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, 2019

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:

1,677,112,043 outstanding shares of common stock, par value Ps.1.00 per share, excluding 70,761,196 treasury shares.

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

x 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 x 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. 

x 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).

x 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	x	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. x

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 Boardx 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 x No

 

TABLE OF CONTENTS
Item 1.	Identity of Directors, Senior Management and Advisers	8
Item 2.	Offer Statistics and Expected Timetable	8
Item 3.	Key Information	8
SELECTED FINANCIAL DATA		8
EXCHANGE RATES		11
RISK FACTORS		12
Item 4.	Information on the Company	55
HISTORY AND DEVELOPMENT OF THE COMPANY		55
OUR BUSINESS		56
Organizational structure		66
Our Generation Business		68
Our Distribution of Energy Business		77
Our Oil and Gas Business		83
Our Petrochemicals Business		98
Our Holding and Other Business		99
Quality, Safety, Environment and Occupational Health		107
Corporate Responsibility		109
Property, Plant and Equipment		110
Insurance		111
Patents and Trademarks		111
THE ARGENTINE ENERGY SECTOR		112
Item 4A.	Unresolved Staff Comments	142
Item 5.	Operating and Financial Review and Prospects	142
Item 6.	Directors, Senior Management and Employees	182
Item 7.	Major Shareholders and Related Party Transactions	195
Item 8.	Financial Information	198
CONSOLIDATED FINANCIAL STATEMENTS		198
LEGAL PROCEEDINGS		198
DIVIDENDS		204
SIGNIFICANT CHANGES		204
Item 9.	The Offer and Listing	204
TRADING HISTORY		204
THE ARGENTINE SECURITIES MARKET		207
Item 10.	Additional Information	211
MEMORANDUM AND ARTICLES OF ASSOCIATION		211
MATERIAL CONTRACTS		218
EXCHANGE CONTROLS		218
TAXATION		219
DOCUMENTS ON DISPLAY		225
Item 11.	Quantitative and Qualitative Disclosures about Market Risk	226
Item 12.	Description of Securities Other than Equity Securities	226
Item 13.	Defaults, Dividend Arrearages and Delinquencies	228
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	228
Item 15.	Controls and Procedures	228

 

Item 16A.	Audit Committee Financial Expert	229
Item 16B.	Code of Ethics	229
Item 16C.	Principal Accountant Fees and Services	229
Item 16D.	Exemptions from the Listing Standards for Audit Committees	230
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	231
Item 16F.	Change in Registrant’s Certifying Accountant	233
Item 16G.	Corporate Governance	233
Item 16H.	Mine Safety Disclosure	238
Item 17.	Financial Statements	239
Item 18.	Financial Statements	239
Item 19.	Exhibits	239

 

PRESENTATION OF INFORMATION

This document comprises the annual report on Form 20-F for the year ended December 31, 2019 of Pampa, that has been approved by resolution of the Board of Directors meeting of Pampa held on April 29, 2020. 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, 2019 and 2018,and the related consolidated statements of comprehensive income, changes in equity and cash flows for each of the years in the three-year period ended December 31, 2019, and the notes thereto (the “Consolidated Financial Statements”). The Consolidated Financial Statements have been audited by Price Waterhouse & Co. S.R.L., an independent registered public accounting firm in Buenos Aires, Argentina, member firm of PricewaterhouseCoopers International Limited network, whose report is included in this annual report.

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, 2020.

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.

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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 changed its functional and presentation currencies from the Peso to the U.S. Dollar commencing on January 1, 2019 following a change in facts and circumstances relevant to its business operations.  Therefore, as from January 1, 2019, the Company records its operations in U.S. Dollars, the new functional currency, and also presents its Consolidated Financial Statements in U.S. Dollars.

The comparative information has been stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29 "Financial reporting in hyperinflationary economies", since the Peso was the Company’s functional currency up to that date.

As from the change in functional currency, the Company has discontinued the preparation and presentation of financial statements in accordance with IAS 29, and has treated the amounts expressed in terms of the measuring unit current as of December 31, 2018 as the basis for the carrying amounts in subsequent financial statements.

The information as of December 31, 2018 and 2017 disclosed for comparative purposes arises from the Consolidated Financial Statements denominated in Pesos stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

The results and financial position of subsidiaries and associates that have a different functional currency have been translated into the group’s presentation currency and the results from the translation process have been recognized in “Other Comprehensive Income (loss)”. For more information, see Note 3 and 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.

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;

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- 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 pending obligations after the RTI;

- the evolution of Edenor’s energy losses and the impact of Edenor’s fines and penalties and uncollectable debt;

- electricity shortages;

- the potential disruption or interruption of Edenor’s service;

- the revocation or amendment of Edenor’s concession by the granting authority;

- 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;

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

- 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 ongoing or future 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 a pandemic or epidemic and any subsequent mandatory regulatory restrictions or containment measures; and

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

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

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GLOSSARY

Glossary of certain terms used in this Annual Report

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

• “ADDUC”: Asociación de Defensa de Derechos de Usuarios y Consumidores;
• “Adjustment Agreement”: Renegotiation of the Concession, an agreement entered into between Edenor and the Argentine Government in February 2006 relating to the adjustment and renegotiation of the terms of Edenor’s concession (Acta Acuerdo sobre la Adecuación del Contrato de Concesión del Servicio Público de Distribución y Comercialización de Energía Eléctrica);
• “ADR”: American Depositary Receipt;
• “ADS” or “ADSs”: American Depositary Shares;
• “AFIP”: Federal Administration of Public Revenue (Administración Federal de Ingresos Públicos);
• “AML in the Capital Market Sector”: Resolution UIF No. 21/2018 and, subsequently amended by Resolutions No. 156/2018, No. 18/2019 and No. 117/2019;
• “ANSES”: National Social Security Agency (Administración Nacional de la Seguridad Social);
• “Anti-Money Laundering Law”: Law No. 25,246, subsequently amended by Laws No. 26,087, 26,119, 26,268, 26,683, 26,733, 26,734 and Decree No. 27/2018;
• “ASC”: Accounting Standards Codification;
• “Authorized Markets”: securities market in Argentina that require authorization from the CNV to operate.
• “Banco Nación”: Banco de la Nación Argentina;
• “BASE”: Buenos Aires Stock Exchange;
• “BCL”: Business Corporation Law;
• “BLL”: Bodega Loma La Lata S.A;
• “Board of Directors”: the board of directors of Pampa Energía S.A.;
• “BONY”: The Bank of New York Mellon;
• “BOPS”: Bi-orientated polystyrene;
• “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.;
• “CAU”: Charge of Access and Use (Cargo de Acceso y Uso);
• “CBs”: Corporate Bonds;
• “CC”: Combined Cycle;
• “CEE”: Emergency Executive Committee (Comité Ejecutivo de Emergencia);
• “CER”: refers to the Coeficiente de Estabilización de Referencia, a benchmark stabilization coefficient that follows the currency value before pesification upon Executive Order No. 214 dated year 2002;
• “CFEE”: Federal Council on Electricity (Consejo Federal de la Energía Eléctrica);
• “CIESA”: Compañía de Inversiones de Energía S.A.;
• “CITELEC”: Compañía Inversora en Transmisión Eléctrica Citelec S.A.;
• “CML”: Capital Markets Law No. 26,831;
• “CMM”: Cost Monitoring Mechanism;
• “CMIEE”: Average Incremental Charge of Surplus Demand (Cargo Medio Incremental de la Demanda Excedente);
• “CNG”: compressed natural gas;
• “CNV”: Comisión Nacional de Valores;
• “Consolidated Financial Statements”: audited consolidated statements of financial position as of December 31, 2019 and 2018, and the related consolidated statements of comprehensive income, changes in equity and cash flows for each of the years in the three-year period ended December 31, 2019, and the notes thereto of Pampa;
• “Corporate Criminal Liability Law”: Corporate Criminal Liability Law No. 27,401;
• “Corod”:Corod Producción S.A.;
• “CPB”: Central Piedra Buena S.A. or “Central Térmica Piedra Buena”;
• “CPD”: Costo Propio de Distribución or Own Distribution Costs;
• “CPI”: Consumers Prices Index;
• “CSJN”:Corte Suprema de Justicia de la Nación;
• “CTB”: CT Barragán S.A. (previusly known as PEA);
• “CTEB”: Central Térmica Ensenada de Barragán;

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• “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;
• “CVP”: Corporación Venezolana de Petróleo S.A;
• DIGO”: Guaranteed Availability Commitments;
• “DisTro”: High-Voltage Electric Power Transmission System and/or Main Distribution Electric Power Transmission System.
• “DOP”: delivery or pay.
• “EASA”: Electricidad Argentina S.A
• “Ecuador TLC”: EcuadorTLC S.A.;
• “Edenor”: Empresa Distribuidora y Comercializadora Norte S.A.;
• “Edesur”: Empresa Distribuidora Sur S.A.;
• “Eg3Red”: Eg3 Red S.A;
• “EMESA”: Empresa Mendocina de Energía Sociedad Anónima;
• “ENARGAS”: Ente Nacional Regulador del Gas or National Gas Regulatory Entity;
• “ENARSA/IEASA”. Integración Energética Argentina S.A. (former Energía Argentina S.A.);
• “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”: a program under SE Resolution 1,281/2006;
• “Exchange Act”:United States Securities Exchange Act of 1934, as amended;
• “FO or GO”: Fuel Oil or Gas Oil;
• “FODER”: Fondo para el Desarrollo de Energía Renovables;
• “FONINVEMEM”: Fund for Investments required to increase the Power Supply in the Electricity Wholesale Market (Fondo Para Inversiones Necesarias que Permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista);
• “Foundation”: Fundación Pampa Energía S.A;
• “FOCEDE”:Fund for Electricity Distribution Expansion and Consolidation Works(Fondo para Obras de Consolidación y Expansión de Distribución Eéectrica);
• “GCA”: Gaffney, Cline & Associates
• “G&P”:Gas y Petróleo de Neuquén S.A.;
• “GDP”: Gross Domestic Product;
• “Greenwind”: Greenwind S.A.;
• “GT” or “TG”: 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;
• “ICSID”: International Centre for Settlement of Investment Disputes;
• “IGJ”: City of Buenos Aires’s Public Registry of Commerce (Inspección General de Justicia);
• “INDEC”: National Statistics and Census Institute (Instituto Nacional de Estadística y Censos);
• “Independent Reserves Engineers Firm”: Gaffney, Cline & Associates;
• “INDISA”: Inversora Diamante S.A.;
• “INNISA”: Inversora Nihuiles S.A.;
• “IPB”: Inversora Piedra Buena S.A.;
• “IPIM”: Wholesale Domestic Price Index (Índice de Precios Internos al por Mayor);
• “J.P. Morgan”: JPMorgan Chase Bank, N.A;
• “LNG”: liquefied natural gas;
• “LPG”: liquefied petroleum gas;
• “LVFVD”: Sales Settlements with Maturity Date to be Defined (Liquidaciones de Ventas sin Fecha de Vencimiento a Definir);
• “MAT”: Term Market (Mercado a Término);
• “MAT ER”: Renewable Energy Term Market

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• “MBTU” refers to million of British Thermal Units (BTU);
• “MDP”: Ministry of Productive Development (former SGE)
• “ME&M”: Ministry of Energy and Mining;
• “MinEn”: Former Ministry of Energy (former ME&M)
• “MMBOE”: million barrels of oil equivalent.
• “MMC”: Cost Monitoring Mechanism (Mecanismo de Monitoreo de Costos);
• “MMm³/d”: million cubic meters of gas per day
• “MULC”: Single Free Exchange Market (Mercado Único y 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;
• “NAL”: new tariff items that must file for non-automatic licenses, under the Resolution N°1/20 of the Secretariat of Industry, Knowledge Economy and Foreign Commercial Management;
• “NGL”: Natural Gas Liquids
• “NYSE”: New York Stock Exchange;
• “OCP”:Oleoducto de Crudos Pesados Ltd.;
• “OED”:Agency in Charge of Dispatch(Organismo Encargado del Despacho);
• “Official Gazette”: Official Gazette of Argentina (Boletín Oficial de la República Argentina);
• “Oldeval”:Oleoductos del Valle S.A.;
• “OPGW”:Optical Ground Wire;
• “PACOSA”:Pampa Comercializadora S.A.;
• “Pampa” or “the Company”: Pampa Energía S.A.;
• “Pampa Cogeneración”: Pampa Cogeneración S.A.;
• “PDVSA”: Petróleos de Venezuela S.A.;
• “PEB”: Pampa Energía Bolivia S.A. (former “PBI” - Petrobras Bolivia Internacional S.A.);
• “PEISA”: Petrobras Energia Internacional S.A.;
• “PELSA”: Petrolera Entre Lomas S.A.;
• “PEMC”: Parque Eólico Mario Cebreiro;
• “PEMF”: Parques Eólicos Fin del Mundo S.A
• “PEN”: National Executive Branch (Poder Ejecutivo Nacional);
• “PEO”: Petrobras Energía Operaciones S.A.
• “PEPASA”: Petrolera Pampa S.A.;
• “PEPE”: Parque Eólico Pampa Energía
• “Pesos” of “Ps.” or “AR$”:Argentine Pesos;
• “Petrobras Argentina”: Petrobras Argentina S.A.;
• “Petrobras”:Petroleo Brasileiro S.A;
• “Petrolera Pampa”: Petrolera Pampa S.A.;
• “PHA”: PHA S.A.U.;
• “PISA”: Pampa Inversiones S.A.;
• “PIST”:Transportation System Entry Point or natural gas price at wellhead (Punto de Ingreso al de Sistema de Transporte);
• “Plasticos de Zarate”: Plásticos de Zárate S.A.;
• “Polisur”: PBB Polisur S.A;
• “PPA” or “PPAs”: relevant wholesale electricty supply agreements or power purchase agreements (Contratos de Abastecimiento Mayorista de Electricidad);
• “PP”: Pampa Participaciones S.A.U.;
• “PP II”: Pampa Participaciones II S.A.;
• “PPP”: public-private participation projects;
• “PPSL”: Petrobras Participaciones S.L.;
• “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.”;
• “PUREE”: Programa de Uso Racional de la Energía Eléctrica;
• “QSELH”: Quality, Safety, Environment and Labor Health;
• “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);
• “Regulatory Framework Law”: Law No. 24,065, which established guidelines for the restructuring and privatization of the electricity sector;
• “Reserves Report”: the year-end reserves report by Gaffney, Cline & Associate;
• “RET”: Temporary Special Regime (Régimen Especial Temporario);

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• “RT”: Technical Resolution (Resolucion Tecnica);
• “RTI”: Tariff Structure Review (Revision Tarifaria Integral);
• “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”: Security and Exchange Commission;
• “Securities Act”: U.S. Securities Act of 1933, as amended;
• “SEDRONAR”: Secretariat of Planning for the Prevention of Drug Addiction and Action against Drug Trafficking (Secretaría de Políticas Integrales sobre Drogas de la Nación Argentina);
• “SEE”: Subsecretariat of Electric Energy, former Secretariat of Electric Energy (Subsecretaría de Energía Eletrica);
• “SGE”: Former Government Secretariat of Energy (former MinEn) (Ex Secretaría de Gobierno de Energía (ex MinEn);
• “SHC”: Undersecretary of Hydrocarbons and Fuels (Subsecretaría de Recursos Hidrocarburíferos (ex Secretaría de Recursos Hidrocarburíferos);
• “SIMI”: “Integral Import Monitoring System” (AFIP) (Sistema Integral de Monitoreo de Importaciones).
• “Social Solidarity and Productive Reactivation Law”: Law No. 27,541;
• “SRRYME”:Secretary of Renewable Resources and Electricity Market (Secretaría de Recursos Renovables y Mercado Eléctrico);
• “SSERyEE”: Undersecretary of Renewable Energy and Energy Efficiency (Subsecretaria de Energías Renovables y Eficiencia Energética de la Nación);
• “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.;
• “Transelec”: Transelec Argentina S.A.;
• “Transener”: Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.;
• “Transfer Agreement”: Agreement on the Implementation of the Transfer of Jurisdiction between the City of Buenos Aires and the Province of Buenos Aires entered into by and among the Federal Government, the City of Buenos Aires and the Province of Buenos Aires, dated May 9, 2019;
• “TV”: Vapor Turbine (Turbina a Vapor);
• “UIF”: Financial Information Unit (Unidad de Información Financiera);
• “UNIREN”: Public Utility Contract Renegotiation and Analysis Unit (Unidad de Renegociación de Contratos de Servicios Públicos);
• “U.S.”: United Stated of America;
• “US$ and/ or U.S. Dollars”: U.S. currency;
• “UTEs”: joint operations (Unión Transitoria);
• “VAD”: Distribution Added Value (Valor Agregado de Distribución);
• “VAT”: Value Added Tax;
• “WEM”: Wholesale Electricity Market;
• “WEM Large Users”: WEM users with a capacity higher than 300 KW;
• “Wheeling System Users”: certain of Edenor’s large users that are eligible to purchase their energy needs directly from generators in the WEM and only acquire from Edenor the service of electricity delivery.
• “Wheeling Charges”: Edenor’s tariffs for wheeling system users; and
• “YPF”: YPF S.A.

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Item 1.  Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

SELECTED FINANCIAL DATA

The following table presents our selected financial data as of and for each of the years in the four-year period ended December 31, 2019. The selected consolidated statement of comprehensive income and the selected consolidated statement of cash flow data for the years ended December 31, 2019, 2018 and 2017 and the selected consolidated statement of financial position as of December 31, 2019 and 2018, have been prepared in accordance with IFRS as issued by the IASB and have been derived from our Consolidated Financial Statements included elsewhere in this annual report. The selected consolidated statement of comprehensive income and the selected consolidated statement of cash flow data for the year ended December 31, 2016 prepared in accordance with IFRS have derived from our audited consolidated financial statements for each of the years in the three-year period ended December 31, 2018 that are not included in this annual report, which were audited by Price Waterhouse & Co. S.R.L. The summary financial data as of and for the year ended December 31, 2015 have not been presented as these cannot be provided on a restated basis without unreasonable effort or expense.

Comparative information in our Consolidated Financial Statements and the comparative financial information included elsewhere in this Annual Report arises from figures denominated in Pesos stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29 and was translated into U.S. Dollars using the exchange rate as of that date. See “Presentation of Information—Financial Information” “Presentation of Information—Functional and Presentation Currency”, “Item 5—Operating and Financial Review and Prospects—Results of Operations” and Note 3 and Note 4.3 to the Consolidated Financial Statements.

The Company changed its functional and presentation currencies from the Peso to the U.S. Dollar commencing on January 1, 2019. You should read the information below in conjunction with our Consolidated Financial Statements, including the notes thereto, as well as the sections “Presentation of Financial Information” and “Item 5. Operating and Financial Review and Prospects.”

	As of December 31,
	2019	2018	2017	2016
	(in million of US$) (1)
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
Non-current assets:
Property, plant and equipment	3,507	3,316	2,959	3,129
Intangible assets	151	161	169	174
Right-of-use assets	16	-	-	-
Deferred tax assets	28	2	51	60
Investments in joint ventures and associates	511	407	315	255
Financial assets at amortized cost	18	-	-	3
Financial assets at fair value through profit and loss	11	11	8	36
Other assets	1	1	-	1
Trade and other receivables	79	253	197	218
Total non-current assets	4,322	4,151	3,699	3,876
Current assets:
Inventories	153	137	113	164
Financial assets at amortized cost	54	35	1	1
Financial assets at fair value through profit and loss	365	405	572	205
Derivative financial instruments	4	-	-	1
Trade and other receivables	561	703	751	691
Cash and cash equivalents	225	241	31	69
Total current assets	1,362	1,521	1,468	1,131
Non current assets classified as held for sale	-	-	490	1

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Total assets	5,684	5,672	5,657	5,008
Shareholders´ equity
Share capital	46	50	55	51
Share capital adjustment	260	260	289	287
Share Premium	510	491	491	422
Treasury shares	1	-	-	-
Treasury shares cost	(44)	(39)	(3)	-
Treasury shares adjustment	1	4	-	-
Legal reserve	42	24	19	15
Voluntary reserve	422	195	333	250
Other reserves	(18)	(13)	10	9
Retained earnings	726	403	313	114
Other comprehensive income	(29)	(9)	(9)	(4)
Equity attributable to owners of the company	1,917	1,366	1,498	1,144
Non-controlling interest	492	429	472	465
Total equity	2,409	1,795	1,970	1,609
Non-current liabilities:
Investments in joint ventures  and associates	4	4	-	-
Provisions	145	146	174	218
Income tax and minimum notional income tax provision	10	27	34	46
Deferred revenue	5	7	8	10
Taxes payables	4	14	14	15
Deferred tax liabilities	368	407	443	585
Defined benefit plans	27	31	39	45
Salaries and social security payable	4	4	5	5
Borrowings	1,764	1,835	1,454	747
Trade and other payables	90	220	250	260
Total non-current liabilities	2,421	2,695	2,421	1,931
Current liabilities:
Provisions	20	23	31	39
Deferred revenue	-	-	-	-
Income tax and minimum notional income tax provision	53	29	37	71
Taxes payables	72	54	77	117
Defined benefit plans	4	4	5	5
Salaries and social security payable	65	72	84	85
Derivative financial instruments	3	1	3	-
Borrowings	183	342	229	522
Trade and other payables	454	657	707	629
Total current liabilities	854	1,182	1,173	1,468
Liabilities associated to assets classified as held for sale	-	-	93	-
Total liabilities	3,275	3,877	3,687	3,399
Total liabilities and equity	5,684	5,672	5,657	5,008
Number of outstanding shares (in millions) (2)	1,677	1,874	2,080	1,938

⁽¹⁾ Peso amounts as of December 31, 2018, 2017 and 2016 have been translated into US$ at the seller exchange rate for US$ quoted by Banco Nación on December 31, 2018 of Ps.37.70 to US$1.00. See “Item 3. Key Information—Exchange Rates.”

⁽²⁾ As of December 31, 2019, 2018 and 2017 we held 71 million, 25 million and 2.5 million treasury shares, respectively.

	For the year ended December 31,
	2019	2018	2017	2016(3)
	(in millions of US$) (1)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Revenue	2,836	2,920	2,175	1,360
Cost of sales	(2,032)	(1,967)	(1,574)	(1,137)
Gross profit	804	953	601	223
Selling expenses	(148)	(171)	(127)	(119)
Administrative expenses	(174)	(206)	(198)	(199)
Exploration expenses	(9)	(1)	(2)	(5)
Other operating income	40	181	149	222
Other operating expenses	(86)	(200)	(103)	(103)
Impairment of property, plant and equipment	(62)	(32)	-	-
Share of profit from joint ventures and associates	101	118	48	8

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Operating income	751	670	368	54
Gain on net monetary position	187	629	304	153
Financial income	96	99	62	46
Financial costs	(299)	(316)	(232)	(216)
Other financial results	113	(858)	(100)	13
Financial results, net	97	(446)	34	(4)
Profit before income tax	848	224	402	50
Income tax and minimun notional income tax	(48)	(17)	26	42
Profit of the year from continuing operations	800	207	428	92
Profit (Loss) of the year from discontinued operations	-	80	(50)	4
Total Profit of the year	800	287	378	96
Items that will not be reclassified to profit of loss:
Remeasurements related to defined benefit plans	2	(4)	-	(1)
Income tax	-	1	-	-
Share of loss from joint ventures	-	(1)	-	-
Exchange differences on translation	(15)	-	-	-
Items that may be reclassified to profit of loss:
Exchange differences on translation	(22)	1	3	-
Other Comprehensive income of the year from continuing operations, net of tax	(35)	(3)	3	(1)
Other comprehensive income of the year from discontinued operations	-	8	(14)	4
Total Other Comprehensive (loss) income of the year	(35)	5	(11)	3
Total Comprehensive income of the year	765	292	367	99
Total Profit of the year attributable to:
Owners of the Company	692	224	286	76
Non - controlling interest	108	63	92	20
Total Profit of the year attributable to owners of the company:
Continuing operations	692	146	341	72
Discontinued operations	-	78	(55)	4
Total Comprehensive Income of the year attributable to:
Owners of the Company	672	225	281	76
Non - controlling interest	93	67	86	23
Total Comprehensive Income of the year attributable to owners of the company:
Continuing operations	672	141	343	68
Discontinued operations	-	84	(62)	8
Basic earnings per share from continuing operations	14.42	2.81	6.65	1.53
Diluted earnings per share from continuing operations	14.42	2.81	6.65	1.53
Basic earnings (loss) per share from discontinued operations	-	1.50	(1.07)	0.13
Diluted earnings (loss) per share from discontinued operations	-	1.50	(1.07)	0.13
Dividends per share	-	-	-	-
Basic earnings per ADS (2) from continuing operations	0.58	0.11	0.27	0.06
Diluted earning per ADS (2) from continuing operations	0.58	0.11	0.27	0.06
Basic earning (loss) per ADS (2) from discontinuing operations	-	0.06	(0.04)	0.01
Diluted earning (loss) per ADS (2) from discontinuing operations	-	0.06	(0.04)	0.01
Dividends per ADS (2)	-	-	-	-
Weighted average amount of outstanding shares (in millions)	48	52	51	46
CONSOLIDATED CASH FLOW DATA
Net cash generated by operating activities	802	610	439	327
Net cash (used in) generated by investing activities	(369)	19	(846)	(581)
Net cash generated by (used in) financing activities	(390)	(470)	372	281

⁽¹⁾ Peso amounts as of December 31, 2018, 2017 and 2016 have been translated into US$ at the seller exchange rate for US$ quoted by Banco Nación on December 31, 2018 of Ps.37.70 to US$1.00. See “Item 3.Key Information—Exchange Rates.” 

⁽²⁾ Each ADS represents 25 common shares.

⁽³⁾ Financial information for the year ended December 31, 2016 reflects the effect of consolidation of Petrobras Argentina beginning on July 27, 2016, when we consummated the acquisition from Petrobras of all the shares of PPSLwhich in turn owned, at such time, 67.2% of the shares of Petrobras Argentina. Consequently, Petrobras Argentina’s results of operations before such date were not consolidated.

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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,
2015	13.400	8.222	9.265	13.040
2016	16.030	13.200	14.782	15.890
2017	19.200	15.190	16.572	18.649
2018	41.250	18.410	28.093	37.700
2019	60.400	36.900	48.234	59.890
Month
November 2019	59.950	59.500	59.745	59.940
December 2019	59.990	59.815	59.875	59.890
January 2020	60.350	59.815	60.010	60.350
February 2020	62.210	60.470	61.356	62.210
March 2020	64.469	62.259	63.124	64.469
April 2020(3)	66.750	64.529	65.707	66.750

Source: Banco Nación

(1)   Represents the average of the 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 29, 2020.

Pursuant to Argentine law, we are required to pay cash dividends 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.

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RISK FACTORS

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. We also have investments outside of Argentina, in Venezuela (our investments in Venezuela are currently valued at Ps.0, see “Our Oil and Gas Business——Others—Venezuela”) and in Ecuador (through our equity interest in OCP). 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. The Argentine Government may not be able to renegotiate its debt with their private creditors and/or with the IMF, affecting its capacity to obtain financing and credit and to plan and implement public policies and reforms that foster economic growth” 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.

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.

The Argentine economy remains vulnerable to external shocks that could be caused by significant economic difficulties of Argentina’s major regional trading partners, particularly Brazil, 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

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.

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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.

Financial and securities markets in Argentina are also influenced by economic and market conditions in other markets worldwide. U.S. monetary policy has significant effects on capital inflows and asset price movements in emerging market economies. Increases in U.S. interest rates result in the appreciation of the U.S. Dollar and decreases in prices for raw materials, which can adversely affect commodity-dependent emerging economies. In January 2017, Donald J. Trump took office as President of the United States, generating significant uncertainty about the future relationship between the United States and other countries, including with respect to the trade policies, treaties, government regulations and tariffs that could apply to trade between the United States and other nations. Even though President Trump's protectionist measures are not, for the time being, aimed at Argentina, we cannot predict how they will evolve, nor can we predict the effect that the same or any other measure taken by the Trump administration could cause on global economic conditions and the stability of global financial markets.

During the second semester of 2019, Latin America was subject to a period of turmoil stemming from unexpected results regarding certain political elections and a couple of major protests throughout the region generating instability and political uncertainty which could affect Argentina and our business.

On January 1, 2019, Jair Bolsonaro took office as Brazil’s president, generating uncertainties in connection with his administration’s announced policies. Those policies included, among others, a major economic reform and significant changes in foreign relationships. Argentina’s foreign trade depends highly on exports to Brazil and Argentina’s trade balance could be significantly affected with a deterioration of economic conditions in Brazil or of its diplomatic relationships. Other political and economic crises in Brazil may have a material adverse effect on Argentina’s economy and on our business, financial condition and operational results. The Brazilian economy contracted by 3.6% during 2016. Notwithstanding, Brazil’s economy grew 1.1% in 2017 and 2018, and 0.9% in 2019. A deterioration of economic conditions in Brazil may reduce demand for Argentine exports and increase demand for Brazilian products.

Luis Alberto Lacalle Pou was elected President of the Oriental Republic of Uruguay after winning the elections on November 24, 2019. Political uncertainties may arise due to a change in the governing party after 15 years, and may adversely affect Argentina, which considers Uruguay a key ally.

Additionally, the political and economic crisis in Venezuela may adversely affect Argentina and our Business. See “-Our activities may be adversely affected by events in other countries in which we do business, particularly in Venezuela” below.

A slowdown of China’s GDP growth has led to a reduction in exports to China, which in turn has caused oversupply and price declines in certain commodities. Decreases in exports may have a material adverse effect on Argentina’s public finances due, among other factors, to a loss of revenues relating to tax on exports, and cause an imbalance in the country’s exchange market. Recently, the IMF issued a report warning that the economic growth expected for 2020 may be lowered due to the coronavirus outbreak.

On June 23, 2016, the United Kingdom voted in favor of exiting the European Union (the “Brexit”). Brexit became effective on February 1, 2020 and is currently undergoing a transition period ending on December 31, 2020. Brexit long-term effects still remain uncertain, but volatility in the financial markets –among other negative effects –is expected in the short and medium-term. Additionally, Brexit could lead to additional political, legal and economic instability in both the European Union and the United Kingdom, producing negative impacts on the commercial trade of Argentina with those regions, which may in turn have a material adverse effect on our business, financial condition and operational results.

13

 

The Argentine economy remains vulnerable 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 economy has been volatile since 2011. For example, Argentina’s economy grew in 2017, but contracted in 2018. The Argentine economy remains vulnerable, as reflected by the following economic conditions:

· according to the revised calculation of 2004 GDP published by the INDEC on June 29, 2016, which forms the basis for the real GDP calculation for every year after 2004, and recent data published by the INDEC in 2020, for the year ended December 31, 2019, Argentina’s real GDP decreased by 1.7 % compared to the same period in 2018. Argentina’s performance has depended to a significant extent on high commodity prices which, despite having favorable long-term trends, are volatile in the short-term and beyond the control of the Argentine Government and the private sector;

· The IMF, in its World Economic Outlook issued in October 2019, projected a 3.1% contraction in Argentina’s economy in 2019 due to the loss of trust and the hardening of the conditions required to access credit and a 6.0% contraction for 2020 due to the effects of COVID19. For more information, see “Item 3. Key Information—Risk Factors— Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”;

· continued increases in public expenditures have resulted and could continue to result in fiscal deficit and affect economic growth;

· inflation remains high and may continue at those levels in the future;

· investment as a percentage of GDP remains low to sustain the growth rate of the past decades;

· 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. We cannot guarantee that these kinds of events will not occur in the future;

· energy or natural gas supply may not be sufficient to supply increased industrial activity (thereby limiting industrial development) and consumption;

· unemployment and informal employment remain high; and

· the Argentine Government’s economic expectations may not be met and the process of restoring 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.

In recent years, the Argentine Peso experienced a rapid devaluation against major foreign currencies, particularly against the U.S. Dollar. According to the exchange rate information published by the Banco de la Nación Argentina, the Argentine Peso devaluated by 59% against the U.S. Dollar during the year ended December 31, 2019 (compared to 102%, 17% and 22% in the years ended December 31, 2018, 2017 and 2016, respectively).

14

 

Throughout 2019, the depreciation of the Peso continued, and in September 2019, as a result of the financial and economic events that took place after the open primary elections (the “PASO”), the Argentine Government issued Decree No. 609/19 that established certain regulations regarding imports and exports of goods and services, foreign exchange controls and currency transfers to other countries and access to the foreign currency market. Also, due to the remarkable and sustained decrease in the price of the Argentine national bonds, the Argentine Government issued Decree No. 596/19, which postponed the maturity of certain local-law bonds. More recently, the Argentine government announced its plans for the restructuring of its external debt, including foreign-law bonds, debt with the IMF and other international multilateral organizations and the Paris Club group of sovereign lenders. If the Argentine government is not able to restructure its outstanding debt obligations, private sector companies, such as our company, may not be able to access the international capital markets for funding on accessible terms.

We cannot affirm there will be no adverse effect on our business, financial condition or operational results or no negative impact on the market value of our ADSs and our common shares resulting from a decline in economic growth, an increase in economic instability or the expansion of economic policies and measures taken or that may be adopted in the future by the Argentine Government to control inflation or address other macroeconomic developments that affect private sector entities such as us, all developments over which we have no control.

Political changes in Argentina may adversely affect the Argentine economy and the sectors in which we perform our activities

Between 2007 and 2015, the Argentine Government increased its direct intervention in the Argentine economy, including expropriations, price controls, foreign exchange controls and amendments in legislation that affected foreign trade and investments. Those policies had a material adverse effect in the private sector companies, including ourselves.

From December 2015 to December 2019, the Macri administration implemented several significant economic and policy reforms towards the de-regulation of the economy and stabilization of the main economic indicators. Those policies included (i) declaration of a state of emergency for the electricity system and reforms thereto; (ii) reforms affecting the transportation and distribution of natural gas; (iii) reforms concerning the INDEC; (iv) reforms affecting foreign exchange and foreign trade; (v) modification of Argentina’s debt policy; (vi) the correction of monetary imbalances; (vii) reform of the pension framework; (viii) Tax Reform; and (ix) the implementation of a fiscal consensus (Pacto Fiscal). Nevertheless, the high inflation rates and the Peso depreciation forced the Argentine Government to reinstate foreign exchange controls.

On August 11, 2019, the PASO were held and the results indicated that President Macri would not be reelected and could be replaced by the opposition candidate Alberto Fernández. As a result, the political and economic environment became subject to uncertainty. After the PASO, the Peso suffered a 30% devaluation, the Argentine stock markets fell at an average of 50% and the country-risk rate surpassed 2,000 points on August 28, 2019. On October 27, 2019, the presidential general elections were held, with the same results as the PASOs. The new administration took office on December 10, 2019, and since then has implemented –and is expected to continue implementing – several policies and reforms, mainly in the economy.

The Macri and the current administration implemented several policies pursuing a reduction in inflation and a stabilization in the foreign currency market. Those policies included:

· Reprofiling of the local-law debt: On December 20, 2019, the Argentine Government issued Decree No. 49/19, which established that certain debt amortization payment obligations emerging from certain Treasury Bonds (Letras del Tesoro) denominated in U.S. Dollars were deferred in full until August 31, 2020. Additionally, on February 5, 2020, the Argentine Congress passed Law No. 27.544 (the Law for the Restoration of the Sustainability of the National Debt issued under Foreign Law). This Law authorized the Executive Branch to carry out transactions regarding the administration of liabilities and/or swaps and/or restructuring of interests payments and principal amortizations of national bonds issued under foreign law. Additionally, the Executive Branch issued Decree No. 141/20 under which it deferred the payment of the amortization for national bonds in dual currency with maturity in 2020 entirely until September 30, 2020, and the interruption of the accrual of interests.

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· Reinstating of foreign exchange controls: On September 1, 2019, certain foreign exchange restrictions were reinstated to diminish the volatility of the Argentine Peso with respect to the U.S. Dollar. These restrictions, which were – and continue to be – further amended and complemented, regulate, among others, the purchase of external assets for Argentine citizens, the payment of financial debts outside the Argentine borders, the payment of dividends, the payment of imports of goods and services, the obligation to repatriate and settle the incomes from exports of goods and services. For more information, please see “Item 10. Additional Information – Exchange Control” below.

· Declaration of the state of emergency: The Social Solidarity and Productive Reactivation Law declared a state of emergency with respect to several areas: economy, finance, fiscal, administrative, pensions, tariffs, energy and social, and granted the Executive Branch several powers, allowing it to introduce exceptional measures and policies in the energy market during the state of emergency. The Social Solidarity and Productive Reactivation Law also allows the Executive Branch to intervene in the ENRE and the ENARGAS for up to one year, and to designate the officials who will be in charge of the decision-making processes. Additionally, the Social Solidarity and Productive Reactivation Law sets a cap at 8% for the export duty applicable to hydrocarbons, establishing that in any case such export duty shall be deducted from the base value for the calculation and payment of royalties. However, its implementation is still pending, therefore current export duty to hydrocarbons is set at 12%. By means of Decree No. 277/20, the Executive Power ordered the intervention of the ENRE until December 31, 2020.

· Tax reforms: Several tax reforms were completed. For more information, please see “Item 10. Additional Information – Taxation” below.

· Tariffs revisions: The Social Solidarity and Productive Reactivation Law freezes of natural gas and electricity tariff schedules for up to 180 days counted from the effectiveness of such law, and encourages the Argentine provinces to adhere to this policy. Additionally, the Social Solidarity and Productive Reactivation Law authorizes the Executive Branch to renegotiate tariffs under federal jurisdiction within the RTI or based on an extraordinary revision in accordance with Law N° 24,076.

· Tariffs on exports: The Social Solidarity and Productive Reactivation Law authorizes the Executive Branch to establish tariffs on exports that in no case can exceed 33% of the taxable value or the official FOB price. The Social Solidarity and Productive Reactivation Law caps the percentage of tariffs on exports of hydrocarbons and mining to 8% of the taxable value or the official FOB price, and establishes that in any case such export duty shall be deducted from the base value for the calculation and payment of royalties. However, its implementation is still pending, therefore current export duty to hydrocarbons is set at 12%.

· Double severance payment for labor termination without cause: Executive Decree No. 34/19, issued on December 13, 2019, declared a labor public emergency for the term of 180 days counted from the effectiveness of the decree. During this emergency process, in case of termination without just cause of a labor relationship started prior to the effectiveness of said decree, the employee will be entitled to receive a compensation that equals two times the severance due in accordance with applicable laws. The duplication is applicable to every item of the compensation. Decree No. 34/19 also establishes that the double severance payments will not be applicable to labor relationships that start after the effectiveness of said decree. Additionally, the Social Solidarity and Productive Reactivation Law established new percentages and mechanisms to calculate the employers’ contributions.

· Suspension of Section 124 of Law No. 27,467: The Social Solidarity and Productive Reactivation Law suspended the applicability of the second paragraph of section 124 of Law No. 24,467. That paragraph took away ENRE’s powers and abilities relating to the public service of electricity distribution once Edenor and Edesur were transferred to the jurisdictions of the City of Buenos Aires and the Province of Buenos Aires (for more information, please see “The Argentine Energy Sector – Regulatory Authorities”). The Social Solidarity and Productive Reactivation Law reinstated ENRE’s powers and attributions for one year.

As of the date of this annual report, the impact of the aforementioned policies cannot be predicted, and any other policy or action implemented by the Argentine Government may result in an adverse effect for the Argentine economy and/or the energy sector. Pampa does not have any control over the implementation of, and cannot predict the outcome of, the reforms of the regulatory framework that rule in the different sectors in which Pampa performs its operations, nor the effect that those reforms may have over Pampa’s business, financial condition and operations. Additionally, uncertainty over these reforms and policies may result in volatility in the prices of Argentine financial assets, especially in Argentine corporations’ debt and equity securities listed in local and/or international markets. Moreover, the uncertainty may affect the main macroeconomic indicators, such as foreign exchange, production, labor or inflation.

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Pampa cannot affirm that the Argentine economic, regulatory, social and political framework or the policies 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.

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 the following months were:

CPI	2019
	July	August	September	October	November	December
	2.2%	4.0%	5.9%	3.3%	4.3%	3.7%
	2020
	January	February	March
	2.3%	2.0%	3.3%

For more information, please see “—The credibility of several Argentine economic indexes was called into question, which may lead to a lack of confidence in the Argentine economy and, in turn, limit our ability to access credit and the capital markets” below. The Argentine Government has implemented programs to control inflation and monitor prices for essential goods and services, including the freezing of prices of supermarket products, and through price support arrangements with private sector companies in several industries and markets. 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.

A high inflation rate affects Argentina’s foreign competitiveness by diluting the effects of the Peso devaluation, 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.

The inflation rates may increase in the future, and 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.

Fluctuations in the value of the Argentine Peso could adversely affect the Argentine economy and could, in turn, adversely affect our operational results

The Argentine Peso suffered important fluctuations during the last four years: it depreciated by more than 22% as compared to the U.S. dollar in 2016, and approximately 17% in 2017, 102% in 2018, and 59% in 2019. We are unable to predict the future value of the Peso against the U.S. Dollar. If the Argentine Peso devaluates further, the negative effects on the Argentine economy could have adverse consequences on our businesses, our operational results and the market value of our ADSs, including as measured in U.S. Dollars.

On September 1, 2019, certain exchange controls and restrictions were reinstated in order to control the volatility in the currency exchange rate. The new controls and restrictions regulate, among others, the purchase of external assets for the Argentine population, the payment of financial debts outside the Argentine borders, the payment of dividends, the payment of imports of goods and services, the obligation to repatriate and settle the income from exports of goods and services. 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. For more information, please see “Item 10. Additional Information – Exchange Control” below.

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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. 

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.

The credibility of several Argentine economic indexes was called into question, which may lead to a lack of confidence in the Argentine economy and, in turn, limit our ability to access credit and the capital markets

Prior to 2015, the credibility of the CPI, as well as other indices published by the INDEC, were called into question.

On January 8, 2016, based on its 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 Macri administration declared a state of administrative emergency for the national statistical system and the INDEC. 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, 2019 was 53.8%.

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. The Argentine Government may not be able to renegotiate its debt with their private creditors and/or with the IMF, affecting its capacity to obtain financing and implement public policies and reforms that foster economic growth

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 by offering holders of the defaulted bonds two opportunities to exchange them for newly issued debt securities, in 2005 and again in 2010. Holders of approximately 93% of Argentina’s defaulted debt participated in the exchanges. Nonetheless, a number of bondholders held out from the exchange offers and pursued legal actions against Argentina in the courts of the United States and several other jurisdictions.

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The Macri Administration settled several agreements with the defaulted bondholders, ending more than 15 years of litigation. On April 22, 2016, Argentina issued US$16.5 billion of new bonds, of which US$9.3 billion were applied to pay the amounts due to comply with the agreements settled with the defaulted bondholders. Since then, almost every pending claim has been settled.

In addition, certain bondholders that did not participate in the exchange offers described above, filed claims before the ICSID alleging that the emergency measures adopted by the Argentine Government in 2002 did not meet the just and equal treatment requirements of several bilateral investment treaties to which Argentina is a party. Several of these claims have been granted award against Argentina.

In June 2018, the Argentine Government agreed to enter into the stand-by credit facility (the “SBA”) with the IMF that granted Argentina access to financing by the IMF. The SBA granted Argentina credit for US$50 billion subject to public spending cuts and the compliance with certain fiscal and political benchmarks by the Argentine Government. After further reviews, the IMF extended the amounts granted by the SBA for a total amount of US$57.1 billion. As of the day of this annual report, the Argentine Government is trying to renegotiate the credit due to the IMF, but has not reached an agreement yet.

On August 28, 2019, the Macri administration issued a decree deferring the scheduled payment date for 85% of the amounts due on short-term notes maturing in the fourth quarter of 2019, governed by Argentine law and held by institutional investors. Of the deferred amounts, 30% would be repaid 90 days after the original payment date and the remaining 70% would be repaid 180 days after the original payment date, except for payments under Lecaps (“Peso denominated Treasury Bond” – “Letras del Tesoro Capitalizables en Pesos”) due 2020 held domestically, which would be repaid entirely 90 days after the original payment date. Amounts due on short-term notes held by individual investors would be paid as originally scheduled. In December 2019, the Fernández administration further extended payments of a series of short term U.S. Dollar-denominated notes which were held by institutional investors until the end of August 2020.

Additionally, on February 11, 2020, the Argentine Government decreed the extension of maturity to September 30, 2020 of a U.S. Dollar-linked treasury note governed by Argentine law, which had been originally subscribed to a large extent with U.S. Dollar remittances, to avoid a payment with Argentine pesos that would have required significant stabilization efforts by the monetary authority. Also, in February 2020, the Argentine Congress enacted a law enabling the government to take all necessary steps to ensure the Argentine sovereign debt governed by foreign law as sustainable. Additionally, an IMF team visited Buenos Aires in February 2020 to discuss the recent macroeconomic developments and learn more about the Argentine authorities’ economic plans and policies. On February 19, 2020 the IMF issued a statement in which, in light of recent developments and the materialization of certain risks to debt sustainability that were considered during the previous Debt Sustainability Analysis (DSA) published in July 2019, the IMF staff assessed Argentina’s debt to be unsustainable. Accordingly, the IMF staff stated that “a definitive debt operation—yielding a meaningful contribution from private creditors—is required to help restore debt sustainability with high probability”.

On April 5, 2020, the Executive Branch issued Decree No. 346/2020 by which the Government deferred the payment of interest and principal amortization obligations of certain sovereign debt issued under Argentine law and denominated in U.S. Dollars, until December 31, 2020, or an earlier date to be determined by the Ministry of Economy, considering the progress of the public debt’s sustainability restoring process (Proceso de Sostenibilidad de la Deuda Pública). This Decree did not affect the currency of denomination, principal or interest set forth under the original terms of the issuance. On April 21, 2020, the Argentine Government announced its offer to exchange external bonds in the aggregate amount of approximately US$64 billion for new bonds. The Argentine Government did not make the interest payment due on April 22, 2020 with respect to three of its US$-denominated bonds and availed itself of the 30-day grace period provided under the indenture. As of the date of this annual report, there is no certainty on the acceptance the exchange offer will have among the bondholders or whether further negotiations and proposals will be carried out and the consequences of such negotiations. Any new event of default by the Argentine Government could negatively affect their valuation and repayment terms, as well as have a material adverse effect on the Argentine economy and, consequently, our business and results of operations. Without renewed access to the financial market, the Argentine Government may not have the financial resources to implement reforms and boost growth, which could have a significant adverse effect on the country’s economy and, consequently, on our activities. Likewise, Argentina’s inability to obtain credit in international markets could have a direct impact on the Company’s ability to access those markets to finance its operations and its growth, including the financing of capital investments, which would negatively affect our financial condition, operational results and cash flows.

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Past situations, such as the lawsuits with creditors that did not accept the debt exchange, the claims before the ICSID, and the economic policy measures adopted by the Argentine Government or any future default of Argentina regarding its financial obligations, including as a consequence of the exchange offer not being accepted by holders, may harm Argentine companies’ ability to obtain financing. Further, the financial conditions of such access could be disadvantageous to Argentine companies and, therefore, may adversely affect our business, results of operations, financial condition, the value of our securities, and our ability to meet our financial obligations.

We cannot predict if the Argentine Government will be able to successfully renegotiate the debt held with private bondholders. There is uncertainty regarding the Argentine Government’s ability to successfully stabilize the foreign exchange market, re-establish economic growth and comply with the SBA terms. Additional depreciation of the Peso against the U.S. Dollar, a breach of the terms of the SBA and the potential failure of the Argentine Government in the renegotiation of the debt may adversely affect the Argentine economy and, in turn, our business, financial situation, operational results and the value of our ADSs and our common shares.

We cannot affirm that a decrease in economic growth, an increase in the economic instability or the expansion of the economic and political policies adopted in the future by the Argentine Government to control inflation and other macroeconomic imbalances that affect us and other companies from the private sector, will not have a material adverse effect on the Argentine economy, and, in turn, on our business, operational results and our growth perspectives.

Intervention by the Argentine Government may adversely affect the Argentine economy and, as a result, our business and operational results

In the recent past, the Argentine Government directly intervened in the economy, including through the implementation of expropriation and nationalization measures, price controls and exchange controls.

Starting in December 2001, the Argentine Government imposed a number of monetary and foreign exchange control measures in an attempt to prevent capital flight and a further depreciation of the Peso. These measures included restrictions on the free disposition of funds deposited with banks, the exchange of Argentine currency into foreign currencies and the transfer of funds abroad without prior approval by the Central Bank.

Additionally, between 2011 and 2015, the Kirchner administration –through a combination of exchange control and tax regulations, significantly reduced the access to the foreign currency market for individuals and entities in the private sector. Subsequently, a non-official U.S. Dollar currency market emerged, with a major difference between the official and the non-official exchange rate.

Also, the Argentine Government has historically adopted measures to control –directly or indirectly – the individuals’ and private companies’ access to the foreign trade and foreign exchange markets, such as restriction to free access, and the obligation to repatriate and settle in the local exchange market every income in foreign currency obtained from exports. Those regulations limited our ability to compensate the risks that arise from our exposure to the Dollar.

At the beginning of the Macri administration, the Argentine Government eliminated exchange restrictions implemented during the Kirchner administration. Notwithstanding, on September 1, 2019, the Argentine Government reinstated several exchange restrictions regarding the inflows and outflows of foreign currency to the country, with the intention of diminishing the volatility of foreign exchange rates. As of the date of this annual report, such exchange restrictions are still valid.

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 capitals 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. Such restrictions and measures may generate political and social tensions and deteriorate the Argentine Government’s public finances, as has occurred in the past, generating an adverse effect in the Argentine economic activity and, in consequence, adversely affect our business and operational results and cause the market value of our ADSs and our common shares to decline.

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Moreover, we cannot guarantee that the measures that may be adopted by the current or any future Argentine Government, such as expropriation, nationalization, forced renegotiation or modification of existing contracts, new taxation policies, changes in laws, regulations and policies affecting foreign trade and investments, restrictions to transfers to other countries or to capitals movement, or an important devaluation of the Peso will not have a material adverse effect on the Argentine economy and, as a consequence, adversely affect our financial condition, our operational results or cause the market value of our ADSs and our common shares to decline.

Argentine corporations may be restricted to make payments in foreign currencies

There are restrictive conditions currently applicable in Argentina that affect corporations’ ability to access the MULC 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 MULC. In such case, the possibility of Argentine corporations to make payments outside Argentina and to comply with their obligations and duties may be affected.

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), 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.

Exchange controls in an economic environment in which the access to local capital markets is restricted may cause an adverse effect in our activities, mainly in our ability to make payments of principal and/or interest of our notes in foreign currency. For more information, please see “Item 10.Additional Information – Exchange Control” below.

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 spending, 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.

As of the date of this annual report, we cannot predict how the measures that the new administration 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 are uncertainties regarding the impact of policies that the Argentine Government will adopt in order to resolve the crisis in the energy sector

The energy sector was one of the sectors that were most damaged by the policies adopted by the Argentine Government since the 2001 crisis. In 2001, natural gas and electricity tariffs and prices were frozen, discouraging investments in the sector. The Argentine Government tried to generate incentives to attract investments by subsiding energy consumption. However, such measures failed and caused a stagnation in both oil and gas production and in the infrastructure necessary for generation, transmission and distribution of electricity; at the same time, consumption of both was growing. In 2011, the energy crisis lead to a shortage. In order to satisfy the increasing overdemand, the Argentine Government tried to resolve the issue by increasing energy imports, which had a negative outcome in the balance of trade, current accounts and the Central Bank’s international reserves.

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The Macri administration declared a state of emergency with respect to the national electric system to address the existing distortions in the sector and to attract investments. The state of emergency allowed the Argentine Government to adopt measures aiming to stabilize the supply of electricity through the country, such as eliminating certain subsidies to energy and passing the additional cost resulting from such elimination to end-users, or the implementation of important tariff reviews to reflect real cost. Nevertheless, some of those measures were questioned before the Argentine courts and resulted in rulings that limited the Administration’s initiatives (such as a ruling that halted increases in electricity and gas tariffs implemented on February 1, 2016, and instructed that non-compulsory public hearings prior to the approval of increases in tariffs prices should be held).

Regarding the spot price for electricity, on February 27, 2020, the Secretariat of Energy issued Resolution No. 31/20, which modified –retroactively, from February 1, 2020 onwards certain aspects of the remuneration scheme established by Resolution SRRYME No. 1/19. The new scheme turns the whole remuneration scheme from foreign currency into local currency at an exchange rate of 60 Argentine Pesos per U.S. Dollar, and establishes a restatement factor, from the second month of application and onwards, that contemplates a formula composed by CPI (60%) and WPI (40%). However, on April 8, 2020, the Secretariat of Energy instructed CAMMESA to postpone the automatic application of the adjustment formula until further notice. Additionally, Resolution No. 31/20 modified the payments for electricity and added additional remuneration for high-thermic requirement hours of every month. For more information, please see (“—The Argentine Energy Sector— Remuneration Scheme for Generation Not Covered by Contracts— SE Res. No. 31/20: Current Remuneration Scheme as from February 2020”; “—Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”.

The lack of action to correct the existing problems in generation, transportation and distribution in Argentina may adversely affect Argentina’s economic situation and our business, financial situation and operational results. We cannot ensure that the Argentine Government will not adopt policies and measures that may have an adverse effect over our business, and that the policies implemented by the Argentine Government will be successful to correct the energy production sector in Argentina.

Pampa’s business and operations may be affected by restrictions on imports of products

In February 2011, the former Argentine Ministry of Industry issued Resolution No. 45/11, which, among other things, decided to extend the applicability of non-automatic permits regarding imports of products considered as luxury goods or that compete in a non-loyal manner with domestic production, in accordance with the aforementioned Ministry’s criteria. The Argentine Government issued Resolution No. 45/11 considering that domestic production was able to satisfy the domestic demand. On January 25, 2013, the Ministry of Economy issued Decree N° 11/13 which abolished Resolution No. 45/11, ending with the system that compelled importers to request an authorization to import certain products to the country.

On January 8, 2020, the Secretariat of Industry, Knowledge Economy and Foreign Commercial Management (Secretaría de Industria, Economía del Conocimiento y Gestión Comercial Externa) issued Resolution No. 1/20 which: (i) incorporated new tariff items that must file for non-automatic licenses (NAL); (ii) modified the forms that needed to be presented to request import licenses; (iii) decreased the tolerance in the FOB unitary value of merchandises subject to filing for NAL; (iv) decreased the validity of the NAL from 180 days to 90 days counted from their approval in the SIMI; (v) extended the scope of merchandise imports to Isla Grande de la Tierra del Fuego (creating an exception for products entering from continental territory); and (vi) established the Sub-Secretariat of Politics and Commercial Management of the Secretariat of Industry, Knowledge Economy and Foreign Commercial Management as authority.

As of the date of this annual report, we cannot guarantee that the Argentine Government will not implement similar measures in the future. Those measures may affect goods that we use as inputs, causing an adverse effect on our business, our financial condition and operational results.

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). This has generated a vulnerability in the Argentine economy with respect to the fluctuation of commodities’ prices. 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.

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A sustained decline 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 Argentine companies may increase as a result of the implementation or adoption of certain measures or policies by the Argentine Government and by pressures from unions

On several occasions, the Argentine Government implemented laws and collective bargaining agreements that compelled employers of the private sector to maintain certain salary levels and to bring additional benefits to their employees. Employers have suffered great pressure from their employees and the unions to grant increases in wages and other benefits.

There are possibilities that in the future, the Argentine Government may issue regulations and/or adopt policies or measures that imply increases in the minimum wage (salario mínimo, vital y móvil) and/or in benefits, indemnities, compensations and other labor costs that the employers may face. Every increase in wages or any other labor related cost may increase our costs and reduce the results of our operations. For more information, please 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” below.

Current investigations being conducted on corruption in Argentina could have an adverse impact on the development of the Argentine economy and on investor confidence

As of the date of this annual report, several Argentine businesspersons, mainly associated with public works projects, and former government officials of the Kirchner administration are being investigated for inappropriate gifts and unlawful association. On September 17, 2018, prosecution for unlawful association began against the former president –and current Vice-president – of Argentina, Cristina Elisabet Fernández de Kirchner and several businesspersons.

Depending on the results of such investigations and the time it takes to complete them, the companies involved could face, among other consequences, a decrease in their credit rating, claims from their investors, as well as restrictions on financing through capital markets. These adverse effects could hinder the ability of these companies to meet their financial obligations on time. In relation to the above, the lack of future financing for these companies could affect the realization of the projects or works that are currently in execution.

Likewise, the effects of these investigationsor any future investigation could affect the levels of investment in infrastructure in Argentina, as well as the continuation, development and completion of public works projects and public-private participation projects (PPP), which could ultimately lead to lower growth of the Argentine economy.

We cannot estimate the impact that these investigations could have on the Argentine economy. Similarly, it is not possible to predict the duration of the corruption investigations, nor which other 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.

Any downgrade in the credit rating or rating outlook of Argentina could adversely affect both the rating and the market price of our ADS and our common shares

Argentina’s long-term debt denominated in foreign currency is currently rated as “Ca” by Moody’s, as “CCC-” (negative) by S&P and as “CC” by Fitch. On August 30, 2019, Moody’s downgraded Argentina’s long-term sovereign credit rating as issuer in foreign currency from “B2” to “Caa2”, and its rating was prepared for further downgrades, depicting the increasing uncertainty regarding the public policy plans expected from the Argentine Government and the consequences for the investors’ trust. Fitch mentioned that its “CC” rating for Argentina reflected its expectations of a new breach of its obligation or a debt restructuring. The sharply weaker economic activity and uncertain prospects for multi-year fiscal consolidation and market financing availability as IMF funds are utilized, constitute risks to sovereign debt sustainability. In addition, on January 21, 2020, S&P confirmed Argentina’s long-term and short-term sovereign credit ratings at “CCC-”, maintaining it negative. In a public release, S&P explained that its rating reflects the expectations of an additional restructuring of the sovereign debt while the Argentine Government discusses with debtholders, brokers and official creditors on its priorities regarding politics, economic strategy and debt reprofiling.

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We cannot guarantee that Argentina’s credit rating or rating outlook will not be 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.

Developments relating to the novel coronavirus may have a material adverse impact on our business operations, financial condition or results of operations

In late December 2019 a notice of 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. The virus rapidly spread globally and, as of the date of this annual report, has affected more than 150 countries and territories around the world, including Argentina, Brazil, Paraguay, Uruguay and the United States. Several measures have been undertaken by the Argentine Government and other governments around the globe, including the use of quarantine, screening at airports and other transportation hubs, travel restrictions, suspension of visas, nation-wide lockdowns, closing of public and private institutions, suspension of sport events, restrictions to museums and tourist attractions and extension of holidays, among many others.

The Executive Branch of the Argentine Government issued Decree No. 260/2020 on March 12, 2020, which declared a public health emergency for a period of one year and established a mandatory quarantine of fourteen days for the following individuals: (i) suspected cases, including individuals with fever and respiratory symptoms and individuals who had traveled in the last few days to affected areas or had been in contact with individuals who had confirmed positive or were likely positive for COVID-19, (ii) confirmed cases, (iii) those who had arrived in Argentina after March 12, 2020 having traveled through affected areas, and (iv) those who had arrived in Argentina in the last fourteen days prior to March 12, 2020 having traveled through affected areas. Incoming flights from affected areas were also prohibited for a period of 30 days.

The Executive Branch issued Decree No. 297/2020 on March 20, 2020, which established a mandatory and preventive social isolation effective as of March 20, 2020 until March 31, 2020, which, as of the date of this Annual Report, was extended until May 10, 2020, without prejudice to the possibility that the term may be extended again. The Decree expressly stated that minimal and essential movement would be allowed only for the purchase of food, medication and cleaning products. Some individuals, such as healthcare personnel, supermarket and pharmacy employees, among others, would be exempted from the isolation measure. Some essential activities, like power generation plants, oil basins, refining plants and food and medical industries, were allowed.

Moreover, on April 7, 2020, through Administrative Decision No. 468/2020, construction activities for energy infrastructure works, including our ongoing expansion projects, were included as an essential activity. However not all contractors and suppliers have been declared essential and also the arrival of expert personnel needed for the projects has not been permitted because the travel restrictions and national borders lockdown remains in force. In addition, the Argentine Goverments established special protocols that affect the development and productivity of construction work. As a result, we expect that the schedules of our ongoing projects and the estimated costs for their completion will be affected but, we cannot yet determine the magnitude of the impact. In this sense, in the case of the Cycle Closing Project at CTGEBA ((for more information, please see “Progress in the Cycle Closing Project at CTGEBA”), our best estimate, based on the information that we have as of the date of this annual report, is for the commercial commissioning of the closing-to-combined-cycle at CTGEBA Plus to be concluded around the third quarter of 2020, when the originally estimated date was the second quarter of 2020.

To date, the outbreak of the novel coronavirus has caused significant social and market disruption. For example, the Dow Jones declined by about 28% between February 11 and March 12, 2020. 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. Any prolonged restrictive measures put in place in order to control an outbreak of a contagious disease or other adverse public health development such as the ongoing COVID-19 outbreak, may have a material and adverse effect on our business operations, financial condition or operational results.

We may also be affected by the need to implement policies limiting the efficiency and effectiveness of our operations, including home office policies. It is unclear whether these challenges and uncertainties will be contained or resolved, and what effects they may have on the global political and economic conditions in the long term. Additionally, we cannot predict how the disease will evolve in Argentina, nor anticipate what additional restrictions the Argentine Government may impose. However, we expect COVID-19 to have a significant adverse effect on the world economy, which will in turn negatively affect Argentina’s economy

Furthermore, the crisis caused by COVID-19 has resulted in a decrease in the demand for crude oil, since industrial and domestic activity has slowed down in many countries due to control measures. On the other hand, in the context of the coronavirus pandemic crisis, Russia broke the agreement it had with Saudi Arabia in the internal dispute for 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. In particular, the Argentine economy was adversely affected by a lower demand from customers, interruptions in the payments chains, among other adverse effects due to control measures imposed by the Argentine Government. For more information, please see “—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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The Company is currently considering available alternatives to mitigate the effects this outbreak may have on its operations and ongoing projects, as well as with regards to measures adopted by the Argentine Government, which so far have resulted in a slowdown in economic activity that will further adversely affect economic growth in Argentina in 2020 and possibly 2021, to a degree that we cannot quantify as of the date of this annual report. For more information on the measures adopted by the Argentina Government. For more information, please see “Item 4—Relevant Events—Measures Designed by the Argentine Government to Address the Covid-19 Outbreak” and “Impact of the COVID-19 outbreak on our Operations”. 

We cannot affirm that the current COVID-19 outbreak will not cause a material adverse effect in our businesses and operational results, as well as a decrease in the market value of our shares and corporate bonds.

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.

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, 2019, 43.41% of our workforce was represented by unions under collective bargaining agreements. Although our relations with trade unions have been historically stable, we cannot assure 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.

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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.

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.

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. Until the issuance of Resolution SE 31/2020, power generation segment’s remuneration scheme established U.S. Dollar denominated prices and payment was made in Argentine Pesos by applying the Central Bank’s exchange rate effective on the business day before the expiration date, in accordance with procedures of CAMMESA. As a result, we were exposed to an exchange rate risk between the collection date and the payment date (in the event CAMMESA does not pay at the expiration date, see “CAMMESA could alter and delay payments to power generators and fuel producers”) of U.S. Dollars-denominated financial indebtedness. The same applies to contracts signed with gas distributors for the sale of natural gas, since the exchange rate agreed in those contracts is the one fixed by the ENARGAS for the seasonal period corresponding to the delivery of the invoiced gas. In addition, a significant portion of our existing financial indebtedness is denominated in U.S. Dollars, which exposes us to the risk of loss from the devaluation of the Argentine Peso. During 2018, our hedging contracts did not cover all of our exposure to such depreciation. 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 significantly increase our debt service burden, which, in turn, may have a material adverse effect on our financial condition and results of operations.

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

We and our subsidiaries 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”.

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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. 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 (“SCADA”) and DCS Software, Inc.(“DCS”). 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 have our business operations disrupted, fraud, property damaged and customer information stolen; experience substantial loss of revenues, response costs and other financial loss; and be subject to increased regulation, litigation and damage to our reputation.

During 2019, we have been the target of different fraud attempts and were exposed to malware infections, as other companies in the industry have, but this did not result in a significant loss or negative impact on our operations. Therefore, it is not possible to ensure that we will not incur in losses related to such attacks in the future. Our risk and exposure to these matters cannot be fully calculated or mitigated due, among other things, to the evolution and nature of these threats.

In 2019, we conducted an assessment of our cybersecurity in critical operational infrastructures, based on the standard applicable to electricity distributors in the United States (NERC-CIP) and the standards proposed by IEC62443.Based on the results of this evaluation, a multi-year mitigation plan was launched.

As part of the mitigation plan, new specialized management functions were created a team composed of members from the information security area was created to carry out the multi-year mitigation plan. At the same time, work began on the acquisition of a new cybersecurity event monitoring system to improve our ability to monitor, detect and act against cybersecurity threats to our networks, IT infrastructure and control systems.

Additionally, an annual cybersecurity training plan was carried out for all of our personnel, aiming to deepen awareness and learning about the risks, threats and good practices of information security. In this framework, we carried out simulations of targeted phishing and pentesting attacks, which allowed determining the degree of user compression on critical issues related to cybersecurity. Furthermore, specific industrial cybersecurity workshops were scheduled for the critical infrastructure areas of our assets.

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 could adversely affect our business, operational results and financial condition.

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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.

In addition, 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 operators in Argentina could significantly increase the costs of our activity.

We cannot predict the general 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 fossil 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 be enough to cover all of the generators and fuel producers’ claims against CAMMESA, CAMMESA’s payable account would grow over time. As of the date of this annual report, according to CAMMESA, it is estimated that approximately 40% of the total cost of electricity generation, is not being transferred to the end-users but covered by the Argentine Government through subsidies. 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. In fact, due to the quarantine imposed due to COVID-19, Distributors and Large User’s payments had significantly decreased, increasing the share that would have to be covered by the National Government to maintain CAMMESA’s payment rate. Moreover, the Secretariat of Energy instructed CAMMESA to apply a new payment scheme for the Large Users affected by COVID-19 increasing the financial stress on CAMMESA and, ultimately, on generators if the National Government does not cover such amounts. Since November 2019, payments from CAMMESA which should be settled within 42 days from the end of the transaction month, have been raised to approximately 70 days (except for RenovAr power purchase agreements, which are paid in a timely manner and are guaranteed by FODER). 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 (“—Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”.

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 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 a 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 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 in any event 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 units, power transmission and electricity distribution grid 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.

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

Some of the investment projects of us and our subsidiaries could be guaranteed by Pampa Energía, 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 its 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.

Risks Relating to Our Businesses

Risks Relating to the Electricity Sector

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There is uncertainty as to what other measures the Argentine Government may adopt in connection with tariffs on public services and their impact on the Argentine economy

As explained in other risk factors in this annual report, following the economic crisis of 2001-2002, the subsequent freeze on gas and electricity rates in Pesos and the significant devaluation of the Argentine Peso against the U.S. Dollar, there was a lack of investment in the supply and transport capacities of gas and electricity and, at the same time, demand for natural gas and electricity increased substantially.

In response, the Macri administration announced several measures, including the revision of subsidy policies, Decree No. 134/2015 of December 16, 2015, which placed the national electricity system in a state of emergency until December 31, 2017 and Decree No. 367/2016 of February 16, 2016, which instructed the ministries, including the ME&M to continue the procedures related to the renegotiation of contracts related to the provision of public services and their RTI, among which are the distribution and transportation of gas and electricity.

In relation to natural gas, prices with gas distributors began to be agreed upon in the spot market on a daily basis as from October 2018. Subsequently, ENARGAS Resolutions No. 280-289 and No. 292/18 were issued, which established, effective for a six-month period beginning October 1, 2018, the new natural gas final tariffs for SGP, CNG and residential users considering a price for natural gas as input ranging between US$1.74/MBTU y US$3.98/MBTU, including the differential tariff. Moreover, on February 2019, a tender 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, for a term of 12 months with seasonality terms, and effective as from April 2019. For the Noroeste Basin, 9.4 and 3.8 million m3 per day were assigned for the winter (April – September 2019) and summer (October 2019 – April 2020), respectively, at an average tender price of 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. We submitted an application and were awarded with the bid. Producers would bill to distribution companies in Ps. pursuant to ENARGAS Resolution No. 72/19, considering BNA’s average currency nominal exchange rate for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the nominal exchange rate stipulated in the agreements. However, the nominal 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. With the entry into effect of the Social Solidarity and Productive Reactivation Law, the nominal exchange rate freeze was subjected to a maximum term of up to 180 days.

ENARGAS Resolution No. 193-199, 201-202 and 205-207 /19 established gas tariff schemes effective as from April 2019, considering an average PIST price of gas as a raw material for the following 6 months ranging between US$2.14/MBTU and US$4.69/MBTU, including the differential tariff Later, 27% and 12% discounts in the price of natural gas within the PIST were set for the months of April and May 2019, respectively, by means of subsidies and, with the purpose of reducing monetary expenses for seasonal consumption, a 22% deferral on bills issued during the July – October 2019 period was approved, to be recovered in five installments as from December 2019. Later, the tariff scheme update corresponding to October 2019 was deferred until February 1, 2020 pursuant to SGE Res. No. 521, 751 and 791 /19 and, with the entry into effect of the Social Solidarity and Productive Reactivation Law, effective as from December 23, 2019, it was determined that tariffs under federal jurisdiction would remain unchanged and a process for an extraordinary review of the RTI would be initiated for a maximum term of 180 days. Regarding gas transportation, on March 27, 2018, ENARGAS issued Resolution No. 310/18 which implemented a 50% tariff increase applicable to natural gas transportation utility service of TGS, effective as from April 1, 2018. Subsequently, ENARGAS issued Resolution No. 265/2018 which implemented a 19.7% tariff increase effective as of October 1, 2018. Furthermore, ENARGAS Resolution No. 192/19 determined a 26.0% increase on account of costs variations effective as from April 2019. This increase was calculated based on the IPIM semiannual variation for the August 2018 – February 2019 period. Later, 22% of the amount of bills issued during the July – October 2019 period was deferred, to be recoverable in five installments as from December 2019, pursuant to SGE Resolution No. 336/19. The semiannual update which, according to the RTI, should have been applied since October 1, 2019, was deferred pursuant to several regulations. Finally, the tariff increase was suspended for a maximum term of up to 180 days since the entry into force of the Social Solidarity and Productive Reactivation Law on December 23, 2019. Moreover, this Law contemplates the possibility of performing an RTI review for a term of up to 180 days. See, “Item 4. Information on the Company—Our Interest in TGS.”

In relation to the distribution of electricity, on January 31, 2018, the ENRE issued Resolution No. 33/18 which approved the tariff scheme for Edenor to be applied as from February 1, 2018. Furthermore, such resolution approved the new adjustments to own distribution costs (“CPD”) (last stage of 17% according to Resolution No 63/17, including the inflation adjustment of 11.9% for the period July 2017-December 2017 and a stimulus factor “E” of negative 2.51%) and determined the deferred income to be recovered in 48 instalments for a total amount of Ps.6,343.4 million. Additionally, it reported that the price of the average tariff reached Ps.2.4627/ KWh. See, “Item 4. Information on the Company— Our Distribution of Energy Business.”

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In relation to the transmission of electricity, on February 19, 2018, the ENRE issued Resolutions No. 37/18 and No. 38/18, which were modified on April 5, 2018 by ENRE Resolutions No. 99/18 and No. 100/18 that adjusted Transener and Transba’s remuneration by 24.15% and 23.39% for the December 2016 to December 2017 period, respectively, to be applied to the remuneration scheme as from February 2018. Subsequently, on November 16, 2018, the ENRE issued Resolutions No. 280/18 and No. 281/18, which adjusted Transener’s and Transba’s compensation by 42.55% and 43.25%, respectively, for the December 2016 to June 2018 period, to be applied to the remuneration scheme as from August 2018. As CAMMESA did not compute interest for the months of August and September 2018, Transener and Transba filed a claim before the ENRE and CAMMESA for the settlement of the applicable interest. On March 22, 2019, the ENRE issued Res. No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 78.41% and 81.26%, respectively, for the December 2016 – December 2018 period, effective as from February 1, 2019. On September 25, 2019, the ENRE issued Res. No. 269/19 and No. 267/19 updating Transener and Transba’s remunerations by 112.41% and 115.75%, respectively, for the December 2016 – June 2019 period, retroactively to August 1, 2019.

Notwithstanding the measures adopted by the Macri administration, the change of administration implied a radical change in governmental policies. One of the first measures of the Fernandez 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 and enabled the President to intervene before the regulatory authorities (ENRE and ENARGAS). 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. For more information, please See “Item 4. The Argentine Energy Sector—Electricity Regulatory Framework”.

Therefore, there is uncertainty as to what other measures the Argentine Government may adopt in connection with tariffs, whether tariffs will be updated from time to time to reflect an increase in operating costs, and their impact on the Argentine economy and, consequently, on our business or operational results.

The Argentine Government has intervened in the electricity sector in the past, and may continue intervening

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

To address the Argentine economic crisis in 2001 and 2002, the Argentine Government adopted the Public Emergency Law No. 25,561 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 and included the freezing of nominal distribution margins, the revocation of adjustment and inflation indexation mechanisms for tariffs, a limitation on the ability of electricity distribution companies to pass on to the user increases in costs due to regulatory charges and the introduction of a new price-setting mechanism in the WEM which had a significant impact on electricity generators and generated substantial price differences within the market. From time to time, the Argentine Government intervened in this sector, by, for example, granting temporary nominal margin increases, proposing a new social tariff regime for residents of poverty-stricken areas, removing discretionary subsidies, creating specific charges to raise funds that were transferred to government-managed trust funds that finance investments in generation and distribution infrastructure and mandating investments for the construction of new generation plants and the expansion of existing transmission and distribution networks.

On January 27, 2017, the SEE issued Resolution No. 19/2017 which modified the remuneration scheme approved by Resolution No. 22/2016, improving the revenue of generators. See “Item 4. The Argentine Energy Sector—Remuneration Scheme for Generation Not Covered by Contracts—SEE Resolution No. 19/2017: February 2017 - February 2019”. In 2019, the SRRYME issued Resolution No. 1/19 establishing a new remuneration scheme for energy generation. This new regime has, in general, a negative impact on the revenues of generating units that do not have the benefit of a special regime (e.g. Energía Plus or MATER) or a contract with CAMMESA, particularly, over older TG and TV units (such as those that are installed in CPB and CTG), as it has decreased the prices for capacity and generated/operated energy. Moreover, the new regime introduced a 50% discount on the capacity and energy remuneration in the event that the generator had assumed its own supply of fuel and, when dispatched, lacked such fuel. We cannot assure that future remuneration scheme will not have an adverse effect on our operational results. Regarding the spot price for electricity power, on February 27, 2020, the Secretariat of Energy issued Resolution No. 31/20, which modified –retroactively, from February 1, 2020 onwards certain aspects of the remuneration scheme established by Resolution (SRRYME) No. 1/19.

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On November 28, 2017, through Resolution SEE No. 1085/17, a new scheme that transferred the cost of electricity transport to the users was enacted. Generators pay for the connection and operation costs of their own connection through a special charge determined by the SEE.

During 2017, the Argentine Government, through the relevant agencies, enacted several resolutions to establish the penalties regime and adjust tariffs. On February 1, 2017, the RTI process was completed and a new tariff scheme for the following five-year period was enacted. However, the aforementioned Social Solidarity and Productive Reactivation Law (Law 27,541) established a new tariff revision.

Notwithstanding the recent measures adopted, 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.

Electricity distributors, generators and transmitters were severely affected by the emergency measures adopted during the economic crisis, many of which remain in effect

Distribution and transmission tariffs include a regulated margin that is intended to cover the costs of distribution or transmission, as applicable, and provide an adequate return. Generators, which mostly depend on sales made to the spot market (the market created by the supply and demand of energy available for immediate delivery), used to have stable prices and were able to reinvest their profits to become more efficient and achieve better margins. Under the Convertibility Regime, which established a fixed exchange rate of one Peso per U.S. Dollar, distribution and transmission tariffs and electricity spot prices were calculated in U.S. Dollars and distribution and transmission margins were adjusted periodically to reflect variations in U.S. inflation indexes. However, the Public Emergency Law, which came into effect in January 2002, froze all margins, revoked all margin adjustments provisions and converted tariffs into Argentine Pesos at a rate of Ps.1.00 per US$1.00. These measures, coupled with the effect of high inflation and the devaluation of the Peso, led to a decline in revenues and an increase of costs in real terms, which could no longer be recovered through margin adjustments or market price-setting mechanisms. This situation, in turn, led many public utility companies, including Edenor, to suspend payments on their commercial debt (which continued to be denominated in U.S. Dollars despite the revenues being in Pesos), effectively preventing these companies from obtaining further financing in the domestic or international credit markets and making additional investments.

In the past, the Argentine Government granted temporary and partial relief to some distribution companies, including limited increases in distribution margins, a temporary cost adjustment mechanism which was not fully implemented and the ability to apply certain additional charges to customers.

Although as of the date of this annual report, the Argentine Government under the Macri administration completed the process after RTI for distributors, transmitters and transporters of gas and approved the new remuneration scheme for generators and the declaration of emergency expired and was not renewed (see “Item 4. The Argentine Energy Sector —Remuneration Scheme for Generation Not Covered by Contracts —SEE Resolution No. 19/2017: February 2017 - February 2019”and “SRRYME Resolution No. 1/19: March 2019 - January 2020” and “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Operational results—Electricity prices and tariffs”), the different measures taken by the Fernandez administration described in the previous risk factors imply a return of the direct intervention of the Argentine Government in the energy sector. We cannot affirm that new emergency or intervention measures will not be issued or the depth of their impact on our financial condition and operational results. Furthermore, we cannot assure that these recent measures will be sufficient to address the structural problems created for our Company by the economic crisis and in its aftermath. Our inability to cover the costs or to receive an adequate return on our asset base may further adversely affect our financial condition and operational results.

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Electricity demand may be affected by tariff increases, which could lead distribution companies, such as Edenor, to record lower revenues

From 2013 through 2018, electricity demand in Argentina increased by 6%, which in part reflects the relative low cost, in real terms, of electricity to users due to the freezing of distribution margins, the establishment of subsidies in the purchase price of energy and the elimination of the inflation adjustment provisions in distribution concessions coupled with the devaluation of the Peso and inflation through 2018.

We cannot make any assurances that tariff increases made under the previous administration or any future increases in the cost of electricity will not have a material adverse effect on electricity demand or result in a decline in collections from users. In this respect, we cannot assure that these measures or any future measure will not lead electricity companies, like Edenor, to record lower revenues and operational results, which may, in turn, have a material adverse effect on the market value of our ADSs.

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, which in turn could result in customer complaints and substantial fines for any interruptions

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, in 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 2017 and 2018, which would increase the installed capacity in the coming years, 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.

Additionally, according to Argentine law, distribution companies such as Edenor are responsible towards their customers for any interruption in the supply of electricity. Consequently, customers can direct their claims to the distribution companies. Also, distribution companies are subject to fines and penalties for service disruptions caused by energy shortages, unless the respective Argentine authorities determine that energy shortages constitute force majeure events. As a result, we could face user claims and fines and penalties for service disruptions caused by energy shortages unless the relevant Argentine authorities determine that energy shortages constitute force majeure. Additionally, disruptions in the supply of electricity could expose us to intervention by the Argentine Government, which warned of such possibility during the blackouts of December 2013 (which resulted from an increase in demand for electricity). We cannot affirm that we will not experience a lack in the supply of energy or that such claims, fines, penalties 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.

Risks Relating to Our Generation Business

There are electricity transmission constraints in Argentina that may prevent us from recovering the full marginal cost of our electricity, 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. While under the remuneration scheme established by SEE Resolution No. 19/2017, such transmission constraints should not affect the price that is paid to the generator, nonetheless our dispatch may be affected. 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.

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Changes in regulations governing the dispatch of generators may affect our generators

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. Such modifications or any other modifications under the emergency established by Decree No. 134/15 or any other measures may result in a lower dispatch of our generators and, in turn, could adversely affect our operational results and financial conditions.

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. Since 2012, a significant number of WEM agents – mostly distributors, including Edenor - defaulted in the payment of amounts owed to the WEM or failed to pay in a timely manner to CAMMESA (see “Edenor may not have the ability to raise the funds necessary to repay its commercial debt with CAMMESA, its major supplier ”), which adversely affected the ability of CAMMESA to meet its own payment obligations to generators or to pay them in a timely manner. This situation led to the creation of the Fondo Transitorio de Recomposición de Cobranzas”– SE Notes No. 7588/12, 8147/12 and 8476/12 (the Transitory Recovery Fund), by means of which the SE instructed CAMMESA to collect the charges and interest accrued from distributors’ defaults and renegotiate the terms of the payment of the defaulted amounts. 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.

Resolution ME&M No. 197/2016, instructed CAMMESA to negotiate payment plans with distributors and large users for the repeal of injunctions that had suspended tariff increases. It further ordered that the payment plans be in four monthly installments, equal and consecutive free of interest or surcharges related to non-payment. The first installment expired in October 2016. Similarly, with respect to the amounts not paid by the users of Edenor and Edesur, it was also provided that such amounts were to be paid in four installments under the same conditions.

We cannot provide any assurance that any measures aimed at reducing the debt of distributors and large users 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. 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 70 days instead (except for RenovAr agreements which are paid in a timely manner and have FODER’s guarantee).

Furthermore, as a consequence of the suspension of the incorporation or renewal of contracts in the term market (except for Energy Plus Program and MATER), the revenues of electricity generators will depend on the payments received from CAMMESA.

The inability of generators, including us and certain of our subsidiaries, to collect their credits from CAMMESA 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

 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.

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The statute also includes tax and other benefits for new renewable energy projects. As of December 31, 2019, 6% 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 Major Large Users (as defined below) 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 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 were unable to purchase gas at prices that are favorable to us, if the supply of gas was reduced or if CAMMESA did 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, some of our generation units are included in the “Energy Plus” program under SE Resolution 1,281/2006 and/or have executed WEM supply agreements under SE Resolution No. 220/2007, and both regulations require the generator to ensure the committed capacity with its own fuels through the execution of firm natural gas and transport contracts.

Moreover, WEM supply agreements under SEE Resolution No. 21/16 and SEE Resolution 287/17 also require that the generator covers its fuel supply. 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.

 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, SE Resolution No. 12/2019 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.

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

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 and SEE Resolution 287/17 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. Moreover, under the WEM supply agreement under SEE Resolution 287/17 for the Genelba Plus Combined Cycle, a breach of the obligation to enter into commercial operations by a specified date entitles CAMMESA to apply

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	penalties that may adversely impact the revenues derived from such agreements, which in turn may adversely affect our operational results. If the delay in the entry into commercial operations extends for more than 180 days from the specified date, the relevant PPAs may be automatically terminated by CAMMESA who may enforce the performance guarantee granted under such contract. In such event the project will be remunerated according to the general WEM remuneration scheme and therefore could negatively impact our operational results.
(ii)	a breach of the energy delivery commitments set forth in Greenwind’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.
(iii)	A breach of PEPE IV 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 the enforcement of the performance guarantees granted in connection with these projects. On November 2019, CAMMESA initiated the enforcement procedure. However, the parties have reached an agreement to suspend such procedure until April 30, 2020. See “Item 4. Our Generation Business—Renewable Energy”.

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 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.

Revenues from Greenwind, PEPE II and PEPE III 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 and PEPE III’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 WEM Large Users (PEPE II and PEPE III). 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 and PEPE III’s client).

Moreover, PEPE II and PEPE III 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 31/20 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 mechanismby 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 MATER projects and, therefore, potentially affect our operational results.

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 a number of ways, which we cannot fully predict. For example, hydrological conditions that result in a low supply of electricity in Argentina could lead to, among others, the implementation of broad electricity conservation programs, including mandatory reductions in electricity generation or consumption. 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.

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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, we 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.

CPB could be exposed to third-party claims on real property utilized for its 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 favor of CPB 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 CPB. 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, CPB sued the Province of Buenos Aires seeking the creation of the administrative easements in favor of CPB. CPB has 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, CPB 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 CPB 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.

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This risk extends to our thermal generation plant Ingeniero White (“CTIW”) which is constructed on CPB’s real property.

CPB could be subject to fines and penalties for not having a concession for the use of seawater for the refrigeration of its generation units

CPB uses seawater to refrigerate its generation units. According to applicable provincial law, such activity requires a concession to be granted by the provincial government. CPB consulted the regulatory authorities who informed that, according to their files, no such concession has been granted to CPB. The penalties for such infringement may vary from the application of a maximum Ps.50,000 fine to the closing of the plant. While CPB considers 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.

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 31/2020).

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 temporary dispatch surcharge and for GUDIs of 0 Ps./MWh. The CMIEE implies an indirect maximum limit to the price that generators under the Energy Plus Program may charge. The detrimental effect that such limits could have on our generators could be exacerbated if the Peso continues to devalue. As a consequence, if the CMIEE is not adjusted or a higher devaluation of the Peso occurs, this could result in a decline in prices charged by our generators under their Energy Plus Program contracts or in a discontinuance of the Energy Plus contracts, forcing such generators to sell the capacity and energy unsold in the spot market at lower prices.

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 operations may not be effectively resolved or similar events may occur in our energy projects.

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 are taking 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, 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.

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Risks Relating to our Distribution of Energy Business

Failure or delay to negotiate further improvements to Edenor’s tariff structure, including increases in Edenor’s distribution margin, and/or to have Edenor’s tariffs adjusted to reflect increases in Edenor’s distribution costs in a timely manner, or at all, affected Edenor’s capacity to perform its commercial obligations and could also have a material adverse effect on Edenor’s ability to perform its financial obligations

Since the execution of the Adjustment Agreement and as required by the Argentine Government, Edenor was engaged in an RTI with the ENRE through February 1, 2017. 

The Adjustment Agreement contemplated a cost adjustment mechanism for the transitional period during which the RTI process was being conducted. This mechanism, known as the Cost Monitoring Mechanism (CMM), required the ENRE to review our actual distribution costs every six months (in May and November of each year) and adjust our distribution margins to reflect variations of 5% or more in our distribution cost base. We could also request that the ENRE apply the CMM at any time that the variation in our distribution cost base was at least 10% or more. Any adjustments, however, were subject to the ENRE’s assessment of variations in our costs, and the ENRE’s approval of adjustments were not sufficient to cover our actual incremental costs in a timely manner. During such time, even when the ENRE approved adjustments to Edenor’s tariffs, there was a lag between the time when we actually experienced increases in Edenor’s distribution costs and the time when Edenor received increased income following the corresponding adjustments to our distribution margins pursuant to the CMM.

In January 2016, the ME&M issued Resolution No. 7/16, pursuant to which the ENRE implemented a VAD adjustment to the tariff schedule on account of the future RTI in effect as of February 1, 2016.

In addition, such resolution: (i) abrogated the PUREE; (ii) repealed Resolution No. 32/15 as from the date the ENRE resolution implementing the new tariff schedule becomes effective; (iii) discontinued the application of mechanisms that imply the transfer of funds from CAMMESA in the form of loan agreements with CAMMESA; (iv) ordered the implementation of the actions required to terminate the trusts created pursuant to Resolution No. 347/12 of the ENRE and (v) prohibited the distribution of dividends in accordance with Section 7.04 of the Adjustment Agreement.

However, pursuant to Resolution No. 7/16, the ENRE issued Resolution No. 1/16 establishing a new tariff structure, which remained in force (with certain suspensions as a result of injunctions, which are no longer in effect) until February 2017, when the RTI process was completed.

Prior to the completion of the RTI process, several regulatory mechanisms, programs or changes were implemented from time to time by the ENRE to adjust Edenor’s tariffs to reflect increased costs. Any requested adjustments were usually subject to the ENRE’s assessment of variations in Edenor’s costs, and not sufficient to cover Edenor’s actual incremental costs in a timely manner.

On April 1, 2016, the ENRE issued Resolution No. 55/16, which approved the program for the review of the distribution tariff scheme, establishing the criteria and methodologies for completing the RTI process.

On September 5, 2016, pursuant to Resolution No. 55/16, Edenor submitted its rate schedule proposal for the following five-year period. On October 28, 2016, a public hearing was held to provide information and listen to the public opinion on the RTI.

The RTI was completed on February 1, 2017, on which date the ENRE issued Resolution No. 63/17, through which it approved a new tariff scheme that established our new distribution added value (VAD) for the following five-year period. On January 31, 2018, the ENRE issued Resolution Nº 33/18 approving the new distribution cost for Edenor applicable from February 1, 2018 and the new tariff scheme applicable to Edenor. On July 31, 2018, the ENRE issued Resolution No. 208/18, pursuant to which it approved, the CPD for January 2018 through June 2018 of which 7.93% was to be applied as of August 1, 2018, and 6.51% in six consecutive monthly installments as of February 1, 2019. The CPD amounted to 15.85%. For more information, see “Item 4. Our Distribution of Energy Business”.

