.2
Deferred tax liability	(60.2)
Income tax liability	(5.0)
Trade and other payables	(3.3)
Other payables	(46.0)
Tax liabilities	(0.2)
Total acquisition price allocation (4)	121.4

⁽¹⁾ Arauco Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

⁽²⁾ The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

⁽³⁾ For acquired trade receivables, contractual value does not differ from fair value.

⁽⁴⁾ No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Schedule of subsidiaries information

			12.31.2022	12.31.2021
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Autotrol Renovable S.A. (1)	Argentina	Generation	100.00%	-
GASA	Argentina	Generation	100.00%	100.00%
Enecor S.A.	Argentina	Electricity transportation	70.00%	70.00%
Fideicomiso CIESA	Argentina	Investment	100.00%	100.00%
Greenwind (3)	Argentina	Generation	100.00%	50.00%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
CISA	Argentina	Trader & investment	100.00%	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PB18	Ecuador	Oil	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Pampa Ecuador Inc	Ecuador	Investment	100.00%	100.00%
PE Energía Ecuador LTD	Gran Cayman	Investment	100.00%	100.00%
EISA	Uruguay	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
TGU	Uruguay	Gas transportation	51.00%	51.00%
Corod (3)	Venezuela	Oil	-	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
Vientos de Arauco Renovables S.A.U. (4)	Argentina	Generation	100.00%	-
Vientos Solutions Argentina S.A.U.	Argentina	Advisory services	100.00%	-
VS S.L. (2)	España	Investment	100.00%	-

⁽¹⁾ See Note 5.1.4.

⁽²⁾ See Note 5.1.3.

⁽³⁾ Interest assigned under the assignment of the indirect interest in the capital stock of mixed companies in Venezuela. See Note 5.3.2.

⁽⁴⁾ See Note 5.1.5.

Disclosure Of Investments In Associates And Joint Ventures

		Information about the issuer
	Main activity	Date	Share capital	Profit (loss) of the  year	Equity
Associates
OCP	Investment	12.31.2022	100	(4)	96
TGS (1)	Gas transportation	12.31.2022	4	182	1,508
Joint ventures
CIESA (1)	Investment	12.31.2022	4	93	770
Citelec (2)	Investment	12.31.2022	3	5	235
CTB	Generation	12.31.2022	48	53	536

⁽¹⁾ The Company holds a direct and indirect interest of 3.764% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, additionally the Company has an indirect participation of 25.50% in TGS.

As of December 31, 2022, the quotation of TGS's ordinary shares and ADR published on the Buenos Aires Stock Exchange and the NYSE was $ 811.05 and US$ 11.80, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of $ 188,568 million.

⁽²⁾ The Company holds a 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, 2022, Transener’s common share price listed at the Buenos Aires Stock Exchange was $ 184,50, conferring Pampa’s indirect interest an approximate $ 21,598 million market value.

Schedule of interest in associates and joint ventures

	12.31.2022	12.31.2021
Disclosed in non-current assets
Associates
Refinor (1)	-	22
OCP	15	24
TGS	67	52
Total associates	82	98
Joint ventures
CIESA	435	347
Citelec	117	102
CTB	268	227
Total joint ventures	820	676
Total associates and joint ventures	902	774
Disclosed in non-current liabilities
Joint ventures
Greenwind	-	(4)
Total joint ventures	-	(4)

⁽¹⁾ See Note 5.1.2.

Schedule of result from interests in associates and joint ventures

	12.31.2022	12.31.2021	12.31.2020
Associates
Refinor	(12)	(2)	(2)
OCP	(1)	18	(5)
TGS	7	7	1
Total associates	(6)	23	(6)
Joint ventures
CIESA	43	50	11
CTB	41	49	64
Citelec	3	(3)	13
Greenwind (1)	24	(2)	3
Total joint ventures	111	94	91
Total associates and joint ventures	105	117	85

⁽¹⁾ See Note 5.1.3.

Schedule of evolution of interests in associates and joint ventures

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	770	547	507
Compensation	-	-	(5)
Dividends	(8)	-	(34)
Increases	1	17	3
Decrease due to acquisition of control (1)	(20)	-	-
Decrease due to sale of equity interests  (2)	(6)	-	-
Share of profit	116	117	85
Impairment (2)	(11)	-	-
Exchange differences on translation	60	89	(9)
At the end of the year	902	770	547

⁽¹⁾    See Note 5.1.3.

⁽²⁾    See Note 5.1.2.

Investment in associates adquisition

	In million US$
Acquisition cost	(5.0)
Total consideration	(5.0)
Share value of the interest in the fair value of OCP’s identifiable assets and liabilities (1)	12.7
OCP dividends to be received	9.5
Assets fair value	22.2
Profit (2)	17.2

⁽¹⁾ Calculated based on the present value of expected dividend flows.

⁽²⁾ Disclosed under “Share of profit from associates and joint ventures”.

Schedule of oil and gas areas participations

		Participation			Duration Up To
Name	Location	Direct	Indirect	Operator
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
La Tapera - Puesto Quiroga	Chubut	35.67%	-	Tecpetrol	2027
El Tordillo	Chubut	35.67%	-	Tecpetrol	2027
Aguaragüe (1)	Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala	Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento (2)	Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro (3)	Río Negro	15.00%	-	YPF	2026
Río Limay este (Ex Senillosa) (4)	Neuquén	85.00%	-	PAMPA	2040
Veta Escondida y Rincón de Aranda	Neuquén	55.00%	-	PAMPA	2027
Rincón del Mangrullo	Neuquén	50.00%	-	YPF	2052
Los Blancos (ex Chirete)	Salta	50.00%	-	High Luck Group Limited	2045
Argentine exploration
Parva Negra Este (5)	Neuquén	42.50%	-	PAMPA	2019
Río Atuel (6)	Mendoza	33.33%	-	Petrolera El Trebol	2023
Borde del Limay (7)	Neuquén	85.00%	-	PAMPA	2015
Los Vértices (7)	Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte (8)	Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾ On February 3, 2023, an agreement for a 10-year extension of the concession was signed with the enforcement authority. The Provincial Executive Order ratifying this agreement is pending publication.

⁽²⁾ Direct participation in 9 wells. On January 19, 2023, the Company accepted Oilstone Energía S.A.’s offer to terminate its rights and obligations under the investment agreement, the Joint Venture and the operating agreement of the block, effective from January 1, 2023.

⁽³⁾ Direct participation in 13 wells.

⁽⁴⁾ On January 2, 2023, the environmental remediation plan was approved by the Province of Neuquén’s Subsecretariat of Environment, a necessary preliminary step to relinquish the block.

⁽⁵⁾ A contractual continuity plan was submitted (see details below).

⁽⁶⁾ Pursuant to Resolution No. 1,787/22 of the Province of Mendoza’s Ministry of Economy and Energy, the granting of a lot under evaluation, requested by Phoenix Global Resources —Petrolera El Trébol’s controlling company— and the Company on April 6, 2022, was approved until August 31, 2023.

⁽⁷⁾ Under process of relinquishment to the province.

⁽⁸⁾ On January 4, 2023, the exploration period terminated, and the Company’s rights and obligations over the area expired.

Schedule of exploratory well costs

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	42	50	33
Increases	2	8	24
Transferred to development	(6)	(16)	(7)
At the end of the year	38	42	50
Number of wells at the end of the year	7	10	12

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RISKS (Tables)

12 Months Ended

Dec. 31, 2022

Risks

Schedule of exposure to the price risk

	Increase of the result for the year
Financial assets	12.31.2022	12.31.2021
Shares	19	15
Government securities	28	28
Corporate Bonds	12	2
Mutual funds	3	4
Variation of the result of the year	62	49

Schedule of borrowings classified by interest rate and currency

	12.31.2022	12.31.2021
Fixed interest rate:
Argentine pesos	57	11
U.S. dollar	1,173	1,318
Subtotal loans obtained at a fixed interest rate	1,230	1,329
Floating interest rate:
Argentine pesos	140	-
U.S. dollar	149	87
Subtotal loans obtained at a floating interest rate	289	87
Non interest accrued
Argentine pesos	22	-
U.S. dollar	72	22
Subtotal loans no interest accrued	94	22
Total borrowings	1,613	1,438

Schedule of expected credit loss on trade receivables and financial assets rates

12.31.2022	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.08%	0.26%	2.54%	7.11%	14.37%	21.39%	27.22%	33.01%
Oil and Gas	0.18%	0.48%	13.24%	31.50%	32.01%	32.09%	32.31%	32.38%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Holding	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
12.31.2021	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.06%	0.29%	2.08%	2.83%	4.67%	6.12%	6.24%	6.25%
Oil and Gas	0.04%	0.17%	0.77%	2.72%	6.88%	19.88%	21.97%	15.89%
Petrochemicals	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
Holding	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
12.31.2020	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.35%	1.11%	5.74%	9.78%	11.23%	19.77%	20.87%	22.71%
Oil and Gas	0.49%	0.72%	5.96%	16.21%	16.23%	17.74%	17.76%	17.79%
Petrochemicals	0.02%	0.06%	0.72%	2.26%	9.95%	23.84%	19.14%	36.92%
Holding	12.58%	0.94%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%

Schedule of liquidity index

	12.31.2022	12.31.2021
Current assets	1,343	1,125
Current liabilities	631	342
Liquidity ratio	2.13	3.29

Schedule of financial liabilities contractual undiscounted cash flows maturity

As of December 31, 2022	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	412	231	118
Three months to one year	19	50	304
One to two years	6	12	357
Two to five years	12	3	992
More than five years	-	6	332
No set maturity term	41	-	-
Total	490	302	2,103
As of December 31, 2021	Trade and other receivables	Trade and other payables (1)	Borrowings
Less than three months	304	178	56
Three months to one year	61	4	102
One to two years	6	5	557
Two to five years	18	3	256
More than five years	-	4	1,025
No set maturity term	42	-	-
Total	431	194	1,996

⁽¹⁾ Includes Lease Liabilities (see Note 19).

Schedule of financial leverage ratios

	12.31.2022	12.31.2021
Total borrowings	1,613	1,438
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(692)	(568)
Net debt	921	870
Total capital	3,198	2,655
Leverage ratio	28.80%	32.77%

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2022

Segment Information

Disclosure of operating segment information

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	663	370	425	20	-	1,478
Revenue - foreign market	-	159	192	-	-	351
Intersegment revenue	-	117	-	-	(117)	-
Cost of sales	(370)	(359)	(536)	-	117	(1,148)
Gross profit	293	287	81	20	-	681
Selling expenses	(3)	(36)	(17)	-	-	(56)
Administrative expenses	(39)	(60)	(5)	(34)	-	(138)
Other operating income	25	61	1	44	-	131
Other operating expenses	(5)	(26)	(6)	(9)	-	(46)
Impairment of property, plant and equipment, intangible assets and inventories	-	(30)	(2)	(6)	-	(38)
Impairment of financial assets	-	(2)	-	(6)	-	(8)
Share of profit from associates and joint ventures	65	-	-	40	-	105
Operating income	336	194	52	49	-	631
Financial income	1	2	-	9	(7)	5
Financial costs	(82)	(107)	(3)	(36)	7	(221)
Other financial results	72	(28)	6	116	-	166
Financial results, net	(9)	(133)	3	89	-	(50)
Profit before income tax	327	61	55	138	-	581
Income tax	(73)	(16)	(15)	(20)	-	(124)
Profit of the year	254	45	40	118	-	457
Depreciation and amortization	82	125	5	-	-	212

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022	Generation	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit of the year attributable to:
Owners of the company	253	45	40	118	-	456
Non-controlling interest	1	-	-	-	-	1
Consolidated financial position information as of December 31, 2022
Assets	2,464	1,234	177	1,029	(162)	4,742
Liabilities	979	1,248	147	245	(161)	2,458
Net book values of property, plant and equipment	1,299	807	24	34	-	2,164
Additional consolidated information as of December 31, 2022
Increases in property, plant and equipment, intangible assets and right-of-use assets	115	324	7	36	-	482

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	656	-	282	310	22	-	1,270
Revenue - foreign market	-	-	58	180	-	-	238
Intersegment revenue	-	-	113	-	-	(113)	-
Cost of sales	(355)	-	(289)	(424)	-	113	(955)
Gross profit	301	-	164	66	22	-	553
Selling expenses	(2)	-	(18)	(13)	-	-	(33)
Administrative expenses	(31)	-	(46)	(4)	(18)	-	(99)
Other operating income	42	-	58	1	4	-	105
Other operating expenses	(5)	-	(28)	(3)	(22)	-	(58)
Impairment of intangible assets and inventories	(2)	-	-	(2)	-	-	(4)
Impairment of financial assets	-	-	-	-	(2)	-	(2)
Share of profit from associates and joint ventures	47	-	-	-	70	-	117
Operating income	350	-	130	45	54	-	579
Financial income	4	-	3	-	4	(1)	10
Financial costs	(46)	-	(103)	(3)	(34)	1	(185)
Other financial results	(14)	-	(16)	(2)	18	-	(14)
Financial results, net	(56)	-	(116)	(5)	(12)	-	(189)
Profit before income tax	294	-	14	40	42	-	390
Income tax	(75)	-	8	(12)	2	-	(77)
Profit of the year from continuing operations	219	-	22	28	44	-	313
Loss of the year from discontinued operations	-	(75)	-	-	-	-	(75)
Profit (Loss) of the year	219	(75)	22	28	44	-	238
Depreciation and amortization	88	-	114	3	-	-	205

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2021	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	218	(39)	22	28	44	-	273
Non-controlling interest	1	(36)	-	-	-	-	(35)
Consolidated financial position information as of December 31, 2021
Assets	1,670	-	1,157	176	1,067	(209)	3,861
Liabilities	525	-	1,324	166	264	(209)	2,070
Net book values of property, plant and equipment	969	-	636	22	32	-	1,659
Additional consolidated information as of December 31, 2021
Increases in property, plant and equipment, intangible assets and right-of-use assets	39	-	213	6	6	-	264

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue - local market	559	-	199	178	20	-	956
Revenue - foreign market	-	-	28	89	-	-	117
Intersegment revenue	-	-	67	-	-	(67)	-
Cost of sales	(254)	-	(243)	(233)	-	67	(663)
Gross profit	305	-	51	34	20	-	410
Selling expenses	(2)	-	(15)	(9)	-	-	(26)
Administrative expenses	(30)	-	(42)	(3)	(18)	-	(93)
Other operating income	35	-	9	-	7	-	51
Other operating expenses	(6)	-	(17)	(6)	(7)	-	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(128)	-	-	(11)	-	-	(139)
Impairment of financial assets	-	-	(13)	1	3	-	(9)
Share of profit from associates and joint ventures	67	-	-	-	18	-	85
Operating income (loss)	241	-	(27)	6	23	-	243
Financial income	3	-	7	-	1	(2)	9
Financial costs	(73)	-	(100)	(3)	(3)	2	(177)
Other financial results	1	-	44	5	34	-	84
Financial results, net	(69)	-	(49)	2	32	-	(84)
Profit (loss) before income tax	172	-	(76)	8	55	-	159
Income tax	(33)	-	23	(2)	(23)	-	(35)
Profit (loss) of the year from continuing operations	139	-	(53)	6	32	-	124
Loss of the year from discontinued operations	-	(592)	-	-	-	-	(592)
Profit (loss) of the year	139	(592)	(53)	6	32	-	(468)
Depreciation and amortization	95	81	108	2	-	-	286

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2020	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) of the year attributable to:
Owners of the company	147	(499)	(53)	6	32	-	(367)
Non-controlling interest	(8)	(93)	-	-	-	-	(101)
Consolidated financial position information as of December 31, 2020
Assets	1,595	1,356	1,085	107	832	(85)	4,890
Liabilities	707	1,021	1,174	126	178	(85)	3,121
Net book values of property, plant and equipment	1,015	-	543	19	33	-	1,610
Additional consolidated information as of December 31, 2020
Increases in property, plant and equipment and right-of-use assets	61	135	41	3	2	-	242

XML

REVENUE (Tables)

12 Months Ended

Dec. 31, 2022

Revenue [abstract]

Schedule of revenue

	12.31.2022	12.31.2021	12.31.2020
Energy sales in Spot Market	210	167	179
Energy sales by supply contracts	346	380	323
Fuel supply	103	104	54
Other sales	4	5	3
Generation sales subtotal	663	656	559
Gas sales	383	231	152
Oil sales	136	99	65
Other sales	10	10	10
Oil and gas sales subtotal	529	340	227
Products from catalytic reforming sales	270	185	98
Styrene sales	96	84	42
Synthetic rubber sales	106	99	49
Polystyrene sales	141	119	71
Other sales	4	3	7
Petrochemicals sales subtotal	617	490	267
Technical assistance and administration services sales	20	22	20
Other	-	-	-
Holding and others subtotal	20	22	20
Total revenue	1,829	1,508	1,073

XML

COST OF SALES (Tables)

12 Months Ended

Dec. 31, 2022

Cost Of Sales

Schedule of cost of sales

	12.31.2022	12.31.2021	12.31.2020
Inventories at the beginning of the year	155	116	153
Plus: Charges of the year
Purchases of inventories, energy and gas	502	433	153
Salaries and social security charges	79	59	51
Employees benefits	15	13	11
Accrual of defined benefit plans	5	4	4
Works contracts, fees and compensation for services	87	68	55
Property, plant and equipment depreciation	202	194	194
Intangible assets amortization	1	1	5
Right-of-use assets amortization	3	5	1
Energy transportation	8	6	5
Transportation and freights	35	22	20
Consumption of materials	30	26	17
Penalties	1	2	-
Maintenance	61	52	26
Canons and royalties	89	65	42
Environmental control	5	4	4
Rental and insurance	31	27	23
Surveillance and security	4	3	2
Taxes, rates and contributions	5	4	3
Other	3	6	2
Total charges of the year	1,166	994	618
Exchange differences on translation	-	-	8
Less: Inventories at the end of the year	(173)	(155)	(116)
Total cost of sales	1,148	955	663

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2022

Other Items Of Statement Of Comprehensive Income

Selling expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	5	3	3
Employees benefits	1	-	-
Compensation agreements	-	-	1
Fees and compensation for services	4	3	3
Taxes, rates and contributions	14	11	8
Transportation and freights	31	14	9
Other	1	2	2
Total selling expenses	56	33	26

Administrative expenses

	12.31.2022	12.31.2021	12.31.2020
Salaries and social security charges	50	34	34
Employees benefits	8	5	4
Accrual of defined benefit plans	9	7	7
Fees and compensation for services	30	32	26
Compensation agreements	19	2	-
Directors' and Sindycs' fees	7	6	7
Property, plant and equipment depreciation	6	5	5
Maintenance	2	2	1
Transport and per diem	2	1	1
Rental and insurance	1	1	1
Surveillance and security	1	-	1
Taxes, rates and contributions	2	2	2
Communications	1	1	1
Other	-	1	3
Total administrative expenses	138	99	93

Other operating income and expenses

	Note	12.31.2022	12.31.2021	12.31.2020
Other operating income
Insurance recovery		-	3	3
Services provided to third parties		1	2	4
Result from property, plant and equipment sale		2	1	1
Result from intangible assets sale		2	2	-
Dividends received		-	-	1
Contingencies recovery		-	13	2
Tax charges recovery		-	2	-
Contractual penalty		-	-	7
Commercial interests		27	27	30
Argentine Natural Gas Production Promotion Plan		56	51	-
Compensation for arbitration award	15.6	37	-	-
Other		6	4	3
Total other operating income		131	105	51
Other operating expenses
Provision for contingencies		(4)	(16)	(7)
Provision for environmental remediation		-	(15)	-
Derecognition of property, plant and equipment		-	-	(1)
Tax on bank transactions		(14)	(13)	(11)
Donations and contributions		(2)	(2)	(3)
Institutional promotion		(3)	(3)	(2)
Readjustment of investment plan (1)		(9)	-	-
Royalties of Argentine Natural Gas Production Promotion Plan		(8)	(5)	-
Other		(6)	(4)	(12)
Total other operating expenses		(46)	(58)	(36)

⁽¹⁾ Corresponding to the investment plan’s readjustment bond at the Sierra Chata block (see Note 17.2).