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However, if Edenor is not able to recover all future cost increases and have them reflected in its tariffs, and/or if there is a significant lag of time between when it incurs the incremental costs and when it receives increased income, Edenor may be unable to comply with its financial obligations and may suffer liquidity shortfalls and need to restructure its debt to ease its financial condition, any of which, individually or in the aggregate, could have a material adverse effect on our business and operational results and may cause the value of our ADSs or our common shares to decline.

Edenor’s distribution tariffs may be subject to challenges by Argentine consumer and other groups

In the recent years, Edenor’s tariffs have been challenged by Argentine consumer associations, such as the action brought against Edenor in December 2009, by an Argentine consumer association, (Unión de Usuarios y Consumidores), seeking to annul certain retroactive tariff increases, which was ultimately dismissed by the Argentine Supreme Court of Justice on October 1, 2013.

In May 2016, Edenor was notified by several courts of the Province of Buenos Aires of certain injunctions granted to individual and collective users against Resolution No. 6/16 and Resolution No. 1/16 issued by the ENRE (which authorized our new tariff schedule as from February 2016). Consequently, the then applicable tariff schedule, which included the WEM prices established by Resolution No. 6/16, was not applied during certain periods in 2016 (i) to the entire concession area as a result of the injunctions issued in the “Abarca” case and (ii) to the districts of “Pilar” and “La Matanza” where injunctions remained in effect until October 24 and November 11, 2016, respectively, when they expired. Therefore, as of those dates tariff increases have been applied to all users. If any future legal challenge were successful and prevented Edenor from implementing any tariff adjustments granted by the Argentine Government, Edenor could face a decline in collections from its users, and a decline in its operational results, which could have a material adverse effect in our financial condition and the market value of our ADSs or our common shares.

Our distribution business has been, and may continue to be, subject to fines and penalties that could have a material adverse effect on our financial condition and operational results

We operate in a highly regulated environment and our distribution business has been and in the future may continue to be subject to significant fines and penalties imposed by regulatory authorities, including for reasons outside our control, such as service disruptions attributable to problems at generation facilities or in the transmission network that result in a lack of electricity supply. Since 2001, the amount of fines and penalties imposed on our distribution business has increased significantly. As of December 31, 2019 and 2018, our accrued fines and penalties totaled US$121 million and US$187 million, respectively (considering adjustments made to fines and penalties following the ratification of the Adjustment Agreement and recent regulation). See Item 4. Our Distribution of Energy Business—Empresa Distribuidora y Comercializadora Norte S.A. (Edenor) —Fines and Penalties”.

On October 19, 2016, pursuant to Note No. 123,091 the ENRE established the average rate values (Ps./kWh) to be applied as from December 2012, for calculating the penalties payable to the Argentine Government. In accordance with the terms of Edenor’s Concession Agreement, such values should correspond to the average sale price of energy charged to users. Since the amounts set forth in the note were not consistent with the principle contained in Edenor’s Concession Agreement, on November 1, 2016, Edenor submitted a claim to the ENRE requesting that the amounts in Note No. 123,091 be modified to reflect the amounts contained in the Edenor’s Concession Agreement. As of the date of this annual report, Edenor has received the response from the ENRE (Note No. 129,061), which clarified that the increases or adjustments are not applicable, and only the values paid by the customers should be considered.

On February 1, 2017, the ENRE issued Resolution No. 63/17, through which it approved new parameters related to the quality standards with the purpose of achieving an acceptable quality level by the end of the 2017-2021 period. In this regard, the ENRE established a penalty regime to be applied in the event of non-compliance with the requisite quality rates.

On March 29, 2017, through Note No. 125,248 the ENRE established a new methodology for the calculation of fines and penalties, determining that they must be valued according to the kWh values in effect as of the first day of the six-month period during which the event giving rise to the penalty occurred or the kWh values in effect as of the day of the occurrence of the event in the case of penalties arising from specific events.

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In addition, fines and penalties, accrued and not imposed during the transition period of the Adjustment Agreement must be updated using the CPI that the Central Bank uses to elaborate the Multilateral Real Exchange Rate Index, corresponding to the month prior to the six-month period during which the event giving rise to the penalty occurred or the month prior to that on which the specific penalty event occurred, till the previous month of the day on which the penalty was imposed. Those fines and penalties accrued and imposed since the date of issuance of the Note No. 120,151 through the completion of the RTI on February 1, 2017 (i.e., the period between April 2016 and February 2017) must also be updated using the CPI.

We cannot assure you that our distribution segment will not incur significant fines in the future, which could have a material adverse effect on our financial condition and operational results, and the market value of our ADSs and our common shares.

If Edenor is unable to control its energy losses, its operational results could be adversely affected

Edenor’s distribution concession does not allow our energy distribution business to pass on to Edenor’s users the cost of additional energy purchased to cover any energy losses that exceed the loss factor contemplated by the concession, which is, on average, 10%. As a result, if our energy distribution business experiences energy losses in excess of those contemplated by the concession, we may record lower operating profits than we anticipate. Prior to the 2001 and 2002 economic crisis in Argentina, Edenor was able to reduce the high level of energy losses experienced at the time of the privatization down to the levels contemplated (and reimbursed) under the concession. However, during the last years, Edenor’s level of energy losses, particularly Edenor’s non-technical losses, started to grow again, in part as a result of the increase in poverty levels and, in turn, in the number of delinquent accounts and fraud. Although Edenor continues to make investments to reduce energy losses, these losses continue to exceed the average 10% loss factor contemplated by the concession, and based on the current tariff schedule and the economic turmoil, we do not expect these losses to decrease in the near term. Energy losses in our distribution business amounted to 19.9% in 2019, 18.2% in 2018 and 17.1% in 2017. We cannot affirm that energy losses will not continue to increase in future periods, which may lead to lower margins in our distribution segment and could adversely affect our financial condition and consolidated operational results and the market value of our shares or our ADSs.

The Argentine Government could foreclose on its pledge over Edenor’s Class A common shares under certain circumstances, which could have a material adverse effect on our business and financial condition

Pursuant to Edenor’s Concession Agreement and the provisions of the Adjustment Agreement, the Argentine Government has the right to foreclose on its pledge over Edenor’s Class A common shares and sell these shares to a third-party buyer if:

· the fines and penalties incurred in any given year exceed 20% of Edenor’s gross energy sales, net of taxes, which corresponds to Edenor’s energy sales;

· Edenor repeatedly and materially breaches the terms of its distribution concession and does not remedy these breaches upon the request of the ENRE;

· Edenor’s controlling shareholder, creates any lien or encumbrance over Edenor’s Class A common shares (other than the existing pledge in favor of the Argentine Government);

· Edenor or Edenor’s controlling shareholder obstructs the sale of Class A common shares at the end of any management period under our distribution concession;

· Edenor’s controlling shareholder fails to obtain the ENRE’s approval in connection with the disposition of Edenor’s Class A common shares;

· Edenor’s shareholders amend its articles of incorporation or voting rights in a way that modifies the voting rights of the Class A common shares without the ENRE’s approval; and

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· Edenor or any existing shareholders or former shareholders of Edenor’s controlling shareholder who have brought a claim against the Argentine Government in the ICSID do not desist from such ICSID claims following completion of the RTI and the approval of a new tariff regime.

On February 1, 2017, the ENRE issued Resolution No. 63/17 establishing the new tariff scheme resulting from the completion of the RTI process, for the following five-year period. In accordance with the provisions of the Adjustment Agreement, Electricidad Argentina S.A. (“EASA”) (currently merged into Pampa Energía S.A.) and EDF International S.A. (“EDFI”) withdrew their ICSID claim, and on March 28, 2017, the ICSID acknowledged the discontinuance of the procedure.

In 2019, our fines and penalties remained below 10% of our gross energy sales. See Item 4. Our Distribution of Energy Business—Empresa Distribuidora y Comercializadora Norte S.A. (Edenor) —Fines and Penalties”.

If the Argentine Government were to foreclose on its pledge over Edenor’s Class A common shares, pending the sale of those shares, the Argentine Government would also have the right to exercise the voting rights associated with such shares. In addition, the potential foreclosure by the Argentine Government on its pledge on Edenor’s Class A common shares could be deemed to constitute a change of control under the terms of Edenor’s Senior Notes due 2022. See “Edenor may not have the ability to raise the funds necessary to finance a change of control offer as required by Edenor’s Senior Notes due 2022.” If the Argentine Government forecloses on the pledge over Edenor’s Class A common shares, our operational results and financial condition could be significantly affected and the market value of our shares and ADSs could also be affected.

Default by the Argentine Government could lead to termination of Edenor’s distribution concession, and have a material adverse effect on our business and financial condition

If the Argentine Government breaches its obligations in such a way that Edenor cannot comply with its obligations under its distribution concession or in such a way that Edenor’s service is materially affected, Edenor may request the termination of its distribution concession, after giving the Argentine Government 90 days’ prior notice in writing. Upon termination of Edenor’s distribution concession, all of its assets used to provide the electricity distribution service would be transferred to a new state-owned company to be created by the Argentine Government, whose shares would be sold in an international public bidding procedure. The amount obtained in such bidding would be paid to Edenor, net of the payment of any debt owed by Edenor to the Argentine Government, plus an additional compensation established as a percentage of the bidding price, ranging from 10% to 30% depending on the management period in which the sale occurs. Any such default could have a material adverse effect on our business and financial condition.

Edenor may be unable to import certain equipment to meet the growing demand for electricity, which could lead to a breach of Edenor’s concession and could have a material adverse effect on its operations and financial position

Certain exchange controls established by the Argentine Government and future restrictions on imports that may be adopted in the future could limit or delay Edenor’s ability to purchase capital goods that are necessary for its operations (including carrying out specific projects). Under Edenor’s concession, Edenor is obligated to satisfy all of the demand for electricity originated in our concession area, maintaining at all times certain service quality standards that have been established for its concession. If Edenor is not able to purchase significant capital goods to satisfy all of the demand or suffers unexpected delays in the import process, it could face fines and penalties, which may, in turn, adversely affect our activity, financial position, operational results and/or the market value of our ADSs and common shares.

Edenor employs a largely unionized labor force and could be subject to an organized labor action, including work stoppages that could have a material effect on their business

As of December 31, 2019, approximately 83% of Edenor employees were union members. Although Edenor’s relations with unions are currently stable and Edenor has had an agreement in place with the two unions representing its employees since 1995, we cannot assure you that Edenor will not experience work disruptions or stoppages in the future, which could have a material adverse effect on our business and revenues. We cannot assure you that Edenor will be able to negotiate salary agreements or labor conditions on the same terms as those currently in effect, or that Edenor will not be subject to strikes or work stoppages before or during the negotiation process. If Edenor is unable to negotiate salary agreements or if Edenor is subject to demonstrations or work stoppages, our operational results, financial conditions and the market value of our ADSs and common shares could be materially adversely affected.

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Edenor could incur material labor liabilities in connection with outsourcing in our distribution business that could have an adverse effect on our business and operational results

Edenor outsources a number of activities related to our distribution business to third-party contractors in order to maintain a flexible cost base. As of December 31, 2019, Edenor had approximately 5,588 third-party employees under contract in its distribution business. Although Edenor has very strict policies regarding compliance with labor and social security obligations by contractors, Edenor is not in a position to ensure that contractors will not initiate legal actions to seek indemnification from us based upon a number of judicial rulings issued by labor courts in Argentina which have recognized joint and several liability between the contractor and the entity to which it is supplying services under certain circumstances. We cannot make any assurances that such proceedings will not be brought against Edenor or that the outcome of such proceedings would be favorable to Edenor. If we were to incur material labor liabilities in connection with the outsourcing of our distribution business, such liabilities could have an adverse effect on our financial condition and consolidated operational results and the market value of our shares and ADSs.

In the event of an accident or other event not covered by our insurance, Edenor could face significant losses that could materially adversely affect our business and operational results

As of December 31, 2019, Edenor’s physical assets were insured for up to US$1,604.3 million.

However, Edenor does not carry insurance coverage for losses caused by its network or business interruption, including for the loss of Edenor’s concession. Although Edenor believes its insurance coverage is commensurate with standards for the distribution industry, no assurance can be given of the existence or sufficiency of risk coverage for any particular risk or loss. If an accident or other event occurs that is not covered by Edenor’s current insurance policies, Edenor may experience material losses or have to disburse significant amounts from its own funds, which may have a material adverse effect on our financial condition and consolidated operational results and the market value of our shares and ADSs.

A substantial number of Edenor’s assets are not subject to attachment or foreclosure and the enforcement of judgments obtained against us by Edenor’s shareholders may be substantially limited

A substantial number of Edenor’s assets are essential to the public service Edenor provides. Under Argentine law, as interpreted by the Argentine courts, assets which are essential to the provision of a public service are not subject to attachment or foreclosure, whether as a guarantee for an ongoing legal action or in aid of enforcement of a court judgment. Accordingly, the enforcement of judgments obtained against Edenor by Edenor’s shareholders may be substantially limited to the extent Edenor’s shareholders seek to attach those assets to obtain payment on their judgment.

The loss of exclusivity to distribute electricity in Edenor’s service area may be adversely affected by technological or other changes in the energy distribution industry, which would have a material adverse effect on our business

Although Edenor’s distribution concession grants Edenor the exclusive right to distribute electric energy within Edenor’s service area, this exclusivity may be revoked in whole or in part if technological developments would make it possible for the energy distribution industry to evolve from its present condition as a natural monopoly into a competitive business. In no case does the complete or partial revocation of Edenor’s exclusive distribution rights entitle Edenor to claim or to obtain reimbursement or indemnity. Although, to our knowledge, there are no current projects to introduce new technologies in the medium or long-term, which may reasonably modify the composition of the electricity distribution business, we cannot assure you that future developments will not enable competition in Edenor’s industry that would adversely affect the exclusivity right granted by Edenor’s concession. Any total or partial loss of Edenor’s exclusive right to distribute electricity within Edenor’s service area would likely lead to increased competition, and result in lower revenues in our distribution segment, which could have a material adverse effect on our financial condition and consolidated operational results and the market value of our shares and ADSs.

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A potential nationalization or expropriation of 51% of Edenor’s capital stock, represented by its Class A shares, may limit the capacity of the Class B common shares to participate in the Board of Directors

As of the date of this annual report, the ANSES owned shares representing 26.8% of the capital stock of Edenor and appointed five Class B directors in the last shareholders’ meeting. The remaining directors were appointed by the Class A shares.

If the Argentine Government were to expropriate 51% of Edenor’s capital stock, represented by Edenor’s Class A shares, the Argentine Government would be the sole holder of the Class A shares and the ANSES would hold the majority of the Class B shares. Certain strategic transactions require the approval of the holders of the Class A shares. Consequently, the Argentine Government and the ANSES would be able to determine substantially all matters requiring approval by a majority of Edenor’s shareholders, including the election of a majority of Edenor’s directors, and would be able to direct Edenor’s operations.

If the Argentine Government nationalizes or expropriates 51% of Edenor’s capital stock, represented by its Class A shares, our operational results and financial condition could be adversely affected and this could cause the market value of our ADSs and Edenor’s ADSs and Class B common shares to decline.

Edenor may not have the ability to raise the funds necessary to repay its commercial debt with CAMMESA, its major supplier

On May 10, 2019, Edenor entered into with the Energy Government Secretariat, on behalf of the Federal Government, the Agreement on the Regularization of Obligations, pursuant to which the parties agreed to end pending reciprocal claims during the 2006-2016 transitional period (the “Agreement on the Regularization of Obligations”). Accordingly, pending obligations with the MEM for electrical energy purchases during such period were fully compensated. However, as a result of (i) the enactment of the Social Solidarity and Productive Reactivation Law (in the framework of the public emergency), (ii) the subsequent instruction to Edenor to refrain from applying, as from January 1, 2020, the Electricity Rate Schedules Maintenance Agreement entered into between Edenor and the National State on September 19, 2019 and (iii) the prevailing macroeconomic situation, aggravated by the recent effects of COVID-19 outbreak (See For more information, please see (“—Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”., Edenor will not have the ability to raise the funds necessary to repay its commercial deb with CAMMESA.

All of Edenor’s outstanding financial indebtedness contains bankruptcy, reorganization proceedings and expropriation events of default, and Edenor may be required to repay all of its outstanding debt upon the occurrence of any such events

As of the date of this annual report, US$132.6 million of Edenor’s financial debt was represented by its Senior Notes due 2022. Under the indenture for the Senior Notes due 2022, certain expropriation and condemnation events with respect to Edenor may constitute an event of default, which if declared could trigger the acceleration of Edenor’s obligations under the notes and require Edenor to immediately repay all such accelerated debt. In addition, all of Edenor’s outstanding financial indebtedness contains certain events of default related to bankruptcy and voluntary reorganization proceedings (concurso preventivo). If Edenor is not able to comply with certain payment obligations as a result of its current financial situation, and if the requirements set forth in the Argentine Bankruptcy Law No. 24,522 are met, any creditor, or even Edenor, could file for its bankruptcy, or Edenor could file for concurso preventivo. In addition, all of Edenor’s outstanding financial indebtedness also contains cross-default provisions or cross-acceleration provisions that could cause all of Edenor’s debt to be accelerated if the debt containing expropriation or bankruptcy and/or reorganization proceeding events of default goes into default or is accelerated. In such a case, Edenor would expect to actively pursue formal waivers from the corresponding financial creditors to avoid such potential situation, but in case those waivers are not timely obtained and immediate repayment is required, Edenor could face short-term liquidity problems, which could adversely affect our operational results and cause the market value of our shares and ADSs and our common shares to decline.

Edenor may not have the ability to raise the funds necessary to finance a change of control offer as required by Edenor’s Senior Notes due 2022

As of the date of this annual report, US$132.6 million of Edenor’s financial debt was represented by its Senior Notes due 2022. Under the indenture for the Senior Notes due 2022, if a change of control occurs, Edenor must offer to repurchase any and all such notes that are outstanding at a purchase price equal to 100% of the aggregate principal amount of such notes, plus any accrued and unpaid interest thereon and additional amounts, if any, through the purchase date. Edenor may not have sufficient funds available to make the required repurchases of the Senior Notes due 2022 upon a change of control. If Edenor fails to repurchase such notes in circumstances that may constitute an event of default under the indenture, it may in turn trigger cross-default provisions in other of Edenor’s debt instruments then outstanding, our operational results could be adversely affected and the market value of our ADSs and common shares could decline.

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

Edenor revenues are mainly collected in Pesos. Although (i) the remuneration scheme set forth by the Electric Energy Secretariat (“SEE”) Resolution No. 1/19, establishes U.S. Dollar-denominated prices, the payment is made in Pesos by applying the Central Bank’s exchange rate effective on the day before the expiration date (although this remuneration scheme was significantly altered by the Energy Secretariat Resolution No. 31/20 which came into force in February 2020 and converted the remuneration scheme applied to energy sold in the Argentine spot market into pesos), and (ii) the remuneration scheme for other contracts with CAMMESA established U.S. Dollar -denominated prices but the payment is made in Pesos by applying the Central Bank’s exchange rate effective on the last business day of the month of the applicable transaction, adjusted through credit or debit notes, as appropriate, to consider the Central Bank’s exchange rate of the day before the expiration date, in accordance with CAMMESA’s procedures. As a result, we are exposed to an exchange rate risk between the collection date and the payment date (in the event CAMMESA does not pay at the expiration date) of U.S. Dollars-denominated financial indebtedness. In addition, a significant portion of our existing financial indebtedness is denominated in U.S. Dollars, which exposes Edenor to the risk of loss from the depreciation of the Peso. During 2019, Edenor’s hedging contracts did not cover all of its exposure to such depreciation. If Edenor is not able to effectively hedge all or a significant portion of its currency risk exposure, a depreciation of the Peso, may significantly increase Edenor’s debt service burden, which, in turn, may have a material adverse effect on our financial condition and results of operations.

The New York Stock Exchange and/or the Buenos Aires Stock Exchange may suspend trading and/or delist Edenor’s ADSs and Class B common shares, upon the occurrence of certain events relating to Edenor’s financial situation

The NYSE and/or the BASE may suspend and/or cancel the listing of Edenor’s ADSs and Class B common shares, respectively, in certain circumstances, including upon the occurrence of certain events relating to Edenor’s financial situation. For example, the NYSE may decide such suspension or cancellation if its shareholders’ equity becomes negative.

The NYSE may in its sole discretion determine on an individual basis the suitability for continued listing of an issue in the light of all pertinent facts. Some of the factors mentioned in the NYSE Listed Company Manual, which may subject a company to suspension and delisting procedures, include: “unsatisfactory financial conditions and/or operating results,” “inability to meet current debt obligations or to adequately finance operations,” and “any other event or condition which may exist or occur that makes further dealings or listing of the securities on the NYSE inadvisable or unwarranted in the opinion of NYSE.”

The BASE may cancel the listing of Edenor’s Class B common shares if it determines that Edenor’s shareholders’ equity and Edenor’s financial and economic situation do not justify Edenor’s access to the stock market or if the NYSE cancels the listing of Edenor’s ADSs.

We cannot assure you that the NYSE and/or BASE will not commence any suspension or delisting procedures in light of Edenor’s financial situation, including if Edenor’s shareholders’ equity becomes negative. A delisting or suspension of trading of Edenor’s ADSs or Class B common shares by the NYSE and/or the BASE, respectively, could adversely affect Edenor’s results of operations and financial conditions and cause the market value of Edenor’s ADSs and its Class B common shares to decline.

Changes in weather conditions or the occurrence of severe weather (whether or not caused by climate change or natural disasters), could adversely affect Edenor’s operations and financial performance

Weather conditions may influence the demand for electricity, Edenor’s ability to provide it and the costs of providing it. In particular, severe weather may adversely affect Edenor’s operational results by causing significant demand increases, which Edenor may be unable to meet without a significant increase in operating costs. This could strongly impact the continuity of Edenor’s services and its quality indicators. Furthermore, any such disruptions in the provision of Edenor’s services could expose Edenor to fines and orders to compensate those customers affected by any such power cuts, as has occurred in the past. Edenor’s financial condition, operational results and cash flows could therefore be negatively affected by changes in weather conditions and severe weather.

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The Argentine Government signed an agreement with the Province of Buenos Aires and the City of Buenos Aires for the transfer of the public service of electricity distribution

Pursuant to Law No. 27,467, which enacted the 2019 Federal Budget of Expenditures and Resources, the Executive Branch was instructed to promote the transfer of Edenor’s jurisdiction to the joint jurisdiction of the Province of Buenos Aires and the City of Buenos Aires as of January 1, 2019 and the creation of a new oversight body. On February 28, 2019, the Argentine Government, the Province of Buenos Aires and the City of Buenos Aires, entered into an agreement for the transfer of the public service of electricity distribution duly awarded to Edenor under the Concession Agreement (as defined below) entered into by the Argentine Government (including the Concession Agreement), to the joint jurisdiction of the Province of Buenos Aires and the City of Buenos Aires. Pursuant to such agreement, the Province of Buenos Aires and the City of Buenos Aires will create a new entity in lieu of the ENRE, in charge of controlling and regulating the distribution service. It was also agreed that the Argentine Government shall be the sole responsible for any and all debts and credits relating to the distribution service awarded to Edenor which cause is prior to February 28, 2019. As of the date of this annual report, there are certain major issues related to such transfer still to be defined, including, among others, (i) the continuation of the existing Concession Agreement as is; (ii) whether the federal legal and regulatory framework shall continue to apply or not; and (iii) the resolution of claims and debts between Edenor and the Argentine Government resulting from the contractual transition period ended on January 31, 2016. However, on December 21, 2019, the Argentine Congress passed the Social Solidarity and Productive Reactivation Law which, among other things, suspended the transfer of Edenor’s jurisdiction to the jurisdiction of the Province of Buenos Aires and the City of Buenos Aires, with the ENRE reassuming the jurisdiction over the public service of electricity distribution provided by Edenor and Edesur. Although as of the date of this annual report such transfer is suspended, we cannot assure that such transfer or any action or omission from the transferees following the consummation of such transfer will not have an adverse effect on our business, financial condition or result of operations or would not have a negative impact on the market value of our ADSs and common shares.

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 have 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 the enactment of 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” (as amended by Law No. 27,007) provides for oil and gas concessions to remain in effect for 25, 30 or 35 years, depending on the concession, as from 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. The authority to extend the terms of current and new permits, concessions and contracts is of the province in which the relevant area is located (and the Argentine Government in respect of offshore areas beyond 12 nautical miles). In order to be eligible for an extension, any concessionaire and permit holder must (i) have complied with its obligations under the Hydrocarbons Law and the terms of the particular concession or permit, including evidence of payment of taxes and royalties, the supply of the necessary technology, equipment and labor force and compliance with various environmental, investment and development obligations, (ii) be producing hydrocarbons in the relevant concession area and (iii) submit an investment plan for the development of the areas as requested by the relevant authorities at least one year prior to the expiration of the original concession. In addition, concessionaires that request extensions under Law No. 27,007 have to pay additional royalties ranging from 3% to a maximum of 18%. Under the Hydrocarbons Law, non-compliance with these obligations and standards may also result in the imposition of fines and in the case of material breaches, following the expiration of applicable cure periods, the revocation of the concession or permit. 

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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.

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

A significant amount of our revenue is derived from sales of crude oil, oil products and natural gas. 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  (“OPEC”) 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 the COVID-19, resulted in a collapse of crude oil prices. The Brent registered the worst decline of the last three decades with a 30% decrease, and the West Intermediate Texas traded at negative prices. For more information, please see (“—Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”.

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 March 1, 2002, the Argentine Government imposed a withholding tax on exports of hydrocarbons, initially lasting five years, which was subsequently extended through 2017. This tax framework prevented us from benefiting from significant increases in international prices for oil, oil related products and natural gas, hindered us from offsetting sustained increases in costs related to the energy industry, and materially affected our competitiveness and operational results. On January 6, 2017, the Argentine Government did not extend the resolutions that imposed a withholding tax on exports of hydrocarbons.

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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.

We cannot affirm 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 the internal dispute for 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 (“—Developments relating to the novel coronavirus may have a material adverse impact on 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” and “Impact of the COVID-19 outbreak on our Operations”. ”. 

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.

Crude oil exports, as well as the export of most of our hydrocarbon products, currently require prior authorization from the SGE pursuant to Resolution No. 241-E/17, as amended. Companies seeking to export must first demonstrate that the local demand is satisfied or that an offer to sell the product to local purchasers has been made and rejected.

In addition, on March 21, 2017, Decree No. 192/2017 created the Oil and its Byproducts Import Operations Registry (the “Registry”) and provided that the MinEn would be responsible for controlling the Registry. The Registry covered the import of (i) crude oil and (ii) certain other specific byproducts (section 2 of the decree). The regulation established that any company that wished to perform such import operations was obligated to register such operation in the Registry and to obtain authorization from the MinEn before the import took place. This regime exempted any import by CAMMESA in order to supply power plants with the main purpose of technical supply to the SADI. On November 24, 2017, Decree No. 962/2017 provided that the need for the Registry was temporary and therefore, since December 31, 2017, the import operations related to crude oil, gasoline, and diesel oil included in Decree No. 192/2017 are no longer subject to prior registration.

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On August 22, 2018, the former ME&M issued Resolution No. 104/2018, which established a new procedure to obtain authorizations to export natural gas, later modified by Res. SSHC 284/19 through which the operative procedure of natural gas exports is approved, effective until September 30, 2021 (See “Item4. The Argentine Energy Sector—OIL & GAS REGULATORY FRAMEWORK—Regulations Specifically Applicable to the Gas Market ”).

These and any other export-import related 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 under our investment agreements could negatively affect our operational results

We have commitments to make certain investments 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.

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.

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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 (as defined below) and the Gas Plan II (as defined 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.

In connection with these government programs, we received US$7.50 per million BTU from the Argentine Government for the volume of natural gas that we produced in excess of the agreed threshold. As of the date of this annual report, we had only collected payments from the Argentine Government for December 2016 and three months of 2017. The Gas Plan I and the Gas Plan II of Pampa finished on December 31, 2017 and June 31, 2018 respectively.

On April, 3, 2018, ME&M Resolution No. 97/18 was issued approving the procedure to cancel the outstanding compensation and/or payments as of December 2017, regarding the Gas Plan I, Gas Plan II and Gas Plan III (as defined below). On May 2, 2018, we adhered to this procedure for the cancellation in 30 equal consecutive installments, payable as from January 1, 2019, of the amounts owed under the following programs: (i) Gas Plan I (Resolution No.1/13); (ii) the Gas Plan II (SE Resolution No. 60/13); and (iii) the Gas Plan III (ME&M Resolution No. 74/16).

On February 21, 2019, SGE Resolution No. 54/19 was published, cancelling the obligations arising from the provisions of the ME&M Resolution No. 97/18 through the issuance of public debt instruments. Consequently, on February 26, 2019, joint Resolution No. 21/2019 of the Secretariat of Finance and the Secretariat of Treasury was published, which provided for the issuance of Natural Gas Program Bonds denominated in US$, issued on February 27, 2019, for a term of two years and four months, without interest and with an amortization of 29 monthly and consecutive installments, the first installment representing 6.66% of the original nominal value, the following 18 installments representing 3.33% of the original nominal value and the remaining ten installments representing 3.34% of the original nominal value. Pampa adhered to the terms and scope of SGE Resolution No. 54/19 (see “Item 4—Our Business—The Argentine Energy Sector—OIL & GAS REGULATORY FRAMEWORK—Gas Market Regulatory Framework” and Relevant Events— Oil and Gas—Modifications to the Unconventional Gas Plan - Resolution No.46-E/17). This resolution keeps 85% of the Argentine Government debt denominated in U.S. dollars, despite the billing in Pesos described above, reducing our currency devaluation risk.

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, 2019 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. 

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

Oil and gas 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 Gas y Petróleo de Neuquén S.A. (G&P) and Empresa de Desarrollo Hidrocarburífero Provincial S.A. (“EDHIPSA”)) are also highly competitive in the Argentine oil and gas market. As a result, we cannot assure 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.

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On August 15, 2019, Decree No. 566/19 established that, for a period of ninety days: (i) deliveries of crude oil in the local market must be invoiced and paid by applying a reference exchange rate of Ps.45.19/US$ and a reference price of Brent crude oil of US$59/barrel; (ii) the prices of gasoline and diesel sold locally cannot exceed the current price as of August 9, 2019; and (iii) hydrocarbon producing companies, refineries and retail companies must supply the national demand for crude oil and liquid fuels, respectively, at the established prices.

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.

We cannot assure 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.

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

Although we have investments in Ecuador and Venezuela, most of our operations and activities are concentrated in Argentina. 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.

For example, regarding our investments in mixed-capital companies in Venezuela, the monetary and fiscal policies implemented by the Venezuelan government together with the significant drop in international oil prices since 2014 have eroded the ability of the mixed-capital companies to efficiently operate the producing fields, creating greater uncertainty as to the risks of our investments in Venezuela.

The level of government intervention in the economy of Latin American countries has adversely affected our business and operational results, including, by changing the terms and conditions of operating service agreements in Venezuela and by increasing tax rates. Even though our investment in Venezuela is valued at zero, we cannot assure that such intervention will not continue or increase, which could adversely affect our future business, operational results and financial condition. As of the date of this annual report, we had not obtained the authorizations of the Government of Venezuela related to the requested change of indirect control. Likewise, CVP has determined that, given the time that has elapsed, we should begin the process of submitting plans according to new guidelines to be provided by the Ministerio del Poder Popular de Petróleo de la República Bolivariana of Venezuela, which have not been communicated to us yet. As a result, we have expressed with the authorities of the Government of Venezuela that our interest in making investments and/or financing proposals in the mixed-capital companies has ceased and that we are willing to negotiate the transfer of our shares to CVP.

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 reestablished 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.

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ADS holders’ ability to receive cash dividends may be limited

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

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

Our corporate affairs are governed by our by-laws 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.

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 by-laws 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 an official gazette in Argentina, 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.

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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 by-laws 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 in control of our Company, such as the requirement, upon the acquisition of a certain percentage of our capital stock, to launch a tender offer to acquire a certain percentage of our capital stock, which percentage ranges from 10% to 100% depending on several factors. These provisions may delay, defer or prevent a transaction or a change in 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.

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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 February 21, 1945, for a duration of 99 years, 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 the largest independent energy integrated company 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 PPSL, which in turn owned, at such time, 67.2% of the shares of Petrobras Argentina (the “Acquisition”). On August 4, 2016, (i) 100% of the rights and obligations under the concession agreement relating to the Colpa and Caranda areas in Bolivia were sold to Petrobras; (ii) 33.66% of the rights and obligations in the Río Neuquén area was sold to an affiliate of Petrobras; and (iii) 33.33% and 80% of the rights and obligations in the Río Neuquén and the Aguada de la Arena areas, respectively, were sold to YPF.

Since the Acquisition, we started a corporate reorganization process and have merged certain subsidiaries into Pampa, including, among others, Petrobras Argentina, Petrolera Pampa, CTG and CTLL, by way of absorption, with Pampa as the surviving company.

 The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

Capital Expenditures and Divestitures

For a description of our capital expenditures see “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

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 the largest independent integrated energy company in Argentina. As of December 31, 2019, we were engaged in the electricity and gas value chain (not including discontinued operations; for more information, please see Note 5.2 to the Consolidated Financial Statements):

· Generation. Our generation installed capacity reached approximately 4,751 MW, 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 471 MW, which would bring our total installed capacity to 5,222 MW (see “—Our Generation Business–Summary of the committed expansion projects”). 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 Greater Buenos Aires, comprised by a 674 MW combined cycle gas-fired generating unit, a 169 MW open-cycle gas turbine which was granted an additional power capacity of 19 MW, effective as of June 1, 2019, as well as a new open-cycle gas turbine of 188 MW under the expansion to CC process, totaling 1,050 MW of installed capacity. The committed expansion projects include the closing to combined cycle at CTGEBA for 383 MW, of which 207 MWwere commissioned in June 2019, estimated for the third quarter of 2020. Upon the commissioning of the closing to CC, CTGEBA will increase its installed capacity to 1.2 MW;

o CTLL, a 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) with an installed capacity of 765 MW. The committed expansion projects include the incorporation into CTLL of, two engines, which will increase its installed capacity by 15 MW, estimated for the second quarter of 2020;

o CPB, a thermal gas or fuel oil-fired generation plant located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires, with an installed capacity of 620 MW;

o CTIW, a thermal gas or fuel oil-fired generation plant located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires, with an installed capacity of 100 MW;

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o CTG, a thermal gas-fired generation plant located in General Güemes, in the Province of Salta, with an installed capacity of 361 MW;

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;

o CTPP, a thermal power generation plant at Pilar Industrial Park, located in Pilar, Northern Greater Buenos Aires, which comprises six Wärtsilä motor generators (Wärtsilä W18V50DF) with an installed capacity of 100 MW and which runs on natural gas and fuel oil;

o CTEB, a thermal gas-fired generation plant located in the petrochemical complex of the City Ensenada, Greater La Plata, Province of Buenos Aires, with an installed capacity of 567 MW and which is owned by CTB, an affiliate that we co-control through our subsidiary Pampa Cogeneración, with YPF;

o EcoEnergía, a cogeneration thermal power plant with 14 MW of installed capacity, located in Bahía Blanca, in the Province of Buenos Aires;

o Hidroeléctrica Los Nihuiles and Hidroeléctrica Diamante, two hydroelectric power generation systems located in the Province of Mendoza, with an aggregate installed capacity of 653 MW, through our subsidiaries HINISA and HIDISA. HINISA holds 4.6% interests in both TJSM and TMB, and HIDISA holds 2.4% in each entity;

o HPPL, which has three electricity generating units with an installed capacity of 285 MW and is located in the Comahue region, in the Province of Neuquén;

o PEMC, a wind farm located in Bahía Blanca, in the Province of Buenos Aires, owned by Greenwind, a company that we jointly control with Viento Solutions SL. Greenwind was created for the main purpose of developing PEMC, which has a capacity of 100 MW.;

o PEPE II: on May 10, 2019, CAMMESA granted the commercial commissioning of our second wind farm in the City of Bahía Blanca, Province of Buenos Aires. PEPE II contributes 53 MW of renewable energy to the national grid;

o PEPE III: on May 10, 2019, CAMMESA granted the commercial commissioning of our third wind farm in the City of Bahía Blanca, Province of Buenos Aires. PEPE III contributes 53 MW of renewable energy to the national grid; and

o 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 generation business segment recorded US$819 million in revenue and an operating profit of US$273 million for the year ended December 31, 2019.

· Distribution of Energy. We are engaged in the electricity distribution business through our subsidiary Edenor, that serves on exclusive basis to approximately 3.1 million customers, throughout an area of approximately 4,637 square kilometers comprised by the northern region of the City of Buenos Aires and the Northwestern Greater Buenos Aires area, making us the largest electricity distribution company in Argentina whether in terms of number of customers and electricity sold (in terms of GWh and revenues) in 2019, based on publicly available figures released by electricity distribution companies in Argentina.

Our distribution of energy business segment recorded US$1,502 million in revenue and an operating profit of US$342 million for the year ended December 31, 2019.

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· Oil and Gas. We are engaged in the oil and gas business through:

o Direct interest in oil and gas blocks in Argentina where, as of December 31, our combined crude oil and natural gas proved reserves amounted approximately 135.4 million barrels of oil equivalent, 52% of which were proved developed reserves. Natural gas accounted for approximately 90% of our combined proved reserves and liquid hydrocarbons for 10%;

o our combined oil and gas production in Argentina averaged 48.2 thousand barrels of oil equivalent per day, considering continued operations (see Note 5.2.1 to the Consolidated Financial Statements), with operations in 12 production blocks and 885 production wells. Crude oil accounted for approximately 5.0 thousand barrels of oil equivalent per day, while natural gas accounted for approximately 259 million standard cubic feet per day, or 43.2 thousand barrels of oil equivalent per day based on a measure of conversion of 6,000 cubic feet of gas per barrel of oil equivalent; and

o Direct interest in (i) our 2.1% direct interest in Oleoductos del Valle S.A.(“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 refinery located in the pipeline’s area of influence; (ii) our investments in Oleoductos de Crudos Pesados Ltd. (“OCP”); and (iii) minor interests in four productive blocks in Venezuela, through mixed-capital companies (Empresas Mixtas, corporations whose majority shareholder is a subsidiary of Petróleos de Venezuela S.A. (“PDVSA”) Corporación Venezolana de Petróleo S.A. (class A shares), which are controlled by the Bolivarian Republic of Venezuela, and in which we own a minority interest (class B shares)), see “Our Oil and GasBusiness—Others—Venezuela”.

Our oil and gas business segment recorded US$444 million in revenue from continuing operations and an operating profit from continuing operations of US$71 million for the year ended December 31, 2019.

· Petrochemicals. Our petrochemicals operations are entirely based in Argentina. We own three plants producing styrene, styrene butadiene rubber (SBR) and polystyrene, with a domestic market share ranged between 89% and 100% as of December 31, 2019. The petrochemicals division has the following assets:

o an integrated petrochemicals complex at Puerto General San Martín, located in the Province of Santa Fe, with an annual production capacity of 50,000 tons of gases (liquefied petroleum gas -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$321 million in revenue and an operating profit of US$5 million for the year ended December 31, 2019.

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

o PHA owns 40% of CIESA, which in turn owns 51% of TGS, which is engaged mainly in the transportation of gas in southern Argentina and in the processing and marketing of natural gas liquids. Also, PHA has a direct interest of 0.79% in TGS and we directly own 10% of CIESA and 0.91% of TGS. As a result, we have a direct and indirect interest of 27.2% in TGS;

o We hold a 50% interest in Citelec, which holds 52.65% of the shares and votes in Transener. As a result, we have an indirect interest of 26.33% in Transener. As of December 31, 2019, our electricity transmission operations covered 20,981 kilometers of high voltage transmission lines, representing approximately 85% of the high voltage system in Argentina; and

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o We participate in the refining and distribution operations through our participation of 28.5% interest in Refinor, which owns a refinery located at Campo Durán in the Province of Salta with an installed capacity of 25,800 oil barrels per day and a commercial network of 90 gas stations located in Argentina.

CIESA, CITELEC Refinor, CT Barragán S.A. and Greenwind are accounted for using the equity method.

Our holding and other business segment recorded US$20 million in revenue and an operating profit of US$60 million for the year ended December 31, 2019.

Relevant Events

Corporate Reorganization Process

Merger of Pampa and PEA

On March 29, 2019, the boards of directors of Pampa and PEA resolved that it would be beneficial for these companies to merge into a single company, where Pampa would be the surviving company, with retroactive effects from January 1, 2019. However, the shareholders’ meetings of Pampa and PEA held on May 29, 2019 resolved to leave without effect the proposed merger between Pampa and PEA.

Merger of Pampa and PEFM

On August 30, 2019, the board of directors of Pampa and PEFM approved the merger between Pampa as the surviving company, and PEFM, as the merged company, as from July 1, 2019. This merger was later approved by Pampa’s Extraordinary General Shareholders’ Meetings held on October 15, 2019. As of the date of this annual report, the approval by the City of Buenos Aires’s Public Registry of Commerce (IGJ) is still pending.

Merger of Pampa and CPB

On October 8, 2019, our Board of Directors instructed management to assess the benefits of a merger between Pampa, as the surviving company, and CPB, as the merged company, establishing January 1, 2020 as the potential effective merger date. On March 9, 2020 our Board of Directors resolved to approve such merger. As of the date of this annual report, the definitive merger agreement had not been executed.

Merger of Pampa, Pampa Cogeneración and PHA

On March 26, 2020, our Board of Directors instructed management to assess the benefits of a merger between Pampa, as the surviving company, and Pampa Cogeneración and PHA as the merged companies, establishing April 1, 2020 as the effective merger date. As of the date of this annual report, the definitive merger agreement had not been executed.

Generation

Fuel Self-Procurement by Power Generators

Pursuant to Resolution SGE No. 70/18, since November 2018, power generators were authorized to acquire fuel required for their own power generation. Should power generators chose this option, CAMMESA would then value and pay to power generators their fuel costs through a standardized mechanism. CAMMESA remained, however, in charge of the commercial management and the dispatch of fuels for power generators which could not or would not make use of such option. On November 12, 2018, Pampa decided to use this option, allocating a significant portion of its gas production for the dispatch of its thermal units.

However, as of December 30, 2019, through Resolution MDP No. 12/19, Section 8 of Resolution SE No. 95/13 and Section 4 of Resolution SE No. 529/14 were reinstated. As a result, fuel supply is again being centralized by CAMMESA (other than power generators with Energy Plus). Resolution SGE No. 70/1836F was therefore repealed.

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Commissioning of Two New Wind Farms

On May 10, 2019, CAMMESA granted the commercial commissioning of PEPE II and III, each with 53 MW of installed capacity. The commissioning of PEPE II and III was achieved within the scheduled timeframe set forth in the awarding of priority dispatch.

PEPE II is located in the area known as Corti, 20 kilometers away from the City of Bahía Blanca, Province of Buenos Aires, nearby PEMC, whereas PEPE III is located in the City of Coronel Rosales, 25 kilometers away from the City of Bahía Blanca.

Both wind farms consist of 14 wind turbines each. Each turbine is made up of four tower sections, a nacelle and three blades driving the turbine with a total diameter of 136 meters. Furthermore, through Resolution No. 281-E/2017 enacted by the former Ministry of Energy and Mining (MEyM) PEPE II and III were awarded the Renewable Energy Term Market (MAT ER) and were destined to meet the demand by large electricity consumption users through PPAs between private parties. The wind farms demanded a final estimated investment of US$130 million.

Progress in the Cycle Closing Project at CTGEBA

CAMMESA granted the commercial commissioning to CTGEBA’s Gas Turbine 04 as from June 12, 2019, for an installed capacity of 188 MW. Moreover, CAMMESA granted the commissioning to the capacity enhancement of the already existing Gas Turbine 03, also known as Genelba Plus, for an additional power capacity of 19 MW, effective as from June 1, 2019.

These units, which contributed an additional 207 MW capacity to the grid, are part of Genelba Plus’ closing-to-combined-cycle project, which will include the entry into service of a steam turbine, estimated to be completed by the third quarter of 2020. Upon the commissioning of the closing-to-combined-cycle at CTGEBA Plus, which will require a total estimated investment of US$350 million, the PPA executed with CAMMESA will come into effect for a 15-year period, and CTGEBA will have two combined cycles with a total installed capacity of approximately 1.2 GW.

Joint Acquisition of CTEB

After submitting a joint bid, on May 29, 2019, IEASA notified that Pampa, through its subsidiary Pampa Cogeneración, and YPF were awarded the tender for the sale and transfer by IEASA of CTEB. On June 26, 2019, the transaction was completed, subject, however, to the sale and transfer to CTB (the “Acquiring Company”), a company co-controlled by YPF and Pampa.

CTEB is located in the petrochemical complex of the City of Ensenada, Greater La Plata, Province of Buenos Aires, and consists of two open-cycle gas turbines with an installed capacity of 567 MW. As part of the transaction, the Acquiring Company should complete, within a 30-month period, the necessary works to convert CTEB into a combined cycle, which will result in the expansion of its installed capacity to 847 MW and derive in higher efficiency, as it will generate 50% more electricity with the same amount of fuel (gas). Once the combined cycle works are completed, it is estimated that CTEB will be one of the most efficient thermal power units among the country’s power grid.

Both CTEB’s open and closed cycles are subject to PPAs executed with CAMMESA pursuant to Resolution No. 220/07 issued by the former Secretariat of Energy (SE). The open cycle’s PPA is effective as of March 26, 2009 and expires on April 27, 2022, and the closed cycle’s PPA was executed on March 26, 2013 and expires in 10 years from the date of the commissioning of the combined cycle.

CTEB’s acquisition price amounted to US$282 million, which also accounted for the purchase price of a certain amount of debt securities (VRDs) issued under the trust agreement called “Contrato suplementario del programa global de fideicomisos financieros y de administración para la ejecución de obras de infraestructura energética -Serie 1- ENARSA (Barragán)” (Trust). For the payment of the acquisition price, the Acquiring Company received a US$200 million contribution from its co-controlling shareholders, and executed a US$170 million loan with a syndicate of banks. The banks have no recourse against Pampa and YPF.

Furthermore, it is estimated that the investment for the closing to combined cycle will be of approximately US$200 million. CTEB’s acquisition also involved the assignment to the Acquiring Company of the trustee’s contractual status under the Trust. The VRDs debt (excluding the VRDs acquired by CTB) amounted to approximately US$229 million as of the transaction date and is estimated to be repaid with CTEB’s operation cash flow proceeds.

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Pampa will be responsible for CTEB’s operating management until 2023 and YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for CTEB’s conversion into combined cycle. YPF and Pampa will be in charge of CTEB’s operating management on an alternate basis, for periods of four years.

Agreement for the Regularization and Settlement of Receivables with the WEM (CAMMESA Agreement)

Pursuant to the call made to generators under the instructions of the Government Secretariat of Energy (SGE), on August 5, 2019 Pampa and certain subsidiaries executed with CAMMESA an agreement for the Regularization and Settlement of Receivables with the WEM whereby CAMMESA committed to disburse the Sales Settlements with maturity date to be defined (LVFVD) in arrears, after offsetting debts undertaken with the WEM under financing agreements, loan agreements and assignment of receivables executed with generators, and applying an 18% reduction on the balance. Pampa and certain subsidiaries agreed on a net amount for all items associated with the outstanding LVFVD, including interests as of July 31, 2019, as well as the above-mentioned debt reduction, which amounted to Ps.2,123 million before any applicable withholding.

On August 7, 2019, the corresponding offsetting was completed and the LVFVD’s remaining balance was collected. In furtherance of the undertaken commitments, Pampa and certain subsidiaries have waived all submitted claims and have irrevocably dismissed their rights to file any claim against the Federal Government, SGE and/or CAMMESA regarding the outstanding LVFVD. As a result of the agreement, we recorded sales revenues for Ps. 260 million and financial net gains for Ps.3,119 million.

Oil and Gas

Gas Plan

Modifications to the Unconventional Gas Plan - Resolution No.46-E/17

The Stimulus Program for Unconventional Production issued by the ME&M Resolution No.46-E/17 as amended, was created to encourage investments in natural gas production from unconventional reservoirs at the Neuquina Basin (and, later, was extended to cover the Austral Basin).

We had requested the SGE to include our exploration projects in the Rio Neuquén, El Mangrullo and Sierra Chata areas within this program, as the same projects had previously been approved by the relevant provincial authorities. However, on January 30, 2019, at a meeting called by theSGE, in which the gas producers affected by the Unconventional Gas Plan, including us, participated, we were informed that no new projects would be approved within the Unconventional Gas Plan.

As of the date of this annual report there was no resolution or formal instruction issued by the SGE relating to above, nor has the Company been formally notified that the inclusion within the Unconventional Gas Plan of the above mentioned projects was rejected.

Amendment to the Natural Gas Exports’ Authorization Procedure

On July 26, 2019, SGE Resolution No. 417/2019 amended the previous procedures for the authorization of natural gas exports, effective as from its publication in the Official Gazette. Exports can be agreed under firm, interruptible, operational exchanges or support agreements, provided that the supply to the Argentine domestic market is secured in all cases. Furthermore, in the case of projects under the Encouragement Program for the Investment in Development of Natural Gas Production from Unconventional Reservoirs, approved by Resolutions No. 46, 419, 447 /17 and 12/18 of former MEyM (“Unconventional Gas Plan”), exported natural gas shall not be eligible as part of and/or within the production applicable to such program. Later, in October 2019, this Res. was supplemented by SHC Provision No. 284/19.

If higher costs are incurred by the WEM as a result of the use of alternative fuels for power generation (imported LNG, coal, fuel oil or gas oil), which costs would be borne by the Federal Government, exporting companies may pay a compensation to CAMMESA (SGE Res. No. 506/19). Furthermore, as from September 2018 a duty on gas export was established, with a maximum 12% tax rate, which was modified as from December 2019 with the entry into effect of the Social Solidarity and Productive Reactivation Law, setting a rate lower than or equal to 8% of the taxable value or the FOB price. However, the latter has not yet been formally implemented, therefore export duty still stands at 12%.

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Export of Natural Gas on a Firm Basis During the Summer Period

SGE Resolution No. 252/18 passed on December 12, 2018 authorized Pampa to export gas to Chile, on an interruptible basis, to Colbún S.A. at a PIST price of US$4.2/MBTU, for a maximum volume of 2 million m3/day until November 15, 2019, or until meeting the equivalent total maximum quantity, whichever occurs first. SGE Resolution No. 12/19 of January 22, 2019 authorized Pampa to export gas to Uruguay, on an interruptible basis, to Uruguay’s Power Plants and Transmissions state-owned company, at a PIST price of US$4/MBTU, for a maximum volume of 600 dam3/day until May 1, 2019 or for the equivalent total maximum quantity.

On August 21, 2019, Disposition No. 168/2019 issued by the Undersecretariat of Hydrocarbon and Fuels (SHC) was published in the Official Gazette, approving the terms and conditions for the export of natural gas to Chile on a firm basis, and permitting exports during the period between September 15, 2019 and May 15, 2020 with a maximum aggregate volume of 353 million cubic feet/day, divided as follows: 65% from the Argentine Central-Western area, 25% from the South and 10% from Northwest area; provided, that the Argentine domestic market is fully supplied.

In September 2019, we obtained a permit to export gas on a firm basis (from our production at the Neuquina Basin) to ENAP Refineries in Chile for a maximum volume of 0.6 million cubic meters/day or a total 136.8 million cubic meters at a price of US$3.11/MBTU, net of export duties and transportation costs until May 15, 2020. In December 2019, the maximum volume was increased to 0.9 million cubic meters/day or a total of 188.7 million cubic meters.

Investment in OCP

On December 5, 2018, through our subsidiary PEB, we entered into an agreement with Agip Oleoducto de Crudos Pesados BV (AGIP) for the acquisition of 4.49% of the capital stock of OCP and the credit that AGIP held with respect to the subordinated debt issued by OCP. On March 8, 2019, the agreement was approved by the Ecuadorian State and executed on June 20, 2019. This acquisition increased our interest in OCP to 15.91%. If the aforementioned credit is collected by PEB in advance of its maturity in 2021, PEB should reimburse AGIP 50% or 25% of the amount collected in 2019 or 2020, respectively.

The closing of the transaction resulted in the recognition of a gain of US$25 million in our Consolidated Financial Statements. On the other hand, as of December 31, 2019, PEB recorded an impairment loss on its previous participation in OCP (11.42%) for an amount of US$6.7 million.

Exploration Permits

The extension of the exploration license for the Parva Negra Este block, located in the Province of Neuquén, granted in concession to Gas y Petróleo de Neuquén S.A.P.E.M. (GyP) and operated by us for a 4-year term beginning on April 2014, expired in April 2019. Pampa holds a 42.5% interest in the Parva Negra Este block.

On March 29, 2019, GyP requested to the Province of Neuquén that thewhole Parva Negra Este block should be classified as an “evaluation lot” for a period of 3 years. The approval is still pending.

On February 22, 2019, Salta’s Provincial Executive Order No. 249/19 was issued, extending the exploratory term for a 12-month period effective as from November 18, 2018. We have a 50% interest in the Chirete area, located in the province of Salta, operated by High Luck Group Limited. On April 26, 2019 an exploitation concession was requested on the lot called “Los Blancos”, with an area of 95 square km. Additionally, on April 30, 2019, the extension of the third exploratory period over the remaining area was requested for three years, considering an exploratory potential that will require additional studies after the discovery of oil.

The exploration permits for Río Atuel, a block located in the Province of Mendoza and operated by Petrolera El Trébol, expired in September 2018, and the term was extended until March 13, 2019 pursuant to Administrative Decision No. 19/18 issued by the Department of Hydrocarbons of Mendoza. We hold a 33.33% interest in the Río Atuel block. Then December 7, 2019 was determined as the new expiration date of the second exploratory period, and on December 18, 2019 the third exploratory period entered into force for a period of one year, reversing 50% of the total area of 998 square km.

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Additionally, we had duly communicated to our partners of the Enarsa 1 and Enarsa 3 areas our decision to not participate in the conversion of those areas into exploration permits according to Law No. 27,007. On April 15, 2019, Resolution SGE No. 195/19 and 196/19 were published informing the reversal and transfer to the National State of the Enarsa 3 area, the partial conversion of the Enarsa 1 area into an exploration permit in favor of YPF and the reversion and transfer to the National State of the remaining surface of the Enarsa area 1. As a result, we no longer hold any participation in these areas.

Strategic Divestments

Closing of Dock Sud Terminal Sale

In line with the Company’s strategy to focus its resources on core businesses, in March 2019, we executed an agreement with Raízen Argentina, a licensee of the Shell brand, for the sale of our Dock Sud Terminal.

The transaction’s price was US$19.5 million plus an additional amount of US$2.0 million for terminal’s products. The transaction resulted in a profit before income tax in the amount of Ps.45 million.

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. As of April 29, 2020, Argentina identified 4,285 confirmed cases of coronavirus, of which 214 were fatal. Argentina has 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:

· February 26— March 12, 2020: screening of passengers at airports; mandatory isolation for 14 days of individuals with suspected or confirmed cases of Covid-19, individuals in close contact with suspected or confirmed cases of Covid-19 and individuals arriving or recently arrived from affected zones; closure of activities with large crowds; prohibition of audience attendance to sport events;

· March 13— March 15, 2020: stricter surveillance of Argentine borders; suspension of flights by various airlines and adoption of regulations to coordinate repatriation flights for Argentine residents abroad; prohibition of access to national parks and protected areas; schools and universities shutdown (which remain open for food aid and administrative purposes);

· March 16— March 18, 2020: closure of Argentine borders; suspension of domestic flights and long-distance trains and buses operations; suspension of the national soccer league; temporary work leaves for pregnant women, individuals older than 60 years and other persons considered at special risk upon infection; authorization for federal public employees to work remotely (except for employees providing essential services); promotion of home office policies in the private sector and beginning of construction of eight modular hospitals;

· March 19, 2020: imposition of a nation-wide mandatory lockdown, where exceptionally essential transit is permitted; deployment of security forces for lockdown enforcement;

· March 20 - April 11, 2020 – April 26, 2020: assistance to Argentine residents abroad; extension of nation-wide lockdown until May 10, 2020 inclusive.

Simultaneously, the Argentine Government has announced and is implementing a several stimulus measures to limit the effects of the Covid-19 outbreak on the economy, including the following:

· a one-time Ps.3,100 cash payment to recipients of the universal child allowance;

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· a one-time Ps.3,000 cash payment to retirees receiving minimum benefits (currently Ps.15,892) and those that receive above the minimum but less than Ps.18,892 which covers approximately 4.6 million retirees;

· a one-time Ps.10,000 cash payment which will be granted to approximately 7,785,000 to unemployed individuals and individuals employed informally, among other socially vulnerable individuals;

· a capital spending program on infrastructure, education and tourism for approximately Ps.100 billion;

· a payment exemption of employers’ contributions for companies in vulnerable industries, and an increase of unemployment insurance and salaries subsidies;

· subsidized loansfor working capital to small- and medium-sized companies of approximately Ps.30 billion via the financial system;

· a 40% increase in the budget allocation for capital expenditures, mainly in road infrastructure, housing and school construction; and

· a financial assistance program for the provinces for an amount up to Ps. 120 billion (Programa Para la Emergencia Financiera Provincial) created to provide financial relief to the provinces.

Other measures adopted by the Argentine Government to mitigate the effects of the Covid-19 outbreak in the economy include the following:

· a 180-day period waiver of suspension of the following services upon certain beneficiaries’, who fail to pay less than three consecutive invoices from March 1, 2020: electric energy, natural gas through pipeline, water and sewage, landline and mobile telephony, internet and cable television services. This measure is only applicable to certain users identified in the decree. Specifically, regarding electric energy, users that have prepaid systems, shall be provided with the service even if they fail to make the corresponding recharges; additionally, through Resolution No.173/2020, in force as of April 18, 2020, the Ministry of Productive Development sets forth that electricity distribution services, among others, shall be payable in 30 monthly, equal and consecutive installments, the first one being due on September 30, 2020 (notwithstanding the possibility for customers to pay invoices before or through a smaller number of installments). This resolution is of limited application to a specific group of clients detailed in the resolution. Furthermore, the financing can also be applied to the purchase of energy that the Company makes to the MEM associated with these consumptions.

· the suspension of certain penalties and disqualifications applicable to checking accounts with insufficient funds until April 30, 2020;

· the prices freezes as of March 6, 2020, for certain essential goods such as food, personal care, medication and medical products for a 30-day period;

· lease prices freeze and evictions suspension until September 30, 2020;

· prohibition to dismiss employees without cause and dismiss and suspend employees due to work slowdown or force majeure for a 60-day period beginning March 31, 2020.

· On April 8, 2020, the Secretariat of Energy 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 rescindment of the COVID-19 isolation.

Measures Designed by the Company to Address the Covid-19 Outbreak

In this regard, and by virtue of the current public health emergency, we have implemented a Contingency Plan in order to minimize the risk of contagion from our employees and ensure business continuity. On February 27, 2020, a special multidisciplinary preventive committee was created, which established and coordinated different internal practices to be implemented in our facilities. Due to the mandatory and preventive social isolation effective as from March 20, 2020, we implemented mandatory home office for our employees, provided that their tasks allow it. Those individuals involved in activities and services that have been declared essential during the public health emergency according to the applicable regulations, must comply with the security and prevention measures imposed by the authorities and the Company, thus allowing the continuity of most of our activities.

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The ongoing circumstances of the current coronavirus outbreak (COVID-19), among others, will be key in determining the depth and the duration of the economic crisis in the world and in Argentina in particular, and therefore in our strategy, financial situation and results of operations.

As of the date of this annual report, although the early development of the coronavirus pandemic has not yet had any significant impact on the Company, we cannot reasonably quantify to what extent the COVID-19, and in particular, the measures taken by the Government to prevent its spread have affected and will affect our businesses and results of operations. We are evaluating the impacts in relation to the items’ valuation of property, plant and equipment and the impairment of our financial assets. For more information, please see “—Developments relating to the novel coronavirus may have a material adverse impact on our business operations, financial condition or results of operations”).

Impact of the COVID-19 outbreak on our Operations

As aforementioned, the Argentine Government and several governments have adopted drastic measures in response to the Covid-19 outbreak, which have affected the Argentine energy industry, as described below:

•    With respect to the generation business, the electric demand in the SADI has decreased an average of 26% since the start of the lockdown. Also, due to significant delays on its collections from distribution companies and large users, CAMMESA has extended the payment date for generators and producers by more than 30 days, and it is possible there may be even greater delays. It has also suffered delays in receiving contributions from the National Treasury. Additionally, the SE instructed CAMMESA to suspend the automatic adjustment mechanism for spot remuneration in SE Resolution No. 31/20. These measures directly affect the financial situation of the electric business, and will continue deteriorating if the payment chain is compromised, hindering the maintenance and risking the availability of the generation park.

•    As for the gas business, although the local production volume is aligned to its historical average, the total demand has also been affected with a 30% decrease mainly due to the fact that CAMMESA has lowered the electric dispatch and, in consequence, there is a lower demand for thermic electric generation. Also, the lockdown of all non-essential activities and consumer seasonality have contributed to a lower demand. In consequence, the prices obtained in recent CAMMESA auctions have shown a tendency to be lower to those obtained prior to the lockdown. Moreover, an agreement has not been reached for the contracts with the distributors that have expired on March 31, 2020.

•    Demand for hydrocarbons has significantly diminished due to a lower demand for refined products and it is not certain how it will evolve in the near future.  Particularly, crude oil storage capacity has reached its limit at a local and global scale. Also, the local oil prices, that have International prices as a reference, have suffered a big decrease and their future is uncertain.  It is expected that the Argentine Government will intervene in order to fix a price for the locally produced barrel (usually known as “barril criollo”) as has occured in past crises. However, to the date of this form, no rule has been issued, and it is not possible to estimate the price that may be fixed.

•    With regards to the petrochemical business, there has been a significant reduction in the local demand for some products like styrene and octane bases for gasoline. Also, our rubber production was suspended due to the fact that it was not considered an essential activity, in accordance with our clients activities.

•    As for the electric distribution business, there has been a decrease in the demand, due mainly to lower non-essential commercial and industrial activity, compensated by an increase in residential demand. Also, the lockdown had an impact on the collection businesses and the consumers’ income, which has produced a significant decrease in their earnings and cash flows. On March 25, 2020, the PEN issued the Decree No. 311/20 suspending for 180 days the energy power cuts due to lack of or delay in payment for certain socially vulnerable clients. Due to the continuous increase in the costs associated with the service and the need to invest in order to maintain the quality of service, Edenor was forced to partially postpone payments to CAMMESA for the energy acquired in the MEM with maturities as from March 2020.

The Company’s management is monitoring the situation and implementing all necessary measures to assure the sanitary well-being of its employees, continue with its operations and preserve its financial situation. This includes a home office scheme, except for those working positions that must inevitably attend their working place. For the cases, there was an implementation of a preventive protocol. Also, investments have been rescheduled and we have negotiated with banks in order to obtain new credit lines, among other measures.    

We are also evaluating the impact of the measures implemented by the Argentine Government in relation to the valuation of the recoverability of our properties, plants, equipment, inventories and financial assets.

The final scope of the outbreak of the novel coronavirus and its impact on Argentina’s economy is unknown and impossible to reasonably predict. However, although there have been significant adverse effects in the short term, it is not estimated that the continuity of the business of the Company will be affected.

Due to our financial solidity, we estimate we will satisfy our financial commitments in the next twelve months.

Notwithstanding the aforementioned, due to the recently adopted governmental measures, it is not possible to accurately quantify the duration of the restrictions, their evolution, their impact on the economy and, especially, how our business and the results of our operations will be affected in the future. If the measures were to be extended for a long period of time, we may have to recognize losses in the future due to the deterioration of the registered value of our assets or renegotiate the maturities of our commercial and financial debts. 

Organizational structure

The following chart sets forth our corporate structure as of December 31, 2019.

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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 and interests in HINISA, HIDISA, PEMC y CTEB.

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, 2019, 2018 and 2017. 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	PEPE II	PEPE III
Installed Capacity (MW)	265	388	285	100	53	53	1,144
Market Share	0.7%	1.0%	0.7%	0.3%	0.1%	0.1%	2.9%
Net Generation 2019 (GWh)	498	334	823	383	122	148	2,309
Market Share	0.4%	0.3%	0.6%	0.3%	0.1%	0.1%	1.8%
Sales 2019(GWh)	498	334	823	383	129	154	2,321
Net Generation 2018 (GWh)	577	393	886	247	-	-	2,103
Variation Net Generation  2019-2018	-14%	-15%	-7%	+55%	N/A	N/A	+10%
Sales 2018 (GWh)	577	393	886	247	-	-	2,103
Net Generation 2017 (GWh)	751	480	760	-	-	-	1,991
Variation Net Generation  2018-2017	-23%	-18%	17%	N/A	-	-	-24%
Sales 2017 (GWh) In US$/MWh	751	480	760	-	-	-	1,991
Avg. Price 2019	38	58	23	69	62	65	44
Avg. Price 2018	31	46	22	80	N/A	N/A	36
Avg. Gross Margin  2019	23	42	15	59	53	55	33
Avg. Gross Margin  2018	20	32	15	71	N/A	N/A	26

Sources: Pampa Energía S.A. and CAMMESA.

Note: gross margin before amortization and depreciation. Exchange rate Ps./US$: 2019 – 48.23; 2018 – 28.13.

Summary of Electricity Generation Assets	Thermal
	CTLL	CTG	CTP	CPB	CTPP	CTIW	CTGEBA	ECO-ENERGÍA	CTEB	Subtotal	Total
Installed Capacity (MW)	765	361	30	620	100	100	1,050	14	567	3,607	4,751
Market Share	1.9%	0.9%	0.1%	1.6%	0.3%	0.3%	2.6%	0.04%	1.4%	1,453	1,659
Net Generation 2019 (GWh)	5,096	755	53	1,106	168	312	5,550	105	128	13,273	15,582
Market Share	3.9%	0.6%	0.0%	0.8%	0.1%	0.2%	4.2%	0.1%	0.1%	10.1%	12.0%
Sales 2019 (GWh)	5,096	891	53	1,106	168	312	5,887	110	128	13,751	16,072
Net Generation 2018 (GWh)	4,748	1,674	134	753	192	274	4,859	108	-	12,743	14,845

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Variation Net Generation  2019-2018	+7%	-55%	-61%	+47%	-13%	+14%	+14%	-3%	N/A	+4%	+5%
Sales 2018 (GWh)	4,748	2,227	134	753	192	274	5,457	110	-	13,751	16,072
Net Generation 2017 (GWh)	3,864	1,772	156	1,453	142	23	4,685	100	-	12,195	14,186
Variation Net Generation  2018-2017	23%	-6%	-14%	-48%	+35%	N/A	+4%	+8%	-	2%	+5%
Sales 2017 (GWh) In US$/MWh	3,864	2,358	156	1,453	142	23	5,424	103	-	13,523	15,514
Avg. Price 2019	55	45	113	62	N/A	107	46	47	N/A	61	58
Avg. Price 2018	43	35	59	88	N/A	107	36	57	N/A	45	44
Avg. Gross Margin  2019	31	29	N/A	23	N/A	80	17	7	N/A	33	33
Avg. Gross Margin 2018	37	20	N/A	46	N/A	85	18	15	N/A	30	29

Sources: Pampa Energía S.A. and CAMMESA.

Note: gross margin before amortization and depreciation. Exchange rate Ps./US$: 2019 – 48.23; 2018 – 28.13.

Summary of the committed expansion projects

Project	MW	Equipment Provider	Marketing	Date of Commissioning
Thermal
CTLL	15	MAN	SE Resolution No. 31/20	Second Quarter of 2020
CTGEBA	176	Siemens	Agreement in US$ for 15 years	CC1:Third Quarter of 2020
CTEB	280	Siemens	Agreement in US$ for 10 years	CC1:2022
Total	471

Thermal Generation plants

CTLL

CTLL is located in the Province of Neuquén, which has an installed capacity of approximately 765 MW, representing approximately 1.9% of Argentina’s installed capacity. 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 combined cycle and repowered in January 2018, a 105 MW General Electric aeroderivative gas turbine installed in May 2016 and the incorporation in August 2017 of a 105 MW General Electric gas turbine. 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. From 1997 to 2019, CTLL’s average annual generation was 1,993 GWh, with a generation record high of 5,096 GWh in 2019, and a record low of 272 GWh in 2002.

CTGEBA

CTGEBA is located in Marcos Paz, Province of Buenos Aires. The plant began operating in 1999 and has a combined cycle with a 674 MW installed capacity, which consists of two gas turbines of 219 MW each and a 236 MW steam turbine. On the same lot, there is a gas turbine with a 169 MW power capacity known as Genelba Plus, which was repowered by 19 MW in June 2019, known as Genelba Plus, was commissioned in 2009 under the Energy Plus Program and is currently under expansion (for more information, please see “Progress in the Cycle Closing Project at CTGEBA”), as well as a 188 MW gas turbine incorporated in June 2019 under the expansion to combined cycle process. CTGEBA’s combined cycle 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 combined cycle, when it will start to be sold under a PPA. Currently, the total installed capacity of the CTGEBA complex amounts to 1,050 MW, which represents 2.6% of Argentina’s installed capacity. From 2000 to 2019, CTGEBA’s historical average annual generation was 4,763 GWh, with a generation record high of 5,550 GWh in 2019, and a record low of 3,438 GWh in 2001.

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CPB

CPB is a thermal generation plant (which we own through our subsidiary Piedra Buena) 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 with an installed capacity of 620 MW, consisting of two identical conventional units (Unit 29 and Unit 30) with an installed capacity of 310 MW each, which represents 1.6% of Argentina’s installed capacity. 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. From 1997 to 2019, CPB’s average annual generation was 2,048 GWh, with a generation record high of 3,434 GWh in 2012, 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 0.9% of Argentina’s installed capacity. From 1993 to 2019, its average annual generation was 1,751 GWh, with a generation record high of 1,903 GWh in 1996, and a record low of 755 GWh in 2019.

Royalty assignment agreement

In June 2007, we entered into a royalty assignment agreement with the Province of Salta pursuant to which the Province agreed to assign natural gas to Central Térmica Güemes, which the Province is entitled to collect as in-kind royalties in respect of natural gas produced within the provincial territory. In consideration for such assignment, we committed to pay a 5% premium over the applicable average wellhead gas price. The term of the agreement is five years, starting from the date of the first delivery of natural gas, and is subject to an automatic renewal clause. The daily amount under the agreement may reach 500,000 m3 per day if the production of gas in the Province of Salta increases from the production level existing at the time of the agreement’s execution. As of the date of this annual report, we had not requested any deliveries under this agreement because it has been able to supply the new 100 MW of generation with gas purchased from several suppliers, including our own gas production.

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. From 2011 to 2019, its average annual generation was 121 GWh, with a generation record high of 156 GWh in 2017, and a record low of 53 GWh in 2019.

ECOENERGÍA

EcoEnergía is a co-generation power plant located at TGS’s General Cerri complex in Bahía Blanca, in the Province of Buenos Aires. The plant, consisting of a steam turbine with a power capacity of 14 MW, was commissioned in 2011. The plant sells electricity in the Energía Plus market. From 2011 to 2019, EcoEnergía’s average annual generation amounted to 89 GWh, with a generation record high of 108 GWh in 2018, and a record low of 20 GWh in 2011.

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CTPP

CTPP is located in the Pilar Industrial Complex, in the district of Pilar, Province of Buenos Aires. Construction began in October 2016, and the plant was commissioned on August 29, 2017.

The plant, which was built under SEE Resolution No. 21/2016, has a total power capacity of 100 MW and is made up of six cutting-edge Wärtsilä engines with an approximate 43% performance rate. The annual average energy generation for the period from 2018 to 2019 was 180 GWh. 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.

CTIW

CTIW is located in Ingeniero White, Bahía Blanca, in the Province of Buenos Aires, and consists of six high-efficiency Wärtsilä engines, with a total power installed capacity of 100 MW. 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 annual average energy generation for the period from 2018 to 2019 was 293 GWh.

CTEB

CTEB is located in the City of Ensenada, Province of Buenos Aires, owned by CTB, a company that we jointly control, through our subsidiary Pampa Cogeneración, with YPF. The plant began its operations in 2012 and is composed of two open cycle gas turbines with a total installed capacity of 567 MW, which represents 1.4% of the installed capacity in Argentina. CTEB is currently under expansion to close the cycle, which will increase its installed capacity to 847 MW.

CTEB is a thermal plant with dual fuel, natural gas or gas oil. From 2012 to 2019, the average annual generation amounted to 1,461 GWh, with a high generation record of 2,093 GWh in 2018, and a low record of 564 GWh in 2019.

Pampa will be responsible for CTEB’s operating management until 2023 and YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for CTEB’s conversion into combined cycle. YPF and Pampa will be in charge of CTEB’s operating management on an alternate basis, for periods of four years.

Hydroelectric Generation Plants

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

HINISA

We own Class A and Class B shares representing 31.63% and 20.41%, respectively, of the voting capital stock of HINISA, a hydroelectric generation company with an installed capacity of 265 MW located in the Province of Mendoza.

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. In addition, HINISA owns 4.6% of the capital stock of TJSM and 4.6% of the capital stock of TMB. From 1990 to 2019, the average annual generation was 818 GWh, with the highest level of generation (1,250 GWh) recorded in 2006 and the lowest level (498 GWh) recorded in 2019.

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The Province of Mendoza, through Empresa Mendocina de Energía Sociedad Anónima con Participación Estatal Mayoritaria (EMESA), currently owns Class D shares representing 10.21% of the capital stock of HINISA and Class C shares representing 37.75% of the capital stock of HINISA, and publicly announced in 2006 its intention to sell its Class C shares. Pursuant to HINISA’s public concession contracts, if the Province of Mendoza sells its Class C shares in HINISA, we would be required to sell our Class B shares of HINISA (representing 20% of HINISA’s capital stock) through a public offering promptly after the Province’s sale of its Class C shares. Assuming that the Province of Mendoza sells its 37.75% interest in HINISA, and consequently we are required to sell our Class B shares (representing 20% of the capital stock of HINISA), we would no longer own a controlling interest in HINISA and would not be permitted to purchase any additional shares (of any class) of HINISA. 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 Class B shares of HINISA. As a result, such shares may be sold at a time and price per share that is adverse to our interests. As of the date of this annual report, the Province of Mendoza had expressed no intention to modify HINISA’s by-laws. See “Item 3. Key Information—Risk Factors—Risks Relating to our Generation Business—We may no longer own a controlling interest in HINISA, if the Province of Mendoza sells its participation in HINISA.”

HIDISA

We own, directly and indirectly, 61% of the voting capital stock of HIDISA, a hydroelectric generation company with an installed capacity of 388 MW located in the Province of Mendoza.

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 owns 2.4% of the capital stock of TJSM and 2.4% of the capital stock of TMB. From 1990 to 2019, the average annual generation has been 553 GWh, with the highest level of generation (943 GWh) recorded in 2006 and the lowest level (322 GWh) recorded in 2014.

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.

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.

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On February 2, 2017, SEE Resolution No. 19/2017 terminated the remuneration scheme of SEE Resolution 22/2016 as from the economic transactions for February 2017, which represented a new increase in HIDISA’s and HINISA's revenues mainly due to: (i) greater availability of power determined independently of the level of the dam, eliminating the risk of hydrology; and (ii) a higher price as a result of its dollarization, minimizing the risk associated with exchange rate fluctuations.

Moreover, on April 10, 2017, and as a result of the claims filed by the HINISA, the SEE recategorized Nihuil I, Nihuil II and Nihuil III hydroelectric plants as “small”, which had an impact in the base price applicable to such plants under SEE Resolution 19/2017 increasing from 3,000 US$/MW per month to 4,500 US$/MW per month.

In February 2019, the remuneration scheme was modified by Resolution SEE 1/19 which was then amended by Resolution SE 31/2020 on February 27, 2020, with effects as from February 2020 (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 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.

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 works) 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.

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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 Pampa, it was awarded for hydroelectric power generation at HPPL beginning in August 1999. The HPPL complex has three electricity generating units with an installed capacity of 285 MW, 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. From 2000 to 2019, HPPL’s average annual generation was 961 GWh, with a generation record high of 1,430 GWh in 2006, and a record low of 494 GWh in 2016.

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, as from 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. As of December 31, 2019, we paid the maximum rate of hydroelectric royalties at a rate of 12% per year. 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.

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.

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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 works) 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.

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

On April 18, 2016, we acquired 100% of Greenwind, for an amount of US$2.1 million. Greenwind is a company incorporated under the laws of Argentina whose purpose was to develop the PEMC. For such purpose, Greenwind has the legal right to use and obtain a profit from over 1,500 hectares of land where wind measurements have been taking for the last five years.

On October 7, 2016, through Resolution No. 213/2016, the ME&M announced the awardees of the RenovAr 1 Program Tender. On January 23, 2017, we were awarded a PPA to develop the PEMC project through Greenwind. Greenwind has entered into the respective supply and construction agreements for the construction and commissioning of wind farms in Bahia Blanca with affiliates of Vestas.

On March 10, 2017, we entered into an agreement with Valdatana Servicios y Gestiones S.L.U (the “Buyer”), an investment vehicle led by Castlelake L.P. (a private equity global investment company) for the sale of certain shares owned by us in Greenwind totaling US$11.2 million. In addition, the Buyer has acquired shares of Greenwind owned by PP for US$45,9 thousand, which together with the sale of the shares owned by us account for 50% of the capital stock and rights of Greenwind. As a consequence, as of the date of this annual report, we jointly control Greenwind with Viento Solutions SL.

The PEMC is located at Corti, 12 miles from the City of Bahía Blanca, Province of Buenos Aires. The PEMC consists of 29 Vestas wind turbines, each with a 3.45 MW power capacityand an 87-meter hub height. The PEMC contributes 100 MW of renewable energy to the national Argentine grid.

On June 8, 2018, CAMMESA granted the commercial commissioning of PEMC, which was obtained before the date originally stipulated in the PPA executed with CAMMESAunder the RenovAr Program (for more information, please see “The Argentine Energy Sector – RenovAr Program”). Since its commercial commissioning and during 2018, PEMC generated 247 GWh.

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PEPE II

PEPE II is located in the area known as Corti, 20 kilometers 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 136 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. Since its commercial commissioning and during 2019, PEPE II generated 122 GWh.

PEPE III

PEPE III is located in the City of Coronel Rosales, 25 kilometers away 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 136 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. Since its commercial commissioning and during 2019, PEPE II generated 148 GWh.

PEPE IV

The PEPE IV project was announced on May 23, 2018. This project was to be located at the Las Armas area, in the Municipality of Maipú, Province of Buenos Aires, with a gross power capacity of 53 MW. PEPE IV obtained the dispatch priority as established in Resolution ME&M No. 281-E/17 and committed to begin its commercial operations in June 2019.

However, as a result of events occurred during 2019, including the devaluation of the peso and the increase in interest rates, which resulted in macroeconomic instability, the Company requested an extension of the term to initiate the commercial operations, in order to (i) evaluate the feasibility of the project under the new economic conditions and (ii) negotiate certain changes proposed by work contractors and equipment suppliers. In this context, and based on a thorough evaluation of the renewable projects in progress, on September 11, 2019 the SSERyEE instructed CAMMESA to temporarily suspend the claims for non-compliance, and demanded the Company to extend the validity of the US$12.5 million guarantee for a term of 180 days. On October 4, 2019, the Company complied with the requested extension. On October 9, 2019, the SSERyEE cancelled the suspension. On October 30, 2019, CAMMESA served the Company with a formal claim for the payment of certain amounts associated with the postponement of the commercial commissioning of the project and its relocation, and alternatively would enforce the guaranty if such payments were not performed. The Company rejected the claim served by CAMMESA awaiting SGE’s consideration of the extension request, and, on December 9, 2019 it entered into an agreement with CAMMESA establishing a negotiation period until January 31, 2020, during which CAMMESA should suspend the guarantee’s execution. The negotiation period was then extended until April 30, 2020.

Others

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.

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Our Distribution of Energy Business

Empresa Distribuidora y Comercializadora Norte S.A. (Edenor)

We are engaged in the electricity distribution business through our subsidiary Edenor, which was the largest electricity distribution company in Argentina in terms of number of customers and electricity sold (both in GWh and in Pesos) in 2019. Edenor holds a concession to distribute electricity on an exclusive basis to the northwestern zone of the greater Buenos Aires metropolitan area and the northern portion of the City of Buenos Aires, comprising an area of 4,637 square kilometers and a population of approximately 9 million people. As of December 31, 2019, Edenor served 3.1 million users.

Summary of the Edenor concession

Edenor is a public service company incorporated on July 21, 1992 as part of the privatization of the Argentine state‑owned electricity utility company, SEGBA. At the time of privatization, SEGBA was divided into three electricity distribution companies, including Edenor, and four electricity generation companies, and, as part of the privatization process, in August 1992, the Argentine Government granted Edenor a concession to distribute electricity on an exclusive basis within a specified area, which we refer to as Edenor’s service area, for a period of 95 years.

Term. Edenor’s concession currently expires on August 31, 2087, and can be extended for one additional 10-year period if Edenor requests the extension at least 15 months before expiration. The Argentine Government may choose, however, to grant Edenor the extension on a non-exclusive basis. The term of the concession is divided into management periods: a first period of 15 years and subsequent periods of ten years each. In addition, at the end of each management period under the concession, the ENRE will arrange for an international public bidding procedure to be conducted for the sale of 51% of Edenor’s capital stock and voting rights in similar conditions to those under which we acquired our stake. If we (or our successor) are the highest bidder or if our bid matches the highest bid, we will retain 51% of Edenor’s stock, no funds will be owed to the Argentine Government and we will have no further obligation with respect to the bid. There is no restriction as to the price we may bid. The first management period commenced on February 1, 2017 and ends on March 1, 2022.

Obligations. Under the concession, Edenor is obligated to supply electricity upon request of the owner or occupant of any premises in its service area. Edenor is entitled to charge for the electricity supplied at rates that are established by tariffs set by the ENRE. Pursuant to its concession, Edenor must also meet specified service quality standards relating to: (i) the time required to connect new users; (ii) voltage fluctuations; (iii) interruptions or reductions in service; and (iv) the supply of electricity for public lighting and to certain municipalities.

Edenor’s concession requires it to make the necessary investments to establish and maintain quality of service standards and to comply with stringent minimum public safety standards as specified in the concession. Edenor is also required to furnish the ENRE with all information requested by it and must obtain the ENRE’s prior consent for the disposition of assets that are assigned to the provision of electricity distribution services. The ENRE also requires Edenor to compile and periodically submit various types of reports regarding the quality of its service and other technical and commercial data, which we must periodically report to the ENRE.

Pursuant to Law No. 27,467, which enacted the 2019 Federal Budget of Expenditures and Resources, the executive branch of the Argentine Government was instructed to transfer Edenor’s jurisdiction to the jurisdiction of the Province of Buenos Aires and the City of Buenos Aires as from January 1, 2019 and the creation of a new oversight body. On February 28, 2019, the Argentine Government, the Province of Buenos Aires and the City of Buenos Aires entered into an agreement for the transfer of the public service of electricity distribution, duly awarded under the Concession Agreement by the Argentine Government to Edenor, from the jurisdiction of the Argentine Government to the Province of Buenos Aires and the City of Buenos Aires.

Under such agreement, on May 9, 2019, the Federal Government, the City of Buenos Aires and the Province of Buenos Aires entered into the Transfer Agreement, which became effective on October 2, 2019, after obtaining the approval of the legislature of the City of Buenos Aires and the Provincial Executive Branch, pursuant to which the City of Buenos Aires and the Province of Buenos Aires jointly assumed, as from the date of effectiveness, the regulation, control and the capacity as grantors over the distribution service granted to Edenor under the Concession Agreement. Furthermore, it is provided that (i) the Concession Agreement and also the national regulations issued by both the Energy Secretariat and the ENRE will remain in full force and effect until the effective date of the transfer occurs pursuant to the applicable regulatory framework; and (ii) that the pledge of the Class “A” shares, duly pledged as collateral to secure the performance of the obligations assumed by the holder of the concession and/or the majority shareholders under the Concession Agreement, is assigned on an undivided basis by the Federal Government to the City of Buenos Aires and the Province of Buenos Aires.

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Edenor was notified of and assented to the arrangement made by the Federal Government and the new grantors of the concession with respect to the Transfer Agreement and undertook both to indemnify them against any claims and to obtain the agreement of the majority of its shareholders. The Transfer Agreement was ratified by the Provincial Executive Power and the City of Buenos Aires’ Legislative Power.

Further, with the enactment of the Social Solidarity and Productive Reactivation Law and the suspension of the transfer of the jurisdiction, the ENRE retained its jurisdiction over the public service of electricity distribution during the term of the emergency as set forth in such law.

Finally, in the framework of the Social Solidarity and Productive Reactivation Law, the Federal Executive Power was authorized to assume the administrative control of the ENRE and the ENARGAS for a term of one year and, consequently, on March 16, 2020, by means of Decree N° 277/20, the Executive Power intervened the ENRE until December 31, 2020.

Edenor is subject to the terms of its concession agreement and the provisions of the regulatory framework comprised by Laws Nos. 14,772, 15,336 and 24,065, resolutions and regulatory and supplementary standards issued by certain authorities. Thus, Edenor is responsible for the distribution and sale of electricity as a public service with a satisfactory quality level pursuant to the requirements set forth in the aforementioned concession agreement and regulatory framework.

Fines and penalties. Under the terms of the concession, the ENRE may impose fines and penalties if Edenor fails to comply with its obligations, including a failure to meet any of the quality and delivery standards applicable to the concession. The ENRE may also impose fines for any network installations that it considers to be a potential safety or security hazard in public spaces, including streets and sidewalks. In addition, the ENRE may impose fines for inconsistency in the technical information that is required to be furnished to the ENRE.

As of December 31, 2019, total accrued fines and penalties imposed on Edenor amounted to US$121 million.

Pledge of Class A shares. In accordance with the concession, the 51% stake we own in Edenor was pledged to the Argentine Government to secure the obligations arising from the concession. The Adjustment Agreement (as defined below) extended the pledge to secure the obligations under such agreement as well. The Argentine Government may foreclose on its pledge over the Class A shares and sell them in a public bidding process if certain situations occur (see “Item 3. Risk Factors–Risks Relating to our Distribution of Energy Business – The Argentine Government could foreclose on its pledge over Edenor’s Class A shares under certain circumstances, which could have a material adverse effect on our business and financial condition”).

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Revocation of concession. The Argentine Government has the right to revoke the concession if Edenor files for bankruptcy and if the Argentine Government decides that it shall not continue rendering services, in which case all of its assets will be transferred to a new state‑owned company that will be sold through an international public bidding process. At the conclusion of this bidding process, the purchase price will be delivered to the bankruptcy court in favor of Edenor’s creditors, net of any debt owed by Edenor to the Argentine Government and any residual proceeds will be distributed to Edenor’s shareholders.

Tariffs. Under the terms of Edenor’s concession, the tariffs charged by Edenor (other than those applied to users in the wheeling system – see below) are composed of:

· the cost of electricity purchases, which Edenor passes through to its users and a fixed charge (which varies depending on the category and level of consumption of each user and their energy purchase prices) to cover a portion of Edenor’s energy losses in its distribution activities (determined by reference to a fixed percentage of energy and power capacity for each respective voltage level set forth in our distribution concession);

· Edenor’s regulated distribution margin, which is known as the value‑added for distribution, or VAD; and

· any taxes imposed by the Province of Buenos Aires or the City of Buenos Aires, which may differ in each jurisdiction.

Certain of Edenor’s large users (which we refer to as “wheeling system users”) are eligible to purchase their energy needs directly from generators in the WEM and only acquire from Edenor the service of electricity delivery. As a result, Edenor’s tariffs for these large users (known as “wheeling charges”) do not include charges for energy purchases. Accordingly, wheeling charges consist of the fixed charge for recognized energy losses (determined by reference to a fixed percentage of energy and power capacity for each respective voltage level set forth in Edenor’s concession) and Edenor’s distribution margin. Although the amounts billed to wheeling system users are relatively lower than those billed to other large users, namely industrial users, the distribution margin on sales to wheeling system users is similar to that of other large users because Edenor does not incur the corresponding cost of electric power purchases related to those sales.

For more information, please see “Item 4. The Argentine Energy Sector—Distribution of Energy”.

Users. As of December 31, 2019, Edenor served 3,119,279 users. Edenor defines a “user” as one meter. Edenor classifies its users pursuant to the following tariff categories:

· Residential (T1-R1 to T1-R9): residential users whose peak capacity demand is less than 10kW. In 2019, this category accounted for approximately 43.1% of Edenor’s electricity sales.