Financial results

	12.31.2022	12.31.2021	12.31.2020
Financial income
Financial interest	1	-	1
Other interest	4	10	8
Total financial income	5	10	9
Financial costs
Financial interests (1)	(172)	(137)	(164)
Commercial interests	(1)	-	-
Fiscal interests	(38)	(38)	(3)
Other interests	(5)	(3)	(3)
Bank and other financial expenses	(5)	(7)	(7)
Total financial costs	(221)	(185)	(177)
Other financial results
Foreign currency exchange difference, net	80	3	14
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement	(14)	(1)	2
Result from exchange of corporate bonds	(14)	-	-
Result from repurchase of corporate bonds	6	-	38
Other financial results	(2)	(1)	-
Total other financial results	166	(14)	84
Total financial results, net	(50)	(189)	(84)

⁽¹⁾ Net of US$ 11 million and US$ 10 million capitalized in property, plant and equipment for the years ended December 31, 2022 and 2020, respectively. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

Income tax benefit expense

	12.31.2022	12.31.2021	12.31.2020
Current tax	99	67	13
Deferred tax	46	10	22
Difference between previous fiscal year income tax provision and the income tax statement	(21)	-	-
Total  income tax -  Loss	124	77	35

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2022	12.31.2021	12.31.2020
Profit before income tax	581	390	159
Current income tax rate	35%	35%	30%
Income tax at the statutary tax rate	203	138	48
Share of profit from companies	(37)	(40)	(26)
Non-taxable results	(3)	(1)	(5)
Effects of exchange differences and other results associated with the valuation of the currency, net	275	79	88
Effects of valuation of property, plant and equipment, intangible assets and financial assets	(575)	(269)	(156)
Effect of change in tax rate	-	(6)	19
Effect for tax inflation adjustment	253	169	74
Unrecognized deferred assets	-	4	-
Difference between previous fiscal year income tax provision and the income tax statement	2	1	(7)
Non-deductible cost	4	3	-
Impairment on deferred tax assets	2	-	-
Other	-	(1)	-
Total  income tax -  Loss	124	77	35

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2022

Non-financial Assets And Liabilities

Schedule of changes in property plant and equipment

	Original values
Type of good	At the beginning	Increases (1)	Increases for incorporation (2)	Transfers	Decreases	Impairment
							At the end
Lands	14	-	-	-	-	-	14
Buildings	140	-	3	-	-	-	143
Equipment and machinery	1,458	5	291	163	(1)	-	1,916
Wells	867	9	-	145	(1)	(28)	992
Mining property	253	-	-	-	-	(72)	181
Vehicles	8	2	-	-	-	-	10
Furniture and fixtures and software equipment	55	2	-	2	-	-	59
Communication equipments	3	-	-	-	-	-	3
Materials, spare parts and tools	30	43	-	(37)	-	-	36
Petrochemical industrial complex	23	-	-	6	-	-	29
Work in progress	135	352	-	(233)	-	-	254
Advances to suppliers	52	37	-	(46)	-	-	43
Other goods	2	-	1	-	-	-	3
Total at 12.31.2022	3,040	450	295	-	(2)	(100)	3,683
Total at 12.31.2021	2,792	253	-	-	(5)	-	3,040

⁽¹⁾ Includes US$ 11 million corresponding to capitalized financial costs in the fiscal year ended December 31, 2022. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

⁽²⁾ See Notes 5.1.3 and 5.1.5.

	Depreciation					Net book values
Type of good	At the beginning	Decreases	For the year	Impairment	At the end	At 12.31.2022	At 12.31.2021
Lands	-	-	-	-	-	14	14
Buildings	(68)	-	(8)	-	(76)	67	72
Equipment and machinery	(536)	-	(103)	-	(639)	1,277	922
Wells	(532)	-	(77)	20	(589)	403	335
Mining property	(174)	-	(10)	50	(134)	47	79
Vehicles	(7)	-	(1)	-	(8)	2	1
Furniture and fixtures and software equipment	(48)	-	(4)	-	(52)	7	7
Communication equipments	(1)	-	-	-	(1)	2	2
Materials, spare parts and tools	(3)	-	-	-	(3)	33	27
Petrochemical industrial complex	(12)	-	(5)	-	(17)	12	11
Work in progress	-	-	-	-	-	254	135
Advances to suppliers	-	-	-	-	-	43	52
Other goods	-	-	-	-	-	3	2
Total at 12.31.2022	(1,381)	-	(208)	70	(1,519)	2,164
Total at 12.31.2021	(1,182)	-	(199)	-	(1,381)		1,659

Schedule of changes in intangible assets

	Original values
Type of good	At the beginning	Increases	Increases for incorporation (1)	Decreases	Impairment (2)	At the end
Concession agreements	2	-	-	-	-	2
Goodwill	35	-	-	-	-	35
Intangible identified in acquisitions of companies	7	-	94	-	-	101
Digital assets	-	31	-	(18)	(6)	7
Total at 12.31.2022	44	31	94	(18)	(6)	145
Total at 12.31.2021	62	4		(4)	(18)	44
	Amortization
Type of good	At the beginning	For the year	Impairment (2)	At the end
Concession agreements	(2)	-	-	(2)
Intangible identified in acquisitions of companies	(4)	(1)	-	(5)
Total at 12.31.2022	(6)	(1)	-	(7)
Total at 12.31.2021	(21)	(1)	16	(6)
	Net book values
Type of good	At 12.31.2022	At 12.31.2021
Goodwill	35	35
Intangible identified in acquisitions of companies	96	3
Digital assets	7
Total at 12.31.2022	138
Total at 12.31.2021		38

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

⁽²⁾ As of December 31, 2022, digital assets recoverability was affected by their closing market value, resulted in the recognition of impairment losses for US$ 6 million. Considering the assumptions detailed in Note 11.1, the assessment of recoverability for the Power Generation segment, resulted in the recognition of impairment losses for the Diamante hydroelectric power plant in an amount of US$ 2 million in 2021.

Schedule of inventories

	12.31.2021	Profit (loss)	Increases for incorporation (1)	12.31.2022
Tax loss carryforwards	13	6	-	19
Property, plant and equipment	80	71	-	151
Financial assets at fair value through profit and loss	3	(3)	-	-
Trade and other receivables	5	(1)	-	4
Provisions	57	2	-	59
Salaries and social security payable	-	1	-	1
Defined benefit plans	9	(1)	-	8
Other	-	1	-	1
Deferred tax asset	167	76	-	243
Property, plant and equipment	-	-	(79)	(79)
Intangible assets	(13)	-	(22)	(35)
Investments in companies	(11)	3	-	(8)
Inventories	(10)	(9)	-	(19)
Financial assets at fair value through profit and loss	(14)	(1)	-	(15)
Trade and other receivables	(31)	8	-	(23)
Taxes payables	(3)	1	-	(2)
Tax inflation adjustment	(1)	(124)	(13)	(138)
Deferred tax liability	(83)	(122)	(114)	(319)
Deferred tax (liability) asset	84	(46)	(114)	(76)

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

	12.31.2020	Profit (loss) (1)	12.31.2021
Tax loss carryforwards	126	(113)	13
Property, plant and equipment	-	80	80
Intangible assets	3	(3)	-
Financial assets at fair value through profit and loss	-	3	3
Trade and other receivables	6	(1)	5
Provisions	28	29	57
Salaries and social security payable	3	(3)	-
Defined benefit plans	5	4	9
Trade and other payables	3	(3)	-
Tax inflation adjustment	4	(4)	-
Deferred tax asset	178	(11)	167
Property, plant and equipment	(13)	13	-
Intangible assets	(11)	(2)	(13)
Investments in companies	(25)	14	(11)
Inventories	(6)	(4)	(10)
Financial assets at fair value through profit and loss	(4)	(10)	(14)
Trade and other receivables	(7)	(24)	(31)
Taxes payables	(3)	-	(3)
Tax inflation adjustment	(2)	1	(1)
Deferred tax liability	(71)	(12)	(83)
Deferred tax asset (liability)	107	(23)	84

⁽¹⁾ Includes US$ 13 million corresponding to discontinued operations.

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:

	12.31.2022	12.31.2021
Deferred tax asset	36	84
Deferred tax liability	(112)	-
Deferred tax (liability) asset	(76)	84

11.4 Inventories

	12.31.2022	12.31.2021
Current
Materials and spare parts	104	87
Advances to suppliers	8	8
In process and finished products	61	60
Total (1)	173	155

⁽¹⁾ It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

Schedule of inventories

	12.31.2022	12.31.2021
Current
Materials and spare parts	104	87
Advances to suppliers	8	8
In process and finished products	61	60
Total (1)	173	155

⁽¹⁾ It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

Schedule of provisions

	12.31.2022	12.31.2021
Non-Current
Contingencies	107	106
Asset retirement obligation and wind turbines decommisioning	25	19
Environmental remediation	15	15
Other provisions	-	1
Total Non-Current	147	141
Current
Asset retirement obligation and wind turbines decommisioning	2	2
Environmental remediation	2	3
Total Current	4	5

Schedule of changes in provisions

	12.31.2022
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	106	21	18
Increases	5	6	-
Increases for incorporation (1)	-	1	-
Decreases	(1)	-	(1)
Gain on monetary position, net	(2)	-	-
Reversal of unused amounts	(1)	(1)	-
At the end of the year	107	27	17

⁽¹⁾ See Note 5.1.3.

	12.31.2021
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	103	21	3
Increases	16	3	15
Decreases	-	(1)	-
Reversal of unused amounts (1)	(13)	(2)	-
At the end of the year	106	21	18

⁽¹⁾ Includes recovery of US$ 12.5 million related to waive the timely granted dispatch of Las Armas Wind Farm (see Note 2.1.2.3).

	12.31.2020
	Contingencies	Asset retirement obligation and decommisioning  of wind turbines	Environmental remediation
At the beginning of the year	139	22	3
Increases	21	2	-
Decreases	(1)	-	-
Gain on monetary position, net	(15)	-	-
Reversal of unused amounts	(8)	(3)	-
Reclassified to liabilities associated to assets classified as held for sale	(33)	-	-
At the end of the year	103	21	3

Schedule of income tax and minimum notional income tax liability

	12.31.2022	12.31.2021
Non-current
Income tax, net of witholdings	161	158
Minimum notional income tax	18	30
Total non-current	179	188
Current
Income tax, net of witholdings and advances	5	20
Total current	5	20

Schedule of tax liabilities

	12.31.2022	12.31.2021
Current
Value added tax	5	4
Personal assets tax provision	4	2
Tax withholdings to be deposited	5	6
Royalties	12	9
Other	2	2
Total current	28	23

Schedule of defined benefit plan information

	12.31.2022
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	33	(4)	29
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	15	(2)	13
Items classified in other comprehensive  income
Actuarial losses	9	-	9
Benefit payments	(3)	-	(3)
(Gain) Loss on monetary position, net	(17)	2	(15)
At the end of the year	38	(4)	34
	12.31.2021
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	25	(4)	21
Items classified in profit or loss
Current services cost	1	-	1
Interest cost	13	(3)	10
Items classified in other comprehensive  income
Actuarial losses	1	2	3
Benefit payments	(2)	-	(2)
(Gain) Loss on monetary position, net	(5)	1	(4)
At the end of the year	33	(4)	29

	12.31.2020
	Present value of the obligation	Present value of assets	Net liability at the end of the year
At the beginning of the year	36	(5)	31
Items classified in profit or loss
Current services cost	3	-	3
Interest cost	16	(2)	14
Items classified in other comprehensive  income
Actuarial (gains) losses	(3)	1	(2)
Benefit payments	(2)	-	(2)
Reclasification liabilities associated to assets classified as held for sale	(10)	-	(10)
(Gain) Loss on monetary position, net	(15)	2	(13)
At the end of the year	25	(4)	21

Schedule of estimated expected benefits payments

	12.31.2022
Less than one year	6
One to two years	3
Two to three years	4
Three to four years	4
Four to five years	3
Six to ten years	14

Schedule of significant actuarial assumptions

	12.31.2022	12.31.2021	12.31.2020
Real discount rate	5%	5%	4%
Real wage increase rate	1%	1%	1%
Inflation rate	118%	54%	46%

Schedule of sensitivity analyses on actuarial assumptions variations

	12.31.2022
Discount rate: 4%
Obligation	41
Variation	3
	9%
Discount rate: 6%
Obligation	35
Variation	(3)
	(8%)
Real wage increase rate: 0%
Obligation	37
Variation	(1)
	(4%)
Real wage increase rate: 2%
Obligation	39
Variation	1
	4%

Schedule of salaries and social security payable

	12.31.2022	12.31.2021
Current
Salaries and social security contributions	5	4
Provision for vacations	8	7
Provision for gratifications and annual bonus for efficiency	19	17
Total current	32	28

XML

FINANCIAL ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2022

Financial Assets And Liabilities

Schedule of financial assets at amortized cost

	12.31.2022	12.31.2021
Non-current
Term deposit	101	100
Notes receivable	1	5
Total non-current	102	105
Current
Notes receivable	8	5
Total current	8	5

Schedule of financial assets at fair value through profit and loss

	12.31.2022	12.31.2021
Non-current
Shares	27	29
Total non-current	27	29
Current
Government securities	279	278
Corporate bonds	116	19
Shares	160	120
Mutual funds	31	41
Total current	586	458

Schedule of trade and other receivables

	Note	12.31.2022	12.31.2021
Non-Current
Related parties	16	17	23
Tax credits		2	9
Prepaid expenses		-	1
Other		1	1
Other receivables		20	34
Total non-current		20	34

		12.31.2022	12.31.2021
Current
Receivables from MAT sales		21	24
CAMMESA		165	89
Receivables from oiland gas sales		55	69
Receivables from petrochemicals sales		62	71
Related parties	16	5	7
Other		3	5
Impairment of financial assets		(6)	(9)
Trade receivables, net		305	256
Current
Related parties	16	7	8
Tax credits		14	5
Receivables for complementary activities		-	2
Prepaid expenses		14	10
Financial credit		-	10
Guarantee deposits		27	30
Insurance to be recovered		-	1
Expenses to be recovered		15	-
Receivables for acquisition of subsidiary		7	-
Receivables for sale of subsidiary and associates		4	41
Receivables for financial instruments sale		1	6
Argentine Natural Gas Production Promotion Plan		32	14
Receivables for arbitration award	15.6	37	-
Other		7	14
Other receivables, net		165	141
Total current		470	397

Schedule of allowance for the impairment of trade receivables

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	9	16	68
Impairment (1)	1	1	63
Utilization	(1)	-	(7)
Reversal of unused amounts	-	(6)	(3)
Gain on monetary position, net	(3)	(2)	(2)
Gain on monetary position, net	-	-	(28)
Reclasified to assets classified as held for sale	-	-	(75)
At the end of the year	6	9	16

⁽¹⁾ It includes US$ 26 million corresponding to discontinued operations for fiscal year 2020. As of December 31, 2020, it includes US$ 13 million corresponding to the receivable impairment related to the exchange difference between the price of gas purchased by distributors and the price of gas recognised in distributors´s final tariffs between April 2018 and March 2019 to be assumed by the Federal Government in accordance to PEN Executive Order No. 1,053/18 (see Note 15).

Schedule of impairment of other financial assets assets

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	-	-	6
Impairment	-	-	2
Reversal of unused amounts	-	-	(7)
Reclasified to assets classified as held for sale	-	-	(1)
At the end of the year	-	-	-

Schedule of cash and cash equivalents

	12.31.2022	12.31.2021
Banks	11	26
Mutual funds	95	84
Total	106	110

Schedule of borrowings

	12.31.2022	12.31.2021
Non-Current
Financial borrowings	108	58
Corporate bonds	1,232	1,301
Total non-current	1,340	1,359
Current
Bank overdrafts	59	11
Financial borrowings	51	29
Corporate bonds	163	39
Total current	273	79
Total	1,613	1,438

Schedule of changes in borrowings

	12.31.2022	12.31.2021	12.31.2020
At the beginning of the year	1,438	1,614	1,947
Proceeds from borrowings	308	188	353
Payment of borrowings	(143)	(336)	(300)
Accrued interest	172	137	176
Payment of interests	(162)	(140)	(201)
Repurchase and redemption of corporate bonds	(28)	(3)	(155)
Result from exchange of corporate bonds	14	-	-
Result from repurchase of corporate bonds	(6)	-	(43)
Increases for incorporation (1)	89	-	-
Cancellation through dividend compensation	-	-	(12)
Gain on monetary position, net	-	-	(43)
Foreign currency exchange difference, net	(80)	(22)	(18)
Borrowing costs capitalized in property, plant and equipment	11	-	10
Reclassified to liabilities associated to assets classified as held for sale	-	-	(100)
At the end of the year	1,613	1,438	1,614

⁽¹⁾ See Notes 5.1.3 and 5.1.5.

Schedule of borrowings composition

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2022
Corporate bonds (1)
T Series CB	PAMPA	US$	93	Fixed	7.38%	Jul-23	95
Class 8 CB	PAMPA	$	18	Variable	Badlar + 2%	Jul-23	20
Class 11 CB	PAMPA	$	122	Variable	Badlar + 0%	Jan-24	140
Class 9 CB	PAMPA	US$	102	Fixed	9.50%	Dec-26	184
Class 1 CB	PAMPA	US$	501	Fixed	7.50%	Jan-27	616
Class 13 CB	PAMPA	US$	49	Fixed	0.00%	Dec-27	48
Class 3 CB	PAMPA	US$	285	Fixed	9.13%	Apr-29	292
							1,395
Financial loans (2)
	PAMPA	US$	15	Variable	Libor + 4.21%	Nov-24	16
	GW	US$	83	Variable	Libor + 5.75%	Sep-26	85
							101
Other financial loans (3)
	PAMPA	US$	22	Variable	SOFR + 0.35%	Jul-23	23
	PAMPA	US$	8	Fixed	Between 9.50% and 14.50%	Between Jan-23 and May-23	8
	PAMPA	US$	27	Variable	SOFR + 0%	Agu-24	27
							58
Bank overdrafts (3)
	PAMPA	$	57	Fixed	Between 54% and 54.50%	Jan-23	59
							59
							1,613

⁽¹⁾ Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

⁽²⁾ During the the fiscal year ended December 31, 2022, the Company took on new short-term financing with domestic financial entities, net of cancellations, for a total $ 8,618 million and import prefinancing for US$ 7.6 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million and US$ 10.4 million corresponding to the credit facility subscribed between IDB Invest and Greenwind, a Company that is consolidated since acquisition of an additional 50% interest in August 2022.

⁽³⁾ During the fiscal year ended December 31, 2022, the Company received disbursements in the amount of US$ 1.3 million under the credit facilities taken out with BNP Paribas S.A. in 2020. After the fiscal year closing, the Company repaid short-term bank loans with local financial entities for $ 10,065 million and import prefinancing for US$ 0.7 million.

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2021
Corporate bonds (1)
T Series CB	PAMPA	US$	389	Fixed	7.38%	Jul-23	400
Class 1 CB	PAMPA	US$	636	Fixed	7.50%	Jan-27	648
Class 3 CB	PAMPA	US$	293	Fixed	9.13%	Apr-29	292
							1,340
Financial loans (2)
	PAMPA	US$	23	Variable	Libor + 4.21%	May-24	23
							23
Other financial loans (3)
	PAMPA	US$	22	Variable	Libor + 0.35%	Jul-22	22
	PAMPA	US$	43	Variable	Libor + 0%	Aug-23	42
							64
Bank overdrafts
	PAMPA	$	11	Fixed	33.00%	Jan-22	11
							11
							1,438

⁽¹⁾ Net of the following face value repurchases: US$ 110,4 million of ON 2023, US$ 114,0 million of ON 2027 and US$ 7,5 million of ON 2029.

On September 27, 2021, the Company repaid at maturity Class 6 CBs for $ 6,355 million.

⁽²⁾ During the fiscal year ended December 31, 2021, the Company canceled short-term financing with local financial entities, net of borrowings, for $ 8,158 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million.

⁽³⁾ During the fiscal year ended December 31, 2021, the Company received disbursements in the amount of US$ 27 million under the credit facilities taken out with BNP in 2020.

Schedule of trade and other payables

	Note	12.31.2022	12.31.2021
Non-Current
Compensation agreements		10	3
Finance leases liability		10	9
Other		1	-
Other payables		21	12
Total non-current		21	12
Current
Suppliers		198	154
Customer advances		3	4
Related parties	16	14	15
Trade payables		215	173
Compensation agreements		12	2
Liability for acquisition of companies		46	-
Finance leases liability		2	4
Other		6	3
Other payables		66	9
Total current		281	182

Schedule of financial instruments

As of December 31, 2022	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 receivables and other receivables	437	22	459	31	490
Financial assets at amortized cost
Term deposit	101	-	101	-	101
Notes receivable	9	-	9	-	9
Financial assets at fair value through profit and loss
Government securities	-	279	279	-	279
Corporate bonds	-	116	116	-	116
Shares	-	187	187	-	187
Mutual funds	-	31	31	-	31
Cash and cash equivalents	11	95	106	-	106
Total	558	730	1,288	31	1,319
Liabilities
Trade and other liabilities	298	-	298	4	302
Borrowings	1,613	-	1,613	-	1,613
Derivative financial instruments	-	2	2	-	2
Total	1,911	2	1,913	4	1,917
As of December 31, 2021	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 receivables and other receivables	376	30	406	25	431
Financial assets at amortized cost
Term deposit	100	-	100	-	100
Notes receivable	10	-	10	-	10
Financial assets at fair value through profit and loss
Government securities	-	278	278	-	278
Corporate bonds	-	19	19	-	19
Shares	-	149	149	-	149
Mutual funds	-	41	41	-	41
Cash and cash equivalents	26	84	110	-	110
Total	512	601	1,113	25	1,138
Liabilities
Trade and other liabilities	190	-	190	4	194
Borrowings	1,438	-	1,438	-	1,438
Total	1,628	-	1,628	4	1,632

Schedule of income, expenses, gains and losses from financial instruments

As of December 31, 2022	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	5	-	5	-	5
Interest expenses	(175)	-	(175)	(41)	(216)
Foreign currency exchange difference, net	16	(85)	(69)	149	80
Changes in the fair value of financial instruments	-	110	110	-	110
Result from present value measurement	(1)	-	(1)	(13)	(14)
Other financial results	(15)	-	(15)	-	(15)
Total	(170)	25	(145)	95	(50)
As of December 31, 2021	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	10	-	10	-	10
Interest expenses	(138)	-	(138)	(40)	(178)
Foreign currency exchange difference, net	(11)	(19)	(30)	33	3
Changes in the fair value of financial instruments	-	(15)	(15)	-	(15)
Result from present value measurement	2	-	2	(3)	(1)
Other financial results	(4)	-	(4)	(4)	(8)
Total	(141)	(34)	(175)	(14)	(189)
As of December 31, 2020	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	9	-	9	-	9
Interest expenses	(164)	-	(164)	(6)	(170)
Foreign currency exchange difference, net	38	(35)	3	11	14
Changes in the fair value of financial instruments	-	30	30	-	30
Result from present value measurement	6	-	6	(4)	2
Other financial results	36	-	36	(5)	31
Total	(75)	(5)	(80)	(4)	(84)

Schedule of fair value of financial instruments

As of December 31, 2022	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	279	-	-	279
Corporate bonds	116	-	-	116
Mutual funds	31	-	-	31
Shares	160	-	27	187
Cash and cash equivalents
Mutual funds	95	-	-	95
Other receivables	22	-	-	22
Total assets	703	-	27	730
Liabilities
Derivative financial instruments	-	2	0	2
Total liabilities	-	2	-	2
As of December 31, 2021	Level 1	Level 3	Total
Assets
Financial assets at fair value through  profit and losss
Government securities	278	-	278
Corporate bonds	19	-	19
Mutual funds	41	-	41
Shares	120	29	149
Cash and cash equivalents
Mutual funds	84	-	84
Other receivables	30	-	30
Total assets	572	29	601

XML

EQUITY COMPONENTS (Tables)

12 Months Ended

Dec. 31, 2022

Equity Components

Schedule of earnings (loss) per share

	12.31.2022	12.31.2021	12.31.2020
Earning for continuing operations attributable to equity holders of the Company	456	312	132
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earnings per share from continued operations	0.33	0.22	0.08
Loss for discontinued operations attributable to equity holders of the Company	-	(39)	(499)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted loss per share from discontinued operations	-	(0.03)	(0.32)
Earning (Loss) attributable to equity holders of the Company	456	273	(367)
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earning (loss) per share	0.33	0.19	(0.23)

XML

STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION (Tables)

12 Months Ended

Dec. 31, 2022

Statement Of Cash Flows Complementary Information

Schedule of adjustments to reconcile net profit (loss) to cash flows generated by operating activities

	Note	12.31.2022	12.31.2021	12.31.2020
Income tax	10.5	124	77	35
Accrued interest		185	141	132
Depreciations and amortizations	9 and 10.2	212	205	205
Share of profit of joint ventures and associates	5.2.2	(105)	(117)	(85)
Results for property, plant and equipment sale	10.3	(2)	(1)	-
Result for intangibles assets sale	10.3	(2)	(2)	-
Impairment of property, plant and equipment, intangible assets and inventories	10.1, 10.2 and 10.4	38	4	139
Impairment of financial assets		8	2	9
Result from measurement at present value	10.4	14	1	(2)
Changes in the fair value of financial instruments		(94)	24	(19)
Exchange differences, net		(85)	(3)	(14)
Result from exchange of corporate bonds	10.4	14	-	-
Result from repurchase of corporate bonds	10.4	(6)	-	(38)
Readjustment of investment plan	10.3	9	-	-
Compensation for arbitration award	10.3	(37)	-	-
Recovery of tax charges	10.3	-	(2)	-
Provision for contingecies, net	10.3	4	3	2
Provision for environmental remediation	10.3	-	15	-
Accrual of defined benefit plans	9 and 10.2	14	11	11
Dividends received	10.3	-	-	(1)
Compensation agreements	10.1 and 10.2	19	2	1
Other		(3)	5	5
Adjustments to reconcile net profit to cash flows from operating activities		307	365	380

Schedule of changes in operating assets and liabilities

	12.31.2022	12.31.2021	12.31.2020
(Increase) Decrease in trade receivables and other receivables	(233)	(41)	19
Increase in inventories	(21)	(40)	(6)
Increase in trade payables and other payables	70	43	3
Increase (Decrease) in salaries and social security payable	15	8	(1)
Decrease in defined benefit plans	(3)	(2)	(2)
Increase (Decrease) in tax liabilities	36	(5)	(20)
Decrease in provisions	(1)	(3)	(5)
Income tax paid	(2)	(13)	(5)
Payments from derivative financial instruments, net	(6)	(12)	(5)
Changes in operating assets and liabilities	(145)	(65)	(22)

Schedule of significant non-cash transactions

	12.31.2022	12.31.2021	12.31.2020
Acquisition of property, plant and equipment through an increase in trade payables	(75)	(51)	(8)
Borrowing costs capitalized in property, plant and equipment	(11)	-	(10)
Acquisition of subsidiary by delivering financial assets at fair value through profit and loss	(35)	-	-
Receivables from sales of companies pending collection	-	40	-
Receivables for acquisition of subsidiary	7	-	-
Increase in investments in associates through a decrease in other receivables	-	(20)	-
Increase in right-of-use assets through an increase in other liabilities	(1)	(7)	-
Dividends pending collection	-	2	20
Compensation of loans through dividends assignment	-	-	12
Decrease on well abandonment provision, net, through property, plant and equipment	(1)	(1)	(3)

XML

RELATED PARTIES´ TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2022

Related Parties Transactions

Schedule of balances with related parties

As of December 31, 2022	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
TGS	5	17	6	7
Other related parties
SACDE	-	-	-	7
Other	-	-	1	-
	5	17	7	14
As of December 31, 2021	Trade receivables	Other receivables		Trade  payables
	Current	Non-current	Current	Current
Associates and joint ventures
OCP	-	-	2	-
Refinor	1	-	-	2
TGS	6	23	5	3
Other related parties
SACDE	-	-	-	10
Other	-	-	1	-
	7	23	8	15

Schedule of operations related parties

Operations for the year	Sales of goods and services (1)			Purchases of goods and services (2)			Fees for services (3)			Other operating expenses and income (4)
	2022	2021	2020	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
CTB	2	2	2	-	-	-	-	-	-	-	-	-
Greenwind	-	1	1	-	-	-	-	-	-	-	-	-
Refinor	11	9	10	(11)	(6)	(5)	-	-	-	-	-	-
TGS	51	45	20	(53)	(43)	(24)	-	-	-	-	-	-
Other related parties
Fundación	-	-	-	-	-	-	-	-	-	(2)	(2)	(2)
SACDE	-	-	-	(203)	(48)	(6)	-	-	-	-	-	-
Salaverri, Dellatorre, Burgio & Wetzler	-	-	-	-	-	-	(1)	(1)	(1)	-	-	-
	64	57	33	(267)	(97)	(35)	(1)	(1)	(1)	(2)	(2)	(2)

⁽¹⁾ Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas and refined products.

⁽²⁾ Correspond to natural gas transportation services, purchases of refined products and other services imputed to cost of sales for US$ 191 million, US$ 50 million and US$ 29 million and infrastructure works contracted to SACDE imputed in property, plant and equipment for US$ 76 million, US$ 47 million and US$ 6 million, of which US$ 38 million, US$ 17 million and US$ 2 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, 2022, 2021 and 2020, respectively.

⁽³⁾ Disclosed within administrative expenses.

⁽⁴⁾ Corresponds mainly to donations.

Operations for the year	Finance income (1)			Dividends received			Payment of dividends
	2022	2021	2020	2022	2021	2020	2022	2021	2020
Associates and joint ventures
Citelec	-	-	-	-	-	13	-	-	-
OCP	-	1	1	10	20	21	-	-	-
TGS	2	3	3	-	-	-	-	-	-
Other related parties
EMESA	-	-	-	-	-	-	-	-	(9)
Other	-	-	-	-	-	1	-	-	-
	2	4	4	10	20	35	-	-	(9)

⁽¹⁾ Corresponds mainly to financial leases and accrued interest on loans granted.

XML

LEASES (Tables)

12 Months Ended

Dec. 31, 2022

Leases

Schedule of right of use assets

	Original values
				Decrease
Type of good		At the beginning	Increase		At the end
Machinery and equipment		20	1	(1)	20
Total at 12.31.2022		20	1	(1)	20
Total at 12.31.2021		13	7	-	20
		Amortization
Type of good		At the beginning	For the year	At the end
Machinery and equipment		(8)	(3)	(11)
Total at 12.31.2022		(8)	(3)	(11)
Total at 12.31.2021		(3)	(5)	(8)
		Net book values
Type of good		At 12.31.2022	At 12.31.2021
Machinery and equipment		9	12
Total at 12.31.2022		9
Total at 12.31.2021			12

Schedule of lease liabilities

	12.31.2022	12.31.2021
At the beginning of the year	13	12
Increases	1	6
Result from measurement at present value (1)	2	-
Reversal of unused amounts	(1)	-
Payments	(3)	(5)
At the end of the year	12	13

⁽¹⁾ Included in Other financial results.

Schedule of lease liabilities payments by maturity

	12.31.2022
Three months to one year	1
One to two years	1
Two to three years	3
Three to four years	2
Four to five years	2
More than five years	14
Total	23

Schedule of lease receivables by maturity

	12.31.2022
Less than three months	1
Three months to one year	5
One to two years	5
Two to three years	7
Three to four years	5
Total	23

Schedule of future minimum operating lease

	12.31.2022
Three months to one year	1
One to two years	1
More than three years	1
Total	3

XML

OIL AND GAS RESERVES (Information not covered by the auditors’ report) (Tables)

12 Months Ended

Dec. 31, 2022

Oil And Gas Reserves

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	7,722	17,372	3,214	11,241	10,936	28,613
Total at 12.31.2022	7,722	17,372	3,214	11,241	10,936	28,613

⁽¹⁾ In thousands of barrels.

⁽²⁾ In millions of cubic meters.

XML

GENERAL INFORMATION (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
General Information
Transportation expense	$ 24
Construction cost	1,500
Transportation capacity	11
Construction capacity	$ 20
Percentage of energy	70.00%
Percentage of gross domestic product	6.40%	10.80%
Percentage of cumulative inflation	94.80%	50.90%
Percentage of depreciation	72.50%	22.10%

XML

REGULATORY FRAMEWORK (Details)	12 Months Ended
	Dec. 31, 2022
C T G 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GUEMTG01
Tecnology	TG
Power	100 MW
Applicable regime	Energy Plus Res. No. 1,281/06
C T G 2 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GUEMTV11
Tecnology	TV
Power	≤100 MW
Applicable regime	Resolution No. 826/22
C T G 3 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GUEMTV12
Tecnology	TV
Power	≤100 MW
Applicable regime	Resolution No. 826/22
C T G 4 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GUEMTV13
Tecnology	TV
Power	>100 MW
Applicable regime	Resolution No. 826/22
Piquirenda 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	PIQIDI 01-10
Tecnology	MCI
Power	30 MW
Applicable regime	Resolution No. 826/22
C P B 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	BBLATV29
Tecnology	TV
Power	>100 MW
Applicable regime	Resolution No. 826/22
C P B 2 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	BBLATV30
Tecnology	TV
Power	>100 MW
Applicable regime	Resolution No. 826/22
C T Ing White 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	BBLMD01-06
Tecnology	MCI
Power	100 MW
Applicable regime	Resolution No. 21/16
C T L L 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	LDLATG01/TG02/TG03/TV01
Tecnology	CC
Power	>150 MW
Applicable regime	Resolution No. 826/22
C T L L 2 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	LDLATG04
Tecnology	TG
Power	105 MW
Applicable regime	Res. No 220/07 (75%)
C T L L 3 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	LDLATG05
Tecnology	TG
Power	105 MW
Applicable regime	Resolution No. 21/16
C T L L 4 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	LDLMDI01
Tecnology	MCI
Power	15 MW
Applicable regime	Resolution No. 826/22
C T G E B A 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GEBATG01/TG02/TV01
Tecnology	CC
Power	>150 MW
Applicable regime	Resolution No. 826/22
C T G E B A 2 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GEBATG03
Tecnology	TG
Power	169 MW
Applicable regime	Energy Plus Res. No. 1,281/06
C T G E B A 3 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	GEBATG03/TG04/TV02
Tecnology	CC
Power	400 MW
Applicable regime	Resolution No. 287/17
Ecoenergia 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	CERITV01
Tecnology	TV
Power	14 MW
Applicable regime	Energy Plus Res. N° 1,281/06
C T Parque Pilar 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	PILBD01-06
Tecnology	MCI
Power	100 MW
Applicable regime	Resolution No. 21/16
C T B 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	EBARTG01 - TG02
Tecnology	TG
Power	>50 MW
Applicable regime	Resolution No. 826/22
H I D I S A 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	AGUA DEL TORO
Tecnology	HI
Power	HI – Media 120<P≤300
Applicable regime	Resolution No. 826/22
H I D I S A 2 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	EL TIGRE
Tecnology	HR
Power	Renewable  ≤ 50
Applicable regime	Resolution No. 826/22
H I D I S A 3 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	LOS REYUNOS
Tecnology	HB
Power	HB – Media 120<P≤300
Applicable regime	Resolution No. 826/22
H I D I S A 4 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	NIHUIL I - II - III
Tecnology	HI
Power	HI – Small  50<P≤120
Applicable regime	Resolution No. 826/22
H P P L 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	PPLEHI
Tecnology	HI
Power	HI – Media 120<P≤300
Applicable regime	Resolution No. 826/22
P E M Cebreiro 1 [Member]
IfrsStatementLineItems [Line Items]
Generating unit	CORTEO
Tecnology	Wind
Power	100 MW
Applicable regime	Renovar
P E P E I I [Member]
IfrsStatementLineItems [Line Items]
Generating unit	PAMEEO
Tecnology	Wind
Power	53 MW
Applicable regime	MATER Res. No. 281/17
P E P E I I I [Member]
IfrsStatementLineItems [Line Items]
Generating unit	BAHIEO
Tecnology	Wind
Power	53 MW
Applicable regime	MATER Res. No. 281/17
P E P E I V [Member]
IfrsStatementLineItems [Line Items]
Generating unit	BAHIEO
Tecnology	Wind
Power	18 MW
Applicable regime	MATER Res. No. 281/17
P E Arauco [Member]
IfrsStatementLineItems [Line Items]
Generating unit	AR21EO
Tecnology	Wind
Power	99.75 MW
Applicable regime	Renovar

XML

REGULATORY FRAMEWORK (Details 1)	12 Months Ended
	Dec. 31, 2022
C T B [Member]
IfrsStatementLineItems [Line Items]
Generator	CTB
Technology	CC
Capacity	280 MW
Applicable regime	Resolution No. 220/07
P E P E I V [Member]
IfrsStatementLineItems [Line Items]
Generator	PEPE IV
Technology	Wind
Capacity	63 MW
Applicable regime	MATER Res. No. 281/17
P E P E V I [Member]
IfrsStatementLineItems [Line Items]
Generator	PEPE VI
Technology	Wind
Capacity	94.5 MW
Applicable regime	MATER Res. No. 281/17

XML

REGULATORY FRAMEWORK (Details 2)	12 Months Ended
	Dec. 31, 2022
Minimum Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Technology / Scale	Large CC Capacity > 150 MW
SE No. 31/20 (AR$ / MW-month)	100,650
SE No. 440/21 (AR$ / MW-month)	129,839
SE No. 238/22 (AR$ / MW-month)	185,670
SE No. 826/22 (AR$ / MW-month)	245,084
Minimum Remuneration To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Technology / Scale	Large TV Capacity > 100 MW
SE No. 31/20 (AR$ / MW-month)	143,550
SE No. 440/21 (AR$ / MW-month)	185,180
SE No. 238/22 (AR$ / MW-month)	264,807
SE No. 826/22 (AR$ / MW-month)	349,546
Minimum Remuneration To Thermal Generators 2 [Member]
IfrsStatementLineItems [Line Items]
Technology / Scale	Small TV Capacity ≤ 100 MW
SE No. 31/20 (AR$ / MW-month)	171,600
SE No. 440/21 (AR$ / MW-month)	221,364
SE No. 238/22 (AR$ / MW-month)	316,551
SE No. 826/22 (AR$ / MW-month)	417,847
Minimum Remuneration To Thermal Generators 3 [Member]
IfrsStatementLineItems [Line Items]
Technology / Scale	Large GT Capacity > 50 MW
SE No. 31/20 (AR$ / MW-month)	117,150
SE No. 440/21 (AR$ / MW-month)	151,124
SE No. 238/22 (AR$ / MW-month)	216,107
SE No. 826/22 (AR$ / MW-month)	285,262

XML

REGULATORY FRAMEWORK (Details 3)	12 Months Ended
	Dec. 31, 2022
Additional Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Period	Summer – Winter
Remuneration For Guaranteed Power Capacity To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Period	Summer – Winter
Remuneration SE No. 31/20 ($ / MW-month)	360,000
Remuneration SE No. 440/21 ($ / MW-month)	464,400
Remuneration SE No. 238/22 ($ / MW-month)	664,092
Remuneration SE No. 826/22 ($ / MW-month)	876,601
Remuneration For Guaranteed Power Capacity To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Period	Fall - Spring
Remuneration SE No. 31/20 ($ / MW-month)	270,000
Remuneration SE No. 440/21 ($ / MW-month)	348,300
Remuneration SE No. 238/22 ($ / MW-month)	498,069
Remuneration SE No. 826/22 ($ / MW-month)	657,451

XML

REGULATORY FRAMEWORK (Details 4)	12 Months Ended
	Dec. 31, 2022
Remuneration For Guaranteed Power Capacity To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
[custom:WithAvailabilityCommitmentsPeriod]	Summer – Winter
Additional Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
[custom:WithAvailabilityCommitmentsPeriod]	Summer – Winter
Additional Remuneration To Thermal Generators [Member] | Minimum Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	45,000
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 31/20	22,500
Additional Remuneration To Thermal Generators [Member] | Minimum Remuneration To Thermal Generators 2 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 440/21	58,050
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 440/21	29,025
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	83,012
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	41,506
Additional Remuneration To Thermal Generators [Member] | Additional Remuneration To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 440/21	9,675
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	13,835
Remuneration For Guaranteed Power Capacity To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
[custom:WithAvailabilityCommitmentsPeriod]	Fall - Spring
Additional Remuneration To Thermal Generators 1 [Member] | Minimum Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	7,500