· Small commercial (T1-G1 to T1-G3): commercial users whose peak capacity demand is less than 10kW. In 2019, this category accounted for approximately 8.7% of Edenor’s electricity sales.

· Medium commercial (T2): commercial users whose peak capacity demand is equal to or greater than 10kW but less than 50kW. In 2019, this category accounted for approximately 8% of Edenor’s electricity sales.

· Industrial (T3): industrial users whose peak capacity demand is equal to or greater than 50kW. This category is applied to high-demand users according to the voltage at which each user is connected. The different voltage ranges included in this category are the following: (i) Low Voltage (LV): voltage less than or equal to 1 kV; (ii) Medium Voltage (MV): voltage greater than 1kV but less than 66 kV; and (iii) High Voltage (HV): voltage equal to or greater than 66kV. In 2019, this category accounted for approximately 18% of Edenor’s electricity sales. This category does not include users who purchase their electricity directly through the WEM under the wheeling system.

· Wheeling System: large users who purchase their electricity directly from generation or broker companies through the WEM. These tariffs follow the same structure as those applied under the Industrial category described above. As of December 31, 2019, the total number of such large users was 684, and this category represented approximately 18.3% of Edenor’s electricity sales.

· Others: public lighting (T1-PL) and shantytown users whose peak capacity demand is less than 10kW. In 2019 this category accounted for approximately 3.7% of Edenor’s electricity sales.

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Edenor strives to maintain an accurate categorization of its users in order to charge the appropriate tariff to each user. In particular, Edenor focuses on its residential tariff categorizations to both minimize the number of commercial and industrial customers who are classified as residential users and to identify residential users whose peak capacity demand exceeds 10kW and which, therefore, do not qualify as residential users.

Shantytowns. In accordance with the terms of its concession and given the nature of public service that the distribution of electricity is granted under the Argentine law, Edenor is required to supply electricity to all users within the concession area, including low-income areas and shantytowns located within its service area. In October 2003, Edenor, Edesur and Edelap entered into a framework agreement (the “Framework Agreement”) with the Argentine Government and the Province of Buenos Aires to regulate their supply to low-income areas and shantytowns. Under this agreement, Edenor has the right to receive compensation for the services provided to shantytowns from funds collected from residents of each relevant shantytown, the municipality in which it is located and, if there is a shortfall, by a special fund sponsored by the Argentine Government and the Government of the Province of Buenos Aires. The Argentine Government contributes an amount equal to 21%, and the Province of Buenos Aires contributes an amount equal to 15.5% of such compensation, net of taxes.

In the past, the term of the Framework Agreement was repeatedly extended. Furthermore, within the framework of the transfer of jurisdiction of the public service of electricity distribution that had been determined by Law No. 27,467, the Government of the Province of Buenos Aires enacted Law No. 15,078 on the General Budget, pursuant to which established (i) that the Province of Buenos Aires would pay as from January 1, 2019 the same compensation paid in 2018 for the low-income areas and shantytowns’ electricity consumption, and (ii) that any amount in excess of the compensation provided item (i) would have to be borne by Municipalities in whose territories each shantytown is located. Such consumption has to be previously approved by the regulatory agencies or local authorities having jurisdiction in each area. In this regard, on November 27, 2019, the Municipality of General San Martín filed a petition with the Supreme Court to obtain a provisional remedy, claiming that section 104 of Law No. 15,078 that refers to this matter is unconstitutional. As of December 31, 2019, Edenor did not recognize revenues for this concept.

Finally, in light of the recent measures adopted by national and provincial authorities as of the date of this annual report (namely the Social Solidarity and Productive Reactivation Law), Edenor is not aware of the guidelines to be followed concerning the electricity consumption by low-income areas and shantytowns in connection with periods that have not been recognized, as well as future periods.

Energy losses. Energy losses are equivalent to the difference between energy purchased and energy sold, and may be classified as technical or non-technical losses. Technical losses represent the energy that is lost during transmission and distribution within the network as a consequence of natural heating of the conductors that transmit electricity from the generating plants to the users. Non-technical losses are primarily due to illegal use of Edenor’s services and technical errors. Energy losses require Edenor to purchase additional electricity to satisfy demand and its concession allows Edenor to recover from its users the cost of these purchases up to a loss factor specified in the concession for each tariff category. The average loss factor under Edenor’s concession is 10%.

The following table illustrates Edenor’s estimates of the approximate breakdown between technical and non-technical energy losses experienced in its service area for the periods indicated:

	Year ended on December 31,
	2019	2018	2017
Technical Losses	9.6%	8.4%	8.8%
Non Technical Loses	10.3%	9.8%	8.3%
Total Loses	19.9%	18.2%	17.1%

Termination of agreement on real estate property

In November 2015, Edenor entered into an agreement with Ribera Desarrollos S.A. (“RDSA” or the “Seller”) for the purchase and construction of real estate property for a total of US$46 million, equivalent to Ps.439.3 million, according to the effective exchange rate time of the agreement’s execution. Edenor purchased the real estate property to centralize its functions, reduce rental costs and to mitigate the risk of potential rent increases. In addition, Edenor obtained a surety bond from Aseguradores de Cauciones S.A. (“Aseguradores de Cauciones”) for US$46 million, plus the private banks’ BADLAR rate in dollars + 2%, to guarantee payment of liquidated damages in the event of the Seller’s default.

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Pursuant to the agreement, RDSA was obligated to deliver the property on June 1, 2018, and failed to perform. As a result, Edenor declared the RDSA in breach, notified Aseguradores de Cauciones of such breach and subsequently collected US$502,800 in fines accrued during the term of the agreement and duly deposited as bond by the Seller for failing to meet the construction project milestones of the agreement.

With regards to the legal actions brought by Edenor against RDSA and the insurance company, on September 30, 2019, Edenor entered into a settlement agreement pursuant to which the insurance company will pay to the Company a compensation of US$15 million and assign it the insurer’s subrogation right for the amount paid to RDSA.

As of December 31, 2019, Edenor has collected US$14 million. The remaining balance will be paid in six quarterly installments (the first of which was due on April 21, 2020). As of the date of this annual report Edenor has not received payment.

Furthermore, the claim filed by Edenor with the Arbitral Tribunal of the Buenos Aires Stock Exchange against RDSA in order for the latter to refund the price paid for the undelivered real property was suspended so that the claim could be admitted in RDSA’s insolvency proceeding. Such claim was admitted by the court hearing the case for the sum of Ps.2,125.9 million. Additionally, an ancillary proceeding for review of the amount rejected by the court was initiated for an additional amount of Ps.895.7 million.

Regulatory Framework of our Distribution of Energy Business

Memorandum of Understanding with the Federal Government

On February 13, 2006, Edenor entered into the Adjustment Agreement, which established, effective as from November 2005, (i) a 23% increase in the average VAD and (ii) a 5% additional VAD increase to fund specified capital expenditures we are required to make under the Adjustment Agreement. Furthermore, it provided for the inclusion of a social tariff, quality standards for the service to be rendered and a minimum investment plan in the electricity grid to be performed by Edenor, as well as the performance of an RTI. Upon the failure to perform the RTI, the SE and the ENRE passed several transitory measures seeking to reduce Edenor’s operating and asset deterioration which resulted from the tariff freeze. The background and the current tariff situation are disclosed below.

SE Res. No. 250/13

Since May 2013, the SE provided for the recognition of costs owed to Edenor resulting from the partial application of the MMC, the result of which was lower than the actual increase stipulated in the 2007 Contractual Renegotiation Agreement, which was not duly passed on to tariffs. This measure was implemented with the passing of SE Res. No. 250/13 and its subsequent extensions, which allowed for the offsetting of this recognition with Edenor’s debts under PUREE and with CAMMESA for energy purchases. However, in February 2016 the SE issued Res. No. 6/16 abrogating the MMC.

ENRE Res. No. 347/12

ENRE Res. No. 347/12 applied a differential fixed amount to each of the different tariff categories, with the exception of customers exempt from paying the tariff scheme provided for by ENRE Res. No. 628/08. Such amounts —which continued to be deposited in a special account and were used exclusively for the execution of infrastructure and corrective maintenance works in Edenor’s facilities within the concession area— were managed by the FOCEDE. ENRE Res. No. 2/16 terminated the FOCEDE trust on January 31, 2016 and established a new system for the funds collected pursuant to ENRE Res. No. 347/12, which were managed by Edenor. With the implementation of the RTI in February 2017, these amounts ceased to be charged as a special item on customer bills.

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Loan Agreements – Extraordinary Investments Plan

Due to the delay in obtaining the RTI, the Federal Government granted Edenor loans for to conduct the corresponding investments under the investment plan it may deem appropriate. Pursuant to MEyM Res. No. 7/16, CAMMESA suspended, as from February 2016 and until receiving further instructions, all the effects arising from the executed loan agreements and the transfer of resources to distribution companies on behalf of the FOCEDE trust and, therefore, the new work plan would be financed exclusively with tariff proceeds. The amounts owed by Edenor under loan agreements were offset by the Federal Government pursuant to the Agreement on the Regularization  of Obligations executed on May 10, 2019.

SE Res. No. 32/15

In March 2015, Resolution No. 32/15 of the former SE granted Edenor a temporary increase in income through funds provided by CAMMESA to be applied retroactively as from February 1, 2015 through February 1, 2016 to cover costs and investments associated with the regular provision of the energy distribution service on account of the RTI.

However, in January 2016 ENRE Res. No. 7/16 ordered the performance of all necessary acts to conduct Edenor’s RTI, annul the tariff schemes resulting from SE Res. No. 32/15, and adjust the VAD to be charged against the RTI, thus canceling the PUREE and suspending the investments loan agreements entered into with Edenor. Consequently, the ENRE issued Res. No. 1/16 and 2/16 granting a new tariff scheme values for Edenor effective from February 2016. In September 2016, Edenor filed its tariff proposal for the RTI, expressing that it does not contemplate the value Edenor assigns to damages resulting from the failure to timely and properly implement the Memorandum of Understanding or the collection of income necessary to face the liabilities Edenor has incurred as a result.

RTI

ENRE Res. No. 63/17, as amended, established the final tariff schemes, the review of costs, required quality levels and other rights and obligations by Edenor for the five-year period starting February 2017. A 42% cap was set in the VAD increase resulting from the RTI as from February 2017, and the remaining increases would be applied in November 2017 and February 2018. The VAD difference resulting from the gradual application was updated in real terms and incorporated in 48 installments payable as from February 2018. The tariff schemes included the prices established in the seasonal programming for the February - April 2017 period under SEE Res. No. 20/17.

However, both the CPD update contemplated for August 2017 and the VAD increase scheduled for November 2017 were deferred to December 2017, when tariff schemes were fixed pursuant to ENRE Res. No. 603/17 for the two-month period between December 2017 - January 2018, also contemplating the 18% VAD increase and the 11.6% CPD update, adjusted retroactively as of the dates they should have been implemented.

On January 31, 2018, the ENRE issued Resolution No. 33/18 which approved the new distribution cost for Edenor to be applied as from February 1, 2018 and the new tariff scheme.

Furthermore, such resolution approved the new CPD adjustments (last stage of 17% according to Resolution. No 63/17, including the inflation adjustment of 11.9% for the period July 2017-December 2017 and a stimulus factor “E” of negative 2.51%) and determined the deferred income to be recovered in 48 instalments for a total amount of Ps.6,343.4 million. Additionally, it reported that the price of the average tariff reached Ps.2.4627/ kWh.

On July 31, 2018, the ENRE issued Resolution No. 208/18, pursuant to which it approved, the CPD for January 2018 through June 2018 of which 7.93% was applied as of August 1, 2018, and 6.51% in six consecutive monthly installments as of February 1, 2019. The CPD amounted to 15.85%. Moreover, Resolution No. 208/18 established a system of caps for the social tariff as well as the values that the Company had to apply to determine and credit discounts in the electricity bills of the users affected by deficiencies in the quality of the technical product and/or the quality of the technical and commercial service from 2018 to February 2019. Additionally, the informed average electricity rate value amounted to Ps. 2.9871/kWh.

Furthermore, SEE Provisions No. 75/18 and 97/18 established, for the August 2018 – January 2019 period, the power capacity reference price at Ps.10,000/MW-month, the stabilized price for transmission in the extra high voltage system at Ps.64/MWh, and a price for main distribution based on the distribution company which, in the case of Edenor, amounted to Ps.0/MWh. Furthermore, energy reference prices were set at Ps.2,283/MWh for GUDI and at Ps.1,470/MWh for the remaining users. Regarding the social tariff, SEE Res. No. 1091/17’s criteria regarding subsidies to users and discounts for savings remained in effect.

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Effective as from February 2019, SGE Res. No. 366/18 abrogated SEE Res. No. 1091/17 and, consequently, the Federal Government’s social tariffs and the savings discount scheme, and also fixed a power capacity reference price of Ps.80,000/MW per month, with 25% and 20% increases to be applied in May and August, respectively, effective until October 2019. The stabilized price for transmission in the extra high voltage system and the distributor-based main distribution price remained unchanged. Energy reference prices were set at Ps.2,762/MWh for GUDI for the February – October 2019 period, and at Ps.1,852/MWh for the remaining users as from February 2019, with 5% increases to be applied in May and August, effective until October 2019.

ENRE Res. No. 25/19 approved the tariff scheme which became effective in February 2019. It reflected the new seasonal prices described in SGE Res. No. 366/18, and the ENRE Res. No. 27/19, issued in March 2019 established the 24% CPD update corresponding to the July 2018 – January 2019 period, retroactive as of February 2019, and a 7.925% increase which was timely deferred in August 2018, retroactive as of that date. Compensatory retroactive amounts were collected in five installments.

In April 2019, SGE Res. No. 366/18 was partially amended by SRRYME Res. No. 14/19 which suspended the increases planned for May and August 2019 for the power capacity reference price and increases contemplated for residential users, whereas energy reference prices increased by 5% in May and August 2019 for GUDI, and by 7% in May and August 2019 for the rest of non-residential users. Furthermore, SRRYME Res. No. 26/19 and 38/19 approved the seasonal programming for the August – October 2019 and November 2019 – April 2020 periods, respectively, prices remaining unaltered until April 2020. However, as of the date of this annual report, these increases in seasonal prices for non-residential users have not been passed on to new tariff schemes.

On September 19, 201,9 Edenor agreed with the Federal Government to postpone the 19.05% CPD update for August 1, 2019 until January 1, 2020. Furthermore, the continuity of retroactive amounts applied throughout the period from March 2019 to July 2019 for the timely deferred CPD was allowed, the balance being recoverable in seven monthly consecutive installments from January 2020. Besides, the payment of penalties by Edenor was postponed until March 1, 2020 in six monthly installments. However, with the entry into effect of the Social Solidarity and Productive Reactivation Law, on December 27, 2019 the ENRE instructed Edenor to maintain the current tariff schemes until June 2020, suspending all projected updates both in the CPD and in the seasonal price. It also contemplates the possibility of performing an RTI review for up to 180 days as from the Law’s effective date.

Regularization of Liabilities and Transfer of Concession Jurisdiction

On February 28, 2019, the Federal Government entered into an agreement with the Province of Buenos Aires and the City of Buenos Aires for the transfer of the public service of electricity distribution, duly awarded under the Concession Agreement by the Argentine Government to Edenor from the jurisdiction of the Argentine Government to the Province of Buenos Aires and the City of Buenos Aires. The Province of Buenos Aires and the City of Buenos Aires agreed to set up a new bipartite agency in charge of the regulation and control of the distribution service, and the Federal Government agreed to take the necessary steps and carry out the necessary administrative procedures to provide a solution to the pending claims with the distribution company such as the breach of the 2006 Memorandum of Understanding, among others. Until such transfer is perfected, the national regulatory framework would apply.

Furthermore, on May 10, 2019, Edenor and the Energy Government Secretariat, on behalf of the Federal Government, entered into the Agreement on the Regularization of Obligations. By virtue of this Agreement, Edenor (i) undertook to pay users certain penalty and compensation amounts relating to the period between 2006 and 2016; and (ii) agreed to make investments, in addition to those agreed upon in the RTI, aimed at contributing to improving the reliability and safety of the service. In return, the Federal Government partially recognized the claim duly made by Edenor, by fully offsetting pending obligations, cancelling penalties payable to the National Treasury, among others. However, pursuant to the Social Solidarity and Productive Reactivation Law, as from December 23, 2019, the ENRE was appointed as Edenor’s regulatory body until December 31, 2020. Edenor is currently unaware of the guidelines to follow regarding consumptions of shantytowns with community meters for non-recognized and future periods.

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Finally, in accordance with the provisions of the electricity rate schedule maintenance agreement, within the framework of the Economic Emergency Law No. 27,541 on Social Solidarity and Production Reactivation, Edenor agreed to maintain the quality of the service and comply with the quality parameters set forth in the Concession Agreement, and that the payment of any penalty would be postponed until March 1, 2020 and paid in 6 installments at its original value plus any adjustments that may apply at the time of payment.

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:

·development and monetization of unconventional gas reserves;

·exploration for reserves replacement; and

·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, 2019:

· our combined crude oil and natural gas proved reserves were 135.4 million barrels of oil equivalent, 52% of which were proved developed reserves. Natural gas accounted for approximately 90% of our combined proved reserves and liquid hydrocarbons for 10%;

· our combined oil and gas production in Argentina averaged 48.2 thousand of barrels of oil equivalent per day, considering continuing operations. Crude oil accounted for approximately 5.0 thousand of barrels of oil equivalent per day, while natural gas accounted for approximately 259 million standard cubic feet per day, or 43.2 thousands of barrels of oil equivalent 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 distillery located in the pipeline’s area of influence

During 2019, according to the ME&M, gas gross production in Argentina increased by 5% (4.8 billion cubic feet per day on average), whereas oil gross production increased 4.1% and stood at 509 thousand barrels per day (on average).

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In December 2019, according to the ME&M, our consolidated oil and gas production accounted for approximately 1% and 6% of total oil production and gas production in Argentina, respectively.

We are also engaged in the oil and gas business directly and through investments in Oldelval, OCP and minor interests in four productive blocks in Venezuela, through mixed-capital companies, corporations whose majority shareholder is a subsidiary of PDVSA, Corporación Venezolana de Petróleo S.A. (class A shares), which are controlled by the Bolivarian Republic of Venezuela, and in which we own a minority interest (class B shares), see “Our Oil and GasBusiness—Others—Venezuela”.

Key Information Relating to Oil and Gas

As of December 31, 2019, we had interests in 18 areas, joint operations (UTEs) and agreements in Argentina: 12 oil and gas production areas and 6 exploration blocks located within exploration areas or pending authorization for production. As of December 31, 2019, we were directly or indirectly the contractual operator of eight of the 18 blocks in which we hold equity interest.

Acreage

As of December 31, 2019, 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, its subsidiaries, joint operations and associates.

	Acreage (*)
	Production (1)		Exploration (2)
	Gross	Net (3)	Gross	Net (3)
	(in thousands of acres)
Argentina	1,098	373	445	208

(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 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, 2019, our total gross and net productive wells were as follows. The table includes the total gross and net productive wells by the Company and its subsidiaries, joint operations and associates.

	Oil		Gas		Total (3)
	Gross (1)	Net (2)	Gross (1)	Net (2)	Gross (1)	Net (2)
Argentina	472	154	413	193	885	348

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

(1) Refers to 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 2019, 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). We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019. 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,
	2019		2018		2017
	Argentina	Venezuela	Argentina	Venezuela	Argentina	Venezuela
Gross wells drilled:
Production:
Development wells:
Oil	39	-	31	-	35	-
Gas	9	-	31	-	36	-
Dry wells
Total	48	-	62	-	72	-
Exploration:
Discovery wells:
Oil	1	-	2	-	2	-
Gas	2	-	3	-	1	-
Dry wells	-	-	-	-	-	-
Total	3	-	5	-	3	-
Net wells drilled:
Production:
Development wells:
Oil	11	-	8	-	19	-
Gas	5	-	17	-	21	-
Dry wells	-	-	-	-	1	-
Total	16	-	25	-	41	-
Exploration:
Discovery wells:
Oil	1	-	1	-	1	-
Gas	2	-	1	-	-	-
Dry wells	-	-	-	-	-	-
Total	3	-	1	-	1	-

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

In 2019, we continued with the development of our investment plan focusing on the activity and development of tight gas reserves in the areas of El Mangrullo and Sierra Chata. Our investment plan included the drilling and completion of 51 producing and injector’s wells.

In the Neuquén Basin, Pampa concentrated its natural gas drilling activity in El Mangrullo and Sierra Chata areas. Also, we completed the first horizontal shale oil well in Rincon de Aranda and continued with the development in the Gobernador Ayala field and drilled 26 wells. Additionally, 12 wells were drilled in El Tordillo, in the Golfo de San Jorge Basin and one gas well was drilled in the Aguaragüe field in Noroeste basin.

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 operates 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.

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During 2019, our production was concentrated in three basins: the Neuquén, San Jorge and Noroeste. In Argentina, we own 581,000 net acres, and in the Neuquén basin — the most important basin in the country in terms of oil and gas production —we own approximately 411,000 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, 2019, we lifted hydrocarbons from 885 productive wells in Argentina.

For the year 2019, our average daily production was 4,990 barrels of crude oil and 259 million cubic feet of natural gas. Considering continuing operations, oil production decreased by 1.4% and gas production increased 8.7%, compared to 2018 average.

The following table sets forth our oil and gas production during 2019. 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, 2019. 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. We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019.

			2019 Production
Production Blocks	Location	Basin	Oil (1)	Gas (2)	Oil  Equivalent  (3)	Operator	Direct and Indirect Interest	Expiration
El Mangrullo	Neuquén	NQN	23	53,631	8,961	Pampa	100.00 %	2053
Sierra Chata	Neuquén	NQN	24	7,240	1,231	Pampa	45.55%	2053
Río Neuquén	Neuquén/Río Negro	NQN	216	15,287	2,764	YPF	33.07%/31.42%	2027/2051
Rincón del Mangrullo	Neuquén	NQN	46	14,991	2,544	YPF	50.00%	2052
Estación Fernández Oro	Río Negro	NQN	1	151	26	YPF	15.00%	2026(4)
Anticlinal Campamento	Neuquén	NQN	-	113	19	Oilstone	15.00%	2026(5)
Río Limay Este (Ex Senillosa) (8)	Neuquén	NQN	-	-	-	Pampa	85.00%	2040
Aguaragüe(6)	Salta	NOA	74	2,531	496	Tecpetrol	15.00%	2023/2027
El Tordillo	Chubut	CGSJ	1,043	539	1,113	Tecpetrol	35.67%	2027
La Tapera – Puesto Quiroga	Chubut	CGSJ	25	-	25	Tecpetrol	35.67%	2027
Gobernador Ayala	Neuquén	NQN	293	-	293	Pluspetrol	22.51%	2036
Veta Escondida - Rincón de Aranda	Neuquén	NQN	15	-	15	Pampa	55.00%	2027(7)
Total			1,760	94,483	17,487

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

(1)    In thousands of barrels of oil equivalent.

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

(4)    Corresponds to production of 13 wells and to a 15% in association with YPF.

(5)    Corresponds to production of nine wells and to a 15% in association with Oilstone.

(6)    It includes San Antonio Sur, expiring in 2023, and Aguaragüe, expiring in 2027.

(7)    Productive field with production associated with Exploration Fields.

(8)    In the process of being transferred to GyP.

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

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	Year ended December 31,
	2019		2018		2017
Argentina	Oil (1)	Gas (2)	Oil (1)	Gas (2)	Oil (1)	Gas (2)
Río Neuquén (3)	216	15,287	260	15,813	234	13,966
El Mangrullo (3)	23	53,631	27	35,841	21	31,881
Rincón del Mangrullo (3)	46	14,991	67	23,414	85	31,308
Other blocks	1,475	10,574	1,494	12,333	6,807	25,885
Venezuela(4) (5)	-	-	-	-	465	-
Total	1,760	94,483	1,848	87,401	7,612	103,040

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

(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 million 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.

(4) Indirect interests through mixed-capital companies.

(5)We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019.

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, 2019, the location and basin of each area, our net working interest and the expiration date for the exploration authorization.

			2019 Production
Blocks/UTE	Location	Basin	Oil kbbl	Gas mcf	Total kboe	Operator	Interest	Expiration
Parva Negra Este	Neuquén	NQN	-	176	29	Pampa	42,50%	2019(1)
Chirete	Salta	NOA	61	-	61	High Luck	50,00%	2019(2)
Rio Atuel	Neuquén	NQN	-	-	-	Petrolera El Trébol	33,33%	2018
Las Tacanas Norte	Neuquén	NQN	-	-	-	Pampa	90,00%	2022(3)
Borde del Limay	Neuquén	NQN	-	-	-	Pampa	85,00%	2015(4)
Los Vértices	Neuquén	NQN	-	-	-	Pampa	85,00%	2015(4)
Total Exploration Blocks			61	176	90
Total Production in Argentina			1,821	94,659	17,577

(1) On July 24, 2015, the Province of Neuquén approved the sale of 50% of our share in Parva Negra Este to ExxonMobil Exploration Argentina S.R.L. As of the date of this annual report, the extension of the exploration license for the Parva Negra Este block was requested from the Province of Neuquén. The approval still remains pending.

(2) On April 6, 2017, the Secretary of Energy of the Province of Salta granted us an extension of the third exploration period in the Chirete concession area for a period of one year. As of the date of this annual report, we requested the Secretary of Energy of the Province of Salta to extend the concession until November 2022 and its approval remains pending.

(3) Optional extension until November2022.

(4) Relinquishment Process.

As of December 31, 2019, we held interests in approximately 445,000 gross exploration acres in Argentina.

Our exploratory investments in gas in 2019 focused on the completion of two Shale Gas Pilot Wells in El Mangrullo, targeting the Vaca Muerta Reservoir. Also, we drilled one Shale Gas Pilot Well in Sierra Chata, targeting Vaca Muerta, which is expected to be completed during 2020.

In respect of oil investments, during 2019, we drilled and completed one exploratory well in Rincon de Aranda Field targeting Vaca Muerta formation. During the second semester of 2019, the well was tested with promising results, and is currently in production.

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In addition to the abovementioned exploratory investments, we also drilled one gas exploratory well in Rincón del Mangrullo field and one oil exploratory well in Río Atuel field.

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, 2019, 2018 and 2017. This table includes our net share of production, joint operations and associates. We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019.

	Year ended December 31,
Argentina	2019	2018	2017
	(in US$ per barrel of oil equivalent)
Production cost	8	6	12
Royalties	3	4	4
Depreciation	6	4	7
Total	17	14	23
Venezuela (1)
Production cost	-	-	90
Royalties	-	-	8
Depreciation	-	-	18
Total	-	-	116

⁽¹⁾ We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and December 31, 2019.

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, 2019, 2018 and 2017. We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019.

	Year ended December 31,
	2019	2018	2017
Argentina (*)
	(in million of US$)
Oil	98	148	385
Gas	342	434	306
Others	4	5	30
Total	444	587	721

Venezuela (1)
Oil	-	-	15
Gas	-	-	-
Total	-	-	15

(*) Includes discontinued operations.

⁽¹⁾ We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and December 31, 2019.

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, 2019, 2018 and 2017. We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and December 31, 2019.
 

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	Year ended December 31,
Average price of sale for barrel of Oil and for million cubic feet of Gas	2019	2018	2017
Argentina
Oil (In US$ per barrel of Oil)	54	23	52
Gas (In US$ per thousand cubic feet)	4	4	3
Average price of sale for barrel of Oil and for million cubic feet of Gas	2019	2018	2017
Venezuela (1)
Oil (In US$ per barrel of Oil)	-	-	32

⁽¹⁾  We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019.

Delivery commitments

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.

As of December 31, 2019, we were contractually committed to deliver approximately 1.5 million mcm per day of natural gas in 2022. According to our estimates as of December 31, 2019, our contractual delivery commitments that do not extend beyond 2020, could be met with our own production and, if necessary, with purchases from third parties.

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, promulgated by the SEC, 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. GCA performed an independent audit of 94% of our estimated proved reserves as of December 31, 2019. We provided all information required during the course of the audit process to the satisfaction of GCA. See the Reserves Report by GCA, dated March 5, 2020 included as Exhibit 13.2 to this annual report.

As of December 31, 2019, 2018 and 2017, 94%, 83% and 100%, respectively, of our estimated proved reserves were audited by GCA.

As of December 31, 2019, our liquid hydrocarbon and natural gas proved developed and undeveloped reserves totaled 135.4 million boe (13.6 million boe of liquid hydrocarbons and 731.1 billion cubic feet, or 121.8 million boe, of natural gas), of which 704.5 billion cubic feet were estimated to be sales gas and 26.6 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 10% and 90%, respectively, of our total proved reserves as of December 31, 2019. The reserves outside Argentina (Venezuela) were reclassified as contingent in December 2016, due to profitability and the economic situation of Venezuela.

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As of December 31, 2019, proved developed reserves of crude oil equivalent represented 52% of our total proved reserves of crude oil equivalent and we had proved reserves equal to approximately eight years of production at 2019 volumes.

The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas as of December 31, 2019, including joint operations and associates.

	Reserves as of December 31, 2019
Reserves Category	Crude oil, condensate and natural gas liquids (million of barrels)	Natural Gas (billions cubic feet)	Oil Equivalent (million boe)
Proved Developed	8.8	372.0	70.8
Proved Undeveloped	4.7	359.1	64.6
Total proved reserves	13.6	731.1	135.4

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, 2019, 2018 and 2017.

	2019		2018		2017
	Millions of barrels of oil equivalent (1)	% of total proved reserves	Millions of barrels of oil equivalent	% of total proved reserves	Millions of barrels of oil equivalent	% of total proved reserves
Proved developed reserves	70.8	52.3%	77.5	59.4%	107.4	64.3%
Proved undeveloped reserves	64.6	47.7%	52.8	40.6%	59.7	35.7%
Total Proved Reserves	135.4	100%	130.3	100%	167.1	100%

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

We prioritize the development of new business opportunities associated with unconventional gas reserves in Argentina. During 2019, we drilled ten wells in the El Mangrullo area, two wells in the Sierra Chata area and one well in the Rincón de Aranda area aimed at developing unconventional gas reserves in the Punta Rosada and Mulichinco tight reservoirs and Vaca Muerta shale gas and shale oil reservoirs.  

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. As of December 31, 2019, the reserves in Venezuela were reclassified as contingent resources since December 2016 because of profitability and the economic situation of such country.

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. We are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information regarding Venezuela for the year ended December 31, 2018 and 2019. 

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	Crude oil, condensate and natural gas liquids			Natural gas
	Argentina	Venezuela	Total	Argentina	Venezuela	Total	Combined
	(in thousands of barrels)			(in millions of cubic feet)			(in million boe) (1)
Total proved developed and undeveloped reserves as of December 31, 2017	41,630	-	41,630	752,686	-	752,686	167.1
Proved developed reserves as of December 31, 2017	32,935	-	32,935	446,594	-	446,594	107.4
Increase (decrease) originated in:
Revisions of previous estimates	1,003	-	1,003	-54,588	-	-54,588	-8.1
Improved recovery	-	-	-	-	-	-	-
Extensions and discoveries	1,943	-	1,943	99,950	-	99,950	18.6
Purchase of proved reserves in place	81	-	81	65,115	-	65,115	10.9
Sale of proved reserves in place	-27,814	-	-27,814	-85,125	-	-85,125	-42.0
Year’s production	-1,845	-	-1,845	-86,073	-	-86,073	-16.2
Total proved developed and undeveloped reserves as of December 31, 2018	14,997	-	14,997	691,965	-	691,965	130.3
Proved developed reserves as of December 31, 2018	9,179	-	9,179	409,782	-	409,782	77.5
Increase (decrease) originated in:
Revisions of previous estimates	-645	-	-645	1,247	-	1,247	-0.4
Improved recovery	-	-	-	3,530	-	3,530	0.6
Extensions and discoveries	970	-	970	128,832	-	128,832	22.4
Purchase of proved reserves in place	-	-	-	-	-	-	-
Sale of proved reserves in place	-	-	-	-	-	-	-
Year’s production	-1,771	-	-1,771	-94,491	-	-94,491	-17.5
Total proved developed and undeveloped reserves as of December 31, 2019	13,551	-	13,551	731,082	-	731,082	135.4
Proved developed reserves as of December 31, 2019	8,805	-	8,805	372,000	-	372,000	70.8
(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, 2019, our liquid hydrocarbon and natural gas proved developed and undeveloped reserves totaled 135.4 million boe (13.6 million boe of liquid hydrocarbons and 731.1 billion cubic feet, or 121.8 million boe, of natural gas), representing a 4% increase compared to proved reserves as of December 31, 2018 (a decrease of 10% and an increase of 6% for liquid hydrocarbons and natural gas, respectively).

During 2019, previous estimates of our fields located in Argentina were subject to revisions representing a decrease of 0.4 million boe mainly attributable to adjustments of production estimates inAguaragüe, Rincón del Mangrullo and Río Neuquén and performance of drilling activities in El Mangrullo and El Tordillo areas, extension and discoveries increased by 22.4 million boe through drilling activities, mostly in El Mangrullo, Rincón de Aranda, Gobernador Ayala and Sierra Chata areas. In addition, an increase of 0.6 million boe was attributable to improved recovery in Rincón del Mangrullo and the Aguaragüe areas.

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As of December 31, 2019, 52% of our proved reserves were developed, while 48% were undeveloped. Proved developed reserves were 70.8 million of barrels of oil equivalent. During 2019, we invested US$29 million to convert approximately 4.1 million barrels of oil equivalent of proved undeveloped reserves to proved developed reserves.

The 22% decrease in our proved undeveloped reserves in 2019 compared to 2018 was mainly attributable to:

(1)	the conversion of approximately 4.1 million boe of proved undeveloped reserves to proved developed reserves, mainly through drilling activities in our production areas in the Neuquén basin, mainly in El Mangrullo, Río Neuquén and Sierra Chata areas and El Tordillo area in the Golfo San Jorge basin;
(2)	extensions and discoveries, through the drilling activities, mainly in El Mangrullo area and the Gobernador Ayala area in the Neuquén basin, which resulted in the addition of 14.0 million boe of proved undeveloped reserves;
(3)	an increase of 1.2 million boe of proved undeveloped reserves, based on negative revisions to previous estimates of reserves and adjustments to production estimates based on performance of drilling activities, mainly in El Mangrullo and El Tordillo areas; and
(4)	the improved recovery in Rincón del Mangrullo and Aguaragüe areas, caused an addition of 0.6 million boe in our proved undeveloped reserves.

The activities described in items (1), (2), (3) and (4) above resulted in a net increase of 11.7 million boe in our proved undeveloped reserves in 2019 compared to 2018.

As of December 31, 2019, our proved undeveloped reserves were 64.6 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 91% of these proved undeveloped reserves into production through activities to be implemented over the next five years. The balance of 9% 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.

We have a total of 5.7 million barrels of oil equivalent of proved undeveloped reserves, all located in Argentina, that have been booked for more than five years. This is because such reserves are mainly located in gas fields where the activity has been scheduled to maintain production levels in accordance with contracts and installed facilities.

Internal Control over Proved Reserves

The reserves estimation process begins with an initial evaluation of our assets by geophysicists, geologists and engineers. A Reserves Coordinator (Coordinador de Reservas orRC), 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 RC 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, 2019. 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 estimate 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

GCA 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. GCA 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 GCA’s business. GCA is fully familiar with the SEC regulations regarding oil and gas reserves (17 CFR Part 210 Rule 4-10 (a)). GCA 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 94% 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, 2019 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

Venezuela

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

However, since the Acquisition, the authorizations regarding the change of indirect control by the Government of Venezuela have not been obtained, and considering the fact that the contracts of mixed-capitalcompanies provide the mandatory transfer of the shares to said government in these cases, we have determined that the fair value of its investment as of the date of Acquisition is Ps.0.

As of the date of this annual report, we have not obtained the authorizations of the Government of Venezuela related to the change of indirect control requested in a timely manner. However, we have presented the technical, legal and financial information required in due time, as well as development plans and financing proposals that were submitted to the majority of the mixed-capitalcompanies, shareholder CVP without receiving a favorable response. Likewise, CVP has determined that, given the time that has elapsed, we should begin the process of submitting plans according to new guidelines to be provided by the Ministerio del Poder Popular de Petróleo de la República Bolivariana of Venezuela, which have not yet been communicated to us.

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We have expressed with the authorities of the Government of Venezuela that our interest in making investments and/or financing proposals in the mixed-capitalcompanies has ceased and that we are willing to negotiate the transfer of our shares to CVP. As a result, we are currently unable to obtain accurate information about the mixed-capital companies in Venezuela and, consequently, have not disclosed information on oil and gas activities regarding Venezuela for the years ended December 31, 2017, 2018 and 2019.

Ecuador

On October 31, 2008, Ecuador TLC, 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 EcuadorTLC 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, Ecuador TLC, 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.

EcuadorTLC’s participation in the Bloque 18 Consortium is 30% and the final award by the arbitration tribunal corresponding to EcuadorTLC 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 EcuadorTLC 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 Ecuador TLC in accordance with the Arbitration Settlement.

As of May 3, 2018, EcuadorTLC has collected the three installments and has 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, EcuadorTLC was notified of the payment on employee participation profits from 2002 to 2010, to the former consortium workers.

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Crude Oil Transportation OCP Agreement

On November 10, 2003, Ecuador TLC, 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, Ecuador TLC 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.

EcuadorTLC is entitled to sell transportation capacity through OCP’s pipeline to mitigate the negative effect of excess contracted capacity. In this respect, EcuadorTLC periodically negotiates the sale of committed transportation capacity. On December 31, 2008, EcuadorTLC and Petroecuador entered into an agreement under which, as from 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 EcuadorTLC and OCP, up to a maximum of 70,000 barrels per day. EcuadorTLC has initiated legal actions against Petroecuador due to breaches of contract by the buyers. In addition, EcuadorTLC sold transportation capacity for approximately 8,000 oil barrels per day to third parties for the July 2004-January 2012 period.

In January 2018, EcuadorTLC assigned to ENOPSA a transportation capacity of 10,000 barrels per day. As a result, Ecuador TLC 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, Ecuador TLC assigned to Trenerec S.A. (a subsidiary company in Ecuador) the remaining transportation capacity of 70,000 barrels per day held with OCP. Additionally, EcuadorTLC 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 become extinguished. As of December 31, 2019, we do not hold any collateral in this respect.

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. As of December 31, 2018, we held an 11.42% interest in OCP. As of the date of this annual report, OCP’s other shareholders were Andes Petroleum, Ecuador Ltd., Perenco Ecuador Limited, Occidental del Ecuador Inc., Repsol Ecuador S.A. and AGIP Oleoducto de Crudos Pesados B.V.

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.

Our subsidiary, Ecuador TLC, 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 on 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 tocertain 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.

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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, including the notification received by OCP on March 19, 2019 regarding the authorization by the Ecuadorian Government on March 8, 2019.

Pursuant to the agreement, if PEB collected such financial credit before its maturity in 2021, PEB should reimburse AGIP 50% or 25% of the collected amount if collection occurred in 2019 or 2020, respectively.

Taking into consideration the timeline of the agreement with AGIP – which was executed prior to the reversal of the above-mentioned situation –  the closing of the transaction resulted in the recognition of a profit of US$25 million according to IAS 28.

In order to estimate the 4.49% share in the fair value of identifiable assets and liabilities assumed in OCP, PEB has calculated the present value of future cash flows expected to be obtained through the collection of dividends considering the concession term that extends until 2023 and a discount rate of 15.3%.

Furthermore, as of December 31, 2019, PEB recorded an impairment loss regarding the 11.42% interest in OCP (before the acquisition of the aforementioned additional 4.49%) of US$6.7 million in connection with the present value of future cash flows expected to be obtained from such interest. Thus, the book value does not exceed the investment’s recoverable value.

As of the date of this Annual Report, we have a 15.91% equity interest in OCP, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.

Oldelval

In line with our strategy to focus our resources on 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, as of December 31, 2018, we held 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 refinery located in the pipeline’s area of influence.

In 2019, oil volumes transported by Oldelval from Allen to Puerto Rosales averaged 24,809 cubic meters per day, while oil transportation to the refineries located in the Province of Neuquén totaled an average 2,355 cubic meters per day. Total transportation volume was 28,045 cubic meters per day, equivalent to 64.4 million barrels transported in 2019, representing a 16.2% increase compared to 2018. In addition, the transportation of crude oil’s service was provided without interruptions, ensuring operational continuity and a reliable pumping system.

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Our Petrochemicals Business

Our petrochemical operations are entirely based in Argentina where we own three high-complexity plants producing styrene, styrene butadiene rubber (SBR) and polystyrene, with a domestic market share ranging between 89% and 100%. 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 Puerto General San Martín, located in the Province of Santa Fe, with an annual production capacity of 50,000 tons of gases (liquefied petroleum gas (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

·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 petrochemicals division in Argentina for the fiscal year ended December 31, 2019 and 2018:

	2019	2018
Technical Information
Sales (in thousand ton):
Styrene (incl. propylene y ethylene)	55	64
SBR	27	26
Polystyrene (incl. BOPS)	44	50
Others	217	213

Styrene Division

As of December 31, 2019, monomer styrene sales volumes totaled 45 thousand tons, representing a decrease of 9% compared to 2018 and polystyrene sales volumes totaled 44 thousand tons,experiencing a 13% decrease in domestic sales associated with the market downsize, and a 46% increase in exports. In order to optimize the results of the business, we decided to discontinue the operation of the BOPS Plant as of April 2018. In this context, the Polystyrene Plant remains temporarily stopped.

In 2019, rubber sales totaled 27 thousand tons, of which 11.8 thousand tons were attributable to the domestic market and 15.1 thousand tons to exports. In 2019, the sales volume increased by 4% compared to 2018.

Reforming Gasoline Division

Sales of intermediate gasoline and naphtha during 2019 totaled 158 thousand tons, increasing by 5% compared to 2018. During 2019, 28 thousand tons of Virgin Naphtha owned by YPF was processed through a processing agreement, obtaining 15 thousand tons of gasoline and naphtha that were returned to YPF, the remaining products obtained from such processing agreement were purchased by us.

Sales of aromatics, hexane and paraffinic solvents during 2019 totaled 49.4 thousand tons, which represented a 6% decrease compared to 2018. Propellant gas (LPG included) sales totaled 9.2 thousand tons in 2019, representing a 11% decrease compared to 2018 associated with lower production volumes.

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As of December 31, 2019, our estimated market share of the following products in Argentina were 100% for styrene, 89% for polystyrene and 89% for SBR.

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 9,231 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 14.5 thousand km of proprietary lines, as well as 6.5 thousand km of Transba-owned high voltage lines. Transener transports 85% of the electricity in Argentina. In addition, we participate in the refining and distribution operations through Refinor, which owns a refinery located at Campo Durán in the Province of Salta with an installed capacity of 25.8 thousand oil barrels per day and a commercial network of 90 gas stations.

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 (“NGL”) 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, 2019, Pampa holds a 27.2% interest in TGS through CIESA.

Description of TGS’s Business Segments

Regulated Segment: Gas Transportation

In 2019, revenues from this business segment amounted to Ps.22,620 million, evidencing a 5% decrease compared to the Ps.23,786 million recorded in 2018. This decrease is mainly due to the deferral of the semiannual update which should have applied since October 2019, the mismatch between the costs variation adjustment and the inflation reflected in the restated financial information, and the lower deliveries of natural gas on an interruptible basis, where the transportation of natural gas is subject to the gas pipeline’s available capacity. These effects were partially offset by the full application of the tariff increase resulting from the RTI granted by Res. ENARGAS No. 310/18 as from April 2018, as well as the increases granted pursuant to ENARGAS Res. No. 265/18 and 192/19 as from October 2018 and April 2019, respectively.

Revenues from this business 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 also provides services on an interruptible basis. Moreover, TGS provides operation and maintenance services for assets allocated to the natural gas transportation service for the expansions incentivized by the Federal Government and held under trusts created to such effect. For this service, TGS receives from customers with incremental natural gas transportation capacities the CAU established by ENARGAS, which remained unchanged since its creation in 2005 until its first update in May 2015.

In 2019, 79% of TGS’s average daily deliveries of natural gas were made under firm transportation agreements, whereas the rest were made under interruptible service, and exchange and displacement agreements. Furthermore, as of December 31, 2019, the total capacity hired on a firm basis amounted to 81.5 million m3/day with a weighted average life of 13.6 years. In 2019, the daily average injection of natural gas into the gas pipeline system operated by TGS amounted to 73.8 million m3/day, a volume 6% higher compared to 2018. In this scenario, TGS’s gas pipeline system was fairly responsive to meet demand needs.

Regarding trade, during 2019, TGS launched an open tender which allowed for the renewal of the total firm capacity of agreements terminating in 2020 and 2021 (which represented an approximate amount of 12.7 million m3/day), achieving an average additional term of 12 years. Additionally, in July 2019 a call for bids was launched for the construction and provision of a transportation service connecting the Vaca Muerta formation with the Province of Buenos Aires. Within the 35 years of concession, a Temporary Special Regime (RET) is contemplated for the first 17 years aiming to make the repayment of the construction feasible. As of the date of this annual report, although the Argentine Government has not confirmed its intentions to conduct the project, TGS is currently analyzing its participation.

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Non-Regulated Segment: Production and Marketing of Gas Liquids

Unlike the gas transportation business, the production and selling of gas liquids is not regulated by ENARGAS.

In 2019, this segment’s revenues accounted for 48% of TGS’s total revenues. In 2019, revenues from sales amounted to Ps.23,138 million (in real terms, 10% lower than in 2018). The decrease in revenues from sales is mainly attributable to the decline in international reference prices, the decrease in the dispatch of ethane, due to Polisur’s impossibility to process the product in its plant after the accident which took place in 2019, and the mismatch between the inflation reflected in the restated financial information and the devaluation during the period over US$-denominated sales. These effects were partially offset by higher propane and butane sales.

Gas liquids production and selling activities are conducted at the Cerri Complex, located close to Bahía Blanca, which is supplied by all of TGS’s main gas pipelines. In the Cerri Complex, ethane, LPG and natural gasoline are extracted from natural gas, which arrives through our three main pipelines from the Neuquina and Austral natural gas basins. TGS sells these liquids to both domestic and foreign markets. In the domestic market, propane and butane are sold to fractioning companies. In the foreign market, the sale of these products and natural gasoline is performed at current international market prices. Ethane is sold to Polisur at a price mutually agreed by the parties.

During fiscal year 2019, the production of liquids was 1,022,914 short tons, lower than 2018. It should be noted that no production restrictions were recorded during the winter period on account of the higher supply of domestic gas from unconventional gas developments, as well as the lower demand resulting from the economic recession, Furthermore, in 2019 total sales volumes reached 1,040,393 tons, 38% of which were destined to exports. Out of the total sales to the domestic market, 75% were made at US$-denominated prices.

With respect to the foreign market, in 2019 average sales prices for propane, butane and natural gasoline experienced 28.5%, 23.3% and 17.0% decreases, respectively, mainly as a result of the decline in international reference prices in the first semester of 2019. International reference prices have initiated a recovery since August 2019.

Furthermore, pursuant to the PEN Executive Orders No. 793 and 865/18, as from September 2018 a duty was imposed on the export of LNG, among other products, with a maximum 12% rate, which was limited to up to 8% as from the entry into effect of the Social Solidarity and Productive Reactivation Law.

It is worth highlighting that TGS has entered into agreements for the export of NGL for the 2018/2019 summer period which not only allowed for an improvement in prices compared to the expired agreements, but also brought short-term certainty for its sales. Furthermore, TGS also exports by land through transportation via trucks to Chile, Paraguay and Brazil which, despite being lower volumes than those exported by sea, allow TGS to capitalize on a higher operating margin.

In the domestic market, during 2019, TGS continued participating in the Household Gas Bottles’ Program and the Propane for Grids Agreement, which 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, which, under certain conditions, results in negative operating margins. Furthermore, as a result of the participation in these programs, the Federal Government has to reimburse to TGS an economic compensation denominated in Argentine pesos, which is currently being collected with delays. Outside these programs, TGS sold 184,941 tons of propane and 14,736 tons of butane, mainly to the reseller market, and, to a lower extent, to the industrial, propellant and automotive market.

Furthermore, in 2019, TGS continued selling ethane under the long-term agreement entered into with Polisur in September 2018. This agreement stipulates commercial guidelines with improvements in the TOP clause, which guarantees for TGS a gradual increase in sales volumes over the first five years of the contract. However, during fiscal year 2019, there was a significant decrease in the volume of ethane sold to Polisur, which amounted to 283,635 tons under the current agreement, 29% lower than in 2018, due to the customer’s impossibility to process the product in its plant after the accident which took place in June 2019. After the accident, Polisur returned to its normal operations in October 2019.

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Non-Regulated TGS’s 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.

This segment represented 6% of TGS’s total income in 2019. Revenues from sales, decreased by 8% in real terms as compared to 2018, which is mainly due to the mismatch between the inflation reflected in the restated financial information and the peso devaluation during the period ended on December 31, 2019 over sales denominated in U.S. Dollars, as well as lower construction, operation and maintenance services, which were partially offset by the commissioning of Vaca Muerta’s gathering pipeline.

The construction of the 147-km gathering pipeline in the Vaca Muerta formation initiated in April 2019, and its commissioning was successfully concluded throughout the year, with a total transportation capacity of 60 million m3 per day and a conditioning plant with an initial capacity of 5 million m3 per day. This pipeline required an investment of US$260 million, and the execution of long-term gas transportation and conditioning agreements with gas producers were key to its development. Additionally, in February 2020, TGS approved the expansion of the conditioning plant with an additional investment of US$15 million.

Furthermore, as of the date hereof, TGS has a portfolio of projects under assessment which will contribute to the development of unconventional resources in Vaca Muerta. In 2019, TGS conducted a pre-feasibility study for the development of a liquefaction plant in the City of Bahía Blanca aiming to increase export opportunities and reduce import needs in the winter period. This project is now subject to the final investment decision. TGS has also made progress on the pre-feasibility study for the construction of a new liquid processing plant in the town of Tratayén, province of Neuquén, which will allow for the enhancement and growth of the liquids business.

However, as a consequence of the COVID-19 TGS adapted its business plan to the economic expectations of Argentina. TGS has implemented a reduction in its investment plans, without affecting those safety works, which allow TGS to guarantee normal business continuity.

Regulatory Framework of Midstream

Regulations Specifically Applicable to Gas Main Pipeline Transportation

RTI

Public Emergency and Exchange Rate Regime Reform Law No. 25,561, enacted in January 2002 and extended on several occasions until January 2018, provided for the conversion into Pesos of utility service tariffs; consequently, the transportation tariff remained unchanged in Pesos as from 1999, despite the sharp increase in price indexes and operating costs. This mismatch directly affected the operating costs of this business segment, deteriorating its economic and financial condition.

On March 29, 2016, the MEyM issued Res. No. 31/16 which, among other measures, instructed ENARGAS to conduct the RTI process and to grant a transitory tariff increase to be charged against the RTI. Within this framework, ENARGAS passed Res. No. 3724/16 on March 31, 2016 approving a 200.1% increase in tariff schemes effective as from April 1, 2016, applicable to the natural gas transportation utility service and the CAU. However, on August 18, 2016, the CSJN established the obligation to hold non-binding public hearings to set the tariffs and prices without market intervention, and declared the nullity of MEyM’s Res. No. 28/16 and 31/16 regarding residential users; therefore, tariff schemes were taken back to the values effective as of March 31, 2016. The public hearing was held on October 6, 2016, and, consequently, ENARGAS approved a 200.1% transitory tariff increase effective as from October 7, 2016, the execution of the investment plan, and restrictions on the distribution of dividends (Res. No. 4054/16).

In December 2016, the public hearing required for the RTI process was held. On March 30, 2017, pursuant to ENARGAS Res. No. I-4362/17, a transitory tariff scheme was approved, with a 214.2% and 37% increase in the natural gas transportation utility service and the CAU, respectively, applicable as from April 1, 2017. The RTI contemplates a semiannual non-automatic tariff adjustment mechanism subject to the PPI published by the INDEC. As a result, TGS executed the 2017 Comprehensive Memorandum of Understanding and the 2017 Transitory Agreement with the purpose of implementing the tariff update; to such effect, ENARGAS Res. No. 4362/17 was issued, which applied the tariff increase resulting from the RTI in three stages, 58% in April 2017, and the remaining in December 2017 and April 2018.

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The RTI considered the income necessary to execute a Five-Year Investments Plan between April 2017 and March 2022 for Ps.6,787 million, expressed as of December 2016 values, which are essential for the operations and maintenance of the main gas pipelines under TGS’s concession, as well as to guarantee the safety and continuity of the gas transportation utility service to meet the system’s expected higher demand resulting from the development of reserves.

The public hearing to present cost variations was held on November 14, 2017, and pursuant to ENARGAS Res. No. 120/17, an average 78% increase in tariff schemes was established, effective as from December 1, 2017, including a 15% increase on account of the non-automatic adjustment established in the RTI for the January – October 2017 period. This increase was deemed as charged against the amounts resulting from the Comprehensive Renegotiation Memorandum of Understanding for the License executed by TGS on March 30, 2017.

The Comprehensive Renegotiation Memorandum of Understanding was ratified by the Federal Government on March 28, 2018 (PEN Executive Order No. 250/18), thus concluding the RTI process initiated in April 2016, and, as a result, on June 26, 2018, TGS voluntarily dismissed the arbitration proceeding it had brought before the ICSID related to the redenomination of tariffs in pesos (pesificación) and other unilateral changes to TGS’s regulatory structure affected by the Public Emergency Law and related laws and decrees violated the requirement of fair and equitable treatment under the treaty. Furthermore, ENARGAS issued Res. No. 310/18 approving, effective as from April 1, 2018, the last installment of the tariff increase established by Res. No. 4362/17, equivalent to a 50% increase in tariff schemes, including a 13% recognition on account of PPI variations for the November 2017 – February 2018 period, and a compensation for the programmed deferral of the increase payable in installments.

For the calculation of costs variations for the February – August 2018 period applicable as from October 2018, TGS requested an approximate 30% tariff increase based on the variation in the PPI; however, on September 27, 2018 ENARGAS issued Res. No. 265/2018 setting a 19.7% increase based on the simple average of the PPI, the Construction Cost Index and the Salary Variation Index (provisional as of June 2018). The regulatory entity alleged that, according to the RTI, under certain macroeconomic conditions and circumstances, such as the significant peso devaluation which occurred in April 2018, and taking into consideration that the semiannual update is a non-automatic adjustment mechanism, it may use other indexes different from the PPI to determine tariff increases.

ENARGAS Res. No. 192/19 determined a 26.0% increase on account of costs variations effective as from April 2019. This increase was calculated based on the PPI semiannual variation for the August 2018 – February 2019 period. Later, 22% of the amount of the bills issued during the July – October 2019 period was deferred, to be recoverable in five installments as from December 2019, pursuant to SGE Res. No. 336/19.

The semiannual update which, according to the RTI, should have applied since October 1, 2019, was deferred pursuant to several regulations. Finally, the tariff increase has been suspended for a maximum term of up to 180 days since the entry into force of the Solidarity Law on December 23, 2019. Furthermore, this Law contemplates the possibility of performing an RTI review for a term of up to 180 days.

Public Tender for the Litoral Main Gas Pipeline

SGE Res. No. 437/19 issued on July 30, 2019 launched a national and international public tender for the award of a gas transportation license to connect the town of Tratayén, in the Province of Neuquén, with the town of Salliqueló, in the Province of Buenos Aires (phase 1), and Salliqueló with the City of San Nicolás de los Arroyos, in the Province of Buenos Aires (phase 2).

The new license provides for a RET for the first 17 years of the total 35-year concession term for the repayment of the construction and, for the rest of the concession period, Gas Law No. 24,076 will apply. Furthermore, the license agreement provides for an irrevocable transportation offer of 10 million m3/day to CAMMESA for a 15-year period.

The date for the opening of tenders was successively postponed until March 31, 2020. As of the issuance of this Annual Report, although the new Government has not expressed itself on this matter, TGS is analyzing the bid terms and its participation.

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Our Interest in Transener

Transelec owns 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 was acquired equally by Electroingeniería S.A., which in turn transferred its participation to Grupo Eling S.A. and IEASA. More recently, Grupo Eling S.A. transferred its participation to IEASA.

Transener was privatized in July 1993, when CITELEC was awarded the Argentine Government’s controlling stake in Transener. In August 1997, the Province of Buenos Aires privatized Transba, a company organized in March 1996 to own and operate the regional electricity transmission system of the Province of Buenos Aires. Transener acquired 90% of Transba’s capital stock on August 5, 1997.

On September 30, 2016, Grupo Eling S.A sold its interest in CITELEC and all of their rights and obligations under the technical assistance agreement for the operation, maintenance and administration of system of the high voltage electric energy transport system dated November 9, 1994, were transferred to IEASA, except for amounts accrued to Grupo Eling S.A until September 30, 2016.

Transener’s operations

Transener is the leading company in the utility service of high voltage electricity transmission in Argentina, which directly operates 85% of the high voltage lines of the country. Transener operates and maintains the leading electricity transmission system in Argentina at the 500 kV level under a concession agreement under which Transener holds an exclusive 95-year concession to provide high voltage electricity transmission services throughout the Transener network spanning 14,489 km and 57 transforming substations.

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 6,492 km and 104 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 Electricity Transmission System operated and maintained by Transener is subject to increasingly higher load conditions every year. In 2019, the peak voltage had not exceeded the previously highest historical peak voltage of 26,320 MW recorded in 2018.

Despite the great number of power grid solicitations, in 2019 service quality has been fully acceptable for the values required from a company like Transener, which ended the year with a failure rate equal to 0.35 failures per each 100 kilometer-line, which is consistent with international parameters accepted for companies that operate and maintain extra high-voltage transmission systems.

Business Development

              Engineering Services

Taking into consideration its electrical system projects, Transener has focused on projects with competitive advantages by giving priority to those within the 500kV and 132kV systems.

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The development of several projects for the replacement and installation of new reserves in the transportation system, has brought new service requirements such as: elaboration of contract specifications, electric studies, implementation of the generation and demand control (DAG and DAD systems), testing and entry into service of the transformer stations. Transener’s technical team extensive expertise has been a key factor in the customers’ decision to entrust it with the performance of critical works. Bidding documents for the expansion of the transmission system under the RenovAr I and II Programs, as well as other expansions to be executed by different WEM agents have been prepared. Among the most important projects, we can mention the 132-kV expansion works for power input from wind farms.

              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 utiliy 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, OPGW 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

Transener has continued to provide infrastructure services to different communication companies during 2019, 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.

Regulatory Framework of Transmission

Transener’s Tariff Situation

The Public Emergency and Exchange Rate Regime Reform Law (Law No. 25,561) imposed the obligation on public utilities, such as Transener and its subsidiary Transba, to renegotiate their agreements in force with the Government while continuing to provide electricity services. This situation has significantly affected Transener and Transba’s economic and financial condition.

In May 2005, Transener and Transba entered into a Memorandum of Understanding with the UNIREN stipulating the terms and conditions to update the Concession Agreements. The guidelines of this Memorandum of Understanding provided for the performance of an RTI before the ENRE and the determination of a new tariff regime for Transener and Transba, which should have come into force in 2006, as well as for the recognition of variations in operating costs incurred until the entry into effect of the new tariff regime resulting from the RTI.

Since 2006, Transener and Transba have repeatedly requested the ENRE to regularize compliance with the commitments stipulated in the Memorandum of Understanding, expressing the need to launch the RTI process. Furthermore, Transener and Transba filed their respective tariff claims for their assessment, the holding of a public hearing and the definition of the new tariff scheme.

Instrumental Agreement

In December 2010, Transener and Transba entered into an Instrumental Agreement, in connection with UNIREN’s Memorandum of Understanding, with the SE and the ENRE, which mainly provided for the acknowledgment of a credit claim in favor of Transener and Transba for cost fluctuations incurred during the June 2005 – November 2010 period, calculated as per the cost variation index established in the Memorandum of Understanding. These receivables were assigned in consideration of disbursements by CAMMESA pursuant to loan agreements.

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RTI

ENRE Res. No. 66/17 and No. 73/17 passed in February 2017, as amended, established the tariffs for the 2017/2021 five-year period. Furthermore, the ENRE established the remuneration update mechanism, the service quality system and applicable penalties, the reward system, and the investment plan to be executed by both companies during such period. In October 2017, the ENRE issued Res. No. 516/17 and No. 517/17 partially upholding the Motions for Reconsideration filed by Transener and Transba and establishing, retroactively as of February 2017, a Ps.8,629 million and Ps.3,575 million recognized capital base and Ps.3,534 million and Ps.1,604 million annual regulated income for Transener and Transba, respectively.

The purpose of the semiannual adjustment mechanism stipulated in the RTI is to keep real-term values for remunerations collectable by Transener and Transba during the RTI’s five-year period. The adjustment formula takes into consideration the variations during such semester in the PPI – “Manufactured Products” item, the CPI and the Salary Index published by the INDEC, which are weighed based on the cost structure and average investments for the 2017-2021 period in the RTI. This mechanism contemplates a trigger clause that weighs the PPI and the CPI semiannual variations published by the INDEC, ascertained at a variation equal to or higher than 5%.

For the December 2016 – June 2017 period, the trigger clause reached 9.02%, and, therefore, the semiannual adjustment for Transener and Transba remuneration was activated; however, its application was deferred until December 15, 2017, when ENRE issued Res. No. 627/17 and No. 628/17 updating Transener and Transba’s compensation by 11.35% and 10.96%, respectively, for the December 2016 – June 2017 period, retroactively to August 1, 2017.

ENRE Res. No. 37/18 and No. 38/18, issued on February 19, 2018 and later amended by ENRE Res. No. 99/18 and 100/18 on April 5, 2018, updated Transener and Transba’s remunerations by 24.15% and 23.39%, respectively, for the December 2016 – December 2017 period, effective as from February 1, 2018. On November 16, 2018, the ENRE issued Res. No. 280/18 and No. 281/18, updating Transener and Transba’s remunerations by 42.55% and 43.25%, respectively, for the December 2016 – June 2018 period, effective as from August 1, 2018.

On March 22, 2019, the ENRE issued Res. No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 78.41% and 81.26%, respectively, for the December 2016 – December 2018 period, effective as from February 1, 2019. On September 25, 2019, the ENRE issued Res. No. 269/19 and No. 267/19 updating Transener and Transba’s remunerations by 112.41% and 115.75%, respectively, for the December 2016 – June 2019 period, effective as from August 1, 2019.

The Social Solidarity and Productive Reactivation Law, which entered into effect on December 23, 2019, provided that electricity tariffs under federal jurisdiction would remain unchanged, and contemplates the possibility to perform an extraordinary review of the current RTI for a maximum term of up to 180 days. As of the date hereof, Transener has received no instructions by the ENRE on the semiannual remuneration update which, according to the RTI, should have applied as from February 1, 2020 corresponding to the December 2016 – December 2019 period.

Distribution of Transmission Costs among WEM Users

SEE Res. No. 1085/17 issued on November 28, 2017 (effective as from December 1, 2017) established the methodology for the distribution of costs associated with the remuneration of transmission companies among its users (distributors, GU, self-generators and generators). These costs are distributed based on the demand and/or contribution of energy by each WEM agent directly and/or indirectly associated to the DisTro, after discounting costs assigned to generating agents as operational and maintenance costs for connection and transformation equipment.

It is worth highlighting that prices payable by distribution companies in consideration of electric power transmission within the WEM are stabilized for their payment by distributors, and are calculated together with each Seasonal Programming or Quarterly Reprogramming. In the case of distributing agents whose demand is connected to different DisTros, their demand’s percentage corresponding to each DisTro will be established, and the price will contemplate the demand and the price on a weighted basis. Furthermore, prices applicable to GU within the WEM are calculated in the economic transaction on a monthly basis. In the case of WEM GU not directly associated with the high-voltage transmission and/or DisTro, the applicable monthly value will be that corresponding to the connecting agent.

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Our interest in Refinor

We have a 28.5% interest in Refinor, whose other shareholders are YPF (50%) and Pluspetrol S.A. (21.5%). Refinor is engaged in crude oil refining, natural gas processing, product transportation, marketing and sales.

Refinor owns the only refinery in the northern region of Argentina, which is located in Campo Durán, in the Province of Salta. Refinor’s refining capacity is 25.8 thousand barrels per day and its natural gas processing capacity is 20.3 million cubic meters of gas per day (“mcm/d”).

Refinor owns and operates the following processing plants: an atmospheric distillation unit (topping), a vacuum distillation unit, a gasoline hydro-treatment unit, a catalytic reformer plant, an isopentane plant using fractional distillation of gasoline turbex, two turbo expander and fractioning plants for LPG production, as well as a plant for the production of auxiliary services (industrial water, steam, electricity, compressed air) used in the different processing plants.

The Campo Durán refinery receives crude oil/condensate and natural gas from the northwestern basin and from Bolivia. These operations are conducted through two oil pipelines and three gas pipelines. In 2019, the average daily processing of crude oil amounted to 5,852 barrels. In turn, gas processing reached a daily average of 6.9 million cubic meters.

Refinor entered into an agreement with IEASA in 2012 to supply the compression gas service, which IEASA was importing from Bolivia. In 2019, this agreement was amended to extend: (i) the compression’s capacity up to 21 mcm of gas per day; and (ii) the term of the agreement to April 2021.

In addition, Refinor operates a 1,108 km-long pipeline running from Campo Durán (in the Province of Salta) to Montecristo (in the Province of Córdoba) for the distribution of its products. Along the pipeline, the Banda Río Salí (in the Province of Tucumán), Güemes (in the Province of Salta) and Leales (in the Province of Tucumán) dispatch plants are supplied. This pipeline is the most important distribution channel for liquids generated in the Northwestern Basin in Argentina and transports diesel, virgin naphtha, gasoline components for formulating motonaphtas for automotive use, butane and propane.

As of December 31, 2019, Refinor had a commercial network of 90 gas stations located in the Provinces of Tucumán, Salta, Santiago del Estero, La Rioja, Jujuy, Catamarca and Chaco. Through these gas stations, Refinor sells a high performance fuel line, including: Premium Max (97 octanes), Super Max (95 octanes) Eco Diesel Max and Eco Diesel Premium Max.

In 2019, sales of gasoline, gasoil, raw naphtha and other liquid fuels amounted to 478 thousand cubic meters, which represented a 10% decrease compared to 2018. LPG sales amounted to approximately 74 thousand tons, representing a 62% decrease compared to 2018.

Quality, Safety, Environment and Occupational Health

We consider that economic progress will only be sustainable to the extent performance is attained through the implementation and improvement of a management system committed to all stakeholders: shareholders, customers, employees, the community, suppliers and supervisory bodies, with a focus on quality personal health and safety, environmental care and energy efficiency.

Pampa applies its quality, safety, environment and health (QSELH) policy in all its business segments through guidelines establishing good practices, ensuring compliance with regulations, and pointing the way towards continuous improvement in QSELH. In 2019, Pampa completed the first QSELH guidelines’ assessment and improvement program in all its facilities, and its results were used as a reference for 2019 and 2020 planning.

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In addition, we continued advancing management programs in all our operations by allocating important resources, both at the corporate and asset level, to staff training; and furthered the development and strengthening of our QSELH culture through an integrated and aligned QSELH management.

Quality

We improved our management quality by using international ISO standards and the ‘National Quality Prize’ as references and seeking continuous improvement in all our activities. The main methodologies applied for quality management are certified management systems, standards managements, anomalies and audits, and improvement teams.

In 2019, the QSELH risk management matrix was updated to facilitate the integrated assessment of the most relevant risks, and the first evaluation cycle, scheduled to be conducted from December 2019 to April 2020, was launched in all the facilities.

Our asset management system is certified under ISO 9001 (generation, refining and distribution and petrochemical business - quality management), ISO 14001 (environmental management), OHSAS 18001 (occupational health and safety management) and ISO 50001 (energy management) international standards. Pursuant to the implemented model, external audits are conducted on an annual basis to guarantee adherence to the requirements of the above-mentioned international standards. Furthermore, each asset has a management program in place which promotes continuous performance improvement.

During 2019, we started the certification process for the new ISO 45001:2018 standard, which replaces OHSAS 18001, reinforcing safety and health management at the workplace. Seven induction workshops were offered, and certifications are expected to be completed between 2020 and early 2021. CTGEBA was certified under the new standard, and also received the Efficient Argentina award, granted by the National Undersecretariat of Renewable Energies and Energy Efficiency, in the Energy Management category.

With respect to quality standards in daily management, in early 2019 the anomalies management process was reviewed and among other actions, it was decided to strengthen contractors’ control and performance improvement. In July 2019, a global QSELH improvement project for applications operating in the SharePoint and Qlikview platforms was launched, offering a more agile, modern and customized solution for Pampa’s needs.

We continue developing ‘Improvement Teams’, an initiative launched in 2012 with the purpose of implementing enhancements with a focus on efficiency, productivity, costs, quality, safety and environment.

Safety

We have moved forward with the definition and periodic monitoring of our safety goals through the QSELH indicator board, as well as with the development of different initiatives to improve safety management and performance in each of our facilities. In 2019, we worked with the Health and Safety Golden Rules, which are targeted to all Pampa employees to protect individuals performing high-risk tasks. These rules are mandatory, and are part of the daily activities.

Along the same lines, a Work Permits System Manual was drawn up focusing on a comprehensive risk analysis during the planning stage of tasks. In 2019, four workshops were organized for specialists of each of our businesses to meet their specific needs.

In terms of human behavior, which is one of the pillars of QSELH management, a comprehensive review of the Behavioral Preventive Observations tool was made focusing on the approach to people, seeking commitment, and increased awareness on prevention and compliance with the golden rules during such observations.

With regards to industrial hygiene, we continued focusing on quality improvements in hygiene risk maps, covering chemical, physical and ergonomic risks. Assessments were conducted, and metrics of both work environments and individual dosimetry were optimized, resulting in several plant improvements geared at minimizing risks.

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Environment

Our operations are conducted within a context of sustainable development. We are committed to the protection of the environment and endeavor to use natural resources rationally in each of our projects by applying proper and economically viable technologies.

We continue managing environmental risks to prevent the occurrence of undesirable events and/or to minimize their impact by developing actions and programs, for example, for the integrity of aerial and underground pipelines and tanks. The Risk Management Matrix (MGR-QSELH), a tool to be implemented in 2020 through ad hoc technical teams, will focus, among other aspects, on anything that may pose a potential risk of damage to verify the proper implementation of the corrective measures. In addition, monitoring and environmental studies are performed to become acquainted with different environmental situations.

In line with the country’s energy requirements and aiming to have an active participation in the diversification of the Argentine energy matrix, in 2019 we started operations of PEPE II and III, with a total installed power capacity of 106 MW, and important progresses were made at CTGEBA’s cycle closing, which are expected to become operative by mid-2020 and will add 383 MW to the matrix. In June 2019, we acquired CTEB in partnership with YPF, and will operate the power plant over the next four years, with a 567 MW capacity, participating in its cycle closing, which will add an additional 280 MW of power capacity.

Response to Emergency

Although we endeavor to prevent undesirable events, we are fully prepared to provide a prompt and efficient response to emergency situations to minimize possible consequences. In 2018, we continued making periodic emergency response exercises in terrestrial and aquatic scenarios to develop the skills and capabilities necessary to set up emergency plans and coordinate the necessary activities to be deployed should an undesirable event occur.

Should an undesirable event occur, practices and trainings are performed based on the roles established in the Emergency Response Plans in order to develop all the necessary skills and capabilities to execute emergency plans and coordinate the necessary activities. In 2019, critical emergency scenarios in the power generation business were identified and updated, and this process will be extended to the rest of the businesses in 2020.

Furthermore, in 2019 we started a survey on the condition of fire detection and suppression systems with the purpose of assessing their proper working condition and response capacity. We also provided basic training on the emergency response methodology known as Incident Command System, which will be applied to each business during 2020.

Occupational Health

In 2019, we continued implementing our alcohol, drugs and psychoactive substances’ policy. In addition, the Preventive Labor Environments certification granted by SEDRONAR and COPOLAD (“Programa de Cooperación entre América Latina, el Caribe y la Unión Europea en Políticas sobre Drogas”) was obtained in all facilities operated by us. These certifications aim to recognize the implementation of preventive programs in work environments, which involve the development of the preventive and effective actions policy based on the employees’ welfare.

Aiming to promote the biopsychosocial health of all our members, in 2019 we continued advancing our Labor Health Management program. Occupational and risk medical exams were performed on more than 2,000 employees, and individual feedback was provided for the granting of the Certificate of Physical Fitness. Furthermore, the Labor Health qualification for contractors was completed.

With regards to prevention, we continued implementing the physical activity program, as well as flu and tetanus immunization campaigns. Furthermore, the cardio-protection program continued, which aims to train staff to be able to provide immediate assistance through Cardiopulmonary Resuscitation (CPR) and the use of the automated external defibrillator (AED). In 2019 and jointly with Experta ART, CPR courses were given in all of our facilities with the use of AED and First Aid training, and we achieved the certification as a cardiac-safe company.

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On the other hand, together with theFoundation, a blood donation campaign was conducted through the implementation of voluntary blood donation drives, collecting 158 blood bags. This practice is organized on a systematic basis in all our facilities to strengthen the bonds among Pampa, its staff and the community.

Corporate Responsibility 

Programs and social investment actions performed by Pampa are embedded in a strategic relational model with our stakeholders led jointly with the Foundation. With a strong commitment to the community, we develop programs oriented towards improving the quality of life of individuals, and strengthening the capabilities of the institutions of the communities where we operate.

As a company committed to managing the economic, social and environmental impacts of our business, through our social investments and the voluntary support of our employees, 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. We have developed program SDG 17 (partnerships for the goals) which is cross-cutting to all our initiatives.

In 2019, we continued reinforcing our strategic social programs with emphasis on education, employment and social inclusion. Set forth below a brief description of our programs.

Education and Labor Placement Training

We believe that education is key to development and social and labor market inclusion. Therefore, we seek to provide equal opportunities to vulnerable boys and girls.

Through the granting of scholarships and the development of soft skills, we support the completion of technical secondary education studies and the entrance into universities of teenagers living in the Provinces of Neuquén, Salta, Mendoza, Buenos Aires and Santa Fe. In 2019, we supported 1,082 students in the last three years of technical secondary education and 349 university students. In addition, there were 421 secondary education graduates and 25 university graduates from academic courses associated with our businesses, mainly engineering.

Furthermore, we continued supporting the Learning Schools Network, a program fostered by the Ministry of Education of the Government of the Province of Buenos Aires that provides training to 1,914 principals and 7,214 teachers throughout the province; and we granted 15 scholarships for the Bachelor’s Degree in Educational Management at Escuela Superior de Economía y Administración de Empresas (Higher School of Economy and Business Administration). At the secondary level, together with the National Institute of Technical Education, we conducted the “Trainers’ Training Program”, an initiative that provided tools to 310 teachers for the planning and implementation of the students’ professional practices. We organized 12 meetings in the Provinces of Mendoza, Neuquén and Salta.

Regarding the Labor Placement Training, we conducted professional practices and first job workshops so that secondary and university students may consolidate, integrate and develop knowledge and capabilities matching the professional profile they are developing and to increase their employability opportunities.

In 2019 we continued fostering professional practices for more than 191 students attending the final grades at different technical schools, who performed practices at Pampa and the Group’s subsidiaries, as well as in projects in association with other institutions, totaling more than 20,000 practice hours; 49% of these students were also part of our secondary school scholarships program. In turn, at the university level, 30 interns performed professional practices and internships and, since the beginning of the Educational Paths Escort Program, 19 interns have been hired in different arms of the Pampa Group. In the Provinces of Buenos Aires and Salta, we conducted eight first-job workshops with the attendance of 1,270 near graduates from secondary school.

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Local Assessment and Development of Community Impact Projects

We believe in the creation of shared value, and we design and execute local development projects in coordination with municipalities and civil organizations. These projects arise from dialog and mapping processes with our stakeholders, whereby we identify different problems affecting each community and define strategic courses of action related to our business.

We understand that the relationship between the Company and its stakeholders is cross-cutting throughout the business. In 2019, we worked with leaders and heads of different Company areas to incorporate a strategic view and define the direction, scope, priorities and issues to address with respect to each interest group. We organized five workshops, provided training to 56 employees and developed six analysis matrices aiming to move forward with the action plan in 2020, including the following: (i) Sustainable Energy; (ii) Skills Training and Support to Productive Undertakings; and (iii) Enhancement of Local Organizations.

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. With ‘Pampa Volunteering’, we seek to generate a space where, through the Volunteering Committees, employees may identify social problems at the local level and draw up proposals which may contribute to solve them. This allows each employee to reinforce its relationship with the community, contribute to its socio-economic and community development, and strengthen the organizational culture and the employees’ sense of belonging.

We hold periodical meetings to discuss the volunteering intervention strategies. The committee members at each facility define action plans for volunteering activities and their coordination with strategic partners at a local level. In 2019 we fostered 49 actions, with the participation of more than 1,300 volunteers who dedicated more than 19,000 hours to humanitarian activities. We currently have nine active volunteering committees, of which three new committees are in the process of being established.

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 Operational results -Electricity Demand and Supply – Seasonality”.

Property, Plant and Equipment   

We have freehold and leasehold interests, but there is no specific interest that is individually material to us. The majority of our property, consisting of oil and gas reserves, voltage lines, petrochemicals plants, power plants, manufacturing facilities, stock storage facilities, pipelines, oil and gas wells 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, 2019, the total generation assets covered under these policies are valued at US$4,558 million.

In our oil & gas business, we carry full insurance, including business interruption and general liability insurance. As of December 31, 2019, the total oil & gas assets covered under these insurance policies are valued at US$449 million.

 In our petrochemical business and distribution business, we also carry full insurance, including business interruption and general liability insurance. As of December 31, 2019, the total assets covered under insurance policies are valued at US$1,217 million.

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Patents and Trademarks

Certain portions of our commercial activities are conducted under licenses granted by third parties. Royalties related to sales associated with such commercial activities are paid under the relevant licenses. In 2019, we used the name “Petrobras” with the permission of Petrobras and its relevant affiliates. We used the name “Petrobras” and related brands for the performance of the downstream business activities in Argentina (basically, operation of gas service stations and production and commercialization of lubricant products), and we have the right to continue doing so (subject to certain contractual terms) for a period of three years, ending in July 2019.

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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.

The Public Emergency Law combined with the devaluation of the Peso and high rates of inflation had a severe effect on public utilities in Argentina. Because public utilities were no longer able to increase tariffs, inflation led to decreases in their revenues in real terms and a deterioration of their operating performance and financial condition. Most public utilities had also incurred large amounts of foreign currency indebtedness under the Convertibility Law 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 combined cycle generators had been completed. These two generators commenced commercial operations in open cycle during 2008 and in combined cycle 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 Fondo Para Inversiones Necesarias que Permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista (the fund for investments required to increase the electricity supply in the WEM, or “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.

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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.

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 IEASA. The generator in the WEM was IEASA. 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 IEASA 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 (see “—The Argentine Energy Sector— Remuneration Scheme for Generation Not Covered by Contracts—SEE Resolution No. 19/2017: February 2017 - February 2019”). As of the date of this Annual Report, the current remuneration scheme as from 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: Current Remuneration Scheme as from February 2020”).

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: Current Remuneration Scheme as from February 2020”).

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’s and enabled the President to intervene the regulatory authorities (ENRE and ENARGAS).

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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 Productive Development (“MDP”), which assumed the responsibility of the ME&M and 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.”

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.

The ENRE is managed by a five-member board of directors appointed by the Argentine Government. On January 30, 2018, a new board was appointed (Decree No. 84/18). Two of these members are nominated by the Consejo Federal de la Energía Eléctrica (Federal Council on Electricity, or 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.

The Annual Budget Law for 2019, established the transfer of the ENRE’s jurisdiction over Edenor and Edesur to the local authorities (City of Buenos Aires and the Province of Buenos Aires). However, the Social Solidarity and Productive Reactivation Law, established that during the term of the emergency declared therein, the tariffs shall continue to be defined by the ENRE.

On March 16, 2020, the Executive Branch ordered the intervention of the ENRE as authorized by the Social Solidarity and Productive Reactivation Law.

The creation of the WEM made it necessary to create an entity in charge of the management of the WEM and the dispatch of electricity into the National Interconnection System (the “SIN”). The duties were entrusted to CAMMESA, a private company created for this purpose.

CAMMESA is in charge of:

· the dispatch of electricity into the SIN, maximizing the SIN’s safety and the quality of electricity supplied and minimizing wholesale prices in the spot market;

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· 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, 2018, Argentina had a nominal installed capacity as reported by CAMMESA of 38.5 GWh. In 2018, thermal generation generated 87,725 GWh (64%), hydroelectrically energy generated 39,671 GWh (29%), the nuclear energy generated 6,453 GWh (5%) and renewable energy generated 3,350 GWh (2%). In 2018, imports amounted to 344 GWh and exports to 280 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 concessions agreements. The three distribution companies divested from SEGBA (Edenor, Edesur and Edelap) 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:

         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

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· 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.

       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;

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· 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).

On October, 2019, through SEERRYM No. 38/19, the spot price at the WEM was established at 720 Ps./MWh

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, as from February 1, 2020, SE Res. No. 31/20 has come into in effect.

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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.”

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:

¾in 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

¾in 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 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 estimates, 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.

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.

Stabilization fund

The stabilization fund, managed by CAMMESA, was created to absorb the difference between purchases by distributors at seasonal prices and payments to generators for energy sales at the spot price. When the spot price was lower than the seasonal price, the stabilization fund increased, and when the spot price was higher than the seasonal price, the stabilization fund decreased. The outstanding balance of this fund at any given time reflected the accumulation of differences between the seasonal price and the hourly energy price in the spot market. The stabilization fund was required to maintain a minimum amount to cover payments to generators if prices in the spot market during the quarter exceeded the seasonal price.

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Billing of all WEM transactions is performed monthly through CAMMESA, which acts as the clearing agent for all purchases between participants in the market. Payments are made approximately 40 days after the end of each month. However, due to the default of the other WEM’s agents –mainly distributors- during 2013 such payment period increased to an average of 90 days.

The stabilization fund was adversely affected as a result of the modifications to the spot price and the seasonal price stipulated by the emergency regulations, pursuant to which seasonal prices were set below spot prices resulting in large deficits in the stabilization fund. As of December 31, 2019, the stabilization fund balance was approximately Ps. Ps. 229,981,164,648. This deficit has been financed by the Argentine Government through loans to CAMMESA, FONINVEMEM funds, and through other specific agreements between the SE and the generators, but these actions continue to be insufficient to cover the differences between the spot price and the seasonal price.

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.

FONINVEMEM

In 2004, the Argentine Government, seeking to increase thermal generation capacity, created a fund called FONINVEMEM to be administered by CAMMESA and to provide funds for investment in thermal generation. To provide capital for the FONINVEMEM, the SEE invited all WEM participants holding interest-bearing receivable credits against CAMMESA, also known as LVFVDs (Sales Settlements with Due Date to be Determined), that originated from January 2004 to December 2006 to contribute these credits to the FONINVEMEM. In exchange, generators were entitled to participate in the construction of two new 800 MW combined cycle generators to be financed with funds from the FONINVEMEM. Consequently, on December 13, 2005, the generator companies TMB and TJSM were created. Generators that opted to participate in these projects received ten-year take-or-pay supply contracts of electricity and an equity interest in the two new power projects. As of the date of this annual report, both combined cycle generators had started operations as closed-cycle generations units. In addition, the Argentine Government required generators to contribute 65% of their profits (in the case of hydroelectric generators) or variable margins (in the case of thermal generators) to the FONINVEMEM, to be repaid in 120 installments or, at each generator’s option, capitalized in the new power projects. However, because total investment in these two projects was expected to exceed available financing from the FONINVEMEM, in 2005 the Argentine Government created special charges to non-residential consumers per MWh of energy billed and specific charges applicable to large users, in each case to be deposited in the FONINVEMEM. Since March 2010, CAMMESA has started paying the corresponding installments as stated in the FONINVEMEM conditions. Therefore, as of that month, we started collecting the first installment related to receivables of our hydroelectric units, CPB and Central Térmica Güemes.

In 2007, the Argentine Government amended the terms of the FONINVEMEM by reducing mandatory contributions from generators to 50% of profits or variable margins. Repayment of these contributions would also be made in 120 installments at LIBOR plus 1% margin. However, generators were no longer permitted to capitalize their contributions. In addition, on May 31, 2007, the SEE offered generators the opportunity to allocate credits contributed to the FONINVEMEM in 2007 to new electricity investments, so long as these investments were at least four times higher than the amount of the credits and the projects had to comply with certain conditions.

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In accordance with this resolution, we submitted all of our installed capacity expansion projects against our FONINVEMEM credits for 2007. These projects include HINISA, HIDISA, CPB, Central Térmica Güemes and Loma la Lata, for an aggregate amount of approximately US$13 million as of December 2007. On June 20, 2008 the SEE verified our proposal and instructed CAMMESA to pay the 2007 LVFVDs, which as of December 31, 2008, had been duly collected.

In 2012 and 2013 the SEE (pursuant to SE Resolution No. 1261/2012 and Note No. 5568/13) approved the works in order to increase the total capacity of Termoeléctrica Manuel Belgrano and Termoeléctrica José de San Martín and instructed CAMMESA to request the shareholders of Termoeléctrica Manuel Belgrano and Termoeléctrica José de San Martín to allocate a portion of their LVFVD accrued during 2008-2011 not used in other projects for such purpose.

The LVFVD allocated to the expansion of Termoeléctrica Manuel Belgrano and Termoeléctrica José de San Martín will be repaid pursuant to the scheme governing repayment of original investments in these power plants, converted into Dollars at the rate established by the Central Bank (“Tipo de Cambio de Referencia Comunicación A 3500 (Mayorista)”) on the date of the effective payment to the contractors of the works. As of the date of this annual report, CAMMESA repaid some of the LVFVD’s allocated to such projects.

HIDISA, HINISA, CPB and CTG adhered to such request, which resulted in the partial termination of certain assignments executed with CTLL for the allocation of such LVFVDs to the Loma de la Lata Project.

Situation at TMB and TJSM

The PPAs entered into between CAMMESA and the Bice Fideicomisos S.A. (“BICE”), in its capacity as trustee and acting on behalf of the Trusts, for the purchase and sale of energy produced by TMB and TJSM, terminated on January 6 and February 2, 2020, respectively. Consequently, as from these dates, the remuneration collectable by such power plants are those stipulated for capacity without contracts.

Simultaneously, the respective Trust agreements were terminated. As a consequence, this triggered the process for the incorporation of the Government as a shareholder of TMB and TJSM; once completed, the Trustee will transfer the trust assets —including such power plants— to the beneficiary of the Trust, which are the managing companies, including Pampa. As of the date of this Annual Report, the incorporation of the Government as a shareholder of TMB and TJSM remains pending.

As TMB and TJSM’s operating and maintenance contracts also terminated on the above-mentioned dates, on January 3, 2020, the applicable amendments to the management contracts were executed extending their validity until the actual transfer of each Trust’s liquidation assets, setting a new remuneration for such management.

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, replaced by SRRYME Resolution No. 1/19 as from March 2019); (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

SEE Resolution No. 19/2017: February 2017 - February 2019

The SEE Resolution No. 19/17 issued on February 2, 2017, established a remuneration scheme for legacy capacity which was applied from January 1 to February 28, 2019, when it was amended by SRRYME Res. No. 1/19, which entered into effect on March 1, 2019.

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Res. No. 19/17 provided for remunerative items based on technology and scale, establishing U.S. Dollar-denominated prices payable in Argentine pesos, by applying Central Bank’s exchange rate effective on the last business day of the month of the transaction’s maturity date, according to CAMMESA’s Procedures.

               Thermal Power Generators

The resolution provides for a minimum remuneration for power capacity based on technology and scale and allows generating, co-generating and self-generating agents owning conventional thermal power stations to offer Guaranteed Availability Commitments for the energy and power capacity generated by their units not committed under the Energía Plus service modality or under a WEM Supply Agreement pursuant to SE Resolution No. 220/07.

Availability Commitments for each unit should be declared for a term of three years, together with information for the Summer Seasonal Program (except for 2017, where information may be submitted within the term for the winter seasonal period), with the possibility of offering different availability values for summer and winter six-month periods.

Finally, generators will enter into a Guaranteed Availability Commitment Agreement with CAMMESA, which may assign it to the demand as defined by the SE. The committed thermal generators’ remuneration for power capacity will be proportional to their compliance.