XML

REGULATORY FRAMEWORK (Details 5)	12 Months Ended
	Dec. 31, 2022
Base And Additional Remuneration To Hydroelectric Generators [Member]
IfrsStatementLineItems [Line Items]
Technology and scale	Medium HI Capacity > 120 ≤ 300 MW
Remuneration SE No. 31/20 ($ / MW-month)	132,000
Remuneration SE No. 440/21 ($ / MW-month)	170,280
Remuneration SE No. 238/22 ($ / MW-mes)	243,500
Remuneration SE No. 826/22 ($ / MW-mes)	321,421
Base And Additional Remuneration To Hydroelectric Generators One [Member]
IfrsStatementLineItems [Line Items]
Technology and scale	Small HI Capacity > 50 ≤ 120 MW
Remuneration SE No. 31/20 ($ / MW-month)	181,500
Remuneration SE No. 440/21 ($ / MW-month)	234,135
Remuneration SE No. 238/22 ($ / MW-mes)	334,813
Remuneration SE No. 826/22 ($ / MW-mes)	441,953
Base And Additional Remuneration To Hydroelectric Generators Two [Member]
IfrsStatementLineItems [Line Items]
Technology and scale	Medium Pumped HI Capacity > 120 ≤ 300 MW
Remuneration SE No. 31/20 ($ / MW-month)	132,000
Remuneration SE No. 440/21 ($ / MW-month)	170,280
Remuneration SE No. 238/22 ($ / MW-mes)	243,500
Remuneration SE No. 826/22 ($ / MW-mes)	321,421
Base And Additional Remuneration To Hydroelectric Generators Three [Member]
IfrsStatementLineItems [Line Items]
Technology and scale	Renewable HI Capacity ≤ 50 MW
Remuneration SE No. 31/20 ($ / MW-month)	297,000
Remuneration SE No. 440/21 ($ / MW-month)	383,130
Remuneration SE No. 238/22 ($ / MW-mes)	547,876
Remuneration SE No. 826/22 ($ / MW-mes)	723,196

XML

REGULATORY FRAMEWORK (Details 6)	12 Months Ended
	Dec. 31, 2022
Remuneration For Guaranteed Power Capacity To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Period	Summer – Winter
Additional Remuneration To Hydroelectric Generators [Member] | Minimum Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	39,000
Additional Remuneration To Hydroelectric Generators [Member] | Minimum Remuneration To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	25,155
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	50,310
Additional Remuneration To Hydroelectric Generators [Member] | Minimum Remuneration To Thermal Generators 2 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	35,972
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	71,943
Additional Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Period	Summer – Winter
Additional Remuneration To Thermal Generators [Member] | Minimum Remuneration To Thermal Generators [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	6,500
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	19,500
Additional Remuneration To Thermal Generators [Member] | Minimum Remuneration To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	8,385
Additional Remuneration To Thermal Generators [Member] | Minimum Remuneration To Thermal Generators 2 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	11,991
Remuneration For Guaranteed Power Capacity To Thermal Generators 1 [Member]
IfrsStatementLineItems [Line Items]
Period	Fall - Spring
Remuneration For Guaranteed Power Capacity To Thermal Generators Units [Member]
IfrsStatementLineItems [Line Items]
Period	Summer – Winter
Remuneration For Guaranteed Power Capacity To Thermal Generators Units [Member] | Minimum Remuneration To Thermal Generators Units [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	42,000
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	21,000
Remuneration For Guaranteed Power Capacity To Thermal Generators Units [Member] | Minimum Remuneration To Thermal Generators Units 1 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	9,030
Additional Remuneration To Hydroelectric Generators Units [Member] | Minimum Remuneration To Thermal Generators Units 1 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	27,090
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	54,180
Additional Remuneration To Hydroelectric Generators Units [Member] | Minimum Remuneration To Thermal Generators Units 2 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for second 25 hours ($ / MW-hmrt) SE No. 238/22	38,739
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	77,478
Remuneration For Guaranteed Power Capacity To Thermal Generators Units 1 [Member]
IfrsStatementLineItems [Line Items]
Period	Fall – Spring
Remuneration For Guaranteed Power Capacity To Thermal Generators Units 1 [Member] | Minimum Remuneration To Thermal Generators Units [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 31/20	7,000
Remuneration For Guaranteed Power Capacity To Thermal Generators Units 3 [Member] | Minimum Remuneration To Thermal Generators Units 2 [Member]
IfrsStatementLineItems [Line Items]
Remuneration for first 25 hours ($ / MW-hmrt) SE No. 238/22	12,913

XML

REGULATORY FRAMEWORK (Details 7)	12 Months Ended
	Dec. 31, 2022
Minimum Remuneration To Thermal Power Generator 3 [Member]
IfrsStatementLineItems [Line Items]
Remuniration	Generated energy
SE No. 31/20 ($ / MW-month)	Between 240 and 420
SE No. 440/21 ($ / MW-month)	Between 310 and 542
SE No. 238/22 (AR$ / MW-month)	Between 403 and 705
SE No. 826/22 (AR$ / MW-month)	Between 585 and 1,023
Minimum Remuneration To Thermal Power Generator 1 [Member]
IfrsStatementLineItems [Line Items]
Remuniration	Operated energy
SE No. 31/20 ($ / MW-month)	84
SE No. 440/21 ($ / MW-month)	108
SE No. 238/22 (AR$ / MW-month)	154
SE No. 826/22 (AR$ / MW-month)	204

XML

REGULATORY FRAMEWORK (Details 8)	12 Months Ended
	Dec. 31, 2022
Minimum Remuneration To Thermal Power Generator [Member]
IfrsStatementLineItems [Line Items]
[custom:Remuneration1]	Generated energy
SE No. 31/20 ($ / MW-month)	210
SE No. 440/21 ($ / MW-month)	271
SE No. 238/22 (AR$ / MW-month)	388
SE No. 826/22 (AR$ / MW-month)	512
Minimum Remuneration To Thermal Power Generator 1 [Member]
IfrsStatementLineItems [Line Items]
[custom:Remuneration1]	Operated energy
SE No. 31/20 ($ / MW-month)	84
SE No. 440/21 ($ / MW-month)	108
SE No. 238/22 (AR$ / MW-month)	154
SE No. 826/22 (AR$ / MW-month)	204

XML

REGULATORY FRAMEWORK (Details 9)	12 Months Ended
	Dec. 31, 2022
Minimum Remuneration To Thermal Power Generator [Member]
IfrsStatementLineItems [Line Items]
Remuneration 1	Generated energy
SE No. 31/20 ($ / MW-month)	210
SE No. 440/21 ($ / MW-month)	271
SE No. 238/22 (AR$ / MW-month)	388
SE No. 826/22 (AR$ / MW-month)	512
Minimum Remuneration From Unconvention Sources [Member]
IfrsStatementLineItems [Line Items]
SE No. 31/20 ($ / MW-month)	1,680
SE No. 440/21 ($ / MW-month)	2,167
SE No. 238/22 (AR$ / MW-month)	3,099
SE No. 826/22 (AR$ / MW-month)	3,719

XML

REGULATORY FRAMEWORK (Details Narrative) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Aug. 31, 2023	Feb. 28, 2023	Dec. 31, 2022	Sep. 30, 2022	Feb. 25, 2022	Dec. 31, 2022	Dec. 31, 2021
Regulatory Framework
Power capacity term						15 years
Percentage of commitment capacity						85.00%
Net power capacity term						5 years
Percentage of remuneration power capacity						35.00%	15.00%
Percentage of spot remuneration values modified				20.00%
Percentage of economic transaction	28.00%	25.00%	10.00%
Percentage of remuneration					25.00%
Percentage of increase remuneration					23.00%
Asessed tax							$ 100
Taxable income			$ 300			$ 300
Prepayment paid			$ 1,863			1,863
Purchase investment property						$ 30,000

XML

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2022
Buildings [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	50 years
Other property, plant and equipment [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	5 years
Other property, plant and equipment [member] | Vehicles [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	3 years
Vehicles [member] | Top of range [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	5 years
Computer equipment [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	3 years
Tools [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	10 years
Machinery [member] | Top of range [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	30 years
Machinery [member] | Bottom of range [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment estimated useful lives	10 years

XML

ACCOUNTING POLICIES (Details Narrative)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Applicable tax rate	35.00%	35.00%	30.00%
Argentina [Member]
IfrsStatementLineItems [Line Items]
Applicable tax rate	35.00%
Ecuador [Member]
IfrsStatementLineItems [Line Items]
Applicable tax rate	25.00%
Bolivia [Member]
IfrsStatementLineItems [Line Items]
Applicable tax rate	25.00%
Uruguay [Member]
IfrsStatementLineItems [Line Items]
Applicable tax rate	25.00%
E C [Member]
IfrsStatementLineItems [Line Items]
Surcharge rate	3.00%
B O [Member]
IfrsStatementLineItems [Line Items]
Withholding income tax rate	12.50%
Percentage of withholdings on dividends	10.00%

XML

GROUP STRUCTURE (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Group Structure
Revenue			$ 493	$ 1,085
Cost of sales			(398)	(926)
Gross profit			95	159
Selling expenses			(36)	(79)
Administrative expenses			(26)	(64)
Other operating income			21	29
Other operating expenses			(18)	(25)
Reversal of property, plant and equipment impairment			16	(589)
Impairment of financial assets			(11)	(50)
Operating income (loss)			41	(619)
Gain on monetary position, net			120	115
Financial income				1
Financial costs			(106)	(110)
Other financial results			8	(20)
Financial results, net			22	(14)
Profit (Loss) before income tax			63	(633)
Income tax			(138)	41
Loss of the year from discontinued operations			(75)	(592)
Other comprehensive income (loss)
Results related to defined benefit plans				1
Exchange differences on translation			34	(15)
Exchange differences on translation	[1]		30	(19)
Other comprehensive income (loss) of the year from discontinued operations			64	(33)
Total comprehensive loss of the year from discontinued operations			(11)	(625)
Total  (loss) profit of the year from discontinued operations attributable to:
Owners of the company			(39)	(499)
Non - controlling interest			(36)	(93)
Total comprehensive loss of the year from discontinued operations attributable to:
Owners of the company			(9)	(517)
Non - controlling interest			(2)	(108)
Total comprehensive (loss) income of the year from discontinued operations attributable to:			$ (11)	$ (625)

[1] As of December 31, 2021, corresponds to the reclassification adjustment for exchange differences losses included in profit or loss on Edenor disposal. No exchange differences losses on translation were reconized during 2021.

XML

GROUP STRUCTURE (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Group Structure
Net cash generated by operating activities		$ 116	$ 211
Net cash used in investing activities		(166)	(86)
Net cash used in financing activities		(7)	(73)
(Decrease) Increase in cash and cash equivalents		(57)	52
Cash and cash equivalents at the beginning of the year		52	9
Effect of devaluation and inflation on cash and cash equivalents		5	(9)
Cash and cash equivalents at the end of the year			$ 52

XML

GROUP STRUCTURE (Details 2) - USD ($) $ in Millions		Dec. 31, 2022	Aug. 12, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Property, plant and equipment		$ 2,164.0		$ 1,659.0
Trade receivables		490.0		431.0
Borrowings		(1,613.0)		(1,438.0)
Trade and other payables		$ (281.0)		$ (182.0)
Greenwind [Member]
IfrsStatementLineItems [Line Items]
Consideration transferred			$ (20.5)
Fair value of the previous interest in Greenwind			(20.4)
Total			(40.9)
Property, plant and equipment	[1]		127.7
Intangible assets - Customer contract	[2]		31.6
Financial assets at fair value			24.4
Trade receivables	[3]		6.3
Other assets			0.1
Cash and cash equivalents			3.1
Borrowings			(89.3)
Deferred tax liabilities			(54.3)
Income tax liabilities			(4.4)
Trade and other payables			(2.0)
Provisions			(1.4)
Tax liabilities			(0.9)
Total acquisition price allocation	[4]		$ 40.9

[1] Mario Cebreiro Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

[2] The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

[3] For acquired trade receivables, contractual value does not differ from fair value.

[4] No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

XML

GROUP STRUCTURE (Details 3) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Property, plant and equipment		$ 2,164.0	$ 1,659.0
Trade receivables		490.0	431.0
Trade and other payables		(281.0)	$ (182.0)
V A R [Member]
IfrsStatementLineItems [Line Items]
[custom:ConsiderationTransferred-0]		(128.1)
Estimated price adjustment		6.7
Total		(121.4)
Property, plant and equipment	[1]	167.7
Intangible assets - Customer contract	[2]	62.3
Trade receivables	[3]	4.9
Other receivables		1.2
Deferred tax liability		(60.2)
Income tax liability		(5.0)
Trade and other payables		(3.3)
Other payables		(46.0)
Tax liabilities		(0.2)
Total acquisition price allocation	[4]	$ 121.4

[1] Arauco Wind Farm’s fair value was assessed using the “cost-based approach,” which consists of the farm’s replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

[2] The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the “income-based approach” and the “multi-period excess earnings” method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

[3] For acquired trade receivables, contractual value does not differ from fair value.

[4] No differences in the acquired assets’ accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

XML

GROUP STRUCTURE (Details 4)		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Autotrol Renovable S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name	[1]	Autotrol Renovable S.A. (1)
Country	[1]	Argentina
Main activity	[1]	Generation
Direct and indirect participation	[1]	100.00%
G A S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		GASA
Country		Argentina
Main activity		Generation
Direct and indirect participation		100.00%	100.00%
Enecor S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Enecor S.A.
Country		Argentina
Main activity		Electricity transportation
Direct and indirect participation		70.00%	70.00%
Fideicomiso C I E S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Fideicomiso CIESA
Country		Argentina
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
Greenwind [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name	[2]	Greenwind (3)
Country	[2]	Argentina
Main activity	[2]	Generation
Direct and indirect participation	[2]	100.00%	50.00%
Hidroelectrica Diamante S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		HIDISA
Country		Argentina
Main activity		Generation
Direct and indirect participation		61.00%	61.00%
Hidroelectrica Los Nihuiles S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		HINISA
Country		Argentina
Main activity		Generation
Direct and indirect participation		52.04%	52.04%
C I S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		CISA
Country		Argentina
Main activity		Trader & investment
Direct and indirect participation		100.00%	100.00%
Pampa Energia Bolivia S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		PEB
Country		Bolivia
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
P B 18 [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		PB18
Country		Ecuador
Main activity		Oil
Direct and indirect participation		100.00%	100.00%
Energia Operaciones E N O P S A S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Energía Operaciones ENOPSA S.A.
Country		Ecuador
Main activity		Oil
Direct and indirect participation		100.00%	100.00%
Pampa Ecuador [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Pampa Ecuador Inc
Country		Ecuador
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
Petrobras Energia Ecuador [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		PE Energía Ecuador LTD
Country		Gran Cayman
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
E I S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		EISA
Country		Uruguay
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
Pampa Inversiones S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		PISA
Country		Uruguay
Main activity		Investment
Direct and indirect participation		100.00%	100.00%
Transportey Serviciosde Gasen Uruguay S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		TGU
Country		Uruguay
Main activity		Gas transportation
Direct and indirect participation		51.00%	51.00%
Corod Produccion S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name	[2]	Corod (3)
Country	[2]	Venezuela
Main activity	[2]	Oil
Direct and indirect participation	[2]		100.00%
Petrolera San Carlos S A [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Petrolera San Carlos S.A.
Country		Venezuela
Main activity		Oil
Direct and indirect participation		100.00%	100.00%
Vientos De Arauco Renovables S A U [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name	[3]	Vientos de Arauco Renovables S.A.U. (4)
Country	[3]	Argentina
Main activity	[3]	Generation
Direct and indirect participation	[3]	100.00%
Vientos Solutions Argentina S A U [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name		Vientos Solutions Argentina S.A.U.
Country		Argentina
Main activity		Advisory services
Direct and indirect participation		100.00%
V S S L [Member]
IfrsStatementLineItems [Line Items]
Subsidiary name	[4]	VS S.L. (2)
Country	[4]	España
Main activity	[4]	Investment
Direct and indirect participation	[4]	100.00%

[1] See Note 5.1.4.

[2] Interest assigned under the assignment of the indirect interest in the capital stock of mixed companies in Venezuela. See Note 5.3.2.

[3] See Note 5.1.5.

[4] See Note 5.1.3.

XML

GROUP STRUCTURE (Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Share capital		$ 36	$ 36
(Loss) Profit of the year		$ 457	$ 238	$ (468)
Compania De Inversiones De Energia S A [Member]
IfrsStatementLineItems [Line Items]
Joint ventures	[1]	CIESA
Main activity	[1]	Investment
Date	[1]	Dec. 31, 2022
Share capital	[1]	$ 4
(Loss) Profit of the year	[1]	93
Equity	[1]	$ 770
Compania Inversora En Transmision Electrica Citelec S A [Member]
IfrsStatementLineItems [Line Items]
Joint ventures	[2]	Citelec
Main activity	[2]	Investment
Date	[2]	Dec. 31, 2022
Share capital	[2]	$ 3
(Loss) Profit of the year	[2]	5
Equity	[2]	$ 235
C T B [Member]
IfrsStatementLineItems [Line Items]
Joint ventures		CTB
Main activity		Generation
Date		Dec. 31, 2022
Share capital		$ 48
(Loss) Profit of the year		53
Equity		$ 536
Oleoducto De Crudos Pesados [Member]
IfrsStatementLineItems [Line Items]
Joint ventures		OCP
Main activity		Investment
Date		Dec. 31, 2022
Share capital		$ 100
(Loss) Profit of the year		(4)
Equity		$ 96
Transportadora De Gas Del Sur S A [Member]
IfrsStatementLineItems [Line Items]
Joint ventures	[1]	TGS
Main activity	[1]	Gas transportation
Date	[1]	Dec. 31, 2022
Share capital	[1]	$ 4
(Loss) Profit of the year	[1]	182
Equity	[1]	$ 1,508

[1] The Company holds a direct and indirect interest of 3.764% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, additionally the Company has an indirect participation of 25.50% in TGS.

[2] The Company holds a 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, 2022, Transener’s common share price listed at the Buenos Aires Stock Exchange was $ 184,50, conferring Pampa’s indirect interest an approximate $ 21,598 million market value.

XML

GROUP STRUCTURE (Details 6) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Interests in associates		$ 82	$ 98
Interests in joint ventures		820	676
Interests in associates and joint ventures		902	774
Investments in joint ventures and associates			(4)
Compania De Inversione De Energia S A [Member]
IfrsStatementLineItems [Line Items]
Interests in joint ventures		435	347
Compania Inversora En Transmision Electrica Citelec S A [Member]
IfrsStatementLineItems [Line Items]
Interests in joint ventures		117	102
C T Barragan S A [Member]
IfrsStatementLineItems [Line Items]
Interests in joint ventures		268	227
Greenwind S A [Member]
IfrsStatementLineItems [Line Items]
Investments in joint ventures and associates			(4)
Refineria Del Norte S A [Member]
IfrsStatementLineItems [Line Items]
Interests in associates	[1]		22
Oleoducto De Crudos Pesados Ltd [Member]
IfrsStatementLineItems [Line Items]
Interests in associates		15	24
Transportadora De Gas Del Sur S A [Member]
IfrsStatementLineItems [Line Items]
Interests in associates		$ 67	$ 52

[1] See Note 5.1.2.

XML

GROUP STRUCTURE (Details 7) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Share of profit (loss) of associates		$ (6)	$ 23	$ (6)
Share of profit (loss) of joint ventures		111	94	91
Total investments in associates and joint ventures		105	117	85
C I E S A [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of joint ventures		43	50	11
C T B [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of joint ventures		41	49	64
Citelec [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of joint ventures		3	(3)	13
Greenwind [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of joint ventures	[1]	24	(2)	3
Refinor [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of associates		(12)	(2)	(2)
O C P [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of associates		(1)	18	(5)
T G S 1 [Member]
IfrsStatementLineItems [Line Items]
Share of profit (loss) of associates		$ 7	$ 7	$ 1

[1] See Note 5.1.3.

XML

GROUP STRUCTURE (Details 8) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Group Structure
At the beginning of the year		$ 770	$ 547	$ 507
Compensation				(5)
Dividends		(8)		(34)
Increases		1	17	3
Decrease due to acquisition of control	[1]	(20)
Decrease due to sale of equity interests	[2]	(6)
[custom:ShareOfProfitLossOfAssociatesAndJointVentureAccountedForUsingEquityMethod]		116	117	85
Impairment	[2]	(11)
Exchange differences		60	89	(9)
At the end of the year		$ 902	$ 770	$ 547

[1] See Note 5.1.3.

[2] See Note 5.1.2.

XML

GROUP STRUCTURE (Details 9) - Pampa Energia Bolivia S A [Member] $ in Millions	Aug. 12, 2021 USD ($)
IfrsStatementLineItems [Line Items]
Acquisition cost	$ (5.0)
Total consideration transferred	(5.0)
Share value of the interest in the fair value of associates’s identifiable assets and liabilities	12.7	[1]
Dividends to be received	9.5
Fair value of net assets	22.2
Profit	$ 17.2	[2]

[1] Calculated based on the present value of expected dividend flows.

[2] Disclosed under “Share of profit from associates and joint ventures”.

XML

GROUP STRUCTURE (Details 10)	12 Months Ended
	Dec. 31, 2022
Argentinian Production 1 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Río Neuquén
Operator name	YPF
Duration up to	2027/2051
Argentinian Production 1 [Member] | Minimum [Member]
IfrsStatementLineItems [Line Items]
Direct participation	3142.00%
Argentinian Production 1 [Member] | Maximum [Member]
IfrsStatementLineItems [Line Items]
Direct participation	3307.00%
Argentinian Production 2 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Sierra Chata
Direct participation	4555.00%
Operator name	PAMPA
Location	Neuquén
Duration up to	2053
Argentinian Production 3 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	El Mangrullo
Direct participation	10000.00%
Operator name	PAMPA
Location	Neuquén
Duration up to	2053
Argentinian Production 4 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	La Tapera - Puesto Quiroga
Direct participation	3567.00%
Operator name	Tecpetrol
Location	Chubut
Duration up to	2027
Argentinian Production 5 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	El Tordillo
Direct participation	3567.00%
Operator name	Tecpetrol
Location	Chubut
Duration up to	2027
Argentinian Production 6 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Aguaragüe	[1]
Direct participation	1500.00%	[1]
Operator name	Tecpetrol	[1]
Duration up to	2023/2027	[1]
Location	Salta	[1]
Argentinian Production 7 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Gobernador Ayala
Direct participation	2251.00%
Operator name	Pluspetrol
Location	Mendoza
Duration up to	2036
Argentinian Production 8 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Anticlinal Campamento	[2]
Direct participation	1500.00%	[2]
Operator name	Oilstone	[2]
Location	Neuquén	[2]
Duration up to	2026	[2]
Argentinian Production 9 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Estación Fernández Oro	[3]
Direct participation	1500.00%	[3]
Operator name	YPF	[3]
Location	Río Negro	[3]
Duration up to	2026	[3]
Argentinian Production 10 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Río Limay este (Ex Senillosa)	[4]
Direct participation	8500.00%	[4]
Operator name	PAMPA	[4]
Location	Neuquén	[4]
Duration up to	2040	[4]
Argentinian Production 11 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Veta Escondida y Rincón de Aranda
Direct participation	5500.00%
Operator name	PAMPA
Location	Neuquén
Duration up to	2027
Argentinian Production 12 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Rincón del Mangrullo
Direct participation	5000.00%
Operator name	YPF
Location	Neuquén
Duration up to	2052
Argentinian Production 13 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Los Blancos (ex Chirete)
Direct participation	5000.00%
Operator name	High Luck Group Limited
Location	Salta
Duration up to	2045
Argentinian Exploration 1 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Parva Negra Este	[5]
Direct participation	4250.00%	[5]
Operator name	PAMPA	[5]
Location	Neuquén	[5]
Duration up to	2019	[5]
Argentinian Exploration 2 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Río Atuel	[6]
Direct participation	3333.00%	[6]
Operator name	Petrolera El Trebol	[6]
Location	Mendoza	[6]
Duration up to	2023	[6]
Argentinian Exploration 3 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Borde del Limay	[7]
Direct participation	8500.00%	[7]
Operator name	PAMPA	[7]
Location	Neuquén	[7]
Duration up to	2015	[7]
Argentinian Exploration 4 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Los Vértices	[7]
Direct participation	8500.00%	[7]
Operator name	PAMPA	[7]
Location	Neuquén	[7]
Duration up to	2015	[7]
Argentinian Exploration 5 [Member]
IfrsStatementLineItems [Line Items]
Joint operation name	Las Tacanas Norte	[8]
Direct participation	9000.00%	[8]
Operator name	PAMPA	[8]
Location	Neuquén	[8]
Duration up to	2023	[8]

[1] On February 3, 2023, an agreement for a 10-year extension of the concession was signed with the enforcement authority. The Provincial Executive Order ratifying this agreement is pending publication.

[2] Direct participation in 9 wells. On January 19, 2023, the Company accepted Oilstone Energía S.A.’s offer to terminate its rights and obligations under the investment agreement, the Joint Venture and the operating agreement of the block, effective from January 1, 2023.

[3] Direct participation in 13 wells.

[4] On January 2, 2023, the environmental remediation plan was approved by the Province of Neuquén’s Subsecretariat of Environment, a necessary preliminary step to relinquish the block.

[5] A contractual continuity plan was submitted (see details below).

[6] Pursuant to Resolution No. 1,787/22 of the Province of Mendoza’s Ministry of Economy and Energy, the granting of a lot under evaluation, requested by Phoenix Global Resources —Petrolera El Trébol’s controlling company— and the Company on April 6, 2022, was approved until August 31, 2023.

[7] Under process of relinquishment to the province.

[8] On January 4, 2023, the exploration period terminated, and the Company’s rights and obligations over the area expired.

XML

GROUP STRUCTURE (Details 11) Number in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Number	Dec. 31, 2021 USD ($) Number	Dec. 31, 2020 USD ($) Number
Group Structure
At the beginning of the year	$ 42	$ 50	$ 33
Increases	2	8	24
Transferred to development	(6)	(16)	(7)
At the end of the year	$ 38	$ 42	$ 50
Number of wells at the end of the year | Number	7	10	12

XML

GROUP STRUCTURE (Details Narrative) - USD ($) $ in Millions					1 Months Ended				12 Months Ended
	Dec. 12, 2022	Oct. 14, 2022	Aug. 12, 2022	Aug. 12, 2021	Sep. 30, 2022	Sep. 15, 2022	Aug. 22, 2022	May 16, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 14, 2022
IfrsStatementLineItems [Line Items]
impairment losses					$ 11.0				$ 589.0
Percentage of sale						28.50%
Capital stock price						$ 5.7
Collect cash		$ 1.7
Collected cash		$ 4.0
Interest rate		8.00%
Acquisition amount			$ 20.5
Equity interest rate			50.00%
Percentage of fair value									50.00%
Acquisition revenues									$ 11.3
Net earnings									3.5
Revenues from sale									1,844.0
Additional equity interest									20.5
Cash and cash equivalents									3.1
Net cash flow									17.4
Capacity price	$ 171.0
Interest liability	$ 46.0
Revenues from sales									1,858.0	$ 448.0
Partial payment public securities									34.9
Accrued amount							$ 4,235.0	$ 25.0
Fixed interest rate	0.00%							0.00%
Maturity date	May 16, 2025							May 16, 2025
Accruing interest								$ 1,754.0
Variable fixed interest rate								2.98%
Maturity dates								Nov. 16, 2023
Accruing interest rate							1.00%
Additional accruing interest	$ 58.6
Fair value of accrued	10.7
Outstanding face value	$ 32.2
Impairment reversal				$ 1.6
Percentage of discount rate				15.09%
Exploration interest rate											4250.00%
Greenwinds [Member]
IfrsStatementLineItems [Line Items]
Revenues from sale									$ 459.0

XML

RISKS (Details) - Number	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Variation of the result for the year	62	49
Shares [Member]
IfrsStatementLineItems [Line Items]
Variation of the result for the year	19	15
Government Securities [Member]
IfrsStatementLineItems [Line Items]
Variation of the result for the year	28	28
Corporate Bonds [Member]
IfrsStatementLineItems [Line Items]
Variation of the result for the year	12	2
Investment funds [member]
IfrsStatementLineItems [Line Items]
Variation of the result for the year	3	4

XML

RISKS (Details 1) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Total borrowings	$ 1,613	$ 1,438
Fixed interest rate [member]
IfrsStatementLineItems [Line Items]
Total borrowings	1,230	1,329
Fixed interest rate [member] | Argentinian Pesos [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	57	11
Fixed interest rate [member] | U S Dollar [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	1,173	1,318
Floating interest rate [member]
IfrsStatementLineItems [Line Items]
Total borrowings	289	87
Floating interest rate [member] | Argentinian Pesos [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	140
Floating interest rate [member] | U S Dollar [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	149	87
Non Interest Accrues [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	94	22
Non Interest Accrues [Member] | Argentinian Pesos [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	22
Non Interest Accrues [Member] | U S Dollar [Member]
IfrsStatementLineItems [Line Items]
Total borrowings	$ 72	$ 22

XML

RISKS (Details 2)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Undue [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.08%	0.06%	0.35%
Undue [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.18%	0.04%	0.49%
Undue [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.00%	0.02%
Undue [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.00%	12.58%
Thirty Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.26%	0.29%	1.11%
Thirty Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.48%	0.17%	0.72%
Thirty Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.00%	0.06%
Thirty Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.00%	0.94%
Sixty Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	2.54%	2.08%	5.74%
Sixty Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	13.24%	0.77%	5.96%
Sixty Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.01%	0.72%
Sixty Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.01%	0.00%
Ninety Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	7.11%	2.83%	9.78%
Ninety Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	31.50%	2.72%	16.21%
Ninety Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.05%	2.26%
Ninety Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.05%	0.00%
One Hundred Twenty Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	14.37%	4.67%	11.23%
One Hundred Twenty Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	32.01%	6.88%	16.23%
One Hundred Twenty Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.12%	9.95%
One Hundred Twenty Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.12%	0.00%
One Hundred Fifty Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	21.39%	6.12%	19.77%
One Hundred Fifty Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	32.09%	19.88%	17.74%
One Hundred Fifty Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.52%	23.84%
One Hundred Fifty Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.52%	0.00%
One Hundred Eighty Days [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	27.22%	6.24%	20.87%
One Hundred Eighty Days [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	32.31%	21.97%	17.76%
One Hundred Eighty Days [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.52%	19.14%
One Hundred Eighty Days [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.52%	0.00%
One Hundred Eighty Days And More [Member] | Generation [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	33.01%	6.25%	22.71%
One Hundred Eighty Days And More [Member] | Oil Gas [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	32.38%	15.89%	17.79%
One Hundred Eighty Days And More [Member] | Petrochemicals [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.54%	36.92%
One Hundred Eighty Days And More [Member] | Holding [Member]
SEC Schedule, 12-29, Real Estate Companies, Investment in Mortgage Loans on Real Estate [Line Items]
Credit loss on trade receivables and financial assets	0.00%	0.54%	0.00%

XML

RISKS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Risks
Current assets	$ 1,343	$ 1,125
Current liabilities	$ 631	$ 342
Liquidity index	2.13%	3.29%

XML

RISKS (Details 4) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Trade receivables		$ 490	$ 431
Trade and other payables	[1]	302	194
Borrowings		2,103	1,996
Not later than three months [member]
IfrsStatementLineItems [Line Items]
Trade receivables		412	304
Trade and other payables	[1]	231	178
Borrowings		118	56
Later than three months and not later than one year [member]
IfrsStatementLineItems [Line Items]
Trade receivables		19	61
Trade and other payables	[1]	50	4
Borrowings		304	102
Later than one year and not later than two years [member]
IfrsStatementLineItems [Line Items]
Trade receivables		6	6
Trade and other payables	[1]	12	5
Borrowings		357	557
Later than two years and not later than five years [member]
IfrsStatementLineItems [Line Items]
Trade receivables		12	18
Trade and other payables	[1]	3	3
Borrowings		992	256
Later than five years [member]
IfrsStatementLineItems [Line Items]
Trade receivables		(0)	(0)
Trade and other payables	[1]	6	4
Borrowings		332	1,025
No Set Maturity Term [Member]
IfrsStatementLineItems [Line Items]
Trade receivables		41	42
Trade and other payables		(0)	(0)
Borrowings

[1] Corresponding to the investment plan’s readjustment bond at the Sierra Chata block (see Note 17.2).

XML

RISKS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Risks
Total borrowings	$ 1,613	$ 1,438
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(692)	(568)
Net debt	921	870
Total capital attributable to owners	$ 3,198	$ 2,655
Leverage ratio	2880.00%	3277.00%

XML

SEGMENT INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Gross profit	$ 681	$ 553	$ 410
Other operating income	131	105	51
Other operating expenses	(46)	(58)	(36)
Share of profit from associates and joint ventures	105	117	85
Operating income (loss)	631	579	243
Financial income	5	10	9
Other financial results	166	(14)	84
Financial results, net	(50)	(189)	(84)
Profit (loss) before income tax	581	390	159
Profit (loss) of the year	457	238	(468)
Total profit (loss) of the year attributable to:
Owners of the company	456	273	(367)
Non-controlling interest	1	(35)	(101)
Profit (loss) of the year from continuing operations	457	313	124
Loss of the year from discontinued operations		(75)	(592)
Generation [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market	663	656	559
Revenue - foreign market
Intersegment revenue
Cost of sales	(370)	(355)	(254)
Gross profit	293	301	305
Selling expenses	(3)	(2)	(2)
Administrative expenses	(39)	(31)	(30)
Other operating income	25	42	35
Other operating expenses	(5)	(5)	(6)
Impairment of property, plant and equipment, intangible assets and inventories
Impairment of financial assets
Share of profit from associates and joint ventures	65	47	67
Operating income (loss)	336	350	241
Financial income	1	4	3
Financial costs	(82)	(46)	(73)
Other financial results	72	(14)	1
Financial results, net	(9)	(56)	(69)
Profit (loss) before income tax	327	294	172
Income tax	(73)	(75)	(33)
Profit (loss) of the year	254	219	139
Depreciation and amortization	82	88	95
Total profit (loss) of the year attributable to:
Owners of the company	253	218	147
Non-controlling interest	1	1	(8)
Assets	2,464	1,670	1,595
Liabilities	979	525	707
Net book values of property, plant and equipment	1,299	969	1,015
Increases in property, plant and equipment and right-of-use assets	115	39	61
Impairment of property, plant and equipment, intangible assets and inventories		(2)	(128)
Profit (loss) of the year from continuing operations		219	139
Loss of the year from discontinued operations
Oil And Gas Segment [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market	370	282	199
Revenue - foreign market	159	58	28
Intersegment revenue	117	113	67
Cost of sales	(359)	(289)	(243)
Gross profit	287	164	51
Selling expenses	(36)	(18)	(15)
Administrative expenses	(60)	(46)	(42)
Other operating income	61	58	9
Other operating expenses	(26)	(28)	(17)
Impairment of property, plant and equipment, intangible assets and inventories	(30)
Impairment of financial assets	(2)		(13)
Share of profit from associates and joint ventures
Operating income (loss)	194	130	(27)
Financial income	2	3	7
Financial costs	(107)	(103)	(100)
Other financial results	(28)	(16)	44
Financial results, net	(133)	(116)	(49)
Profit (loss) before income tax	61	14	(76)
Income tax	(16)	8	23
Profit (loss) of the year	45	22	(53)
Depreciation and amortization	125	114	108
Total profit (loss) of the year attributable to:
Owners of the company	45	22	(53)
Non-controlling interest
Assets	1,234	1,157	1,085
Liabilities	1,248	1,324	1,174
Net book values of property, plant and equipment	807	636	543
Increases in property, plant and equipment and right-of-use assets	324	213	41
Impairment of property, plant and equipment, intangible assets and inventories
Profit (loss) of the year from continuing operations		22	(53)
Loss of the year from discontinued operations
Petrochemicals [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market	425	310	178
Revenue - foreign market	192	180	89
Intersegment revenue
Cost of sales	(536)	(424)	(233)
Gross profit	81	66	34
Selling expenses	(17)	(13)	(9)
Administrative expenses	(5)	(4)	(3)
Other operating income	1	1
Other operating expenses	(6)	(3)	(6)
Impairment of property, plant and equipment, intangible assets and inventories	(2)
Impairment of financial assets			1
Share of profit from associates and joint ventures
Operating income (loss)	52	45	6
Financial income
Financial costs	(3)	(3)	(3)
Other financial results	6	(2)	5
Financial results, net	3	(5)	2
Profit (loss) before income tax	55	40	8
Income tax	(15)	(12)	(2)
Profit (loss) of the year	40	28	6
Depreciation and amortization	5	3	2
Total profit (loss) of the year attributable to:
Owners of the company	40	28	6
Non-controlling interest
Assets	177	176	107
Liabilities	147	166	126
Net book values of property, plant and equipment	24	22	19
Increases in property, plant and equipment and right-of-use assets	7	6	3
Impairment of property, plant and equipment, intangible assets and inventories		(2)	(11)
Profit (loss) of the year from continuing operations		28	6
Loss of the year from discontinued operations
Holding And Others [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market	20	22	20
Revenue - foreign market
Intersegment revenue
Cost of sales
Gross profit	20	22	20
Selling expenses
Administrative expenses	(34)	(18)	(18)
Other operating income	44	4	7
Other operating expenses	(9)	(22)	(7)
Impairment of property, plant and equipment, intangible assets and inventories	(6)
Impairment of financial assets	(6)	(2)	3
Share of profit from associates and joint ventures	40	70	18
Operating income (loss)	49	54	23
Financial income	9	4	1
Financial costs	(36)	(34)	(3)
Other financial results	116	18	34
Financial results, net	89	(12)	32
Profit (loss) before income tax	138	42	55
Income tax	(20)	2	(23)
Profit (loss) of the year	118	44	32
Depreciation and amortization
Total profit (loss) of the year attributable to:
Owners of the company	118	44	32
Non-controlling interest
Assets	1,029	1,067	832
Liabilities	245	264	178
Net book values of property, plant and equipment	34	32	33
Increases in property, plant and equipment and right-of-use assets	36	6	2
Impairment of property, plant and equipment, intangible assets and inventories
Profit (loss) of the year from continuing operations		44	32
Loss of the year from discontinued operations
Eliminations [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market
Revenue - foreign market
Intersegment revenue	(117)	(113)	(67)
Cost of sales	117	113	67
Gross profit
Selling expenses
Administrative expenses
Other operating income
Other operating expenses
Impairment of property, plant and equipment, intangible assets and inventories
Impairment of financial assets
Share of profit from associates and joint ventures
Operating income (loss)
Financial income	(7)	(1)	(2)
Financial costs	7	1	2
Other financial results
Financial results, net
Profit (loss) before income tax
Income tax
Profit (loss) of the year
Depreciation and amortization
Total profit (loss) of the year attributable to:
Owners of the company
Non-controlling interest
Assets	(162)	(209)	(85)
Liabilities	(161)	(209)	(85)
Net book values of property, plant and equipment
Increases in property, plant and equipment and right-of-use assets
Impairment of property, plant and equipment, intangible assets and inventories
Profit (loss) of the year from continuing operations
Loss of the year from discontinued operations
Consolidateds [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market	1,478	1,270	956
Revenue - foreign market	351	238	117
Intersegment revenue
Cost of sales	(1,148)	(955)	(663)
Gross profit	681	553	410
Selling expenses	(56)	(33)	(26)
Administrative expenses	(138)	(99)	(93)
Other operating income	131	105	51
Other operating expenses	(46)	(58)	(36)
Impairment of property, plant and equipment, intangible assets and inventories	(38)
Impairment of financial assets	(8)	(2)	(9)
Share of profit from associates and joint ventures	105	117	85
Operating income (loss)	631	579	243
Financial income	5	10	9
Financial costs	(221)	(185)	(177)
Other financial results	166	(14)	84
Financial results, net	(50)	(189)	(84)
Profit (loss) before income tax	581	390	159
Income tax	(124)	(77)	(35)
Profit (loss) of the year	457	238	(468)
Depreciation and amortization	212	205	286
Total profit (loss) of the year attributable to:
Owners of the company	456	273	(367)
Non-controlling interest	1	(35)	(101)
Assets	4,742	3,861	4,890
Liabilities	2,458	2,070	3,121
Net book values of property, plant and equipment	2,164	1,659	1,610
Increases in property, plant and equipment and right-of-use assets	$ 482	264	242
Impairment of property, plant and equipment, intangible assets and inventories		(4)	(139)
Profit (loss) of the year from continuing operations		313	124
Loss of the year from discontinued operations		(75)	(592)
Distribution Of Energy [Member]
IfrsStatementLineItems [Line Items]
Revenue - local market
Revenue - foreign market
Intersegment revenue
Cost of sales
Gross profit
Selling expenses
Administrative expenses
Other operating income
Other operating expenses
Impairment of financial assets
Share of profit from associates and joint ventures
Operating income (loss)
Financial income
Financial costs
Other financial results
Financial results, net
Profit (loss) before income tax
Income tax
Profit (loss) of the year		(75)	(592)
Depreciation and amortization			81
Total profit (loss) of the year attributable to:
Owners of the company		(39)	(499)
Non-controlling interest		(36)	(93)
Assets			1,356
Liabilities			1,021
Net book values of property, plant and equipment
Increases in property, plant and equipment and right-of-use assets			135
Impairment of property, plant and equipment, intangible assets and inventories
Profit (loss) of the year from continuing operations
Loss of the year from discontinued operations		$ (75)	$ (592)