              Minimum Remuneration

             Applicable to generators with no Availability Commitments:

Technology / Scale	Minimum Price (US$/ MW-month)
Large CC Capacity > 150 MW	3,050
Large ST Capacity > 100 MW	4,350
Small ST Capacity ≤ 100 MW	5,700
Large GT Capacity > 50 MW	3,550

             Base Remuneration

             Applicable to generators with Availability Commitments:

Period	Base Price (US$/MW- month)
May 2017 – October 2017	6,000
November 2017 onwards	7,000

             Additional Remuneration

Additional remuneration is paid for the additional available power capacity aiming to encourage Availability Commitments for such periods with higher energy demand. CAMMESA will define a Monthly Thermal Generation Goal for the set of qualified generators on a bi-monthly basis and will call for additional power capacity availability offers with prices not exceeding the additional price.

Period	Additional Price (US$/MW-month)
May 2017 – October 2017	1,000
November 2017 onwards	2,000

              Hydroelectric Generators

In the case of hydroelectric power plants, a base remuneration and an additional remuneration for power capacity were established. 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 following is considered to calculate availability: (i) the operation as turbine at all hours within the period, and (ii) the availability as pump at off-peak hours every day and on non-business days.

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             Base Remuneration

             Determined by the actual power capacity plus that under programmed and/or agreed maintenance:

Classification	Base Price (US$/MW- month)
Medium HI Capacity > 120 ≤ 300 MW	3,000
Small HI Capacity > 50 ≤ 120 MW	4,500
Large Pumped HI Capacity > 120 ≤ 300 MW	2,000
Renewable HI Capacity ≤ 50 MW	8,000

Similarly, to the provisions of SE Resolution No. 22/2016, in the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor will be applied to the plant at the headwaters.

              Additional Remuneration

Applicable to power plants of any scale for their actual availability and based on the applicable period:

Type of Power Plant	Period	Additional Price (US$/MW-month)
Conventional	May 2017 – October 2017	500
	November 2017 onwards	1,000
Pumped	May 2017 – October 2017	-
	November 2017 onwards	500

As from November 2017, the allocation and collection of 50% of the additional remuneration will be conditional upon the generator taking out insurance, to CAMMESA’s satisfaction, to cover for major incidents on critical equipment, and the progressive updating of the plant's control systems pursuant to an investment plan to be submitted based on criteria to be defined by the SGE.

Other Technologies: Wind Power

The remuneration is comprised of a base price of US$7.5/MWh and an additional price of US$17.5/MWh, which is associated with the availability of the installed equipment with an operating permanence longer than 12 months as from the beginning of the Summer Seasonal Programming.

              Remuneration for Generated and Operated Energy

The remuneration for Generated Energy is valued at variable prices according to the type of fuel:

Technology / Scale	In US$/MWh
	Natural Gas	Hydrocarbons
Large CC Capacity > 150 MW	5.0	8.0
Large ST Capacity > 100 MW	5.0	8.0
Small ST Capacity ≤ 100 MW	5.0	8.0
Large GT Capacity > 50 MW	5.0	8.0
Internal Combustion Engines	7.0	10.0

The remuneration for Operated Energy applies to the integration of hourly power capacities for the period, and is valued at US$2.0/MWh for any type of fuel. In the case of hydroelectric plants, prices for Generated and Operated Energy are as follows:

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Technology / Scale	In US$/MWh
	Generated Energy	Operated Energy
Medium HI Capacity > 120 ≤ 300 MW	3.5	1.4
Small HI Capacity > 50 ≤ 120 MW	3.5	1.4
Large Pumped HI Capacity > 120 ≤ 300 MW	3.5	1.4
Renewable HI Capacity ≤ 50 MW	3.5	1.4

              Additional Remuneration for Low-Use Thermal Generators

The resolution provides for an additional remuneration for low-use thermal generators having frequent startups based on the monthly generated energy for a price of US$2.6/MWh multiplied by the usage/startup factor.

The usage factor is based on the Rated Power Use Factor recorded during the last rolling year, which will have a 0.5 value for thermal units with a usage factor lower than 30% and a 1.0 value for units with a usage factor lower than 15%. In all other cases, the factor will equal 0.0.

              Additional Remuneration for Thermal Generators having Frequent Startups

The startup factor is established based on startups recorded during the last rolling year for issues associated with the economic dispatch made by CAMMESA. It will have a 0.0 value for units with up to 74 startups, a 0.1 value for units recording between 75 and 149 startups, and a 0.2 value for units recording more than 150 startups. In all other cases, the factor will equal 0.

              Repayment of Overhaul Financing

The resolution abrogates the Maintenance Remuneration and provides that, with respect to the repayment of outstanding loans applicable to thermal and hydroelectric generators, credits already accrued and/or committed to the cancellation of such maintenance works will be applied first. The balance will be repaid by discounting US$1/MWh for the energy generated until the total cancellation of the financing.

SRRYME Resolution No. 1/19: March 2019 - January 2020

The SRRYME Res. No. 1/19 was published on March 1, 2019, modifying certain aspects of the remuneration scheme previously defined by SEE Res. No. 19/17.

Thermal Power Generators

The remuneration under SRRYME Resolution No. 1/19 is still comprised of a payment for power capacity and a payment for energy (generated and operated energy).

For DIGO generators, the following power capacity base prices apply:

Technology / Scale	Minimum Price (US$/ MW-month)
Large CC Capacity > 150 MW	3,050
Small CC Capacity > 150 MW	3,400
Large ST Capacity > 100 MW	4,350
Small ST Capacity > 100 MW, Internal combustion engineer	5,200
Large GT Capacity > 50 MW	3,550
Small GT Capacity ≤ 50 MW	4,600

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Furthermore, SRRYME Resolution No. 1/19 provides for a DIGO offer scheme for quarterly periods: (a) summer (December, January and February); (b) winter (June, July and August), and (c) ‘Other’, which comprises two quarters (March, April and May; and September, October and November).

For agents declaring DIGO, the guaranteed power capacity price will apply, which will equal US$7,000/MW-month in the summer and winter quarters, and US$5,500/MW-month in the “Other” quarters.

Additionally, the power capacity remuneration ―whether or not the agent declares DIGO― will be affected by a utilization factor equivalent to the average dispatch factor for the generating unit during the rolling year prior to the calculation month, applying a coefficient range between 70% and 100% of the power capacity price; in this sense, if the usage factor is: (i) higher than 70%, 100% of the power capacity remuneration is paid; (ii) lower than 30%, 70% of the power capacity remuneration is paid; and (iii) equal to or higher than 30% and lower than 70%, the power capacity remuneration is linearly associated with between 70% and 100% of the power capacity remuneration.

Generated Energy remuneration values have decreased by US$1/MWh for all technologies except for Internal Combustion Engines, in which the decrease amounted to US$3/MWh. The Operated Energy remuneration value was reduced from US$2/MWh to US$1.4/MWh.

In case the generator has opted to use its own fuels for generation (pursuant to the option set forth by SGE Resolution No. 70/18) and does not have such availability upon dispatch, the power capacity availability calculation will be reduced to 50% of the actual availability. Similarly, the generator will lose its priority dispatch, and in case the OED assigns it fuel for generation, the Generated Energy will be remunerated at just 50% of the approved non-fuel variable costs.

The additional remuneration scheme to encourage DIGO offered during the periods with a higher demand of the system and the additional remuneration of efficiency-based generation variable costs were eliminated. Furthermore, the additional remuneration for low-use thermal generators was also eliminated.

Hydrological Generators

SRRYME Resolution No. 1/19 maintained the power capacity base prices established by SEE Resolution No. 19/17, as well as remuneration values for Generated Energy and Operated Energy. However, with respect to the power capacity payment, as from March 1, 2019, the hours during which a hydroelectric generator is not available due to programmed and/or agreed maintenance will no longer be computed for the calculation of the power capacity remuneration.

Similarly to SEE Resolution No. 19/17, in the event that a hydraulic generator operates and maintains facilities that control the course of the river with no hydraulic generation facility directly associated to it, then the capacity remuneration for the main hydraulic generator shall be affected by a factor equal to 1.2.

The energy remuneration for hydraulic generation is equal to US$3.5/MWh for the generated energy and US$1.4/MWh for the operated energy.

Other Items

With respect to generation from unconventional sources (wind and photovoltaic solar energy, biomass, biogas from urban solid waste), a single remuneration value for Generated Energy is established at US$28/MWh, irrespective of the source. Energy produced by generators from unconventional sources prior to their commissioning by the OED will be remunerated at 50% of the above-mentioned remuneration.

With respect to refunds to generators under the loan agreements for the execution of overhauls in their units, the Resolution established, firstly, the application of all receivables accrued in favor of generators for settlement, and secondly, a discount scheme in the generator’s revenues equivalent to US$1/MWh for each generated MW, or US$700/MW-month for the unit’s actual availability, whichever is higher.

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SE Res. No. 31/20:  Current Remuneration Scheme as from February 2020

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 from 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 as from 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 > 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	-
Internal Combustion Engines Capacity ≤ 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:

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.

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With respect to the additional remuneration in the hours with a high thermal demand (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:

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:

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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.

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:

· 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.”

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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. Furthermore, CTEB has an ongoing expansion project to add 280 MW.

WEM Supply Agreements under SEE Res. No. 21/16

As a result of the state of emergency in the national electricity sector declared by PEN Executive Order 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 Combined Cycle 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 combined cycle over existing equipment. The projects should have low specific consumption (lower than 1,680 kcal/kWh operating on natural gas and 1,820 kcal/kWh operating with alternative liquid fuels), and the new capacity should not increase electricity transmission needs beyond the existing capacity; otherwise, the cost of the necessary extensions would be borne by the bidder.

Awarded projects were remunerated under a PPA for a term of 15 years. The remuneration is made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if offered), less penalties and fuel surpluses. Power capacity surpluses would be remunerated as legacy capacity.

Within this framework, in September 2017, the SEE issued 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 combined cycle for a 383 MW capacity. Commercial operations at open cycle started in June, 2019, and its commissioning at closed cycle is expected for the second quarter of 2020, in line with the originally committed term.

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 as from the originally committed commissioning date. However, Pampa ratified Genelba Plus CC's commercial commissioning date. For further information on the project to the closing of the combined cycle at Genelba conducted under this resolution, see “Item 4. Information on the Company – Generation – Progress in the Cycle Closing Project at CTGEBA”.

Agreement to Increase Thermal Generation Availability

In 2014, the Federal Government submitted a proposal to generators for the execution of a new agreement to increase the thermal generation availability through the application of LVFVDs and the generators’ own resources. CTLL, CTG, CPB, HINISA and HIDISA entered into this agreement, which set out the conditions for the incorporation into CTLL of a high-efficiency GT (105 MW), which was commissioned for service in July 2016, and two engines (15 MW), which are expected to be put into service in 2020.

As of August 2019, Pampa’s involved generators had several claims with CAMMESA regarding the breach of the LVFVD’s payments for projects executed under previous agreements. In August, 2019, the Company, its subsidiaries (HIDISA, HINISA and CPB) and CAMMESA executed an agreement to cancel the outstanding LVFVD plus interests (calculated up to July 31, 2019) considering a 18% discount (“Acuerdo de Regularización y Cancelación de Acreencias con el Mercado Eléctrico Mayorista (MEM)”). The Company and its subsidiaries collected a total amount of AR$2,122,714,757. The Company and its subsidiaries withdrew all claims related to the outstanding LVFVD.

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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 Fondo para el Desarrollo de Energía Renovables (“FODER”), which is destined, among other objectives, to the granting of loans, capital contributions, etc. for the financing of these projects.

RenovAr Program

ME&M Resolution No. 71/16 issued in May 2016 launched the RenovAr (Round 1) Program’s open call for tenders. In October 2016 and pursuant to Resolution No. 213/16, the ME&M awarded 29 projects for a total 1,142 MW (97% of which were wind and solar energy projects), 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.

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.

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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”).

Renewable Energy Distributed Generation

On December 27, 2017, Law 27,424 was passed. Such law declares the distributed generation of renewable energy of “national interest” and set forth the basic conditions for such generation by the energy distributor’s final users (excluding large users and self-generators) both for their own use and the sale of any exceeding generation to the network.

Furthermore, all national public building projects should contemplate the use of a distributed generation system leveraging the use of renewable sources after conducting, if applicable, an environmental impact study. Besides, the enforcement authority will carry out a study of existing national public buildings and will suggest incorporating power efficiency systems, including renewable distributed generation capacity.

Decree No. 986/18 issued in November 2018 and SGE Resolution No. 314/18 dated December 2018 regulated the Regime Encouraging Grid-Integrated Renewable Energy Distributed Generation seeking to reach a 1,000 MW capacity within a term of 12 years.

Regarding the billing scheme, it is expected that a balance will be reached between each user-generator’s consumption and injection. In this line, distributors should file a monthly declaration to CAMMESA indicating the values corresponding to the electric power generated by users-generators.

On September, 2019, SERYRR Dispositon 113/19 increased the benefit for those user-generators to 30 Ps./W up to a maximum of Ps. 2,000,000.

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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.

Additionally, on April 8, 2020, the Secretariat of Energy 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. For more information, please see (“—Developments relating to the novel coronavirus may have a material adverse impact on our business operations, financial condition or results of operations”).

Restructuring of Argentine Government’s Energy Sector Assets

On October 31, 2017, the Macri administration issued Decree No. 882/17 ordering the restructuring of the Argentine Government’s energy sector assets aimed at the reduction of government participation.

Pursuant to the Decree:

1.the ME&M is to take all necessary actions for the merger of IEASAS’ and Emprendimientos Energéticos Binacionales S.A.(“EBISA”) and change the corporate name of the merged entities to IEASA. IEASA will be responsible for selling Argentina’s generation capacity in binational energy projects;

2.IEASA will be responsible for the construction of hydroelectric projects on the Santa Cruz river (Barrancosa and Condor Cliff). In addition, IEASA will grant the future power generation concession. The ME&M must establish a public and competitive process for its future transfer to the private sector;

3.IEASA will be responsible for the construction of the following projects: (a) Río Turbio thermal plant; (b) Regional Centro II Pipeline; (c) Sistema Cordillerano y Patagónico Pipeline; (d) Cordillerano Pipeline; and (e) de la Costa Pipeline.

4.The ME&M must take all necessary actions to sell: (a) CT Ensenada de Barragán and Bgd. López (the purchaser must close the combined cycle); (b) Argentine Government’s rights in CT Manuel Belgrano II; and (c) IEASA equity participation in CITELEC;

5.The ME&M must, through sale, assignment or other method; transfer:

a.The Argentine Government’s equity participation in Central Dique S.A., Central Puerto S.A., Centrales Térmicas Patagónicas S.A., TRANSPA and Dioxitek;

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b.The Argentine Government’s right in TJSM, TMB, Termoeléctrica Vuelta de Obligado, and Termoeléctrica Guillermo Brown.

The decree authorized the ME&M to collect part of the price for the abovementioned assets in LVFVD issued under SE Resolution No. 406/03 as amended. The ME&M is entitled to define the specific conditions for such collection.

In order to value the assets, the decree establishes the intervention of the relevant public entities (e.g. Tribunal de Tasaciones). However, it also authorizes to hire private specialized firms.

The above-indicated sales should follow a public and competitive processes, preserving the rights stipulated in the applicable contracts and corporate documents (i.e., preemptive rights). Competent public bodies (for example, the Appraisal Court) will take part in the valuations, although private entities may be hired to such effect. Furthermore, the ME&M and IEASA were authorized to receive as payment the LVFVDs issued pursuant to SE Resolution No. 406/03 and other provisions passed by the SE for up to the maximum amounts and under the conditions to be established by the ME&M.

To such effect, IEASA launched the public tender for the sale of the CT Ensenada de Barragán and the CT Brigadier López CTs. On May 29, 2019, Pampa and YPF were jointly awarded the public tender for the sale and transfer by IEASA of CT Ensenada de Barragán. On June 26, 2019, the sale and transfer to CTB a company jointly controlled by YPF and Pampa, was completed. CTEB is located in the petrochemical complex of the City of Ensenada, Province of Buenos Aires, and consists of two open-cycle gas turbines with a total installed capacity of 567 MW.

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 considers new drilling techniques available in the industry, and also introduces changes mainly related to terms and extensions of exploration permits and exploitation concessions, levies and royalty rates, the incorporation of concepts for the continental shelf and off-shore exploration and exploitation of unconventional hydrocarbons, and a promotion regime pursuant to Executive Order No. 929/13, among other factors. The main changes introduced by Law No. 27,007 are detailed below:

Unconventional Hydrocarbons Exploitation

The Law conferred legal status to the concept of “Unconventional Hydrocarbon Exploitation Concession” created by Executive Order 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 that they duly demonstrate the geological continuity of these blocks. Such request should be based on the development of a pilot plan.

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Terms for Exploitation Concessions and Permits

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

i.	Conventional exploitation: 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 exploitation permits is reduced from fourteen to eleven years;
ii.	Unconventional exploitation: the basic term is divided into two periods of four years each, plus an optional extension of up to five years; as such, a single concession would last a maximum of 13 years; and
iii.	Exploitation in the continental shelf and the territorial sea: 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 basic term’s first period, the exploitation permit holder will decide whether to continue exploiting the block or to return it, in whole, to the Government. The whole originally-granted block may be kept provided the obligations arising from the permit have been properly met. Upon the expiration of the basic term, the holder of the exploitation permit will relinquish the whole block, unless it exercises its right to use the extension period, in which case the relinquishment will be limited to 50% of the remaining block.

Exploitation concessions will be granted for the following terms, which will be computed as from 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.

Furthermore, the holder of an exploitation concession may, with a minimum one-year notice before the expiration of the concession, request the granting of indefinite extensions, for a 10-year term each, provided that it has properly met its obligations as exploitation concessionaire, is actually producing hydrocarbons in the blocks in question, and files an investment plan consistent with the development of the concession.

The ban on simultaneously holding more than five exploitation permits and/or exploitation concessions (whether directly or indirectly) has been lifted.

Concessions Extension

Law No. 27,007 grants the provinces having already started the concession extension process a 90-day term to terminate them based on the conditions established for each of them. All subsequent extensions will be governed by the Argentine Hydrocarbons Law.

Awarding of Areas

Law No. 27,007 proposes the 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.

·Levies and Royalties

The amended Argentine Hydrocarbons Law updated the values related to the exploration and exploitation levy established by Executive Order No. 1,454/07; such values may, in turn, be generally updated by the PEN based on variations in the domestic market’s crude oil price. The updated values for each levy and royalty are detailed below.

-Exploration Levy

The holder of the exploitation permit will pay the levy on an annual basis, in advance, for each square kilometer or its fraction based on the following scale:

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•      First period: Ps.250 per km2 or fraction;

•      Second period: Ps-1,000 per km2 or fraction; and

•      Extension: during the first year of the extension, Ps.17,500/km2 or fraction, with a 25% annual cumulative increase.

In this case, offsetting mechanisms remain in place: the amount that the exploitation permit holder should pay for the second period of the basic term and for the extension period may be readjusted by offsetting it with exploitation investments actually made within the block, until reaching a minimum levy equivalent to 10% of the applicable levy according to the period per km2, which will be payable in all cases.

-Exploitation Levy

The holder of the exploitation permit will pay a levy which will consist of an annual advance payment of Ps.4,500 per km2 or its fraction.

-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.

Cash payment of the royalties will be made based on the value of crude oil at the wellhead less freight costs up to the base location for the definition of its commercial value. Payment in kind of this royalty will only apply when the concessionaire is assured a reasonably permanent reception. The possibility to reduce the royalty up to 5% taking into consideration productivity, conditions and wells location remains in place.

In case of extension, additional royalties for up to 3% of the royalties applicable upon the first extension and up to a total maximum of 18% of royalties for the following extensions will be payable.

To conduct hydrocarbon conventional exploitation complementary activities, as from the expiration of the granted concession and within the unconventional hydrocarbons exploitation concession, the enforcement authority may set additional royalties of up to 3% above the current royalties, capped at 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 often years after the conclusion of the pilot project in favor of companies requesting a hydrocarbon unconventional exploitation concession within a term of 36 months as from Law No. 27,007’s effective date.

Finally, with the Hydrocarbon Investments Committee’s prior approval, royalties may be reduced to 50% for tertiary production projects, extra-heavy oil and offshore products in view of their productivity, location and other unfavorable economic and technical characteristics.

-Extension Bond

For exploitation concession extensions, Law No. 27,007 empowers the enforcement authority to establish the payment of an extension bond, the maximum amount of which will result 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, the maximum amount of which will result 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 (which had historically been granted for 35 years) will be granted for the same term granted for the initial 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, whereas those originating in an unconventional exploitation concession will have a basic 35-year term, each in addition to any granted extension term. After the expiration of these terms, 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 whatsoever.

-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 accordance 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 Argentine Hydrocarbons Law restricts the Federal Government and the provinces from reserving new blocks in the future in favor of public or mixed-capitalcompanies or entities, irrespective of their legal form. However, contracts entered into by provincial 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 Executive Order No. 929/13, which created: (i) the Investment Promotion Regime for the Exploitation of Hydrocarbons —both conventional and unconventional— whose purpose is to encourage investments destined to the exploitation of hydrocarbons; and (ii) a new type of concession for the exploitation of unconventional hydrocarbons.

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Law No. 27,007 extends 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 hydrocarbons exploitation concessions, and/or third parties associated with such holders and registered with the National Registry of Hydrocarbon Investments submitting this kind of projects will enjoy the following rights as from the third year of their respective projects’ execution:

i.	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 in offshore projects, respectively, with a 0% export duty, if applicable; and
ii.	The free availability of 100% of the foreign currency derived from the export of these hydrocarbons, provided the applicable projects have resulted in 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 Argentine Hydrocarbons Law, those covered by the Promotion Regime will have, as from 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 export duties) from the exportable liquid and gaseous hydrocarbon percentage produced under such projects.

Pursuant to these investment projects, Law No. 27,007 provides for two contributions payable to the producing provinces where the investment project is developed:

i.	The first one, payable by the project holder, for an amount equivalent to 2.5% of the investment amount undertaken to be committed to corporate social responsibility projects; and
ii.	The second contribution, payable by the Federal Government, which amount will be determined by the Hydrocarbon Investments Committee based on the size and scope of the investment project, and which will be destined to infrastructure projects.

Regulations Specifically Applicable to the Gas Market

Encouragement Programs for the Increase in Domestic Natural Gas Production

-Gas Plan

In February 2013, Res. No. 1/13 was published establishing the Gas Plan for a five-year term to offset projects contributing to the domestic gas self-supply. The Federal Government had undertaken to pay a monthly compensation resulting from:

i.	The difference between the Surplus Injection price (US$7.5/MBTU) and the price actually collected from the sale of the Surplus Injection; plus
ii.	The difference between the Base Price and the price actually collected from the sale of the Adjusted Base Injection.

Petrolera Pampa S.A., later merged into Pampa, joined Gas Plan in August 2013, with retroactive effects as of March 2013 and until December 2017. Regarding the compensation accrued in fiscal year 2017, the Gas Plan Natural Bond was received in April 2019.

In November 2013, the Hydrocarbon Investments Committee issued Res. No. 60/13 including more beneficiary companies under Gas Plan. Petrobras Argentina, later merged into Pampa, joined the plan on January 30, 2015, effective until June 30, 2018. Regarding the compensations accrued in fiscal year 2017, the Gas Plan Natural Bond was received in July 2019, whereas compensations corresponding to the first semester of 2018 were collected in cash in April 2019.

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-Unconventional Gas Plan

On March 6, 2017, MEyM Res. No. 46/17 was published creating the Encouragement Program to further investments for the production of natural gas from unconventional reservoirs in the Neuquina Basin, effective from its publication to December 31, 2021. This program provided for a compensation mechanism for the unconventional gas volume —either tight or shale— produced in the Neuquina Basin, calculated on the basis of a minimum guaranteed price and the total weighted-average gas sales price by each company to the domestic market, including both conventional and unconventional gas. The minimum price was fixed at US$7.5/MBTU for the year 2018, and would be later decreased by US$0.5/MBTU per year until reaching US$6.0/MBTU for calendar year 2021.

Later, on November 2, 2017, MEyM Res. No. 419/17 was published amending the terms and conditions, and classifying projects into pilot and developing, the latter having an initial unconventional gas production equal to or higher than 500,000 m3 per day between July 2016 and June 2017. Undeveloped concessions may obtain a guaranteed minimum price for their production provided they reach an annual average production equal to or higher than 500,000 m3/day during a twelve-month period by December 31, 2019. Developing concessions may only apply for the benefit for the portion exceeding their initial production. The reference price for the incentive will be calculated using the domestic market’s weighted average reported by the MEyM’s Secretariat of Hydrocarbon Resources.

The MEyM Res. No. 447/17 was published on November 17, 2017, extending the application of the Unconventional Gas Plan to the Austral Basin. Additionally, on January 20, 2018, MEyM Res. No. 12/18 was issued, which introduced the applicable amendments to the Unconventional Gas Plan so as to apply the incentives provided therein to adjacent concessions operated on a unified basis and meeting all other applicable conditions.

Pampa repeatedly requested before the SGE the inclusion under this program of its projects in the Río Neuquén, El Mangrullo and Sierra Chata blocks, which had been previously approved by the Provincial enforcement authority.

However, on January 30, 2019, the SGE informed gas producers covered by the Unconventional Gas Plan, including the Company, that no new projects would be approved under it.

Natural Gas for the Residential and CNG Segment

-Priority Demand and CEE

In June 2017 ENARGAS Res. No. 4502/17 was issued, which approved the procedure for dispatch administration in the CEE. In case the CEE did not reach an agreement, ENARGAS defines the required supply taking into consideration 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.

 

-Natural Gas Price within the PIST

In early January, 2018, Law No. 27,200 terminated the public emergency declared in 2002 and, 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. As a result, natural gas distributors executed an agreement with the country’s main natural gas producers, including Pampa, effective for a year as from January 1, 2018. Prices were categorized based on the source basin, the user category, and whether the tariff was full or differential, with periodic increases, and ranged from US$1/MBTU to US$6.5/MBTU.

However, on account of the significant Peso devaluation of the and the impossibility by distributors to pass this new exchange rate on to final users’ tariff schemes, in early October 2018, this agreement was rendered ineffective and pricing agreements with distributors started to be governed by the price range recognized by ENARGAS in tariff schemes.

Nevertheless, with respect to the exchange rate’s discrepancies between the prices of gas purchased by distributors and those recognized in final tariffs, on November 15, 2018, PEN Executive Order No. 1053/18 established, on an exceptional basis, that the Federal Government would bear such difference for the April 2018 – March 2019 period, in 30 monthly and consecutive installments payable as from October 2019.

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In mid-February 2019, an auction 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, for a term of 12 months with seasonality terms, and effective as from April 2019. For the Noroeste Basin, 9.4 and 3.8 million m3 per day were assigned for the winter (April – September 2019) and summer (October 2019 – April 2020), respectively, at an average tender price of US$4.35/MBTU.

For the rest of basins, 36.1 and 14.4 million m3/day were assigned for the winter and the summer, respectively, at an average tender price of US$4.62/MBTU. Pampa submitted an offer and was awarded. Producers would bill to distribution companies in Pesos pursuant to ENARGAS Res. No. 72/19, considering BNA’s average currency exchange rate for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the exchange rates stipulated in the agreements. However, the exchange rate updates which should have been implemented on October 1, 2019, applicable to the October 2019 - April 2020 summer seasonal period, was deferred in several occasions. With the entry into effect of the Social Solidarity and Productive Reactivation Law, the exchange rate freeze was subject to a maximum term of up to 180 days. Recently, ENARGAS Res. No. 27/20 repealed the above mentioned ENARGAS Res. No. 72/19. The Company is currently studying its next steps on this matter.

ENARGAS Res. No. 193-199, 201-202 and 205-207 /19 established gas tariff schemes effective as from April 2019, considering an average PIST price of gas as raw material for the following six months ranging between US$2.14/MBTU and US$4.69/MBTU, including the differential tariff. Later, 27% and 12% discounts in the price of natural gas within the PIST were set for the months of April and May 2019, respectively, by means of subsidies and, with the purpose of smoothing monetary expenses for seasonal consumption, a 22% deferral on bills issued during the July – October 2019 period was approved, to be recovered in five installments as from December 2019.

The tariff scheme update corresponding to October 2019 was deferred until February 1, 2020 pursuant to SGE Res. No. 521, 751 and 791 /19 and, with the entry into effect of the Social Solidarity and Productive Reactivation Law, effective as from December 23, 2019, it was determined that tariffs under federal jurisdiction would remain unchanged and a process for the renegotiation or an extraordinary review of the RTI would be initiated for a maximum term of 180 days.

On March 31, 2020 the natural gas supply contracts with distribution companies signed in mid-February 2019 expired, but some distribution companies have informed that pursuant to the Ministry of Energy’s instructions producers were obliged to extend those gas supply contracts until June 2020.

As of the date of this annual report, the Company has not been notified of any administrative act in connection with the paragraph above. However, Pampa has decided to enter in daily SPOT contracts with some natural gas distribution companies.

Furthermore, as of April 2020, we received several notes from some gas distribution companies notifying the partial payment of our gas bills based on the "social, preventive and compulsory isolation" set forth by Decree No. 297/20 and the effects of Decree No. 311/ 20 that prohibited the possibility of stopping gas supply to certain users due to lack of payment.

·Natural Gas for Power Generation

In November 2018, thermal power plants were authorized to procure their own fuel. The Company opted to exercise self-supply for the dispatch of its thermal units, with the allocation of a significant portion of its gas production. In January 2019, the maximum gas prices for gas within the PIST set by SGE Note No. 66680075/18 continued to be used as a reference: for the June-August 2019 period, it was fixed at US$4.95/MBTU for the Neuquina Basin, US$5.15/MBTU for the Noroeste Basin, US$5.10/MBTU for the Golfo San Jorge Basin, US$4.90/MBTU for the Santa Cruz Sur Basin, and US$4.85/MBTU for the Tierra del Fuego Basin; whereas for the rest of the year they were fixed at US$3.70/MBTU for the Neuquina Basin, US$3.60/MBTU for the Noroeste Basin, US$3.55/MBTU for the Golfo San Jorge Basin, US$3.35/MBTU for the Santa Cruz Sur Basin and US$3.30/MBTU for the Tierra del Fuego Basin.

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On the other hand, seeking that the WEM should bear the costs of imported gas and, consequently, reflect them in the variable costs the electric dispatch is based on, SGE Res. No. 25/18 was issued on October 4, 2018, determining that, in case the supplier is IEASA, CAMMESA should adopt the acquisition and commercialization cost, effective as from October 1, 2018.

On December 27, 2018, an auction was launched for the gas for power plants effective for 2019, in which Pampa took part. At CAMMESA’s auction, indicative prices were received for a total 222 million m3 per day on an interruptible basis, at seasonal PIST prices with a maximum price of US$5.2/MBTU and a minimum price of US$3.2/MBTU for the June-August 2019 period, and with a maximum price of US$3.7/MBTU and a minimum price of US$2.2/MBTU for the rest of the year. This auction considered the maximum PIST seasonal reference prices established by SGE Note No. 66680075/18 described in the previous paragraph.

However, SGE Note No. 07973690/19 instructed CAMMESA to recognize in the CVPs declared as from February 18, 2019 the maximum price for gas equivalent to the weighted average per basin which would have resulted if all the fuel had been acquired under contracts entered into under CAMMESA’s auction for 2019. Therefore, gas reference prices within the PIST significantly decreased, and were set in ranges of approximately US$3.70/MBTU during the months of June through August 2019, and US$2.70/MBTU for the rest of the year for the Neuquina Basin.

For 2020 consumptions, as of the date of this annual report, CAMMESA has launched successive auctions for monthly coverages. On December 27, 2019, CAMMESA’s auction for the January 2020 period took place, and indicative prices for a total 260 million m3 per day on an interruptible basis were received, with an average PIST price of US$1.73/MBTU in the Neuquina Basin. Nevertheless, on January 29, 2020, an auction for gas was launched for the month of February 2020, but on a partially firm basis, where the producer commits to deliver a minimum volume equal to 30% (DoP). Offers were received for a total 84 million m3 per day at an average PIST price of US$2.59/MBTU for the Neuquina Basin. CAMMESA used the same methodology for the March 2020 auction, receiving offers for a total 78 million m3 per day at an average PIST price of US$2.42/MBTU for the Neuquina Basin.

Furthermore, as from December 30, 2019, the supply of fuel for power plants was again centralized in CAMMESA (except for generators under Energía Plus).

·Natural Gas Export

MinEn Res. No. 104/18 and SGE Res. No. 9/18, later superseded by SGE Res. No. 417/19 in July 2019, established the procedure for the authorization of natural gas exports, the security of supply to the Argentine domestic market being a condition in all cases. In the case of projects covered by the Unconventional Gas Plan, the exported volumes do not qualify for such incentives. In this regard, in December 2018 and January 2019, Pampa was authorized pursuant to SGE Res. No. 252/18 and 12/19 to export natural gas on an interruptible basis to Chile and Uruguay, respectively.

Furthermore, SHC Provision No. 168/19 issued in August 2019 approved the export of gas from September 2019 to May 2020, for a maximum aggregate volume of 10 million m3/day, 65% from the Argentine Central-Western area, 25% from the South, and 10% from the Northeast area. Pampa obtained a permit to export gas on a firm basis from its production in the Neuquina Basin to Refinerías ENAP in Chile.

In case higher costs are incurred by the Federal Government as a result of the use of alternative fuels for electric power generation by the WEM (imported LNG, coal, FO or GO), exporting companies will pay a compensation to CAMMESA. SGE Res. No. 506/19 issued on August 29, 2019 set a minimum value of US$0.1/MBTU and a maximum value of US$0.2/MBTU for the exported volume, which may be offset with other receivables from the sale of gas in the domestic market each exporter holds against CAMMESA. This compensation would be included in the cost of electricity within the WEM.

Finally, pursuant to PEN Executive Orders No. 793 and 865/18, a gas export duty of Ps.4 per each exported US$ is in effect as from September 2018, with a maximum 12% rate; this rate was later amended by the Social Solidarity and Productive Reactivation Law, which provided, effective as from December 23, 2019, that it may not exceed 8% of the taxable value or the FOB price (pending regulation).

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Regulations Specifically Applicable to the Crude Oil Market

·Crude Oil Commercialization in the Domestic Market

In January 2017, the Federal Government executed the Agreement for the Transition to International Prices of the Argentine Hydrocarbon Industry with producers and refineries of crude oil with the purpose of generating a gradual convergence of the price of the crude oil barrel traded in Argentina towards the international price. This agreement was suspended in October 2017 as the Brent crude oil price exceeded US$55/bbl for ten consecutive days and, since then, the domestic price for the barrel of crude oil to be used as raw material for refining and gas pump prices have been determined based on the domestic supply and demand.

However, following the exchange rate volatility experienced in August 2019, DNU No. 566/19 was passed on August 16, 2019, which set the barrel price agreed between producers and refiners in the domestic market as of August 9, 2019, and valid until November 13, 2019, considering a reference Brent price of US$59/bbl and an exchange rate of Ps.45.19/US$.

·Liquid Hydrocarbons Export Duty

As from September 2018, PEN Executive Orders No. 793 and 865/18 provide for an oil export duty of Ps.4 per exported US$, with a maximum 12% rate. However, the Social Solidarity and Productive Reactivation Law established that this rate (pending implementation) should be lower than or equal to 8% of the taxable value.

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 PEN Executive Order No. 470/15 and encompassed under the Household Gas Bottles’ Program (SRH Res. No. 56/17, as amended) provided for the supply of a defined quota of LPG by producers to fractionation companies, under a maximum reference price, to benefit low-income residential users. The sales price for butane and propane under the Household Gas Bottles’ Program is determined by the SRH, which set a price of Ps.5,416/ton for butane and Ps.5,502/ton for propane as from April 2018 (Provision No. 5/18). Later, prices were updated to Ps.9,154/ton for butane and Ps.9,042/ton for propane effective as from February 1, 2019 (SGE Resolution No. 15/19), to Ps.9,327/ton of butane and Ps.9,213/ton for propane as from May 10, 2019 (SHC Provisions No. 34/19), and to Ps.9,895/ton for butane and Ps.9,656/ton for propane as from July 1, 2019 (SHC Provisions No. 104/19). Consequently, the participation in this program forces TGS and Refinor 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, which provides for a set of resolutions regulating the price of butane, TGS executed the 16th extension to the agreement on May 30, 2018, which set a new methodology for the determination of the price and volumes to be sold for the April 1, 2018 – December 31, 2019 period under this program. As of the date of release of this Annual Report, this program has not been postponed. However, on January 14, 2020, TGS was instructed by the SE to proceed with the propane deliveries pursuant to the conditions of the 16th extension to the Propane for Grids Agreement, indicating that this entity is performing all necessary acts to extend the life of the Agreement until at least June 30, 2020.

Both the Household Gas Bottles’ Program and the Propane for Grids Agreement provide for the payment of a compensation to participants, payable by the Federal Government, 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 PEN Executive Order 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.

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On October 29, 2019, the judge 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

Pursuant to PEN Executive Orders No. 793 and 865/18 and effective as from September 2018, a duty applies to exports of natural gas, propane, butane and natural gasoline, among other products, equivalent to Ps.4 per each exported US$, with a maximum 12% tax rate. However, as from December 23, 2019, with the implementation of the Social Solidarity and Productive Reactivation Law, the rate may not exceed 8% of the taxable value or the FOB price (pending regulation).

·Regulations Specifically Applicable to Crude Oil Transportation

In the month of June 2016, the performance of the RTI was requested to the MEyM as the tariffs were insufficient to develop a maintenance and investment plan that may guarantee the integrity of facilities, minimize wastages, prevent and detect fraud, and improve energy efficiency towards the evolution of the transportation service in terms of reliability and efficiency. Consequently, on March 10, 2017, a new dollar-denominated tariff scheme was published providing for an average 34% increase, effective for a term of five years as from March 2017 (MEyM Res. No. 49/17).

In November 2018 Pampa closed the sale of 21% of Oldelval’s capital stock to ExxonMobil, keeping a 2.1% equity interest in OldelVal. 

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 “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, as well as “Item 3. Key Information—Selected Financial Data”.

Sources of Revenues

              Generation

Our electricity generation operations derive revenues from the sale of electricity in the spot market, through supply agreements with CAMMESA and through sale contracts with large users within the MAT.

              Distribution of Energy

Our electricity distribution operations generate revenues mainly from electricity sales to users in our distribution service area. Electricity sales reflect the distribution tariffs Edenor charges its customers (on the basis of applicable tariffs).

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Revenue from electricity provided by Edenor to low-income areas and shantytowns is recognized to the extent that the framework agreement has been renewed for the period in which the service was rendered.

             Oil & Gas

Our oil and gas operations derive revenues from the sale of natural gas to generators and industrial clients. Regarding crude oil, we sell our production mainly in the domestic market.  

              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 the domestic and foreign markets from natural gas, virgin naphtha, propane and other supplies. These revenues are recognized when the possession of the product is transferred.

              Holding and others segment

Our holding and others segment generate revenues from contracts with customers in relation to advisory 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, international petrochemical product’s prices and in regulated electricity distribution tariffs, fluctuations in demand for oil related products, natural gas and electricity in Argentina and costs of sales and operating expenses.

We changed our functional currency from the Peso to U.S. Dollar, therefore, as from January 1, 2019, we record our operations in U.S. Dollars. The comparative information has been stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29, since the Peso was our functional currency up to that date.

During 2018, we divested our main assets related to refining and distribution segment and certain oil and gas assets. Therefore, the results of the affected operations have been disclosed under “Discontinued Operations” in the consolidated statement of comprehensive income and the consolidated statement of cash flows.  

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.

In December 2001, Argentina experienced an unprecedented crisis that virtually paralyzed the country’s economy through most of 2002 and led to radical changes in the Argentine Government’s policies. The crisis and the Argentine Government’s policies during this period severely affected the energy sector, as described below. Although over the following years the Argentine economy recovered significantly from the crisis, and the business and political environment was largely stabilized, the Argentine Government has only recently begun to address the difficulties experienced by the Argentine electricity sector as a result of the crisis and its aftermath.

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

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	Year ended December 31,
	2019	2018	2017
Real GDP (% change)	-2.2%	-2.5%	2.7%
Nominal GDP (in millions of Pesos)	21,650,351	14,605,790	10,644,779
Real Consumption (% change)	-6.4%	-2.4%	4.0%
Real Investment (% change)	-15.9%	-5.8%	12.2%
Industrial Production (% change)	-6.4%	-5.0%	2.5%
Consumer Price Index	53.8%	47.6%	24.8%
Nominal Exchange Rate (in Ps. /US$ at year end)	59.90	37.81	18.77
Exports (in million of US$)	65,115	61,782	58,621
Imports (in million of US$)	49,125	65,483	66,938
Trade Balance (in million of US$)	15,990	-3,701	-8,293
Current Account (% of GDP)	-0.8%	-5.4%	-4.9%
Reserves (in million of US$)	44.8	65.8	55.1
Tax Collection (in million of Pesos)	5,473,537,926	3,713,409	2,842,217
Primary Surplus (in million of Pesos)	-95.122	-338,987	-404,142
Public Debt (% of GDP at December 31) *	89.4%	86.2%	56.6%
Public Debt Service (% of GDP)	3.3%	2.7%	6.1
External Debt (% of GDP at December 31)	76.8%	72.1%	41.4%

               Sources: INDEC; Central Bank; Ministry of Treasury.

              *Includes hold-outs

Economic Recovery and Outlook

Argentina’s economy grew by 2.8% during 2017, driven by an increase in private consumption, public spending and investment which counteracted the 2.2% contraction in 2016. Such recovery was attributed to both external and domestic factors. The external factors included, among others, an overall improvement of the Brazilian economy, which led to an increase in Argentina exports to Brazil. The domestic factors included, among others, the growth in average wages, an increase in welfare and public works spending by the Argentine Government and the increase in bank lending activity to the private sector, which stimulated consumption and private investment. However, the performance of the various sectors of the economy was varied. Sectors buoyed by the change in relative prices, by public works spending or by specific trade agreements, such as agriculture, construction and the automotive industry, respectively, recorded high growth rates during 2017. By contrast, those affected by the relaxation of import controls and the Peso’s appreciation, such as the textiles and electronics industries, continued their contraction.

Inflation, measured by its general level, declined from 39.7% in December 2016 to 24.8% in December 2017, having achieved the disinflation process simultaneously with the updating of some utility service tariffs.

On the monetary policy front, the Central Bank formally instituted an inflation targeting regime, and established a new policy interest rate (the 7-day interbank repo rate). With a view to bringing inflation within the target band (between 12% and 17% for 2017), the monetary authority maintained a policy of high interest rates, which led to increased absorption of Pesos through the placement of central bank bills (LEBAC) and repos; the policy interest rate followed an upward trend during the year, from 24.75% in January 2017 to 28.75% in December 2017.

The Central Bank maintained the free floating exchange rate and intervened in the foreign exchange market only at times of strong rises. In this context, the nominal Ps./US$ exchange rate increased by 17% during the year 2017. Although during the last days of 2017, the price of the US currency in the domestic exchange market was rising, the dollar closed December at levels around Ps./US$18.00 (monthly average).

In 2017, there was a real increase in public spending. As a result of stronger growth in revenues as compared to expenditures, the primary deficit decreased to 3.9% of GDP in 2017 (compared to 4.3% in 2016); after payment of interest on the debt, the fiscal outturn stood at 6.1% of GDP, above the 5.9% recorded in 2016. The fiscal deficit remained high, notwithstanding the policy to reduce subsidies for utility service, the extraordinary revenues from the special tax under the capital legalization (or repatriation) program, and the increase in tax receipts associated with greater economic activity.

The fiscal deficit and the current account deficit were financed by a marked increase in external borrowing in 2017, which also underpinned an increase in international reserves. The current account deficit widened in 2017, standing at 5.5% of GDP, as a result of higher imports of goods and services (reflecting the economic recovery and the reduction in import controls and tariff rates), as well as an increase in debt service payment obligations with respect to interest due on Argentina’s public external debt.

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After a slight recovery in 2017, the first quarter of 2018 showed a trend which was similar to that of the previous year due to a carry-over effect. However, a harvest lower than expected and a reduced supply of international creditors willing to finance the Argentine Government revealed certain weaknesses of Argentina’s economy.

In addition to the external debt assumed by the Argentine Government and the lack of “genuine” dollars to meet maturities, Argentina became exposed to rollover risk. As a result, the Argentine Government signed the SBA with the IMF to secure the foreign currency it was unable to obtain from agricultural exports or from external financing; however, the assistance was conditioned upon correcting certain fiscal, monetary and exchange imbalances of the Argentine economy.

In 2018, additional volatility occurred in the exchange market due to a lack of predictability generated by the SBA with the IMF. After a financial crisis during the first half of 2018, the wholesale peso exchange rate devalued 54% as of June 2018 compared to December 2017. In August 2018, economic volatility intensified as a result of the exchange rate increasing to approximately Ps.40 per US$1.00. During 2018, economic factors such as the increase in the exchange rate and the Argentine Government’s decision not to renew the LEBACs, which had strongly increased the monetary base, contributed to the increase of inflation.

In response to increased inflation, the Central Bank applied a restrictive monetary policy and increased reference interest rates which caused a reduction in economic activity. In September 2018, the Central Bank modified the monetary policy with a focus on monetary-aggregates targets and maintaining the monetary base constant until mid-2019. Such monetary policy measures combatted inflation directly and contributed to a decrease in economic activity in the construction, commerce and manufacturing sectors.

In 2018, due to the external crisis and its domestic impact, which resulted in a fiscal and exchange rate crisis, cumulative economic activity decreased approximately 2.6%, as compared to 2017. Public consumption decreased by approximately 3.0%, while exports, net of imports, decreased by approximately 7.5%, compared to 2017. The contraction in economic activity negatively impacted 13 of the 16 economic sectors, with decreases in manufacturing (14.2%), wholesale and retail sales and repairs (15.7%) and construction (12.7%). However, such economic activity decreases were partially offset by increases in the agriculture, livestock, hunting and forestry (4.7%), Education (1%) and Health and social services (0.4%) sectors.

In 2018, the Cost of Living Index published by the INDEC showed a variation of 47.6%. The greatest variations in the index were increases in the following sectors: transportation (66.8%), communications (55.3%), and basic goods and services (53.2%). The least affected sectors were alcoholic beverages and tobacco (28.3%), clothing and footwear (33.1%) and education (32.1%). Wages measured by the Permanent Workers’ Average Taxable Remuneration (Remuneración Imponible Promedio de los Trabajadores Estables or “RIPTE”), increased by 29% between December 2018 and December 2017.

According to the INDEC, the estimated current account deficit in December 2018 totaled US$3.8 billion (which represented 4.7% of the GDP). In 2018, FOB value estimated exports totaled US$61.6 billion, whereas the CIF value of estimated imports amounted to US$65.4 billion. In December 2018, exports of primary products increased approximately 36.9%, whereas exports of agricultural manufacturing and industrial manufacturing increased by approximately 11.8% and 9.9% respectively. Fuel and energy exports recorded an estimated decrease of 13.5%, amounting to US$4 billion. As for imports, capital goods decreased approximately 38% comprising fuel and lubricants 33.9%, parts and accessories for capital goods 22.9%, consumer goods 33.7%, passenger motor vehicles 62.8%. Imports of intermediate goods increased approximately 0.2%.

In 2018, the non-financial public sector’s tax accounts recorded a cumulative primary and total deficit of 2.5% and 5.3% of GDP, respectively. Tax revenues increased 30.7% as compared to 2017. Moreover, primary expenditures showed a year-on-year variation of 22.4%, as compared to that of 2017.

Central Bank’s US$ wholesale exchange rate (Resolution A3500) was Ps.37.81/US$ as of December 31, 2018, showing a cumulative 101.4% increase compared to the end of 2017 and a 69.6% average year-on-year variation. Central Bank’s international reserves stock amounted to US$65.8 billion at closing, which represents a US$10.7 billion increase compared to the previous year. Moreover, the monetary base reached Ps.1,409 billion, showing a 40.7% increase at the closing of 2018 compared to the previous year. Furthermore, Central Bank’s debt stock in issued bonds amounted to US$19.4 billion as of the closing of 2018, which represents a 69% year-on-year contraction.

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As of the third quarter of 2019, the economic activity recorded an accumulated 2.5% decrease compared to the same period of the previous year, mainly as a result of the 7.8%, 1.1% and 17.8% decreases in private and public consumption, and investment, respectively. The activity contraction affected 10 out of 16 identified sectors of the Argentine economy, the most affected being financial intermediation (-12.4%), wholesale and retail business and repairs (-9.4%) and manufacturing industry (-7.6%). These declines were partially offset by increases in agriculture, livestock, hunting and forestry (+26.3%), private households with domestic service (+5.8%) and mining and quarrying (+1.1%), among others. These declines were also partially offset by a 77.1% year-on-year increase in exports net of imports.

With regards to the evolution of prices, the National Cost of Living Index published by the INDEC showed a 53.8% variation in 2019. The most important variations were recorded in health (+72.1%), communications (+63.9%) and household equipment and maintenance (+63.7%). The sectors affected to a lower extent were housing, water, electricity and other fuels (+39.4%), education (+47.1%) and leisure and culture (+48.5%). Furthermore, salaries, as measured by the registry of the Stable Workers’ Average Taxable Remuneration (RIPTE) experienced a 44.4% year-on-year increase between December 2019 and the same month of the previous year.

Moreover, as of December 2019 Non-Financial Public Sector’s fiscal accounts accumulated a 0.5% and 4.0% 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 2019 with a 47.4% increase compared to 2018. Besides, in 2019 primary expenditures by the National Treasury showed a 37.2% year-on year variation.

With respect to the financial situation, the Central Bank’s U.S. Dollar currency wholesale exchange rate (Res. A3500) closed at Ps.59.90/US$ on December 31, 2019, showing a cumulative 58.4% increase compared to the end of 2018 and a 71.7% average year-on-year variation. The Central Bank’s international reserves amounted to US$44.8 billion at year-end, which represents a US$20.9 billion decrease compared to the previous year. Moreover, the monetary base reached Ps.1,895 billion, showing a 34.5% increase at the closing of 2019 compared to the previous year. Furthermore, the Central Bank’s debt stock in issued bonds totaled an equivalent amount expressed in dollars of US$17.8 billion as of the closing of 2019, which represents a 9% year-on-year contraction.

Finally, at the external level, as of the third quarter of 2019 the cumulative current account deficit amounted to US$6.5 billion according to INDEC’s data, which represents 1.4% of the GDP. However, in the first three quarters of 2019, the trade balance recorded a surplus of US$1.5 billion, whereas Free on Board value exports reached US$48.0 billion, and Cost, Insurance and Freight value imports amounted to US$38.5 billion. Primary exports increased by 26.3% during this period, as well as agricultural manufactures exports, which experienced a 2.6% increase, while industrial manufactures exports experienced a 7.1% contraction. Fuel and energy exports experienced a 5.9% increase, reaching US$3.2 billion. Imports showed a contraction compared to the same period of 2018 in the automotive (-56.5%), capital goods (-34.3%), fuels and lubricants (-33.2%), consumables goods (-28.6%), parts and accessories (-19.1%) and intermediate goods (-13.5%).

Electricity prices and tariffs

Our revenues and margins in our electricity generation and distribution 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 and distribution tariffs (including the tariff setting and adjustment process contemplated by Edenor’s distribution concessions).

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

Tariffs

Distribution

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See “Item 4. Our Distribution of Energy Business—Empresa Distribuidora y Comercializadora Norte S.A. (Edenor) —Tariffs”.

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.

During 2019, the electricity demand decreased by 3% compared to 2018, with a total electricity demand volume of 128,880 GWh and 133,010 GWh for 2019 and 2018, respectively.  

Peak Demand Records

	2019	2018	2017
Power Capacity (MW)	26,113	26,320	25,628
Date	1/29/2019	2/8/2018	2/24/2017
Temperature (°C)	34.0	30.2	27.7
Time	2:25 PM	3:35 PM	2:25 PM

                    Source: CAMMESA.

Generation of electricity decreased by 5% in 2019, from 137,199 GWh in 2018 to 130,838 GWh in 2019, mainly due to the downturn in the economic activity.

Thermal generation continued to be the main resource to supply demand in 2019, as it contributed 80,138 GWh (61%), followed by hydroelectric generation net of pumping, which contributed 34,961 GWh (27%), nuclear generation, which contributed 7,927 GWh (6%) and renewable generation, which contributed 7,812 GWh (6%). There were also imports, for 2,746 GWh (higher than 244 GWh recorded in 2018), exports for 261 GWh (7% lower than in 2018) and losses for 4,443 GWh (4% higher than in 2018).

Hydroelectric power generation net of pumping and thermal power generation’s contribution volumes experienced a 12% and 9% year-on-year decrease, respectively, mainly as a result of the lower electricity demand and the entrance of renewable energies. These decreases were partially offset by a 23% and 133% year-on-year increase in nuclear and renewable generation, respectively, mainly as a result of the commercial commissioning under the RenovAr and MAT ER programs, and the commissioning of Central Nuclear Embalse’s reconditioning.

The following chart shows the development of electricity generation by type of generation (thermal, hydro, nuclear and renewable):

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Generation by Type of Power Plant

In %, 2010 – 2019

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

During 2019, generation facilities have recorded an increase in their installed capacity compared to 2018, totaling 39,704 MW. The main new commercial operations starting in 2019 were for units under the RenovAr program and MAT ER for 1,220 MW, which includes PEPE II and PEPE III (106 MW).

The chart below shows the composition of installed capacity in Argentina (39.7 GW) as of December 31, 2019:

Argentina’s Installed Capacity

100%=39.7 GW

Source: CAMMESA

Regarding fuel supply for power generation, during 2019, SGE Res. No. 70/18 issued in November 2018 remained in force, which allowed thermal plants to acquire their own fuel for power generation. For those not exercising such option, CAMMESA remained in charge of the fuel’s operating and commercial management. For its instrumentation, maximum prices of natural gas within the PIST for the generation of electricity to be traded within the WEM, established by MinEn Res. No. 46/18 and SGE Notes No. 66680075/18 and 07973690/19, were observed.

The consumption of natural gas for electricity generation in 2019 decreased 5% compared to 2018 (17.2 million Dam³). There was a 67% decrease in fuel-oil consumption in 2019, a 54% decrease in gas-oil consumption and a 66% decrease in mineral coal, in each case compared to 2018.

The chart below shows the monthly average cost during 2019 (compared to 2018) that electricity consumers should pay so that the system does not become deficient. This cost includes, in addition to the price of energy, the capacity charge, the increased generation cost resulting from using fuel oil or diesel oil and other minor items.

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Monthly Average Monomic Cost (Ps. Per MWh) 

Source: CAMMESA.

             Seasonality

Seasonality also has a significant impact on the demand for electricity, with electricity consumption peaks in summer and winter. The impact of seasonal changes in demand is registered primarily among the residential and small commercial customers of Edenor. The seasonal changes in demand are attributable to the impact of various climatological factors, including weather and the amount of daylight time, on the usage of lights, heating systems and air conditioners.

The impact of seasonality on industrial demand for electricity is less pronounced than on the residential and commercial sectors for several reasons because (i) different types of industrial activity by their nature have different seasonal peaks, such that the effect on them of climate factors is more varied, and (ii) industrial activity levels tend to be more significantly affected by the economy, and with different intensity levels depending on the industrial sector.

             Cost of sales

Our most significant costs of sales are mainly comprised of 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.

               Reserves and Production of oil and gas

Natural gas and oil constitute the main energy sources in the national primary energy mix. The following chart illustrates their share as of December 31, 2018:

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2018 Argentine Energy Mix

100% = 75.5 million Ton of oil equivalent

 

Source: SGE.There is no available information for the year 2019.

              Natural Gas

In 2019, the total gross natural gas production increased to approximately 135 million m³/day, which represented a 5% increase compared to the volumes produced in 2018. This was mainly due to the continuous growth of production in the Neuquina Basin and, to a lesser extent, in the Austral Basin, with an increase in contributions associated with the development of unconventional gas reserves, which was partially offset by a decline in the Golfo San Jorge and Noroeste basins.

However, the domestic supply was not able to meet the domestic demands, a situation that has occurred since 2003, and, therefore, the Federal Government resorted to natural gas imports. As a result, the supply from Bolivia reached an average of 14 million m3/day in 2019, a figure 15% lower than the volume recorded in 2018. In addition, imports of seaborne LNG later injected into the national natural gas transportation system at the Escobar port, located in the Province of Buenos Aires, recorded an average contribution of 5 million m3 per day in 2019, 52% lower than the volume recorded in 2018. Furthermore, no imports of LNG regasified in Chile were recorded in 2019, whereas in 2018 they totaled 0.6 million m3 per day. Lower imports are mainly due to the drop in the domestic demand resulting from the economic recession, and the higher domestic production of unconventional gas as a result of the Gas Plan incentive to certain blocks.

Based on the last annual information published by the SGE, as of December 31, 2018 total natural gas reserves in Argentina reached 1,130,799 million m³, of which 33% are proved reserves. Furthermore, 57% of the total reserves and resources were unconventional. Compared to December 31, 2017, reserves have recorded a 7% increase and resources increased by 11%, totaling 399,584 million m3.

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Evolution of Natural Gas Production and Reserves and Resources*

In billion m³, 2006-2019

Source: SEG. * There is no available information on reserves for the year 2019. Production is gross.

             Crude Oil

Throughout 2019, total oil production amounted to 81 thousand m³ per day, a volume 4% higher than the volume recorded in 2018 (78 thousand m³ per day), confirming the downward trend in oil production recorded over the last sixteen years.

Based on the last annual information published by the SGE, in 2019 oil imports were not recorded, while in 2018, 1.2 thousand m³/day were imported. In 2019, oil exports amounted to 10.4 thousand m³/day, a volume 6% higher compared to 2018. This volume represented 13% of the total domestic production during 2019.

As of December 31, 2018, total oil reserves within the country reached 799,402 thousand m3, of which 48% were proven reserves. Additionally, 27% of total reserves and resources were unconventional. Furthermore, resources increased by 16%, totaling 169,501 thousand m3. 

Evolution of Oil Production and Reserves and Resources*

In million m³, 2006-2018

Source: SGE. * There is no available information on reserves for the year 2019.

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For information about the regulatory framework of our Oil and Gas business, please see “Item4. The Argentine Energy Sector—OIL & GAS REGULATORY FRAMEWORK”.

Critical Accounting Policies and Judgments

The preparation of the Consolidated Financial Statements, in conformity with IFRS requires our 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 the Consolidated Financial Statements. Our accounting policies and estimates are more fully described in Note 4 to the Consolidated Financial Statements, and estimates which have a significant risk of producing adjustments on the amounts of the assets and liabilities during the following year are detailed in Note 6.1 to our Consolidated Financial Statements.

Results of Operations

The table below provides a summary of our results of operations for the years ended December 31, 2019, 2018 and 2017.

Results of operations in relation to divested assets of refining and distribution and oil and gas segments, were disclosed within discontinued operations.  

	For the year ended December 31,
	2019	2018	2017
	(in million of US$)
Revenue	2,836	2,920	2,175
Cost of sales	(2,032)	(1,967)	(1,574)
Gross profit	804	953	601
Selling expenses	(148)	(171)	(127)
Administrative expenses	(174)	(206)	(198)
Exploration expenses	(9)	(1)	(2)
Other operating income	40	181	149
Other operating expenses	(86)	(200)	(103)
Impairment of property, plant and equipment	(62)	(32)	-
Share of profit from associates and joint ventures	101	118	48
Income from the sale of associates	-	28	-
Agreement on the regularization of obligations	285	-	-
Operating income	751	670	368
Gain on net monetary position	187	629	304
Finance income	96	99	62
Finance costs	(299)	(316)	(232)
Other financial results	113	(858)	(100)
Financial results, net	97	(446)	34
Profit before income tax	848	224	402
Income tax	(48)	(17)	26
Profit for the year from continuing operations	800	207	428
Profit (Loss) for the year from discontinued operations	-	80	(50)
Total Profit of the year	800	287	378
Total Profit of the year attributable to:
Owners of the Company	692	224	286
Non - controlling interest	108	63	92

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	For the year ended December 31,
	2019	2018	2017
	(in million of US$)
Revenue
Generation	819	606	353
Distribution of energy	1,502	1,484	1,050
Oil and gas	444	521	462
Petrochemical	321	338	314
Holding and others	20	36	17
Eliminations	(270)	(65)	(21)
Total Sales	2,836	2,920	2,175
Gross profit
Generation	353	333	158
Distribution of energy	277	348	251
Oil and gas	131	234	152
Petrochemical	23	4	24
Holding and others	20	36	16
Eliminations	-	(2)	-
Total Gross profit	804	953	601
Operating income
Generation	273	274	130
Distribution of energy	342	103	61
Oil and gas	71	250	152
Petrochemical	5	(62)	(11)
Holding and others	60	106	35
Eliminations	-	(1)	1
Total operating income	751	670	368
Total profit of the year
Generation	248	106	79
Distribution of energy	197	116	138
Oil and gas	63	(113)	(42)
Petrochemical	11	(54)	(6)
Holding and others	281	231	207
Eliminations	-	1	2
Total profit of the year	800	287	378
Total profit attributable to owners of the company
Generation	239	100	75
Distribution of energy	98	61	73
Oil and gas	63	(115)	(65)
Petrochemical	11	(54)	(6)
Holding and others	281	231	207
Eliminations	-	1	2
Total profit attributable to owners of the company	692	224	286
Total profit attributable to non - controlling interest
Generation	9	6	4
Distribution of energy	99	55	65
Oil and gas	-	2	23
Total profit attributable to non - controlling interest	108	63	92

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The Company is a fully integrated power company in Argentina, which participates in the electricity, 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 CPB, HINISA, HIDISA, Greenwind, Enecor, TMB, TJSM, CTB and through our own electricity generation activities through thermal plants Güemes, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picun Leufu hydroelectric complex and Pampa Energía I and II wind farms;

· Distribution of Energy, consisting of our direct interest in Edenor;

· Oil and Gas, consisting of our own interests in oil and gas areas and through our direct interests in PACOSA, and Oldelval and our indirect interest in OCP;

· Petrochemicals, comprised of our own styrene operations and the catalytic reformer plant operations conducted in Argentine plants; and

· Holding and Other Business, consisting of financial investment transactions, holding activities, 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.

The Company manages its operating segments based on its individual net profit.

154

 

Year ended December 31, 2019 compared to year ended December 31, 2018

              Generation Segment

	Generation
	12.31.2019	12.31.2018	Variation	%
Revenue	819	606	213	35%
Cost of sales	(466)	(273)	(193)	71%
Gross profit	353	333	20	6%
Selling expenses	(3)	(1)	(2)	200%
Administrative expenses	(36)	(41)	5	(12%)
Other operating income and expenses, net	(2)	(6)	4	(67%)
Share of profit from joint ventures	13	(11)	24	(218%)
Impairment of property, plant and equipment	(52)	-	(52)	(100%)
Operating income	273	274	(1)	(0%)
Gains on net monetary position	-	233	(233)	100%
Finance income	51	52	(1)	(2%)
Finance costs	(82)	(85)	3	(4%)
Other financial results	86	(365)	451	(124%)
Financial results, net	55	(165)	220	(133%)
Profit before income tax	328	109	219	201%
Income tax	(80)	(3)	(77)	2,567%
Profit of the year	248	106	142	134%
Owners of the Company	239	100	139	139%
Non - controlling interest	9	6	3	50%

              Revenue

Revenue from our generation segment increased by 35%, to US$819 million, during the fiscal year ended December 31, 2019, compared to US$606 million for the same period in 2018. The segment’s US$213 million increase in electricity sales was mainly due to: (i) the recognition of higher sales during 2019 related to fuel self-supply as allowed pursuant to SGE Resolution No. 70/18 as from November 2018, and (ii) the commissioning of new wind farms (PEPE II and PEPE III), partially offset by (iii) lower spot market prices in accordance to SRRYME Resolution No. 1/19 effective as from March 2019.

The amount of electricity sold remained stable compared to 2018 (16,072 GWh for the fiscal year ended December 31, 2019, compared to 15,599 GWh for the fiscal year ended December 31, 2018).

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

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GWh	Fiscal years ended December 31,
	2019			2018
	Net generation	Purchases	Total sales	Net generation	Purchases	Total sales
Hydroelectric facilities:
HINISA	498	-	498	577	-	577
HIDISA	334	-	334	393	-	393
HPPL	823	-	823	886	-	886
Thermal facilities:
CTG	755	137	891	1,674	553	2,227
CTLL	5,096	-	5,096	4,748	-	4,748
CTP	53	-	53	134	-	134
CPB	1,106	-	1,106	753	-	753
CTPP	168	-	168	192	-	192
CTIW	312	-	312	274	-	274
CTGEBA	5,550	337	5,887	4,859	598	5,457
EcoEnergía	105	5	110	108	2	110
CTEB (1)	128	-	128	-	-	-
Wind facilities:
PEMC (1)	247	-	247	-	-	-
PEPE2	122	7	129	-	-	-
PEPE3	148	5	154	-	-	-
Total	15,582	490	16,072	14,845	1,154	15,999
Note: All figures have been subject to rounding, so figures shown as totals may not add up. (1)Non-consolidated plant

             Cost of Sales

Cost of sales increased by 71%, to US$466 million for the fiscal year ended December 31, 2019, compared to US$273 million for the fiscal year ended December 31, 2018, mainly due to: (i) US$176 million for higher gas purchases; (ii) US$5 million for higher depreciation of property, plant and equipment, and (iii) US$5 million for higher rental and insurance costs.

             Gross Profit

Gross profit from our generation segment increased by US$20 million and recorded a US$353 million profit for the fiscal year ended December 31, 2019, compared to a US$333 million profit for the same period in 2018. On the other hand, gross margin on sales decreased to 43% for the year ended December 31, 2019 compared to 55% for the same period in 2018.

               Selling Expenses

Selling expenses from our generation segment increased to US$3 million, for the fiscal year ended December 31, 2019, compared to US$1 million for the fiscal year ended December 31, 2018, mainly due to US$1 million for higher charges for taxes, rates and contributions and US$1 million for higher net impairment losses on financial assets.

              Administrative Expenses

Administrative expenses decreased by 12%, to US$36 million, for the fiscal year ended December 31, 2019, compared to US$41 million for the fiscal year ended December 31, 2018, mainly due to US$5 million for lower labor costs.

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             Other Operating Income and Expenses, Net

Other operating income and expenses, net decreased by US$4 million, due to a US$2 million loss, for the fiscal year ended December 31, 2019, compared to a US$6 million loss for the fiscal year ended December 31, 2018, mainly attributable to: (i) the absence, during 2019 fiscal year, of the US$12 million loss registered on account of provision for contingencies, partially offset by (ii) US$4 million for higher tax on bank transactions and (iii) US$2 million for lower insurance recoveries.

              Operating Income

Operating income of our generation segment amounted to US$273 million for the fiscal year ended December 31, 2019, compared to US$274 million for the same period in 2018, thus remaining stable. The operating margin on sales for 2019 fiscal year decreased to 33% compared to 45% in 2018 fiscal year.

               Financial Results, Net

Net financial results from the generation segment accounted for a US$55 million gain for the fiscal year ended December 31, 2019, compared to a US$165 million loss for the fiscal year ended December 31, 2018, mainly due to: (i) US$340 million for lower losses generated by net foreign exchange difference mainly as a result of the change in Pampa’s functional currency as from January 1, 2019 (see Note 3.1 to our Consolidated Financial Statements); (ii) a US$49 million gain on discounted value measurement, during 2019, compared to a US$41 million loss during 2018; (iii) US$16 million for higher gains on changes in the fair value of financial instruments, and (iv) US$2 million for lower financial interest expenses net. These effects were partially offset by US$233 million from gains on net monetary position resulting from the application of IAS 29 during the 2018 fiscal year.

              Income Tax

Generation segment recorded an income tax charge of US$80 million for the fiscal year ended December 31, 2019, compared to US$3 million charge for the fiscal year ended December 31, 2018, in line with the improvement in profits during the 2019 fiscal year.

             Profit

Generation segment recorded a US$248 million profit for the fiscal year ended December 31, 2019, of which US$239 million are attributable to the owners of the Company, compared to US$100 million attributable to the owners of the Company for the fiscal year ended December 31, 2018.

             Distribution of energy segment

	Distribution of energy
	12.31.2019	12.31.2018	Variation	%
Revenue	1,502	1,484	18	1%
Cost of sales	(1,225)	(1,136)	(89)	8%
Gross profit	277	348	(71)	(20%)
Selling expenses	(122)	(134)	12	(9%)
Administrative expenses	(65)	(76)	11	(14%)
Other operating income and expenses, net	(33)	(35)	2	(6%)
Agreement on regularization of obligations	285	-	285	100%
Operating income	342	103	239	232%
Gains on net monetary position	187	226	(39)	(17%)
Finance income	20	18	2	11%
Finance costs	(112)	(132)	20	(15%)
Other financial results	(62)	(50)	(12)	24%
Financial results, net	33	62	(29)	(47%)
Profit before income tax	375	165	210	127%
Income tax	(178)	(49)	(129)	263%
Profit of the year	197	116	81	70%
Owners of the Company	98	61	37	61%
Non - controlling interest	99	55	44	80%

157

 

               Revenues

Revenues from our distribution of energy segment increased by 1%, to US$1,502 million for the fiscal year ended December 31, 2019, compared to US$1,484 million for the fiscal year ended December 31, 2018.

              Cost of Sales

The cost of sales for the distribution of energy segment increased by 8% to US$1,225 million for the fiscal year ended December 31, 2019, compared to US$1,136 million for the fiscal year ended December 31, 2018, mainly due to: (i) a US$106 million increase in energy purchases, (ii) a US$8 million increase in property, plant and equipment depreciation; (iii) a US$6 million increase in fees and compensation for services, and (iv) a US$6 million increase on consumption of materials. These effects were partially offset by: (i) US$31 million for lower charges in fines and penalties, and (ii) US$7 million for lower labor costs.

             Gross Profit

Gross profit from our distribution of energy segment decreased by US$71 million and amounted to US$277 million for the fiscal year ended December 31, 2019, compared to US$348 million for the same period in 2018. Likewise, gross margin on sales decreased to 18% for the year ended December 31, 2019 compared to 23% for the same period in 2018.

              Selling Expenses

The distribution of energy segment’s selling expenses decreased by 9%, to US$122 million, in the fiscal year ended December 31, 2019, compared to US$134 million in the fiscal year ended December 31, 2018, mainly due to: (i) a US$6 million decrease in fines and penalties, (ii) a US$4 million decrease in labor costs, and (iii) a US$3 million decrease in net impairment losses on financial assets.

              Administrative Expenses

Administrative expenses decreased by 14%, to US$65 million, for the fiscal year ended December 31, 2019, compared to US$76 million for the fiscal year ended December 31, 2018, mainly due to: (i) a US$4 million decrease in fees and compensation for services; (ii) a US$1 million decrease in labor costs; (iii) a US$1 million decrease in rentals and insurance, and (iv) a US$1 million decrease in surveillance and security service charge.

              Other Operating Income and Expenses, Net

Other operating income and expenses, net recorded for losses of US$33 million for the fiscal year ended December 31, 2019 as compared to US$35 million during the fiscal year ended December 31, 2018 mainly due to a US$3 million decrease of the non-recognition of property, plant and equipment and a US$3 million decrease in tax on bank transactions, partially offset by US$4 million higher provision for contingencies charges.

158

 

              Operating Income

The operating income from our distribution of energy segment accounted for a profit of US$342 million for the fiscal year ended December 31, 2019, representing an increase of US$239 million when compared to the US$103 million profit for the fiscal year ended December 31, 2018. Likewise, the operating margin on sales in fiscal year 2019 was 23%, compared to 7% in fiscal year 2018. Furthermore, during fiscal year 2019, a US$285 million operating gain was recorded as a result of the Agreement on the regularization obligations.

              Financial Results, Net

Net financial results related to our distribution of energy segment decreased by 47% and amounted to an income of US$33 million for the fiscal year ended December 31, 2019, compared to an income of US$62 million for the fiscal year ended December 31, 2018, mainly due to: (i) US$39 million lower gain on net monetary position and (ii) a US$17 million lower income for changes in the fair value of financial instruments, which were partially offset by US$22 million in lower net financial expenses.

              Income Tax

Our distribution of energy segment recorded an income tax charge of US$178 million in the fiscal year ended December 31, 2019, compared to a US$49 million charge for the fiscal year ended December 31, 2018, in line with the improvement in profits during the 2019 fiscal year.

             Profit

Distribution of energy segment generated a US$197 million profit million for the fiscal year ended December 31, 2019, of which US$98 million are attributable to the owners of the Company, compared to a US$116 million profit, of which US$61 million were attributable to the owners of the Company for the fiscal year ended December 31, 2018.

              Oil and Gas Segment

	Oil and Gas
	31.12.2019	31.12.2018	Variation	%
Revenue	444	521	(77)	(14.8%)
Cost of sales	(313)	(287)	(26)	9.1%
Gross profit	131	234	(103)	(44.0%)
Selling expenses	(12)	(19)	7	(36.8%)
Administrative expenses	(47)	(56)	9	(16.1%)
Exploration expenses	(9)	(1)	(8)	800.0%
Other operating income and expenses, net	(3)	27	(30)	(111.1%)
Share of profit from associates	21	37	(16)	(43.2%)
Income from the sale of companies	-	28	(28)	100.0%
Impairment of property, plant and equipment	(10)	-	(10)	(100.0%)
Operating income	71	250	(179)	(71.6%)
Gains on net monetary position	-	107	(107)	100.0%
Finance income	18	15	3	20.0%
Finance costs	(94)	(79)	(15)	19.0%
Other financial results	84	(512)	596	(116.4%)
Financial results, net	8	(469)	477	(101.7%)
Profit (Loss) before income tax	79	(219)	298	(136.1%)
Income tax	(16)	57	(73)	(128.1%)
Profit (Loss) from continuing operations	63	(162)	225	(138.9%)
Discontinued operations	-	49	(49)	100.0%
Profit (Loss) of the year	63	(113)	176	(155.8%)
			-
Owners of the Company	63	(115)	178	(154.8%)
Non - controlling interest	-	2	(2)	100.0%

159

 

Revenues

Revenues from continuing operations in our oil and gas segment amounted to US$444 million for the fiscal year ended December 31, 2019, which was 15% lower than US$521 million for the fiscal year ended December 31, 2018. The US$77 million decrease was attributable to the decrease in oil and gas average prices for 2019 fiscal year, which was partially offset by the increase in gas sales volumes.

The following table shows our production for the oil and gas segment for the periods shown, including the production of discontinued operations:

	Fiscal years ended December 31,
	2019	2018
Oil (thousand m3/d)
Continuing operations	0.8	0.8
Discontinued operations	-	2
Total	0.8	2.8
Gas (thousand m3/d)
Continuing operations	7,344	6,753
Discontinued operations	-	1,112
Total	7,344	7,865
GLP (thousand m3/d)
Continuing operations	-	-
Discontinued operations	-	0.1
Total	-	0.1
Note: All figures have been subject to rounding, so figures shown as totals may not add up.

              Cost of Sales

The cost of sales from our oil and gas segment from continuing operations increased by 9%, to US$313 million for the fiscal year ended December 31, 2019, compared to US$287 million for the fiscal year ended December 31, 2018, mainly due to: (i) a US$20 million increase in property, plant and equipment depreciations, and (ii) a US$11 million increase in purchases of inventory and gas. These effects were partially offset by a US$15 million decrease in royalties.

Gross Profit

Gross profit from our oil and gas segment decreased by US$103 million and recorded a US$131 million profit for the fiscal year ended December 31, 2019, compared to a US$234 million profit for the same period in 2018. The gross margin of sales decreased to 30% for the fiscal year ended December 31, 2019, compared to 45% for the same period in 2018.

160

 

              Selling Expenses

Selling expenses from our oil and gas segment from continuing operations decreased by 37% to US$12 million for the fiscal year ended December 31, 2019, compared to US$19 million for the same period in 2018, mainly due to: (i) a US$5 million decrease in taxes, fees and contributions, and (ii) a US$3 million decrease in compensation agreement charges.

              Administrative Expenses

Administrative expenses from continuing operations decreased by 16% to US$47 million for the fiscal year ended December 31, 2019, compared to US$56 million for the fiscal year ended December 31, 2018, mainly due to: (i) a US$7 million decrease in labor costs; (ii) a US$3 million decrease in compensation agreements charges, and (iii) a US$1 million decrease in taxes, fees and contributions. These effects were partially offset by a US$2 million increase in fees and compensation for services.

              Exploration Expenses

Exploration expenses from our oil and gas segment from continuing operations amounted to US$9 million, during the fiscal year ended December 31, 2019, compared to US$1 million in the fiscal year ended December 31, 2018, mainly due to higher well write-offs (US$4 million) and higher geological and geophysical expenses (US$4 million).

              Other Operating Income and Expenses, net

Other operating income and expense, net from continuing operations amounted to a loss of US$3 million, for the fiscal year ended December 31, 2019, compared to gain of US$27 million for the fiscal year ended December 31, 2018. This decrease was mainly a result of (i) the US$30 million income from the settlement agreement in Ecuador TLC recorded in 2018, and (ii) the absence of Gas Plan compensations due to the expiration of Gas Plan II from July 1, 2018. These effects were partially offset by (i) the US$9 million ship or pay contract loss recorded in 2018, and (ii) the absence of charges resulting from agreements with provincial treasuries in relation with the Gas Plan compensations.

             Operating Income

The operating income from our oil and gas segment from continuing operations decreased by 72% and accounted for US$71 million for the fiscal year ended December 31, 2019, compared to the US$250 million for the fiscal year ended December 31, 2018. Consequently, gross margin on sales decreased to 16% for the year ended December 31, 2019 compared to 48% for the same period in 2018.

             Financial Results, Net

The net financial results from the oil and gas segment from continuing operations amounted to a gain of US$8 million for the fiscal year ended December 31, 2019, compared to a loss of US$469 million for the fiscal year ended December 31, 2018, mainly due to: (i) US$567 million for lower losses generated by net foreign exchange difference mainly as a result of the change in Pampa’s functional currency as from January 1, 2019 (see Note 3.1 to our Consolidated Financial Statements); (ii) a US$1 million gain on discounted value measurement, during 2019, compared to a US$17 million loss during 2018; and (iii) US$17 million for higher gains from repurchase of financial debt. These effects were partially offset by (i) US$107 million from gains on net monetary position resulting from the application of IAS 29 during 2018 fiscal year, and (ii) US$7 million lower gains from changes in the fair value of financial instruments.

             Income Tax

Our oil and gas segment’s continuing operations recorded an income tax charge of US$16 million for the fiscal year ended December 31, 2019, compared to an income tax benefit of US$57 million for the same period in 2018, in line with the improvement of profits during 2019 fiscal year.

161

 

            Profit

Our oil and gas segment’s continuing operations recorded a profit of US$63 million for the fiscal year ended December 31, 2019, compared to a loss of US$162 million for the same period in 2018.

Our oil and gas segment recorded a total profit of US$49 million for discontinued operations in the fiscal year ended December 31, 2018, due to the sale in April 2018 of the direct 58.88% interest in PELSA and the direct interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Medanito-Jagüel de los Machos blocks.

Finally, our oil and gas segment recorded a total profit for continuing and discontinued operations of US$63 million for the fiscal year ended December 31, 2019, all of which were attributable to the owners of the Company, compared to a total loss of US$113 million recorded for the fiscal year ended December 31, 2018, of which US$115 million were attributable to the owners of the Company.

            Petrochemicals Segment

	Petrochemicals
	12. 31.2019	12. 31.2018	Variation	%
Revenue	321	338	(17)	(5%)
Cost of sales	(298)	(334)	36	(11%)
Gross profit	23	4	19	475%
Selling expenses	(9)	(13)	4	(31%)
Administrative expenses	(4)	(6)	2	(33%)
Other operating income and expenses, net	(5)	(15)	10	(67%)
Impairment of property, plant and equipment	-	(32)	32	(100%)
Operating income	5	(62)	67	(108%)
Gains on net monetary position	-	49	(49)	(100%)
Finance income	1	1	-	0%
Finance costs	(8)	(15)	7	(47%)
Other financial results	18	(39)	57	(146%)
Financial results, net	11	(4)	15	(375%)
Profit (Loss) before income tax	16	(66)	82	(124%)
Income tax	(5)	12	(17)	(142%)
Profit (Loss) of the year	11	(54)	65	(120%)
Owners of the Company	11	(54)	65	(120%)
Non - controlling interest	-	-	-	0%

             Revenues

Revenues from our petrochemicals segment amounted to US$321 million during the fiscal year ended December 31, 2019, 5% lower than US$338 million for the fiscal year ended December 31, 2018.

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

Selling volume (in thousands tons)	2019	2018
Styrene & Polystyrene	99	113
SBR	27	26
Others	217	215
Total	343	355
Note: All figures have been subject to rounding, so figures shown as totals may not add up.

162

 

              Cost of Sales

The petrochemicals segment’s cost of sales decreased by 11%, to US$298 million, for the fiscal year ended December 31, 2019, compared to US$334 million for the fiscal year ended December 31, 2018, mainly due to: (i) a US$22 million decrease in consumption of materials; (ii) a US$5 million decrease in labor costs; (iii) a US$5 million decrease in depreciation of property, plant and equipment, and (iv) US$2 million decrease in raw material purchases.

Gross Profit

Gross profit from our petrochemicals segment increased by US$19 million and recorded a US$23 million profit for the fiscal year ended December 31, 2019, compared to a US$4 million profit for the same period in 2018. Likewise, the gross margin on sales in 2019 increased to 7% from 1% in 2018.

             Selling Expenses

Selling expenses from the petrochemicals segment amounted to US$9 million for the fiscal year ended December 31, 2019, 31% lower than the US$13 million recorded for the fiscal year ended December 31, 2018, mainly due to: (i) a US$2 million decrease in net impairment losses on financial assets, and (ii) a US$1 million decrease in taxes, fees and contributions.

              Administrative Expenses

Administrative expenses decreased to US$4 million during fiscal year ended December 31, 2019, compared to US$6 million in the fiscal year ended December 31, 2018.

              Other Operating Income and Expenses, Net

Other operating income and expenses, net recorded a loss of US$5 million for the fiscal year ended December 31, 2019, compared to a loss of US$15 million during the fiscal year ended December 31, 2018, mainly on account of US$12 million of lower idle capacity charges.

              Operating Income (Loss)

The petrochemicals segment’s operating income (loss) accounted for an income of US$5 million for the fiscal year ended December 31, 2019, compared to a loss of US$62 million for the fiscal year ended December 31, 2018. The operating margin on sales for fiscal year 2019 was 2%, compared to the operating loss on sales of 18% in fiscal year 2018.

               Financial Results, Net

The net financial results from the petrochemicals segment represented a gain of US$11 million during fiscal year ended December 31, 2019, compared to a loss of US$4 million for the fiscal year ended December 31, 2018, mainly due to: (i) US$46 million for higher gains from net foreign exchange difference mainly as a result of the change in Pampa’s functional currency as from January 1, 2019 (see Note 3.1 to our Consolidated Financial Statements) and (ii) US$7 million for lower financial expenses net. These effects were partially offset by US$49 million from gains on net monetary position resulting from the application of IAS 29 during the 2018 fiscal year.

              Income Tax

Our petrochemicals segment recorded an income tax charge of US$5 million for the fiscal year ended December 31, 2019, compared to an income tax benefit of US$12 million for the fiscal year ended December 31, 2018.

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              Total (Profit) Loss

The petrochemicals segment disclosed a net profit of US$11 million for the fiscal year ended December 31, 2019, compared to a net loss of US$54 million all of which are attributable to the owners of the Company.

Holding and Others Segment

	Holding and others
	12.31.2019	12.31.2018	Variation	%
Revenue	20	36	(16)	(44%)
Cost of sales	-	-	-	-
Gross profit	20	36	(16)	(44%)
Selling expenses	(2)	(4)	2	(50%)
Administrative expenses	(22)	(27)	5	(19%)
Other operating income and expenses, net	(3)	9	(12)	(133%)
Share of profit from joint ventures	67	92	(25)	(27%)
Operating income	60	106	(46)	(43%)
Results on net monetary position	-	12	(12)	(100%)
Finance income	7	14	(7)	(50%)
Finance costs	(4)	(6)	2	(33%)
Other financial results	(13)	108	(121)	(112%)
Financial results, net	(10)	128	(138)	(1)
Profit before income tax	50	234	(184)	100%
Income tax	231	(34)	265	(779%)
Profit from continuing operations	281	200	81	0
Discontinued operations	-	31	(31)	(100%)
Profit of the year	281	231	50	22%
Owners of the Company	281	231	50	22%
Non - controlling interest	-	-	-	-

              Revenues

Revenues from our holding and others segment amounted to US$20 million for the fiscal year ended December 31, 2019, US$16 million lower than US$36 million for the fiscal year ended December 31, 2018.

             Cost of Sales

Cost of sales of the holding and others segment was not material for fiscal years ended December 31, 2019 and 2018.

             Gross Profit

Gross profit from our holding and others segment decreased by US$16 million and recorded a US$20 million profit for the fiscal year ended December 31, 2019, compared to a US$36 million profit for the same period in 2018.

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                Selling Expenses

                   Selling expenses from our holding and others segment amounted to US$2 million and US$4 million for the fiscal years ended December 31, 2019 and 2018, respectively.

             Administrative Expenses

Administrative expenses decreased by 19%, to US$22 million, during the fiscal year ended December 31, 2019, compared to US$27 million for the fiscal year ended December 31, 2018. This decrease was mainly due to US$8 million lower charges for fees and compensations for services, partially offset by US$3 million higher charges for directors and syndicates’ fees and US$3 million higher labor costs.

             Other Operating Income and Expenses, Net

Other operating income and expenses, net recorded a loss of US$3 million for the fiscal year ended December 31, 2019 compared to a profit of US$9 million for the fiscal year ended December 31, 2018, due to: (i) US$6 million lower gains from services to third-parties, (ii) US$3 million allowance for uncollectible tax credits recorded in 2019 fiscal year and (iii) US$3 million for lower reversal of contingencies provision.

             Operating Income

Our holding and others segment’s operating income amounted to US$60 million for the fiscal year ended December 31, 2019, 43% lower than the US$106 million recorded for the fiscal year ended December 31, 2018. This variation includes a decrease of US$25 million in share of profit from joint ventures to US$67 million gain for the year ended December 31, 2019 compared to US$92 million gain for the year ended December 31, 2018.

              Financial Results, Net

Net financial results from our holding and other segment amounted to a loss of US$10 million for the fiscal year ended December 31, 2019 compared to a US$128 million gain for the fiscal year ended December 31, 2018, mainly due to: (i) a US$21 million loss from net foreign exchange difference, during 2019, compared to a US$156 million gain during 2018 mainly as a result of the change in Pampa’s functional currency as from January 1, 2019 (see Note 3.1 to our Consolidated Financial Statements); (ii) a US$12 million gains on net monetary position resulting from the application of IAS 29 during the 2018 fiscal year, and (iii) US$5 million for lower net financial gains. These effects were partially offset by: (i) a US$3 million gain from changes in the fair value of financial instruments, compared to a US$32 million loss in 2018 and (ii) a US$5 million gain from current valuation of asset, during 2019, compared to a US$17 million loss during 2018.

              Income Tax

Our holding and others segment recorded an income tax benefit of US$231 million for the fiscal year ended December 31, 2019, compared to a US$34 million charge for the fiscal year ended December 31, 2018.

             Total Profit

Our holding and others segment registered a net profit from continuing operations of US$281 million for the fiscal year ended December 31, 2019 compared to a net profit of US$200 million recorded in the fiscal year ended December 31, 2018, all of which are attributable to the owners of the Company.

Our holding and others segment recorded a profit of US$31 million for discontinued operations in the fiscal year ended December 31, 2018, due to the sale in May 2018 of the main assets of the refining and distribution segment.

Our holding and others segment registered a net profit from continuing and discontinued operations of US$281 million for the fiscal year ended December 31, 2019 compared to a net profit of US$231 million recorded in the fiscal year ended December 31, 2018, all of which are attributable to the owners of the Company.

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Year ended December 31, 2018 compared to year ended December 31, 2017

              Generation Segment

	Generation
	12.31.2018	12.31.2017	Variation	%
Revenue	606	353	253	72%
Cost of sales	(273)	(195)	(78)	40%
Gross profit	333	158	175	111%
Selling expenses	(1)	(4)	3	(75%)
Administrative expenses	(41)	(32)	(9)	28%
Other operating income and expenses, net	(6)	10	(16)	(160%)
Share of profit from joint ventures	(11)	(2)	(9)	450%
Operating income	274	130	144	111%
Gain on net monetary position	233	17	216	1,271%
Finance income	52	39	13	33%
Finance costs	(85)	(69)	(16)	23%
Other financial results	(365)	(34)	(331)	974%
Financial results, net	(165)	(47)	(118)	251%
Profit before income tax	109	83	26	31%
Income tax	(3)	(4)	1	(25%)
Profit of the year	106	79	27	34%
Owners of the company	100	75	25	33%
Non - controlling interest	6	4	2	50%

              Revenue

Revenues from our generation segment increased by 72%, to US$606 million, during the fiscal year ended December 31, 2018, compared to US$353 million for the same period in 2017. The segment’s US$253 million increase in electricity sales was mainly due to: (i) the impact of the devaluation of the Peso on sales denominated in U.S. Dollar, (ii) the commissioning of new thermal power plants (CTPP and CTIW), (iii) the incorporation of additional installed capacity in CTLL (new LMS100 plant and extension of the closing to combined cycle), and (iv) the recognition of the generation cost with own fuels as from November 2018, as allowed pursuant to SGE Resolution No. 70/2018.