XML

REVENUE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Revenue	$ 1,829	$ 1,508	$ 1,073
Generation [Member]
IfrsStatementLineItems [Line Items]
Revenue	663	656	559
Generation [Member] | Sales Of Energy To The S P O T Market [Member]
IfrsStatementLineItems [Line Items]
Revenue	210	167	179
Generation [Member] | Sales Of Energy By Contract [Member]
IfrsStatementLineItems [Line Items]
Revenue	346	380	323
Generation [Member] | Fuel Supply [Member]
IfrsStatementLineItems [Line Items]
Revenue	103	104	54
Generation [Member] | Other Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	4	5	3
Oil And Gas Segment [Member]
IfrsStatementLineItems [Line Items]
Revenue	529	340	227
Oil And Gas Segment [Member] | Other Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	10	10	10
Oil And Gas Segment [Member] | Gas Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	383	231	152
Oil And Gas Segment [Member] | Oil Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	136	99	65
Petrochemicals [Member]
IfrsStatementLineItems [Line Items]
Revenue	617	490	267
Petrochemicals [Member] | Other Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	4	3	7
Petrochemicals [Member] | Products From Catalytic Reforming Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	270	185	98
Petrochemicals [Member] | Styrene Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	96	84	42
Petrochemicals [Member] | Synthetic Rubber Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	106	99	49
Petrochemicals [Member] | Polystyrene Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	141	119	71
Holding And Others [Member]
IfrsStatementLineItems [Line Items]
Revenue	20	22	20
Holding And Others [Member] | Technical Assistance And Administration Services Sales [Member]
IfrsStatementLineItems [Line Items]
Revenue	20	22	20
Holding And Others [Member] | Other [Member]
IfrsStatementLineItems [Line Items]
Revenue

XML

COST OF SALES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Cost Of Sales
Inventories at the beginning of the year	$ 155	[1]	$ 116	$ 153
Plus: Charges of the year
Purchases of inventories, energy and gas	502		433	153
Salaries and social security charges	79		59	51
Employees benefits	15		13	11
Accrual of defined benefit plans	5		4	4
Works contracts, fees and compensation for services	87		68	55
Property, plant and equipment depreciation	202		194	194
Intangible assets amortization	1		1	5
Right-of-use assets amortization	3		5	1
Energy transportation	8		6	5
Transportation and freights	35		22	20
Consumption of materials	30		26	17
Penalties	1		2
Maintenance	61		52	26
Canons and royalties	89		65	42
Environmental control	5		4	4
Rental and insurance	31		27	23
Surveillance and security	4		3	2
Taxes, rates and contributions	5		4	3
Other	3		6	2
Total charges of the year	1,166		994	618
Exchange differences on translation				8
Less: Inventories at the end of the year	(173)		(155)	(116)
Total cost of sales	$ 1,148		$ 955	$ 663

[1] It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Total selling expenses	$ 56	$ 33	$ 26
Salaries And Social Security Charges [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	5	3	3
Benefits To Employees [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	1
Compensation Agreements [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses			1
Fees And Compensation For Services [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	4	3	3
Taxes Rates And Contributions [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	14	11	8
Transport [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	31	14	9
Other [Member]
IfrsStatementLineItems [Line Items]
Total selling expenses	$ 1	$ 2	$ 2

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Total administrative expenses	$ 138	$ 99	$ 93
Salaries And Social Security Charges [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	50	34	34
Benefits To The Personnel [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	8	5	4
Accrual Of Defined Benefit Plans [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	9	7	7
Fees And Compensation For Services [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	30	32	26
Compensation Agreements [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	19	2
Directors And Syndicates Fees [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	7	6	7
Property Plant And Equipment Depreciations [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	6	5	5
Maintenance One [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	2	2	1
Transport And Per Diem [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	2	1	1
Rental And Insurance [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	1	1	1
Surveillance And Security [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	1		1
Taxes Rates And Contributions [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	2	2	2
Communications [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses	1	1	1
Other [Member]
IfrsStatementLineItems [Line Items]
Total administrative expenses		$ 1	$ 3

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Total other operating income		$ 131	$ 105	$ 51
Total other operating expenses		(46)	(58)	(36)
Contractual Penalty [Member]
IfrsStatementLineItems [Line Items]
Total other operating income				7
Commercial Interests [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		27	27	30
Compensation For Arbitration Award [Member]
IfrsStatementLineItems [Line Items]
Total other operating income
Provision For Contingencies [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(4)	(16)	(7)
Provision For Environmental Remediation [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses			(15)
Decrease In Property Plant And Equipment [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses				(1)
Tax On Bank Transactions [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(14)	(13)	(11)
Donations And Contributions [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(2)	(2)	(3)
Institutional Relationships [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(3)	(3)	(2)
Readjustment Of Investment Plan [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses	[1]	(9)
Royalties Of Argentine Natural Gas Production Promotion Plan [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(8)	(5)
Other [Member]
IfrsStatementLineItems [Line Items]
Total other operating expenses		(6)	(4)	(12)
Insurance Recovery [Member]
IfrsStatementLineItems [Line Items]
Total other operating income			3	3
Services To Third Parties [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		1	2	4
Profit For Property Plant And Equipment Sale [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		2	1	1
Result From The Sale Of Intangible Assets [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		2	2
Dividends Received [Member]
IfrsStatementLineItems [Line Items]
Total other operating income				1
Contingencies Recovery [Member]
IfrsStatementLineItems [Line Items]
Total other operating income			13	2
Tax Charges Recovery [Member]
IfrsStatementLineItems [Line Items]
Total other operating income			2
Surplus Gas Injection Compensation [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		56	51
Compensation For Arbitration Award [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		37
Other [Member]
IfrsStatementLineItems [Line Items]
Total other operating income		$ 6	$ 4	$ 3

[1] Corresponding to the investment plan’s readjustment bond at the Sierra Chata block (see Note 17.2).

XML

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 3) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Total finance income		$ 5	$ 10	$ 9
Total finance cost		(221)	(185)	(177)
Foreign currency exchange difference, net		80	3	14
Result from exchange of corporate bonds		14
Total other financial results		166	(14)	84
Financial results, net		(50)	(189)	(84)
Current tax		99	67	13
Deferred tax		46	10	22
Difference between previous fiscal year income tax provision and the income tax statement		(21)
Total  income tax -  Loss		124	77	35
Profit before income tax		$ 581	$ 390	$ 159
Current tax rate		35.00%	35.00%	30.00%
Income tax at the statutary tax rate		$ 203	$ 138	$ 48
Share of profit from companies		(37)	(40)	(26)
Non-taxable results		(3)	(1)	(5)
Effects of exchange differences and other results associated with the valuation of the currency, net		275	79	88
Effects of valuation of property, plant and equipment, intangible assets and financial assets		(575)	(269)	(156)
Effect of change in tax rate			(6)	19
Effect for tax inflation adjustment		253	169	74
Unrecognized deferred assets			4
Difference between previous fiscal year income tax provision and the income tax statement		2	1	(7)
Non-deductible cost		4	3
Impairment on deferred tax assets		2
Other			(1)
Financial Income [Member]
IfrsStatementLineItems [Line Items]
Financial interest		1		1
Other interest		4	10	8
Finance Costs [Member]
IfrsStatementLineItems [Line Items]
Financial interests	[1]	(172)	(137)	(164)
Commercial interest		(1)
Fiscal interest		(38)	(38)	(3)
Other interests		(5)	(3)	(3)
Bank and other financial expenses		(5)	(7)	(7)
Other Finance Income Cost [Member]
IfrsStatementLineItems [Line Items]
Foreign currency exchange difference, net		80	3	14
Changes in the fair value of financial instruments		110	(15)	30
(Losses) Gains from present value measurement		(14)	(1)	2
Result from exchange of corporate bonds		(14)
Results for the repurchase of corporate bonds		6		38
Other financial results		$ (2)	$ (1)

[1] Net of US$ 11 million and US$ 10 million capitalized in property, plant and equipment for the years ended December 31, 2022 and 2020, respectively. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		$ 3,040	$ 2,792
Increases	[1]	450	253
Increases for incorporation	[2]	295
Transfers
Decreases		(2)	(5)
Impairment		(100)
Property, plant and equipment, ending		3,683
Property, plant and equipment depreciation, beginning		(1,381)	(1,182)
Decreases
Depreciation for the year		(208)	(199)
Impairment		70
Property, plant and equipment depreciation, ending		(1,519)	(1,381)
Net book value		2,164	1,659
Land [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		14
Increases	[1]
Increases for incorporation	[2]
Transfers
Decreases
Impairment
Property, plant and equipment, ending		14
Property, plant and equipment depreciation, beginning
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending
Net book value		14	14
Buildings [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		140
Increases	[1]
Increases for incorporation	[2]	3
Transfers
Decreases
Impairment
Property, plant and equipment, ending		143
Property, plant and equipment depreciation, beginning		(68)
Decreases
Depreciation for the year		(8)
Impairment
Property, plant and equipment depreciation, ending		(76)	(68)
Net book value		67	72
Machinery [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		1,458
Increases	[1]	5
Increases for incorporation	[2]	291
Transfers		163
Decreases		(1)
Impairment
Property, plant and equipment, ending		1,916
Property, plant and equipment depreciation, beginning		(536)
Decreases
Depreciation for the year		(103)
Impairment
Property, plant and equipment depreciation, ending		(639)	(536)
Net book value		1,277	922
Wells [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		867
Increases	[1]	9
Increases for incorporation	[2]
Transfers		145
Decreases		(1)
Impairment		(28)
Property, plant and equipment, ending		992
Property, plant and equipment depreciation, beginning		(532)
Decreases
Depreciation for the year		(77)
Impairment		20
Property, plant and equipment depreciation, ending		(589)	(532)
Net book value		403	335
Mining property [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		253
Increases	[1]
Increases for incorporation	[2]
Transfers
Decreases
Impairment		(72)
Property, plant and equipment, ending		181
Property, plant and equipment depreciation, beginning		(174)
Decreases
Depreciation for the year		(10)
Impairment		50
Property, plant and equipment depreciation, ending		(134)	(174)
Net book value		47	79
Vehicles [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		8
Increases	[1]	2
Increases for incorporation	[2]
Transfers
Decreases
Impairment
Property, plant and equipment, ending		10
Property, plant and equipment depreciation, beginning		(7)
Decreases
Depreciation for the year		(1)
Impairment
Property, plant and equipment depreciation, ending		(8)	(7)
Net book value		2	1
Fixtures and fittings [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		55
Increases	[1]	2
Increases for incorporation	[2]
Transfers		2
Decreases
Impairment
Property, plant and equipment, ending		59
Property, plant and equipment depreciation, beginning		(48)
Decreases
Depreciation for the year		(4)
Impairment
Property, plant and equipment depreciation, ending		(52)	(48)
Net book value		7	7
Communication and network equipment [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		3
Increases	[1]
Increases for incorporation	[2]
Transfers
Decreases
Impairment
Property, plant and equipment, ending		3
Property, plant and equipment depreciation, beginning		(1)
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending		(1)	(1)
Net book value		2	2
Materials And Spare Parts [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		30
Increases	[1]	43
Increases for incorporation	[2]
Transfers		(37)
Decreases
Impairment
Property, plant and equipment, ending		36
Property, plant and equipment depreciation, beginning		(3)
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending		(3)	(3)
Net book value		33	27
Petrochemical Industrial Complex [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		23
Increases	[1]
Increases for incorporation	[2]
Transfers		6
Decreases
Impairment
Property, plant and equipment, ending		29
Property, plant and equipment depreciation, beginning		(12)
Decreases
Depreciation for the year		(5)
Impairment
Property, plant and equipment depreciation, ending		(17)	(12)
Net book value		12	11
Work In Progress [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		135
Increases	[1]	352
Increases for incorporation	[2]
Transfers		(233)
Decreases
Impairment
Property, plant and equipment, ending		254
Property, plant and equipment depreciation, beginning
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending
Net book value		254	135
Advances To Suppliers [Member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		52
Increases	[1]	37
Increases for incorporation	[2]
Transfers		(46)
Decreases
Impairment
Property, plant and equipment, ending		43
Property, plant and equipment depreciation, beginning
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending
Net book value		43	52
Other property, plant and equipment [member]
IfrsStatementLineItems [Line Items]
Property, plant and equipment, ending		2
Increases	[1]
Increases for incorporation	[2]	1
Transfers
Decreases
Impairment
Property, plant and equipment, ending		3
Property, plant and equipment depreciation, beginning
Decreases
Depreciation for the year
Impairment
Property, plant and equipment depreciation, ending
Net book value		$ 3	$ 2

[1] Includes US$ 11 million corresponding to capitalized financial costs in the fiscal year ended December 31, 2022. There are no capitalized financial costs in the fiscal year ended December 31, 2021.

[2] See Notes 5.1.3 and 5.1.5.

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 1) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Intangible assets, beginning		$ 44	$ 62
Increase		31	4
Increases for incorporation	[1]	94
Decrease		(18)	(4)
Impairment	[2]	(6)	(18)
Intangible assets, ending		145	44
Intangible assets amortization, beginning		(6)	(21)
Depreciation for the year		(1)	(1)
Impairment	[2]		16
Intangible assets amortization, ending		(7)	(6)
Intangible assets		138	38
Concession Agreements [Member]
IfrsStatementLineItems [Line Items]
Intangible assets, beginning		2
Increase
Increases for incorporation	[1]
Decrease
Impairment	[2]
Intangible assets, ending		2	2
Intangible assets amortization, beginning		(2)
Depreciation for the year
Impairment	[2]
Intangible assets amortization, ending		(2)
Goodwill [member]
IfrsStatementLineItems [Line Items]
Intangible assets, beginning		35
Increase
Increases for incorporation	[1]
Decrease
Impairment	[2]
Intangible assets, ending		35	35
Intangible assets		35	35
Intangibles Identified In Acquisitions Of Companies [Member]
IfrsStatementLineItems [Line Items]
Intangible assets, beginning		7
Increase
Increases for incorporation	[1]	94
Decrease
Impairment	[2]
Intangible assets, ending		101	7
Intangible assets amortization, beginning		(4)
Depreciation for the year		(1)
Impairment	[2]
Intangible assets amortization, ending		(5)
Intangible assets		96	3
Digital Assets [Member]
IfrsStatementLineItems [Line Items]
Intangible assets, beginning
Increase		31
Increases for incorporation	[1]
Decrease		(18)
Impairment	[2]	(6)
Intangible assets, ending		7
Intangible assets		$ 7

[1] See Notes 5.1.3 and 5.1.5.

[2] As of December 31, 2022, digital assets recoverability was affected by their closing market value, resulted in the recognition of impairment losses for US$ 6 million. Considering the assumptions detailed in Note 11.1, the assessment of recoverability for the Power Generation segment, resulted in the recognition of impairment losses for the Diamante hydroelectric power plant in an amount of US$ 2 million in 2021.

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Increases for incorporation	[1]	$ 295
Deferred tax asset		36		84
Deferred tax liability		(112)
Deferred tax (liability) asset		(76)		84
Property, plant and equipment [member]
IfrsStatementLineItems [Line Items]
Profit (loss)
Increases for incorporation		(79)	[2]	13	[3]
Deferred tax liability, beginning				(13)
Deferred tax liability, ending		(79)
Intangible assets and goodwill [member]
IfrsStatementLineItems [Line Items]
Profit (loss)
Increases for incorporation		(22)	[2]	(2)	[3]
Deferred tax liability, beginning		(13)		(11)
Deferred tax liability, ending		(35)		(13)
Investments In Joint Ventures And Associates [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		3
Increases for incorporation			[2]	14	[3]
Deferred tax liability, beginning		(11)		(25)
Deferred tax liability, ending		(8)		(11)
Inventory [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		(9)
Increases for incorporation			[2]	(4)	[3]
Deferred tax liability, beginning		(10)		(6)
Deferred tax liability, ending		(19)		(10)
Financial Assets At Fair Value Through Profit And Loss Deferred Tax Liabilities [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		(1)
Increases for incorporation			[2]	(10)	[3]
Deferred tax liability, beginning		(14)		(4)
Deferred tax liability, ending		(15)		(14)
Trade And Other Receivables [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		8
Increases for incorporation			[2]	(24)	[3]
Deferred tax liability, beginning		(31)		(7)
Deferred tax liability, ending		(23)		(31)
Taxes Payable [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		1
Increases for incorporation			[2]		[3]
Deferred tax liability, beginning		(3)		(3)
Deferred tax liability, ending		(2)		(3)
Adjustment For Tax Inflation [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		(124)
Increases for incorporation		(13)	[2]	1	[3]
Deferred tax liability, beginning		(1)		(2)
Deferred tax liability, ending		(138)		(1)
Deferred Tax Liabilities [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		(122)
Increases for incorporation		(114)	[2]	(12)	[3]
Deferred tax liability, beginning		(83)		(71)
Deferred tax liability, ending		(319)		(83)
Deferred Tax Asset Liabilities Net [Member]
IfrsStatementLineItems [Line Items]
Profit (loss)		(46)
Increases for incorporation		(114)	[2]	(23)	[3]
Deferred tax asset (liabilities), net		84		107
Deferred tax asset (liabilities), net		(76)		84
Tax Loss Carryforwards [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		13		126
Profit (loss)		6		(113)	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		19		13
Property, plant and equipment [member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		80
Profit (loss)		71		80	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		151		80
Financial Assets At Fair Value Through Profit And Loss Deferred Tax Liabilities [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		3
Profit (loss)		(3)		3	[3]
Increases for incorporation	[2]
Deferred tax asset, ending				3
Trade And Other Receivables [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		5		6
Profit (loss)		(1)		(1)	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		4		5
Provisions [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		57		28
Profit (loss)		2		29	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		59		57
Salaries And Social Security Payable [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning				3
Profit (loss)		1		(3)	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		1
Defined benefit plans [member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		9		5
Profit (loss)		(1)		4	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		8		9
Other [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning
Profit (loss)		1
Increases for incorporation	[2]
Deferred tax asset, ending		1
Deferred Tax Asset [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning		167		178
Profit (loss)		76		(11)	[3]
Increases for incorporation	[2]
Deferred tax asset, ending		243		167
Deferred tax asset, ending				167
Intangible assets and goodwill [member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning				3
Profit (loss)	[3]			(3)
Deferred tax asset, ending
Trade And Other Payables [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning				3
Profit (loss)	[3]			(3)
Deferred tax asset, ending
Adjustment For Tax Inflation [Member]
IfrsStatementLineItems [Line Items]
Deferred tax asset, beginning				4
Profit (loss)	[3]			(4)
Deferred tax asset, ending

[1] See Notes 5.1.3 and 5.1.5.

[2] See Notes 5.1.3 and 5.1.5.

[3] Includes US$ 13 million corresponding to discontinued operations.

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 3) - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
IfrsStatementLineItems [Line Items]
Inventories	$ 173	[1]	$ 155	[1]	$ 116	$ 153
Materials And Spare Parts [Member]
IfrsStatementLineItems [Line Items]
Inventories	104		87
Advances To Suppliers [Member]
IfrsStatementLineItems [Line Items]
Inventories	8		8
In Process And Finished Products [Member]
IfrsStatementLineItems [Line Items]
Inventories	$ 61		$ 60

[1] It includes impairment loss as a result of the performed recoverability assessment for US$ 2 million as of December 31, 2022 and 2021, acoording with the policy described in Note 4.13.