The amount of electricity sold remained stable compared to 2017 (15,599 GWh for the fiscal year ended December 31, 2018, compared to 15,514 GWh for the fiscal year ended December 31, 2017) since the additional generation of the new thermal power plants was offset by downtimes at CTGEBA, a lower dispatch at CPB and lower water flow and input at HIDISA and HINISA.

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

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GWh	Fiscal years ended December 31,
	2018			2017
	Net generation	Purchases	Total sales	Net generation	Purchases	Total sales
Hydroelectric facilities:
HINISA	577	-	577	751	-	751
HIDISA	393	-	393	480	-	480
HPPL	886	-	886	760	-	760
Thermal facilities:
CTG	1,674	553	2,227	1,772	586	2,358
CTLL	4,748	-	4,748	3,864	-	3,864
CTP	134	-	134	156	-	156
CPB	753	-	753	1,453	-	1,453
CTPP4	192	-	192	142	-	142
CTIW5	274	-	274	23	-	23
CTGEBA	4,859	598	5,457	4,685	739	5,424
EcoEnergía	108	2	110	100	3	103
Wind facilities:
PEMC	247	-	247	-	-	-
Total	14,845	1,154	15,999	14,186	1,328	15,514
Note: All figures have been subject to rounding, so figures shown as totals may not add up.

              Cost of Sales

Cost of sales increased by 40%, to US$273 million for the fiscal year ended December 31, 2018, compared to US$195 million for the fiscal year ended December 31, 2017, mainly due to: (i) higher gas purchases for generation; (ii) the impact of the devaluation of the Peso on energy purchases denominated in, or pegged to, other currencies; and (iii) the higher depreciation of property, plant and equipment, and higher maintenance costs and materials consumption, resulting from the commissioning of the new thermal power plants.

             Gross Profit

Gross profit from our generation segment increased by US$175 million and recorded a US$333 million profit for the fiscal year ended December 31, 2018, compared to a US$158 million profit for the same period in 2017.

             Selling Expenses

Selling expenses from our generation segment decreased by 75%, to US$1 million, for the fiscal year ended December 31, 2018, compared to US$4 million for the fiscal year ended December 31, 2017, mainly due to lower charges for taxes, rates and contributions and net impairment losses on financial assets mainly resulting from the effects of the application of IFRS 9.

              Administrative Expenses

Administrative expenses increased by 28%, to US$41 million, for the fiscal year ended December 31, 2018, compared to US$32 million for the fiscal year ended December 31, 2017, mainly due to higher labor costs for an increase in the staffing allocated to the generation segment and higher fees for third-party services.

              Other Operating Income and Expenses Net

Other net operating income and expenses decreased by US$16 million, to a US$6 million loss, for the fiscal year ended December 31, 2018, compared to a profit of US$10 million for the fiscal year ended December 31, 2017, mainly attributable to: (i) the absence, during the 2018 fiscal year, of the recovery of receivables and others, mainly from tax credits resulting from the merger of subsidiaries and the recovery of tax contingencies resulting from the adherence to the regularization regime (moratorium) provided by Law No. 27,260 regarding certain claims by tax authorities associated with the importation of a generation turbine and certain spare parts, which provides for benefits consisting of the waiver of tax fines and a reduction of compensatory interest during the fiscal year ended December 31, 2017; (ii) the granting of the guarantee for the construction of PEPE IV during the fiscal year ended December 31, 2018; (iii) all of which was offset by insurance recoveries recorded in fiscal year 2018 on account of the accident which took place at CTGEBA in 2017.

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             Operating Income

Operating income of our generation segment amounted to US$274 million for the fiscal year ended December 31, 2018, compared to US$130 million for the same period in 2017.

              Financial Results, Net

Net financial results from generation activities accounted for a US$165 million loss for the fiscal year ended December 31, 2018, compared to a loss of US$47 million for the fiscal year ended December 31, 2017, mainly due to: higher losses in other financial results, in the amount of US$331 million, mainly generated by net foreign exchange differences of financial debt and, to a lower extent, the loss resulting from the re estimation of the value of receivables from CAMMESA, which were partially offset by US$216 million resulting from the gain on net monetary position resulting from the application of IAS 29.

           Income Tax

Power generation activities recorded an income tax charge of US$3 million for the fiscal year ended December 31, 2018, compared to a charge of US$4 million for the fiscal year ended December 31, 2017, due to the fact that the 2017 fiscal year was negatively impacted by the effect of income tax rate reduction on a deferred tax asset position.

            Total Profit

Generation activities recorded a net profit of US$106 million for the fiscal year ended December 31, 2018, of which US$100 million are attributable to the owners of the Company, compared to US$75 million attributable to the owners of the Company for the fiscal year ended December 31, 2017.

Distribution of energy segment

	Distribution of energy
	12.31.2018	12.31.2017	Variation	%
Revenue	1,484	1,050	434	41%
Cost of sales	(1,136)	(799)	(337)	42%
Gross profit	348	251	97	39%
Selling expenses	(134)	(95)	(39)	41%
Administrative expenses	(76)	(66)	(10)	15%
Other operating income and expenses, net	(35)	(29)	(6)	21%
Operating income	103	61	42	69%
Gain on net monetary position	226	145	81	56%
Finance income	18	12	6	50%
Finance costs	(132)	(69)	(63)	91%
Other financial results	(50)	1	(51)	(5,100%)
Financial results, net	62	89	(27)	(30%)
Profit before income tax	165	150	15	10%
Income tax	(49)	(12)	(37)	308%
Profit of the year	116	138	(22)	(16%)
Owners of the company	61	73	(12)	(16%)
Non - controlling interest	55	65	(10)	(15%)

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                Revenues

Revenues from our distribution of energy activities increased by 41%, to US$1,484 million, for the fiscal year ended December 31, 2018, compared to US$1,050 million for the fiscal year ended December 31, 2017, mainly on account of the increase in the cost of energy purchases, which represent 74% of the variation. The remainder of the variation is due to the entry into effect of the update in the Distribution Value Added (VAD) provided for in the RTI process, together with the bi-annual CPD adjustments. Between December 31, 2017 and December 31, 2018, increases totaling 87.7% were applied, and the last update corresponding to the first semester of 2018 was partially applied, with the application of the remainder being deferred to March 2019. If the full VAD update had been recorded, in the fourth quarter of 2018 sales would have increased. This increase in revenue was reduced by a 2% decrease in the volume of energy sales.

              Cost of Sales

The cost of sales for the distribution of energy segment increased by 42% to US$1,136 million for the fiscal year ended December 31, 2018, compared to US$799 million for the fiscal year ended December 31, 2017, mainly due to: (i) increases in the average price of energy purchases resulting from the entry into effect in December 2017, February 2018 and August 2018 of the new reference seasonal prices for electricity set forth by Resolution No. 1,091/17 and Provision No. 75/18 of the former Secretariat of Electric Energy (SEE), (ii) increases in fines and penalties resulting from recovery in the year 2017, and an increase, in 2018, due to the new penalties imposed by ENRE Resolution No. 91/18 for breaches in reading and billing terms and the change in the methodology for the calculation of penalties, and (iii) an increase in fees for third-party services. These increases were partially offset by a decrease in costs for salaries and social security taxes.

              Gross Profit

Gross profit from our distribution of energy segment increased by US$97 million and recorded a US$348 million profit for the fiscal year ended December 31, 2018, compared to a US$251 million profit for the same period in 2017.

              Selling Expenses

The distribution of energy segment’s selling expenses increased by 41%, to US$134 million, in the fiscal year ended December 31, 2018, compared to US$95 million in the fiscal year ended December 31, 2017, mainly due to: (i) an increase impairment losses on financial assets, (ii) an increase in taxes paid driven by an expansion of our taxable income base that accompanied the tariff increase, and (iii) increase in fees for third-party services, mainly explained by a higher expenses associated with the distribution of bills. These increases were partially offset by a decrease in costs for salaries and social security taxes.

              Administrative Expenses

The distribution of energy segment’s administrative expenses increased by 15%, to US$76 million, for the fiscal year ended December 31, 2018, compared to US$66 million for the fiscal year ended December 31, 2017, mainly due to an increase in fees for third party services.

             Other Operating Income and Expenses, Net

Other operating income and expenses net recorded a loss of US$35 million for the fiscal year ended December 31, 2018, compared to US$29 million losses during the fiscal year ended December 31, 2017. The increase was mainly due to a growth in provisions for contingencies, mainly due to the existence of new causes and increase in interest rates, and in debit and credit taxes.

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              Operating Income

The operating income from our distribution of energy segment accounted for US$103 million for the fiscal year ended December 31, 2018, representing a 69% increase compared to the US$61 million for the fiscal year ended December 31, 2017.

               Financial Results, Net

Net financial results related to our distribution of energy activities represented a profit of US$62 million for the fiscal year ended December 31, 2018, compared to a profit of US$89 million for the fiscal year ended December 31, 2017, mainly due to: a US$81 million increase in gains on net monetary position, resulting from the application of IAS 29, which were partially offset by higher losses in financial expenses for US$63 million and other financial results for US$51 million mainly on account of commercial interest and net foreign exchange differences.

              Income Tax

Our distribution of energy operations recorded an income tax charge of US$49 million in the fiscal year ended December 31, 2018, compared to a US$12 million charge for the fiscal year ended December 31, 2017, mainly to the improvements in operating results arising from the application of the new tariff schedule in 2018.

              Total Profit

Distribution of energy activities generated a net profit of US$116 million for the fiscal year ended December 31, 2018, of which US$61 million are attributable to the owners of the Company, compared to a net profit of US$138 million, of which US$73 million are attributable to the owners of the Company for the fiscal year ended December 31, 2017.

               Oil and Gas Segment

	Oil and Gas
	12.31.2018	12.31.2017	Variation	%
Revenue	521	462	59	13%
Cost of sales	(287)	(310)	23	(7%)
Gross profit	234	152	82	54%
Selling expenses	(19)	(17)	(2)	12%
Administrative expenses	(56)	(54)	(2)	4%
Exploration expenses	(1)	(2)	1	(50%)
Other operating income and expenses, net	27	72	(45)	(63%)
Share of profit from associates	37	1	36	3,600%
Income from the sale of companies	28	-	28	100%
Operating income	250	152	98	64%
Gain (Loss) on net monetary position	107	(18)	125	(694%)
Finance income	15	6	9	150%
Finance costs	(79)	(78)	(1)	1%
Other financial results	(512)	(93)	(419)	451%
Financial results, net	(469)	(183)	(286)	156%
Loss before income tax	(219)	(31)	(188)	606%
Income tax	57	24	33	138%
Loss for the continuing operations	(162)	(7)	(155)	2,214%
Discontinued operations	49	(35)	84	(240%)
Loss of the year	(113)	(42)	(71)	169%
Owners of the company	(115)	(62)	(53)	85%
Non - controlling interest	2	20	(18)	(90%)

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Revenues

Revenues from continuing operations in our oil and gas segment amounted to US$21 million for the fiscal year ended December 31, 2018, which was 13% higher than US$462 million for the fiscal year ended December 31, 2017. The US$59 million increase was mainly attributable to sales in U.S. Dollars, due to the increase in the exchange rate exceeding inflation in gas and crude oil sales. A slight decrease in gas sales volumes, mainly from the Rincón del Mangrullo block, was partially offset by an increase in El Mangrullo, Río Neuquén and Parva Negra blocks.

The following table shows our production for the oil and gas segment for the periods shown, including the production of discontinued operations:

	Fiscal years ended December 31,
	2018	2017
Oil (m3/d)
Pampa (1)	0.8	1.2
Total	0.8	1.2
Gas (m3/d)
Pampa	6.8	4.2
PEPASA (1)	0.0	2.8
Total	6.8	7.0
Note: All figures have been subject to rounding, so figures shown as totals may not add up. (1) Considering the volume of Medanito La Pampa for the benefit of PEPASA.

              Cost of Sales

The cost of sales from our oil and gas segment from continuing operations decreased by 7%, to US$287 million, for the fiscal year ended December 31, 2018, compared to US$310 million for the fiscal year ended December 31, 2017, mainly due to lower amortizations in 2018 on account of the extension of concessions in Rincón del Mangrullo, in August 2017, and in El Mangrullo, in June 2018, which was partially offset by an increase in royalties.

              Gross Profit

Gross profit from our oil and gas segment increased by US$82 million and recorded a US$234 million profit for the fiscal year ended December 31, 2018, compared to a US$152 million profit for the same period in 2017.

             Selling Expenses

Selling expenses from our oil and gas segment from continuing operations increased to US$19 million for the fiscal year ended December 31, 2018, with no significant variations compared to US$17 recorded during the fiscal year ended December 31, 2017.

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              Administrative Expenses

Administrative expenses from our oil and gas segment from continuing operations amounted to US$56 million for the fiscal year ended December 31, 2018, with no significant variations compared to the fiscal year ended December 31, 2017 US$54 million.

             Exploration Expenses

Exploration expenses from our oil and gas segment from continuing operations decreased by 50%, to US$1 million, during the fiscal year ended December 31, 2018, compared to US$2 million in the fiscal year ended December 31, 2017, mainly due to lower results on account of well write-offs.

              Other Operating Income and Expenses, net

Other operating incomes and expenses net from continuing operations decreased by 63%, to a profit of US$27 million, for the fiscal year ended December 31, 2018, compared to a profit of US$72 million for the fiscal year ended December 31, 2017. This decrease was mainly a result of a decrease in Gas Plan compensations and a higher Ship or Pay charge, which were partially offset by income from the settlement agreement in Ecuador TLC (See Our Oil and Gas Business—Others—Ecuador) and a lower charge resulting from agreements with provincial treasuries regarding royalties, in line with the decrease of the Gas Plan compensations due to the expiration of Gas Plan II as from July 1, 2018.

              Operating Income

The operating income from our oil and gas segment from continuing operations accounted for US$250 million for the fiscal year ended December 31, 2018, representing a 64% increase compared to the US$152 million profit for the fiscal year ended December 31, 2017. This variation includes: (i) a US$35 million profit resulting from interests in OCP, as a result of the settlement agreement entered into with the Republic of Ecuador terminating all claims and legal actions regarding differing interpretations on tax issues in favor of the Ecuadorian Government; and (ii) a US$28 million profit resulting from the sale to ExxonMobil Exploration Argentina S.R.L. of shares representing 21% of Oldelval’s capital stock.

Financial Results, Net

The net financial results from the oil and gas segment from continuing operations accounted for a loss of US$469 million for the fiscal year ended December 31, 2018, compared to a loss of US$183 million for the fiscal year ended December 31, 2017, mainly due to: higher losses in other financial results, in the amount of US$419 million, mainly generated by net foreign exchange differences of financial debt, changes in the fair value of financial instruments and re estimation of receivables with gas distributors, which were partially offset by US$125 million resulting from gain on net monetary position, resulting from the application of IAS 29.

              Income Tax

Our oil and gas segment’s continuing operations recorded an income tax benefit of US$57 million for the fiscal year ended December 31, 2018, compared to a benefit of US$24 million for the same period in 2017, due to the higher income tax gain in 2018 generated by the increase in taxable losses, whereas 2017 fiscal year was positively impacted by the effect of income tax rate reduction on a deferred tax liability position.

               Total Profit (Loss)

Our oil and gas segment’s continuing operations recorded a total loss of US$162 million for the fiscal year ended December 31, 2018, compared to a US$7 million loss for the same period in 2017.

Our oil and gas segment recorded a total profit of US$49 million for discontinued operations in the fiscal year ended December 31, 2018, compared to a US$35 million loss for the same period in 2017, due to the sale in April 2018 of the direct 58.88% interest in PELSA and the direct interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Medanito-Jagüel de los Machos blocks.

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Finally, our oil and gas segment recorded a total loss for continuing and discontinued operations of US$113 million for the fiscal year ended December 31, 2018, of which US$115 million were attributable to the owners of the Company, compared to a total loss of US$42 million recorded for the fiscal year ended December 31, 2017, of which US$62 million were attributable to the owners of the Company.

             Petrochemicals Segment

	Petrochemicals
	12.31.2018	12.31.2017	Variation	%
Revenue	338	314	24	8%
Cost of sales	(334)	(290)	(44)	15%
Gross profit	4	24	(20)	(83%)
Selling expenses	(13)	(12)	(1)	8%
Administrative expenses	(6)	(16)	10	(63%)
Other operating income and expenses, net	(15)	(7)	(8)	114%
Impairment of property, plant and equipment	(32)	-	(32)	(100%)
Operating loss	(62)	(11)	(51)	464%
Gain on net monetary position	49	2	47	2,350%
Finance income	1	-	1	100%
Finance costs	(15)	(10)	(5)	50%
Other financial results	(39)	(6)	(33)	550%
Financial results, net	(4)	(14)	10	(71%)
Loss before income tax	(66)	(25)	(41)	164%
Income tax	12	19	(7)	(37%)
Loss of the year	(54)	(6)	(48)	800%
Owners of the Company	(54)	(6)	(48)	800%
Non - controlling interest	-	-	-	-

             Revenues

Revenues from our petrochemicals segment amounted to US$338 million during fiscal year ended December 31, 2018, 8% higher than US$314 million for the fiscal year ended December 31, 2017. The US$24 million increase was mainly attributable to sales in U.S. Dollars, due to the increase in the exchange rate exceeding inflation and the rise in average U.S. Dollars denominated prices, which was partially offset by a decrease in the Reformer unit’s domestic sales upon the termination of the agreement with Oil Combustibles S.A., lower polystyrene sales and a decrease in rubber domestic sales. The following table shows sales volumes in the petrochemicals segment during the specified periods:

Selling volume in thousands of ton	2018	2017
Styrene & Polystyrene	113	134
SBR	26	33
Others	215	291
Total	355	458
Note: All figures have been subject to rounding, so figures shown as totals may not add up.

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             Cost of Sales

The petrochemicals segment’s cost of sales increased by 15%, to US$334 million, for the fiscal year ended December 31, 2018, compared to US$290 million for the fiscal year ended December 31, 2017, mainly due to higher raw material costs.

Gross Profit

Gross profit from our petrochemical segment decreased by US$20 million and recorded a US$4 million profit for the fiscal year ended December 31, 2018, compared to a US$24 million profit for the same period in 2017.

             Selling Expenses

Selling expenses from the petrochemicals segment amounted to US$13 million for the fiscal year ended December 31, 2018, with no significant variations compared to the US$12 million recorded in the fiscal year ended December 31, 2017.

              Administrative Expenses

Administrative expenses decreased to US$6 million during fiscal year ended December 31, 2018, compared to US$16 million in the fiscal year ended December 31, 2017, mainly due to lower fees for third party services.

              Other Operating Income and Expenses, Net

Other operating income and expenses net recorded a loss of US$15 million for the fiscal year ended December 31, 2018, compared to US$7 million loss during the fiscal year ended December 31, 2017, mainly on account of higher idle capacity charges.

             Operating Income (Loss)

The petrochemicals segment’s operating income (loss) accounted for a loss of US$62 million for the fiscal year ended December 31, 2018, 464% higher than the US$11 million loss for the fiscal year ended December 31, 2017. This variation includes losses resulting from the impairment of property, plant and equipment in the amount of US$32 million as a consequence of the drop evidenced in the segment’s margins resulting from the steady increase in operating costs, mainly impacted by the cost of raw material processed in the Catalytic Reform unit.

              Financial Results, Net

The net financial results from the petrochemicals segment represented a loss of US$4 million during fiscal year ended December 31, 2018, compared to a loss of US$14 million for the fiscal year ended December 31, 2017, mainly due to: a US$47 million gain resulting from net monetary position,resulting from the application of IAS 29, which was partially offset by higher losses in other financial results, in the amount of US$33 million, mostly generated by commercial net foreign exchange differences.

Income Tax

Our petrochemicals activities have recorded an income tax benefit for fiscal years ended December 31, 2018 and 2017 in the amount of US$12 million and US$19 million respectively, due to the fact that 2017 fiscal year was positively impacted by the effect of income tax rate reduction on a deferred tax liability position.

             Total Profit (Loss)

The petrochemicals segment disclosed a net loss of US$54 million for the fiscal year ended December 31, 2018, all of which is attributable to the owners of the Company, compared to a net loss of US$6 million attributable to the owners of the Company for the fiscal year ended December 31, 2017.

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             Holding and Others Segment

	Holding and others
	12.31.2018	12.31.2017	Variation	%
Revenue	36	17	19	112%
Cost of sales	-	(1)	1	100%
Gross profit	36	16	20	125%
Selling expenses	(4)	-	(4)	(100%)
Administrative expenses	(27)	(30)	3	(10%)
Other operating income and expenses, net	9	-	9	100%
Share of profit from joint ventures	92	49	43	88%
Operating income	106	35	71	203%
Gain on net monetary position	12	158	(146)	(92%)
Finance income	14	7	7	100%
Finance costs	(6)	(8)	2	(25%)
Other financial results	108	32	76	238%
Financial results, net	128	189	(61)	(32%)
Profit before income tax	234	224	10	4%
Income tax	(34)	(1)	(33)	3,300%
Loss for the continuing operations	200	223	(23)	(10%)
Discontinued operations	31	(16)	47	(294%)
Profit of the year	231	207	24	12%
Owners of the Company	231	207	24	12%
Non - controlling interest	-	-	-	-

               Revenues

Revenues from our holding and others segment amounted to US$36 million for the fiscal year ended December 31, 2018, 112% higher than US$17 million for the fiscal year ended December 31, 2017. This increase was mainly due to higher fees collected from related parties.

             Cost of Sales

Cost of sales of the holding and others segment amounted US$1 million for the fiscal year ended December 31, 2017. Such costs were immaterial.

              Gross Profit

Gross profit from our holding and others segment increased by US$20 million and recorded a US$36 million profit for the fiscal year ended December 31, 2018, compared to a US$16 million profit for the same period in 2017.

             Selling Expenses

Selling expenses from our holding and others segment during the fiscal years ended December 31, 2018 and 2017 were immaterial.

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              Administrative Expenses

Administrative expenses decreased by 10%, to US$27 million, during the fiscal year ended December 31, 2018, compared to US$30 million for the fiscal year ended December 31, 2017. This decrease was explained by lower compensation agreements, and was partially offset by higher fees for third-party services.

              Other Operating Income and Expenses Net

Other operating income and expenses net recorded a profit of US$9 million for the fiscal year ended December 31, 2018.

             Operating Income

Our holding and others segment’s operating income amounted to US$106 million for the fiscal year ended December 31, 2018, 203% higher than US$35 million for the fiscal year ended December 31, 2017. This variation includes higher profits resulting from the participation in joint ventures in the amount of US$43 million, mainly on account of higher profits resulting from the equity investment in CIESA in the amount of US$49 million, which was partially offset by lower results from the equity investment in CITELEC for US$6 million.

Financial Results, Net

Net financial results from our holding and other activities represented a profit of US$128 million during fiscal year ended December 31, 2018 compared to a US$189 million profit for the fiscal year ended December 31, 2017, mainly due to a US$146 million lower gain on net monetary position, resulting from the application of IAS 29, which was partially offset by higher gain in other financial results in the amount of US$76 mostly generated by net foreign exchange differences.

               Income Tax

Our holding and others segment recorded an income tax charge of US$34 million for the fiscal year ended December 31, 2018, compared to a US$1 million charge for the fiscal year ended December 31, 2017, due to higher taxable income for the 2018 fiscal year.

             Total Profit

Our holding and others segment registered a net profit from continuing operations of US$200 million for the fiscal year ended December 31, 2018 attributable to the owners of the Company, compared to a net profit of US$223 million recorded in the fiscal year ended December 31, 2017, and also attributable to the owners of the Company.

Our holding and others segment recorded a total profit of US$31 million for discontinued operations in the fiscal year ended December 31, 2018, compared to a US$16 million loss for the same period in 2017, due to the sale in May 2018 of the main assets of the refining and distribution segment.

Finally, holding and others segment recorded a total profit for continuing and discontinued operations of US$231 million for the fiscal year ended December 31, 2018, compared to US$207 million recorded for the fiscal year ended December 31, 2017, all of which were 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:

·Design a capital structure consistent with industry standards adaptable to the financial markets in which we operate;

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·Maintain a liquidity level—invested in financial assets with high credit quality—that allows us to meet our obligations;

·Maintain a debt maturity profile consistent with projected cash generation; and

·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.

Total consolidated borrowings as of December 31, 2019, 2018 and 2017 were US$1,947 million, US$2,177 million, and US$1,683 million, respectively. As of December 31, 2019, 2018 and 2017, 92%, 93% and 85% of our borrowings were denominated in U.S. Dollars, respectively.

As of December 31, 2019, 2018 and 2017, cash and cash equivalents were US$225 million, US$241 million and US$31 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,
	2019	2018	2017
	(in million of US$(1))
Cash at the beginning of the year	241	31	69
Net cash generated by operating activities	802	610	439
Net cash (used in) generated by investing activities	(369)	19	(846)
Net cash (used in) generated by financing activities	(390)	(470)	372
Exchange difference generated by cash and cash equivalents	(59)	53	14
Loss on net monetary position generated by cash and cash equivalents	-	(8)	(11)
Cash and cash equivalent classified as held for sale	-	6	(6)
Cash and cash equivalent at the end of the year	225	241	31

⁽¹⁾ Peso amounts as of December 31, 2018 and 2017 have been translated into US$ at the seller exchange rate for U.S. Dollars quoted by Banco Nación on December 31, 2018 of Ps.37.70 to US$1.00. See “Item 3. Key Information—Exchange Rates.”

Net cash generated by operating activities

Net cash generated by operating activities amounted to US$802 million for the year ended December 31, 2019, attributable to cash flow generated by net income without considering (i) non-cash losses (mainly related to US$267 million for depreciation and amortization of assets, US$202 million for interest accrual, and US$75 million for net foreign currency exchange difference), and (ii) non-cash profits (mainly related to US$285 million in relation with the Agreement on the Regularization of Obligations entered into by Edenor, US$187 million for gains on net monetary position, and US$101 million for share of profit from joint ventures and associates), but considering (iii) changes in operating assets and liabilities (mainly related to US$97 million increase in trade and other payables and US$20 million increase in tax payables); and (iv) US$87 million in income tax payments.

Net cash generated by operating activities amounted to US$610 million for the year ended December 31, 2018, attributable to cash flow generated by net income from continuing and discontinued operations without considering (i) non-cash losses (mainly related to US$863 million for net foreign currency exchange difference, US$234 million for depreciation and amortization of assets, and US$219 million for interest accrual), and (ii) non-cash profits (mainly related to US$629 million for gains on net monetary position and US$118 million for share of profit from joint ventures and associates), but considering (iii) changes in operating assets and liabilities (mainly related to US$172 million increase in trade and other receivables and US$60 million decrease in provisions, partially offset by US$35 million increase in tax payables); (iv) US$46 million cash flow used in discontinued operations; and (v) US$49 million in income tax payments.

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Net cash generated by operating activities amounted to US$439 million for the year ended December 31, 2017, attributable to cash flow generated by net income from continuing and discontinued operations without considering (i) non-cash losses (mainly related to US$205 million for depreciation and amortization of assets, US$156 million for net foreign currency exchange difference and US$166 million for interest accrual), and (ii) non-cash profits (mainly related to US$304 million for gains on net monetary position and US$62 million for changes in the fair value of financial instruments), but considering (iii) changes in operating assets and liabilities (mainly related to US$65 million increase in trade and other receivables, US$48 million decrease in provisions); (iv) US$87million cash flow generated by discontinued operations and (v) US$56 million in income tax payments.

Net cash generated by or used in investing activities

Net cash used in investing activities amounted to US$369 million for the year ended December 31, 2019, including payments of US$582 million for purchases of property, plant and equipment and US$108 million for capital integration in associates and joint ventures, partially offset by US$217 million proceeds from financial assets and US$87 million in proceeds from received dividends.

Net cash generated by investing activities amounted to US$19 million for the year ended December 31, 2018, including US$457 million in proceeds from sales of shares in companies and property, plant and equipment and US$250 million from the recovery of investment funds, net, partially offset by uses of cash including US$674 million in purchases of property, plant and equipment.

Net cash used in investing activities amounted to US$846 million for the year ended December 31, 2017, principally due to payments of US$485 million in purchases of property, plant and equipment, US$109 million for financial assets and US$219 million for the subscription of investments funds.

Net cash used in or generated by financing activities

Net cash used in our financing activities amounted to US$390 million for the year ended December 31, 2019, principally due to payments of US$698 million made in connection with bank and financial borrowings (including principal and interest), US$151 million related to acquisition of our own shares and US$91 million related to repurchase and redemption of corporate bonds, partially offset by US$556 million proceeds from borrowings.

Net cash used in our financing activities amounted to US$470 million for the year ended December 31, 2018, principally due to payments of US$373 million made in connection with bank and financial borrowings (including principal and interest) and US$369 million related to acquisitions of our own shares, partially offset by US$245 million proceeds from borrowings.

Net cash generated by our financing activities amounted to US$372 million for the year ended December 31, 2017, principally due to US$1,250 million proceeds from borrowings, partially offset by payments of US$841 million made in connection with bank and financial borrowings (including principal and interest).

Capital Expenditures

The following table sets forth our capital expenditures for the years ended December 31, 2019, 2018 and 2017:

	At December 31,
	2019	2018	2017
	(in millions of US$(1))
Generation	240	235	275
Distribution of energy	173	227	225
Oil and gas	191	192	140
Petrochemical	4	4	5
Holding and others	3	7	12
	611	665	657
(1) Peso amounts as of December 31, 2018 and 2017 have been translated into U.S. Dollars at the seller exchange rate for US$ quoted by Banco Nación on December 31, 2018 of Ps.37.70 to US$1.00. See “Item 3. Key Information—Exchange Rates.”

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In 2019, our capital expenditures in our generation segment amounted to US$240 million mostly related to work in progress (US$217 million) in order to increase thermal generation capacity mainly through the closing of Genelba’s combined cycle project and the completion of wind farm projects.

In our distribution of energy segment, we invested US$173 million in 2019, mainly related to work in progress (US$139 million) and substations, high, medium and low voltage lines, meters, transforming chamber and platforms (US$9 million). A substantial portion was dedicated to increasing the capacity of our grid in line with the growth of our customer base. In addition, we made investments in order to meet our quality standards levels. Edenor complied with the investment plan for a five-year period agreed upon with the ENRE in the context of the RTI process.

Our capital expenditures in our oil and gas segment amounted to US$191 million in 2019, mostly related to work in progress (US$148 million) in order to develop gas reserves and exploratory wells (US$24 million).

In 2018, our capital expenditures in our generation segment amounted to US$235 million mostly related to work in progress (US$222 million) in order to increase thermal generation capacity mainly through the installation of a new turbine and the development of wind power projects.

In our distribution of energy segment, we invested US$227 million in 2018, mainly related to work in progress (US$195 million) and substations and high, medium and low voltage lines (US$13 million). A substantial portion was dedicated to increasing the capacity of our grid in line with the growth of our customer base. In addition, we made investments in order to meet our quality standards levels. Edenor complied with the investment plan for a five-year period agreed upon with the ENRE that had been submitted in the context of the RTI process.

Our capital expenditures in our oil and gas segment amounted to US$192 million in 2018, mostly related to work in progress (US$163 million), wells (US$1 million) and mining property (US$26 million) in order to develop gas reserves mainly through well drilling.

In 2017, our capital expenditures in our generation segment amounted to US$275 million mostly related to work in progress (US$222 million) and advances to suppliers (US$43 million) in order to increase thermal generation capacity mainly through the construction of new thermal generation plants.

In our distribution of energy segment, we invested US$225 million in 2017, mainly related to work in progress (US$205 million). A substantial portion was dedicated to increasing the capacity of our grid in line with the growth of our customer base. In addition, we made investments in order to meet our quality standards levels.

Our capital expenditures in our oil and gas segment amounted to US$140 million in 2017, mostly related to work in progress (US$107 million), wells (US$13 million) and mining property (US$10 million) in order to develop gas reserves mainly through well drilling.

              Future Capital Requirements

We estimate that our capital expenditure requirements, debt payment obligations, dividend payments and working capital will be financed with cash from operations, new debt financings, capital contributions and possible divestments.

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.

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In our generation segment, future capital expenditures will mainly focus on the completion of expansion of thermal generation capacity projects through the execution of the closing to combined cycle at Genelba and CTEB power plants.  

In turn, in our distribution of energy segment, future capital expenditures will focus on maintaining quality of service and safety and environmental requirements.

Finally, in our oil and gas segment, future capital expenditures will focus on developing unconventional gas reserves (shale and tight gas) through well drilling, as well as, exploration studies aimed at making new discoveries at unconventional gas reservoirs.

For further information on our investment commitments in oil and gas areas and our generation projects, please see Note 16 to our Consolidated Financial Statements.

Description of Indebtedness

Our total consolidated financial indebtedness as of December 31, 2019 was US$1,947 million, of which 91% was long-term debt, 92% of which was denominated in U.S. Dollars. The amount of our total consolidated financial debt does not include Transener, TGS, Greenwind 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:

	2019	2018	2017
	(in millions of US$)
Short-Term Debt(1)
Bonds	32	25	29
Financial	137	313	200
Related parties	14	1	-
	183	339	229
Long-Term Debt(1)
Bonds(2)	1,603	1,457	1,087
Financial	161	258	233
Total	1,764	1,715	1,320
Total Indebtedness	1,947	2,054	1,549

⁽¹⁾ 2018 and 2017 figures exclude indebtedness with CAMMESA, settled in 2019.

⁽²⁾ Net of repurchase of Corporate Bonds of Pampa for a nominal value of US$81 million and US$9 million, and the repurchase of Edenor’s Corporate Bonds for a nominal value of US$29 million and US$10 million, as of December 31, 2019 and 2018, respectively.

Financings

In 2019, we had short term debt maturities for approximately US$282 million. During 2019, particularly after the issuance of the Series III notes, the Company cancelled at maturity and pre-cancelled short term financings with banks and additionally pre-cancelled and repurchased its own bonds in the market, improving its short term debt profile while keeping a solid cash position. As of December 31, 2019, our short-term maturities amounted to US$101 million.

Additionally, after the end of the 2019 fiscal year, we paid, at maturity, financings in a total amount of US$25 million and prepaid short-term financings for a total amount of US$40 million.

Additionally, during April 2020, we obtained new financings denominated in Argentine Pesos in the amount of Ps. 1,500 million with a one-year maturity, Ps.3,000 million with a 90 days maturity and repurchase agreements in the amount of Ps. 950 million with a maturity of up to 30 days. Likewise, we prepaid short-term financings for a total amount of Ps. 2,938 million.

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The following table describes our debt maturity profile for the periods indicated, including principal amount plus the corresponding accrued interest as of December 31, 2019:

	< 1 year	1-5 years	> 5 years	Total
	(in millions of US$)
Total Indebtedness	183	784	980	1,947

Corporate Bonds

On July 2, 2019, Pampa issued the Series III notes for a total amount of US$300 million. Series III notes accrue interest at a fixed rate of 9.125% and are due at a single installment upon its maturity in April 2029.

Additionally, on July 12, 2019 we pre-cancelled 100% of the principal of the Series IV notes for US$33.9 million.

On April 30, 2020, we issued (i) Series IV notes for a total amount of Ps.1,238 million and (ii) Series V notes for a total amount of Ps.565 million. Series IV notes accrue interest at a floating rate based on a Private Badlar plus an applicable margin of 3.00% and are due at a single installment upon its maturity in July 29, 2020. Series V notes accrue interest at a floating rate based on Private Badlar plus an applicable margin of 5.00% and are due at a single installment upon its maturity in October 27, 2020.

Credit Ratings

In July 2019 the agency Moody’s amended the outlook on the ratings assigned to the CBs issued by Pampa Group from stable to negative, mainly reflecting the negative outlook on the sovereign rating, but maintaining the ratings unchanged. As a result of the downgrade of the Argentine sovereign debt in early September 2019, the ratings assigned to Pampa Group’s CBs were downgraded, with negative to under review for downgrade outlook. Pampa’s global rating was downgraded from “B2” to “Caa1”, whereas Edenor and TGS’s were downgraded from “1” to “Caa”. Edenor and TGS’s local ratings were downgraded from “Aa3.ar” and “Aa2.ar”, respectively, to “Baa3.ar”.

Between August and September 2019 and for the same reasons as Moody’s, the agency S&P downgraded the assigned ratings from a stable to a negative outlook. The global ratings of Pampa, Edenor, TGS and Transener were downgraded from “B” to “B-”. Edenor’s local rating was downgraded from “raA” to “raBBB”, whereas Transeners was downgraded from “raAA-” to “raBBB+”. Furthermore, in January 2020, after the enactment of the Solidarity Law, S&P downgraded the global rating granted to Edenor’s CBs from “B-” to “CCC+”, and local rating from “raBBB” to “raBB-”, keeping the negative outlook.

Between August and September 2019, the agency FitchRatings downgraded the global rating assigned to the CBs issued by Pampa from “B” with a stable outlook to “CCC+” with a negative outlook and kept its local rating at “AA-” with a stable outlook.

Furthermore, in April 2020, due to regulatory changes in the domestic power industry, S&P Global Ratings resolved to review the stand alone rating of the Company from “B+” to “B”.

Repurchase of debt securities

Since mid-August 2019 and as of the date of this annual report, Pampa has acquired and held in treasury: (i) US$13.5 million of face value (“FV”) of its Corporate Bonds (“CBs”) maturing in 2023 (“2023 CBs”), acquired at an average clean price of US$74.5 per US$100 FV; (ii) US$53.2 million FV of its CBs maturing in 2027 (“2027 CBs”), acquired at an average clean price of US$73.2 per US$100 FV which, in addition to those already held in treasury by the Company, amount to a total US$63.0 million FV of its 2027 CBs; and (iii) US$7.3 million FV of its CBs maturing in 2029 (“2029 CBs”), acquired at an average clean price of US$78.6 per US$100 FV.

In addition, in September 2019, we acquired Edenor’s CBs for US$19 million FV at a clean price of US$66.4 per US$100 FV.

Furthermore, during October 2019, we acquired a total of 1.1 million of Edenor’s ADRs at an average cost of US$5.0 per ADR. As a result, our equity interest amounts to 54.3% of Edenor’s issued capital stock.

Finally, in 2019 Edenor repurchased a total of US$29.1 million FV of its 2022 CBs at an average clean price of US$73.7 per US$100 FV.

During March 2020, we acquired: (i) US$41,222,000 FV of our own 2023 CBs at an average clean price of US$72.34 per US$100 FV; and (ii) US$19,715,000 FV of our own 2027 CBs) at an average clean price of US$70.11 per US$100 FV.

During April 2020, we acquired: (i) US$10,500,000 FV of our own 2023 CBs at an average clean price of US$65.77 per US$100 FV; (ii) US$8,481,000 FV of our own 2027 CBs) at an average clean price of US$62.13 per US$100 FV; and (iii) US$150,000 FV of our own 2029 CBs) at an average clean price of US$59.00 per US$100 FV.

 As of the date of this Annual Report, we acquired a total of: (i) US$65,212,000 FV of our 2023 CBs at an average clean price of US$71.74 per US$100 FV; (ii) US$91,222,000 FV of our own 2027 CBs at an average clean price of US$72.24 per US$100 FV; and (iii) US$7,475,000 FV of our own 2029 CBs at an average clean price of US$78.23 per US$100 FV. The total amount invested in repurchase of CBs adds up to US$106,268,493, without considering accrued interest.

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, 2019, we and our subsidiaries were in compliance with the covenants under our respective outstanding indebtedness.

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Contractual obligations

In the tables below, we set forth certain contractual obligations as of December 31, 2019 and the period in which the contractual obligations become due. Peso amounts have been translated to U.S. Dollars at the seller rate for U.S. Dollars quoted by Banco Nación on December 31, 2019 of Ps. 59.89 to U$$1.00. 

		Payments due by period
	Total	Less than 1 year	1 - 3 years	3 - 5 years	More than 5 years	Until
	(in million of US$)
Payments Obligations
Debt obligations (1)	2,638	283	288	834	1,233
Capital Expenditures (2)	1,029	352	358	101	218
Royalty payments (3)	24	8	6	5	5
	3,691	643	652	940	1,456
Purchase Obligations
Natural gas purchase agreements for electricity generation (4)	9	4	5	-	-	2022
Natural gas transportation agreement (5)	415	15	26	26	349	2053
Steam (6)	48	4	7	7	29	2032
Long-term services agreement (7)	65	51	10	1	3	2031
Petroleum services and materials (8)	174	123	51	0	-	2022
	710	196	99	34	380
Other
Accrued fines and penalties (9)	122	45	77	-	-
Total	4,523	885	828	974	1,836
Sales Obligations (10)
Electricity Power	1,558	345	484	272	457	2038
Natural gas	21	21	-	-	-	2020
CNG	2	2	-	-	-	2020
LPG	23	8	15	-	-	2022
Oil	17	17	-	-	-	2020
Total	1,620	392	499	272	457

(1)	Includes amortization of principal and accrued and future interest payments. Estimated variable interest rates in Pesos were based on Private BADLAR and Corrected BADLAR rates plus an applicable margin, and estimated variable interest rates denominated in U.S. Dollars were based on the Libor rate plus an applicable margin. See “Item 5.- Description of Indebtedness” for a broader description of our financial debt.
(2)	Includes executed contractual obligations relating to major maintenance and new projects in our generation segment, as well as investment commitments in oil and gas areas (a further description of our investment commitments in oil and gas areas and our generation projects is disclosed in Note 16 to our Consolidated Financial Statements). Edenor’s concessions do not require mandatory capital expenditures.
(3)	Based on royalty estimated payments included in our annual budget; royalty payments beyond 2019 are calculated based on average hydraulicity.
(4)	Natural gas supply agreements based on the estimated average price of US$0.11 per m3.
(5)	Firm natural gas transportation agreements based on the estimated average price of US$0.01 per m3.
(6)	We have entered into steam purchase agreement with TGS (for the supply of the Ecoenergia power plant).
(7)	Long-term services agreements in the ordinary course of business (for the supply of maintenance and repair of plants, transportation between facilities and technical support).
(8)	Long-term services and materials agreements with oil and gas providers (for the supply of services such as pulling, work-over, perforation works and the provision of materials).
(9)	See “Item 4. Our Distribution of Energy Business—Empresa Distribuidora y Comercializadora Norte (Edenor)—Fines and penalties.”
(10)	Sales obligation agreements correspond to sale commitments in order to ensure the sale of different products. Prices are generally determined by formulas based on future market prices. Estimated prices used to calculate the monetary equivalent of these sales obligations for purposes of the table are based on current market prices as of December 31, 2019 and may not reflect actual future prices. Accordingly, the Peso amounts provided in this table with respect to these obligations are provided for illustrative purposes only.

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Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements required to be disclosed under Item 5.E. of Form 20-F.

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. Four of our ten directors are independent according to the criteria and requirements for independent directors under applicable Argentine law. One of our alternate directors is 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 business person. 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.

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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.

Board of Directors

The following table sets forth information about the members and alternate members of our board of directors, five of whom have terms that expired in December 2019, while six have terms that will expire in December 2020 and the remaining eight have terms that will expire in December 2021. 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	56	Chairman	04/27/2018	12/31/2020
Gustavo Mariani	49	Vice Chairman	04/07/2017	12/31/2019
Ricardo Alejandro Torres	62	Director	04/07/2017	12/31/2019
Damián Miguel Mindlin	54	Director	04/27/2018	12/31/2020
Gabriel Cohen	55	Director	04/29/2019	12/31/2021
Carlos Correa Urquiza(1) (2)	50	Director	04/29/2019	12/31/2021
Santiago Alberdi(1) (2) (3)	37	Director	04/29/2019	12/31/2021
Dario Epstein(1) (2)	56	Director	04/29/2019	12/31/2021
María Carolina Sigwald	52	Director	04/29/2019	12/31/2020
Miguel Ricardo Bein(1) (2)	69	Director	04/07/2017	12/31/2019
Pablo Alejandro Diaz	62	Alternate Director	04/29/2019	12/31/2021
Nicolás Mindlin	30	Alternate Director	04/29/2019	12/31/2021
Gerardo Carlos Paz	51	Alternate Director	04/29/2019	12/31/2020
Silvana Wasersztrom(1) (2)	52	Alternate Director	04/29/2019	12/31/2021
Brian Robert Henderson	74	Alternate Director	04/29/2019	12/31/2020
Mariano Batistella	37	Alternate Director	04/29/2019	12/31/2021
Victoria Hitce	43	Alternate Director	04/07/2017	12/31/2019
Mauricio Penta	43	Alternate Director	04/27/2018	12/31/2020
Horacio Jorge Tomás Turri	59	Alternate Director	04/29/2019	12/31/2019

(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.

(3)On April 13, 2020, the Board of Directors approved the resignation presented by Santiago Alberdi to his position as Director of the Company. The resignation obeys to personal reasons and will be effective as from the designation of its replacement by the Shareholders Meeting convened for May 11^th, 2020.

Marcos Marcelo Mindlin and Damián Miguel Mindlin are brothers, Marcos Marcelo Mindlin and Nicolás Mindlin are father and son and, therefore, Damián Miguel Mindlin and Nicolás Mindlin are uncle and nephew. 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
Miguel Bein	President
Gustavo Mariani	Regular Member
Ricardo Torres	Regular Member
Victoria Hitce	Alternate Member
Silvina Wasersztrom	Alternate Member

Senior Management

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

Name	Position	Age
Marcos Marcelo Mindlin	Chairman	56
Gustavo Mariani	Executive Vice president - Chief Executive Officer	49
Ricardo Alejandro Torres	Executive Vice president	62
Damián Miguel Mindlin	Executive Vice president	54
Horacio Jorge Tomás Turri	Executive Director of Oil & Gas	59
Gabriel Cohen	Chief Financial Officer	55
María Carolina Sigwald	Executive Director of Legal Affairs	52
Mariano Batistella	Executive Director of Planning, Strategy, Downstream and Affiliates	37

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. He is a member of the Council of the Americas. 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. 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. 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. Mr. Mindlin is currently Chairman of the Foundation, Grupo Dolphin Holding S.A., Grupo Emes S.A. and Emes Inversora S.A. Mr. Mindlin also serves as director of Orígenes Seguros de Retiro S.A., Orígenes Seguros de Vida S.A., Consultores Fund Management and Mindlin Warrants S.A.

Gustavo Mariani was born on September 9, 1970. Mr. Mariani holds a degree in Economics from the Universidad de Belgrano and a Master’s degree in Business Administration from the Universidad del CEMA (Center of Macroeconomic Studies) and also is a Chartered Financial Analyst (CFA) since 1998. He has been a member of our board of directors since November 2005 and serves as Vice-Chairman and CEO. 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, PACOSA, CIESA, TGS and Transelec. He is also Vice Chairman of SACDE and Edenor. He also serves as Director of GMA Warrants S.A.,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., PP, CPB, Sitios Argentinos S.A and Pampa Cogeneración. In addition, Mr. Mariani is a member of the management board of the Foundation.

Ricardo Alejandro Torres was born on March 26, 1958. 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. He has been a member of our board of directors since November 2005 and serves as Executive Vice president. Mr. Torres was a professor of Tax and Finance at the school of Economics of the Universidad de Buenos Aires. He currently serves as Chairman of Edenor, CPB, PISA, RT Warrants S.A., Pop Argentina S.R.L. (Partner), Todos Capital S.R.L. (Partner), Orígenes Seguros de Vida S.A., Orígenes Seguro de Retiro S.A. and Pampa Cogeneración. Mr. Torres is also member of the board of directors of HIDISA, HINISA, PACOSA, PP and Transelec; and alternate director of CITELEC. Also, Mr. Torres is Vice Chairman the Foundation.

Damián Miguel Mindlin was born on January 3, 1966. He has been a member of our board of directors since November 2005. 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 PP, 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. Also, Mr. Mindlin is the Vice Chairman of HIDISA, HINISA, PISA, Pampa Cogeneración, 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 directors of Transelec, CPB, PACOSA, Pampa F&F, DMM Warrants S.A., Orígenes Seguros de Vida S.A., Orígenes Seguros de Retiro S.A., Consultores Fund Management Ltd and Emes Air S.A.; and alternate director of ByMA, Transba and CITELEC. Mr. Mindlin is currently the treasurer of the management board of the Foundation.

Gabriel Cohen was born on September 11, 1964. Mr. Cohen has been a director of Pampa since June 2006 and is currently the CFO of the Company. Mr. Cohen holds a degree in Business Administration from the Universidad de Buenos Aires. In addition, he worked for 15 years at Citibank, N.A., serving at the banks offices in Buenos Aires and Paris, holding different positions in financial control, treasury, investment banking, corporate banking and debt restructuring processes. Mr. Cohen currently serves as Chairman of Enecor and as Vice-Chairman of CITELEC and CPB. He is a member of the board of directors of Transener and Transba; and alternate director of HIDISA, HINISA, PACOSA, PP and Transelec.

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María Carolina Sigwald was born on November 15, 1967. She is the Executive Director of Legal Affairs of the Company since November 2017. Ms. Sigwald obtained her law degree from the University of 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 Energia among them. Likewise, she took office in Transportadora de Gas del Sur’s and Telefónica de Argentina’s board of directors. She is currently the Chairman of Greenwind and a member of the board of directors of Edenor, CTB and PHA, and an alternate member of the board of directors of Plásticos de Zárate, Pampa Cogeneración, Transba and CITELEC.

Carlos Correa Urquiza was born on September 17, 1969. On April 29, 2019, he joined the Company as a member of the board of directors. 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’s degree in Banking Management from Universidad del Cema and a Bachelor’s Degree in Business Administration from Universidad de Belgrano.

Santiago Alberdi was born on April 6, 1983. On April 29, 2016, he joined the Company as a member of the board of directors. Mr. Alberdi is also a member of the supervisory committee at the “Lotería de la Ciudad Autónoma de Buenos Aires (LOTBA)”. Mr. Alberdi holds a law degree from the UBA.

Miguel Ricardo Bein was born on October 28, 1950. Mr. Bein has been a director of our company since April 2017. He is currently an economic and financial consultant at Bein & Asociados, a consultant firm founded in 2001. Previously, he was Secretary of State at the Secretariat of Economic and Regional Programming of the Ministry of Economy, Works and Public Services during the period from 2000-2001. He was also Undersecretary of State in the Under Secretariat of Small and Medium Enterprise, Ministry of Industry and Foreign Trade. Mr. Bein holds a degree in Economics from the UBA. In 1993, he obtained a degree from the International Senior Management Program Harvard Business School in Boston, USA.

Dario Epstein was born on July 19, 1963. On April 29, 2019, he joined the Company as a member of the board of directors. 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 a director of CNV.

Pablo Díaz was born on June 26, 1957. Mr. Díaz has been an alternate director of our company since June 2006. Previously, he was an advisor to the federal Subsecretaría de Energía Eléctrica (the Sub-Secretariat for Electrical Energy). He currently serves as director of Citelec and Transba and as an alternate member of the board of directors of CPB, Transener, Edenor, HIDISA, HINISA, PACOSA, PP, Transelec, and Transener. He is the Executive Secretary of the Foundation.

Nicolás Mindlin was born on November 11, 1989. Mr. Mindlin has been a member of the Board of directors of Pampa since April 2017. Mr. Mindlin holds an Industrial Engineer degree from the Technological Institute of Buenos Aires. Mr. Mindlin is also Chairman of PEB, Vicechairman of PHA, Plásticos de Zárate, Trenerec Energía Bolivia S.A., member of the board of directors of Petrobras Energía Ecuador Ltd. and alternate member of CIESA, Enecor and TGS.

Gerardo Carlos Paz was born on October 24, 1968. Mr Paz obtained a law degree from Universidad Nacional de Córdoba. He has worked at several places such as ENRE from 1994 to 2000, Camuzzi Gas Pampeana from 2001 to 2007 and Pampa Energía S.A. since 2007. Mr. Paz holds a Master’s degree in business law. Mr. Paz serves as Vice Chairman of PACOSA and Transelec. He is also director of HIDISA, TJSM and TMB and alternate director of CPB, CIESA, CITELEC, HINISA, Plásticos de Zárate and Transba. Mr. Paz is also a member of the supervisory committee of CAMMESA.

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Silvana Wasersztromwas born on March 18, 1968. Ms. Wastersztrom is a partner of Moncayo & Wasersztrom Abogados since 2012. She also worked in Marval, O’Farrell & Mairal law firm as a lawyer during the years 1994 - 2002. She did an internship at a law firm placed in Tampa, Florida and holds two master degrees in Tax and Customs Law in Universidad Austral and Universidad de Belgrano. 

Brian Henderson was born on September 23, 1945. Mr. Henderson is a Senior Advisor to the board of Pampa Energia S.A. Previously, Mr. Henderson served as director of the Latin America Region of National Grid, Silica Networks and Manquehue Net Telecomunicaciones (Chile) and vice-Chairman of commercial operations of Energy Charter Oak for America, Africa and Europe. Before Charter Oak Energy, Mr. Henderson served as vice-Chairman and CEO of Deutsche Babcock Riley, Canada Inc. Mr. Henderson is Chairman of Transener and Vice-Chairman of Enecor and Transba. He is also director of Citelec and alternate director of HINISA, HIDISA and Transelec. He holds a degree in Industrial Engineering from the Hebum University.

Mariano Batistella was born on July 31, 1982. He has been an alternate director of the Company since 2013. He currently is the Executive Director of Planning, Strategy and affiliates of the Company. Mr. Batistella holds a degree in business administration from the Universidad de San Andres and has a master degree in finance from the same institution and worked in investment banking at Goldman Sachs. He currently serves as Chairman of PHA, Trenerec Energía Bolivia S.A., Plásticos de Zárate and General Manager of Ecuador TLC and ENOPSA. Mr. Batistella also serves as Vice-Chairman of PP and member of the board of directors of Transporte de Servicios y Gas en Uruguay, CIESA, HINISA, Pampa Cogeneración, Petrobras Energía Ecuador Ltd and TGS; and alternate director of Edenor, Enecor, HIDISA, PACOSA and Transelec.

Victoria Hitce was born on April 9, 1977. Ms. Hitce has been a member of the Board of Directors of Pampa since April 2017. Also, she was a founding partner of the Salaverri, Burgio & Wetzler Malbrán law firm. Currently, she is the Corporate and M&A Director of the Company. She is a lawyer graduated from the Universidad Católica Argentina. Ms. Hitce serves as director of Transba, CIESA and CITELEC and as alternate director of PHA, Pampa Cogeneración, CTB, Transporte de Servicios y Gas en Uruguay, PEB, Plásticos de Zárate, HIDISA, HINISA and Transener and alternate member of the supervisory committee of Refinor.

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 is also an alternate member of the board of directors of TGS.

Mauricio Penta was born on July 23, 1976. He is the Director of Administration and Systems 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 director of CTB and as alternate director of PHA.

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, Pablo Alejandro Diaz, Nicolás Mindlin, Gabriel Cohen, María Carolina Sigwald, Mariano Batistella, Brian Robert Henderson, Mauricio Penta, Victoria Hitce, Horacio Jorge Tomás Turri and Gerardo Carlos Paz.

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: Miguel Bein, Santiago Alberdi, Carlos Correa Urquiza, Darío Epstein and Silvana Wasersztrom.

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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 to the aforementioned 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 one alternate member.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
Miguel Bein	President	69
Carlos Correa Urquiza	Regular Member	50
Darío Epstein	Regular Member	56
Silvana Wasersztrom	Alternate Member	52

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 will have 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;

· 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;

· 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;

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

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

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

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

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

Independence Criteria

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

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

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

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

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

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.

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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
José Daniel Abelovich	Chairman	63
Martín Fernandez Dussaut	Member	39
Germán Wetzler Malbrán	Member	50
Marcelo Héctor Fuxman	Alternate Member	64
Tomás Arnaude	Alternate Member	38
Damián Burgio	Alternate Member	56

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

José Daniel Abelovich was born on July 20, 1956. He has been a member of our supervisory committee since 2007. Mr. Abelovich holds a degree in Public Accounting from the Universidad de Buenos Aires. Mr. Abelovich is a partner of Abelovich, Polano & Asociados/NEXIA INTERNATIONAL, an auditing firm. Mr. Abelovich also serves as member of the following supervisory committees, among others: Arcos del Gourmet S.A., AdCap Securities Argentina S.A., Banco de Crédito y Securitización S.A., Banco Hipotecario S.A., BH Valores S.A. de Sociedad de Bolsa, BHN Seguros Generales S.A., BHN Sociedad de Inversión S.A., BHN Vida S.A., TGS, CIESA, Transener, Citelec, Convexity Sociedad Gerente de Fondos Comunes de Inversión S.A., Cresud SACIF, CT Mitre Office S.A, Cyrsa S.A., E-Commerce Latina S.A., Emprendimiento Recoleta S.A., HIDISA, Transba, Edenor, Hoteles Argentinos S.A., Inversora Bolívar S.A., IRSA Inversiones y Representaciones S.A., Palermo Invest S.A., PACOSA, Panamerican Mall S.A., Shopping Neuquén S.A., Llao – Llao Resorts S.A., Nuevas Fronteras S.A., Orígenes Seguros de Retiro S.A., Orígenes Seguros S.A., Solares de Santa María S.A., Tarshop S.A. y Unicity S.A.

Germán Wetzler Malbrán was born on April 25, 1970 and obtained a law degree from the Universidad Católica Argentina. He is a founding partner of Salaverri, Burgio & Wetzler Malbrán Law Firm, and member of the following supervisory committees, among others: of PP, Greenwind, SACDE, Edenor, Pampa Cogeneración, PACOSA, Plásticos de Zárate, CTB, Creaurban S.A., Fidus S.G.R., Compañía Americana de Transmisión Eléctrica S.A., Los Yaros Agropecuaria S.A., GG Negocios Fiduciarios S.A., Lubricantes Avellaneda S.A.U., ODS S.A. and Agropecuaria La Volanta S.A. Additionally, Mr. Wetzler Malbrán serves as an alternate member of supervisory committee of Grupo Dolphin Holding S.A., Orígenes Seguros de Retiro S.A., Orígenes Seguros S.A., Grupo ST S.A., Salta Refrescos S.A., PEFM and Envases Plásticos S.A. and alternate director of Escrow Services S.A.

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 GG Negocios Fiduciarios S.A., AR Partners S.A., CT Mitre Office S.A. and Escrow Services S.A. Also, he is a member of the supervisory committee of ODS S.A., Greenwind, PP, CTB, SACDE, Creaurban S.A., Fidus S.G.R., Compañía Americana de Transmisión Eléctrica S.A. PEFM, and Lubricantes Avellaneda S.A.U. He is also alternate member of the supervisory committee of Grupo Dolphin Holding S.A., Pampa Cogeneración, Edenor and Enecor.

                Marcelo Héctor Fuxman was born on November 30, 1955. He has been a member of our supervisory committee since June 2006. Mr. Fuxman holds a degree in Accounting from the Universidad de Buenos Aires. Mr. Fuxman is a partner of Abelovich, Polano & Asociados/NEXIA INTERNATIONAL, an auditing firm, and managing partner of Real Estate Investments S.R.L. He currently serves as alternate director of Agra Argentina S.A. and member of the supervisory committee of Abus las Americas I S.A., Abus Securities S.A., Advanced Capital Securities S.A., Agro Managers S.A., Agro Investment S.A., Amauta Agro S.A., Arcos del Gourmet S.A., Austral Gold Argentina S.A., Baicom Networks S.A., Banco de Crédito y Securitización S.A., Banco Hipotecario S.A., BH Valores S.A. de Sociedad de Bolsa, BHN Seguros Generales S.A., BHN Sociedad de Inversión S.A., BHN Vida S.A., Bitania 26 S.A., Boulevard Norte S.A., Carnes Pampeanas S.A., Cincovial S.A., CATESA, TGS, Transener, Citelec, Convexity Sociedad Gerente de Fondos Comunes de Inversión S.A., Corpus Energía S.A., Creaurban S.A., Cresud SACIF, Cyrsa S.A., CT Mitre Office S.A., E-Commerce Latina S.A., Emprendimiento Recoleta S.A., Emprendimientos del Puerto S.A., Transba, Edenor, Fibesa S.A., Fidus S.G.R., Focolare S.A., Futuros y Opciones.com S.A., Granos Olavarría S.A., HIDISA, Hoteles Argentinos S.A., SACDE, Inversora Bolívar S.A., IRSA Inversiones y Representaciones S.A., IRSA Propiedades Comerciales S.A., La Clara de Banderaló S.A., La Pionera de Anta S.A., Líneas del Norte S.A., Líneas del Comahue de Cuyo S.A., Líneas Mesopotámicas S.A., Llao – Llao Resorts S.A., Minera Geometales S.A., Nabsa Corporation S.A., Nuevas Fronteras S.A., Oberli S.A., ODS S.A., Palermo Invest S.A., Panamerican Mall S.A., Posadas Encarnación S.A., Profingas S.A., Préstamos y Servicios S.A., Proyectos Edilicios S.A., Puerto Retiro S.A., Dolphin Créditos S.A., Dolphin Créditos Holding S.A., Dolphin Finance S.A., Grupo Dolphin Holding S.A., Palermo Invest S.A., Quality Invest S.A., Shopping Neuquén S.A., S.R.K. Italia Hotel S.A., Tarshop S.A., Torres del Puerto S.A., Torres de Puerto Madero S.A. and Sociedad de Inversiones Dique 4 S.A.

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Tomás Arnaude was born on December 17, 1981. He has been an alternate member of our supervisory committee since November 2016. 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 ofShearman & Sterling LLP in 2010. He currently serves as member of the Supervisory Committee of Lubricantes Avellaneda S.A.U., PEFM, Pampa Cogeneración, PACOSA, PP, Enecor and Plásticos de Zárate and as alternate statutory auditor of GG Negocios Fiduciarios S.A., Creaurban S.A. and Veinticuatro de Enero S.A.

Damián Burgio was born on December 13, 1963. He is a founding partner of the law firm Salaverri, Burgio & Wetzler Malbrán. Mr. Burgio is a lawyer graduated from the Universidad Católica Argentina. He currently serves as director of CT Mitre Office S.A., Creaurban S.A. and GG Negocios Fiduciarios S.A. as a member of the supervisory committee of Compañía Americana de Transmisión Eléctrica S.A., Fidus S.G.R, Grupo Dolphin Holding S.A., Envases Plásticos S.A., Enecor, Greenwind, SACDE, PEFM, Plásticos de Zárate, Salta Refrescos S.A. and ODS S.A.

Corporate Governance

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

· Business Code of Conduct. This Code not only states the ethical principles that constitute the foundation of the relationship between the Company, its employees and suppliers, but also 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 the Ethics Hotline as an exclusive channel to report, under strict confidentiality, any suspected misconduct or breach of the Code.

· Insider Trading Policy. This Policy has been implemented in order to avoid “insider trading” practices by the Company’s employees (i.e., to prevent the use of non-public material information to gain advantage for oneself or for others, either directly or indirectly). The Policy applies to the Company’s staff and its subsidiaries, including directors, supervisory committee members, and senior management lines, and it extends to their families or persons who live with them, as well as to certain suppliers.

· Self-Assessment Questionnaire for the Board of Directors. The Company’s Board of Directors passed the implementation of a self-assessment questionnaire to annually examine and assess its own performance and management. The Company’s Corporate Law Department along with the Nomination Committee 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 Company’s board of directors all the proposed measures deemed useful to improve the performance of the board of directors’ duties.

· Internal Policy on Transactions with Related Parties. According to the provisions of the CML, the Company approved the Internal Policy of Transactions with Related Parties. Pursuant to such policy and as stated in the applicable regulations, all high-value transactions (i.e. all exceeding 1% of the equity of the Company) made by the Company with individuals and/or legal entities which are considered as “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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· Nomination Policy. The Nomination 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. The Compensation 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.

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

· Fraudulent Practices Prevention Program. In accordance with the provisions of the U.S. Foreign Corrupt Act and in addition to the Business Code of Conduct, the Company adopted the Fraudulent Practices Prevention Program, which sets out the responsibilities, duties and methodology necessary to prevent and detect any misconduct and/or fraudulent behavior within the Company and/or any of its subsidiaries.

· Policy on Material Information’s Disclosure. This Policy was approved with the aim of standardizing the basic principles concerning the way in which Company’s material information disclosure processes operate, in accordance with the regulatory requirements of the securities markets on which the Company’s securities are listed or those in which it is registered to such end. To ensure the duly execution and compliance with the internal dispositions and applicable regulations with respect to this matter, the Company established an Information Disclosure Committee.

· Dividend Policy. This policy was approved by the board of directors in accordance with laws and regulations in force in Argentina and the bylaws of the Company. It establishes a set of guidelines to be observed in order to keep an adequate balance between distributed amounts and Pampa’s investment plans; aiming at establishing a clear, transparent and consistent practice which 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.

· Policy on Quality, Safety, Environment and Labor Health. Our board of directors approved the QSELH Policy to continue meeting the standards for operating oil and gas, generation, distribution of energy, refining and distribution and petrochemical segments with the highest safety possible within the ordinary course of each activity.

· Swap Transactions Policy. Our board of directors approved the ‘Swap Transactions Policy’, which 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.

· Anti-Money Laundering and Terrorist Financing Prevention Policy. This Policy was approved in accordance with the provisions set forth in Law No. 25,246, its regulations and related provisions, and UIF. Its main purpose is to establish the procedures aimed at preventing money laundering and financing of terrorism.

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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.

For the fiscal year ended December 31, 2019, fees paid and/or accrued during that year to Pampa’s directors amounted to US$6 million. 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 Pampa’s strategic plan and creating a transparent and direct link between value creation for the shareholders and personnel remuneration, on February 8, 2017, Pampa’s board of directors approved the creation of stock-based compensation plan (the “Plan”). In order to implement the Plan, the Company can create Individual Plans.

In addition, Pampa’s board of directors on February 8, 2017, approved the repurchase of Pampa Shares in accordance with Article 64 of the CML and CNV regulations as a means to implement the Individual Plans 2017-2019 and 2018-2020.

On March 8, 2018, the Board of Directors approved a second repurchase of Pampa shares in accordance with Section 64 of the CML and CNV rules that will be destined to cover the Individual Plan 2019-2021.

As of the date of this annual report, Pampa repurchased in open market operations 717,750 ordinary shares and 191,290 ADRs, to cover the Plan (see Note 19 to the Consolidated Financial Statements). During 2019, 290,363 ordinary shares were allocated to executive directors.

Stock-based Compensation Plan - Edenor

In 2016, the Edenor’s board of directors proposed that the shares that Edenor held in treasury be used for the implementation of a long-term incentive plan in favor of executive directors, managers or other personnel holding key executive positions that have an employment relationship with Edenor and those individuals that are invited to participate in the future, under the terms of Section 67 of the CML. The plan was ratified and approved by the ordinary and extraordinary shareholders’ meeting of Edenor held on April 18, 2017.

In 2017, the “long term incentive plan” addressed to Edenor’s staff was developed with the purpose of keeping and attracting key staff and promoting the highest performance by offering company’s shares to the executive and management levels and other key employees. The plan would be administered and executed by an implementing committee to be composed of three members of Edenor’s Executive Committee, which, in April of each year decides on the implementation of the plan for the respective calendar year and shall issue the corresponding annual granting resolution.

Compensation Agreements – Senior Management

On June 2, 2017, the Board of Directors approved the execution of compensation agreements with the Company’s main executives. These agreements mainly provide for an annual, variable and contingent compensation equivalent to, in the aggregate, to 3% of the Company’s annual market value appreciation. For the fiscal year ended December 31, 2017, the calculation period started on June 1. Furthermore, an annual cap of 50% of the accrued amount and 1.5% of the Company’s operating income before interest, taxes and other non-cash items (adjusted EBITDA provision) for the period to be compensated, was established.

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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 1.5% 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. 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.

The objective of this variable compensation 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. The compensation agreements were subject to the prior consideration of our Audit Committee, which concluded favorably regarding their reasonability.

Company-Value / Annual Variable Compensation

On November 6, 2013, Petrolera Pampa’s (currently, Pampa as the surviving company) extraordinary general meeting of shareholders resolved to approve a variable and contingent compensation to certain officers equivalent to 7% of the capital stock after the Company’s capital stock increase, valued based on the difference between the share’s market value at the time of exercising the right and a given value of US$0.1735 per share determined at the exact moment of the capital stock increase. On January 13, 2014, former Petrolera Pampa’s capital stock increase was carried out and the rights granted to officers to receive the Company-Value Compensation became effective for the equivalent to 8,359,000 shares. Moreover, on October 7, 2019, the officers agreed to terminate the monetization option included in this compensation Plan, and as a result, the Company paid on October 11, 2019 a cash amount equivalent to the trading value of such shares (for more information, see Note 19 to the Consolidated Financial Statements).

On the other hand, Petrolera Pampa (currently, Pampa as the surviving company) granted to certain officers an annual variable compensation for the performance of technical and administrative duties amounting to 7% of the EBDA accrued (EBITDA less paid income tax, less total net financial costs, less interest on its own capital, considering an annual 10% dollar-denominated rate) of the oil and gas business from Petrolera Pampa. The Company recognizes a provision (liability) and an expense for this EBDA Compensation based on the previously mentioned formula (see Note 19 to the Consolidated Financial Statements).

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
Miguel Bein	President
Dario Epstein	Regular Member
Carlos Correa Urquiza	Regular Member
Silvana Wasersztrom	Alternate Member

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Share Ownership

As of March 31, 2020, the following members of our board of directors and our senior management had an ownership interest in our capital stock of: Marcos Marcelo Mindlin (15.01%), Gustavo Mariani (2.49%), Damian Miguel Mindlin (2.66%), Ricardo Alejandro Torres (1.65%), Gabriel Cohen (0.19%), Horacio Turri (0.11%), Nicolás Mindlin (0.03%), Mauricio Penta (0.01%), Victoria Hitce (0.01%) and María Carolina Sigwald (0.0002 %). 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, 2019, we had 1,944 full time employees. Additionally, we operate CTEB, which is jointly owned with YPF and has 95 full-time employees.

Approximately 43.41% of our work force is affiliated with a union and/or is a party to a collective bargaining agreement. We have completed salary negotiations for 2019. 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

On May 2, 2018, the merger of Pampa, Petrobras Argentina, Albares and PEISA was registered with the IGJ. As a result, Pampa issued 101,873,741 common shares and, consequently, our capital stock increased to 1,938,368,431 common shares.

Furthermore, on August 2, 2018, the merger of Pampa, Petrolera Pampa, CTG, CTLL, EG3 Red S.A., BLL, INDISA, INNISA, IPB and PP II S.A. was registered with the IGJ. As a result, Pampa issued 144,322,083 common shares and, consequently, our capital stock increased to 2,082,690,514 common shares.

On October 2, 2018, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 182,820,250 common treasury shares of Pampa, which represented 8.8% of the then-issued capital. The withdrawal of the repurchased shares from the capital stock provides the Company with the ability to repurchase shares in the market.Consequently, the IGJ registered the capital reduction and 182,820,250 shares were cancelled, decreasing Pampa’s capital stock to 1,899,870,264 shares (1,874,434,580 of which are outstanding shares and 25,435,684 treasury shares).

On October 1, 2019, the extraordinary general meeting of shareholders approved a capital stock reduction through the cancellation of 151,997,025 common treasury shares of Pampa, which represented 8% of the then-issued capital. The withdrawal of the repurchased shares from the capital stock allows the Company to repurchase shares in the market. Consequently, the IGJ registered the capital reduction, decreasing Pampa’s capital stock to 1,747,873,239 shares. As of the date of this annual report, 151,997,025 shares are still pending cancellation by the CNV.

As of December 31, 2019, our share capital authorized for public trading was Ps. 1,747,873,239 represented by 1,747,873,239 common shares of par value Ps.1 and with right to one vote per share, of which 70,761,196 are treasury shares under share repurchase programs. Therefore, as of December 31, 2019, excluding treasury shares, the total outstanding common shares amount to 1,677,112,043.

On April 7, 2020, after the sixth repurchase of shares (for more information please see “Repurchase of Pampa’s Shares” below), 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. As of the date of this annual report, the registration with IGJ is still pending.

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As of the date of this annual report, we held in treasury 18,802,202 common shares, which represented 1.18% of our issued capital.

J.P. Morgan informed us that, as of March 31, 2020, there were 49,105,459 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, 2020:

Name of Shareholder	Number of Shares	Percentage of our Capital Stock	Percentage of voting power
ANSES (¹)	306,958,364	17.56%	17.56%
Marcos Marcelo Mindlin	262,366,623	15.01%	15.01%
Gustavo Mariani	43,531,984	2.49%	2.49%
Damián Miguel Mindlin	46,532,923	2.66%	2.66%
Ricardo Alejandro Torres	28,877,864	1.65%	1.65%

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.

We are aware through public filings before SEC, that Hidden Lake S.A. and Tavistock Life Sciences Company (Asset Management) owns shares representing, in the aggregate, 9.67% of our capital stock as of March 31, 2020.

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 exceed 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.

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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, 2017, 2018 and 2019, we engaged the services of the Argentine law firm Salaverri, Burgio & Wetzler Malbrán. Two members of our Supervisory Committee, German Wetzler Malbrán and Martín Fernandez Dussaut, and two of the alternate members of our Supervisory Committee, Damián Burgio and Tomás Arnaude, are partners of Salaverri, Burgio & Wetzler Malbrán.

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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, 2019, we had established accruals in the aggregate amount of US$139.9 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 valued 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 are brief descriptions of the nature of the significant legal proceedings or claims in which the Company is a party. As of December 31, 2019, 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.

·Claims alleging that the index (IPC) used to update the plan benefits is ineffective to keep the benefits’ “constant value”.

·Claims on an alleged underfunding of the plan upon the elimination of the Company’s contributions based on earnings.

·Claims by former employees who were dismissed as part of scheduled layoffs due to Company’s change of control.

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.

Tax and Customs Proceedings 

Claims on naphtha exports

There is a significant number of customs claims, whereby the Tax Authority charged us with the infringement of misreporting, on the basis of the Section 954 (1.a) of the Customs Code during the period 2008-2014. The Tax Authority, AFIP – DGA, alleged that the exported naphtha during the previous years should had been levied with a higher tax rate. As of December 31, 2019, the provision recorded in relation to these claims amounted to US$84.7 million.

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Income Tax refund claim 

The Company, HIDISA, HNISA and CPB, had filed different petitions for refund of income tax paid in excess taking into consideration the application of inflation adjustment for an amount of Ps.1,169 million. On December 7, 2017, CPB collected the amount claimed for the 2002 period, which amounted to Ps. 4 million plus interest. However, upon joining the tax revaluation regime detailed in Note 2.6.1.4 of the Financial Statements, on March 29, 2019 and April 3, 2019, Pampa and CPB, respectively, formally presented their waiver to the rights invoked in the mentioned tax refund claims in the amounts of Ps. 1,095 million and Ps. 1.6 million, respectively.

Minimum national income tax - Refund claim

The Company and CTLL (currently merged with us) have filed different petitions for refund against AFIP – DGI for the application of the minimum presumed income tax corresponding to the fiscal years 2008 and 2009. This claim seeks the refund of Ps.25 million, including the recovery of payments recorded and the reversal of the payment made on account of the offsetting of several fiscal credits. As AFIP did not answer the claim, we brought the tax refund claim before a National First Instance Administrative Litigation Court.

On August 25, 2016, CTLL obtained a favorable ruling by the Chamber of Appeals, which confirmed the first instance decision sustaining the refund claim; however, the payment had not been received as of the date of this annual report, and the Company is conducting the relevant proceedings in this respect. The Company considers it is highly probable to obtain a favorable, final and conclusive ruling.

Minimum national income tax - Declaratory relief

The Company and its subsidiaries filed a petition for declaratory relief pursuant to Section 322 of the Federal Code of Civil and Commercial Procedure against AFIP in order to obtain assurance as to the application of the minimum national income tax for the 2010-2016 period based on the decision by the Supreme Court of Justice of Argentina passed on June 15, 2010 (“Hermitage” case).

In this precedent, the Court had declared this tax unconstitutional since it may be considered unreasonable under certain circumstances and since it breaches the tax capacity principle.

Pursuant the validation made by AFIP to the precedent mentioned above, through General Instruction 2/2017, the Company and its subsidiaries have resolved not to file a petition for declaratory relief as of the fiscal year ended December 31, 2017.

Furthermore, the Company and certain subsidiaries have requested the granting of interim injunctive relief so that AFIP may refrain from demanding payment or instituting tax execution proceedings on the tax for the fiscal years mentioned. The Court overseeing the proceedings decided to reject the precautionary measures, a decision that was appealed by the Company and certain subsidiaries.

Taking into consideration the different rulings favorable to the Company and its subsidiaries, and in line with the case law established by the “Hermitage” decision and the Treasury’s position on closing several verifications for periods where taxpayers do not have any taxable income (before the calculation of tax losses), in which the Treasury has waived its claims for these debts based on the unfavorable case law and in line with the criterion established by the Court, the Company has decided to derecognize the liabilities it had previously disclosed for the Minimum Notional Income Tax  (“IGMP”- “Impuesto a la Ganancia Minima Presunta)” it should have assessed if the provisions of the Hermitage decision had not applied.

Sales tax

The Company maintains interpretative differences with the AFIP and Argentinian provincial tax authorities related to taxes applicable to its oil and gas activity. The Company estimates that the outcome of these differences will not have significant adverse effects on the Company’s financial position or operational results.

 HIDISA and HINISA have filed a note to the Province of Neuquén’s Revenue Department informing that they consider that the electric power generation activity conducted in that province should be covered by the provisions of Section 12 of Act No. 15,336. Pursuant to this Section, revenues resulting from the generation of electric power are exempted from the provincial sales tax.

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Environmental Claims

- The Association of Landowners of Patagonia (ASSUPA) has brought a complaint for an indefinite amount against the Company and other companies seeking the restoration of the environment to the state prior to the exploration, exploitation, production, storage and transportation of hydrocarbon works conducted by the defendants and the prevention of alleged future environmental impacts on certain 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 answer to the complaint stage.

- ASSUPA has instituted a complaint before the CSJN against ten 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. 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 according to the United Nations Development Program report. The proceeding is at the answer to the complaint 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 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 at 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 at 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 Ps. 200 million. The proceeding is pending the resolution of the admissibility of CSJN’s jurisdiction.

- A group of neighbors of the City of Bahía Blanca instituted a complaint before the provincial courts of this city for alleged environmental damage having collective impact against the companies of the petrochemical complex, Consorcio de Gestión Del Puerto de Bahía Blanca and the Province of Buenos Aires. The plaintiffs seek the redress of collective moral injury (estimated at Ps. 52 million), the cessation of the alleged damage to the estuary of Bahía Blanca, and a comprehensive restoration to its previous state. In case this is not possible, the plaintiffs subsidiarily seek damages, the beneficiary of which would be the Environmental Compensation Fund. They also request a prohibition to install new industrial activities in the area and the development of a new and efficient industrial waste collection, disposal and treatment system. The proceeding is pending judgment.

- 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. CSJN decided its jurisdiction over the environmental aspect and resolved to maintain the jurisdiction of the court regarding the compensation of alleged damages.

- A neighbor of the Province of Salta owning a lot where a joint venture made up of the defendant (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. A negative conflict of jurisdiction is being discussed.

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- 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 proceeding is at the lawsuit integration stage.

- María Elena Baya de Rudd and David Rudd have filed a complaint against the Company, other companies and the joint venture made up by them for the repair of alleged damages caused in the Estancia Laguna Esperanza lot owned by them and the remediation of alleged environmental damage caused by the exploitation and abandonment of oil wells in the lot. The Company has filed an appeal in this proceeding and requested jointly with the plaintiff for a stay of procedural deadlines in order to negotiate a settlement. Such request has been granted.

- 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 proceeding is currently at the evidentiary stage.

- A resident of the Province of Buenos Aires filed a complaint against the Company seeking the removal of fuel storage tanks and fuel pumps, and remediation and restoration of the soil where the above mentioned tanks were located, in case of determination of the alleged damage to the environment. The answer complaint stage has concluded, and the proceeding is currently at the discovery stage.

Civil and Commercial Claims

- The consumers’ association named “Consumidores Financieros Asociación Civil Para Su Defensa”, has filed an arbitration action against Petrobras, claiming a nominal amount of US$3,650 million in damages, based on the loss of value of shares as a consequence of the “operation lava jato”, also known as “Petrolao”. The action, filed before the General Arbitration Tribunal of the Buenos Aires Stock Exchange, was also addressed against Pampa, its former subsidiary Petrolera Pampa S.A. and several directors of Pampa appointed during 2016 fiscal year, mainly because the plaintiff invokes that the acquisition by Pampa of Petrobras’ indirect shareholding interest in Petrobras Argentina S.A. impaired the plaintiff`s chances to seize Petrobras’ assets  in Argentina in order to enforce a potentially favorable award in its action against Petrobras. The plaintiff has challenged the decision of the General Arbitration Tribunal to exclude it from the main arbitration action due to lack of payment of arbitration fees.

- We were notified of collective action initiated in the city of Rio de Janeiro, Brazil. The plaintiff of the collective action is Felipe Machado Caldeira. The plaintiff claims that Petrobras Argentina would not have been sold by Petrobras Brasil through a bidding process with a nominal value of R$1,000 million because such action goes against the Brazilian regulations regarding mixed-capitalcompanies (joint ventures between the public and the private sectors). This collective action does not refer explicitly to Pampa. Currently, due to the death of the plaintiff and the lack of interest of the Prosecutor’s Office in continuing this proceeding, a legal notice has been published requesting any citizen to express its interest in continuing this legal proceeding. 

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- Messrs. Candoni, Giannasi, Pinasco and Torriani have filed arbitration claims before the General Arbitration Tribunal of the Buenos Aires Stock Exchange against the Company objecting the ratio applied to the exchange of Petrobras Argentina’s shares for Pampa`s shares made as a result of the merger of Petrobras Argentina into Pampa. The General Arbitration Tribunal has issued a partial arbitral award considering that the type of action filed by the plaintiffs is correct. Such decision has been appealed by the Company and will be reviewed by the Court of Appeals in Commercial Matters.

- Fees associated with the injunction granted in favor of Oil Combustibles: Oil Combustibles’ attorneys claim an increase in their fees assessed by the first-instance judge and ratified by the Chamber of Appeals of Rosario. The Supreme Court of Santa Fe resolved to annul the Camber’s decision and ordered that a new judgment should be passed. A motion for clarification was filed against this judgment before the Supreme Court of Justice, as well as an extraordinary appeal before the CSJN. A settlement agreement has been reached and all pending claims have been withdrawn.

- Petrobras Operaciones S.A. has filed an arbitration claim before the International Court of Arbitration of the International Chamber of Commerce (“ICC”) against the Company for alleged breaches of the provisions of the Assignment Agreement entered into by Petrobras Argentina (currently the Company) and Petrobras Operaciones S.A. in 2016 in order to assign 33.60% of the participating interest in the “Río Neuquén Concessions” in the Provinces of Neuquén and Río Negro, Argentina. The arbitration will be administered by the ICC in accordance with the ICC Rules, the Arbitration seat will be Buenos Aires, Argentina and the applicable law will be the law of the Argentine Republic.  

- Consumidores Financieros Asociación Civil para su Defensa, a consumers’ association, instituted an action against Edenor and Edesur in the National Court of First Instance in Federal Administrative Claims Tribunal No. 2, Secretariat 3 (Juzgado Nacional de Primera Instancia en lo Contencioso) during a ten year period. The action is based on three claims. First, the plaintiffs claim a refund for the percentage payment of VAT over a taxable base they allege was inappropriately increased to include an amount that exceeded Edenor’s and Edesur’s own payments to the WEM. Second, the plaintiffs claim a refund for charges relating to interest on payments by users that the plaintiffs claim Edenor and Edesur failed to adjust to reflect the actual number of days the payment was outstanding. Finally, the plaintiffs claim a refund for late payment charges from 2008 onwards calculated at the rate of the tasa pasiva (the interest rate that Banco Nación pays on deposits) in alleged contravention of the Law of Consumer Defense (Ley de Defensa del Consumidor) in April 2008. On April 22, 2010, we answered the complaint and filed a motion to dismiss for lack of standing (“excepción de falta de legitimación”), requesting, at such opportunity, that a summons be served upon the Argentine Government, the AFIP and the ENRE as third-party defendants. As of the date of this annual report, a decision on this case is pending. It is estimated that the proceedings will not conclude in 2019.

- Asociación de Defensa de Derechos de Usuarios y Consumidores (ADDUC), filed a lawsuit against Edenor, requesting that the intervening court (i) order the reduction or moderation of penalty interest rates or late payment interest that Edenor charges to users, because such rates allegedly violate Art. 31 of Law 24,240, and (ii) declare the non-implementation of the agreements or conventions which have stipulated the interest rates that Edenor applies to its customers, and of the administrative regulations on the basis of which Edenor justifies the interest charging and (iii) order the restitution of the interest wrongfully perceived against customers. On April 8, 2014, the court decided to grant the motion to dismiss on account of the existence of other action pending (lis pendens) and ordered that the proceedings be referred to such other court, to be consolidated with such other case “Consumidores Financieros Asociación Civil c/EDESUR y Otros s/ incumplimiento contractual”. As of the date of this annual report, a decision on this case is pending. It is estimated that the proceedings will not be terminated in 2019.

- ADDUC requested that Edenor be ordered by the Court to reduce or mitigate the default or late payment interest rates charged to customers who pay their bills after the first due date, inasmuch as they violate section 31 of Law 24,240, ordering both the non-application of pacts or accords that stipulate the interest rates that are being applied to the users of electricity –their unconstitutional nature– as well as the reimbursement of interest amounts illegally collected from the customers of the service from August 15, 2008 through the date on which the defendant complies with the order to reduce interest. It is also requested that the VAT and any other taxes charged on the portion of the surcharge illegally collected be reimbursed. These proceedings have been joined to those mentioned above and have been brought to trial.

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Set forth below are brief descriptions of the nature of the significant legal proceedings or claims brought by the Company. As of December 31, 2019, we consider that such legal proceedings are probable and economic benefits are expected to the Company.

Administrative claims

- CTLL, currently merged with us, filed an administrative complaint against the National Government for contractual breach during the January 2016-October 2018 period. CTLL claims that CAMMESA’s decision regarding the renewal and recognition of costs associated with natural gas supply agreements should be reversed, or alternatively, sustained damages should be redressed. As of the date of this annual report the total claim amounts to US$48.7 million.

- Upon the determination of the expiration of the Veta Escondida area concession granted by the Province of Neuquén, we filed a declaratory judgment action to achieve certainty under the original jurisdiction of the Federal Supreme Court of Justice pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. Both parties agreed to suspend the proceeding and settle a solution. Negotiations are currently in progress, and terms have been suspended for 20-day periods renewable until settling the conflict.

Civil and Commercial claims

- The Company has filed an arbitration claim before the ICC against Petrobras International Braspetro B.V. This dispute arises from Petrobras International Braspetro B.V.’s fraudulent misrepresentations and omissions during the negotiation of the Sale and Purchase Agreement dated May 13, 2016 (the “SPA”) and the related due diligence process, in relation to certain exports. Pursuant to the SPA, the Company acquired Petrobras International’s 67.2% stake in Petrobras Argentina. The arbitration will be administered by the ICC in accordance with the ICC Rules, the arbitration seat will be New York, and the applicable law will be the law of the State of New York, USA

- Edenor seeks to obtain the judicial annulment of the ENRE’s Resolution 32/11 that provided Edenor to: (i) be fined in the amount of Ps. 750,000 due to its failure to comply with the obligations arising from Section 25, sub-sections a, f and g, of the Concession Agreement and Section 27 of Law No. 24,065, (ii) be fined in the amount of Ps. 375,000 due to its failure to comply with the obligations arising from Section 25 of the Concession Agreement and ENRE Resolution No. 905/99 and (iii) be ordered to pay customers as compensation for the power cuts suffered the following amounts: Ps. 180 to each small-demand residential customer (TIR) who suffered power cuts that lasted more than 12 consecutive hours, Ps. 350 to those who suffered power cuts that lasted more than 24 consecutive hours, and Ps. 450 to those who suffered power cuts that lasted more than 48 consecutive hours. The course of these proceedings is currently suspended due to the fact that an “Agreement of parties” has been entered into with the ENRE. In view of the time elapsed since Edenor and the ENRE agreed to suspend the procedural time-limits, the court has requested that the parties express their stance on the issue. Based on the terms of the Agreement on the Regularization of Obligations entered into on May 10, 2019 by and between Edenor and the Federal Government, this proceeding should be abandoned, with each party bearing its own court costs, as agreed in such Agreement.

As of December 31, 2019, Edenor made a provision for principal and interest accrued for an amount of US$1.5 million within the Non-current other liabilities account. Based on what is mentioned in the paragraph above, and once Edenor provides its consent in connection with the withdrawal of this claim, such provision should no longer be recorded.

- Edenor sued the Ministry of Planning, Public Investment and Services for breach of contract due to the Federal Government’s failure to perform in accordance with the terms of the Adjustment Agreement.

On September 16, 2019, in the framework of the request to litigate without expenses, Edenor filed a brief regarding the abandonment of the action and waiver of right, requesting at the same time that each party be held liable for its own court costs. The representatives of the Federal Government gave their consent to the terms of the brief. Therefore, on September 24, 2019, the Court terminated this separate proceeding.

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Furthermore, in the main proceedings, Edenor, with the Federal Government’s consent, submitted on September 16, 2019 a waiver of the action and the right, declaring that the facts disputed in the proceedings amounted to Ps. 6,900 million; as a result, the payment of court fees was integrated, which amounted to Ps 207 million. The proceedings were sent to the tax authorities for their approval, and Edenor attached the breakdown of the amounts comprising the reconciled principal.

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, 2014, December 31, 2015, December 31, 2016, December 31, 2017, December 31, 2018 or December 31, 2019.

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 and Paying Agents.”

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.

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
2015(1)	16.50	4.32	12,680,872	26.87	9.10	3,522,741
2016(1)	23.20	9.65	21,213,181	37.11	17.52	7,832,862
2017(1)	51.25	22.15	39,518,145	71.39	35.52	16,535,669
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

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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
2018(1)
First Quarter	56.15	46.25	52,265,797	72.98	57.18	16,441,550
Second Quarter	54.90	40.00	63,872,867	60.52	35.08	26,378,028
Third Quarter	57.60	35.05	49,177,242	43.67	24.93	14,530,158
Fourth Quarter	56.60	41.40	37,826,590	38.33	28.00	10,961,437
2019(1)
First Quarter	60.40	44.75	49,262,881	39.89	25.47	12,232,829
Second Quarter	60.30	35.05	51,107,586	35.56	19.50	25,126,398
Third Quarter	64.50	29.15	51,510,391	36.41	12.01	16,498,487
Fourth Quarter	54.40	37.30	48,822,580	19.10	12.43	11,124,680
2020(1)
First Quarter	50.20	32.00	37,002,047	16.69	8.72	6,832,201
Second Quarter	47.50	35.85	37,578,269	11.76	9.14	4,008,991

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
2019(1)
November	53.90	37.30	41,318,099	17.00	12.43	14,814,728
December	50.80	38.70	57,087,219	17.37	12.88	9,194,056
2020(1)
January	50.20	42.80	35,138,416	16.69	12.80	6,648,831
February	49.95	37.65	29,386,518	14.85	11.62	7,069,200
March	46.80	32.00	46,188,304	14.47	8.72	6,641,845
April(3)	47.50	35.85	37,578,269	11.76	9.14	4,008,991

⁽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 29, 2020.

 Repurchase of Pampa’s Shares

On April 27, 2018, the Board of Directors approved the repurchase of Pampa shares plan in accordance with Section 64 of the CML and the CNV rules. To arrive at this decision, the Board of Directors took into consideration the difference between the value of our assets and the quoted price of Pampa in the stock exchanges. The Board of Directors determined that the latter does not reflect the value or the economic reality of Pampa, nor Pampa’s potential, resulting in a detriment to Pampa’s shareholders’ interest. In its determination, the Board of Directors considered our strong cash position and funds availability.

On June 27, 2018, the Repurchase Program I was completed for a total number of 4,119,451 ADRs, which equal 103.0 million common shares, at an average price of US$48.52/ADR. Furthermore, Pampa’s Board of Directors approved on June 22, 2018 a second share repurchase plan for up to US$200 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock, which was completed on October 23, 2018, for a total number of 3,997,742 ADRs, which equal 99.9 million common shares, at an average price of US$32.14/ADR.

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On October 2, 2018, the extraordinary meeting of shareholders approved a capital stock reduction through the cancellation of 182,820,250 common treasury shares of Pampa, which represented 8.8% of then-issued capital. The withdrawal of the repurchased shares from the capital stock provides the Company with the ability to repurchase shares in the market.Consequently, the IGJ registered the capital reduction and 182,820,250 shares were cancelled, decreasing Pampa’s capital stock to 1,899,870,264 shares.

In addition, on March 27, 2019, the Board of Directors approved a third share repurchase plan for up to US$100 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock. On June 12, 2019, the Board of Directors suspended the Repurchase Program III as the price of our shares and ADRs reached values exceeding the repurchase cap.

On August 12, 2019, the Board of Directors approved a fourth share repurchase plan. On August 30, 2019, an extension of the maximum amount to be disbursed under this program was approved by the Board of Directors, from US$50 million to US$65 million.

Moreover, on November 8, 2019 the Board of Directors approved the fifth share repurchase plan for US$50 million or the lower amount resulting from the acquisition until reaching 10% of repurchased treasury shares over the capital stock.

Furthermore, on October 1, 2019 the extraordinary shareholders’ meeting approved a capital stock reduction through the cancellation of 151,997,025 million common treasury shares of Pampa. The withdrawal of the repurchased shares from the capital stock provides the Company with the ability to repurchase shares in the market.Consequently, the IGJ registered the capital reduction decreasing Pampa’s capital stock to 1,747,873,239 shares. As of the date fo this annual report, 151,997,025 shares are still pending cancellation by the CNV.

On March 9, 2020, the Board of Directors approved the sixth share repurchase plan for US$27 million or the lower amount resulting from the acquisition until reaching 10% of repurchased treasury shares over the capital stock.

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. As of the date of this Annual Report, the registration with IGJ is still pending.

Finally, on April 13, 2020, the Board of Directors approved the seventh share repurchase plan for US$20 million or the lower amount resulting from the acquisition until reaching 10% of repurchased treasury shares over the capital stock. The Repurchase Program VII will commence once the end of the Repurchase Program VI is communicated to the market.

As of the date of this annual report, net of share cancellations upon approval from regulatory authorities, Pampa repurchased in open market operations 1,704,770 ADRs, which equal 42,619,250 million common shares under the Repurchase Program VI.

For more information, please see “Item 16.E—Purchases of Equity Securities by the Issuer and Affiliated Purchasers”.

American Depositary Shares

Since October 9, 2009, our ADSs have been listed on the NYSE and trade under the ticker PAM. Each ADS represents 25 common shares (or a right to receive 25 common shares). Pursuant to the provisions of the Deposit Agreement, on January 23, 2017, Pampa sent a notice to 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.

Each ADS will also represent any other securities, cash or other property, which may be held by the ADS Depositary, J.P. Morgan.

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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, 2019, there were 48,918,539 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.

On December 29, 2016, the CNV authorized BYMA and on January 2, 2017, IGJ and CNV authorized the creation and operation of BYMA. Sixty percent of its capital stock is held by shareholders of S&P MERVAL and the other 40 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 will be 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.

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In order to improve Argentine securities market regulation, the Argentine Government issued Decree No. 677/2001 on June 1, 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. In this respect, the following key reforms were approved, among others:

(i)Certain amendments aimed at promoting access to MiPyMES (micro, small and medium-sized companies) to the capital market, among others;

(ii)Changes to the regulatory framework of tender offers, such as the criteria to determine fair price requirements and timing for launching a tender offer due to a change in control, among others.

(iii)Amendments to the preemptive subscription rights in the public offerings;

(iv)Amendments regarding the duties of the CNV and its financial sources, the most important is the amendment to item (a) of Section 20 of the CML, which previously providedthat the CNV could inspect any entity subject to its oversight (such as us, our controlling shareholder or any of our affiliates subject to CNV oversight), and had the power to appoint an observer (veedor) with veto powers and to temporarily suspend the board of directors under certain circumstances. Additionally, Subsection (i) of the Section 19 of the current CML was removed, as a result a previous administrative summary proceeding is required before the CNV is able to declare that an act under its control is irregular or ineffective;

(v)Reestablishes the jurisdiction of the courts in commercial matters to hear appeals relating to resolutions and fines imposed by the CNV;

(vi)Main amendments to the Argentine Negotiable Obligations Law No. 23,576: (a) expressly permits the issuance of Dollar-linked notes; (b) financial institutions and issuers engaged in construction, sale and financing of real property, infrastructure works and real estate development, will be authorized to issue notes with indexation clauses; (c) allows issuers to establish a procedure to obtain the consent of the majority of bondholders without the need for bondholders meetings, subject to certain requirements; among others.

Prior to offering securities to the public in Argentina, an issuer must meet certain requirements established by the CNV (for example, regarding the issuer’s assets, operating history and management, among others), and only securities authorized for public offering by the CNV may be listed on a stock exchange. Although issuers of listed securities are required to file with the CNV and the stock exchange on which their securities are listed several financial documents (such as, unaudited quarterly financial statements, audited annual financial statements, various other periodic reports), as well as to report any event related to the issuer and its shareholders that may materially affect the value or trading volume of the traded securities,- the CNV approval does not imply any kind of certification as to the quality of the securities or the solvency of the issuer.

Money Laundering

The concept of money laundering is commonly used to refer to operations that aim to enter funds from criminal activities into the institutional system and thus convert profits from illegal activities into assets of apparently lawful origin.

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 harsh sanctions for those incurring in such illicit activity and has created the UIF, a unit of the Ministry of Treasury 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 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; and (vii) Crimes of underage prostitution and child pornography under Articles 125, 125 bis, 127 bis and 128 of the Argentine Criminal Code.

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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 transactions, 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.

In the capital markets sector, the UIF issued Resolution No. 229/2011 (“Resolution 229”), which was replaced by Resolution UIF No. 21/2018 and, subsequently amended by Resolutions No. 156/2018, No. 18/2019 and No. 117/2019 (“AMLin 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 the committing of money laundering and terrorist financing crimes in the capital market sector. Additionally, the AML in the Capital Market Sector introduced general guidelines to identify different types of customers (including a distinction between frequent, casual and inactive customers), the requested information, the documentation to be kept and the procedure to detect and report all suspicious transactions within the established deadlines.

The main obligations pursuant to the AML in the Capital Market Sector are the following: (i) to prepare manuals providing the mechanisms and procedures for the prevention of money laundering and financing of terrorism; (ii) to appoint a compliance officer; (iii) to audit regularly; (iv) to provide training programs to the employees; (v) to enforce measures that would allow the Obliged Subjects in the Capital Market Sector to compile the transactions performed by the customers using a computerized method, as well as technological tools which would enable the analysis and supervision of different transactions to identify behaviors and detect potential suspicious operations; (vi) the implementation of technological tools that would result in effective control and prevention procedures against money laundering and financing of terrorism; and (vii) to record the analysis and risk management of the suspicious transactions that were detected and those that, for having been considered suspicious, have been reported.

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.

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On the other hand, with the issuance of Resolution No. 21/2018, as amended subsequently, the responsibility for the Obliged Subjects in the Capital Market Sector has been included in order to 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. Additionally, new standards were established to carry out due diligence in the control and monitoring of customers and new categories of agents were included (the ones included in the latest reform of the CML).

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 well as the Central Bank regulations require banks to take certain minimum precautions to prevent money laundering. In August 2018, pursuant to UIF Resolution No. 97/2018, the Central Bank's duty of collaboration with the UIF was adjusted in accordance with the guidelines established in UIF Resolution No. 30/2017 regarding the supervision procedures followed by financial and exchange entities.

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 strengthens 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 (GAFILAT).

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) (the “Tax Amnesty Law”) provides 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.

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.

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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 and distributing products 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

    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:

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(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.

   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.

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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.

 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.

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Election of Directors

  In accordance with Article 12 of our by-laws, our Board of Directors is composed of nine 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 from 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.

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.

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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.

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.

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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 Valoreswill 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

In January 2002, the Argentine Government issued the Public Emergency Law and declared a state of public emergency in respect of its social, economic, administrative, financial and foreign exchange matters, authorizing the Argentine Government to establish a system to determine the foreign exchange rate between the Peso and foreign currencies and to issue foreign exchange-related rules and regulations. Within this context, on February 8, 2002, through Decree No. 260/2002, the Argentine Government established (i) the MULC through which all foreign exchange transactions in foreign currency must be conducted, and (ii) that foreign exchange transactions in foreign currency must be conducted at the foreign exchange rate to be freely agreed upon among contracting parties, subject to the requirements and regulations imposed by Central Bank. A summary of the main regulations is set forth below.

On June 9, 2005, through Decree No. 616/2005, the Argentine Government mandated that:

(i)

all inflows of funds into the local foreign exchange market arising from foreign debts incurred by residents (including both individuals and legal entities in the Argentine private sector), other than those concerning foreign trade financing and primary issuances of debt securities offered to the public and listed on self-regulated markets, and

(ii)

all inflows of funds by non-residents channeled through the MULC and intended to be held in local currency for acquiring all types of financial assets or liabilities in the financial or non-financial private sector (except for foreign direct investments and primary issuances of debt securities and shares offered to the public and listed on self-regulated markets), as well as investments in securities issued by the public sector and acquired in secondary markets, have to meet the following requirements: (a) such inflows of funds could only be transferred outside the local foreign exchange market at the expiration of a term of 365 calendar days as from the date the funds entered the country; (b) the proceeds of such inflows of funds had to be credited to an account in the local banking system; (c) a non-transferable and non-interest-bearing deposit for 30% of the amount of the transaction had to be kept in Argentina for a period of 365 calendar days, in accordance with the terms and conditions set forth in the applicable regulations (the “Deposit”); and (d) the Deposit had to be denominated in U.S. Dollars and held in Argentine financial institutions, and it may not be used to guarantee or serve as collateral for any type of credit transactions.

Following the election of President Macri, the aforementioned restrictions were modified mainly by Resolution No. 3/2015 of the former Ministry of Treasury, which (i) reduced the Deposit to zero percent (0%), and (ii) reduced the period in which incoming funds representing new financial debt must remain in Argentina. Additionally, Communication “A” 6244 lifted the existing restrictions that regulated the exchange rate, the general position of changes and revoked Decree No. 616/2005.

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Furthermore, all restrictions related to the transfer and sale of proceeds in the MULC resulting from the export of goods were lifted as of January 6, 2018. On January 6, 2018, the Public Emergency Law ceased to be in effect.

Notwithstanding the aforementioned, on September 1, 2019, after the PASO, Decree No. 609/2019 stipulated that, except otherwise established, until December 31, 2019 the value paid for the export of goods and services should be entered in the country in foreign currency and/or negotiated in the MULC in accordance with the requirements and time limits established by the Central Bank.

Within this context, the same day, on September 1, 2019, the Central Bank issued Communication “A” 6770 aiming to regulate the income and expenses in the exchange market in order to maintain exchange stability and protect international reserves against the high uncertainty and volatility of the exchange rate. Subsequently, the Central Bank issued certain communications modifying Communication “A” 6770, deepening exchange controls and restrictions on the entry and exit of foreign exchange. Also, on December 5, 2019, the Central Bank issued Communication “A” 6844, comprising in a single body the rules on foreign exchange (together with its amendments, the “T.O. on Foreign Exchange”).

Among the most important obligations, restrictions and limitations found in the T.O. on Foreign Exchange, the following is worth highlighting:

(i)	the obligation to enter and liquidate in the MULC currencies resulting from: (a) the export of goods and services by residents, (b) the perception of amounts in foreign currency resulting from the trade of non-produced and non-financial assets by residents to non-residents, (c) the disbursements resulting from financial debts with non-residents as from the issuance of Communication “A” 6770, as a requirement for being able to access the MULC to pay the due capital and interests, (d) the amounts resulting from the issuance of securities denominated and subscribed in foreign currency with public registry in Argentina as from November 29, 2019, as a requirement for being able to access the MULC to pay the due capital and interests;
(ii)	restrictions to access the MULC for the payment of imports of goods and services (including debts from imports) to non-residents;
(iii)	requirement to obtain the Central Bank’s prior authorization in order to access the MULC: (a) by non-residents, with certain exceptions, (b) for the transfer of foreign currency abroad resulting from profits and dividends, to the extent that the exchange control requirements allowing the transfer are not met, (c) for the creation of external assets and the creation of all types of guaranties related to derivatives transactions by legal entities, the same restriction applies to individuals whenever the transaction equals or exceeds US$200 per month, (d) for accelerated payments of capital and interests on financial debts owed to non-residents (at least three business days prior to the due date), and (e) for accelerated payments of debt related to the import of goods and services; and
(iv)	the prohibition to access the MULC for the payment of debts and other obligations in foreign currency between residents as of the date of the issuance of Communication “A” 6770, with certain exceptions.

On December 27 and 30, 2019, the Central Bank, through communications “A” 6854, “A” 6855 and “A” 6856, extended the validity of the T.O. on Foreign Exchange as of December 31, 2019.

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.

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. Investors should consult their own tax advisors as to the tax consequences of the Acquisition, ownership and disposition of common shares or ADSs.

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Although there is at present no income tax treaty between Argentina and the United States, the tax authorities of the two countries have had discussions that may culminate in such a treaty. No assurance can be given, however, 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 that the disposition do not meet such requirements, the income obtained by foreign individual and legal entities 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).

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.

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 the years 2018, 2019, 2020 and 2021 and at the rate of 25% from 2022 and later. 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.

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.

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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 to December 31 2021), and at a 13% rate (on profits accrued in fiscal years starting January 1, 2022 and onwards), provided that they are distributed to Argentine resident individuals and foreign shareholders (including holders of common shares or ADSs).

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 effectivenes, 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.

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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.

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).

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Tax treaties

Argentina has signed tax treaties for the avoidance of double taxation with Australia, Belgium, Spain, Bolivia, Brazil, Canada, Chile, Denmark, Finland, France, Germany, Italy, Mexico, the Netherlands, Norway, Russia, Sweden, Swiss, the United Arab Emirates and the United Kingdom. In addition, Argentina has signed tax treaties with Turkey, Qatar, Luxembourg, Japan, Austria and China but to date they are pending ratification in Argentine Congress for its entry into force. There is currently no tax treaty or convention in effect between Argentina and the United States. 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.

Value Added Tax (VAT)

Investments Tax Returns

                    The return of tax credits originated in investments in fixed assets will be given, in case that,sixmonths 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:

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·a citizen or resident of the United States;

·a U.S. domestic corporation; or

·otherwise subject to U.S. federal income tax on a net income basis with respect to income from the ADS.

In general, if a U.S. holder is the beneficial owner of ADSs, such U.S. holder will be treated as the beneficial owner of the common shares represented by those ADSs for U.S. federal income tax purposes, and no gain or loss will be recognized if such U.S. holder exchanges an ADS for the common shares represented by that ADS.

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 2018 and 2019 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 for our 2020 taxable year.

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.

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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. If no such rules apply, a U.S. holder may be able to claim a credit against its U.S. federal income tax liability for Argentine income taxes withheld at the appropriate rate applicable to the U.S. holder from cash dividends on the ADSs, if the tax is treated for U.S. federal income tax purposes as imposed on the U.S. holder, so long as the U.S. holders has owned the ADSs (and not entered into specified kind of hedging transactions) for at least a 16-day period that includes the ex-dividend date. Dividend distributions with respect to the ADSs generally will be treated as “passive category” income from sources outside the United States for purposes of determining a U.S. Holder’s U.S. foreign tax credit limitation. If a gain realized on the sale or other disposition of ADSs is subject to withholding tax, a U.S. holder may not be able to credit the tax against its U.S. federal income tax liability unless such credit can be applied (subject to applicable conditions and limitations) against tax due on other income treated as derived from foreign sources. It is unclear whether the Argentine personal assets tax (as described in “—Argentine Tax Considerations”) 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. The calculation of foreign tax credits and, in the case of a U.S. holder that elects to deduct foreign taxes, the availability of deductions, involve the application of complex rules that depend on a U.S. holder’s particular circumstances. Investors should consult their own tax advisors regarding the creditability or deductibility of such taxes.

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 $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.

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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 Chase Bank, N.A., 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, 2019.

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, we, with the participation of our chief executive officer and chief financial officer, concluded that as of December 31, 2019, 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 assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on our assessment and those criteria, management believes that the company maintained effective internal control over financial reporting as of December 31, 2019.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2019 has been audited by Price Waterhouse & Co. S.R.L., an independent registered public accounting firm, as stated in their report, which appears herein.

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(c) Attestation Report of the Registered Public Accounting Firm

Reference is made to the report of 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

Miguel Bein, 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 by our Board of Directors on March 9, 2017, 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, 2019, 2018 and 2017. 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,
	2019	2018	2017
	(in million US$)
Audit Fees (1)	1.8	1.4	2.4
Audit-related Fees (2)	-	-	-
Tax Fees (3)	-	-	-
Other non-audit Fees (4)	-	0.2	-
Total	1.8	1.7	2.4

(1) Audit Fees comprised of audit of our financial statements and our subsidiaries, the review of the interim financial statements, review of the Company’s annual report on Form 20-F, work to comply with the requirements of the Sarbanes Oxley – Section 404 and other services rendered by the external auditor in connection with statutory or regulatory filings or engagements.

(2) Audit-related Fees comprised of those outside the normal scope of the services included in an audit but are nevertheless reasonably related to the performance of the audit or review of our financial statements or our subsidiaries and may be effectively and efficiently rendered by the external auditor because of his knowledge of our financial information.

(3) Tax Fees comprised of services rendered by the external auditor for tax compliance.

(4) Services included under this heading include regulatory attestation reports presented to the IGJ for 2018.

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, and audit-related fees, contained in the above table were billed by Price Waterhouse & Co. S.R.L.

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Audit Committee’s Pre-approval Policy

The Audit Committee has developed a Pre-approval Policy regarding the engagement of services by the external auditor, establishing the obligation to obtain prior approval from the audit committee for any service to be rendered by the external auditor to the Company or any of its subsidiaries. The policy ensures that the external auditor preserves its independence and is applicable to the Company and its subsidiaries. Services pre-approved by the audit committee of Edenor do not require pre-approval by the Audit Committee of Pampa, but are reported to the latter.

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.

Item 16D.              Exemptions from the Listing Standards for Audit Committees

Not applicable.

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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
2019	ADS	Common Shares	ADS	Common Shares	Common Shares (*)
January	-	-	-	-	-	-	-
February	-	-	-	-	-	-	-
March	-	-	-	-	-	-	-
April	1,440,235	-	US$23.18	-	36,005,875	for up to US$200 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(i)
May	947,638	-	US$22.39	-	23,690,950	for up to US$200 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(i)
June	-	-	-	-	-	-	-
July	-	-	-	-	-	-	-
August	2,254,450	-	US$15.41	-	56,361,250	for up to US$65 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(ii)
September	633,175	-	US$13.08	-	15,829,375	for up to US$65 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(ii)
October	1,276,598	-	US$15.43	-	31,914,950	for up to US$65 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(ii)
November (until 11-8)	143,469	-	US$15.17	-	3,586,725	for up to US$65 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(ii)
November	1,013,435	-	US$13.14	-	25,335,875	for up to US$50 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(iii)
December	195,516	-	US$13.12	-	4,887,900	for up to US$50 million, or any lower amount resulting in such acquisition reaching 10% of our capital stock.	(iii)

(*) Each ADS represents 25 common shares.                                                                                                                                                         

 (i) Our Board of Directors approved on June 22, 2018 the Repurchase Program II with the purpose of contributing to the reduction of the gap between the Company's fair value based on its assets value and the price of the shares in the stock exchange, seeking to contribute to the market’s strengthening by efficiently applying the Company’s strong cash position. According to the following terms and conditions: (a) Maximum Amount to Invest: Up to US$200,000,000; (b) Maximum amount of Pampa shares or maximum percentage of Pampa capital stock subject to the acquisition: an amount that will never surpass the 10% of our capital stock limit at the time of the acquisition of the Pampa shares, as per the applicable law; (c) Price Per Share: Up to Ps. 62 per share in BYMA and up to US$55 per ADR in the NYSE; and (d) Period in which the acquisitions will be performed: a 120 day period, counted as from the business day following the one when the repurchase is published in the communications media to the market and subject to any renewal or extension of the term that will be duly informed. As of the date of this annual report, this program has expired.

(ii) On August, 12, 2019, our Board of Directors approved the Repurchase Program IV in accordance with Section 64 of the CML and the CNV rules with the purpose of contributing to the reduction of the gap between the Company's fair value based on its assets value and the quoted price from the stock exchange, seeking to contribute to the market’s strengthening by efficiently applying the Company’s strong cash position. According to the following terms and conditions: (a) Maximum Amount to Invest: Up to US$50,000,000; (b) Maximum amount of Pampa shares or maximum percentage of Pampa capital stock subject to the acquisition: an amount that will never surpass the 10% of our capital stock limit at the time of the acquisition of the Pampa shares, as per the applicable law; (c) Price Per Share: Up to the equivalent of US$.1 in Argentine Pesos per share in ByMA and up to US$.25 per ADR in the NYSE; and (d) Period in which the acquisitions will be performed: a 120 day period, counted as from the business day following the one when the repurchase is published in the communications media to the market and subject to any renewal or extension of the term that will be duly informed. As of the date of this annual report, this program has expired. On August 30, 2019, our Board of Directors approved the extension of the maximum amount to be disbursed under the Repurchase Program IV from US$50 million to US$65 million.

(iii) On November 8, 2019, our Board of Directors approved the Repurchase Program V in accordance with Section 64 of the CML and CNV rules that will be destined to cover our Stock-based Compensation Plan, according to the following terms and conditions: (a) Maximum Amount to Invest: Up to Ps. 50,000,000; (b) Maximum amount of Pampa shares or maximum percentage of Pampa capital stock subject to the acquisition: an amount that will never surpass the 10% of our capital stock limit at the time of the acquisition of the Pampa shares, as per the applicable law; (c) Price Per Share: Up to the equivalent of US$.0.58 in Argentine Pesos per share in ByMA and up to US$14.50 per ADR in the NYSE; and (d) Period in which the acquisitions will be performed: a 120 day period, counted as from the business day following the one when the repurchase is published in the communications media to the market and subject to any renewal or extension of the term that will be duly informed. As of the date of this annual report, this program has expired.

233

 

For more information, please see “Item 6. Directors, Senior Management and Employees—Stock-based Compensation Plan” and “Item 9. The Offer and Listing—Repurchase of Pampa’s Shares”.

234

 

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.
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 who does any of the following is not independent: (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;

235

 

CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
		(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);

236

 

CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
		(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.

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CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
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.
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.

238

 

CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
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.

239

 

CORPORATE GOVERNANCE PRACTICES COMPARATIVE TABLE
NYSE REQUIREMENTS for DOMESTIC COMPANIES		REQUIREMENTS AND OUR PRACTICES
NYSE LCM	DESCRIPTION	DESCRIPTION
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.
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.

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Item 17. Financial Statements

Not applicable.

Item 18. Financial Statements

Our Consolidated Financial Statements are included in this annual report beginning on page F-1.

Additionally, for the year ended December 31, 2018, CIESA was a significant 50 percent or less owned person pursuant to Rule 3-09 of Regulation S-X. CIESA is the holding company of TGS. Financial statements of CIESA have been excluded because all of its operations are conducted through TGS. As of December 31, 2018, cash and cash equivalents of CIESA amounted to Ps. 813 million, and the other assets (other than its investment in TGS), other liabilities and income and expenses are inconsequential.

We have included TGS’s audited consolidated statements of financial position as of December 31, 2019 and 2018, and the related consolidated statements of comprehensive income, changes in equity and cash flows for each of the years in the three-year period ended December 31, 2019, and the notes thereto beginning on page F-196 of this Annual Report. As TGS´s consolidated statements were prepared in Pesos, TGS’s summarized financial data in U.S. Dollar that is Pampa´s reporting currency, is presented in the following table:

	2019	2018	2017
	(in millions of US$)
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
Non-current assets	1,247	996	880
Current assets	350	595	272
Total assets	1,597	1,591	1,152
Equity attributable to owners of the company	803	795	649
Non-controlling interest	-	-	-
Total equity	803	795	649
Non-current liabilities	661	613	326
Current liabilities	133	183	177
Total liabilities	794	796	503
Total liabilities and equity	1,597	1,591	1,152
	For the year ended December 31,
	2019	2018	2017
	(in millions of US$)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Revenues	811	875	513
Gross profit	404	459	206
Operating profit	330	366	159
Net income and total comprehensive income for the year	214	293	148
Net income and total comprehensive Income of the year attributable to:
Owners of the company	214	293	148
Non - controlling interest	-	-	-

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.18995818) on August 7, 2018 and incorporated by reference herein.)
2.1	Form of Amended and Restated Deposit Agreement among the Registrant, JPMorgan Chase Bank, N.A.as successor Depositary thereunder (previously filed as Exhibit 2.1 to our Registration Statement on Form 20-F (File No. 333-216157) on February 22, 2017 and incorporated by reference herein.)
2(d)	Description of Securities
8.1	List of significant subsidiaries of Pampa
12.1	Certification of Gabriel Cohen, Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2	Certification of Gustavo Mariani, Chief Executive Officer pursuant to Section 906 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 March 5, 2020.
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.

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SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Pampa Energía S.A.

By: /s/ Gustavo Mariani

Name:  Gustavo Mariani
Title:     Chief Executive Officer

By: /s/ Gabriel Cohen

Name:  Gabriel Cohen
Title:     Chief Financial Officer

Date: April 30, 2020

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CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2019 AND 2018, AND

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(In millions of U.S. dollar (“U$S”))

F-1

 

INDEX TO FINANCIAL STATEMENTS
Pampa Energía S.A.
Consolidated Financial Statements as of December 31, 2019 and 2018, and for the Years Ended December 31, 2019, 2018 and 2017
Report of Independent Registered Public Accounting Firm	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 theBoard 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 positionof Pampa Energía Sociedad Anónima (Pampa Energía S.A.) and its subsidiaries(the “Company”)as of December 31, 2019 and 2018,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, 2019, 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, 2019, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019in 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, 2019, 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 the Management’s Annual Report on Internal Control over Financial Reporting appearing under item 15.  Our responsibility is to express opinions on the Company’s consolidatedfinancial 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 consolidatedfinancial 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 consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial 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 consolidatedfinancial 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 consolidatedfinancial 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.

F-3

 

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 beloware mattersarising 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 theconsolidated 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 consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Estimates of Oil and Gas Reserves on Proved Oil and Gas property, plant and equipment and allocated goodwill.

As described in Note 7 and 11.2 to the consolidated financial statements, as of December 31, 2019, the Company’s consolidated net book value of property, plant and equipment balance of the Oil and gas segment was $612 million, the goodwill balance allocated to the oil and gas segment was $35 million, and depreciation expense for the year ended December 31, 2019 was $112 million. As described in Note 6.1.9 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 oil and gas segment. There are numerous uncertainties in estimating proved 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, including reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors. The Company’s 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 proved oil and gas property, plant and equipment and allocated goodwillare a critical audit matter are that there was 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, including future production profiles, development costs and prices. 

F-4

 

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, including 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 natural gas.

Change in Functional Currency

As described in Note 3.1 to the consolidated financial statements, the Company changed its functional and presentation currencies from the Peso to the U.S. dollar commencing on January 1, 2019 following a change in facts and circumstances relevant to its business operations. The functional currency is the currency of the primary economic environment in which the entity operates. According to IAS 21 The effects of changes in foreign exchange rates, an entity is required to consider primary and secondary indicators to determine its functional currency. Primary indicators are the currency that mainly influences sales prices for its goods and services and labor, material and other costs of providing those goods and services. Secondary and other indicators provide supporting evidence to determine an entity’s functional currency. When the indicators are mixed and the functional currency is not obvious, management uses its judgement to determine the functional currency that most faithfully represents the economic effects of the underlying transactions, events and conditions.

The principal considerations for our determination that performing procedures relating to the change in functional currency is a critical audit matter are that there was significant judgment by management to determine the functional currency that most faithfully represents the economic effects of the underlying transactions, events and conditions, which in turn led to a high degree of auditor judgment, subjectivity and audit effort to address this matter due to its pervasive nature and impact on the consolidated financial statements of the Company. 

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 the Period-end Financial Reporting process and disclosures. These procedures also included, among others, obtaining and evaluating the reasonableness of management’s assessment of primary and other indicators and evaluating the sufficiency of the Company’s disclosures in the consolidated financial statements regarding the facts and circumstances that led to a change in its functional currency.

Acquisition of investment in a Joint Venture over CT Barragan S.A.

As described in Notes 4.4.5 and 5.3.5.1 to the consolidated financial statements, the Company completed the acquisition of a joint venture over CT Barragan S.A. (“CTB”) for a net consideration of US$272 million. Management applied significant judgment in estimating the fair value of the assets acquired and the liabilities assumed, which involved the use of significant estimates and assumptions with respect to the depreciated replacement of property, plant and equipment items and inventories. Depreciated replacement cost of property, plant and equipment items and inventories was calculated with the assistance of independent specialists engaged by management. Also, management applied significant judgment in estimating the recoverable value of the asset through the estimation of weighted present value of future cash flows projections.

F-5

 

The principal considerations for our determination that performing procedures relating to the acquisition of CTB is a critical audit matter are: (i) there was significant judgment by management in estimating the fair value of the assets acquired and the liabilities assumed, including the use of specialists, when developing the depreciated replacement cost of property, plant and equipment items and inventories estimate; (ii) there was significant judgment by management in estimating the recoverable value of the asset through the estimation of weighted present value of future cash flows projections; (iii) there was a high degree of auditor judgment and subjectivity in applying procedures relating to the fair value measurement of assets acquired and liabilities assumed due to the significant judgments made by management when developing the estimate; (iv) significant audit effort was required in evaluating the significant assumptions relating to the estimate of the depreciated replacement cost of property, plant and equipment items and inventories and timing and amounts of cash flow projections; and (v) 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 the acquisition accounting, including controls over management’s valuation of the assets acquired and liabilities assumed and controls over development of the assumptions related to the estimate of the depreciated replacement cost of property, plant and equipment items and inventories and timing and amounts of cash flow projections. These procedures also included, among others, (i) reading the purchase agreement; (ii) testing management’s process for estimating the fair value of assets acquired and liabilities assumed; (iii) testing management’s estimate of the depreciated replacement cost of property, plant and equipment items and inventories and timing and amounts of cash flow projections, using professionals with specialized skill and knowledge to assist in doing so; and (iv) assessing the independent specialist’s report over the depreciated replacement cost of property, plant and equipment items and inventories. Testing management’s process included evaluating the appropriateness of the valuation methods and the reasonableness of significant assumptions.

Impairment of Non-Financial Long-Lived Assets related to Oil and gas, Generation and Distribution segments

As described in Notes 7, 11.1 and 11.2 to the consolidated financial statements, as of December 31, 2019, the Company’s consolidated property, plant and equipment balance related to Oil and gas, Generation and Distribution segments was $3,455 million, the goodwill balance allocated to the oil and gas segment was $35 million, and the intangible asset related to concession agreements allocated to the distribution segment was $111 million. According to Note 11.1.1, as of December 31, 2019 there were internal and external impairment indicators and certain negative changes those segments. Management analyzes the recoverability of its non-financial long-lived assets on a periodical basis or when events or changes in circumstances indicate their recoverable amount, which are measured as the higher of value in use and fair value less costs of disposal at the end of the year, may be below its carrying amount. The value in use is determined based on projected and discounted cash flows, using discount rates that reflect the time value of money and the specific risks of the assets considered. The discount rate used to discount future net cash flows is the WACC, which was determined considering the business segment and the country conditions where the operations are performed. In order to calculate the fair value less the costs of disposal, management uses the estimated value of the future cash flows that a market participant could generate and deducts the necessary costs to carry out the sale of the corresponding cash generating unit. Management’s cash flow projections included significant judgments and assumptions relating to future prices and rates schemes, future demand, costs, the discount rate, among others.

The principal considerations for our determination that performing procedures relating to the impairment assessment of non-financial long-lived assetsrelated to Oil and gas, Generation and Distribution segments is a critical audit matter are that there was significant judgment by management 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 cash flow projections and significant assumptions, including, among others, future prices and rates schemes, future demand, costs, and the discount rate. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist us in performing these procedures and evaluating the audit evidence obtained.

F-6

 

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, testing management’s process for developing the value in use estimate; evaluating the appropriateness of the discounted cash flow model; testing the completeness, accuracy, and relevance of underlying data used in the model; and evaluating the significant assumptions used by management. 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 us in the evaluation of the Company’s discounted cash flow model and certain significant assumptions, including the discount rate.

/s/ PRICE WATERHOUSE & CO. S.R.L.

Reinaldo Sergio Cravero (Partner)

Autonomous City of Buenos Aires, Argentina, March 9, 2020.

We have served as the Company’s auditor since 2006.

F-7

 

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
BCBA	Buenos Aires Stock Exchange
BLL	Bodega Loma La Lata S.A.
BNA	Banco de la Nación Argentina
BO	Official Gazette
ByMA	Argentine stock exchange and markets
CABA	Ciudad Autónoma de Buenos Aires
CAMMESA	Compañía Administradora del Mercado Eléctrico Mayorista S.A.
CAU	Charge of Access Use
CC	Combined Cycle
CEE	Comité Ejecutivo de Emergencia
CGU	Cash-Generating Unit
CIESA	Compañía de Inversiones de Energía S.A.
Citelec	Compañía Inversora en Transmisión Eléctrica Citelec S.A.
CMIDE	Average Incremental Charge of Surplus Demand
CNCD	Comisión Nacional de Defensa de la Competencia
CNV	Comisión Nacional de Valores
Corod	Corod Producción S.A.
CPB	Central Térmica Piedra Buena S.A.
CPD	Own Distribution Costs
CSJN	Corte Suprema de Justicia de la Nación
CTB	CT Barragán S.A. (formerly PEA)
CTEB	Central Térmica Enseada Barragán
CTG	Central Térmica Güemes S.A.

F-8

 

GLOSSARY OF TERMS:(Continuation)
Terms	Definitions
CTGEBA	Central Térmica Genelba
CTLL	Central Térmica Loma La Lata S.A.
CTP	Central Térmica Piquirenda
EBISA	Emprendimientos Energéticos Binacionales S.A.
EcuadorTLC	EcuadorTLC S.A.
Edenor	Empresa Distribuidora y Comercializadora Norte S.A.
Edesur	Empresa Distribuidora Sur S.A.
Eg3 Red	Eg3 Red S.A.
EGSSA	EMDERSA Generación Salta S.A.
ENARGAS	National Regulator of Gas
ENARSA / IEASA	Integración Energética Argentina S.A. (formerly Energía Argentina S.A.)
ENRE	National Regulatory Authority of Electricity
FACPCE	Federación Argentina de Consejos Profesionales de Ciencias Económicas
FGS – ANSES	Fondo de Garantía de Sustentabilidad – Administración Nacional de la Seguridad Social
FOTAE	Works Administration Trust Transport for Electricity Supply
GE	General Electric
Greenwind	Greenwind S.A.
GUMA, GUME, GUDI	Gran Usuario Mayor, Gran Usuario Menor, Gran Usuario del Distribuidor
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

F-9

 

GLOSSARY OF TERMS:(Continuation)
Terms	Definitions
IGJ	Inspección General de Justicia - General Inspection of Justice
IGMP	Minimum Notional Income Tax
INDEC	Instituto Nacional de Estadística y Censos
INDISA	Inversora Diamante S.A.
INNISA	Inversora Nihuiles S.A.
IPB	Inversora Piedra Buena S.A.
IPIM	Índice de Precios Internos al por Mayor
LGS	Commercial Companies General Law No. 19,550 as amended
LNG	Liquefied Natural Gas
LVFVD	Sales Liquidations with Maturity Date to be Defined
MAT	WEM’s Forward Market
MEyM	Ministry of Energy and Mining
MINEM	Ministerio de Energía y Minas
NYSE	New York Stock Exchange
OCP	Oleoducto de Crudos Pesados
OED	Organismo Encargado del Despacho
Oldelval	Oleoductos del Valle S.A.
PACOSA	Pampa Comercializadora S.A.
PBA	Buenos Aires province
PDVSA	Petróleos de Venezuela S.A.
PEB	Pampa Energía Bolivia S.A. (formerly “PBI” - Petrobras Bolivia Internacional S.A.)
PELSA	Petrolera Entre Lomas S.A.
PEN	Federal Executive Power
PEPASA	Petrolera Pampa S.A.
Petrobras	Petrobras Argentina S.A.
PHA	Petrobras Hispano Argentina S.A.

F-10

 

GLOSSARY OF TERMS:(Continuation)
Terms	Definitions
PISA	Pampa Inversiones S.A.
PIST	Transportation System Entry Point
PP	Pampa Participaciones S.A.U.
PP II	Pampa Participaciones II S.A.
PPSL	Petrobras Participaciones S.L.
RDSA	Ribera Desarrollos S.A.
Refinor	Refinería del Norte S.A.
RENPER	National Registry of Renewable Source Electric Power Generation Projects
RT	Technical Resolution
RTI	Tariff Structure Review
RTT	Temporary Tariff Regime
SE	Secretary of Energy
SEC	Security and Exchange Commission
SEE	Secretary of Electrical Energy
SGE	Secretary of Government of Energy
SRRYME	Secretary of Renewable Resources and Electricity Market
SSERYEE	Undersecretary of Renewable Energy and Energy Efficiency
SSHC	Undersecretary of Hydrocarbons and Fuels
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	Buenos Aires Transba S.A.
Transelec	Transelec Argentina S.A.

F-11

 

GLOSSARY OF TERMS:(Continuation)
Terms	Definitions
Transener	Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.
TV	Vapor Turbine
U$S	U.S. dollar
UTE Senillosa	Petrolera Pampa S.A. – Rovella Carranza – Gas y Petróleo del Neuquén, Unión Transitoria de Empresas Senillosa
VAD	Distribution Added Value
VAT	Value Added tax
WACC	Weighted Average Cost of Capital
WEM	Wholesale Electricity Market
YPF	YPF S.A.

F-12

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2019, 2018 and 2017

(In millions of U$S – unless otherwise stated)

	Note	12.31.2019	12.31.2018	12.31.2017
Revenue	8	2,836	2,920	2,175
Cost of sales	9	(2,032)	(1,967)	(1,574)
Gross profit		804	953	601
Selling expenses	10.1	(148)	(171)	(127)
Administrative expenses	10.2	(174)	(206)	(198)
Exploration expenses	10.3	(9)	(1)	(2)
Other operating income	10.4	40	181	149
Other operating expenses	10.4	(86)	(200)	(103)
Impairment of property, plant and equipment	11.1.1	(62)	(32)	-
Share of profit from associates and joint ventures	5.3.2	101	118	48
Income from the sale of associates	5.1.2.2	-	28	-
Agreement on the regularization of obligations	2.3.4	285	-	-
Operating income		751	670	368
Gain on monetary position, net	10.5	187	629	304
Finance income	10.5	96	99	62
Finance costs	10.5	(299)	(316)	(232)
Other financial results	10.5	113	(858)	(100)
Financial results, net		97	(446)	34
Profit before income tax		848	224	402
Income tax	10.6	(48)	(17)	26
Profit of the year from continuing operations		800	207	428
Profit (loss) of the year from discontinued operations	5.2.3	-	80	(50)
Profit of the year		800	287	378
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans		2	(4)	-
Income tax		-	1	-
Share of loss from joint ventures		-	(1)	-
Exchange differences on translation		(15)	-	-
Items that may be reclassified to profit or loss
Exchange differences on translation		(22)	1	3
Other comprehensive income (loss) of the year from continuing operations		(35)	(3)	3
Other comprehensive income of the year from discontinued operations	5.2.3	-	8	(14)
Other comprehensive income (loss) of the year		(35)	5	(11)
Total comprehensive income of the year		765	292	367

F-13

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(In millions of U$S – unless otherwise stated)

	Note	12.31.2019	12.31.2018	12.31.2017
Total income of the year attributable to:
Owners of the company		692	224	286
Non - controlling interest		108	63	92
		800	287	378
Total income (loss) of the year attributable to owners of the company:
Continuing operations		692	146	341
Discontinued operations		-	78	(55)
		692	224	286
Total comprehensive income of the year attributable to:
Owners of the company		672	225	281
Non - controlling interest		93	67	86
		765	292	367
Total comprehensive  income (loss) of the year attributable to owners of the company:
Continuing operations		672	141	343
Discontinued operations		-	84	(62)
		672	225	281
Earnings per share attributable to the equity holders of the company during the year
Basic and diluted earnings per share from continuing operations	13.2	14.42	2.81	6.69
Basic and diluted earnings (loss) per share from discontinued operations	13.2	-	1.50	(1.07)
Total basic and diluted earnings per share	13.2	14.42	4.31	5.61

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-14

 

CONSOLIDATEDSTATEMENT OF FINANCIAL POSITION

As of December 31, 2019 and 2018

(In millions of U$S – unless otherwise stated)

	Note	12.31.2019	12.31.2018
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment	11.1	3,507	3,316
Intangible assets	11.2	151	161
Right-of-use assets	18.1.1	16	-
Deferred tax assets	11.3	28	2
Investments in joint ventures and associates	5.3.2	511	407
Financial assets at amortized cost	12.1	18	-
Financial assets at fair value through profit and loss	12.2	11	11
Other assets		1	1
Trade and other receivables	12.3	79	253
Total non-current assets		4,322	4,151
CURRENT ASSETS
Inventories	11.4	153	137
Financial assets at amortized cost	12.1	54	35
Financial assets at fair value through profit and loss	12.2	365	405
Derivative financial instruments		4	-
Trade and other receivables	12.3	561	703
Cash and cash equivalents	12.4	225	241
Total current assets		1,362	1,521
Total assets		5,684	5,672

F-15

 

CONSOLIDATEDSTATEMENT OF FINANCIAL POSITION

As of December 31, 2019 and 2018 (Continuation)

(In millions of U$S – unless otherwise stated)

	Note	12.31.2019	12.31.2018
SHAREHOLDERS´ EQUITY
Share capital		46	50
Share capital adjustment		260	260
Share premium		510	491
Treasury shares		1	-
Treasury shares adjustment		1	4
Treasury shares cost		(44)	(39)
Legal reserve		42	24
Voluntary reserve		422	195
Other reserves		(18)	(13)
Retained earnings		726	403
Other comprehensive income		(29)	(9)
Equity attributable to owners of the company		1,917	1,366
Non-controlling interest		492	429
Total equity		2,409	1,795
LIABILITIES
NON-CURRENT LIABILITIES
Investments in joint ventures  and associates	5.3.2	4	4
Provisions	11.5	145	146
Income tax and minimum notional income tax provision	11.6	10	27
Deferred revenue		5	7
Taxes payables	11.7	4	14
Deferred tax liabilities	11.3	368	407
Defined benefit plans	11.8	27	31
Salaries and social security payable	11.9	4	4
Borrowings	12.5	1,764	1,835
Trade and other payables	12.6	90	220
Total non-current liabilities		2,421	2,695
CURRENT LIABILITIES
Provisions	11.5	20	23
Income tax and minimum notional income tax provision	11.6	53	29
Taxes payables	11.7	72	54
Defined benefit plans	11.8	4	4
Salaries and social security payable	11.9	65	72
Derivative financial instruments		3	1
Borrowings	12.5	183	342
Trade and other payables	12.6	454	657
Total current liabilities		854	1,182
Total liabilities		3,275	3,877
Total liabilities and equity		5,684	5,672

       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, 2019, 2018 and 2017

(In millions of U$S – 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 (1)	Other comprehensive income / (loss)	Retained earnings (Accumulated losses)	Subtotal	Non-controlling interest	Total equity
Balance as of December 31, 2016	51	287	421	-	-	-	15	250	9	(4)	114	1,143	464	1,607
Constitution of legal reserve - Shareholders’ meeting 04.07.2017	-	-	-	-	-	-	4	-	-	-	(4)	-	-	-
Constitution of voluntary reserve - Shareholders’ meeting 04.07.2017	-	-	-	-	-	-	-	83	-	-	(83)	-	-	-
Stock compensation plans	-	-	1	-	-	-	-	-	1	-	-	2	-	2
Acquisition of own shares	-	-	-	-	-	(3)	-	-	-	-	-	(3)	-	(3)
Merger with subsidiaries (Note 5.1.1.1)	4	2	69	-	-	-	-	-	-	-	-	75	(75)	-
Dividends provided for pay	-	-	-	-	-	-	-	-	-	-	-	-	(4)	(4)
Profit of the year	-	-	-	-	-	-	-	-	-	-	286	286	92	378
Other comprehensive income for the year	-	-	-	-	-	-	-	-	-	(6)	-	(6)	(5)	(11)
Balance as of December 31, 2017	55	289	491	-	-	(3)	19	333	10	(10)	313	1,497	472	1,969
Change in accounting policies  (2)	-	-	-	-	-	-	-	-	-	-	(1)	(1)	(1)	(2)
Balance as of Juanary 1, 2018	55	289	491	-	-	(3)	19	333	10	(10)	312	1,496	471	1,967
Constitution of legal reserve - Shareholders’ meeting 04.27.2018	-	-	-	-	-	-	5	-	-	-	(5)	-	-	-
Constitution of voluntary reserve - Shareholders’ meeting 04.27.2018	-	-	-	-	-	-	-	128	-	-	(128)	-	-	-
Stock compensation plans	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Acquisition of own shares (Note 13.1.1.2)	(5)	(29)	-	5	29	(332)	-	-	(23)	-	-	(355)	(14)	(369)
Dividends provided for pay	-	-	-	-	-	-	-	-	-	-	-	-	(2)	(2)
Capital reduction (Note 13.1.1)	-	-	-	(5)	(25)	296	-	(266)	-	-	-	-	-	-
Sale of interest in subsidiaries	-	-	-	-	-	-	-	-	-	-	-	-	(93)	(93)
Profit for the year	-	-	-	-	-	-	-	-	-	-	224	224	63	287
Other comprehensive income for the year	-	-	-	-	-	-	-	-	-	1	-	1	4	5
Balance as of December 31, 2018	50	260	491	-	4	(39)	24	195	(13)	(9)	403	1,366	429	1,795

F-17

 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Continuation)

For the years ended December 31, 2019, 2018 and 2017

(In millions of U$S – 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 (1)	Other comprehensive loss	Retained earnings	Subtotal	Non-controlling interest	Total equity
Balance as of December 31, 2018	50	260	491	-	4	(39)	24	195	(13)	(9)	403	1,366	429	1,795
Constitution of legal and voluntary reserve - Shareholders’ meeting 04.29.2019	-	-	-	-	-	-	18	351	-	-	(369)	-	-	-
Stock compensation plans	-	-	-	-	-	-	-	-	1	-	-	1	-	1
Dividends provided for pay	-	-	-	-	-	-	-	-	-	-	-	-	(1)	(1)
Acquisition of own shares (Note 13.1.1.2)	(4)	-	19	4	-	(135)	-	-	(6)	-		(122)	(29)	(151)
Capital reduction (Note 13.1.1)	-	-	-	(3)	(3)	130	-	(124)	-	-	-	-	-	-
Profit for the year	-	-	-	-	-	-	-	-	-	-	692	692	108	800
Other comprehensive loss for the year	-	-	-	-	-	-	-	-	-	(20)	-	(20)	(15)	(35)
Balance as of December 31, 2019	46	260	510	1	1	(44)	42	422	(18)	(29)	726	1,917	492	2,409

⁽¹⁾Includes the result of operations with non-controlling interests that do not represent a loss of control and reserves for stock-based compensation plans

⁽²⁾Adjustment to the opening balance in equity as a result of the application of IFRS 9, as amended, as of January 1, 2018. See Note 6.2.1.2

The accompanying notes are an integral part of these Consolidated Financial Statements.

F-18

 

CONSOLIDATEDSTATEMENT OF CASH FLOWS

For the years ended December 31, 2019, 2018 and 2017

(In millions of U$S – unless otherwise stated)

	Note	12.31.2019	12.31.2018	12.31.2017
Cash flows from operating activities:
Profit of the year from continuing operations		800	207	428
Profit (loss) of the year  from discontinued operations		-	80	(50)
Adjustments to reconcile net profit (loss) to cash flows generated by operating activities:	14.1	(30)	622	151
Changes in operating assets and liabilities	14.2	32	(253)	(177)
Net cash used in operating activities from discontinued operations	5.2.3	-	(46)	87
Net cash generated by operating activities		802	610	439
Cash flows from investing activities
Payment for property, plant and equipment		(582)	(674)	(485)
Collection (payment) for financial assets		217	(31)	(109)
Payments for capital integration in associates and joint ventures		(108)	-	-
Proceeds from sale of intangible assets		-	2	-
Collections for sales of shares in companies and property, plant and equipment		42	457	15
Dividends received		87	19	1
Colletion (proceeds) from loans		7	(4)	1
Recovery of investment funds, net		(32)	250	(219)
Net cash used in investing activities from discontinued operations	5.2.3	-	-	(50)
Net cash (used in) generated by investing activities		(369)	19	(846)
Cash flows from financing activities:
Proceeds from borrowings	12.5	556	245	1,250
Payment of  borrowings	12.5	(550)	(240)	(733)
Payment of  borrowings interests	12.5	(148)	(133)	(108)
Payment for acquisition of own shares		(151)	(369)	(3)
Payments of dividends from subsidiaries to third parties		(1)	(2)	(2)
Repurchase and redemption of corporate bonds	12.5	(91)	(13)	(1)
Payments of leases		(5)	-	-
Net cash generated by (use in) financing activities from discontinued operations	5.2.3	-	42	(31)
Net cash (used in) generated by financing activities		(390)	(470)	372
Increase (decrease) in cash and cash equivalents		43	159	(35)
Cash and cash equivalents at the begining of the year	12.4	241	31	69
Cash and cash equivalents at the begining of the year reclasified to assets classified as held for sale	5.2.3	-	6	(6)
Exchange difference generated by cash and cash equivalents		(59)	53	14
Loss on net monetary position generated by cash and cash equivalents		-	(8)	(11)
Increase (decrease) in cash and cash equivalents		43	159	(35)
Cash and cash equivalents at the end of the year	12.4	225	241	31

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, 2019, 2018 and 2017

 (In millions of U$S – unless otherwise stated)

NOTE 1: GENERAL INFORMATION AND GROUP STRUCTURE

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, has a 4,751 MW installed capacity, which represents approximately 12% of Argentina’s installed capacity, and is the second largest independent generator in the country. Additionally, the Company is currently undergoing a process to expand its capacity by 471 MW.

In the distribution segment, the Company has a controlling interest in Edenor, the largest electricity distributor in Argentina, which has more than 3.1 million customers and a concession area covering the Northern part of the City of Buenos Aires and Northwestern Greater Buenos Aires.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, with operations in 12 production areas and 6 exploratory areas reaching a production level of 7.3 million m3/day of natural gas and 5,000 barrels/day of oil equivalent for oil in Argentina, as of December 31, 2019. Its main natural gas production blocks are located in the Provinces of Neuquén and Río Negro. The results and cash flows for 2018 and 2017 associated with the divestment mentioned in Note 5.2.1 are disclosed under discontinued operations.

In the petrochemicals segment, operations are located in the Republic of Argentina, where the Company operates three high-complexity plants producing styrene, synthetic rubber and polystyrene, with a domestic market share ranging between 89% and 100%.

Finally, through the holding and others segment, the Company participates in the transmission and gas transportation businesses. In the transmission business, the Company jointly controls Citelec, which has a controlling interest in Transener, a company engaged in the operation and maintenance of a 20,981 km high-voltage electricity transmission network in Argentina with an 85% 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 9,231 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. Additionally, the segment includes advisory services provided to related companies.

The results and cash flows for 2018 and 2017 associated with the divestment of the main assets of the refining and distribution segment mentioned in Note 5.2.2 are disclosed under discontinued operations in the Holding and others segment.

F-20

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 1: (Continuation)

1.2Economic context in which the Company operates

The Company operates in a complex economic context which main variables have recently suffered significant volatility both in the domestic and international spheres.

At the domestic level, a 2.5% year-on-year drop in the GDP was recorded in the first semester of 2019, cumulative inflation in 2019 reached 53.8% (IPC), and the significant devaluation of the peso as from August generated an unexpected draining of dollar-denominated deposits from the financial system (and, consequently, a drop in BCRA’s reserves) and an increase in the benchmark interest rate, which came to exceed 80% over the year (and being at about 60% as of the closing hereof).

On December 10, 2019 a new Federal Government took office, which declared a public emergency in economic, financial, fiscal, administrative, pension, tariff, energy, health and social matters until December 31, 2020 and implemented a series of measures, which are summarized below:

- The delegation to the PEN of the power to maintain electricity and gas tariffs which are under federal jurisdiction, and to begin a process for the renegotiation or an extraordinary review of the current RTI, for a term of 180 days, with the purpose of reducing the actual tariff burden on households, businesses and industries for 2020;

- The delegation to the PEN of the power to conduct an administrative intervention of the ENRE and the ENARGAS for a term of one year;

- The suspension of the application of section 124, second paragraph, of Law No. 27,467, which divested the ENRE, effective as from Edenor and Edesur’s transfer to the jurisdiction of the Province of Buenos Aires and the Autonomous City of Buenos Aires, of its powers and functions associated with the electricity distribution utility, which powers it will keep for a year;

- The establishment of a regime for the regularization of tax, social security and customs obligations for micro, small and middle-sized companies;

- The suspension of the unification of employer contribution rates;

- The PEN’s capacity to provide for mandatory minimum salary increases in the private sector (with the temporary exemption from the payment of contributions to the Argentine social security system of the salary increases granted under this capacity or under collective bargaining agreements);

- The suspension until fiscal years starting on or after January 1, 2021 of the decrease in the income tax rate, which will remain at 30%, and the keeping of the 7% withholdings on dividends during such period (see Note 2.6.1.2);

F-21

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 1: (Continuation)

- The setting of a new mechanism for allocating the tax inflation adjustment for the first and second fiscal years starting on or after January 1, 2019 (see Note 2.6.1.5);

- An increase in export duties (with the exception of hydrocarbons and mining) and in personal assets tax rates;

- The reinstatement of the value-added tax on basic food basket products and the suspension of the pension mobility;

- The modification of the schedular taxation system and the restoration of income tax exemptions for certain securities and bonds;

- The creation of the Tax for an Inclusive and Supportive Argentina (PAIS) for a term of five fiscal periods.

- The extended life of BCRA’s regulations regarding the inflow and outflow of foreign exchange in the foreign exchange market.

Additionally, the Federal Government is preparing a proposal for the renegotiation of the external debt with international creditors.

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 Consolidated 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 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, replaced by SRRYME Resolution No. 1/19 as from March 2019); 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.

F-22

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The Company’s generating units are detailed below:

In operation:
Generator	Generating unit	Tecnology	Power	Applicable regime (2)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1281/06 (1)
CTG	GUEMTV11	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV12	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV13	TV	>100 MW	SE Resolutions No. 1/19
Piquirenda	PIQIDI 01-10	MG	30 MW	SE Resolution No. 220/07 (1)
CPB	BBLATV29	TV	>100 MW	SE Resolutions No. 1/19
CPB	BBLATV30	TV	>100 MW	SE Resolutions No. 1/19
CT Ing. White	BBLMD01-06	MG	100 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATG01	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG02	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG03	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG04	TG	105 MW	SEE Res. 220/07 (75%), SEE Res. 1/19 (25%)
CTLL	LDLATG05	TG	105 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATV01	TV	180 MW	SE Resolution No. 220/07 (1)
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	SE Resolutions No. 1/19
CTGEBA	GEBATG03	TG	188 MW	Energy Plus Res. No. 1281/06 (1)
CTGEBA	GEBATG04	TG	>100 MW	SE Resolutions No. 1/19 (3)
Ecoenergía	CERITV01	TV	Renewable  = 50	Energy Plus Res. N° 1281/06 (1)
CT Parque Pilar	PILBD01-06	MG	100 MW	SE Resolutions No. 1/19 (3)
CTB	EBARTG01 - TG02	TG	HI – Small  50<P≤120	SE Resolution No. 220/07 (1)
HIDISA	AGUA DEL TORO	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	EL TIGRE	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	LOS REYUNOS	HB	HB – Media  120<P≤300	SE Resolutions No. 1/19
HINISA	NIHUIL I - II - III	HI	HI – Chica  50<P≤120	SE Resolutions No. 1/19
HPPL	PPLEHI	HI	HI – Media  120<P≤300	SE Resolutions No. 1/19
P.E. M. Cebreiro	CORTEO	Eólica	100 MW	Renovar (1)
PEPE II	PAMEEO	Eólica	53 MW	SEE Resolution No. 281/17
PEPE III	BAHIEO	Eólica	53 MW	SEE Resolution No. 281/17
(1) Uncommitted power and energy is remunerated according to Resolution No. 1/19.
(2) Resolution No. 1/19 entered into force as of February 19. During the month of January 2019, it was remunerated under Resolution No. 19/17.
(3) Once the combined cycle is commercially enabled, the supply agreements with CAMMESA will come into force under Resolution No. 287/17.
In construction:
Generator	Generating unit	Tecnology	Applicable regime
CTLL	MG	15 MW	SE Resolutions No. 1/19
CTGEBA	CC	176 MW	SE Resolution No. 287/17
CTB	CC	280 MW	SE Resolution No. 220/07

F-23

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.1.2 Remuneration at the Spot market

On February 2, 2017, the SEE issued Resolution No. 19/17, which superseded the remuneration scheme set forth by Resolution No. 22/16 and established guidelines for the remuneration to generation plants as from the commercial transaction corresponding to February 1, 2017.

Later, on March 1, 2019, SRRYME Resolution No. 1/19 was published in the BO, which abrogated, effective as from March 1, 2019, the remuneration scheme established by SEE Resolution No. 19/17.

Both resolutions provide for remunerative items based on technology and scale, establishing U$S-denominated prices payable in pesos by applying BCRA’s exchange rate effective on the last business day of the month of the applicable economic transaction, adjusted through credit or debit notes, as appropriate, to consider the BCRA’s exchange rate of the day before the expiration date, in accordance with CAMMESA’s procedures.

2.1.2.1 Remuneration for Available Power Capacity

2.1.2.1.1 Thermal Power Generators

The SEE Resolution No. 19/17 provides for a minimum remuneration for power capacity based on technology and scale and allows generating, co-generating and self-generating agents owning conventional thermal power stations to offer Guaranteed Availability Commitments for the energy and power capacity generated by their units not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA.

Availability Commitments for each unit should be declared for a term of three years, together with information for the Summer Seasonal Programming, with the possibility to offer different availability values for the summer and winter six-month periods. The committed thermal generators’ remuneration for power capacity will be proportional to their compliance.

The Minimum Remuneration applies to generators with no availability commitments, with prices ranging from U$S3,050 to U$S5,700/MW-month, depending on the technology and scale.

The Base Remuneration applies to generators with availability commitments, with a price of U$S 6,000/MW-month during the May-October 2017 period, and U$S 7,000/MW-month as from November 2017.

The Additional Remuneration is a remuneration for the additional available power capacity aiming to encourage availability commitments for the periods with a higher system demand. CAMMESA will define a monthly thermal generation goal for the set of qualified generators on a bi-monthly basis, and will call for additional power capacity availability offers with prices not exceeding the additional price. The additional price amounts to U$S 1,000/MW-month between May and October, 2017, and to U$S2,000/MW-month as from November 2017.

F-24

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The SRRYME Resolution No. 1/19 maintains in effect a remuneration made up of a minimum or base power capacity payment for generators with no availability commitments, and another for offered guaranteed power capacity, although with lower values than under the previous resolution:

- The minimum remuneration for power capacity was reduced from U$S 5,700/MW-month to U$S 5,200/MW-month for small steam turbine units (≤ 100MW) and internal combustion engines.

- The price of the remuneration for guaranteed power capacity decreased from U$S 7,000/MW-month to U$S 5,500 U$S/MW-month, only for the autumn and spring periods.

Furthermore, the current remuneration scheme, applies a coefficient derived from the unit’s average utilization factor during the last twelve months to the power capacity remuneration: a minimum 70% utilization factor is required to collect 100% of the power capacity payment; if the utilization factor ranges between 30% and 70%, the power capacity payment will range between 70% and 100%; and if the usage factor is lower than 30%, 70% of the power capacity payment will be collected. Additionally, Availability Commitments should be declared for each unit on a quarterly basis.

Finally, the current remuneration scheme, abrogates the additional remuneration scheme to encourage the guaranteed power capacity offered in the periods with a higher system demand.

2.1.2.1.2 Hydroelectric Generators

In the case of hydroelectric power plants, a base remuneration and an additional remuneration for power capacity were established by the SEE Resolution No. 19/17.

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 following is considered to calculate availability: i) the operation as turbine at all hours within the period, and ii) the availability as pump at off-peak hours every day and on non-business days.

The base remuneration is determined by the actual power capacity plus that under programmed and/or agreed maintenance, with prices ranging from U$S2,000 to U$S8,000/MW-month, depending on the scale and type of power plant.

In case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor will be applied to the plant at the headwaters.

The additional remuneration applies to power plants of any scale for their actual availability and based on the applicable period, with prices ranging from U$S0 to U$S500/MW-month between May and October 2017, and U$S500 or U$S1,000/MW-month as from November 2017 for pumping or conventional hydroelectric power plants, respectively.

As from November 2017, the allocation and collection of 50% of the additional remuneration will be conditional upon the generator taking out insurance, to CAMMESA’s satisfaction, to cover for major incidents on critical equipment, and the progressive updating of the plant’s control systems pursuant to an investment plan to be submitted based on criteria to be defined by the SEE.

F-25

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

SRRYME Resolution No. 1/19 maintains power capacity prices set forth by SEE Resolution No. 19/17; nevertheless, the hours in which a hydroelectric generator is not available due to programmed and agreed maintenance will no longer be computed for the calculation of the power capacity remuneration. However, in order to mitigate such incidence, in May 2019, by means of SME Note No. 46631495/19, a 1.05 factor was applied to power capacity prices.

2.1.2.1.3 Wind power

The remuneration under the SEE Resolution No. 19/17 is made up of a base price of U$S7.5/MWh and an additional price of U$S17.5/MWh, which are associated with the availability of the installed equipment with an operating permanence longer than 12 months as from the beginning of the summer seasonal programming.

Later on, SRRYME Resolution No. 1/19 establishes a single remuneration value for generated energy (see next item).

2.1.2.2 Remuneration for Generated and Operated Energy

The SEE Resolution No. 19/17 establishes a remuneration for Generated Energy with prices ranging between U$S5 and U$S10/MWh, depending on the technology, scale and type of fuel. Pursuant to SRRYME Resolution No. 1/19, these values are reduced to U$S 4/MWh and U$S 7/MWh, respectively.

Under the SEE Resolution No. 19/17, the remuneration for Operated Energy applies to the integration of hourly power capacities for the period, and is valued at U$S2.0/MWh for any type of fuel. Under the scheme set forth by SRRYME Resolution No. 1/19, the above-mentioned price is reduced to U$S 1.4/MWh.

In the case of hydroelectric plants, prices for Generated and Operated Energy under the SEE Resolution No. 19/17, are remuneratedU$S3.5 and U$S1.4/MWh, respectively regardless of scale. Under the scheme set forth by SRRYME Resolution No. 1/19, the above-mentioned prices are maintained.

As regards energy generated from unconventional sources, SRRYME Resolution No. 1/19 establishes a single remuneration value of U$S 28/MWh, irrespective of the source used. Energy generated prior to the commissioning by the OED will be remunerated at 50% of the above-mentioned remuneration.

2.1.2.3 Additional Remuneration for Efficiency and for Low-Use Thermal Generators

The “Efficiency” incentive established in the SEE Resolution No. 19/17 consists of the acknowledgment of an additional remuneration equivalent to the remuneration for the generated energy by the percentage difference between the actual consumption and the reference consumption determined for each unit and fuel type. This comparison will be made on a quarterly basis. In the case of higher consumptions, the general remuneration will not be affected.

F-26

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The mentioned Resolution also provides for an additional remuneration for low-use thermal generators having frequent startups based on the monthly generated energy for a price of U$S2.6/MWh multiplied by the usage/startup factor.

Under the scheme set forth by SRRYME Resolution No. 1/19, the efficiency and low-use/frequent startups incentives are canceled.

2.1.2.4 Repayment of Overhauls Financing

The SEE Resolution No. 19/17 provides that, as regards the repayment of outstanding loans applicable to thermal and hydroelectric generators, credits already accrued and/or committed to the cancellation of such maintenance works will be applied first. The balance will be repaid by discounting U$S1/MWh for the energy generated until the total cancellation of the financing.

Later on, as regards the repayment of funds supplied to generators under the loan agreements for the execution of overhauls in their units, SRRYME Resolution No. 1/19 provides for: (i) the application of all receivables accrued in favor of generators for their settlement, and (ii) a discount scheme in the generator’s revenues equivalent to U$S 1/MWh for each generated MW or U$S 700/MW-month for the unit’s actual availability, whichever is higher.

The overhauls financing owed by the Company were canceled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).

2.1.2.5 Suspension of contracts within the MAT

The suspension of contracts within the MAT (excluding those resulting from a differential remuneration scheme) provided for by SE Resolution No. 95/13 was not modified by SRRYME Resolution No. 1/19, this suspension thus remained in effect during 2019.

2.1.3 Sales contracts with large users within the MAT

2.1.3.1 Energy Plus

With the purpose of encouraging new generation works, in 2006 the SE approved Resolution No. 1,281/06 establishing a specific regime which would remunerate newly installed generation sold to a certain category of Large Users at higher prices.

F-27

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

To such effect, it established certain restrictions on the sale of electricity and implemented the Energy Plus service, which consists of the offer of additional generation availability by the generating agents. These measures imply that:

- Generating, co-generating and self-generating agents which, as of the date of issuance of SE Resolution No. 1,281/06, are neither WEM agents nor have facilities or an interconnection with the WEM, will qualify;

- 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.

Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 280 MW. The values of Energía Plus contracts are mostly denominated in U.S. dollars. It is worth pointing out that Güemes has transferred, since May 2019, its contracts to Genelba, selling electricity in the spot market.

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.

Furthermore, SE Note No. 567/07, as amended, provided that GU300 not purchasing their Surplus Demand within the MAT should pay the CMIDE, and that the difference between the actual cost and the CMIDE would be accumulated in an individual account on a monthly basis for each GU300 within CAMMESA's scope.

Pursuant to SE Note No. 111/16, until May 2018, the CMIDE was $ 650/MWh for GUMA and GUME and $ 0/MWh for GUDI. As from June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $ 1,200/MWh or the temporary dispatch surcharge. Additionally, it was provided that, until further instructed, movements in the individual account of each GU300 would temporarily not be recorded.

Due to the decrease in surplus demand as a consequence of the decrease in economic activity, there are GU300 that decide not to make Energy Plus contracts (with higher prices), and generators have to sell their energy at the spot market, thus reducing their profitability. Additionally, the Energy Plus contracts were affected by the growth of Renewable MAT contracts, by the GU300 surplus energy.

F-28

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.1.3.2 Renewable Energy Term Market (“Renewable MAT” Regime)

Pursuant to Resolution No. 281/17, the MEyM regulated the Renewable MAT 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 MAT of electric power from renewable sources or self-generation from renewable sources.

Furthermore, this resolution regulates the conditions applicable to projects for the generation, self-generation and co-generation of electric power from renewable sources. Specifically, the RENPER was created for the registration of such projects.

Projects destined to the supply of electric power from renewable sources under the Renewable MAT regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy will be sold in the spot market.

Finally, contracts executed under the Renewable MAT regime will be 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— may be freely agreed between the parties, although the committed electricity volumes will be 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.

For further information on the projects PEPE II and PEPE III conducted under this resolution, see Note 16.1.1.

2.1.4 Supply Agreements with CAMMESA

2.1.4.1 SE Resolution No. 220/07 (“Agreement Res.220”)

Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into 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 the investments made by the agent at a rate of return to be accepted by the SE.

Under this regulation, the Company, through its thermal power plants Loma de La Lata, Piquirenda and Barragán, has executed Agreement Res.220 to sell energy and power capacity for a total amount of 856 MW.

For further information on the project to the closing of the combined cycle at CTB conducted under this resolution, see Note 16.1.4.

F-29

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.1.4.2 SEE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector, the SEE 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.

Successful bidders will enter into a wholesale power purchase agreement with CAMMESA for a term of 10 years. The remuneration will be 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. 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.

2.1.4.3 SEE Resolution No. 287/17

On May 10, 2017 the SEE 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.

Awarded projects will be remunerated under a wholesale power purchase agreement which will be effective for a term of 15 years. The remuneration will be 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. Surplus power capacity is sold in the spot market.

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 wholesale power purchase agreements, with a limit of 180 days as from the originally committed commissioning date. However, the Company has ratified the originally committed date.

For further information on the project to the closing of the combined cycle at Genelba conducted under this resolution, see Note 16.1.3.

2.1.4.4 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).

F-30

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Successful bidders will enter into renewable electric power supply agreements for the sale of a committed annual electric power block for a term of 20 years.

Additionally, several measures have been established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, accelerated depreciation of 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.

Under this regulation, the Company, through Greenwind, has a supply agreement in place with CAMMESA for a total 100 MW.

2.1.5 Electricity transmission cost payable by Generators

On November 28, 2017, SEE Resolution No. 1,085/17 approved a new cost distribution methodology that represents the transmission service’s remuneration within the WEM.

In this regard, the SEE amended the original regulation of the WEM transmission system, which provided that transmission service costs would be allocated to the Demand and electric power Generation, and resolved that generators should stop paying costs associated with transmission, and start paying a charge representing operating and maintenance costs for connection and transformation equipment linking with the high-voltage transmission system as from December 1, 2017. This amendment implied a cost reduction for the Company.

2.1.6 Fuel Self-Supply for Thermal Power Plants

SGE Resolution No. 70/18, published in the BO on November 6, 2018, empowered generating, co-generating and self-generating agents within the WEM to acquire fuels, without distinction, required for own generation. This resolution superseded Section 8 of Resolution No. 95/13 of the former SE, which provided that the supply of fuels for electric power generation would be centralized in CAMMESA (with the exception of the generation covered under the Energy Plus regime). Likewise, CAMMESA remained in charge of the commercial management and the dispatch of fuel for generators which do not or cannot make use of such capacity.

Under the scheme set forth by SGE Resolution No. 70/18, the cost of generation with own fuels was valued according to the mechanism for the recognition of the Variable Production Costs recognized by CAMMESA. For implementation, maximum prices at the PIST for natural gas destined to the generation of electricity to be sold in the WEM, set by MINEM Resolution No. 46/18 and SGE Notes No. 66680075/18 and 07973690/19.

In case the generator has opted to supply its own fuel for generation and such fuel is not available at the time of dispatch, the calculation of the power capacity availability will be reduced to 50% of the actual availability. Similarly, it will lose its dispatch order, and in case the OED assigns it fuel for generation, the generated energy will be remunerated at just 50% of the approved non-fuel variable costs.

In the seasonal programming conducted on November 12, 2018, the Company has opted to make use of this self-supply capacity and has destined a significant part of its natural gas production as an input to its thermal units’ dispatch.

F-31

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The scheme set forth by SGE Resolution No. 70/18 was in effect during 2019; however, on December 27, 2019, the Ministry of Productive Development passed Resolution No. 12/19, which abrogated, effective as from December 30, 2019, SGE Resolution No. 70/18, and re-established the validity of section 8 and section 4 of SE Resolutions No. 95/13 and 529/14, respectively, thus restoring the CAMMESA centralization scheme for the supply of fuels for generation purposes.

2.1.7 Agreement for the Regularization and Settlement of Receivables with the WEM

On August 5, 2019 and under the call to Generators, the Company and certain subsidiaries executed with CAMMESA an Agreement for the Regularization and Settlement of Receivables with the WEM (the “Agreement”), as instructed through SGE Note NO-2019-66843995-APN-SGE#MHA.

Pursuant to the Agreement, CAMMESA undertook to pay the outstanding LVFVDs after discounting the debts taken on with the WEM under the Financing Agreements, Loan Agreements and Receivables Assignment Agreements executed by generators, and applying a 18% write-off on the balance. In this sense, the parties have agreed a total net settlement amount for the outstanding LVFVDs taking into consideration the interest update as of July 31, 2019 and the effects of the mentioned write-off, which amounts to $ 2,122.7 million, before tax withholdings for a total amount of $ 392.9 million. Finally, on August 7, 2019, the total agreed amount was collected, net of tax withholdings, for an amount of $ 1,729.8 million (U$S 39.4 million) corresponding to outstanding LVFVDs.

In furtherance of the undertaken commitments, the Company and certain subsidiaries have waived all submitted claims and have irrevocably dismissed their rights to file any kind of claim (whether administrative and/or judicial) against the Federal Government, the SGE and/or CAMMESA regarding the outstanding LVFDVs.

As a result of the Agreement, the Company has recognized revenues in the amount of U$S 5.9 million and net financial profits for U$S 71.1 million.

2.1.8      Loosening up of charges and interests in late payment of the economic transaction

SRRYME Resolution No. 29/2019 provided for a relaxation in the application of penalty interest and charges in case of delays in the payment of economic transactions within the WEM.

i.

Reduction of surcharges: the 50% reduction in surcharges for agents with overdue and unpaid debts is postponed until April 30, 2020.

ii.

Compensatory and penalty interest: only compensatory interest will apply, with a rate equivalent to the rate fixed by the BNA for its 30-day discount transactions, for agents registering a delay in payment but having promptly paid the last three immediately preceding debt maturities, provided the payment is made within 15 days after the invoice maturity date; additionally, penalty interest of 1% will apply for each day of delay, with a cap equivalent to the surcharges provided for in the CAMMESA procedures when the payment is made after such term. It is worth highlighting that the previous scheme provided for increasing penalty interest based on the time elapsed.

F-32

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2:(Continuation)

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.

2.2Transmission

2.2.1 Tariff situation

During 2019, pursuant to the provisions of the RTI, the ENRE continued applying the semi-annual tariff update mechanism in accordance with the applicable formula, which depends on the IPIM, the IPC and the Salary Index, as long as compliance with the trigger clause is verified.

On March 22, 2019, the ENRE issued Resolutions No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 25.15% and 26.53% against the previous semester, reaching a cumulative 78.41% and 81.26% increase, respectively, for the December 2016 – December 2018 period, applicable to the remuneration scheme as from February 2019.

On September 25, 2019, the ENRE issued Resolutions No. 269/19 and No. 267/19 updating Transener and Transba’s remunerations by 18.83% and 18.81% against the previous semester, reaching a cumulative 112.41% and 115.75% increase, respectively, for the December 2016 – June 2019 period, applicable to the remuneration scheme as from August 2019.

On the other hand, on July 3, 2018, the ENRE informed the beginning of the procedure to determine the remuneration of the Independent Carriers in exploitation stage: TIBA (Transba), Fourth Line (Transener), YACYLEC and LITSA. In this regard, on October 8, 2018, the costs, investments and expected tariff corresponding to Fourth Line and TIBA were presented to the ENRE. As of the date hereof, the ENRE has not issued the resolution with the results of the analysis of the requested information.

As of the date of issuance of these Consolidated Financial Statements, the ENRE Resolution has not yet been issued with respect to the tariff update corresponding to the semester July-December 2019, applicable to the remuneration scheme as from February 2020.

2.2.2 SADI Service Outage

On June 16, 2019, at 07:07 a.m., the SADI experienced a total outage.

This total outage was a result of the concurrence of multiple shortcomings within the SADI, some of them external to the Transmission System operated and maintained by Transener.

As regards the transmission system under the responsibility of Transener, the fault was due to a specific technical problem, and not to the lack of investment and maintenance. Following the change in the configuration of the littoral corridor due to the 500 kV Colonia Elía – Campana / Colonia Elía – Manuel Belgrano lines bypass, the DAG mechanism was not properly adjusted and failed to recognize signals sent out by the protection system. This bypass was made on account of the relocation of tower 412 to support the highest possible power transmission capacity in the littoral corridor.

F-33

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Due to the great volume of electricity dispatched from this corridor and the DAG failure, there was an imbalance between supply and demand which could not be redressed by the system’s other restraint barriers external to the electric power transmission service, resulting in a total outage.

The 500 kV Transmission System was available immediately after the disruption, and 100% of the transmission lines were available to come into operation and allow for the restoration of the system. Service restoration was overall fast (within 8:30 hours, 75% of the country’s demand had been restored).

Transener estimates that the above-mentioned event will give rise to a U$S 0.1 million penalty, which has been registered by Transener. This estimate is based on the application of the High-Voltage Transmission System’s Service Quality and Penalties Regime attached to Transener’s Concession Agreement as sub-annex II-B. As of the date of these Consolidated Financial Statements, the ENRE has not applied the penalty to Transener, which may differ from Transener’s estimates. 

This event will have an impact on 2020-year figures related to penalties, which will be increased, and premiums, which will be reduced, due to the Additional Service Quality and Sanctions Regime established by Resolutions No. 552/16 and No. 580/16.

2.3Energy distribution

2.3.1 General

Edenor Concession was granted in 1992 for a 95-year term, which may be extended for an additional maximum period of 10 years. The ENRE is empowered to control the quality levels of the technical product and service, the commercial service and the compliance with public safety regulations, as provided for in the Concession Agreement. If the Distribution Company fails to comply with the obligations assumed, the ENRE may apply the penalties stipulated in the aforementioned Agreement.

2.3.2 Edenor’s economic and financial situation

In the last four years, Edenor recorded negative working capital. This situation was not reversed after the application from February 1, 2017 of the new tariff arising from RTI, due mainly to the constant increase of its operating costs, necessary to maintain the level of service, the Argentine economy’s inflationary environment, and the sustained recession since mid-2018, with the consequent impact on the decline in income, the extension of collection periods and the steady increase in levels of energy theft. (See Note 1.2).

Despite the previously described situation, it is worth pointing out that, in general terms, the quality of the electricity distribution service has been improved, both in duration and in interruption frequency. In view of the continuous increase of the costs associated with the provision of the service, as well as the need for additional investments to meet the greater seasonal demand, Edenor has taken a series of measures aimed at mitigating the negative effects of this situation on its financial structure, minimizing the impact on the sources of employment, the execution of the investment plan, and the carrying out of the essential operation, maintenance and improvement-related works that are necessary to maintain the provision of the public service, object of the concession, in a satisfactory manner in terms of quality and safety.

F-34

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2019, 2018 and 2017 (Continuation)
(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Additionally, on December 23, 2019, the PEN enacted Law No. 27,541, which has a direct impact on Edenor’s financial solvency.

Taking into account that the realization of the measures necessary to reverse the manifested negative trend depends on the occurrence of certain events that are not under Edenor’s control, the Edenor’s Board of Directors has raised substantial doubt about Edenor’s ability to continue as a going concern, which may result in Edenor being obliged to defer certain payment obligations or unable to meet expectations for salary increases recorded in third-party costs.

Nevertheless, the Company’s Consolidated Financial Statements have been prepared assuming that Edenor will continue to operate as a going concern, and do not include the effects of the adjustments or reclassifications that might result from the final outcome of these uncertainties.

2.3.3 Electricity rate situation

In the last days of 2019, the PEN enacted, in the framework of the Economic Emergency and as mentioned in note 1, Law No. 27,541 on Social Solidarity and Production Reactivation, pursuant to which is authorized to initiate either a renegotiation process of the tariff structure in effect or an extraordinary review, as from the date on which the law comes into effect, and for a maximum term of up to one hundred and eighty days, with the aim of reducing the actual tariff burden on households, shops and industries for 2020.

In this context, on December 27, 2019, the ENRE instructed Edenor not to apply the electricity rate schedules from January 1, 2020, resulting from the provisions of the Electricity Rate Schedules Maintenance Agreement entered into by and between Edenor and the Federal Government on September 19, 2019, as such agreement had lost its applicability due to the electricity rate emergency provided for in the aforementioned law, with the electricity rate schedule that had been approved by ENRE Resolution No. 104/19 dated April 30, 2019 remaining in effect.

The aforementioned Electricity Rate Schedules Maintenance Agreement provided for the following:

- To maintain the electricity rate schedules that were in effect prior to August 1, 2019 for all electricity rate categories;

- To postpone until January 1, 2020 the application of the CPD that was to be applied as from August 1, 2019 (adjustment mechanism set forth in ENRE Resolution No. 63/17), relating to the January-June 2019 period, which amounted to 19.05%;

- To update the electricity rate schedules in relation to seasonal energy prices as from January 1, 2020;

- To recover the difference of the CPD and the seasonal energy prices generated on August 1, 2019-December 31, 2019 period, in seven monthly and consecutive installments as from January 1, 2020, for the August 1, 2019-December 31, 2019 period, which will be recovered in seven monthly and consecutive installments as from January 1, 2020 and will be adjusted in accordance with the relevant CPD adjustment and the methodology set forth in late payment procedures applied by CAMMESA, respectively;

F-35

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

- Commitment to maintain the quality of the service and meet the quality parameters set forth in the Concession Agreement;

- To postpone until March 1, 2020 the payment by Edenor of any penalty at its original value plus the relevant adjustments applicable at the time of payment.

Additionally, and within this framework, on October 22, 2019 SRRyME Resolution No. 38/19 approved the seasonal scheduling for the November 2019 – April 2020 periods and provided as well that the power reference price, the energy reference price for residential consumers and the energy reference price for the Distribution Company’s Large Users and for the other non-residential consumers, in effect since August 2019, would remain unchanged until April 2020.

Moreover, the referred to ENRE Resolution No.104/19, approved the values of Edenor’s Electricity Rate Schedule and the electricity rate values applicable to Edenor’s self-management metering system, effective from May 1, 2019, and informed Edenor of the value of the average electricity rate as from May 1, 2019, under the terms of Energy Government Secretariat Resolution No. 366/18, which modifies the prices at which Distributors acquire energy in the MEM, and which amounts to $ 4.343/KWh.

In this framework, the provisions of Resolution No. 14/19 dated April 30, 2019 of the Electricity Market and Renewable Resources Secretariat, which, among other issues, approve the MEM definitive winter scheduling and modify the Power Reference Prices and the Stabilized Price of Energy (SPE) relating to the May 1-October 31, 2019 period, are taken into consideration.

This Resolution provides that the increases of the SPE relating to the May-October 2019 six-month period that had been authorized by Resolution 366/18 for Residential customers, are to be absorbed by the Federal Government, whereas the increases established for non-residential customers with supplies lower than 300 kW and those relating to customers with supplies higher than 300 kW, GUDI customers, were modified for the May-July and August-October 2019 three-month periods.

With regard to the supplies lower than 300 kW (non-residential customers), and those higher than 300 kW, GUDI Customers, the values of the SPE were increased for the May-July 2019 and August-October 2019 three-month periods.

F-36

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The following resolutions issued by the ENRE in the months of January and February complete the 2019 regulatory context:

- Resolution No. 25/19, which approved, under the terms of ENRE Resolution No. 366/18, the values of Edenor Electricity Rate Schedule, effective from February 1, 2019, and informed of the value of the average electricity rate as from February 1, 2019, under the terms of Energy Government Secretariat Resolution No. 366/18, which modifies the prices at which Distributors acquire energy in the MEM.

- Resolution No. 27/19, which approved the CPD value of February 2019 together with the stimulus factor, whose application was deferred until March 2019. Additionally, it determined the value to be applied for the 36 remaining installments resulting from the gradual application system established in ENRE Resolution No. 63/17, and provided as well that the 50% of the CPD that should have been applied in August 2019 would be recovered in 6 CPD variation-adjusted installments.

With regard to the discounts under the system of caps applicable to customers benefited from the Social Tariff that the Federal Government owed to this Distributor, Edenor recorded revenue for U$S 19.4 million, considering the related peso-figures stated in constant values, relating to the December 2017-December 2018 period, as a consequence of the implementation and subsequent cancellation thereof by virtue of the Agreement on the Regularization of Obligations.

As of December 31, 2019, the Company recognized revenue from the Social Tariff for U$S 66.7 million. Additionally, Edenor has a receivable for U$S 4.2 million for the same concept.

2.3.4 Change of Jurisdiction and Regularization of Obligations

On February 28, 2019, the Federal Government, the PBA and the CABA entered into an agreement to initiate the process of transferring the public service of electricity distribution, duly awarded by the Federal Government to Edenor under a concession, to the joint jurisdiction of the PBA and the CABA, with the latter two jointly assuming the capacity as Grantor of the concession of the service. In the aforementioned agreement, the PBA and the CABA agreed to set up a new bipartite agency in charge of the regulation and control of the distribution service, and the Federal Government agreed to take the necessary steps and carry out the necessary administrative procedures to provide a solution to the pending claims with both Distribution companies.