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 4) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Provisions, non current	$ 147	$ 141
Provisions, current	4	5
Provisions For Contingencies [Member]
IfrsStatementLineItems [Line Items]
Provisions, non current	107	106
Asset Retirement Obligation [Member]
IfrsStatementLineItems [Line Items]
Provisions, non current	25	19
Provisions, current	2	2
Environmental Remediations [Member]
IfrsStatementLineItems [Line Items]
Provisions, non current	15	15
Provisions, current	2	3
Other provisions [member]
IfrsStatementLineItems [Line Items]
Provisions, non current		$ 1

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Increases for incorporation	[1]	$ 295
Provisions For Contingencies [Member]
IfrsStatementLineItems [Line Items]
Provisions, beginning		106	103		$ 139
Increases		5	16		21
Increases for incorporation	[2]
Decreases		(1)			(1)
Gain on monetary position net		(2)			(15)
Reversal of unused amounts		(1)	(13)	[3]	(8)
Provisions, ending		107	106		103
Reclasification liabilities associated to assets classified as held for sale					(33)
Asset Retirement Obligation [Member]
IfrsStatementLineItems [Line Items]
Provisions, beginning		21	21		22
Increases		6	3		2
Increases for incorporation	[2]	1
Decreases			(1)
Gain on monetary position net
Reversal of unused amounts		(1)	(2)	[3]	(3)
Provisions, ending		27	21		21
Reclasification liabilities associated to assets classified as held for sale
Environmental Remediations [Member]
IfrsStatementLineItems [Line Items]
Provisions, beginning		18	3		3
Increases			15
Increases for incorporation	[2]
Decreases		(1)
Gain on monetary position net
Reversal of unused amounts				[3]
Provisions, ending		$ 17	$ 18		3
Reclasification liabilities associated to assets classified as held for sale

[1] See Notes 5.1.3 and 5.1.5.

[2] See Note 5.1.3.

[3] Includes recovery of US$ 12.5 million related to waive the timely granted dispatch of Las Armas Wind Farm (see Note 2.1.2.3).

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 6) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current income tax and minimum notional income tax provision	$ 179	$ 188
Current income tax and minimum notional income tax provision	5	20
Income Tax Net Of Witholdings And Advances [Member]
IfrsStatementLineItems [Line Items]
Non current income tax and minimum notional income tax provision	161	158
Current income tax and minimum notional income tax provision	5	20
Minimum National Income Tax [Member]
IfrsStatementLineItems [Line Items]
Non current income tax and minimum notional income tax provision	$ 18	$ 30

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 7) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Taxes payables, current	$ 28	$ 23
Value Added Tax [Member]
IfrsStatementLineItems [Line Items]
Taxes payables, current	5	4
Personal Assets Tax Provision [Member]
IfrsStatementLineItems [Line Items]
Taxes payables, current	4	2
Tax Withholdings To Be Deposited [Member]
IfrsStatementLineItems [Line Items]
Taxes payables, current	5	6
Royalties [Member]
IfrsStatementLineItems [Line Items]
Taxes payables, current	12	9
Others One [Member]
IfrsStatementLineItems [Line Items]
Taxes payables, current	$ 2	$ 2

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 8) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Present Value Of The Obligation [Member]
IfrsStatementLineItems [Line Items]
Liabilities, beginning	$ 33	$ 25	$ 36
Current services cost	1	1	3
Cost for interest	15	13	16
Actuarial (gains) losses	9	1	(3)
Benefit payments	(3)	(2)	(2)
Gain on monetary position, net	(17)	(5)	(15)
Liabilities, ending	38	33	25
Reclassification to liabilities associated to assets classified as held for sale			(10)
Fair Value Of Plan Assets [Member]
IfrsStatementLineItems [Line Items]
Liabilities, beginning	(4)	(4)	(5)
Current services cost
Cost for interest	(2)	(3)	(2)
Actuarial (gains) losses		2	1
Benefit payments
Gain on monetary position, net	2	1	2
Liabilities, ending	(4)	(4)	(4)
Reclassification to liabilities associated to assets classified as held for sale
Net Liability At The End Of The Year [Member]
IfrsStatementLineItems [Line Items]
Liabilities, beginning	29	21	31
Current services cost	1	1	3
Cost for interest	13	10	14
Actuarial (gains) losses	9	3	(2)
Benefit payments	(3)	(2)	(2)
Gain on monetary position, net	(15)	(4)	(13)
Liabilities, ending	$ 34	$ 29	21
Reclassification to liabilities associated to assets classified as held for sale			$ (10)

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 9) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Not later than one year [member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	$ 6
Later than one year and not later than two years [member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	3
Later than two years and not later than three years [member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	4
Later than three years and not later than four years [member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	4
Later than four years and not later than five years [member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	3
Later Than Six Years And Not Later Than Ten Years [Member]
IfrsStatementLineItems [Line Items]
Estimated expected benefits payment	$ 14

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 10)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Non-financial Assets And Liabilities
Discount rate	5.00%	5.00%	4.00%
Salaries increase	1.00%	1.00%	1.00%
Average inflation	118.00%	54.00%	46.00%

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 11) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Discount Rate Four Percent [Member]
IfrsStatementLineItems [Line Items]
Defined benefit obligation at present value	$ 41
Increase decrease through change in discount rate defined benefit obligation at present value	$ 3
Percentage of variation	9.00%
Discount Rate Six Percent [Member]
IfrsStatementLineItems [Line Items]
Defined benefit obligation at present value	$ 35
Increase decrease through change in discount rate defined benefit obligation at present value	$ (3)
Percentage of variation	(8.00%)
Salaries Increase Zero Percent [Member]
IfrsStatementLineItems [Line Items]
Defined benefit obligation at present value	$ 37
Increase decrease through change in discount rate defined benefit obligation at present value	$ (1)
Percentage of variation	(4.00%)
Salaries Increase Two Percent [Member]
IfrsStatementLineItems [Line Items]
Defined benefit obligation at present value	$ 39
Increase decrease through change in discount rate defined benefit obligation at present value	$ 1
Percentage of variation	4.00%

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details 12) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Current salaries and social security payable	$ 32	$ 28
Salaries And Social Security Contributions [Member]
IfrsStatementLineItems [Line Items]
Current salaries and social security payable	5	4
Provision For Vacations [Member]
IfrsStatementLineItems [Line Items]
Current salaries and social security payable	8	7
Provision For Gratifications And Annual Bonus For Efficiency [Member]
IfrsStatementLineItems [Line Items]
Current salaries and social security payable	$ 19	$ 17

XML

NON-FINANCIAL ASSETS AND LIABILITIES (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Power generation segment scenarios	The projections used in the calculation of the recoverable amount of the CGUs of the Power Generation segment take into consideration 2 scenarios that weigh: i) the annual price update, ranging between 80% and 100% compared to the annual inflation; ii) the regularization of the financing term granted to CAMMESA in 2022/2023 and iii) a 10.3% WACC rate after taxes.
Pension And Retirement Benefits Plan [Member]
IfrsStatementLineItems [Line Items]
Net Liabilities	$ 17	$ 15	$ 12
Compensatory Plan [Member]
IfrsStatementLineItems [Line Items]
Net Liabilities	17	$ 14	$ 9
Generation Segment [Member]
IfrsStatementLineItems [Line Items]
Recoginition of impairment losses	$ 30

XML

FINANCIAL ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current financial assets at amortized cost	$ 102	$ 105
Current financial assets at amortized cost	8	5
Term Deposits [Member]
IfrsStatementLineItems [Line Items]
Non current financial assets at amortized cost	101	100
Other Non Current [Member]
IfrsStatementLineItems [Line Items]
Non current financial assets at amortized cost	1	5
Other Current [Member]
IfrsStatementLineItems [Line Items]
Current financial assets at amortized cost	$ 8	$ 5

XML

FINANCIAL ASSETS AND LIABILITIES (Details 1) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current financial assets at fair value through profit and loss	$ 27	$ 29
Current financial assets at fair value through profit and loss	586	458
Shares [Member]
IfrsStatementLineItems [Line Items]
Non current financial assets at fair value through profit and loss	27	29
Current financial assets at fair value through profit and loss	160	120
Government Securities [Member]
IfrsStatementLineItems [Line Items]
Current financial assets at fair value through profit and loss	279	278
Corporate Bonds [Member]
IfrsStatementLineItems [Line Items]
Current financial assets at fair value through profit and loss	116	19
Investment funds [member]
IfrsStatementLineItems [Line Items]
Current financial assets at fair value through profit and loss	$ 31	$ 41

XML

FINANCIAL ASSETS AND LIABILITIES (Details 2) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current other receivables	$ 17	$ 23
Non-current trade receivables	20	34
Current trade receivables	305	256
Current other receivables	165	141
Current trade and other receivables	470	397
Related parties [member]
IfrsStatementLineItems [Line Items]
Non current other receivables	17	23
Current trade receivables	5	7
Current other receivables	7	8
Tax Credits [Member]
IfrsStatementLineItems [Line Items]
Non current other receivables	2	9
Prepaid Expenses [Member]
IfrsStatementLineItems [Line Items]
Non current other receivables		1
Current other receivables	14	10
Other One [Member]
IfrsStatementLineItems [Line Items]
Non current other receivables	1	1
Current trade receivables	3	5
Current other receivables	7	14
Other Receivables Net [Member]
IfrsStatementLineItems [Line Items]
Non current other receivables	20	34
Receivables From M A T [Member]
IfrsStatementLineItems [Line Items]
Current trade receivables	21	24
C A M M E S A [Member]
IfrsStatementLineItems [Line Items]
Current trade receivables	165	89
Receivables From Oil And Gas Sales [Member]
IfrsStatementLineItems [Line Items]
Current trade receivables	55	69
Receivables From Petrochemistry [Member]
IfrsStatementLineItems [Line Items]
Current trade receivables	62	71
Impairment Of Trade Receivables [Member]
IfrsStatementLineItems [Line Items]
Current trade receivables	(6)	(9)
Tax Credit [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	14	5
Receivables For Complementary Activities [Member]
IfrsStatementLineItems [Line Items]
Current other receivables		2
Financial Credit [Member]
IfrsStatementLineItems [Line Items]
Current other receivables		10
Guarantee Deposits [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	27	30
Insurance To Recover [Member]
IfrsStatementLineItems [Line Items]
Current other receivables		1
Expenses To Be Recovered [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	15
Acquisition Of Subsidiary [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	7
Credits For The Sale Of Subsidiary [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	4	41
Credit For Sale Of Financial Instruments [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	1	6
Argentine Natural Gas Production Promotion Plan [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	32	14
Arbitration Award [Member]
IfrsStatementLineItems [Line Items]
Current other receivables	$ 37

XML

FINANCIAL ASSETS AND LIABILITIES (Details 3) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financial Assets And Liabilities
At the beginning of the year		$ 9	$ 16	$ 68
Impairment (1)	[1]	1	1	63
Utilizations		(1)		(7)
Reversal of unused amounts			(6)	(3)
Increase (decrease) through net exchange differences, allowance account for credit losses of financial assets		(3)	(2)	(2)
Gain on monetary position, net				(28)
Reclasification to assets clasified as held for sales				(75)
At the end of the year		$ 6	$ 9	$ 16

[1] It includes US$ 26 million corresponding to discontinued operations for fiscal year 2020. As of December 31, 2020, it includes US$ 13 million corresponding to the receivable impairment related to the exchange difference between the price of gas purchased by distributors and the price of gas recognised in distributors´s final tariffs between April 2018 and March 2019 to be assumed by the Federal Government in accordance to PEN Executive Order No. 1,053/18 (see Note 15).

XML

FINANCIAL ASSETS AND LIABILITIES (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financial Assets And Liabilities
At the beginning			$ 6
Impairment (1)			2
Reversal of unused amounts			(7)
Reclasification to assets clasified as held for sales			(1)
At the end of the year

XML

FINANCIAL ASSETS AND LIABILITIES (Details 5) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
IfrsStatementLineItems [Line Items]
Cash and cash equivalents	$ 106	$ 110	$ 141	$ 225
Banks [Member]
IfrsStatementLineItems [Line Items]
Cash and cash equivalents	11	26
Mutual Funds [Member]
IfrsStatementLineItems [Line Items]
Cash and cash equivalents	$ 95	$ 84

XML

FINANCIAL ASSETS AND LIABILITIES (Details 6) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current borrowings	$ 1,340	$ 1,359
Current borrowings	273	79
Borrowing	1,613	1,438
Financial Borrowings [Member]
IfrsStatementLineItems [Line Items]
Non current borrowings	108	58
Current borrowings	51	29
Corporate Bonds [Member]
IfrsStatementLineItems [Line Items]
Non current borrowings	1,232	1,301
Current borrowings	163	39
Bank Overdraft [Member]
IfrsStatementLineItems [Line Items]
Current borrowings	$ 59	$ 11

XML

FINANCIAL ASSETS AND LIABILITIES (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financial Assets And Liabilities
At the beginning of the year	$ 1,438	$ 1,614	$ 1,947
Proceeds from borrowings	308	188	353
Payment of borrowings	(143)	(336)	(300)
Accrued interest	172	137	176
Payment of interests	(162)	(140)	(201)
Repurchase and redemption of corporate bonds	(28)	(3)	(155)
Result from exchange of corporate bonds	14
Result from repurchase of corporate bonds	(6)		(43)
Increases for incorporation (1)	89
Cancellation through dividend compensation			(12)
Gain on monetary position, net			(43)
Foreign currency exchange difference, net	(80)	(22)	(18)
Borrowing costs capitalized in property, plant and equipment	11		10
Reclassified to liabilities associated to assets classified as held for sale			(100)
At the end of the year	$ 1,613	$ 1,438	$ 1,614

XML

FINANCIAL ASSETS AND LIABILITIES (Details 8) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Book Value		$ 1,395	[1]	$ 1,340
Book Value		101	[2]	23
Book Value		58	[3]	64
Book Value		59		11
Book Value		$ 1,613		$ 1,438		$ 1,614
T Series C B [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[1]	PAMPA	[4]
Currency		US$	[1]	US$	[4]
Residual value		$ 93	[1]	$ 389	[4]
Interest		Fixed	[1]	Fixed	[4]
Rate		7.38%	[1]	7.38%	[4]
Expiration		Jul-23	[1]	Jul-23	[4]
Book Value		$ 95	[1]	$ 400	[4]
Class 8 C B [Member]
IfrsStatementLineItems [Line Items]
Company name	[1]	PAMPA
Currency	[1]	$
Residual value	[1]	$ 18
Interest	[1]	Variable
Rate	[1]	Badlar + 2%
Expiration	[1]	Jul-23
Book Value	[1]	$ 20
Class 11 C B [Member]
IfrsStatementLineItems [Line Items]
Company name	[1]	PAMPA
Currency	[1]	$
Residual value	[1]	$ 122
Interest	[1]	Variable
Rate	[1]	Badlar + 0%
Expiration	[1]	Jan-24
Book Value	[1]	$ 140
Class 9 C B [Member]
IfrsStatementLineItems [Line Items]
Company name	[1]	PAMPA
Currency	[1]	US$
Residual value	[1]	$ 102
Interest	[1]	Fixed
Rate	[1]	9.50%
Expiration	[1]	Dec-26
Book Value	[1]	$ 184
Class 1 C B [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[1]	PAMPA	[4]
Currency		US$	[1]	US$	[4]
Residual value		$ 501	[1]	$ 636	[4]
Interest		Fixed	[1]	Fixed	[4]
Rate		7.50%	[1]	7.50%	[4]
Expiration		Jan-27	[1]	Jan-27	[4]
Book Value		$ 616	[1]	$ 648	[4]
Class 13 C B [Member]
IfrsStatementLineItems [Line Items]
Company name	[1]	PAMPA
Currency	[1]	US$
Residual value	[1]	$ 49
Interest	[1]	Fixed
Rate	[1]	0.00%
Expiration	[1]	Dec-27
Book Value	[1]	$ 48
Serie 3 C B [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[1]	PAMPA	[4]
Currency		US$	[1]	US$	[4]
Residual value		$ 285	[1]	$ 293	[4]
Interest		Fixed	[1]	Fixed	[4]
Rate		9.13%	[1]	9.13%	[4]
Expiration		Apr-29	[1]	Apr-29	[4]
Book Value		$ 292	[1]	$ 292	[4]
Financial Loans One [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[2]	PAMPA	[5]
Currency		US$	[2]	US$	[5]
Residual value		$ 15	[2]	$ 23	[5]
Interest		Variable	[2]	Variable	[5]
Rate		Libor + 4.21%	[2]	Libor + 4.21%	[5]
Expiration		Nov-24	[2]	May-24	[5]
Book Value		$ 16	[2]	$ 23	[5]
Financial Loans Two [Member]
IfrsStatementLineItems [Line Items]
Company name	[2]	GW
Currency	[2]	US$
Residual value	[2]	$ 83
Interest	[2]	Variable
Rate	[2]	Libor + 5.75%
Expiration	[2]	Sep-26
Book Value	[2]	$ 85
Otherfinancialoperations [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[3]	PAMPA	[6]
Currency		US$	[3]	US$	[6]
Residual value		$ 22	[3]	$ 22	[6]
Interest		Variable	[3]	Variable	[6]
Rate		SOFR + 0.35%	[3]	Libor + 0.35%	[6]
Expiration		Jul-23	[3]	Jul-22	[6]
Book Value		$ 23	[3]	$ 22	[6]
Otherfinancialoperations One [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[3]	PAMPA	[6]
Currency		US$	[3]	US$	[6]
Residual value		$ 8	[3]	$ 43	[6]
Interest		Fixed	[3]	Variable	[6]
Rate		Between 9.50% and 14.50%	[3]	Libor + 0%	[6]
Expiration		Between Jan-23 and May-23	[3]	Aug-23	[6]
Book Value		$ 8	[3]	$ 42	[6]
Otherfinancialoperations Two [Member]
IfrsStatementLineItems [Line Items]
Company name	[3]	PAMPA
Currency	[3]	US$
Residual value	[3]	$ 27
Interest	[3]	Variable
Rate	[3]	SOFR + 0%
Expiration	[3]	Agu-24
Book Value	[3]	$ 27
Bank Overdraft [Member]
IfrsStatementLineItems [Line Items]
Company name		PAMPA	[3]	PAMPA
Currency		$	[3]	$
Residual value		$ 57	[3]	$ 11
Interest		Fixed	[3]	Fixed
Rate		Between 54% and 54.50%	[3]	33.00%
Expiration		Jan-23	[3]	Jan-22
Book Value		$ 59	[3]	$ 11

[1] Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

[2] During the the fiscal year ended December 31, 2022, the Company took on new short-term financing with domestic financial entities, net of cancellations, for a total $ 8,618 million and import prefinancing for US$ 7.6 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million and US$ 10.4 million corresponding to the credit facility subscribed between IDB Invest and Greenwind, a Company that is consolidated since acquisition of an additional 50% interest in August 2022.

[3] During the fiscal year ended December 31, 2022, the Company received disbursements in the amount of US$ 1.3 million under the credit facilities taken out with BNP Paribas S.A. in 2020. After the fiscal year closing, the Company repaid short-term bank loans with local financial entities for $ 10,065 million and import prefinancing for US$ 0.7 million.

[4] Net of the following face value repurchases: US$ 110,4 million of ON 2023, US$ 114,0 million of ON 2027 and US$ 7,5 million of ON 2029.

[5] During the fiscal year ended December 31, 2021, the Company canceled short-term financing with local financial entities, net of borrowings, for $ 8,158 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million.

[6] During the fiscal year ended December 31, 2021, the Company received disbursements in the amount of US$ 27 million under the credit facilities taken out with BNP in 2020.