F-37

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

In the framework of such agreement, on May 9, 2019, the Federal Government, the CABA and the PBA entered into an agreement, the Agreement on the Implementation of the Transfer of Jurisdiction, pursuant to which the CABA and the PBA jointly assume, as from the date on which the agreement comes into effect with the relevant ratifications, the regulation and control and the capacity as grantor over the distribution service granted to Edenor under a concession. Furthermore, it is provided that the Concession Agreement will remain in full force and effect and the national regulations and provisions issued by both the Energy Secretariat and the ENRE until the effective date of the transfer will be regarded as the applicable regulatory framework; and that the pledge of the class A shares, duly pledged as collateral to secure the performance of the obligations assumed by the Holder of the Concession and/or the majority shareholders under the Concession Agreement, is assigned on an undivided basis by the Federal Government to the CABA and the PBA.

Edenor was notified of and assented to the arrangement made by the Federal Government and the new Grantors of the concession in relation to the Transfer and the Implementation Agreements, and undertook both to indemnify them against any claims and to obtain the agreement of the majority of its shareholders. The Agreement on the Implementation of the Transfer of Jurisdiction was ratified by the Provincial Executive Power and the City’s Legislative Power by means of Executive Order No. 1,289/19 (published in the Official Gazette of the Province of Buenos Aires on October 2, 2019) and Legislative Resolution No. 161/19 (published in the Official Gazette of the CABA on July 17, 2019), respectively.

With the enactment of Law No. 27,541, the ENRE is granted jurisdiction over the public service of electricity distribution during the term the emergency law is in force.

Furthermore, within the framework of the change of jurisdiction and as a condition for the transfer, on May 10, 2019, Edenor and the Energy Government Secretariat, on behalf of the Federal Government, entered into an Agreement on the Regularization of Obligations, putting an end to the mutual pending claims originated in the 2006-2016 Transitional Tariff Period.

By virtue of this Agreement, Edenor: (i) waives any rights to which it may be entitled and abandons any actions against the Federal Government, including the complaint filed by Edenor in 2013 for failure to comply with the obligations resulting from the Agreement on the Renegotiation of the Concession Agreement (the "Adjustment Agreement”) entered into on February 13, 2006; (ii) binds itself to settle debts for works and loans for consumption (“mutuums”) originated in the transition period; (iii) undertakes to pay users certain penalty and compensation amounts relating to that period; and (iv) agrees to make investments, in addition to those agreed upon in the RTI, aimed at contributing to improving the reliability and safety of the service.

In return, the Federal Government partially recognizes the claim duly made by Edenor -referred to in caption (i) of the previous paragraph-, by fully offsetting pending obligations with the MEM for electric power purchases made during the transition period, partially cancelling the mutuums for investments granted by CAMMESA also during that period, and cancelling penalties payable to the National Treasury.

F-38

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The implementation of this agreement implied, on a one-time-only basis, the partial recognition of the claim made by Edenor for an amount of $ 8,674 million as compensation for the Federal Government’s failure to comply with obligations for 10 years during the Transitional Tariff Period, as well as the adjustment of the liabilities recorded at the time of the agreement, replicating the conditions applied to all the sector’s distributors, generating a profit of $ 7,736 million. Additionally, $ 362 million from the Federal Government and $ 323 million from the Province of Buenos Aires were recognized. These effects are disclosed in the “Agreement on the Regularization of Obligations” line item of the Statement of Comprehensive Income, for U$S 285 million, considering the related peso-figures stated in constant values, and do not imply any inflow of funds whatsoever for Edenor; on the contrary, Edenor must comply in the next 5 years with the investment plan stipulated in the above-mentioned agreement, which will be aimed at contributing to the improvement of the reliability and/or safety of the service as a whole, in addition to complying with the Investment Plan duly agreed upon in the tariff structure review (RTI) approved by Resolution No. 63/17, which, together with the penalties payable to users, the settlement of liabilities for mutuums and works, and the payment of the generated income tax amount, implies an actual disbursement of funds for a total approximate amount of $ 7,600 million, in a 5-year term.

Additionally, it was agreed that the receivable amounts in favor of Edenor for the consumption of shantytowns with community meters generated from July 2017 through December 31, 2018 -exclusively with respect to the percentage undertaken by the Federal Government-, relating to the Framework Agreement for $ 470.8 million, and the receivable amount resulting from applying the cap to the bills of users benefited from the Social Tariff for $ 923 million, would be offset against both part of the debt Edenor held with CAMMESA for loans received for the carrying out of works, and the debts Edenor held with CAMMESA for the investments made in the Costanera – Puerto Nuevo – Malaver 220kV Interconnection works, carried out through the FOTAE, and for the carrying out of the Tecnópolis Substation’s works.

In this regard, and based on the terms of the second clause of the aforementioned agreement, as of December 31, 2019 Edenor recorded the update of the amounts related to “penalties to be used for investments” for a total of U$S 24.5 million, totaling a liability pending application of U$S 77.6 million, which was charged to finance interest cost.

In this framework, Edenor Extraordinary Shareholders’ Meeting dated June 10, 2019 not only ratified the actions taken by the Board of Directors in the negotiations and signing of the Agreement on the Implementation of the transfer of jurisdiction and the Agreement on the Regularization of obligations, but also approved the waiver of rights, actions and claims against the Federal Government originated in the Transitional Tariff Period, and the abandonment of the lawsuit filed in 2013 against the Federal Government.

2.3.5 Penalties

The ENRE is empowered to control the quality levels of the technical product and service, the commercial service and the compliance with public safety regulations, as provided for in the Concession Agreement. If the Distribution Company fails to comply with the obligations assumed, the ENRE may apply the penalties stipulated in the aforementioned Agreement.

F-39

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

As of December 31, 2019, 2018 and 2017, Edenor has recognized in its Financial Statements the penalties accrued, whether imposed or not yet issued by the ENRE, relating to the control periods elapsed as of those dates, which may differ from those that ultimately result.

Furthermore, ENRE Resolution No. 63/17 has set out the control procedures, the service quality assessment methodologies, and the penalty system, applicable as from February 1, 2017, for the 2017 – 2021 period.

In accordance with the provisions of Sub-Appendix XVI to the referred to Resolution, Edenor is required to submit in a term of 60 calendar days the calculation of global indicators, interruptions for which force majeure had been alleged, the calculation of individual indicators, and will determine the related discounts, crediting the amounts thereof within 10 business days. In turn, the ENRE will examine the information submitted by Edenor, and in the event that the crediting of such discounts were not verified will impose a fine, payable to the Federal Government, equivalent to twice the value that should have been recorded.

In this regard, the ENRE has implemented an automatic penalty mechanism in order that the discounts on account of deviations from the established limits may be credited to customers within a term of 60 days as from the end of the controlled six-month period.

The penalty system provides that penalties are updated in accordance with the variation of Distributor’s CPD or by the energy tariff average price, as the case may be.

Subsequently, in different resolutions concerning penalties relating to the commercial service and the safety on streets and public spaces, the Regulatory Entity provided for the application of increases and adjustments, applying for such purpose a criterion different from the one applied by Edenor.

Additionally, and subsequent to the Tariff Structure Review, the ENRE regulated and/or issued new penalty procedures, such as:

- ENRE Resolution No. 118/18: It regulated the Compensation for extraordinary service provision interruptions.

- ENRE Resolution No. 170/18: It regulated the Penalty System for Deviations from the Investment Plan, a procedure whereby real investments are assessed by comparison with the annual investment plan submitted by Edenor, and the investment plan carried out for the 5-year rate period is assessed as against the five-year period plan proposed in the RTI.

- ENRE Resolution No. 198/18: New Supplementary Penalty Procedure of Technical Service Quality, which penalizes deviations from quality parameters at feeder level.

- ENRE Resolution No. 91/18: Through the filing of charges, the ENRE informs Edenor about the penalty procedure to be applied for failure to comply with meter-reading and billing time periods.

- ENRE Resolution No. 5/19: Through the filing of charges, the ENRE notifies Edenor of the penalty system to be applied for failure to comply with customer service times in commercial offices (Intelligent Routing and Consumer Service System – Sistema Inteligente de Direccionamiento y Atención de Usuarios (SIDyAA))

The effects of the resolutions detailed in this note were quantified by Edenor and recognized as of December 31, 2019, without implying consent to the criteria applied.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Finally, and in accordance with the provisions of the electricity rate schedule maintenance agreement, it is agreed that Edenor will maintain the quality of the service and comply with the quality parameters set forth in the Concession Agreement, and that the payment of any penalty will be postponed until March 1, 2020 and paid in 6 installments at its original value plus any adjustments that may apply at the time of payment.

2.3.6 Framework agreement

In 2019, Edenor and the Federal Government entered into different extension addenda to the new Framework Agreement, extending the term thereof until May 31, 2019.

Additionally, the above-mentioned addenda provided for the following:

- The Federal Government’s commitment to settle the amounts of its economic contribution for the supply of electricity to shantytowns, after deducting the energy associated with the Social Tariff;  

- That Edenor may assign the receivable amounts recognized by this extension to Edesur. In this regard, the relevant agreement on the assignment of receivables was signed, whereby Edesur, in consideration for the assigned receivables, paid Edenor the sole, full and final sum of $ 167.8 million.

Consequently, as of December 31, 2019 Edenor recognized revenue from the sale of electricity under the Framework Agreement until December 31, 2018 for U$S 9.9 million, and for the first five months of 2019 for U$S 3.7, both related to the Federal Government’s participation.

Furthemore, within the framework of the transfer of jurisdiction of the public service of electricity distribution that had been provided for by Law No. 27,467, the Government of the Province of Buenos Aires enacted Law No. 15,078 on General Budget, which provided that the Province of Buenos Aires would pay as from January 1, 2019 for the low-income areas and shantytowns’ consumption of electricity the same amount as that paid back in 2018, and that any amount in excess of that would have to be borne by the Municipalities in whose territories the particular shantytowns were located. Such consumption had to be previously approved by the regulatory agencies or local authorities having jurisdiction in each area. In this regard, Edenor has become aware that on November 27, 2019, the Municipality of General San Martín filed a petition for the granting of a provisional remedy with the Supreme Court claiming that the section of Law No. 15,078 that refers to this topic was unconstitutional. As of December 31, 2019, Edenor did not recognize revenue for this concept.

Finally, in view of the recent measures adopted by national and provincial authorities as of the date of issuance of these Consolidated Financial Statements, Edenor does not know which guidelines will be followed concerning the consumption of electricity by low-income areas and shantytowns relating to the periods that have not been recognized as well as future periods.

F-41

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.4.Oil and gas

2.4.1 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:

a)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

- Exploration in the continental shelf and the territorial sea: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

b)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.

c)Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.

d)Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

e)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.

f)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.

g)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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

h)Extends the benefits of the Investment Promotion Regime for the Exploitation of Hydrocarbon to projects involving a minimum of U$S 250 million direct investment denominated in foreign currency to be invested during its first 3 years.

2.4.2 Sale of crude oil and natural gas

In January 2017, the Federal Government executed the Agreement for the Transition to International Price in the Argentine Hydrocarbon Industry with producers and refineries of crude oil with the same purpose of generating a gradual convergence of the price of the crude oil barrel traded in Argentina towards the international price. On September 22, 2017, and as a result of fulfilling the condition that the Brent crude oil price exceeds the value of U$S 55/bbl for 10 consecutive days, the MEyM notified the suspension of the Agreement for the Transition to International Price of the Argentine Hydrocarbons Industry as from October 1, 2017. Since then, the internal price of a crude oil barrel as a refining raw material and the supplier price are determined according to the domestic market rules.

On August 15, 2019 Executive Order No. 566/19 was issued, which provided that, during a 90-day period:

- deliveries of crude oil in the domestic market should be billed and paid applying a reference exchange rate of $ 45.19 /U$S and a reference Brent crude oil price of U$S 59/bbl

- prices of gasoline and diesel oil sold in the domestic market may not exceed the price effective as of August 9, 2019.

- hydrocarbon production companies, refineries, and wholesalers and retailers should meet the domestic demand of crude oil and liquid fuels, respectively, at the established prices.

On August 30, 2019, Executive Order No. 601/19 was issued, which updated the reference exchange rate set by Executive Order No. 566/19 to $ 46.69/U$S for the sale of crude oil in the domestic market, effective from its publication to November 13, 2019.

Furthermore, on September 13, 2019 SGE Resolution No. 552/19 was issued, and established a transfer of $ 116.10 per oil barrel supplied to the domestic market in the month of September 2019, 88% of which to be paid to the oil company and 12% to the province where the oil producing concession is located. The transfer request should be accompanied by waivers by the oil company and the granting province to any administrative, judicial, extrajudicial or arbitration claim, proceeding or right, in the Republic of Argentina, abroad or at the international level, associated with the application of Executive Orders No. 566/19 and No. 601/19.

Later, on September 18, 2019, Resolution No. 557/19 issued by the Ministry of Finance was published, which updated the reference exchange rate set by Executive Order No. 601/19 to $ 49.30/U$S, and allowed for an increase of up to 4% compared to the prices effective as of August 9, 2019 for all qualities of gasoline and diesel oil at points of sale, effective from its publication to November 13, 2019.

Pampa has decided not to adhere to the compensation established by SGE Resolution No. 552/19 and is currently evaluating the possible courses of action.

F-43

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.4.3 Gas Market

2.4.3.1 Natural Gas Surplus injection promotion programs

2.4.3.1.1 Gas Plan I

On February 14, 2013, Resolution No. 1/13 was published in the BO. This resolution creates the Gas Plan I, which aims to evaluate and approve projects furthering the national self-supply of hydrocarbons through a gas production into the domestic market, as well as to generate higher levels of activity, investment and employment in this sector. Gas Plan I was regulated by Resolution No. 3/13 issued by the National Plan for Hydrocarbon Investments’ Strategic Planning and Coordination Committee, (the “Committee”) and published in the BO on April 26, 2013.

Gas Plan I provides that the National Government undertakes to pay a monthly compensation resulting from: (i) the difference between the Surplus Injection price (U$S 7.5/MBTU) and the price actually collected from the sale of the Surplus Injection, plus; (ii) the difference between the Base Price and the price actually collected from the sale of the Adjusted Base Injection. These projects will be in force for a maximum term of 5 years, with the possibility for renewal.

On August 7, 2013, pursuant to Resolution No. 27/13, the Committee approved a project for an increase in the total natural gas injection submitted by former subsidiary PEPASA, with retroactive effects to March 1, 2013.

2.4.3.1.2 Gas Plan II

In November 2013, the Committee issued Resolution No. 60/13 creating Gas Plan II. Such program was directed to companies without previous production or with a maximum injection limit of 3.5 MMm3/d and included price incentives in the case of production increases, as well as penalties involving LNG imports in case of non-compliance with committed volumes. Resolution No. 60/13 (as amended by SE Resolution No. 22/14 y No. 139/14), established a price ranging from U$S 4/MBTU to U$S 7.5/MBTU, based on the highest production curve attained.

On March 6, 2014 and January 30, 2015, former subsidiaries PELSA and Petrobras were registered with this program pursuant to Resolution No. 20/14 and 13/15, respectively, of the Secretariat of Economic Policies and Development Planning of the Ministry of Economy and Public Finances, respectively.

However, the receivables registered by the Company, during 2017, under the above-mentioned natural gas surplus injection promotion programs, were not timely collected.

In this regard, on April 3, 2018, MINEM Resolution No. 97/18 was published, which approves the procedure for the cancellation of compensations pending settlement and/or the payment for the year 2017 under the above-mentioned natural gas surplus injection promotion programs. Beneficiary companies opting for the application of the procedure should state their decision to adhere within a term of twenty (20) business days, waiving all present or future administrative and/or judicial actions, remedies, rights or claims regarding the payment of obligations arising from the programs. The cancellation procedure established in the Resolution provides that the amounts will be payable in thirty equal and consecutive installments as from January 1, 2019. 

F-44

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

On May 2, 2018, the Group filed with the Ministry of Energy the application form to join the payment procedure set forth by MINEM Resolution No. 97/18, expressing its consent to and acceptance of its terms and scope, the amount of the compensation to the Group established by this resolution being estimated at U$S 148 million.

On February 21, 2019, SGE Resolution No. 54/19 was published, which modifies the procedure for the cancellation of compensations pending settlement and/or the payment for the year 2017 (MINEM Resolution No. 97/18), the main modification being that cancellations would be instrumented through the delivery of public debt bonds.

On April 17, 2019 and July 16, 2019, bonds were credited in favor of the Company for a face value of U$S 89 million and U$S 54 million, respectively. These bonds do not accrue interest and are repayable in 29 monthly and consecutive installments, the first one for 6.66%, the following eighteen installments for 3.33%, and the remaining ten installments for 3.34% of the original face value.

As of December 31, 2019, the Company collected U$S 36 million and U$S 21 million, respectively, as repayments, 18 installments still pending collection, which are disclosed in “Public debt securities” under “Investments at amortized cost”.

2.4.3.1.3 Unconventional Gas Plan

On March 6, 2017, MEyM Resolution No. 46-E/2017 was published, which created the Program for the Encouragement of Investments in the Development of Natural Gas Production from Unconventional Reservoirs (the “Unconventional Gas Plan”) seeking to encourage investments for the production of natural gas through unconventional methods in the Neuquén Basin and effective until December 31, 2021.

On November 2, 2017, MEyM Resolution No. 419/17 was published in the BO. This resolution amends Resolution No. 46/17 and classifies concessions into pilot and developing, with an initial production equal to or higher than 500,000 m3/day (monthly average between July 2016 and June 2017). Undeveloped concessions may obtain a guaranteed minimum price for their whole production provided they reach an annual average production equal to or higher than 500,000 m3/day during a twelve-month period by December 31, 2019. Developing concessions may only apply for the benefit for the incremental portion of their initial production. The reference price for the incentive will be calculated using the domestic market’s weighted average reported by the MEyM’s Secretariat of Hydrocarbon Resources.

On November 17, 2017, MEyM Resolution No. 447/17 was published in the BO. This resolution extends the application of the Unconventional Gas Plan created by Resolution No. 46/17 and amended by Resolution No. 419/17 to natural gas production from unconventional reservoirs in the austral basin and on January 20, 2018, MEyM Resolution No. 12/18 was published, which introduces certain modifications with the purpose of extending the Unconventional Gas Plan created by MEyM Resolution No. 46/17, as amended, for adjacent concessions operated on a joint basis.

The Company has requested the SGE to include the following exploitation projects timely approved by the provincial enforcement authority in the Unconventional Gas Plan: (i) “Río Neuquén”, filed on February 5, 2018, as owner of 33.07% of production, (ii) “El Mangrullo”, filed on July 26, 2018, as operator and owner of 100% of production; and (iii) “Sierra Chata”, filed on July 30, 2018, as operator and owner of 45.55% of production.

F-45

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

However, on January 30, 2019, in a meeting called by the SGE, affected gas producers (including the Company) were informed that no new projects would be approved under the Unconventional Gas Plan.

2.4.3.2 Natural Gas for the Residential Segment and CNG

2.4.3.2.1 Administration of the Priority Demand

In June, 2016, MEyM Resolution No. 89/16 was published in the BO, which established the criteria for the standardization of natural gas purchases within the PIST by distribution service providers in order to meet the Priority Demand. Additionally, criteria were established to guarantee the meeting of the Priority Demand through the CEE in case of operational emergencies which may affect its normal supply.

In June, 2017 ENARGAS Resolution No. 4,502/17 was published, which approved the procedure for dispatch administration in the CEE. In case the CEE does not reach an agreement, ENARGAS will define the supply taking into consideration each producer’s available quantities minus the amounts previously purchased to meet the Priority Demand, with a progressive allocation until matching the proportional quota of each producer/importer in the Priority Demand.

2.4.3.2.2 Natural Gas Prices within the PIST

In early January, 2018, the extension period set forth by Law No. 27,200 to the public emergency declared in 2002 terminated and, therefore, Law No. 24,076 was reinstated, which provides that the price of natural gas supply agreements will be determined by the free interaction of supply and demand. However, on account of the significant devaluation of the Argentine peso and the impossibility to transfer this new exchange rate on to final users’ tariff schemes, in early October, 2018, prices with gas distributors began to be agreed in the spot market on a daily basis.

Furthermore, ENARGAS Resolutions No. 280-289 and No. 292/18 were issued, which established, effective for a six-month period beginning October 1, 2018, the new natural gas final tariffs considering a price for natural gas as input ranging between U$S 1.74/MBTU and U$S 3.98/MBTU, including the differential tariff.

Furthermore, on November 15, 2018 Executive Order No. 1,053/18 was issued by the PEN, which established, on a one-off basis, that the National Government assumes the difference between the price of gas purchased by gas distributors and the price of gas recognized in distributors’ final tariffs for the April 2018 – March 2019 period. ENARGAS will determine the net amount, which will be transferred to each Distributor in 30 monthly and consecutive installments as from October 1, 2019 updated using the BNA’s 30-day interest rate; once an installment has been received, Distributors must immediately make the corresponding payments to gas suppliers, and must inform and credit them monthly before the ENARGAS.

On August 15, 2019, ENARGAS Resolution No. 466/2019 was published, which, together with its amending resolutions (Resolutions No. 554/19, No. 624/19 and No. 636/19), provides for the methodology to determine the amount payable by the National Government for the differences generated by exchange rate variations between the value of gas purchased by natural gas distributors and the value set in the tariff schemes effective between April 1, 2018 and March 31, 2019, pursuant to the provisions of Executive Order No. 1,053/18.

F-46

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

On October 25, 2019, the Company adhered to the collection procedure established by PEN Executive Order No. 1,053/18 regulated by ENARGAS Resolution No. 466/19, the net amount of the receivable pending collection by the Company and ascertained by ENARGAS Resolution No. 735/19 on November 14, 2019 reaching $ 1,219 million. As of December 31, 2019, the Company collected the first installment of U$S 0.7 million, with the 29 installments and the corresponding update still pending collection, for which it keeps a receivable of U$S 14.6 million, which is disclosed under “Trade and other receivables.”

Pampa is currently claiming to Natural Gas Distributors the payment of certain items not covered by Executive Order No. 1,053/18, including: VAT, gross receipts, Trust Fund, Withheld Gas and Unrecognized Natural Gas.

Through ENARGAS Resolutions No. 193-199, No. 201-202 and No. 205-207/19, natural gas tariff since April 2019 effective for a six-months period were established, considering a price of natural gas as a raw material ranging between U$S 2.14/MBTU and U$S 4.69/MBTU, including the differential tariff. Subsequently, 27% and 12% discounts were established in the PIST gas price for April and May 2019, respectively, through subsidies, and deferral of 22% in invoices issued between July and October 2019, to be recovered in five consecutives installments beginning December 2019.

Regarding the tariff update corresponding to October 2019, it was deferred until February 1, 2020, and provided for by Law 27,541 gas tariffs under Federal jurisdiction would remain unchanged, since December 23, 2019 and a renegotiation or extraordinary review process of the current RTI for up to 180-day term would begin.

2.4.3.3 Tender for Firm Gas Supply

By mid-February 2019, firm gas supply to distributors was auctioned. For the Northwest Basin, 9.4 and 3.8 million m3 per day were allocated for winter (April - September 2019) and summer (October 2019 - April 2020), respectively, at an average price of U$S 4,35/MBTU. And for the rest of the basins, 36.1 and 14.4 million m3 per day were allocated for winter and summer, respectively, at an average price of U$S 4,62/MBTU. Pampa took part in this auctions and was awarded.

According to ENARGAS Resolution No. 72/19, on February 12, 2019, the methodology for passing the gas price on to tariffs considers BNA’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 rates stipulated in the agreements. However, the exchange rate update applicable from October 1, 2019, was deferred and finally subject to the 180-day period from the enactment of Law No. 27,541.

2.4.3.4 Acquisition of Natural Gas for Generation

Since November 2018, the Company has opted to make use of its self-supply capacity, provided for by SGE Resolution No. 70/18, and has destined a significant part of its natural gas production to its thermal units’ dispatch (see Note 2.1.6).

F-47

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

On the other hand, on December 27, 2018, under a CAMMESA auction conducted for the year 2019, offers for a total 222 million m3 interruptible gas-day were received, at seasonal PIST prices with a maximum price of U$S5.2/MBTU and a minimum price of U$S3.2/MBTU for the June-August 2019 period, and with a maximum price of U$S3.7/MBTU and a minimum price of U$S2.2/MBTU for the rest of the year. For implementation of this auction, reference PIST maximum seasonal prices, based on the source basin, were considered according to SGE Note No. 66680075/18, effective as of January 2019. Pampa took part in this auction.

Finally, on December 27, 2019, the Ministry of Productive Development passed Resolution No. 12/19, which abrogated, effective as from December 30, 2019, SGE Resolution No. 70/18, thus restoring the CAMMESA centralization scheme for the supply of fuels for generation purposes.

On December 27, 2019, CAMMESA’s auction only for January 2020 took place. Offers prices for a total 260 million m³ of interruptible gas-day were received, with a weighted average PIST price of U$S 1.83/MBTU. Furthermore, on January 29, 2020, CAMMESA’s auction for February-2020 took place, on a partially firm basis. Offers prices for a total 84 million m³ of gas-day were received, with a weighted average PIST price of U$S 2.50/MBTU. Pampa took part in both auctions.

2.4.3.5 Natural Gas Exports

Through MEyM Resolution No. 104/18 and SGE Resolution No. 9/18, subsequently replaced in July 2019 by the SGE Resolution No. 417/19, a Procedure for the Authorization of Natural Gas Exports was established. Authorizations, considering in all cases the security of supply to the Argentine domestic market, may consist of short-term (up to 1 year) or long-term (1 to 10 years) exports, whether on an interruptible basis or on a firm basis for summer periods (October - April for a term of up to 5 years), or operational exchanges in emergency situations. Furthermore, in the case of projects covered by the Unconventional Gas Plan, exported natural gas may not be computed as part of and/or within the production applicable to such program. Likewise, in August 2019, through the SHC Provision No. 168/19, the terms and conditions for firm gas exports to Chile until May 15, 2020, were approved.

In December 2018 and January 2019, the Company was authorized pursuant to SGE Resolution No. 252/18 and No. 12/19 to export natural gas to Chile and Uruguay, on an interruptible basis, respectively. Furthermore, in September 2019, Pampa obtained permission to export natural gas, on a firm basis, to ENAP Refineries in Chile. Pampa took place in IESA’s auctions to export natural gas in a partially firm basis to ANCAP in Uruguay between January and April 2020, but it was not awarded.

On October 31, 2019, SSHC Resolution No. 284/19 was published in the BO, which approves the operating procedure for natural gas exports effective until September 30, 2021 seeking to:

- ensure the security of the supply to the domestic market;

- ascertain the scope of any need to restrict gas exports which are operationally useful in case of lack of supply to the domestic market (the “Useful Interruption”) to meet the unsatisfied domestic market demand on a certain day;

- organize, document, and provide predictability to natural gas restriction or interruption procedures; and

- coordinate the actions to be implemented to ensure supply to the domestic market.

F-48

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Under this proceeding, the SSHC, ENARGAS, Transport Licensees and Exporters should hold weekly/bi-weekly meetings to analyze the supply domestic status and its implications in gas exports, taking into consideration the projection of the operational status of the gas transportation system and subsystems, the domestic demand, and any event involving potential drawbacks.

The procedure establishes that should the security of the supply to the domestic market be at stake, producers should adjust their exports pursuant to what is resolved under such procedure, and the mere notice of Useful Interruption served by a reliable means will entail the abide by producers.

In case of incurring higher costs for the use of alternative fuels to generate electricity by the WEM (imported LNG, coal, FO or GO), whose cost was borne by the National Government, exporters must pay compensation to CAMMESA. Through SGE Resolution No. 506/19 issued on August 29, 2019, a minimum of U$S 0.1/MBTU and a maximum of U$S 0.2/MBTU for the exported volume were set, that could be offset with receivables for gas sale in in the domestic market with CAMMESA. Such compensation would be included in WEM’s cost of energy.

It should be pointed out that from September 4, 2018 to December 31, 2020, Executive Order No. 793/18 regulated the application of a 12% export tax rate with a cap of $ 4 over each exported U$S for natural gas exports. On December 14, 2019, Executive Order No. 37/19 voided the ceiling of $ 4 for each U$S exported, established in Article 2 of Decree No. 793/18 as amended.

Law No. 27,541 authorized the PEN to modify the Export Duties corresponding to hydrocarbons sold in the external market and ratified the validity of Executive Order No. 793/18 and No. 37/19.

2.5 Gas Transportation

2.5.1 General aspect

TGS’ license has been granted for an original term of 35 years starting December 28, 1992. However, upon termination TGS may request to the ENARGAS a License extension for an additional ten-year period. Upon termination of the License’s life, whether it be 35 or 45 years, the Natural Gas Law and Executive Order No. 2,458/92 require the call for a new bid for the granting of a new license, where TGS —provided it has substantially met its obligations resulting from the License— will have the option to match the best offer received by the National Government during the bidding process.

2.5.2 TGS’s Tariff situation

2.5.2.1Integral Agreement

On March 30, 2017, within the framework of the tariff renegotiation process, TGS executed the 2017 Integral Agreement which, after being approved by the different intervening government agencies and the National Congress, was ratified on March 27, 2018, through PEN Decree No. 250/18. This decree represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS, and thus, the final renegotiation of the license after seventeen years of negotiations.

F-49

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

The 2017 Integral Agreement sets the guidelines for the provision of the natural gas transportation service until the end of the License. Among these guidelines:

- The RTI Process, which will culminate in the signing of the integral agreement, was approved. As a result of this RTI, a new tariff schedule was also approved. This new tariff schedule applicable to the Company determined a total tariff increase of 214.2% and 37%, in the event that it had been granted in a single installment as of April 1, 2017, on the tariff of the natural gas transportation service and the CAU, respectively.

- A Five-Year Investment Plan to be executed by TGS is approved, the plan requires a high level of essential investments for the operation and maintenance of the pipeline system, to provide quality, safe and reliable service. The Five-Year Plan shall be for the period from April 1, 2017 to March 31, 2022 and will amount to $ 6,786 million (valued at December 31, 2016).

- A non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments were approved. This adjustment must be approved by ENARGAS and for its calculation, the evolution of the WPI published by INDEC will be considered.

- TGS and its shareholders must withdraw any claim against the Government related to the natural gas transportation business, including the arbitration proceedings before the ICSID. The Company desisted from it on June 26, 2018.

As it is mentioned above the tariff increase was granted in 3 installments according to the following resolutions:

- Effective as of April 1, 2017, 64.2% of the tariff for the natural gas transport service, the CAU not being adjusted, in accordance with the provisions of Resolution No. 4,362/17.

- Effective as of December 1, 2017, after the issuance of Resolution No. 120/17, 81.1% on the tariff for the natural gas transport service and 29.7% on the CAU, which includes the first adjustment by WPI.

- Effective as of April 1, 2018, an increase of 50% over the tariff for the natural gas transport service and the CAU within the framework of the provisions of Resolution No. 310/18 issued by the ENARGAS.

2.5.2.2 Semi-annual tariff increase

This increase is granted within the framework of the semi-annual tariff adjustment of the natural gas transportation service in accordance with the provisions of the RTI process.

In the public hearing held on September 4, 2018, in which the Company requested, based on the variation of the WPI 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.

F-50

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

This increase was determined by ENARGAS based on the simple average of the WPI, the Construction Cost Index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018.

It is noteworthy that 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 WPI to determine the tariff increase. TGS notified ENARGAS 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 has 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 SGE issued Resolution No. 521/19, later amended by Resolution No. 751/19, which postpones its application until February 1, 2020.

This deferral will result in TGS having to review and adjust, in the same proportion as the foregone income, the execution of the Five-Year Investment Plan. As of the issuance of these Consolidated Financial Statements, TGS has submitted the works adjustment proposal to ENARGAS, without the corresponding approval resolution being issued as of the date hereof.

However, the Law No. 27.541 provides that natural gas transportation and distribution tariffs will remain unchanged for a maximum term of 180 days as from December 23, 2019. In this sense, the PEN is vested with the power to renegotiate them, whether under the current RTI or through an extraordinary review pursuant to the provisions of the Natural Gas Law.

As of the date of issuance of these Consolidated Financial Statements, there has not been any administrative actions to regularize the TGS’s rate situation.

Additionally, the Law No. 27.541 provides for the administrative intervention of the ENARGAS.

2.5.2.3 Collection Deferrals

On June 21, 2019, the SGE issued Resolution No. 336/19, which provided for a 22% payment deferral in bills issued from July 1, 2019 to October 31, 2019 for services provided to natural gas residential users.

The described deferrals will be recoverable in bills issued as from December 1, 2019 in five monthly, equal and consecutive installments. As compensation, the National Government will pay licensees an economic compensation, in the form of a subsidy, for the financial cost resulting from the deferral.

F-51

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

On August 22, 2019, the SGE issued Resolution No. 488/19 establishing the procedure for the calculation applicable by natural gas distributors and subdistributors of the deferral provided for by Resolution No. 336/19. Furthermore, this resolution instructs the Undersecretariat of Hydrocarbon and Fuels to implement the procedure to be used for the calculation and payment of the previously mentioned compensation. As of the issuance of these Consolidated Financial Statements, no regulations for the calculation and methodology applicable to the payment of the above-mentioned economic compensation have been passed.

As of December 31, 2019, TGS’ sales receivables from natural gas distributors amount to $ 1,206 million under these items.

2.5.2.4 Non-regulated segments

2.5.2.4.1 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 SRH (former Secretary of Hydrocarbon Resources), that sets 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 by the SRH. 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 marketing 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.

After successive modifications and pursuant to Provision No. 104/19 issued by the Undersecretariat of Hydrocarbons and Fuels, the current price for butane and propane sold under this program amounts to $ 9,895 and $ 9,656 per ton, respectively. No compensation has been set for these products.

In this context, 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 by which it undertakes to supply propane to the domestic market 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 MINEM.

F-52

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Within the gradual subsidies reduction path granted by MINEM, on March 31, 2017, the MINEM issued Resolutions No. 74 and No. 474/17 that stipulate increases in the price of undiluted propane gas destined to the Propane for Networks Agreement as of April 1 and December 1, 2017, respectively.

From those dates onwards, the price of undiluted propane gas has been set at $ 1,267/tn and $ 2,832/tn and $ 1,941.20/tn and $ 3,964/tn, respectively, depending on the client to whom the undiluted propane gas is delivered.

Finally, in May 2018, TGS initiated the sixteenth extension by which the methodology for determining the price and volumes for the period April 1, 2018 - December 31, 2019 is established. Additionally, this last extension established the propane sale price to customers under this program. Notwithstanding the foregoing, on January 14, 2020 TGS received an instruction issued by the SE to proceed with propane deliveries in accordance with set conditions by the sixteenth extension, also indicating that the SE is working on the extension of the terms of the agreement at least until June 30, 2020.

During 2019 and 2018, TGS received the amount of $ 469 million and $ 626 million, for subsidies for the programs mentioned above, respectively.

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, 2019, the Argentine Government owes TGS $ 144 million under these items.

2.5.2.4.2 Foreign market

On September 3, 2018, the Executive Branch issued Decree No. 793/18, which, between September 4, 2018 and December 31, 2020, sets an export duty of 12% on the exported amount of propane, butane and natural gasoline. This withholding is capped at $4 for each dollar of the tax base or the official FOB price.

Later, as a result of the enactment Law No. 27,541, an 8% cap was set for the rate applicable to hydrocarbons effective as from December 23, 2019.

2.6 Tax reform

On December 29, 2017 the PEN issued Law No. 27,430 that introduced several modifications in tax treatment, the key components of which are described below:

2.6.1 Income tax

2.6.1.1 Income tax rate

According to Law No. 27,430, the income tax rate for Argentine companies will be gradually reduced from 35% to 30% for fiscal years beginning as from January 1, 2018 until December 31, 2019, and to 25% for fiscal years beginning as from January 1, 2020.

F-53

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

However, Law No. 27,541 suspended the reduction in the rate projected for fiscal years beginning on or after January 1, 2021, providing that during the suspension period the tax rate will remain at 30%.

The effect of the application of the income tax rate changes on deferred tax assets and liabilities pursuant to the above-mentioned tax reform was recognized, based on their expected realization year, in “Effect of tax rate change in the deferred tax” under Income tax and Minimum notional income tax of the Consolidated Statement of Comprehensive Income (Note 10.6).

2.6.1.2 Tax on dividends

According to Law No. 27,430, the tax on dividends or earnings distributed by, among others, Argentine companies or permanent establishments to individuals, undivided estates or beneficiaries residing abroad is introduced based on the following considerations: (i) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2018 until December 31, 2019, will be subject to a 7% withholding; and (ii) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2020 will be subject to a 13% withholding.

Pursuant to the suspension of the Income Tax rate provided for by Law No. 27,541, the 7% withholding will remain in effect for fiscal years beginning on or before January 1, 2021.

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 Transfer prices

Controls are established for the import and export of goods through international intermediaries different from the exporter at the point of origin or the importer at destination.

Furthermore, the Law sets out the obligation to provide documentation allowing for the verification of the characteristics of the transaction for the import and export of goods and the export of commodities, in both cases when they are conducted through an international intermediary different from the exporter at the point of origin or the importer at destination.

2.6.1.4 Optional Tax revaluation

Law No. 27,430 provides that Companies may opt to make a tax revaluation of assets located in the country and subject to the generation of taxable earnings existing as of December 31, 2017. The special tax on the revaluation amount depends on the asset, and will amount to 8% for real estate not accounted for as inventories, 15% for real estate accounted for as inventories, and 10 % for personal property and the remaining assets. Once the option is exercised for a certain asset, all assets within the same category should be revalued.

The tax result from the revaluation will not be subject to income tax, and the special tax on the amount of the revaluation will not be deductible from such tax.

F-54

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

Several regulations (Decrees No. 353/18, No. 613/18 and No. 143/19 and AFIP General Resolution No. 4,287), have repeatedly postponed the date for exercising this option based on the international context and the greater volatility in financial variables affecting decision-making regarding the exercise of the option.

On March 27, 2019, Pampa and CPB, based on their evaluation of the domestic context and the evolution of financial variables (including the inflation rate), exercised their option to adhere to the tax revaluation regime on their property, plant and equipment existing as of December 31, 2017 pursuant to Title X of Law No. 27,430, the tax cost of such property thus increasing to $ 15,311 million.

On exercising this option, Pampa and CPB have paid the special tax for a principal amount of U$S 34.5 million plus interest for U$S 1 million.

Additionally, Pampa and CPB had to waive all lawsuits and rights invoked in any previously brought judicial or administrative proceedings seeking the application of updating mechanisms on the income tax (see Notes 11.6.1 and 15.2). Furthermore, Pampa and CPB had to waive their rights to initiate any judicial or administrative proceeding seeking the application of such updating mechanisms regarding fiscal years ended before December 31, 2017.

2.6.1.5 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 IPC 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 one hundred percent (100%) over the thirty-six (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 fifty-five percent (55%), thirty percent (30%) and fifteen percent (15%) for the years 2018, 2019 and 2020, respectively.

Law No. 27,541 provides 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 (1/6) should be charged in that fiscal period and the remaining five sixths (5/6), in equal parts, in the five immediately following fiscal periods.

As of the end of fiscal year 2018, an accumulated variation in the price index exceeding the foreseen 55% condition for the application of the comprehensive adjustment in such first fiscal year was not evidenced. However, the costs of goods acquired during fiscal year 2018 have been adjusted in accordance with the procedure stated in subsection (i).

As of December 31, 2019, the cumulative variation in the IPC exceeds the 30% condition set for the second transition year, and, therefore, the Group has applied the tax inflation adjustment in the calculation of the current and deferred income tax provision, except for the Company and its subsidiary PEFM, which, taking into consideration the merger process described in Note 5.1.1.2, have not exceeded the established legal parameter for the interim six-month period ended on June 30, 2019.

F-55

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 2: (Continuation)

2.6.2 Value-added tax

A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity.

2.6.3 Fuel tax

Certain modifications are introduced to the fuel tax, incorporating a tax on the emission of carbon dioxide. Tax on Fuels comprises the Tax on Liquid Fuels ("ICL") and the Carbon Dioxide Tax ("IDC"). The reform simplifies the fuel taxation structure, keeping the same tax burden effective prior to the reform.

By means of Law No. 27,430, subsection c) of Section 7 of Chapter I of Title III of Law No. 23,966 was modified, establishing the fuel tax exemption for the transfers of certain taxable products used as raw material in petrochemical processes. Later, Decree No. 501/18, regulated Law No. 23,966 and established that transfers of virgin naphtha and pyrolysis gasoline are exempted from the fuel tax when are destined to a petrochemical catalytic reform process.

This regulatory modification allowed a significant financial saving for the Company as a consequence of the tax exemption on the purchase of virgin naphtha as raw material.

2.6.4 Regularization regime (Moratorium)

Between the 29 and the 31 of March 2017, the Company adhered to the regularization regime (moratorium) provided for Law No. 27,260 in relation to certain tax claims and provisions. The Company related liabilities were mainly attributable to contingencies identified in Petrobras’s acquisition process including interpretation differences with the Argentine tax authority regarding i) the time of recording well abandonment expenses for income tax purposes, ii) the exemption from the Tax on Personal Assets as Substitute Taxpayer for the shareholder PPSL; iii) the Tariff heading used by the Company for certain exported products; and iv) inaccurate customs regarding the importation of a turbine supplied by Siemens Germany, including certain spare parts that had not been required nor declared by the Company. In relation to the last matter described before, the Company entered into an agreement with Siemens pursuant to which Pampa received the reimbursement of related incurred costs.

As the adhesion to the regularization regime established benefits of releasing tax fines and reducing compensatory interests, the Company has recorded, during 2017 fiscal year, a net gain after income tax effects of U$S 14.8 million.

F-56

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 3: BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS issued by IASB.

These Consolidated Financial Statements have been approved for issue by the Board of Directors dated March 9, 2020. Significant accounting policies adopted in the preparation of these Consolidated Financial Statements are described in Note 4, which have been consistently applied in these Consolidated Financial Statements, except as mentioned in Note 3.1.

These accounting policies have been applied consistently by all Group companies.

3.1 Change in Functional Currency

The Company changed its functional and presentation currencies from the Peso to the U.S. dollar commencing on January 1, 2019 following a change in facts and circumstances relevant to its business operations. Therefore, as from January 1, 2019, the Company records its operations in U.S. dollars, the new functional currency, and also presents its Consolidated Financial Statements in U.S. dollars.

For purposes of effecting this change, the Company has considered the following factors that have influenced the environment in which the entity operates and its sales prices:

i.	the divestment in the refining and distribution segment in 2018, which has historically been subject to regulations by the Argentine Government and prices set in Pesos;
ii.	the growing trend of the execution of agreements denominated in U.S. dollars in line with the Company’s strategy to focus investments and resources on the expansion of its power generation installed capacity; and
iii.	the keeping in effect of the remuneration scheme for generation during 2019, with prices directly established in U.S. dollars by the Argentine Government, despite the context of instability both at the local and international levels, including the significant exchange rate stress that the Argentine economy has endured.

The Company effected the change in functional currency prospectively as from January 1, 2019, as required by IAS 21 “The effects of changes in foreign exchange rates”.

Upon the change in the functional currency, all transactions in currencies other than the functional currency are considered “foreign currency transactions”.

After the closing of the fiscal year, Resolution SE No. 31/20, as detailed in Note 23, exclusively modified the remuneration scheme for sales in the spot market established by SRRYME Resolution No. 1/19 as from the commercial transaction corresponding to February 1, 2020.

F-57

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 3: (Continuation)

It is worth highlighting that even if the above-mentioned modification adversely affects the profitability of the generation business, the management has concluded that it does not constitute a change to the underlying primary economic environment in which the entity operates due to: i) the higher incidence in 2019 of revenues from dollar-denominated contracts compared to revenues from sales in the spot market in the generation segment as a result of the commissioning of PEPE II and PEPE III wind farms for 106 MW in May and June 2019, which will increase in 2020 through the entry into effect of the contract remunerating the extension and closing to combined cycle of the CTGEBA for 383 MW; and ii) the fact that the dollar remains the basis for setting sales prices and costs in the oil & gas and petrochemicals segments.

3.2 Comparative information

The comparative information has been stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29 "Financial reporting in hyperinflationary economies", since the Peso was the Company’s functional currency up to that date.

The inflation adjustment was calculated taking into consideration the indexes set by the FACPCE based on the price indexes published by the INDEC. As of December 31, 2018, the price index increased to 184.255, with an annual inflation rate of 47.6%.

As from the change in functional currency detailed in Note 3.1, the Company has discontinued the preparation and presentation of financial statements in accordance with IAS 29, and has treated the amounts expressed in terms of the measuring unit current as of December 31, 2018 as the basis for the carrying amounts in subsequent financial statements.

The information as of December 31, 2018 and 2017 disclosed for comparative purposes arises from the Consolidated Financial Statements denominated in Pesos stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

Certain not significant reclassifications have been made to those financial statements to keep the consistency in the presentation with the amounts of the current year.

F-58

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: ACCOUNTING POLICIES

The main accounting policies used in the preparation of these consolidated Consolidated Financial Statements are explained below.

4.1New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2019 and adopted by the Company

The Company has first applied the following standards and/or amendments as from January 1, 2019:

- IFRS 16 – “Leases” (issued in January 2016).

- IFRIC 23 – “Uncertainty over Income Tax Treatments” (issued in June 2017)

- IFRS 9 – “Financial Instruments” (application guideline amended in October 2017)

- IAS 28 – “Investments in Associates and Joint Ventures” (amended in October 2017)

- Annual Improvements to IFRS Standards 2015–2017 Cycle (issued in December 2017)

- IAS 19 – “Employee Benefits” (amended in February 2018)

The impact of the initial application of IFRS 16 in the Company’s operating results and financial position as from January 1, 2019 is detailed below.

The application of the remaining standards, amendments or interpretations did not have any impact on the results of the operations or the financial position of the Company.

4.1.1Impacts of the adoption of IFRS 16

The Company has opted to apply IFRS 16, using the simplified approach, in relation to lease contracts previously identified as such under IAS 17, retrospectively with the cumulative effect recognized as an adjustment to the opening balance of retained earnings as of January 1, 2019, without restating comparative information.

Until December 31, 2018, only contracts classified as financial leases under IAS 17 were capitalized by the Company, that is, contracts where the Company had substantially all of the risks and rewards of ownership of the leased asset. At the financial lease´s inception, the Company recorded an asset and a liability for the same value, corresponding to the leased property’s fair value, or, if lower, the present value of the minimum lease payments. The corresponding rental obligations, net of finance charges, were included in other liabilities. Each lease payment was allocated between the liability and the finance cost. The finance cost was charged to profit or loss over the lease period so as to produce a constant periodic interest rate on the remaining liability balance for each period. Property, plant and equipment acquired under financial leases were depreciated over the asset’s useful life or, if lower, over the lease term. Leases in which a significant portion of the risks and rewards of ownership were not transferred to the Company were classified as operating leases. Payments made under operating leases (net of any incentive received from the lessor) were charged to profit or loss on a straight-line basis over the lease period.

F-59

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

Management has reviewed effective lease contracts and has recognized a right-of-use asset in the amount of U$S 8 million corresponding to the amount of the lease liability as of the adoption date (which equals the present value of the remaining lease payments), as detailed below:

Operating lease commitments as of 12.31.2018	10.5
Discount using incremental borrowing rate of 58.16% as of 01.01.2019	(2.4)
Exchange differences on translation	(0.1)
Lease liability recognised as of 01.01.2019	8

The rest of the identified lease commitments correspond to contracts ending within 12 months of the date of initial application, which continue to be recognized by the Company on a straight-line basis.

As of the adoption date, the Company has maintained the recorded book value for right-of-use assets and lease liabilities which were classified as finance leases under IAS 17.

Finally, no transition adjustments were made for leases in which the Company acts as a lessor.

Consequently, the Company has not recognized any adjustment to retained earnings upon the initial application of IFRS 16.

4.2New 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. 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, 2021, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. The Company estimates that its application will not have a significant impact on the Company’s operating results or financial position.

-     Conceptual Framework: in March 2018, the IASB published a revised conceptual framework which will supersede the current one. However, this framework is not a standard in itself and will not override any existing standard. The concepts of the revised conceptual framework will be immediately taken into consideration in the issuance of future standards by the IASB and the Interpretations Committee. Preparers of financial statements under IFRS will consider the revised conceptual framework for the development of accounting policies on matters not specifically addressed by the IFRS for annual periods beginning on or after January 1, 2020.

F-60

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

- IFRS 3 – “Business Combinations”: amended in October 2018. It clarifies the definition of business and establishes guidelines for determining whether a transaction should be accounted for as a business combination or as an acquisition of assets. It applies to acquisition transactions as from January 1, 2020, and allows for its early adoption.

- IAS 1 – “Presentation of Financial Statements” and IAS 8 – “Accounting Policies, Changes in Accounting Estimates and Errors”: amended in October 2018. They clarify the definition of materiality and incorporate the concept of “information shadowing” when there is an effect similar to omitting or reporting inaccurate information. They apply prospectively to annual periods starting on or after January 1, 2020, and allow for early adoption.

- Amendments to IFRS 9 – “Financial Instruments”, IAS 39 – “Financial instruments: Presentation” and IFRS 7 – “Financial Instruments: Disclosures”: it incorporates temporary exemptions in the case of hedge relationships affected by the interest rate benchmark reform pursuant to the recommendations published by the Financial Stability Board (FSB) in July 2014. Amendments are applicable to fiscal years starting on or after January 1, 2020, allowing for early adoption.

4.3Effects of changes in foreign exchange rates

4.3.1 Functional and presentation currency

The information included in these Consolidated Financial Statements is recorded and presented in U.S. Dollars, which is the Company’s functional currency, that is, the currency of the primary economic environment where the entity operates.

4.3.2 Foreign-currency transactions and balances

Foreign currency transactions are translated into the functional currency at the exchange rates prevailing on each transaction date or valuation date, when items are remeasured. Foreign exchange gains and losses arising on the settlement of monetary items and on translating monetary items at the closing of the fiscal year using year-end exchange rate are recognized within the financial results in the statement of comprehensive income, with the exception of capitalized amounts.

4.3.3 Group companies’ 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 recognized under “Other comprehensive income”.

F-61

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.3.4 Classification 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.

4.4Principles 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 cease 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 companies 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 recognized at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according IFRS 11 “Joint Arrangements”. 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.

F-62

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

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 (see Note 4.4.4 below), after initially being recognized at cost.

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognized at cost and adjusted thereafter 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. Dividends received or receivable from associates and joint ventures are recognized 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 at 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.

F-63

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

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 recognized 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 recognized 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 recognized 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 may mean 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 recognized in other comprehensive income are reclassified to profit or loss where appropriate.

F-64

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.5Segment 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 person/ 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.

4.6Property, plant and equipment

Property, Plant and Equipment is measured following the cost model. It is recognized 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, net of any income obtained from the sale of commercially valuable production during the launching 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.

F-65

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.6.1Depreciation 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
Substations:	35 years
High voltage lines:	40 - 45 years
Medium voltage lines:	35 - 45 years
Low voltage lines:	30 - 40 years
Transformer centrals:	25 - 35 years
Meters:	25 years
Vehicles:	5 years
Furniture, fittings and communication equipment:	5- 20 years
Computer equipment and software:	3 years
Tools:	10 years
Gas Plant and Pipeline:	20 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 Asset retirement obligations

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 recognized. 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 recognized immediately in profit or loss.

F-66

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.7Intangible assets

4.7.1Goodwill

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 at 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 CGUs 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.

4.7.2Concession arrangements

Concession arrangements corresponding to Edenor and 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 each asset’s useful life, which corresponds to the life of each concession agreement.

4.7.3Identified intangible assets in acquired investments

Corresponds to intangible assets identified at the moment of the acquisition of companies. Identified assets meet the criteria established in IFRS for capitalization less depreciation a 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.

4.8Assets 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-67

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.9Impairment 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 recognized 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.

4.10Financial assets

4.10.1Classification

The Group classifies its financial assets in the following categories:

i.	those that are subsequently measured at fair value (either through other comprehensive income or through profit or loss), 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 Statement of 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-68

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.10.2Recognition and derecognition

The conventional purchases and sales of financial assets are accounted for at trade date, that is, the date on which the Company undertakes to purchase or sell the asset, or at settlement date. Financial assets are derecognized 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.

4.10.3Measurement

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 amortised cost and is not part of a hedging relationship is recognized 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 recognized in profit or loss as long as they represent a return on investment.

4.10.4Impairment 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.

4.10.5Offsetting 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 recognized amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

F-69

 

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.11Trade and other receivables

Trade receivables and other receivables are recognized at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognises 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.

Receivables arising from services billed to customers but not collected by Edenor, as well as those arising from services rendered but unbilled at the closing date of each financial year are recognized at fair value and subsequently measured at amortized cost using the effective interest rate method. 

Receivables from electricity supplied to low-income areas and shantytowns are recognized, also in line with revenue, when the Framework Agreement has been renewed for the period in which the service was provided.

Where applicable, allowances for doubtful tax credits have been recognized 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 recognized assets or liabilities or over firm commitment (fair value hedge);
ii.	cash flow hedges of a particular risk associated with recognized 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.

F-70

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

Changes in the measurement of derivative financial instruments designated as cash flow hedge, which have been determined as effective, are recognized in equity. The gain or loss related to the ineffective portion is recognized immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognized in profit or loss.

The Company has not formally designated financial instruments as hedging instruments.

4.13Inventories

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 and Distribution of Energy business segments.

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 recognized 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”.

4.14Non-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 recognised for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognised 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 recognised. The gain or loss not previously recognised by the date of the sale of the non-current asset is recognised at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they be 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 recognized.

F-71

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

Non-current assets classified 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.

4.15Cash 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.

4.16Shareholder´s equity

Equity’s movements have been 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 detailed in Note 3.1, the Company has 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.

4.16.1Share 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. Ordinary shares are classified as equity.

F-72

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2019, 2018 and 2017 (Continuation)
(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.16.2Share 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 subsidiary and the value resulting from applying to the subsidiary’s merged equity interest, the new ownership share resulting from the exchange relationship.

4.16.3Legal 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, the related adjustment of share capital. When for any reason, the amount of this reserve will be shorter, dividends may not be distributed, until such amount is reached.

4.16.4Voluntary 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.

4.16.5Other 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.

4.16.6Retained earnings (Accumulated losses)

Retained earnings comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of the Shareholders' meeting, as long as they are not subject to legal restrictions. These earnings comprise 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.

F-73

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

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.

4.16.7Other 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.

4.16.8Dividends distribution

Dividend distribution to Company shareholders is recognized as a liability in the Consolidated Financial Statements 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.

4.17Compensation plans

Note 19 details the conditions applicable to the different compensation agreements and the main variables considered in the corresponding valuation model.

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

-	Compensations payable in cash:
i.	Compensation agreements – Senior Management: the reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton valuation model. The fair value of the amount payable under the compensation agreements 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.
ii.	Company Value Sharing (“Company-Value Compensation”) – Pampa (as PEPASA´s successor company): the Black-Scholes-Merton financial valuation model was used to make this estimate, taking into consideration the enforceability of the remuneration. The fair value of the amount payable for the compensation plan is accrued and acknowledged as an expense, with the recognition of an increase in liabilities. Liabilities are revalued on each balance sheet date and at their settlement date. Any change in the fair value of liabilities is disclosed under profit or loss.
iii.	Annual Variable Compensation granted to certain officers for the performance of technical and administrative duties amounting to 7% of the EBDA accrued (EBITDA less paid income tax, less total net financial costs, less interest on its own capital, considering an annual 10% dollar-denominated rate) of PEPASA´s continuing business in Pampa. The Company recognizes a provision (liability) and an expense for this EBDA Compensation based on the previously mentioned formula.

F-74

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

-	Compensations payable in shares
i.	Stock-based Compensation Plan – Officers and other key staff: the fair value of the received services is measured at the fair value of shares at the time of granting, and is disclosed during the vesting period, together with the corresponding increase in equity.
ii.	Stock-based Compensation Plan -Edenor: The fair value of the services received is disclosed as an expense and determined by reference to the fair value of the granted shares. When the employees provide the services before the shares are granted, the fair value at the grant date is estimated in order to recognize the respective result.

4.18Trade payables and other payables

Trade payables and other payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, except for particular matters described below.

4.18.1Customer guarantees

Customer guarantees are initially recognized at fair value and subsequently measured at amortized cost using the effective interest method.

In accordance with the Concession Agreement, Edenor is allowed to receive customer guarantees in the following cases:

i.	When the power supply is requested and the user is unable to provide evidence of his legal ownership of the premises;
ii.	When service has been suspended more than once in one-year period;
iii.	When the power supply is reconnected and Edenor is able to verify the illegal use of the service (fraud).
iv.	When the customer is undergoing liquidated bankruptcy or reorganization proceedings.

Edenor has decided not to request customer guarantees from residential tariff customers.

Customer guarantees may be either paid in cash or through the customer’s bill and accrue monthly interest at a specific rate of BNA for each customer category.

When the conditions for which Edenor is allowed to receive customer guarantees no longer exist, the customer’s account is credited for the principal amount plus any interest accrued thereon, after deducting, if appropriate, any amounts receivable which Edenor has with the customer.

4.18.2Edenor’s customer refundable contributions

Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements and the provisions of ENRE Resolution No. 215/12. These contributions are initially recognized as trade payables at fair value against Property, plant and equipment, and are subsequently measured at amortized cost using the effective interest rate method.

F-75

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.18.3Edenor’s particular matters

The recorded liabilities for penalties accrued, whether imposed or not yet issued by the ENRE (Note 2.3), and other provisions are the best estimate of the settlement value of the present obligation in the framework of IAS 37 provisions at the date of these Consolidated Financial Statements.

The balances of ENRE Penalties and Discounts are adjusted in accordance with the regulatory framework applicable thereto and are based on Edenor’s estimate of the outcome of the RTI process described in Note 2.3.

4.19Borrowings

Borrowings are recognized 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 recognized 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, cancelled 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.

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.

4.19.1Borrowing 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.

4.20Deferred revenues

Non-refundable customer contributions: Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements. The assets received are recognized by Edenor as Property, plant and equipment with a contra-account in deferred revenue, the accrual of which depends on the nature of the identifiable services, in accordance with the following:

i.	Customer connection to the network: revenue is accrued until such connection is completed;
ii.	Continuous provision of the electric power supply service: throughout the shorter of the useful life of the asset and the term for the provision of the service.

F-76

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.21Employee benefits

4.21.1Short-term obligations

Liabilities for wages and salaries, including non-monetary benefits and accumulating sick leave that are expected to be settled wholly within 12 months after the end of the period in which the employees render the related service are recognised in respect of employees’ services up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liabilities are presented as current salaries and social security payable in the consolidated statement of financial position.

4.21.2Defined 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 recognized 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 recognized in other comprehensive income (loss) in the period in which they arise and past service costs are recognized immediately in the statement of income (loss).

4.22Provisions, contingent liabilities and contingent assets

Provisions are recognized 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 each 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. The increase in the provision due to the passage of time is recognised as other financial results.

F-77

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– 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 no 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.

4.23Revenue from contracts with customers

4.23.1Generation segment:

4.23.1.1 Revenues from sales to the spot market (SRRYME Resolution No. 1/19)

The Company recognizes revenues from i) power availability 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 applicable depending on the technology of each plant and, in the case of thermal power plants, the application of the coefficient derived from the average usage factor over the last 12 months on the power capacity remuneration specified in the Resolution. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 45 days, which is consistent with market practice.

4.23.1.2 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 45 days, which is consistent with market practice.

4.23.1.3 Revenues from sales contracts with large users within the MAT (energy plus Resolution SE No. 1,281/06)

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.

F-78

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.23.2Distribution segment

4.23.2.1 Revenues from contracts with customers

Edenor's revenue is measured at the fair value of the consideration collected or to be collected, taking into account the estimated amount of any discount, thus determining the net amounts.

Edenor recognizes, on a monthly basis, revenues from electricity distribution as energy is distributed to each client based on the applicable tariff and procedures established by the ENRE. Such revenue includes energy delivered, whether billed or unbilled, at the end of each period. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

Edenor recognizes revenues related to energy supply to low-income areas and shantytowns, only to the extent that the Framework Agreement has been renewed for the period in which the service was rendered. As of the date of issuance of these Consolidated Financial Statements, the Framework Agreement is not currently in effect.

4.23.2.2. Edenor’s other revenues from contracts with customers

Edenor recognizes other revenues from contracts with customers in relation to connection and reconnection services, rights of use on poles and transport of energy to other distribution companies on a monthly basis as services are rendered based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

4.23.3Oil 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 recognized 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 30 days, which is consistent with market practice.

F-79

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.23.4 Petrochemical segment

The Company recognizes revenues from the sale of petrochemical products, whether in local or foreign market, 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:

(a)	when the products are dispatched and transported by and in charge of the client, or,
(b)	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 recognized 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 28 days, which is consistent with market practice.

4.23.5 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.

4.24Other Income

4.24.1Government 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. There are no unfulfilled conditions or other contingencies attaching to the following grants. The group did not benefit directly from any other forms of government assistance.

4.24.1.1Recognition of Compensation from Natural Gas Injection Promotion Programs

The Company recognizes revenues from Natural Gas Injection Promotion Programs when the delivery of the gas is effective based on the price established in the applicable regulation, only to the extent that it is highly probable that a significant reversal will not occur and it is probable that the consideration will be collected, that is, as the procedure established by Government is formally complied with. Although the consideration Programs´ collection depends on the Argentine Government’s payment capacity that has incurred in important delays in the cancellation of the credits in the past, revenues are not adjusted for the effect of financing components, which is consistent with market practice.

F-80

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

The recognition of income from Natural Gas Injection Promotion Programs is covered by IAS 20 since it involves a compensation as a result of the production increase committed.

This item has been disclosed under Natural Gas Injection Promotion Programs under Other operating income, in the Consolidated Statement of Comprehensive Income. Furthermore, ítem Extroardinary Canon disclosed within Other operating expenses includes fiscal costs related to these Programs.

4.24.2Interest income

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 carrying amount net of impairment provision.

4.24.3Dividends

Dividends are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognized as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

4.25Income tax and minimum notional income tax

4.25.1Current and deferred income tax

The tax expenses for the year include current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case, the tax is also recognized 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 recognized, 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 recognized 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 recognized only to the extent that it is probable that future taxable profit will be available and can be used against temporary differences.

F-81

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

Deferred income tax is provided on temporary differences from investments in subsidiaries 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 recognized on account of gains or losses from fiscal tax inflation which, pursuant to Law No. 27,541, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1.5).

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset the recognized 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), Venezuela, Ecuador, Bolivia, Spain and Uruguay are 30%, 50%, 25%, 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.

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.

4.25.2 Minimum notional income tax

The Company assessed the minimum notional income tax until December 31, 2018, by applying the current 1% rate over the assets computable at the closing of the year. As this tax supplements the income tax, the Company does not assess it for the periods where no income is evidenced on the income tax, based on the case law established by the “Hermitage” decision (CSJN, June 15, 2010), which ruled on the unconstitutionality of this tax when tax losses are disclosed for the period.

The Company’s tax obligation for each year will be the higher of the two taxes. If in a fiscal year, however, minimum notional income tax obligation exceeds income tax liability, the surplus will be computable as a payment in advance of income tax through the next ten years.

Pursuant to section 76 of Law No. 27,430, the effectiveness of this tax has been abrogated for fiscal years beginning on or after January 1, 2019, without affecting the remaining term for computing any payments made in excess during its life as payments on account of income tax.

As of the closing date hereof, the Company’s Management analyzed the receivable’s recoverability, and allowances are created in as long as it is estimated that the amounts paid for this tax will not be recoverable within the statutory limitation period taking into consideration the Company’s current business plans. The Company’s Management will evaluate the evolution of this recoverability in future fiscal years.

F-82

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

4.26Leases

In leases where the Company is a lessee (Note 18.1), a right-of-use asset and a lease liability are recognized 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 “Lease liability” under “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 18.2.1). Financial leases are recognized 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 recognized as a profit or a loss 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 derecognized if there is reasonable certainty that the Company will transfer its ownership at the end of the lease term.

F-83

 

 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2019, 2018 and 2017 (Continuation)
(in millions of U$S– unless otherwise stated)

NOTE 4: (Continuation)

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 18.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

NOTE 5: GROUP STRUCTURE

5.1. Business combinations

5.1.1 Corporate reorganization

The corporate reorganizations mentioned below are carried out in order to obtain important benefits for the Company and all its corporate group, as they will allow for enhanced operating efficiency; an optimized use of available resources; the leveraging of technical, administrative and financial structures; and the implementation of converging policies, strategies and goals. Furthermore, the complementarity between the participating companies could be leveraged, thus reducing costs resulting from the duplication and overlapping of operating and administrative structures.

The following reorganizations were perfected by means of a merger through absorption process, under the terms of tax neutrality pursuant to articles 80 and following of the Income Tax Law,whereby the absorbed companies will be dissolved without liquidation subject to the stipulations of the PMC and the provisions of sections 82 to 87 of Argentine Commercial Companies General Law, the CNV provisions, the BCBA Listing Rules and other provisions, the IGJ provisions and all other applicable legal and regulatory provisions.

5.1.1.1 2017 Reorganization

On September 22, 2017, the Company’s Board of Directors informed that the companies which would take part in the merger would be the Company, as absorbing company, and BLL, CTG, CTLL, EG3 Red, INDISA, INNISA, IPB, PP II and PEPASA, as absorbed companies.

The merger became effective on October 1, 2017, date as from which the transfer of the absorbed companies’ equity to the absorbing company became effective and, therefore, all their rights and obligations, assets and liabilities will become incorporated into the absorbing company’s equity, all of which subject to the corresponding corporate approvals under the applicable law and the registration with the Public Registry of Commerce of the merger and the dissolution without liquidation of the absorbed companies.

On December 21, 2017, the Board of Directors of Pampa Energía, as absorbing company and BLL, CTG, CTLL, EG3 Red, INDISA, INNISA, IPB, PP II and PEPASA, as absorbed companies, approved the Previous Fusion Commitment, and on April 27, 2018, the Extraordinary General Meetings of Shareholders approved the merger in agreement with the terms of the Previous Fusion Commitment.

F-84

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

On June 1, 2018, the final merger agreement was entered into between Pampa and the absorbed companies and was filed for registration before the applicable controlling authorities. On July 20, 2018 the CNV’s authorization on merger publication was obtained and on August 2, 2018, the Public Registry registered the merger. On August 15, 2018, the exchange of PEPASA, CTG, INNISA and INDISA shares for 144,322,083 of the Company was effected, with 1,880 shares remaining as treasury shares since they were fractional or decimal shares which were paid in cash. As of December 31, 2018, in accordance with current regulations, the Company proceeded to sell those shares. There was no exchange ratio for the remaining companies, as Pampa direct and indirect held 100% of the capital stock of these companies.

5.1.1.2 PAMPA – PEFM merger

On August 30, 2019, the Company and PEFM’s respective Boards of Directors approved the merger through absorption between the Company, as absorbing company, and PEFM, as absorbed company, establishing July 1, 2019 as the merger's effective date, as from which all PEFM’s rights and obligations, assets and liabilities were incorporated into the Company’s equity. There was no exchange ratio as the Company directly and indirectly held 100% of PEFM’s capital stock.

On October 15, 2019, the Company and PEFM’s respective Shareholders’ Meetings approved the merger process. On February 19, 2020, the CNV’s authorization on merger publication was obtained, its registration with the Public Registry remains pending.

5.1.1.3 PAMPA – CPB merger

On October 8, 2019, the Company’s Board of Directors instructed to move forward with the tasks allowing to assess the benefits of a merger through absorption process between the Company, as absorbing company, and CPB, as absorbed company, establishing January 1, 2020 as the merger's effective date.

5.1.2 Sale of participations and plant

5.1.2.1 Sale of interest in Greenwind

With the purpose of incorporating into the project a strategic partner contributing part of the investments necessary for the development of the Mario Cebreiro Wind Farm, on March 10, 2017, CTLL and PP entered into an agreement with Valdatana Servicios y Gestiones S.L.U., an entity which later changed its name to Viento Solutions S.L. for the sale of 50% of Greenwind’s capital stock and rights for a total amount of U$S 11.2 million.

5.1.2.2 Sale of interest in Oldelval

On November 2, 2018, the Company entered into an agreement with ExxonMobil Exploration Argentina S.R.L. for the sale of 21% of Oldelval’s capital stock and rights, maintaining the remaining 2.1% interest.

Subsequently, on November 27, 2018, the transaction was closed upon the meeting of the applicable precedent conditions, the purchase price paid by the purchaser amounted to U$S 36.4 million. As a result of the transaction, the Company has recognized a U$S 28 million gain, before taxes.

F-85

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.1.2.3Sale of the Dock Sud storage terminal

On March 6, 2019, the Company agreed with Raízen Argentina, a licensee of the Shell brand, on the sale, subject to the meeting of certain conditions precedent which are customary for this kind of transactions, of the Dock Sud storage terminal, which tank yard has a total installed capacity of 228 thousand m3.

On March 30, 2019, after the meeting of all precedent conditions, the transfer of the Dock Sud Terminal to the purchaser was completed at a price of U$S 19.5 million, plus U$S 2 million on account of products. The transaction resulted in profits before income tax in the amount of U$S 1 million, which are disclosed in item “Gains/losses on the sale of Property, plant and equipment” under “Other operating income”.

5.2 Discontinued operations

As of December 31, 2018 and 2017, the results of operations related to divestment transactions detailed below, have been disclosed within “Discontinued Operations” in the consolidated statement of comprehensive income.

5.2.1 Sale of PELSA shares and certain oil areas

On January 16, 2018, the Company agreed to sell to Vista Oil & Gas S.A.B. de C.V. (“Vista”) its direct 58.88% interest in PELSA and its direct interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Medanito-Jagüel de los Machos blocks, in line with the Company's strategy to focus its investments and human resources both on the expansion of its power generation installed capacity and on the exploration and production of natural gas, placing a special focus on the development and exploitation of unconventional gas reserves, as well as to continue investing on the development of its utility concessions.

On April 4, 2018, upon the meeting of all applicable conditions precedent, the transaction was closed. The price paid by Vista, considering the agreed adjustments regarding interests in PELSA, amounted to U$S 389 million. This transaction generated a profit comprehensive income net of taxes in the amount of U$S 30 million, as follows:

	12.31.2018
Sale price (2)	270
Book value of assets sold and costs associated with the transaction	(226)
Result for sale	44
Interests (1)	4
Income tax	(22)
Imputed in results	26
Other comprehensive income (loss)
Reclasification exchange differences on translation	6
Income tax	(2)
Imputed in Other comprehensive income	4
Total comprehensive income	30

(1)	Are exposed in "Financial income" in the consolidated statement of comprehensive income related to discontinued operations.
(2)	Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

F-86

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.2.2 Sale of assets in the Refining and Distribution segment

On December 7, 2017, the Company executed with Trafigura Ventures B.V and Trafigura Argentina S.A. an agreement for the sale of certain assets in the Company’s refining and distribution segment based on the conviction that the oil refining and distribution business calls for a larger scale to attain sustainability.

The assets subject-matter of the transaction were: (i) the Ricardo Eliçabe refinery; (ii) the Avellaneda lubricants plant; (iii) the Caleta Paula reception and dispatch plant; and (iv) the network of gas stations currently operated under Petrobras branding. The Dock Sud storage facility was excluded from the sale, as well as the Company's investment in Refinería del Norte S.A.

Pursuant to the foregoing, and in relation with the measurement of the assets and liabilities subject to this transaction at thelower of fair value less cost to sell and the carrying value, as of December 31, 2017, the Company recognized an impairment of Intangible assets and Property, plant and equipment in the amount of U$S 28 million.

On May 9, 2018, upon the meeting of all applicable precedent conditions the transaction was subject to, the closing of the sale to Trafigura was carried out. After applying the adjustments stipulated in the purchase and sale agreement, the transaction price amounted to U$S 124.5 million. Furthermore, after the closing of the transaction, Trafigura paid to Pampa U$S 56 million for the purchase of crude oil.

As of December 31, 2018, the closing of the transaction did not generate additional profits or losses, according to the following detail:

	12.31.2018
Sale price (1)	28
Book value of assets sold and costs associated with the transaction	(28)
Result for sale	-

⁽¹⁾ Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

The Company considers that under IFRS it has transferred control over the whole assets since, pursuant to the participation agreements entered into with Trafigura, it has not retained the power to redirect their use or substantially derive other benefits. However, as of the issuance of these Consolidated Financial Statements the process for the legal transfer and actual assignment of the agreements associated with three gas stations has started with the rebranding of to the “Puma” brand, owned by Trafigura, this process is expected to end during the first semester of 2020.

F-87

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.2.3 Relevant information on discontinued operations

As of December 31, 2018:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	66	422	(90)	398
Cost of sales	(33)	(361)	91	(303)
Gross profit	33	61	1	95
Selling expenses	(2)	(33)	-	(35)
Administrative expenses	(1)	(4)	-	(5)
Other operating income	1	6	-	7
Other operating expenses	(6)	(10)	-	(16)
Result from the sale of share of profit and property, plant and equipment	44	-	-	44
Operating income	69	20	1	90
Gain on monetary position, net	7	2	(1)	8
Finance income	4	1	-	5
Finance costs	(1)	-	-	(1)
Other financial results	(4)	22	-	18
Financial results, net	6	25	(1)	30
Income before income tax	75	45	-	120
Income tax	(26)	(14)	-	(40)
Profit  of the year from discontinued operations	49	31	-	80
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	(2)	-	-	(2)
Reclasification exchange differences on translation	6	-	-	6
Exchange differences on translation	4	-	-	4
Other comprehensive income of the year from discontinued operations	8	-	-	8
Total comprehensive income  of the year from discontinued operations	57	31	-	88
	Oil and gas	Refining and distribution	Eliminations	Total
Total income of the year from discontinued operations attributable to:
Owners of the company	47	31	-	78
Non - controlling interest	2	-	-	2
	49	31	-	80
Total comprehensive income of the year from discontinued operations attributable to:
Owners of the company	53	31	-	84
Non - controlling interest	4	-	-	4
	57	31	-	88

F-88

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

As of December 31, 2017:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	259	728	(296)	691
Cost of sales	(251)	(618)	297	(572)
Gross profit	8	110	1	119
Selling expenses	(8)	(82)	-	(90)
Administrative expenses	(6)	(19)	-	(25)
Exploration expenses	(1)	-	-	(1)
Other operating income	16	10	-	26
Other operating expenses	(8)	(13)	-	(21)
Result from the sale of  property, plant and equipment	-	(28)	-	(28)
Operating income (loss)	1	(22)	1	(20)
Financial income	1	1	-	2
Financial expenses	-	(1)	-	(1)
Other financial results	(10)	(1)	-	(11)
Financial results, net	(9)	(1)	-	(10)
Income (loss) before income tax	(8)	(23)	1	(30)
Income tax	(28)	8	-	(20)
Profit (loss) of the year from discontinued operations	(36)	(15)	1	(50)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	2	-	-	2
Exchange differences on translation	(16)	-	-	(16)
Other comprehensive loss of the year from discontinued operations	(14)	-	-	(14)
Total comprehensive income (loss) of the year from discontinued operations	(50)	(15)	1	(64)
	Oil and gas	Refining and distribution	Eliminations	Total
Total income (loss) of the year from discontinued operations attributable to:
Owners of the company	(41)	(15)	1	(55)
Non - controlling interest	5	-	-	5
	(36)	(15)	1	(50)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company	(48)	(15)	1	(62)
Non - controlling interest	(2)	-	-	(2)
	(50)	(15)	1	(64)

F-89

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

The consolidated statement of cash flows related to discontinued operations is presented below:

	12.31.2018	12.31.2017
Net cash (used in) generated by operating activities	(46)	87
Net cash used in investing activities	-	(50)
Net cash generated by (used in) financing activities	42	(31)
(Decrease) increase in cash and cash equivalents from discontinued operations	(4)	6
Cash and cash equivalents at the begining of the year	6	4
Loss on net monetary position generated by cash and cash equivalents	(2)	(4)
(Decrease) increase in cash and cash equivalents	(4)	6
Cash and cash equivalents at the end of the year	-	6

F-90

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.Interest in subsidiaries, associates and joint ventures

5.3.1 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.
 

			12.31.2019	12.31.2018
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Corod	Argentina	Oil	100.00%	100.00%
CPB	Argentina	Generation	100.00%	100.00%
CPB Energía S.A.	Argentina	Generation	100.00%	100.00%
EcuadorTLC	Ecuador	Oil	100.00%	100.00%
Edenor (1)(7)	Argentina	Distribution of energy	56.32%	52.18%
Enecor S.A.	Argentina	Transportation of electricity	69.99%	69.99%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
PACOSA	Argentina	Trader	100.00%	100.00%
PEA (2)	Argentina	Generation	-	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PACOGEN	Argentina	Investment	100.00%	100.00%
PEFM (3)	Argentina	Generation	-	100.00%
Petrobras Energía Colombia Gran Cayman (4)	Colombia	Oil	-	100.00%
Petrobras Energía Ecuador	Gran Cayman	Investment	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
PHA (5)	Argentina	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
PP	Argentina	Investment	100.00%	100.00%
PPSL (6)	Spain	Investment	-	100.00%
TGU	Uruguay	Gas transportation	100.00%	100.00%
Transelec	Argentina	Investment	100.00%	100.00%
Trenerec Energía Bolivia S.A.	Bolivia	Investment	100.00%	100.00%
Trenerec S.A.	Ecuador	Investment	100.00%	100.00%

(1)	Corresponds to effective interest considering the treasury shares in Edenor´s effect (54.3664% nominal interest)
(2)	On May 29, 2019, PEA’s Shareholders’ Meetings resolved to change its corporate name to CTB. In the month of June 2019, the Company sold to PACOGEN and YPF 48% and 50%, respectively, of its interest in CTB, whereas PP sold to PACOGEN 2% of its interest in CTB.
(3)	See Note 5.1.1.2.
(4)	Liquidated in January 2019.
(5)	On March 28, 2019, the Company approved PHA’s international address change from Madrid (Spain), to the Autonomous City of Buenos Aires (Republic of Argentina), and on September 20, 2019, the change of jurisdiction was registered with the Public Registry.
(6)	Liquidated in December 2019.
(7)	As of December 31, 2019, the quotation of Edenor's ordinary shares and ADR published on the BCBA and the NYSE was $ 24.05 and U$S 6.26 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 149 million. It should be noted that, as of December 31, 2019, participation in Edenor does not exceed its recoverable value.

F-91

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.1.1 Summarised financial information for each subsidiary that has significant non-controlling interest

Non-controlling interests in subsidiaries are not significant for the Company, except for Edenor with 54.3664% equity interest.

Edenor is registered in Argentina, which is also the place where it develops its activities.

5.3.1.1.1 Edenor’s Summary statement of financial position
 

	12.31.2019	12.31.2018
Non Current
Total non current assets	1,696	1,679
Borrowings	137	191
Other non current liabilities	460	474
Total non current liabities	597	665
Current
Cash and cash equivalents	7	1
Other current assets	292	363
Total current assets	299	364
Borrowings	28	29
Other current liabilities	383	528
Total current liabilities	411	557
Total equity	988	821
Non-controlling interest	451	396

5.3.1.1.2 Edenor’s Summary statement of comprehensive income

	12.31.2019	12.31.2018	12.31.2017
Revenue	1,502	1,484	1,050
Depreciation	(77)	(68)	(57)
Interest income	20	18	12
Interest expense	(113)	(132)	(68)
Profit for the year before tax	381	164	148
Income tax	(178)	(50)	(14)
Profit for the year	203	114	134
Other comprehensive loss	-	(1)	-
Total comprehensive profit of the year	203	113	134
Income of the year attributable to non-controlling interest	98	55	65
Other comprehensive income of the year attributable to non-controlling interest	-	(1)	-
Comprehensive income of the year attributable to non-controlling interest	98	54	65

F-92

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.1.1.3 Edenor’s Summary statement of cash flow

	12.31.2019	12.31.2018	12.31.2017
Net cash generated by operating activities	170	255	78
Net cash used in investing activities	(86)	(221)	(63)
Net cash used in financing activities	(85)	(56)	(13)
(Decrease) increase  in cash and cash equivalents	(1)	(22)	2
Cash and cash equivalents at the begining of the year	1	3	3
Loss on net monetary position generated by cash and cash equivalents	7	19	2
Cash and cash equivalents at the end of the year	7	-	7

5.3.2Investments 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 period / year	Equity	Direct and indirect participation %
Associates
Refinor	Refinery	09.30.2019	2	(3)	57	28.50%
OCP (1)	Investment	12.31.2019	100	22	266	15.91%
TGS (2)(5)	Transport of gas	12.31.2019	13	214	803	27.193%
Joint ventures
CIESA (2)	Investment	12.31.2019	11	109	405	50.00%
Citelec (3)	Investment	12.31.2019	9	38	176	50.00%
Greenwind	Generation	12.31.2019	-	(1)	(11)	50.00%
CTB (4)	Generation	12.31.2019	143	40	227	50.00%

(1)	The Company holds an indirect interest of 15.91% through PEB.
(2)	The Company holds a direct and indirect interest of 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. therefore, the Company has an indirect participation of 25.50% in TGS. The Company holds a direct and indirect interest of 1.693% in TGS.
(3)	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.
(4)	The Company holds an indirect interest of 50% through PACOGEN.
(5)	As of December 31, 2019, the quotation of TGS's ordinary shares and ADR published on the BCBA and the NYSE was $ 108.65 and U$S 7.17 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 306 million.

F-93

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

The details of the balances of investments in associates and joint ventures are as follows:

	12.31.2019	12.31.2018
Disclosed in non-current assets
Associates
Refinor	20	25
OCP	33	35
TGS	21	-
	74	60
Joint ventures
CIESA	235	259
Citelec	88	88
CTB	114	-
	437	347
	511	407
Disclosed in non-current liabilities
Greenwind (1)	4	4
	4	4

⁽¹⁾The Company provides financial assistance to this company.

F-94

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

The following tables show the breakdown of the result from investments in associates and joint ventures:

	12.31.2019	12.31.2018	12.31.2017
Associates
Oldelval	-	3	1
Refinor	(3)	(4)	(3)
OCP	21	35	-
TGS	1	-	-
	19	34	(2)
Joint ventures
CIESA	50	74	25
CTB	13	-	-
Citelec	19	21	27
Greenwind	-	(11)	(2)
	82	84	50

The evolution of investments in associates and joint ventures is as follows:

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year		403	315	255
Reclassifications (1)		(16)	-	12
Dividends	17	(75)	(19)	-
Decreases		-	(10)	-
Increases		108	-	-
Share of profit		101	118	48
Other comprehensive loss		-	(1)	-
Exchange differences on translation		(14)	-	-
At the end of the year		507	403	315

⁽¹⁾ In 2019, mainly corresponds to the financial credit with OCP acquired in the transaction with AGIP (see Note 5.3.6.2), and in 2017 corresponds to the deconsolidation for sale of the interest in Greenwind.

F-95

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.3 Investment in CIESA-TGS

5.3.3.1 Issuance of Corporate Bonds

On May 2, 2018, under the Short and Medium-Term Corporate Bonds Program for a maximum amount of U$S 700 million approved by the CNV, TGS issued Class 2 corporate bonds for U$S 500 million at an annual 6.75% rate. Collected funds will be destined by TGS to: (i) the repurchase of Class 1 corporate bonds, (ii) the redemption of Class 1 corporate bonds; and (iii) capital expenditures.

TGS General Shareholders' Meeting held on August 15, 2019 approved the extension of TGS´s Corporate Bonds Program from U$S 700 million to U$S 1.2 billion. This extension was authorized on October 9, 2019, by the CNV.

5.3.3.2 Acquisition of own shares in TGS

During 2018, TGS’ Board of Directors approved two programs for the repurchase of own shares, on May 9, 2018 and September 6, 2018, which were executed according to the programs established terms. For the definition of these programs, the TGS’ Board of Directors considered TGS’ strong cash position and fund availability, in view of the fact that the TGS’ share price does not reflect either the value or the economic reality its business currently or potentially have.

On March 27, 2019, TGS’ Board of Directors approved a third program for the repurchase of own shares, for a maximum amount of up to $ 1,500 million (in terms of the constitution date).

On August 26, 2019, after terminating the third repurchase program, the TGS’ Board of Directors approved a forth program for the repurchase of own shares for a total amount of $ 3,200 million (in terms of the constitution date).

TGS’s own shares acquired as of October 31, 2019 were distributed as dividend in shares.

Finally, on November 19, 2019, a fifth program for the repurchase of own shares was approved for a total amount of $ 4,000 million (in terms of the constitution date). This program has a 120 days term.

As of December 31, 2019, TGS holds 9,886,755 treasury shares in its portfolio, which represent 1.24% of its total capital stock.

5.3.3.3 Acquisition of TGS’s ADRs by the Company

During the fiscal year ended December 31, 2019, the Company acquired a total number of 1,130,365 TGS’s ADRs, at an acquisition cost of U$S 8 million.

F-96

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.3.4 Vaca Muerta Project

During 2019, TGS successfully completed the assembly and pressurization works on the facilities of an important project at Vaca Muerta that involves a total investment of approximately U$S 260 million and will materially impact on the development of the Vaca Muerta natural gas reserves.

The project consisted in the construction of a gas collector pipeline that will allow to transport natural gas extracted by natural gas producers to the regulated transport systems operated by TGS and TGN and a gas conditioning plant in Tratayén city.

The Vaca Muerta system have two collector pipelines; the first of them with an extension of 115 kilometers, a 36" diameter and 35 MMm3/d transport capacity (the "Northern Trench") and the second one with an extension of 33 kilometers, 30" diameter and 25 MMm3/d transport capacity (the "South Trench"). The gas transported by these pipelines system will be treated in the new conditioning plant that TGS constructed in Tratayén city, Province of Neuquén with 5.0 MMm3/d of initial capacity.

For the development of this project, the implementation of long-term service agreements with different producers was essential to establish the terms and conditions for the provision of transportation and natural gas conditioning services in order to meet ENERGAS’ regulatory requirements to access to the regulated transport system. In this way, TGS becomes the First Midstreamer of Vaca Muerta.

Additionally, in February 2020, TGS approved an investment project with a 1-year execution estimated period and U$S 15 million estimated investment. The project will consist in the conditioning plant capacity increase by 2.6 MM3/d, the installation of a butane extraction unit and the construction of facilities for the storage and dispatch of liquids.

5.3.4 Investment in CITELEC

5.3.4.1 Employee Shareholding Program – Transba S.A.

In the year 1997, the Executive Branch of the Province of Buenos Aires awarded 100% of Transba’s Series “A”, “B” and “C” shares to Transener. Series “C” shares were awarded subject to the obligation to transfer them to the Employee Shareholding Program benefiting certain Transba employees, Transener holding 89.99% of Transba’s capital stock.

On June 28, 2019, Transener acquired all the shares under such program. Consequently, Transener holds 99.99% of Transba’s capital stock.

5.3.4.2 Repurchase of own Corporate Bonds - Transener

As of December 31, 2019 Transener’s Corporate Bonds Class 2 amounted to U$S 98.5 million, of which U$S 5 million and U$S 2 million have been acquired and by Transba S.A and Transener S.A., respectively.

F-97

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.5 Investment in CTB

5.3.5.1 Acquisition of CTEB

On May 29, 2019, the Company, after filing a joint offer, received a notification from IEASA whereby PISA, a subsidiary of the Company, through its subsidiary, PACOGEN, and YPF, were awarded National and International Public Tender No. 02/2019, launched pursuant to SGE Resolution No. 160/19, regarding the sale and transfer by IEASA of CTEB. The acquisition of CTEB also involves the assignment in favor of the awardee of the contractual capacity as trustor under the Enarsa-Barragán Financial Trust, the VRDs of which (excluding the VRDs to be acquired by the awardee) amount to U$S 229 million.

CTEB, 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.

The awardee will have to obtain the commissioning of the closing of the combined cycle within a term of 30 months as from the Seventh Amendment to the Trust Agreement’s effective date, thus increasing the installed power capacity to 847 MW, with an estimated investment of U$S 200 million.

Both the open and the closed cycle have effective power purchase agreements with CAMMESA under Resolution No. 220/07 issued by the former SE: the first one, entered into on March 26, 2009 and terminating on April 27, 2022, as amended and modified from time to time, and the second one dated March 26, 2013 for a term of 10 years as from the commercial operation of the combined cycle.

On June 26, 2019, the acquisition by CTB, a company co-controlled by YPF and PACOGEN, of CTEB transferred by IEASA was completed. The acquisition’s relative price was U$S 282 million, an amount which includes the final (cash) amount offered in the Tender and the acquired VRDs’ purchase price, paid with a contribution of U$S 200 million received by CTB, settled in equal parts by its co-controlling companies, and with a loan received by CTB from a bank syndicate of U$S 170 million.

The Power Plant will be managed and operated by Pampa and YPF on a rotational basis over 4-year periods. Pampa will be responsible for managing CTEB’s operations until 2023. And YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for the closing of the combined cycle.