XML

FINANCIAL ASSETS AND LIABILITIES (Details 9) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Non current other payables	$ 21,000,000	$ 12,000,000
Current trade payables	14,000,000	15,000,000
Trade payables	215,000,000	173,000,000
Total trade and other payables	281,000,000	182,000,000
Compensation Agreements [Member]
IfrsStatementLineItems [Line Items]
Non current other payables	10,000,000	3,000,000
Current other payables	12,000,000	2,000,000
Lease Liability [Member]
IfrsStatementLineItems [Line Items]
Non current other payables	10,000,000	9,000,000
Current other payables	2,000,000	4,000,000
Others [Member]
IfrsStatementLineItems [Line Items]
Non current other payables	1,000,000
Current other payables	6,000,000	3,000,000
Other Payables [Member]
IfrsStatementLineItems [Line Items]
Non current other payables	21,000,000	12,000,000
Current other payables	66,000,000	9,000,000
Suppliers [Member]
IfrsStatementLineItems [Line Items]
Current trade payables	198,000,000	154,000,000
Customer Advances [Member]
IfrsStatementLineItems [Line Items]
Current trade payables	3,000,000	4,000,000
Related parties [member]
IfrsStatementLineItems [Line Items]
Current trade payables	14,000,000	15,000,000
Liability For Acquisition Of Companies [Member]
IfrsStatementLineItems [Line Items]
Current other payables	$ 46,000,000

XML

FINANCIAL ASSETS AND LIABILITIES (Details 10) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost	$ 558,000,000	$ 512,000,000
Financial assets at fair value through profit and loss	730,000,000	601,000,000
Subtotal financial assets	1,288,000,000	1,113,000,000
Non financial assets	31,000,000	25,000,000
Total assets	1,319,000,000	1,138,000,000
Financial liabilities at amortized cost	1,911,000,000	1,628,000,000
Financial liabilities at fair value through profit and loss	2,000,000
Subtotal financial liabilities	1,913,000,000	1,628,000,000
Non financial liabilities	4,000,000	4,000,000
Total liabilities	1,917,000,000	1,632,000,000
Trade And Other Liabilities [Member]
IfrsStatementLineItems [Line Items]
Financial liabilities at amortized cost	298,000,000	190,000,000
Financial liabilities at fair value through profit and loss
Subtotal financial liabilities	298,000,000	190,000,000
Non financial liabilities	4,000,000	4,000,000
Total liabilities	302,000,000	194,000,000
Borrowing [Member]
IfrsStatementLineItems [Line Items]
Financial liabilities at amortized cost	1,613,000,000	1,438,000,000
Financial liabilities at fair value through profit and loss
Subtotal financial liabilities	1,613,000,000	1,438,000,000
Non financial liabilities
Total liabilities	1,613,000,000	1,438,000,000
Derivative Financial Instruments [Member]
IfrsStatementLineItems [Line Items]
Financial liabilities at amortized cost
Financial liabilities at fair value through profit and loss	2,000,000
Subtotal financial liabilities	2,000,000
Non financial liabilities
Total liabilities	2,000,000
Trade Receivables And Other Receivables [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost	437,000,000	376,000,000
Financial assets at fair value through profit and loss	22,000,000	30,000,000
Subtotal financial assets	459,000,000	406,000,000
Non financial assets	31,000,000	25,000,000
Total assets	490,000,000	431,000,000
Financial Assets At Amortized Cost [Member] | Term Deposit [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost	101,000,000	100,000,000
Financial assets at fair value through profit and loss
Subtotal financial assets	101,000,000	100,000,000
Non financial assets
Total assets	101,000,000	100,000,000
Financial Assets At Amortized Cost [Member] | Notes Receivables [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost	9,000,000	10,000,000
Financial assets at fair value through profit and loss
Subtotal financial assets	9,000,000	10,000,000
Non financial assets
Total assets	9,000,000	10,000,000
Financial Assets At Amortized Cost [Member] | Corporate Securities [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost
Financial assets at fair value through profit and loss		19,000,000
Subtotal financial assets		19,000,000
Non financial assets
Total assets		19,000,000
Financial Assets At Fair Value Through Profit And Loss [Member] | Government Securities [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost
Financial assets at fair value through profit and loss	279,000,000	278,000,000
Subtotal financial assets	279,000,000	278,000,000
Non financial assets
Total assets	279,000,000	278,000,000
Financial Assets At Fair Value Through Profit And Loss [Member] | Corporate Bonds [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost
Financial assets at fair value through profit and loss	116,000,000
Subtotal financial assets	116,000,000
Non financial assets
Total assets	116,000,000
Financial Assets At Fair Value Through Profit And Loss [Member] | Shares [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost
Financial assets at fair value through profit and loss	187,000,000	149,000,000
Subtotal financial assets	187,000,000	149,000,000
Non financial assets
Total assets	187,000,000	149,000,000
Financial Assets At Fair Value Through Profit And Loss [Member] | Investment funds [member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost
Financial assets at fair value through profit and loss	31,000,000	41,000,000
Subtotal financial assets	31,000,000	41,000,000
Non financial assets
Total assets	31,000,000	41,000,000
Cash And Cash Equivalent [Member]
IfrsStatementLineItems [Line Items]
Financial assets at amortized cost	11,000,000	26,000,000
Financial assets at fair value through profit and loss	95,000,000	84,000,000
Subtotal financial assets	106,000,000	110,000,000
Non financial assets
Total assets	$ 106,000,000	$ 110,000,000

XML

FINANCIAL ASSETS AND LIABILITIES (Details 11) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Interest income	$ 5	$ 10	$ 9
Interest expense	(216)	(178)	(170)
Foreign currency exchange difference, net	80	3	14
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement	(14)	(1)	2
Other financial results	(15)	(8)	31
Total	(50)	(189)	(84)
Financial Assets Liabilities At Amortized Cost [Member]
IfrsStatementLineItems [Line Items]
Interest income	5	10	9
Interest expense	(175)	(138)	(164)
Foreign currency exchange difference, net	16	(11)	38
Changes in the fair value of financial instruments
Result from present value measurement	(1)	2	6
Other financial results	(15)	(4)	36
Total	(170)	(141)	(75)
Financial Assets Liabilities At Fair Value Through Profit And Loss [Member]
IfrsStatementLineItems [Line Items]
Interest income
Interest expense
Foreign currency exchange difference, net	(85)	(19)	(35)
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement
Other financial results
Total	25	(34)	(5)
Subtotal Financial Assets Liabilities [Member]
IfrsStatementLineItems [Line Items]
Interest income	5	10	9
Interest expense	(175)	(138)	(164)
Foreign currency exchange difference, net	(69)	(30)	3
Changes in the fair value of financial instruments	110	(15)	30
Result from present value measurement	(1)	2	6
Other financial results	(15)	(4)	36
Total	(145)	(175)	(80)
Nonfinancial Assets Liabilities [Member]
IfrsStatementLineItems [Line Items]
Interest income
Interest expense	(41)	(40)	(6)
Foreign currency exchange difference, net	149	33	11
Changes in the fair value of financial instruments
Result from present value measurement	(13)	(3)	(4)
Other financial results		(4)	(5)
Total	$ 95	$ (14)	$ (4)

XML

FINANCIAL ASSETS AND LIABILITIES (Details 12) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Total assets	$ 730	$ 601
Total liabilities	2
Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	703	572
Total liabilities
Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Total liabilities	2
Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	27	29
Total liabilities
Other Receivables [Member]
IfrsStatementLineItems [Line Items]
Total assets	22	30
Other Receivables [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	22	30
Other Receivables [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Other Receivables [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Derivative Financial Instruments [Member]
IfrsStatementLineItems [Line Items]
Total liabilities	2
Derivative Financial Instruments [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total liabilities
Derivative Financial Instruments [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total liabilities	2
Derivative Financial Instruments [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total liabilities	0
Government Securities [Member] | Financial Asset At Fair Value Through Profit And Loss [Member]
IfrsStatementLineItems [Line Items]
Total assets	279	278
Government Securities [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	279	278
Government Securities [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Government Securities [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Corporate Bonds [Member] | Financial Asset At Fair Value Through Profit And Loss [Member]
IfrsStatementLineItems [Line Items]
Total assets	116	19
Corporate Bonds [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	116	19
Corporate Bonds [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Corporate Bonds [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Investment funds [member] | Financial Asset At Fair Value Through Profit And Loss [Member]
IfrsStatementLineItems [Line Items]
Total assets	31	41
Investment funds [member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	31	41
Investment funds [member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Investment funds [member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Investment funds [member] | Cash And Cash Equivalent [Member]
IfrsStatementLineItems [Line Items]
Total assets	95	84
Investment funds [member] | Cash And Cash Equivalent [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	95	84
Investment funds [member] | Cash And Cash Equivalent [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Investment funds [member] | Cash And Cash Equivalent [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Shares [Member] | Financial Asset At Fair Value Through Profit And Loss [Member]
IfrsStatementLineItems [Line Items]
Total assets	187	149
Shares [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 1 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	160	120
Shares [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 2 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets
Shares [Member] | Financial Asset At Fair Value Through Profit And Loss [Member] | Level 3 of fair value hierarchy [member]
IfrsStatementLineItems [Line Items]
Total assets	$ 27	$ 29

XML

FINANCIAL ASSETS AND LIABILITIES (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Financial Assets And Liabilities
Face value of bond	$ 1,435	$ 1,233
Techniques used for level2 and level3 fair value measurements	Shares: it was 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 direct equity interest of 2.84% and 3.19%, and the additional equity interest of 2.18% and 2.46% through HIDISA and HINISA, in TJSM and TMB, respectively, resulting from the Federal Government’s restructuring of assets in the energy sector. This restructuring resulted in TMB’s and TJSM’s share transfer from the Federal Government to IEASA, considering 16.4% and 13.7% discount rate as of December, 31 2022 and 2021, respectively. The key assumptions were prepared based on estimates on the future behavior of certain sensitive variables, including: (i) the dividend distribution policy; (ii) reference prices for energy sold in the spot market; (iii) projections of the availability and dispatch of power plants; (iv) the evolution of structural costs and expenses; (v) macroeconomic variables such as inflation and exchange rates, etc. The Company recognised losses for US$ 1.7 million and earnings for US$ 18 million as a result of changes in the fair value of financial instruments classified as level 3, under the item “Other financial results” of the Consolidated Statement of Comprehensive Income, as of December, 31 2022 and 2021, respectively. Current values may substantially differ from projections, mainly on account of: i) the timeliness and magnitude of the distribution of dividends, ii) the timeliness and magnitude of energy price updates, and/or iii) the evolution of costs. 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.

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EQUITY COMPONENTS (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Equity Components
Earning for continuing operations attributable to equity holders of the Company	$ 456	$ 312	$ 132
Weighted average amount of outstanding shares	1,381	1,405	1,572
Basic and diluted earnings per share from continued operations	$ 0.33	$ 0.22	$ 0.08
Loss for discontinued operations attributable to equity holders of the Company		$ (39)	$ (499)
Basic and diluted loss per share from discontinued operations		$ (0.03)	$ (0.32)
Earning (Loss) attributable to equity holders of the Company	$ 456	$ 273	$ (367)
Basic and diluted earning (loss) per share	$ 0.33	$ 0.19	$ (0.23)

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EQUITY COMPONENTS (Details Narrative)	Dec. 31, 2022 shares
Equity Components
Share capital	1,384
Treasury shares	4

XML

STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement Of Cash Flows Complementary Information Abstract
Income tax	$ 124	$ 77	$ 35
Accrued interest	185	141	132
Depreciations and amortizations	212	205	205
Share of profit of joint ventures and associates	(105)	(117)	(85)
Results for property, plant and equipment sale	(2)	(1)
Result for intangibles assets sale	(2)	(2)
Impairment of property, plant and equipment, intangible assets and inventories	38	4	139
Impairment of financial assets	8	2	9
Result from measurement at present value	14	1	(2)
Changes in the fair value of financial instruments	(94)	24	(19)
Exchange differences, net	(85)	(3)	(14)
Result from exchange of corporate bonds	14
Result from repurchase of corporate bonds	(6)		(38)
Readjustment of investment plan	9
Compensation for arbitration award	(37)
Recovery of tax charges		(2)
Provision for contingecies, net	4	3	2
Provision for environmental remediation		15
Accrual of defined benefit plans	14	11	11
Dividends received			(1)
Compensation agreements	19	2	1
Other	(3)	5	5
Adjustments to reconcile net profit to cash flows from operating activities	$ 307	$ 365	$ 380

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STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement Of Cash Flows Complementary Information Abstract
(Increase) Decrease in trade receivables and other receivables	$ (233)	$ (41)	$ 19
Increase in inventories	(21)	(40)	(6)
Increase in trade payables and other payables	70	43	3
Increase (Decrease) in salaries and social security payable	15	8	(1)
Decrease in defined benefit plans	(3)	(2)	(2)
Increase (Decrease) in tax liabilities	36	(5)	(20)
Decrease in provisions	(1)	(3)	(5)
Income tax paid	(2)	(13)	(5)
Payments from derivative financial instruments, net	(6)	(12)	(5)
Changes in operating assets and liabilities	$ (145)	$ (65)	$ (22)

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STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement Of Cash Flows Complementary Information Abstract
Acquisition of property, plant and equipment through an increase in trade payables	$ (75)	$ (51)	$ (8)
Borrowing costs capitalized in property, plant and equipment	(11)		(10)
Acquisition of subsidiary by delivering financial assets at fair value through profit and loss	(35)
Receivables from sales of companies pending collection		40
Receivables for acquisition of subsidiary	7
Increase in investments in associates through a decrease in other receivables		(20)
Increase in right-of-use assets through an increase in other liabilities	(1)	(7)
Dividends pending collection		2	20
Compensation of loans through dividends assignment			12
Decrease on well abandonment provision, net, through property, plant and equipment	$ (1)	$ (1)	$ (3)

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RELATED PARTIES' TRANSACTIONS (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Trade receivables, current	$ 5,000,000	$ 7,000,000
Other receivables, non current	17,000,000	23,000,000
Other receivables, current	7,000,000	8,000,000
Trade payables, current	14,000,000	15,000,000
Other One [Member]
IfrsStatementLineItems [Line Items]
Trade receivables, current
Other receivables, non current
Other receivables, current	1,000,000
Trade payables, current
T G S [Member]
IfrsStatementLineItems [Line Items]
Trade receivables, current	5,000,000	6,000,000
Other receivables, non current	17,000,000	23,000,000
Other receivables, current	6,000,000	5,000,000
Trade payables, current	7,000,000	3,000,000
S A C D E [Member]
IfrsStatementLineItems [Line Items]
Trade receivables, current
Other receivables, non current
Other receivables, current
Trade payables, current	$ 7,000,000	10,000,000
O C P One [Member]
IfrsStatementLineItems [Line Items]
Trade receivables, current
Other receivables, non current
Other receivables, current		2,000,000
Trade payables, current
Refinor One [Member]
IfrsStatementLineItems [Line Items]
Trade receivables, current		1,000,000
Other receivables, non current
Other receivables, current
Trade payables, current		$ 2,000,000

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RELATED PARTIES' TRANSACTIONS (Details 1) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]	$ 64	$ 57	$ 33
Purchases of goods and services	[2]	(267)	(97)	(35)
Professional fees expense	[3]	(1)	(1)	(1)
Other operating expenses and income	[4]	(2)	(2)	(2)
Finance income	[5]	2	4	4
Dividends received		10	20	35
Payment of dividends				(9)
O C P One [Member]
IfrsStatementLineItems [Line Items]
Finance income	[5]		1	1
Dividends received		10	20	21
Payment of dividends
E M E S A [Member]
IfrsStatementLineItems [Line Items]
Finance income	[5]
Dividends received
Payment of dividends				(9)
C T B [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]	2	2	2
Purchases of goods and services	[2]
Professional fees expense	[3]
Other operating expenses and income	[4]
Greenwind [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]		1	1
Purchases of goods and services	[2]
Professional fees expense	[3]
Other operating expenses and income	[4]
Refinor One [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]	11	9	10
Purchases of goods and services	[2]	(11)	(6)	(5)
Professional fees expense	[3]
Other operating expenses and income	[4]
T G S [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]	51	45	20
Purchases of goods and services	[2]	(53)	(43)	(24)
Professional fees expense	[3]
Other operating expenses and income	[4]
Finance income	[5]	2	3	3
Dividends received
Payment of dividends
Foundation [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]
Purchases of goods and services	[2]
Professional fees expense	[3]
Other operating expenses and income	[4]	(2)	(2)	(2)
S A C D E [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]
Purchases of goods and services	[2]	(203)	(48)	(6)
Professional fees expense	[3]
Other operating expenses and income	[4]
Salaverri Dellatorre Burgio And Wetzler [Member]
IfrsStatementLineItems [Line Items]
Sales of goods and services	[1]
Purchases of goods and services	[2]
Professional fees expense	[3]	(1)	(1)	(1)
Other operating expenses and income	[4]
Citelec [Member]
IfrsStatementLineItems [Line Items]
Finance income	[5]
Dividends received				13
Payment of dividends
Others [Member]
IfrsStatementLineItems [Line Items]
Finance income	[5]
Dividends received				1
Payment of dividends

[1] Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas and refined products.

[2] Correspond to natural gas transportation services, purchases of refined products and other services imputed to cost of sales for US$ 191 million, US$ 50 million and US$ 29 million and infrastructure works contracted to SACDE imputed in property, plant and equipment for US$ 76 million, US$ 47 million and US$ 6 million, of which US$ 38 million, US$ 17 million and US$ 2 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, 2022, 2021 and 2020, respectively.

[3] Disclosed within administrative expenses.

[4] Corresponds mainly to donations.

[5] Corresponds mainly to financial leases and accrued interest on loans granted.

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RELATED PARTIES´ TRANSACTIONS (Details Narrative) - Key Management Remuneration [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
IfrsStatementLineItems [Line Items]
Key management personnel compensation	$ 26	$ 7	$ 7
Directors' and Sindycs' fees	7	6	6
Key management personnel compensation, share-based payment	$ 19	$ 1	$ 1

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INVESTMENT COMMITMENTS (Details Narrative) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Investment Commitments
Generation Estimated investment	$ 128
Oil and Gas investment commitment	$ 180

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LEASES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
IfrsStatementLineItems [Line Items]
Right of use assets, beginning	$ 20	$ 13
Increase	1	7
Decrease	(1)
Right of use assets, ending		20
Right of use assets amortization, beginning	(8)	(3)
For the year	(3)	(5)
Right of use assets amortization, ending	(11)	(8)
Net book values	9	12
Machinery [member]
IfrsStatementLineItems [Line Items]
Right of use assets, beginning	20
Increase	1
Decrease	(1)
Right of use assets, ending	20	20
Right of use assets amortization, beginning	(8)
For the year	(3)
Right of use assets amortization, ending	(11)	(8)
Net book values	$ 9	$ 12

XML

LEASES (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Leases
At the beginning of the year	$ 13	$ 12
Increases	1	6
Result from measurement at present value	2
Reversal of unused amounts	(1)
Payments	(3)	(5)
At the end of the year	$ 12	$ 13

XML

LEASES (Details 2) $ in Millions	Dec. 31, 2022 USD ($)
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	$ 23
Later than three months and not later than one year [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	1
Later than one year and not later than two years [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	1
Later than two years and not later than three years [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	3
Later than three years and not later than four years [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	2
Later than four years and not later than five years [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	2
Later than five years [member]
IfrsStatementLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	$ 14

XML

LEASES (Details 3) $ in Millions	Dec. 31, 2022 USD ($)
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	$ 23
Less Than Three Months [Member]
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	1
Later than three months and not later than one year [member]
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	5
Later than one year and not later than two years [member]
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	5
Later than two years and not later than three years [member]
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	7
Later than three years and not later than four years [member]
IfrsStatementLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	$ 5

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LEASES (Details 4) $ in Millions	Dec. 31, 2022 USD ($)
IfrsStatementLineItems [Line Items]
Future minimum operating leases	$ 3
Later than three months and not later than one year [member]
IfrsStatementLineItems [Line Items]
Future minimum operating leases	1
Later than one year and not later than two years [member]
IfrsStatementLineItems [Line Items]
Future minimum operating leases	1
Later than three months [member]
IfrsStatementLineItems [Line Items]
Future minimum operating leases	$ 1

XML

LEASES (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Leases
Rightofuseassets net book value	$ 6,000	$ 6,000
Monthly consecutive installments	623
Current lease receivable	6,000	5,000
Non-current lease receivable	$ 17,000	$ 23,000

XML

OIL AND GAS RESERVES (Details)	Dec. 31, 2022 Number
Oil And L N G [Member]
IfrsStatementLineItems [Line Items]
Proved developed reserves	7,722	[1]
Proved undeveloped reserves	3,214	[1]
Proved reserves	10,936	[1]
Natural Gas [Member]
IfrsStatementLineItems [Line Items]
Proved developed reserves	17,372	[2]
Proved reserves	28,613	[2]
Natural Gas 1 [Member]
IfrsStatementLineItems [Line Items]
Proved undeveloped reserves	11,241	[2]
Argentina [Member] | Oil And L N G [Member]
IfrsStatementLineItems [Line Items]
Proved developed reserves	7,722	[1]
Proved undeveloped reserves	3,214	[1]
Proved reserves	10,936	[1]
Argentina [Member] | Natural Gas [Member]
IfrsStatementLineItems [Line Items]
Proved developed reserves	17,372	[2]
Proved reserves	28,613	[2]
Argentina [Member] | Natural Gas 1 [Member]
IfrsStatementLineItems [Line Items]
Proved undeveloped reserves	11,241	[2]

[1] In thousands of barrels.

[2] In millions of cubic meters.