The following table details the consideration transferred and the fair value of the assets acquired and the liabilities assumed by CTB as of June 26, 2019:

	in million U$S
Total consideration transferred (1)	(272)
Financial assets at fair value	16
Property, plant and equipment	477
Inventories	8
VRDs	(229)
Fair value of net assets	272

⁽¹⁾Includes U$S 53 million for the purchase of the acquired VRDs and considers a U$S 10 million of a price adjustment in favor of CTB.

F-98

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

The fair value of property, plant and equipment items and inventories was calculated considering mainly the depreciated replacement cost of the acquired goods. For this purpose, CTB was assisted by an independent specialist engaged by management.

The replacement cost approach was applied to measure buildings, equipment, installations and works in progress. The methodology applied to determine their fair value entailed:

1. the calculation of replacement costs (mainly based on consultations with suppliers and the analysis of specialized publications and information),
2. an estimate of residual values at the end of their useful life (based on the interest generated by the asset at the end of its useful life and the owner’s disposal policy), and
3. the application of deductions for physical, functional and/or economic impairment, if applicable.

The methodology for the determination of the remaining useful life was focused on the analysis of aging, wear and loss of service capacity of the assets resulting from normal use in the activities where they operate.

Regarding the work in progress for the closing of the combined cycle, which will allow a 280 MW rated power capacity increase, an estimate of the work progress’ percentage and the depreciation of the installed equipment was made based on physical inspections and the information supplied by the contracts to complete civil and electromechanical works for the closing of the combined cycle.

Lastly, a comparative sales approach was used to measure lands and vehicles. For this purpose relevant market data was gathered, mainly sales prices of lands in surrounding areas and published sales prices for vehicles.

Additionally, CTB has calculated the weighted present value of future cash flows it expects to receive from the assets to confirm that its fair value does not exceed their recoverable value.

As a result of the described process, CTB has not recorded intangible assets associated with the business acquisition.

5.3.5.2 Financial Trust Agreement

As a result of CTEB’s award, 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 financial trust, on April 25, 2011, Series B VRDs with public offering for a face value of U$S 582,920,167 were issued. The trust’s underlying flow is made up of the collection rights resulting from the Power Purchase Agreements originally entered into between ENARSA and CAMMESA, where CTB substitutes ENARSA (currently IEASA) as counterparty.

F-99

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

Pursuant to the agreement currently in force, CAMMESA will deposit the amounts required by the Trustee in the trust account, which will be destined to the payment of the Trust’s expenses and taxes, the replenishment of expense, reserve and settlement reserve funds, and the payments of Series B VRDs pursuant to the payment schedule.

On June 26, 2019, CTB entered into a VRDs transfer agreement with IEASA whereby CTB acquired the outstanding Series B VRDs for a price of U$S 53.5 million (equivalent to 109,628,836 Series B VRDs with a face value of U$S 1 each), thus becoming the holder of such VDRs (the “Trustor’s VRDs”).

On August 22, 2019, the seventh amendment to the Trust Agreement was executed, which incorporated several modifications, including the following:

- as regards the VRDs: i) the granting of a 24-month grace period (during which only interest will be payable); ii) the modification of the interest rate by the Libor rate plus 6.5%; iii) the determination of capital amortization repayments over a 60-month period (to derive constant debt services);

- the obligation to complete the closing of the combined cycle within a term of 30 months, the breach of this obligation resulting in the acceleration of the VRDs;

- the incorporation of additional collection rights regarding both the open and the closed-cycle power purchase agreements;

- establishing that payments to the Trust should be transferred simultaneously, with the same payment priority and in the same kind than under the Syndicated Loan (and any other debt allowed under the Trust);

- providing that upon the occurrence of a CAMMESA Event (pursuant to the definition of this term in the Trust Agreement): (i) CTB may request funds to meet the power plant’s operating expenses, and (ii) VRDs payments will be rescheduled in case funds received as collection rights are insufficient;

- modifying the amount of the Reserve Fund (pursuant to the definition of this term in the Trust Agreement) to the amount equivalent to the estimate of the next two services under the VRDs.

In accordance with the commitment undertaken in the Trust Agreement, pursuant to a resolution dated October 24, 2019, the CNV authorized the cancellation of the Trustor’s VRDs, which was effected on October 29, 2019. Consequently, on October 31, 2019, the eighth amendment to the Trust Agreement was entered into in order to include the new payment schedule effective as from such cancellation.

As of the date of issuance of these Consolidated Financial Statements, IEASA holds VRDs with a face value of 473,291,331.

5.3.5.3 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 U$S 170 million maturing on June 26, 2022, with U$S 136 million accruing a fixed 10.25% interest rate and U$S 34 million accruing a variable LIBOR rate+6.25.

F-100

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

On June 25, 2019, the Company executed a share pledge agreement in favor of the Lenders. Additionally, on August 22, 2019, YPF and PACOGEN entered into an amendment to the pledge agreement to include VRD holders as beneficiaries.

CTB endorsed the insurance policy, which covers CTEB’s open cycle’s operating risk, so that secured creditors should be the recipients of any payment, compensation and/or damages under such policy.

Additionally, CTB and Citibank, N.A.’s Branch (incorporated in the Republic of Argentina), in its capacity as trustee and sole beneficiary of the lenders, executed a trust assignment security agreement, which includes the assignment of the collection rights assigned to the Trustor for up to 42% of the amount to be settled, which CTB is entitled to collect pursuant to the power purchase agreements, net of added-value tax.

Finally, in order to coordinate the execution of the rights shared by the VRD holders and the Lenders under the Share Pledge Agreement and the endorsement of the policy, on August 22, 2019 BICE Fideicomisos S.A., in its capacity as Trustee under the Enarsa-Barragán Trust, executed with the Lenders an inter-creditor agreement that includes certain commitments regarding the exercise of its rights associated with the distribution of funds collected as a result of the possible execution of the guarantees shared by the VRD holders and the Lenders, and their interests in the payments to be made under such guarantees.

5.3.5.4 Granted guarantees

YPF and Pampa jointly guarantee, at 50% each, the timely and proper performance of all payment obligations under i) the Financial Trust Agreement, and ii) the Syndicated Loan Agreement, in case the closing of the combined cycle’s commissioning is not achieved i) within 30 months as from the seventh amendment to the agreement’s effective date, and ii) by December 26, 2021, respectively.

5.3.6 Other interest in Associates

5.3.6.1 Interests in mixed companies in Venezuela:

Interests in Petroritupano S.A. (22%), Petrowayú S.A. (36%), Petroven-Bras S.A. (34.49%) and Petrokariña S.A. (34.49%), companies organized as a result of the migration of operating agreements regulating the exploitation in Venezuela of the Oritupano Leona, La Concepción, Acema and Mata areas, respectively, were incorporated with the purchase of PPSL’s capital stock.

F-101

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

Given that as of the date of the acquisition of PPSL, the authorizations regarding the change of indirect control by the Government of Venezuela were not obtained, and considering the fact that the contracts of mixed companies provide the mandatory transfer of the shares for these cases, the Company has determined market value for its investment as of the date of acquisition was zero, considering: i) the monetary and fiscal policies implemented by the Venezuelan government together with the significant drop in international oil prices since 2014 that have eroded the ability of the mixed companies to efficiently operate the producing fields that resulted in increasing losses and reduction of equity in those investments, and ii) that there is very unlikely to acquire these assets in a stand-alone transaction, as conversion contracts establish that the transfer of direct control of the shares without obtaining prior approval of Venezuelan Government, implies that such participation is considered finished and all of the shares shall be transferred without any consideration in exchange for those shares.

Pampa has not recognized any share in the additional losses from these investments as it has not incurred any legal or implicit obligations or made any payments in the name of these mixed companies as from the acquisition date.

Additionally, under the agreements migration process, in 2006 the Venezuelan Government recognized in favor of the participating Company an interest-free severable and transferable credit in the amount of U$S 88.5 million which may be used to pay acquisition bonds under any new mixed company projects for the development of oil exploration and production activities, or licenses for the development of gas exploration and production operations in Venezuela. Since no projects have been undertaken for its use, negotiations for its transfer to third parties have been unsuccessful, and there are no other foreseen application alternatives, the Company keeps this credit valued at zero.

The Company has submitted the requested technical, legal and financial information, as well as development plans and financing proposals, to the consideration of CVPSA’s (Corporación Venezolana de Petróleo S.A.) majority shareholder, without obtaining, at the date of issuance of these Consolidated Financial Statements, the authorizations regarding the change of indirect control. Furthermore, CVPSA has expressed that, in view of the time elapsed, the Company should begin a new process for the presentation of plans under the guidelines to be provided by the Ministry of People’s Power for Oil of the Bolivarian Republic of Venezuela, which have not been informed to the Company yet. Given these circumstances, the Company has expressed to the Venezuelan Government’s authorities that it is no longer interested in submitting investments and/or financing proposals in mixed companies and that it is willing to negotiate the transfer of its shares to CVPSA. As of the date of issuance of these Consolidated Financial Statements, the Company has not received notifications in this regard.

F-102

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.3.6.2 Investment in OCP

The Company has an equity interest in OCP, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.

On December 6, 2018, OCP entered into a settlement agreement with the Republic of Ecuador to terminate all claims and legal actions brought by the parties regarding discrepancies with the Ecuadorian Treasury. This agreement stipulated a total settlement amount of U$S 182 million, of which U$S 64 million were offseted with receivables from income tax withholdings made by OCP in the 2004-2005 and 2007-2014 periods and U$S 7 million with a payment previously made by OCP corresponding to the determination of the 2003 fiscal year, and the remaining U$S 111 million were paid in cash in two installments. After satisfactorily meeting the stipulated obligations, on December 21, 2018, the parties executed a settlement agreement letter. As a result of the agreement, OCP has recorded profits for U$S 387 million.

In this regard, the Company has resumed recognising its 11.42% interest in OCP’s profits, through PEB, after recording previously unrecognized losses related to OCP´s negative equity, and being the investment valued at zero by the Company as a consequence of not making any capital contributions or financial assistance commitments to OCP, therefore, it has recognised profits for the participation in OCP’s results in the amount U$S 35 million as of December 31, 2018.

On the other hand, on December 5, 2018, and before the execution of the agreement between OCP and the Ecuadorian Government detailed above, the Company, through its subsidiary PEB, executed an agreement with Agip Oleoducto de Crudos Pesados ​​BV (“AGIP”) for the purchase of shares representing 4.49% OCP’s capital stock and of the financial credit that AGIP held with respect to the subordinated debt issued by OCP, in consideration of a base price equivalent to U$S 1 (one U.S. dollar).

On June 20, 2019, after meeting of all precedent conditions the transaction was subject to, including the notification received by OCP on March 19, 2019 regarding the authorization by the Ecuadorian Government on March 8, 2019, the transaction was closed and registered with the Shareholders’ Registry Book.

Pursuant to the agreement, in case the above-mentioned financial credit was collected by PEB before its maturity in 2021, PEB should reimburse AGIP 50% or 25% of the collected amount if collection occurs in 2019 or 2020, respectively.

Taking into consideration the timeliness of the agreement with AGIP, which was executed prior to the reversal of the above-mentioned situation, the closing of the transaction involved the recognition of a profit of U$S 25 million under IAS 28.

In order to estimate the 4.49% share in the fair value of identifiable assets and liabilities assumed in OCP, PEB has calculated the present value of future cash flows expected to be obtained through the collection of dividends considering the concession term that extends until 2023 and a discount rate of 15.3%.

F-103

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

The following table details the consideration transferred and the fair value of the assets acquired and the profit recorded by PEB as of June 20, 2019:

	in million  U$S
Acquisition cost (1)	(0.4)
Contingent consideration (2)	(0.1)
Total consideration	(0.5)
Share value of the interest in the fair value of associates’s identifiable assets and liabilities	9.0
Financial credit with OCP	14.2
Dividends to be received	2.5
Assets fair value	25.7
Profit (3)	25.2

(1)	Including expenses paid by PEB to the Ecuadorian Government (Ministry of the Environment) of U$S 0.1 million for the granting of the authorization to transfer the shares held by AGIP and other advisory expenses related to the transaction.
(2)	Contingent consideration calculated based on the estimated of the likelihood of collection of the financial credit with OCP prior to maturity.
(3)	Disclosed under “Share of profit (loss) from associates and joint ventures”

Furthermore, as of December 31, 2019, PEB recorded an impairment loss regarding the 11.42% interest in OCP (before the acquisition of the additional 4.49%) of U$S 6.7 million in connection with the present value of future cash flows expected to be obtained from such interest. Thus, the book value does not exceed the investment’s recoverable value.

5.4OPERATIONS IN OIL AND GAS CONSORTIUMS

5.4.1 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.

According to Law No.17,319, royalties equivalent to 12% of the wellhead price of crude oil and natural gas are paid in Argentina. 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-104

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.4.2 Oil and gas participation details

As of December 31, 2019, the Company and associates are part of the joint operations and consortia for the exploration and production of oil and gas as indicated below:

			Participation
Name	Note	Location	Direct	Indirect	Operator	Duration Up To
Argentine production
Río Neuquén		Río Negro and Neuquén	31.43% 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		Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala		Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento		Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro		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
Foreign (1)
Oritupano - Leona		Venezuela	-	22.00%	PDVSA	2025
Acema		Venezuela	-	34.49%	PDVSA	2025
La Concepción		Venezuela	-	36.00%	PDVSA	2025
Mata		Venezuela	-	34.49%	PDVSA	2025
Argentine exploration
Parva Negra Este (2)		Neuquén	42.50%	-	PAMPA	2019
Chirete (3)		Salta	50.00%	-	High Luck Group Limited	2019
Río Atuel		Mendoza	33.33%	-	Petrolera El Trebol	2020
Borde del Limay (4)		Neuquén	85.00%	-	PAMPA	2015
Los Vértices (4)		Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte		Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾Participation in mixed companies in Venezuela (see Note 5.3.6.1).

⁽²⁾In the process of requesting appraisal.

⁽³⁾In the process of requesting an exploration concession.

⁽⁴⁾In the process of being transferred to GyP.

5.4.3 New concessions and changes in oil and gas participations

5.4.3.1 Parva Negra Area

The exploration license for Parva Negra Este, an area located in the Province of Neuquén granted under concession to GyP and operated by Pampa since April 2014 for a term of 4 years, expired in the month of April 2018. As the original agreement had stipulated the possibility to extend it for a year, GyP requested such extension in due time and manner.

Upon the expiration of the exploration license’s extension in the month of April 2019, on March 29, 2019 GyP requested that the block should be classified as an evaluation block for a 3-year period.

F-105

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.4.3.2 Las Tacanas Norte area

On January 4, 2019, with the publication in the BO of Executive Order No. 2315/18 passed by the Executive Branch of the Province of Neuquén, this exploratory agreement, effective for a term of 4 years, entered into force. Pampa is the operator of Las Tacanas Norte area with a 90% interest, and GyP is the permit holder with a 10% interest.

The block has a 120 km2 surface and is adjacent to El Mangrullo block, which is currently operated by the Company. The accepted offer consists of a perforation of up to 8 wells with the objective toward Vaca Muerta formation, and other exploratory studies.

5.4.3.3Río Atuel

As a result of the delay in the approval of the drilling project filed on December 19, 2018, Petrolera el Trebol, the area operator, on June 19, 2019 requested, to the applicable authorities, for the suspension of the term of the second exploratory period in progress. On June 7, 2019, the approval of the drilling project was obtained. On June 19, 2019, the suspension of the second exploration period requested was established by the relevant authorities, determining December 7, 2019 as the new expiration date.

Subsequently, upon operator´s request, on November 11, 2019, the Hydrocarbons Department granted a 12-months term extension, effective as from December 18, 2019, for the third exploratory period. In this same administrative decision, the applicable authority accepted the 50% reversal of the area.

5.4.3.4 Chirete

After the discovery of oil in late 2018, on February 22, 2019 the applicable authorities granted a 12-months term extension, effective as from November 18, 2018, for the third exploratory period. Since the field discovered in this block turned out to be commercially exploitable, on April 26, 2019 an application was filed for the granting of a hydrocarbon exploitation concession over the “Los Blancos” block, with a 95-km2 surface, and on April 30, 2019 a three-year extension of the third exploratory period for the permit’s remaining area was requested. which had been extended for 12 months from November 18, 2018. As of the date of issuance of these Consolidated Financial Statements, the above mentioned granting of exploitation concession is in process.

5.4.3.5 Anticlinal Campamento

On December 1, 2010, YPF, owner of the exploitation concession over the block, organized on December 1, 2010, a Joint Venture for the drilling of 9 wells, in which the company has a 15% interest. On August 1, 2019, the concession over the “Anticlinal Campamento” block was transferred from YPF to Oilstone Energía S.A, including the transfer of operations and agreements thus remaining unchanged Pampa´s participation in the Anticlinal Campamento.

5.4.3.6 Sierra Chata

On December 27, 2019, through Decree 129/19, the province of Neuquén has approved the assignment of Total Austral´s participation to Mobil Argentina SA, resulting in a Mobil participation of 54.4477% in the area.

F-106

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

5.5 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2019, 2018 and 2017:

	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year	19	12	16
Increases	30	8	8
Transferred to development	(11)	-	(8)
Loss of the year	(5)	(1)	(1)
At the end of the year	33	19	15
Number of wells at the end of the year	9	7	7

5.6 Operations in Ecuador

As from 2006 the Ecuadorian government implemented far-reaching tax and regulatory reforms in connection with hydrocarbon activities, which involved material changes in the conditions set forth at the time of execution of participation agreements.

5.6.1 Amendatory Agreements and Law amending the Hydrocarbon Law

On October 31, 2008, EcuadorTLC, Teikoku Oil Ecuador and Petroecuador, among others, executed the Amendatory Agreements regulating the operation of Block 18 and Palo Azul while the parties negotiated the migration to a new contract modality.

As a result of the negotiation process mentioned above, the Company decided not to accept the final proposal received from the Ecuadorian government, as this is insufficient to migrate to Service Agreements in Block 18 and Palo Azul Unified Field. Consequently, through Resolution dated November 25, 2010 the Hydrocarbon Secretary notified EcuadorTLC the termination of the Participation Agreements and instructed Petroamazonas EP to undertake the operational transition process; the Ecuadorian government must compensate the terminated parties in an amount equivalent to unamortized investments adjusted by 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 bringing several administrative and judicial proceedings, not having reached an agreement with the Ecuadorian government, EcuadorTLC, Cayman International Exploration Company and Teikoku Oil Ecuador, members of the joint operation, presented, on February 26, 2014 the request for arbitration against Ecuador and EP Petroecuador under the arbitration Rules of the United Nations Commission on International Trade Law.

On January 16, 2018 the Arbitration Court issued the Award, which determined a Settlement Value of U$S 176 million for EcuadorTLC based on its interest in the Block.

F-107

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

As regards the Arbitration, on March 19, 2018, the Republic of Ecuador and the Plaintiff Partners entered into an agreement (the “Agreement”) whereunder the Plaintiff Partners will not seek the collection of the Award in consideration of the award of consequential damages, which for EcuadorTLC consist of: (i) the release from tax and labor claims in dispute in the amount of U$S 132 million, and (ii) the additional collection of U$S 54 million in three installments payable in the months of March, April and May. Additionally, the parties agreed that EcuadorTLC would be the sole beneficiary of the collection of the amount of U$S 9 million corresponding to an obligation undertaken by Petromanabí (a member of the Block 18 Consortium but not a plaintiff). This receivable has not been recognized in view of its contingent nature.

Furthermore, the Republic of Ecuador has declared and recognized in the Agreement: (i) that the Agreement is fully valid and binding on the Republic of Ecuador, (ii) that any payment default by the Republic of Ecuador under the Agreement will enable the Plaintiff Partners to fully enforce the Final Award, and (iii) there are no other obligations pending performance regarding the operation and exploitation of Block 18 by the Plaintiff Partners.

As a result of the Agreement, the Company has disclosed net profits for U$S 40 million as of December 31, 2018, made up of: i) profits of U$S 133 million as consequential damages after writing off the receivable of U$S 53 million to be recovered from the Ecuadorian Government pursuant to the Amending Agreements, and ii) a U$S 93 million loss associated with the agreement to the terms of the tax claims assigned to EcuadorTLC in accordance with the Agreement.

As of May 3, 2018, EcuadorTLC has collected the three installments and has 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, EcuadorTLC was notified of the payment on employee participation profits from 2002 to 2010, to the former consortium workers.

5.6.2 Crude Oil Transportation Agreement with OCP

The Company holds a contract with OCP, whereby it assumed a commitment to an oil transport capacity of 80,000 barrels/day for a term of 15 years counted as from November 10, 2003.

The transport contract is a “Ship or Pay” contract, so the Company must meet its contractual obligations for the total volume agreed upon, regardless of the real volume transported, and has to pay, the same as the other producers, a rate that covers the operating costs and financial services of OCP, among others.

EcuadorTLC had the right to sell the transport capacity in the heavy crude oil pipeline (OCP) to mitigate the negative impact of its non-use. On December 31, 2008, the Company entered into a contract with Petroecuador whereby the Ecuadorian State assumed a commitment to charge, effective January 1, 2009, the available crude owned by it and transported through the heavy crude oil pipeline to the oil transport capacity hired by the Company, up to a maximum volume of 70,000 barrels/day. In addition, the Company sold transport capacity of approximately 8,000 barrels/day of oil for the period from July 2004 to January 2012. As a result of the contract non-compliance by the buyers, the Company is making the pertinent claims to Petroecuador. To such effect, a mediation proceeding has been brought before the Center for Mediation of the Attorney General’s Office of the Government of Ecuador sitting in the City of Quito.

F-108

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 5: (Continuation)

In January 2018, EcuadorTLC assigned to the subsidiary Energía Operaciones ENOPSA S.A. (“ENOPSA”) a transportation capacity of 10,000 barrels/day, and ENOPSA declared the Equity Expropriation Event, whereby, under certain circumstances stipulated in the agreement, the Company, in its capacity as guarantor, will bear the payments for the capital charges associated with the assigned transportation capacity.

The agreement terminated on November 10, 2018 and, therefore collaterals held to ensure compliance with related financial commitments were gradually released as those commitments become extinguished.

5.6.3 Investment in OCP - Ecuador

The Company has a 15.91% equity interest in OCP, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.  See detail in Note 5.3.6.2.

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 raw materials, oil and gas, international petrochemical product’s price, the regulatory framework for the energy industry (mainly expected price recognition and compensation costs methodology), the projected capital investments and the evolution of the energy demand.

F-109

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

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 asset or 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 / Minimum notional 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 recognized figures, such differences will have an effect on income tax and deferred income tax at the year of such determination.

Deferred tax assets are reviewed at each reporting date and reduced in accordance with the probability that the sufficient taxable base will be available to allow 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 those 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. Periodically, the Company reviews the status of each contingency and assesses potential financial liability, applying the criteria indicated in Note 4.22, 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 our 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.

F-110

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

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

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’ 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

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 generation segment the Company mainly considers the ability of CAMMESA to meet its payment obligations to generators, and the resolutions issued by SGE, which allow the Company to collect its credits with CAMMESA through different mechanisms.

Future adjustments to the allowance may be necessary if future 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 recognized 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.

F-111

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

6.1.7 ENRE Penalties and discounts

Edenor considers its applicable accounting policy for the recognition of ENRE penalties and discounts critical because it depends on penalizable events, which are valued on the basis of Edenor’s management best estimate of the expenditure required to settle the present obligation at the date of these Consolidated Financial Statements. The balances of ENRE penalties and discounts are adjusted in accordance with the regulatory framework applicable thereto and have been estimated based on the description made in Note 2.3.

6.1.8 Revenue recognition

In the distribution of energy business segment, revenue is recognized on an accrual basis upon delivery to customers, which includes the estimated amount of unbilled distribution of electricity at the end of each year. We consider our accounting policy for the recognition of estimated revenue critical because it depends on the amount of electricity effectively delivered to customers which is valued on the basis of applicable tariffs. Unbilled revenue is classified as current trade receivables.

In the oil and gas business segment, the fair value of the consideration receivable corresponding to revenues from gas sales to Distributors is recognized based on the volume of gas delivered and the price established by the SE (in accordance with applicable resolutions).

6.1.9 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 exploitation rights, including oil and gas volumes related to those service agreements under which the Company has no ownership rights on the reserves or the hydrocarbons obtained and those estimated to be produced for the contracting company under service contracts. 

There are numerous uncertainties in estimating proved 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 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, including 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 oil and gas segment (see Notes 4.6 to 4.9).

F-112

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

6.1.10 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 (which considers those costs) 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. The provision is recognized on the basis that a future remediation commitment will 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.

6.1.11 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.

F-113

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

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 comprised 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.

Taking into consideration that the Company, (excluding the Distribution segment’s balances), has a net asset position in Argentine pesos, as of December 31, 2019 the Company recorded net foreign exchange losses in the amount of U$S 5 million. The Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values a (decrease)/increase of U$S 11 million in the 2019 fiscal year’s income/(loss), before income tax.

In the Distribution segment, the subsidiary Edenor collects revenues in pesos pursuant to regulated tariffs which are not indexed to the U.S. dollar, whereas a significant portion of its existing financial debt is denominated in U.S. dollar, which exposes Edenor to a risk of loss resulting from a devaluation of the Argentine peso. Edenor can manage this risk through the execution of forward contracts denominated in foreign currency.

F-114

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

As of the year ended December 31, 2019, Edenor has not hedged its exposure to the U.S. dollar. Edenor does not currently hedge its exposure to currency risk. Therefore, any devaluation of the peso could significantly increase its debt service burden, which, in turn, could have a substantial adverse effect on its financial and cash position (including its ability to repay its Corporate Notes) and the results of its operations. During 2019, U.S. dollar currency appreciated by approximately 58.9% against the Argentine peso, from $ 37.70 in December 2018 to $ 59.89 in December 2019 and as of December 31, 2019 Edenor recorded net foreign exchange losses in the amount of U$S 70 million. Edenor estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values an increase/(decrease) of U$S 21 million in the 2019 fiscal year’s income/(loss), 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 on account of the current regulatory, economic, governmental and other policies in force, gas domestic prices are not 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 2019 fiscal year’s income/(loss), 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	12.31.2019	12.31.2018
Shares	2	1
Government securities	11	30
Investment funds	24	11
Variation of the result of the year	37	42

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.

F-115

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

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, 2019, on consolidated basis net of Corporate Bonds’ repurchase, only approximately 4% of the indebtedness was subject to variable interest rates. Most of the Company’s indebtedness subject to variable interest rates is denominated in U.S. dollar, based on Libor rate plus an applicable margin and a small portion is denominated in pesos accruing interest based on the private Badlar 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 chart shows the breakdown of the Company’s borrowings classified by interest rate and the currency in which they are denominated:
 

	12.31.2019	12.31.2018
Fixed interest rate:
Argentinian pesos	143	15
U.S dollar	1,687	1,861
Subtotal loans granted at a fixed interest rate	1,830	1,876
Floating interest rates:
Argentinian pesos	10	108
U.S dollar	64	131
Subtotal loans granted at a floating interest rate	74	239
Non interest accrued
U.S dollar	17	30
Argentinian pesos	26	32
Subtotal no interest accrued	43	62
Total borrowings	1,947	2,177

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 2019 fiscal year's year’s income/(loss), before income tax, of U$S 0.9 million.

F-116

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– 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, 2019, the Company’s trade receivables, excluding Edenor, totaled U$S 299 million, out of which 97% are short-term receivables and the remaining 3% are classified as non-current. With the exception of CAMMESA, which represents approximately 56% 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 risk control area evaluates the customer’s creditworthiness, based on past experiences and other factors.

As of December 31, 2019, Edenor’s trade receivables totaled U$S 204 million. No single customer accounted for more than 10% of sales. The collectibility of trade receivables balances related to the Framework Agreement, which amount to U$S 0.2 million, is subject to such agreement’s being in force and the compliance with it terms.

Edenor’s allowance for impairment of receivables is assessed based on the delinquent balance, which comprises all such debt arising from the bills for electricity consumption of small-demand (T1), medium-demand (T2), and large-demand (T3) customers that remain unpaid 7 working days after their first due dates. Edenor’s Management records an allowance applying to the delinquent balances of each customer category an uncollectibility rate that is determined according to each customer category based on the historical comparison of collections made. Additionally, the amounts related to the Framework Agreement are not considered within delinquent balances.

Additionally, and faced with temporary and/or exceptional situations, Edenor’s Management may redefine the amount of the allowance, specifying and supporting the criteria used in all the cases.

F-117

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

One of the significant items of Edenor’s delinquent balances is that related to the receivable amounts with Municipalities, in respect of which Edenor either applies different offsetting mechanisms against municipal taxes it collects on behalf of the municipalities, or implements debt refinancing plans, with the aim of reducing them.

The inability to collect the accounts receivable in the future could have an adverse effect on Edenor’s results of operations and its financial position, which, in turn, could have an adverse effect on Edenor’s ability to repay loans, including payment of the Corporate Notes.

The Company applies the simplified approach of IFRS 9 to measure the expected credit losses 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, 2019 and 2018 amounts to U$S 24 million and U$S 41 million, respectively (Note 12.3) and was determined based on credit loss rates calculated for days past due detailed below:

12.31.2019	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.10%	0.35%	1.99%	2.95%	4.03%	5.59%	9.79%	16.13%
Oil and Gas	0.53%	1.49%	9.45%	18.03%	18.50%	18.81%	18.90%	18.92%
Distribution of energy	3.00%	3.00%	8.00%	18.00%	20.00%	45.00%	72.00%	72.00%
Petrochemicals	0.39%	0.73%	6.88%	16.66%	25.32%	29.59%	30.97%	43.05%
Holding	1.85%	2.81%	6.84%	17.15%	26.77%	43.21%	49.89%	65.29%
12.31.2018	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.04%	0.09%	2.62%	3.39%	9.37%	13.56%	19.82%	28.88%
Oil and Gas	2.20%	4.42%	11%	20.42%	42.85%	47.32%	49.20%	56.32%
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Petrochemicals	0.03%	0.08%	1.41%	4.98%	11.52%	20.36%	24.91%	25.24%
Holding	0.96%	1.25%	2.03%	2.85%	19.86%	26.41%	32.95%	32.97%

In 2017 fiscal year, the calculation of the loss allowance for trade receivables and other receivables was assessed based on the incurred loss model, and considered the existence of objective evidence of default for the recognition of losses in the statement of comprehensive income. The expected credit loss as of January 1, 2018 (IFRS 9 amended adoption date) was determined based on credit loss rates calculated for days past due detailed below:

Rates	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+180 days
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Rest of business segments	0.32%	0.93%	8.11%	19.61%	35.69%	45.63%	59.00%	63.01%

F-118

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

The loss allowance for financial assets and other receivables adjustment as of January 1, 2018 for the application of the expected credit losses methodology to the loss allowance as of December 31, 2017, is detailed as follows:

	Financial assets	Other receivables
Loss allowance under IAS 39 as of 12.31.2017	22	7
Adjustment to the opening balance of retained earnings	4	(1)
Loss allowance calculated under IFRS 9 as of 01.01.2018	26	6

The detailed adjustments to the opening balance in equity as a result of the application of IFRS 9, are disclosed net of tax effect for a total amount of U$S 2 million, with counterpart in retained earnings of U$S 1 million and in non-controlling interest of U$S 1 million.

Finally, although cash, cash equivalents and financial assets are also subject to the impairment requirements of IFRS 9, the identified impairment loss is immaterial.

Loss allowance evolution as of December 31, 2019, 2018 and 2017, 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 U$S 1.5 million (decrease)/increase in 2019 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 for 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 local and international, capital market as well as 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 provide a sufficient margin as determined in the previously mentioned 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.

F-119

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

It is worth to highlight that restrictions, both current and future new restrictions that could be imposed, affecting the access to the single and free‑floating foreign exchange markets ingle market and free of change by companies could affect the Company's ability to pay debt’s capital and interest and additional transfers of funds abroad (including payments related to Corporate Bonds) or could otherwise affect the Company’s business and results of operations.

The determination of the Company’s liquidity index for fiscal years ended December 31, 2019 and 2018 is detailed below:

	12.31.2019	12.31.2018
Current assets	1,362	1,521
Current liabilities	854	1,182
Index	1.59	1.29

The following table includes an analysis of the Company 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, 2019	Trade and other payables (1)	Borrowings	Total
Less than three months	-	95	95
Three months to one year	454	188	642
One to two years	11	288	299
Two to five years	70	834	904
More than five years	9	1,233	1,242
Total	544	2,638	3,182
As of December 31, 2018	Trade and other payables	Borrowings	Total
Less than three months	331	112	443
Three months to one year	534	318	852
One to two years	9	242	251
Two to five years	3	892	895
More than five years	-	977	977
Total	877	2,541	3,418

(1) Includes Lease Liabilities (see Note 18.1.2)

F-120

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 6: (Continuation)

6.3 Capital risk management

The aims of managing capital are 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, 2019 and 2018 were as follows:

	12.31.2019	12.31.2018
Total borrowings	1,947	2,177
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(590)	(646)
Net debt	1,357	1,531
Total capital attributable to owners	3,274	2,897
Leverage ratio	41.45%	52.85%

6.4 Regulatory risk factors

Pursuant to caption C of Section 37 of the Edenor’s Concession Agreement, the Grantor of the Concession may, without prejudice to other rights to which he is entitled thereunder, foreclose on the collateral granted by Edenor when the cumulative value of the penalties imposed to Edenor in the previous one-year period exceeds 20% of its annual billing, net of taxes and rates.

Edenor’s Management evaluates the development of this indicator on an annual basis. As of the date of issuance of these Consolidated Financial Statements, there are no events of non-compliance by Edenor that could lead to that situation.

F-121

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

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, we were able to identify the following business segments:

Electricity Generation, consisting of the Company’s direct and indirect interests in CPB, HINISA, HIDISA, Greenwind, Enecor, TMB, TJSM, CTB and through its own electricity generation activities through thermal plants Güemes, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picún Leufú hydroelectric complex and Pampa Energía I and II wind farms.

Electricity Distribution, consisting of the Company’s direct interest in Edenor.

Oil and Gas, consisting of the Company’s own interests in oil and gas areas and through its direct interest in PACOSA and Oldelval and indirectly interest in OCP. As of December 31, 2018 and 2017, the Company has classified the results corresponding to the divestment mentioned in Note 5.2.1 as discontinued operations.

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in Argentine plants.

Holding and Other Business, principally consisting of financial investment transactions, holding activities, and 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. As of December 31, 2018 and 2017, includes the results corresponding to the divestment mentioned in Note 5.2.2 as discontinued operations.

The Company manages its operating segment based on its individual net results.

F-122

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	819	1,502	174	321	20	-	2,836
Intersegment revenue	-	-	270	-	-	(270)	-
Cost of sales	(466)	(1,225)	(313)	(298)	-	270	(2,032)
Gross profit	353	277	131	23	20	-	804
Selling expenses	(3)	(122)	(12)	(9)	(2)	-	(148)
Administrative expenses	(36)	(65)	(47)	(4)	(22)	-	(174)
Exploration expenses	-	-	(9)	-	-	-	(9)
Other operating income	9	10	8	4	9	-	40
Other operating expenses	(11)	(43)	(11)	(9)	(12)	-	(86)
Impairment of property, plant and equipment	(52)	-	(10)	-	-	-	(62)
Share of profit from associates and joint ventures	13	-	21	-	67	-	101
Agreement on the regularization of obligations	-	285	-	-	-	-	285
Operating income	273	342	71	5	60	-	751
Gain on net monetary position, net	-	187	-	-	-	-	187
Finance income	51	20	18	1	7	(1)	96
Finance costs	(82)	(112)	(94)	(8)	(4)	1	(299)
Other financial results	86	(62)	84	18	(13)	-	113
Financial results, net	55	33	8	11	(10)	-	97
Profit before income tax	328	375	79	16	50	-	848
Income tax	(80)	(178)	(16)	(5)	231	-	(48)
Profit for the year	248	197	63	11	281	-	800
Depreciation and amortization	71	79	112	1	-	-	263

F-123

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit attributable to:
Owners of the company	239	98	63	11	281	-	692
Non - controlling interest	9	99	-	-	-	-	108
Consolidated statement of financial position as of December 31, 2019
Assets	1,472	1,480	1,261	136	1,527	(192)	5,684
Liabilities	1,226	1,792	465	122	(160)	(170)	3,275
Additional consolidated information as of December 31, 2019
Increases in property, plant and equipment, intangibles assets and right-of-use assets	240	173	191	4	3	-	611
Net book values of property, plant and equipment	1,152	1,691	612	18	34	-	3,507

F-124

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	604	1,484	458	338	36	-	2,920
Intersegment revenue	2	-	63	-	-	(65)	-
Cost of sales	(273)	(1,136)	(287)	(334)	-	63	(1,967)
Gross profit  (loss)	333	348	234	4	36	(2)	953
Selling expenses	(1)	(134)	(19)	(13)	(4)	-	(171)
Administrative expenses	(41)	(76)	(56)	(6)	(27)	-	(206)
Exploration expenses	-	-	(1)	-	-	-	(1)
Other operating income	11	9	141	5	15	-	181
Other operating expenses	(17)	(44)	(114)	(20)	(6)	1	(200)
Impairment of property, plant and equipment	-	-	-	(32)	-	-	(32)
Share of profit (loss) from joint ventures and associates	(11)	-	37	-	92	-	118
Income from the sale of associates	-	-	28	-	-	-	28
Operating income (loss)	274	103	250	(62)	106	(1)	670
Gain on net monetary position	233	226	107	49	12	2	629
Finance income	52	18	15	1	14	(1)	99
Finance costs	(85)	(132)	(79)	(15)	(6)	1	(316)
Other financial results	(365)	(50)	(512)	(39)	108	-	(858)
Financial results, net	(165)	62	(469)	(4)	128	2	(446)
Profit (loss) before income tax	109	165	(219)	(66)	234	1	224
Income tax	(3)	(49)	57	12	(34)	-	(17)
Profit (loss) for the year from continuing operations	106	116	(162)	(54)	200	1	207
Profit for the year from discontinued operations	-	-	49	-	31	-	80
Profit (loss) for the year	106	116	(113)	(54)	231	1	287
Depreciation and amortization	66	69	92	6	1	-	234

F-125

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the company	100	61	(115)	(54)	231	1	224
Non - controlling interest	6	55	2	-	-	-	63
Consolidated statement of financial position as of December 31,2018
Assets	1,414	2,133	1,237	153	872	(137)	5,672
Liabilities	1,054	1,241	1,273	198	247	(136)	3,877
Additional consolidated information as of December 31, 2018
Increases in property, plant and equipment	235	227	192	4	7	-	665
Net book values of property, plant and equipment	1,036	1,657	554	15	54	-	3,316

F-126

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	351	1,050	443	314	17	-	2,175
Intersegment revenue	2	-	19	-	-	(21)	-
Cost of sales	(195)	(799)	(310)	(290)	(1)	21	(1,574)
Gross profit	158	251	152	24	16	-	601
Selling expenses	(4)	(95)	(17)	(12)	-	1	(127)
Administrative expenses	(32)	(66)	(54)	(16)	(30)	-	(198)
Exploration expenses	-	-	(2)	-	-	-	(2)
Other operating income	19	4	110	3	13	-	149
Other operating expenses	(9)	(33)	(38)	(10)	(13)	-	(103)
Share of profit (loss) from joint ventures and associates	(2)	-	1	-	49	-	48
Operating income (loss)	130	61	152	(11)	35	1	368
Gain (loss) on net monetary position	17	145	(18)	2	158	-	304
Finance income	39	12	6	-	7	(2)	62
Finance costs	(69)	(69)	(78)	(10)	(8)	2	(232)
Other financial results	(34)	1	(93)	(6)	32	-	(100)
Financial results, net	(47)	89	(183)	(14)	189	-	34
Profit (loss) before income tax	83	150	(31)	(25)	224	1	402
Income tax	(4)	(12)	24	19	(1)	-	26
Profit (loss) for the year from continuing operations	79	138	(7)	(6)	223	1	428
(Loss) profit for the year from discontinued operations	-	-	(35)	-	(16)	1	(50)
Profit (loss) for the year	79	138	(42)	(6)	207	2	378
Depreciation and amortization	54	58	87	4	2	-	205

F-127

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 7: (Continuation)

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the Company	75	73	(62)	(6)	207	2	289
Non - controlling interest	4	65	20	-	-	-	89
Consolidated statement of financial position as of December 31,2017
Assets	1,115	1,972	1,154	141	1,475	(200)	5,657
Liabilities	333	1,166	444	94	1,850	(200)	3,687
Additional consolidated information as of December 31, 2017
Increases in property, plant and equipment	275	225	140	5	12	-	657

Accounting criteria used by the subsidiaries to measure results, assets and liabilities of the segments is consistent with that used in the Consolidated Financial Statements. Transactions between different segments are conducted under market conditions. Assets and liabilities are allocated based on the segment’s activity.

F-128

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 8: REVENUE

	12.31.2019	12.31.2018	12.31.2017
Energy sales to the Spot Market	251	274	231
Energy sales by supply contracts	285	278	114
Fuel self-supply	281	51	4
Other sales	2	1	2
Generation sales subtotal	819	604	351
Energy sales	1,496	1,477	1,042
Right of use of poles	5	5	6
Connection and reconnection charges	1	2	2
Distribution of energy sales subtotal	1,502	1,484	1,050
Oil, gas and liquid sales	171	454	418
Other sales	3	4	25
Oil and gas sales subtotal	174	458	443
Technical assistance services  and administartion sales	20	36	17
Holding and others subtotal	20	36	17
Petrochemicals sales	321	338	314
Petrochemicals sales subtotal	321	338	314
Total revenue	2,836	2,920	2,175

Revenue is recognized:

1)	At a point in time, that is the effective delivery of the energy, the product or the provision of connection or reconnection services for a total amount of U$S 2,464 million, U$S 2,542 million and U$S 1,976 million as of December 31, 2019, 2018 and 2017, respectively;
2)	Over time in case of power availability, technical assistance services and right to use poles for a total of U$S 372 million, U$S 378 million and U$S 199 million as of December 31, 2019, 2018 and 2017, respectively.

F-129

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 9: COST OF SALES

	12.31.2019	12.31.2018	12.31.2017
Inventories at the beginning of the year	137	113	164
Plus: Charges for the year
Purchases of inventories, energy and gas	1,305	1,224	874
Salaries and social security charges	163	181	202
Benefits to employees	9	6	7
Accrual of defined benefit plans	7	4	7
Works contracts, fees and compensation for services	103	98	84
Depreciation of property, plant and equipment	232	206	195
Intangible assets amortization	7	7	1
Right-of-use assets amortization	2	-	-
Transport of energy	4	4	3
Transportation and freights	18	14	3
Consumption of materials	48	64	29
Penalties	25	56	11
Maintenance	27	24	18
Canons and royalties	59	74	56
Environmental control	3	5	3
Rental and insurance	21	13	11
Surveillance and security	6	6	6
Taxes, rates and contributions	4	5	3
Other	5	-	10
Subtotal	2,048	1,991	1,523
Gain on monetary position	1	-	-
Less: Inventories at the end of the year	(153)	(137)	(113)
Total cost of sales	2,032	1,967	1,574

F-130

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 10: OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	22	26	27
Benefits to employees	1	-	-
Accrual of defined benefit plans	1	-	1
Fees and compensation for services	29	30	26
Compensation agreements	(1)	2	6
Depreciation of property, plant and equipment	9	9	3
Right-of-use assets amortization	1	-	-
Taxes, rates and contributions	25	33	28
Communications	6	7	8
Penalties	22	28	12
Net impairment losses on financial assets	21	28	11
Transport	9	6	4
Other	3	2	1
Total selling expenses	148	171	127

10.2 Administrative expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	62	81	77
Benefits to employees	8	5	5
Accrual of defined benefit plans	8	1	6
Fees and compensation for services	52	68	53
Compensation agreements	-	3	20
Directors' and Syndicates' fees	7	5	4
Depreciation of property, plant and equipment	14	12	6
Consumption of materials	3	4	3
Maintenance	2	2	2
Transport and per diem	2	2	2
Rental and insurance	5	6	6
Surveillance and security	2	5	4
Taxes, rates and contributions	2	8	4
Communications	2	2	2
Right-of-use assets amortization	2	-	-
Institutional advertising and promotion	-	1	2
Other	3	1	2
Total administrative expenses	174	206	198

10.3 Exploration expenses

	12.31.2019	12.31.2018	12.31.2017
Geological and geophysical expenses	4	-	1
Decrease in unproductive wells	5	1	1
Total exploration expenses	9	1	2

F-131

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 10: (Continuation)

10.4 Other operating income and expenses

Other operating income	Note	12.31.2019	12.31.2018	12.31.2017
Compensation for transaction agreement in Ecuador (1)		-	99	-
Recovery of doubtful accounts		-	-	4
Insurrance recovery		6	-	-
Natural Gas Surplus Injection Promotion Program	4.24.1.1	-	23	101
Commissions on municipal tax collections		2	2	1
Services to third parties		13	13	8
Profit for property, plant and equipment sale		-	3	-
Dividends received		1	1	1
Reversal of contingencies and taxes payables (2)		1	4	24
Other		17	36	10
Total other operating income		40	181	149
Other operating expenses
Provision for contingencies		(28)	(35)	(20)
Decrease in property, plant and equipment		(1)	(6)	(1)
Allowance for tax credits		(4)	-	(1)
Tax on bank transactions		(29)	(30)	(27)
Cost for services provided to third parties		(2)	(2)	(2)
Compensation agreements		-	-	(2)
Donations and contributions		(2)	(2)	(2)
Institutional promotion		(2)	(3)	(3)
Extraordinary canon		-	(3)	(14)
Contingent consideration		-	-	(8)
Onerous contract (Ship or Pay)		-	(7)	(4)
Tax contingencies in Ecuador (1)		-	(69)	-
Other		(18)	(43)	(19)
Total other operating expenses		(86)	(200)	(103)

(1)	Pursuant to Agreement executed on March 19, 2018 between the Republic of Ecuador and the Plaintiff Partners, including EcuadorTLC (see Note 5.6.1). Figures recorded as of December 31, 2018 arises from the Consolidated Financial Statements denominated in pesos in accordance with IAS 29, and was translated into U.S. dollars using the exchange rate as of that date.
(2)	In 2017, includes gains on releasing tax fines and reducing compensatory interests, related to benefits for the adhesion to the regularization regime (moratorium) (see Note 2.6.4).

F-132

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 10: (Continuation)

10.5. Financial results

	12.31.2019	12.31.2018	12.31.2017
Gain on monetary position, net	187	629	304
Finance income
Commercial interest	61	58	43
Financial interest	22	34	14
Other interest	13	7	5
Total finance income	96	99	62
Finance cost
Commercial interest	(52)	(78)	(45)
Fiscal interest	(6)	(8)	(11)
Financial interest (1)	(227)	(210)	(162)
Other interest	(10)	(15)	(10)
Other financial expenses	(4)	(5)	(4)
Total financial expenses	(299)	(316)	(232)
Other financial results
Foreign currency exchange difference, net	(75)	(863)	(156)
Changes in the fair value of financial instruments	91	64	62
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results of RDSA	2	13	-
Results for the repurchase of corporate bonds	27	2	-
Other financial results	14	-	-
Total other financial results	113	(858)	(100)
Total financial results, net	97	(446)	34

 ⁽¹⁾ Net of U$S 16.8 million, U$S 7.5 million and U$S 16 million capitalized in property, plant and equipment for the years ended December 31, 2019, 2018 and 2017, respectively.

10.6 Income tax and minimum notional income tax

The breakdown of income tax charge is:

	12.31.2019	12.31.2018	12.31.2017
Current tax	70	39	55
Deferred tax	(57)	(19)	(72)
Other comprehensive income	-	1	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	1	(4)	(12)
Direct charges for income tax	-	-	3
Optional tax revaluation	34	-	-
Total loss (gain) income tax	48	17	(26)

F-133

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 10: (Continuation)

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2019	12.31.2018	12.31.2017
Profit before income tax	848	224	402
Current tax rate	30%	30%	35%
Result at the tax rate	254	67	141
Share of profit of associates and joint ventures	(25)	(3)	(117)
Non-taxable results	(38)	7	(59)
Effects of exchange differences and traslation effect of property, plant and equipment and intangible assets, net	93	-	-
Adjustment of valuation of property, plant and equipment and intangible assets	(202)	-	-
Gain (loss) on monetary position, net	17	(38)	66
Effect of tax rate change in deferred tax	37	(26)	(21)
Adjustment effect for tax inflation	129	-	-
Payment of optional tax revaluation	34	-	-
Special tax, revaluation of property, plant and equipment	(169)	-	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	(86)	4	(20)
Deferred tax not previously recognized	-	4	(31)
Non-deductible cost	-	-	9
Non-deductible provisions	-	-	5
Other	4	2	1
Total  loss (gain) income tax	48	17	(26)

As of December 31, 2019 and 2018 consolidated accumulated tax losses amount to U$S 444 million and U$S 176 million, respectively, which may be offset, pursuant to the applicable tax laws, with tax profits corresponding to future fiscal years, at the tax rate that is estimated to apply, based on the following breakdown:

Fiscal year generation	Fiscal year prescription	12.31.2019	12.31.2018
2015	2020	-	3
2016	2021	4	18
2017	2022	3	4
2018	2023	38	27
2019	2024	66	-
Recognized Tax loss-carryforwards		111	52

F-134

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– 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	Impairment	Transfers (1)	Decreases	Traslation effect	At the end
Land	22	-	-	-	(8)	-	14
Buildings	207	1	(8)	4	(1)	(1)	202
Equipment and machinery	1,051	1	(90)	297	(5)	-	1,254
High, medium and low voltage lines	1,010	3	-	72	(4)	(32)	1,049
Substations	365	-	-	14	-	(12)	367
Transforming chamber and platforms	208	4	-	15	(1)	(7)	219
Meters	209	1	-	23	-	(7)	226
Wells	562	24	-	94	(8)	-	672
Mining property	267	-	(14)	-	-	-	253
Vehicles	22	1	-	-	-	(1)	22
Furniture and fixtures and software equipment	67	4	-	4	-	(1)	74
Communication equipments	15	-	-	-	-	-	15
Materials and spare parts	32	19	-	(14)	-	-	37
Distribution storage center	10	-	-	-	(10)	-	-
Petrochemical industrial complex	15	-	-	(1)	-	-	14
Work in progress	783	510	-	(487)	(3)	(11)	792
Advances to suppliers	19	23	-	(23)	-	(1)	18
Other goods	4	-	-	2	-	-	6
Total at 12.31.2019	4,868	591	(112)	-	(40)	(73)	5,234
Total at 12.31.2018	4,317	665	(56)	-	(58)	-	4,868

⁽¹⁾Includes the transfer of materials and spare parts to the item "Inventories" of the current asset.

F-135

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

	Depreciation
							Net book values
Type of good	At the beginning	Decreases	Impairment	For the year	Traslation effect	At the end	At the end	At 12.31.2018
Land	-	-	-	-	-	-	14	22
Buildings	(74)	1	5	(7)	-	(75)	127	133
Equipment and machinery	(384)	4	41	(72)	-	(411)	843	667
High, medium and low voltage lines	(323)	4	-	(35)	10	(344)	705	687
Substations	(105)	-	-	(13)	3	(115)	252	260
Transforming chamber and platforms	(57)	-	-	(8)	2	(63)	156	151
Meters	(80)	-	-	(10)	3	(87)	139	129
Wells	(321)	-	-	(65)	-	(386)	286	241
Mining property	(119)	-	4	(29)	-	(144)	109	148
Vehicles	(16)	-	-	(5)	-	(21)	1	6
Furniture and fixtures and software equipment	(48)	-	-	(9)	-	(57)	17	19
Communication equipments	(10)	-	-	-	-	(10)	5	5
Materials and spare parts	(2)	-	-	(1)	-	(3)	34	30
Distribution storage center	(2)	3	-	-	-	1	1	8
Petrochemical industrial complex	(7)	-	-	(1)	-	(8)	6	8
Work in progress	-	-	-	-	-	-	792	783
Advances to suppliers	-	-	-	-	-	-	18	19
Other goods	(4)	-	-	-	-	(4)	2	-
Total at 12.31.2019	(1,552)	12	50	(255)	18	(1,727)	3,507
Total at 12.31.2018	(1,358)	9	24	(227)	-	(1,552)		3,316

F-136

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U$S – unless otherwise stated)

NOTE 11: (Continuation)

Edenor’s direct own costs capitalized in the book value of property, plant and equipment during the year ended December 31, 2019 and 2018 amounted to U$S 18.8 million and U$S 27.1 million respectively.

Borrowing costs capitalized in the book value of property, plant and equipment during the year ended December 31, 2019 and 2018 amounted to U$S 17 million and U$S 8 million, respectively (see Note 12.5).

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 Generation segment, a reduction in prices in the spot market was verified in 2019, which was deepened by the drop in the product’s excess demand resulting from the slowdown in the economic activity that impacted on the decrease in Energía Plus contracts (with higher prices) and, consequently, on the segment’s profitability margins.

On the other hand, in the Distribution of Energy segment, Edenor has been affected by the enactment by the PEN of the new measures, mentioned in Notes 1.2 and 2.3.2.

Furthermore, in the Oil & Gas segment, an oversupply in the natural gas market against the domestic demand was verified in 2019 as a consequence of higher production in unconventional blocks, which affected the production of gas thus generating a decrease in natural gas sale price in the domestic market.

Additionally, in the Petrochemicals segment, a drop in margins was recorded in 2018 as a result of the sustained increase in operating costs, which has had a significant impact on the cost of the raw material processed in the Catalytic Reformer unit, as well as a decline in benchmark international prices. This in turn led to the recognition of an impairment loss in 2018. During 2019, the Company did not identify indications of reversal or decrease of the impairment loss recognized in 2018.

Therefore, in view of the above-mentioned indications of impairment, the Company has determined the recoverable amount of the CGUs making up the Generation, Distribution of Energy and Oil & Gas segments as of December 31, 2019 and, for the Petrochemicals segment, as of December 31, 2018.

The methodology used in the estimation of the recoverable amount consisted on 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.

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) nature, timing, and modality of the electricity rate increases and/or recognition of cost adjustments in Edenor; (iii) demand projections per type of product; (iv) costs evolution; (v) investment needs appropriate to the service quality levels required by the Edenor´s regulatory authority, and; (vi) macroeconomic variables such as inflation and exchange rates, etc.

F-137

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.1.1.1 Generation segment

As of December 31, 2019, the recoverability assessment of the Güemes, Piquirenda and Piedra Buena power plants, in the Generation segment, resulted in the recognition of impairment losses in the amount of U$S 52 million.

The key assumptions used in the calculation of the recoverable amount as of December 31, 2019 consider: i) a reduction in the spot market prices consistently with Resolution SE No. 31/20, detailed in Note 23, and ii) a 11.0% WACC discount rate before tax.

As regards projections, it is worth highlighting that the Management has considered: i) that the Energía Plus contracted volume remains allocated to Genelba to maximize efficiency in cost structure, and ii) the entry into effect of co-generation and closing to combined cycle projects under SEE Resolution No. 287/17 and the resulting dispatch reduction for less efficient power plants such as Güemes and Piedra Buena.

The Company has conducted a sensitivity analysis of the segment’s recoverable amount regarding: i) the discount rate: a 1% increase or decrease in the discount rate would involve U$S 8 million impairment losses decrease or increase, respectively, and ii) the price of energy in the spot market: a 2% increase or decrease in the spot market price would involve a would involve U$S 8 million impairment losses increase or decrease, respectively.

11.1.1.2 Distribution of Energy segment

The future increase in electricity rates used by Edenor to assess the recoverability of its non-financial long-lived assets on balances as of December 31, 2019 is based on the contractual rights held by Edenor deriving from the concession agreement. Furthermore, the new announcements made by government officials and the adopted measures described in Notes 1 and 2 to these Consolidated Financial Statements have been taken into account.

Edenor has made its projections under the assumption that it will obtain better electricity rates in the next few years. However, given the complexity of the country’s macroeconomic scenario, Edenor’s Management is not in a position to ensure that the future performance of the assumptions used in making its projections will be in line with what it has estimated at the date of preparation of these Consolidated Financial Statements.

F-138

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

In order to consider the estimation risk included in the projections of the aforementioned variables, Edenor has taken into consideration three alternative probability-weighted scenarios, which are detailed below:

i.	Pessimistic scenario: Edenor forecasts that 80% of the CPD increases fixed by the RTI will be transferred to tariffs as from January 2022. Furthermore, as from the aforementioned date, 80% of the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 18 monthly installments. From February 2021, 80% of the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 20%.
ii.	Intermediate scenario: Edenor forecasts that the CPD increases fixed by the RTI will be transferred to tariffs as from January 2021. Furthermore, as from the aforementioned date, the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 18 monthly installments. From February 2021, the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 60%.
iii.	Optimistic scenario: Edenor forecasts that the CPD increases fixed by the RTI will be transferred to tariffs as from January 2020. As from January 2021, the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 12 monthly installments. From February 2021, the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 20%.

Edenor has assigned to these three scenarios the previously described probability of occurrence percentages based mainly on experience and giving consideration to the current economic and financial situation.

The discount rate before tax (WACC) in pesos used by Edenor in all the scenarios varies for each year of the projection. For the first 5 years, the average of these rates is 41%.

The main factors that could result in impairment charges in future periods are: i) a distortion in the nature, timing, and modality of the electricity rate increases and recognition of cost adjustments, ii) the development of the costs to be incurred, and iii) the investment needs appropriate to the service quality levels required by the regulatory authority in the RTI, among other factors. These factors have been taken into account in the aforementioned weight of scenarios. Due to the uncertainty inherent in these assumptions, Edenor estimates that any sensitivity analysis that considers changes in any of them taken individually could lead to distorting conclusions.

11.1.1.3 Oil & Gas segment

As of December 31, 2019, the assessment of assets recoverability in the Oil & Gas segment, specifically in the Sierra Chata area, resulted in the recognition of impairment losses in the amount of U$S 10 million.

The key assumptions used in the calculation of the recoverable amount as of December 31, 2019 consider i) a 2020 price of natural gas similar to the 2019 price, and a 20-25% gas price increase for 2021, price that is maintained in subsequent years considering a moderate development of unconventional resources (Vaca Muerta) tending to achieve gas domestic demand supply and a decrease in gas imports, and ii) a 14.1% WACC discount rate before tax. It is worth highlighting that the gas price is maintained in the projections, which in turn affects the estimated investment profile.

F-139

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

The Company has conducted a sensitivity analysis of the segment’s recoverable amount regarding: i) the discount rate: a 1% increase or decrease in the discount rate would involve U$S 2 million impairment losses decrease or increase, respectively, and ii) the gas price: a 2% increase or decrease in the gas price would involve U$S 2 million impairment losses increase or decrease, respectively.

Finally, it is important to highlight that as of December 31, 2019, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value.

11.1.1.4 Petrochemicals segment

As of December 31, 2018, the assessment of recoverability of the Petrochemicals segment’s assets resulted in the recognition of impairment losses for U$S 32 million.

Key assumptions used in the calculation of the recoverable value as of December 31, 2018 are as follows:

-	Gross margin	7%
-	Discount rate before tax (WACC)	12.8%
-	International Average Styrene Price	1,138 U$S/tn
-	Average gasoline 87 octane price	2.06 U$S/gallon

As regards these assumptions, the Company’s management has determined the estimated gross margin based on past yields and its market growth expectations (including projections of demand, prices and costs); the discount rate used reflects specific risks associated with the Petrochemicals segment.

F-140

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.2 Intangible assets

Original values
Type of good	At the beginning	Traslate Effect	At the end
Concession agreements	272	(2)	270
Goodwill	35	-	35
Intangibles identified in acquisitions of companies	7	-	7
Total at 12.31.2019	314	(2)	312
Total at 12.31.2018	314	-	314
	Depreciation
Type of good	At the beginning	For the year	At the end
Concession agreements	(151)	(8)	(159)
Intangibles identified in acquisitions of companies	(2)	-	(2)
Total at 12.31.2019	(153)	(8)	(161)
Total at 12.31.2018	(146)	(7)	(153)
	Net book values
Type of good	At the end	At 12.31.2018
Concession agreements	111	121
Goodwill	35	35
Intangibles identified in acquisitions of companies	5	5
Total at 12.31.2019	151
Total at 12.31.2018		161

F-141

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.3 Deferred tax assets and liabilities, income tax and minimum notional income tax

The composition of the deferred tax assets and liabilities is as follows:

	12.31.2018	Profit (loss)	Gain on monetary position, net	12.31.2019
Tax loss carryforwards	52	59	-	111
Trade and other receivables	14	(1)	-	13
Trade and other payables	52	(37)	(2)	13
Salaries and social security payable	1	1	-	2
Defined benefit plans	9	(2)	-	7
Provisions	32	7	-	39
Taxes payable	6	(6)	-	-
Adjustment for tax inflation	-	8	-	8
Other	2	(2)	-	-
Deferred tax asset	168	27	(2)	193
Property, plant and equipment	(334)	(55)	5	(384)
Adjustment for tax inflation	-	(99)	-	(99)
Investments in companies	(19)	11	-	(8)
Intangible assets	(193)	175	5	(13)
Inventory	-	(10)	-	(10)
Trade and other receivables	(9)	5	-	(4)
Financial assets at fair value through profit and loss	(9)	(2)	-	(11)
Cash and cash equivalents	-	-	-	-
Borrowings	(3)	3	-	-
Taxes payable	-	(4)	-	(4)
Other	(6)	6	-	-
Deferred tax liabilities	(573)	30	10	(533)

F-142

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2017	Profit (loss)	Other comprehensive income (loss)	12.31.2018
Tax los-carryforwards	64	(12)	-	52
Trade and other receivables	4	10	-	14
Derivative financial instruments	-	-	-	-
Financial assets at fair value through profit and loss	-	-	-	-
Trade and other payables	46	6	-	52
Salaries and social security payable	-	1	-	1
Defined benefit plans	11	(3)	1	9
Provisions	29	3	-	32
Taxes payable	7	(1)	-	6
Liabilities associated to assets classified as held for sale	14	(14)	-	-
Other	2	-	-	2
Deferred tax asset	177	(10)	1	168
Property, plant and equipment	(443)	108	-	(335)
Investments in companies	(52)	35	(2)	(19)
Intangible assets	(2)	(190)	-	(192)
Trade and other receivables	(27)	17	-	(10)
Financial assets at fair value through profit and loss	(3)	(6)	-	(9)
Borrowings	(5)	2	-	(3)
Assets classified as held for sale	(33)	33	-	-
Other	(4)	(1)	-	(5)
Deferred tax liabilities	(569)	(2)	(2)	(573)

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 amounts, determined after their adequate offset, are disclosed in the statement of financial position:

	12.31.2019	12.31.2018
Deferred tax asset	28	2
Deferred tax liabilities	(368)	(407)
Deferred tax liabilities, net	(340)	(405)

F-143

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.4 Inventories

	12.31.2019	12.31.2018
Materials and spare parts	95	94
Advances to suppliers	21	2
In process and finished products	37	40
Stock crude oil	-	1
Total	153	137

11.5 Provisions

	12.31.2019	12.31.2018
Non-Current
Provisions for contingencies	123	125
Asset retirement obligation and dismantling of wind turbines	20	20
Environmental remediation	1	1
Other provisions	1	-
	145	146
Current
Provisions for contingencies	16	17
Asset retirement obligation and dismantling of wind turbines	2	2
Environmental remediation	2	4
Other provisions	-	-
	20	23

F-144

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2019
	For contingencies	Asset retirement obligation and dismantling of wind turbines	For environmental remediation
At the beginning of the year	142	22	5
Increases	41	3	-
Decreases	(10)	-	(2)
Exchange differences on translation	(4)	-	-
Gain on monetary position, net	(17)	-	-
Reversal of unused amounts	(13)	(3)	-
At the end of the year	139	22	3
	12.31.2018
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	141	42	6
Increases	106	37	6
Reclasification	-	(18)	-
Gain on monetary position, net	(52)	(18)	(2)
Decreases	(23)	(5)	(5)
Reversal of unused amounts	(30)	(16)	-
At the end of the year	142	22	5
	12.31.2017
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	199	91	17
Increases	43	29	4
Reclasification	(9)	(1)	1
Reclasification to liabilities associated to assets classified as held for sale	-	(34)	(7)
Gain on monetary position, net	(37)	(18)	(3)
Decreases	(39)	(7)	(6)
Reversal of unused amounts	(16)	(18)	-
At the end of the year	141	42	6

F-145

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.5.1Provision 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.

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.

11.5.2Asset retirement obligations

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.

11.5.3Provision for legal proceedings

The Company (directly or indirectly through subsidiaries) is a party to several commercial, tax 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.

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, 2019, amount to U$S 89.3 million.

F-146

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

We hereinafter detail the nature of significant proceedings for which provisions have been recorded as of December 31, 2019:

-     Relevant Customs Summary Proceedings - Gasoline Exports: there is an important number of customs summary proceedings and 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’s position involves a higher export duty rate. As December 31, 2019, the associated provision amounts to U$S 84.7 million.

11.6 Income tax and minimum notional income tax liability

	12.31.2019	12.31.2018
Non-current
Income tax, net of witholdings and advances	10	27
Total non current	10	27
Current
Income tax, net of witholdings and advances	53	25
Minimum notional income tax, net of witholdings and advances	-	4
Total current	53	29

11.6.1 Income tax

Pampa and HIDISA and HINISA has assessed income tax for the fiscal period 2012 to 2018, respectively taking into consideration the application of the inflation adjustment mechanisms set forth in Title VI of the Income Tax Act, the update of Property, plant and equipment amortizations (Sections 83, 84 and 89), a cost restatement on account of the disposal of shares and mutual funds quotas (Sections 58, 61 and 89), and the update of intangible assets amortizations (Sections 81.c, 84 and 89, and Section 128 of its regulatory decree), to such effect using the IPIM published by the INDEC and the IPC of the Autonomous City of Buenos Aires for the November-December 2015 period, based on the similarity with the parameters put forward in the matter of “Candy S.A.” heard by the National Supreme Court of Justice, which on July 3, 2009 ruled for the application of the inflation adjustment mechanism.

As a consequence of adherence to the tax revaluation optional regime detailed in Note 2.6.1.4, on March 29, 2019, Pampa withdrew from the actions promoted and on April 4, 2019, paid the income tax corresponding to the 2016 fiscal period, without considering the application of the fiscal inflation adjustment, plus related interests in an amount of U$S 10.8 million.

F-147

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

As of December 31, 2019, HIDISA and HINISA hold a provision for the additional income tax liabilities assessable for fiscal years mentioned in case the inflation adjustment had not been deducted. This provision amounts to U$S 9.9 million including compensatory interest and was disclosed in the line “Income tax liability and minimum notional income tax non-current”.

11.7 Tax liabilities

	12.31.2019	12.31.2018
Non-current
Value added tax	-	4
Sales tax	1	1
Payment plans	-	2
Extraordinary Canon	3	7
Total non-current	4	14
Current
Value added tax	38	21
Municipal, provincial and national contributions	3	3
Personal assets tax provision	3	-
Payment plans	1	1
Municipal taxes	2	3
Tax withholdings to be deposited	6	9
Royalties	4	5
Extraordinary Canon	12	10
Other	3	2
Total current	72	54

11.7.1 Gross Income Tax

The Company has differences in interpretation with Argentine Provincial Treasuries regarding certain taxes applicable to the Company’s activity. Particularly, HIDISA and HINISA have filed a note to the Province of Neuquén’s Revenue Department informing that they consider that the electric power generation activity conducted in that province should be covered by the provisions of Section 12 of Law No. 15,336. Thus, and pursuant to this section, revenues resulting from the generation of electric power are exempted from the provincial gross income tax. However, they hold a provision for gross income tax that would have applied.

The Company’s management estimates that the resolution of these issues will not have a material adverse effect on its financial position or operating results.

F-148

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

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 US 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 US 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 choice to use it, in which case it may have to notify the trustee thereof.

F-149

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

As of December 31, 2019, 2018 and 2017, the most relevant actuarial information corresponding to the described benefit plans is the following:

	12.31.2019
	Present value of the obligation	Fair value of plan assets	Net liability at the end of the year
Liabilities at the beginning	40	(5)	35
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	15	(2)	13
Items classified in other comprehensive  income
Actuarial (gains) losses	(2)	-	(2)
Benefit payments	(2)	-	(2)
Gain on monetary position, net	(18)	2	(16)
At the end	36	(5)	31
	12.31.2018
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	47	(3)	44
Items classified in profit or loss
Current services cost	2	-	2
Cost for interest	9	(1)	8
Past services cost	(5)	-	(5)
Items classified in other comprehensive  income
Actuarial losses (gains)	6	(2)	4
Benefit payments	(3)	-	(3)
Increase for subsidiries acquisition	(16)	1	(15)
At the end	40	(5)	35

F-150

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

	12.31.2017
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	58	(8)	50
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	12	(1)	11
Past services cost	1	-	1
Items classified in other comprehensive income
Actuarial losses (gains)	(1)	-	(1)
Exchange differences on translation	1	(1)	-
Benefit payments	(2)	-	(2)
Reclasification to liabilities associated to assets classified as hed for sale	(11)	4	(7)
Gain (loss) on net monetary position	(14)	3	(11)
At the end	47	(3)	44

As of December 31, 2019, the breakdown of net liabilities per type of plan is as follows: a) U$S 21 million correspond to the Pension and Retirement Benefits Plan and b) U$S 10 million correspond to the Compensatory Plan.

As of December 31, 2018, net liability by type of plan, is as follows: a) U$S 24 million corresponding to Pension and Retirement Benefits Plan and b) U$S 11 million corresponding to Compensatory Plan.

As of December 31, 2017, net liability by type of plan, is as follows: a) U$S 33 million corresponding to Pension and Retirement Benefits Plan and b) U$S 11 million corresponding to Compensatory Plan.

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.

	12.31.2019
Less than one year	4
One to two years	3
Two to three years	2
Three to four years	2
Four to five years	2
Six to ten years	11

F-151

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

Significant actuarial assumptions used were as follows:

	12.31.2019	12.31.2018	12.31.2017
Discount rate	5%	5%	5%
Salaries increase	1%	1%	1%
Average inflation	50%	27%	21%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount:
 

	12.31.2019
Discount rate: 4%
Obligation	39
Variation	3
	10%
Discount rate: 6%
Obligation	33
Variation	(3)
	(9%)
Salaries increase: 0%
Obligation	34
Variation	(2)
	(5%)
Salaries increase: 2%
Obligation	38
Variation	2
	6%

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-152

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 11: (Continuation)

11.9 Salaries and social security payable

	12.31.2019	12.31.2018
Non-current
Seniority - based bonus	3	4
Early retirements payable	1	-
Total non-current	4	4
Current
Salaries and social security contributions	22	24
Provision for vacations	17	19
Provision for gratifications and annual bonus for efficiency	26	29
Total current	65	72

NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1 Financial assets at amortized cost

	12.31.2019	12.31.2018
Non-current
Public securities (1)	18	-
Total non-current	18	-
Current
Time deposits	-	35
Public securities (1)	54	-
Total current	54	35

⁽¹⁾ The public securities were received in accordance with the mechanism set forth by SGE Resolution No. 54/19 for the settlement of receivables under Natural Gas Surplus Injection Promotion Programs. See Note 2.4.3.1.

F-153

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

12.2 Financial assets at fair value through profit and loss

	12.31.2019	12.31.2018
Non-current
Shares	11	11
Total non-current	11	11
Current
Government securities	113	298
Shares	8	1
Investment funds	244	106
Total current	365	405

12.3 Trade and other receivables

	Note	12.31.2019	12.31.2018
Non-Current
CAMMESA Receivable (1)		-	70
Other		8	23
Trade receivables, net		8	93
Non-Current
Tax credits		3	13
Related parties	17	53	49
Prepaid expenses		1	1
Financial credit		-	1
Receivable for sale of property, plant and equipment		-	3
Natural Gas Surplus Injection Promotion Program (2)		-	71
Credit with RDSA	20	35	20
Allowance for doubtful accounts		(35)	-
Other		14	2
Other receivables, net		71	160
Total non-current		79	253

F-154

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

Current	Note	12.31.2019	12.31.2018
Receivables from energy distribution sales		226	223
Receivables from MAT		17	27
CAMMESA		168	131
CAMMESA Receivable (1)		-	15
Receivables from oil and gas sales (3)		48	78
Receivables from refinery and distribution sales		-	6
Receivables from petrochemistry sales		54	67
Related parties	17	6	10
Government of the PBA and CABA by Social Rate		4	-
Other		10	4
Allowance for doubtful accounts		(33)	(34)
Trade receivables, net		500	527
Tax credits		10	27
Advances to suppliers		-	2
Related parties	17	8	5
Prepaid expenses		2	2
Receivables for non-electrical activities		11	14
Financial credit		5	6
Guarantee deposits		5	13
Natural Gas Surplus Injection Promotion Program (2)		-	71
Insurance to recover		-	6
Expenses to be recovered		10	11
Credits for the sale of property, plant and equipment		1	21
Credit with RDSA	20	1	-
Other		14	6
Allowance for other receivables		(6)	(8)
Other receivables, net		61	176
Total current		561	703

(1)	CAMMESA receivables were settled in pursuant to the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
(2)	Receivables under the Natural Gas Surplus Injection Promotion Programs were settled through the delivery of public securities pursuant to the mechanism set forth by SGE Resolution No. 54/19 (see Note 2.4.3.1).
(3)	Including U$S 14.6 million corresponding to the receivables with gas distributors pursuant to the procedure set forth by PEN Executive Order No. 1,053/18 and regulated by ENARGAS Resolution No. 466/19 (see Note 2.4.3.2).

F-155

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

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 allowance for the impairment of trade receivables are as follows:

	12.31.2019	12.31.2018	12.31.2017
At the beginning	34	26	21
Allowance for impairment	23	34	13
Utilizations	(13)	(10)	(3)
Reversal of unused amounts	(2)	(1)	-
Exchange differences on translation	(1)	-	-
Reclasification to  assets held   for sale	-	-	(5)
Gain on monetary position, net	(8)	(15)	(5)
At the end of the year	33	34	21

The movements in the allowance for the impairment of other receivables are as follows:

	12.31.2019	12.31.2018	12.31.2017
At the beginning	8	6	10
Allowance for impairment	1	7	1
Gain on monetary position, net	(1)	(3)	-
Decreases	-	-	(1)
Reversal of unused amounts	(2)	(2)	(5)
At the end of the year	6	8	5

F-156

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

12.4 Cash and cash equivalents

	12.31.2019	12.31.2018
Banks	57	83
Investment funds	4	-
Time deposits	164	158
Total	225	241

12.5 Borrowings

Non-Current	Note	12.31.2019	12.31.2018
Financial borrowings		161	258
Corporate bonds (1)		1,603	1,457
CAMMESA financing		-	120
		1,764	1,835
Current
Financial borrowings		137	313
Corporate bonds		32	25
CAMMESA financing		-	3
Related parties	17	14	1
		183	342
Total		1,947	2,177

⁽¹⁾ Net of the repurchase of Corporate Bonds of Pampa Energía for a nominal value of U$S 81 million and U$S 9 million and the repurchase of Edenor’s Corporate Bonds for a nominal value of U$S 29 million and U$S 10 million as of December 31, 2019 and 2018, respectively.

As of December 31, 2019 and 2018, the fair values of the Company’s Corporate Bonds amount approximately to U$S 1,436 million and U$S 1,300 million, respectively. Such values were calculated on the basis of the determined market price of the Company’s corporate notes at the end of each year (fair value level 1 and 2).

The carrying amounts of short-term borrowings approximate their fair value due to their short-term maturity.

The other long-term borrowings were measured at amortized cost, which does not differ significantly from its fair value.

F-157

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

The movements in the borrowings are as follows:

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning		2,177	1,683	1,269
Proceeds from borrowings		556	245	1,250
Payment of borrowings		(550)	(240)	(733)
Accrued interest		185	179	143
Payment of borrowings' interests		(148)	(133)	(108)
Net foreign currency exchange difference		50	1,244	227
Results for the repurchase of corporate bonds	12.5.2	(27)	(2)	-
Costs capitalized in property, plant and equipment	11.1	17	8	14
Decrease through offsetting  with trade receivables		(135)	-	-
Gain on monetary position, net		(88)	(795)	(379)
Repurchase and redemption of corporate bonds		(91)	(13)	(1)
Other financial results		1	1	1
At the end of the year		1,947	2,177	1,683

As of the date of issuance of these Consolidated Financial Statements, the Company is in compliance with the covenants established in its indebtedness

F-158

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U$S – unless otherwise stated)

NOTE 12: (Continuation)

12.5.1 Details of borrowings:

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2019
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	139
Class E CB	PAMPA	ARS	575	Variable	Badlar	Nov-20	10
Class 1 CB	PAMPA	U$S	687	Fixed	7.50%	Ene-27	698
T Series  CB	PAMPA	U$S	487	Fixed	7.38%	Jul-23	497
Serie 3 CB (1)	PAMPA	U$S	293	Fixed	9.13%	Abr-29	291
							1,635
Regulatory:
Thrid parties:
	PAMPA	U$S	84	Fixed	Between 4.25% and 7.65%	Jan-2020 to May-2020	88
	PAMPA	U$S	39	Fixed and variable	4.21% + Libor	May-2024	39
	PAMPA	ARS	7,775	Fixed	Between 40% and 44.14%	Apr-2021 to Apr-2022	146
							273
Related parties:
	PAMPA	U$S	13	Fixed	6.0%	2020	14
Financial loans:
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	25
							25
							1,947

⁽¹⁾ On June 10, 2019, the Company issued Series 3 Corporate Bonds for a face value of U$S 300 million. These corporate bonds accrue interest at a fixed rate of 9.125% payable semi-annually, and the principal will be payable in a single installment upon maturity, in April 2029.

F-159

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2018
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	170
Class 4 CB (1)	PAMPA	U$S	34	Fixed	6.25%	Oct 20	34
Class E CB	PAMPA	ARS	607	Fixed	Badlar	Nov-20	16
T Series  CB	PAMPA	U$S	500	Fixed	7.38%	Jul-23	753
Class 1  CB	PAMPA	U$S	747	Fixed	7.50%	Jan-27	510
							1,483
Regulatory:
CAMMESA 2014 Agreement	PAMPA	ARS	855	Variable	CAMMESA	(2)	57
CAMMESA Mapro	PAMPA	ARS	174	Variable	CAMMESA	(2)	7
CAMMESA Mapro	CPB	ARS	1,085	Variable	CAMMESA	(2)	59
							123
Financial loans:
	PAMPA	U$S	17,116	Fixed	Between 3.6% and 6.8%	Feb-2019 to May-2021	459
	PAMPA	U$S	1,746	Fixed and variable	6% + Libor	May-2024	46
	PAMPA	ARS	550	Fixed	22.25%	Sep-2019 to Oct-2019	15
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	51
							571
							2,177

(1)	On July 12, 2019, the Company provided for the early redemption of Series 4 Corporate Bonds for a value of U$S 34 million.
(2)	Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).

F-160

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(in millions of U$S – unless otherwise stated)

NOTE 12: (Continuation)

12.5.2 Acquisition of own Corporate Bonds

As of the closing of fiscal year 2019, Pampa held in its portfolio: Series T Corporate Bonds maturing in 2023 for a face value of U$S 13.5 million, repurchased at an average clean price of U$S 74.55 per face value of U$S 100; Series 1 Corporate Bonds maturing in 2027 for a face value of U$S 63.03 million, repurchased at an average clean price of U$S 74.27 per face value of U$S 100; Series 3 Corporate Bonds for U$S 7.33 million, repurchased at an average clean price of U$S 78.63 per face value of U$S 100.

During fiscal years ended December 31, 2019 and 2018, the Company and its subsidiaries purchased and/or redeemed own or different subsidiaries’ Corporate Bonds at their respective market values for a total face value of U$S 91 million and U$S 13.2 million, respectively. As a result of these repurchase and/or redemption transactions, the Company reported consolidated losses for U$S 27 million and U$S 2 million in the fiscal years ended December 31, 2019 and 2018, respectively, which are disclosed in the “Results from the repurchase of corporate bonds” item under Other financial results (see Note 10.5).

12.5.3 Edenor - Global Program for the Issuance of Corporate Bonds

On August 8, 2019, Edenor’s General Ordinary Shareholders’ Meeting approved the creation of Edenor’s Global Program for the Issuance of Corporate Bonds effective for a term of five years and for a maximum outstanding amount of U$S 750 million, or its equivalent value in other currencies. 

12.5.4 Financial loans

In 2019, Pampa paid off Banking debt (including pre-export finance facilities) for U$S 420 million and $ 550 million, and took on new debt for U$S 25 million and $ 8,349 million. As of December 31, 2019, approximately 60% of the bank debt is denominated in pesos. 

As of December 31, 2019, Pampa’s short-term principal maturities amounted to U$S 92 million and $ 575.2 million, whereas Edenor’s short-term maturities amounted to U$S 25 million.

After the closing of the fiscal year, Pampa repaid financing at maturity for a total amount of U$S 25 million.

F-161

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

12.6.  Trade and other payables

Non-Current		12.31.2019	12.31.2018
Customer contributions		3	3
Funding contributions for substations		-	1
Customer guarantees		4	4
Trade payables		7	8
ENRE Penalties and discounts		64	138
Loans (mutuums) with CAMMESA		-	61
Compensation agreements		7	7
Liability with FOTAE		-	5
Payment agreement with ENRE		-	1
Lease liability		12	-
Other		-	-
Other payables		83	212
Total non-current		90	220
Current	Note	12.31.2019	12.31.2018
Suppliers		212	250
CAMMESA		155	316
Customer contributions		1	-
Discounts to customers		-	1
Customer advances		7	6
Related parties	17	8	6
Other		-	1
Trade payables		383	580
ENRE Penalties and discounts		57	49
Related parties	17	5	-
Compensation agreements		3	13
Payment agreements with ENRE		1	2
Other creditors		-	8
Lease liability		4	-
Other		1	5
Other payables		71	77
Total current		454	657

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, except non-current customer contributions.

The fair values of non-current customer contributions as of December 31, 2019 and 2018 amount to U$S 0.8 million and U$S 2.9 million, respectively. The fair values are determined based on estimated discounted cash flows in accordance with a market rate for this type of transactions. This fair value is classified as level 3.

The book value of the compensation agreements approximates their fair value given the valuation characteristics (Note 4.17).

F-162

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

12.7 Financial instruments by category

The following chart presents financial instruments by category:

As of December 31, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	622	4	626	14	640
Financial assets at fair value through profit and loss
Government securities	-	113	113	-	113
Shares	-	19	19	-	19
Investment funds	-	244	244	-	244
Derivative financial instruments	-	4	4	-	4
Cash and cash equivalents	221	4	225	-	225
Total	843	388	1,231	14	1,245
Liabilities
Trade and other liabilities	408	7	415	129	544
Borrowings	1,947	-	1,947	-	1,947
Derivative financial instruments	-	3	3	-	3
Total	2,355	10	2,365	129	2,494
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	909	3	912	44	956
Financial assets at amortized cost
Government securities	35	-	35	-	35
Financial assets at fair value through profit and loss
Government securities	-	298	298	-	298
Shares	-	12	12	-	12
Investment funds	-	106	106	-	106
Cash and cash equivalents	241	-	241	-	241
Total	1,185	419	1,604	44	1,648
Liabilities
Trade and other liabilities	610	15	625	252	877
Borrowings	2,177	-	2,177	-	2,177
Instrumentos financieros derivados	-	1	1	-	1
Total	2,787	16	2,803	252	3,055

F-163

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 12: (Continuation)

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, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	93	3	96	-	96
Interest expense	(275)	-	(275)	(20)	(295)
Foreign exchange, net	(92)	14	(78)	3	(75)
Results from financial instruments at fair value	-	91	91	-	91
Gains (losses) from present value measurement	54	-	54	-	54
Other financial results	37	-	37	2	39
Total	(183)	108	(75)	(15)	(90)
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	94	5	99	-	99
Interest expense	(289)	-	(289)	(22)	(311)
Foreign exchange, net	(865)	86	(779)	(84)	(863)
Results from financial instruments at fair value	-	64	64	-	64
Gains (losses) from present value measurement	(74)	-	(74)	-	(74)
Other financial results	12	-	12	(2)	10
Total	(1,122)	155	(967)	(108)	(1,075)
As of December 31, 2017	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	55	7	62	-	62
Interest expense	(217)	-	(217)	(11)	(228)
Foreign exchange, net	(191)	49	(142)	(14)	(156)
Results from financial instruments at fair value	-	62	62	-	62
Gains (losses) from present value measurement	(6)	-	(6)	-	(6)
Other financial results	(2)	-	(2)	(2)	(4)
Total	(361)	118	(243)	(27)	(270)

F-164

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– 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, 2019 and 2018:

As of Dectember 31, 2019	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	113	-	-	113
Shares	8	-	11	19
Investment funds	244	-	-	244
Cash and cash equivalents
Investment funds	4	-	-	4
Derivative financial instruments	-	4	-	4
Other receivables	4	-	-	4
Total assets	373	4	11	388
Liabilities
Derivative financial instruments	-	3	-	3
Total liabilities	-	3	-	3
As of December 31, 2018	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	298	-	-	298
Trust	1	-	11	12
Investment funds	106	-	-	106
Other receivables	3	-	-	3
Total assets	408	-	11	419
Liabilities
Derivative financial instruments	-	1	-	1
Total liabilities	-	1	-	1

F-165

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– 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 income, 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: they were determined based on Income approach through the Indirect Cash Flow method (net present value of expected future cash flows) and the discount rates used were estimated taking the WAAC rate as a parameter.

NOTE 13: EQUITY COMPONENTS

13.1 Share capital and reserves

13.1.1 Share capital

On October 2, 2018, the Company’s Extraordinary General Meeting of Shareholders approved a capital reduction through the cancellation of 182,820,250 treasury shares it held as a result of the Share Repurchase Programs, the Company’s capital stock thus decreasing from 2,082,690,514 shares to 1,899,870,264 shares (1,874,434,580 of which are outstanding shares and 25,435,684 treasury shares). This reduction was registered with the IGJ on November 22, 2018. Furthermore, on January 9, 2019, the CNV granted the partial cancellation of the public offering regarding the reduced shares.

F-166

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 13: (Continuation)

On October 1, 2019, the Company’s Extraordinary General Meeting of Shareholders resolved to reduce the capital stock through the cancellation of own shares held in treasury as of the last business day prior to the holding of the meeting which had been acquired under the Share Repurchase Programs dated June 22, 2018, and March 27 and August 12, 2019. In this sense, the capital stock was reduced through the cancellation of 151,997,025 treasury shares, the capital stock thus decreasing from 1,899,870,264 shares to 1,747,873,239 shares. This reduction was registered with the IGJ on November 20, 2019, the partial cancellation by the CNV of the public offering regarding the reduced shares still pending as of December 31, 2019.

As of December 31, 2019, treasury shares amount to 4.05% of the capital stock, of which 65,725,450 shares correspond to the Share Repurchase Program and 5,035,746, to the Stock-based Compensation Plan for officers and other key staff.

13.1.1.1 Publicly traded shares

The Company’s shares are listed for trading on Buenos Aires Stock Exchange, forming part of the Merval Index. Also, on August 5, 2009, the SEC authorized the Company for the registration of ADSs representing 25 common shares each. On October 9, 2009, the Company started to market its ADSs on the NYSE.

The listing of the ADSs with the NYSE is part of the Company’s strategic plan to increase its liquidity and the tradable volume of its shares.

13.1.1.2 Company Share Repurchase Programs

In view of the fact that the Company’s share price does not reflect either the value or the economic reality its assets currently or potentially have, this being detrimental to the interests of the Company’s shareholders, and taking into consideration the Company’s strong cash position and fund availability, the Company’s Board of Directors has approved the share repurchase programs that are detailed below, in all cases taking into consideration that treasury shares may not cumulatively exceed the 10% of the share capital:

1.

April 27, 2018 Share repurchase program: for a maximum amount of U$S 200 million and for an initial term of 120 calendar days; extended on June 22, 2018 for an additional maximum amount of up to U$S 200 million for an initial term of 120 calendar days. Shares may be purchased for a maximum price of the amount, in Argentine pesos, equivalent to U$S 2.40 per common share and U$S 60 per ADR, for the initial program, and U$S 2.20 per common share and U$S 55 per ADR for the extension.

2.

March 27, 2019 Share repurchase program: for a maximum amount of U$S 100 million and for an initial term of 120 calendar days. Shares may be purchased for a maximum price of the amount, in Argentine pesos, equivalent to U$S 1.04 per common share and of U$S 26 per ADR. On June 12, 2019, this program was suspended as the listing of the Company’s shares and ADRs had reached values exceeding the repurchase cap set.

F-167

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 13: (Continuation)

3. August 12, 2019 Share repurchase program: for a maximum amount of U$S 50 million and for an initial term of 120 calendar days. Shares may be acquired up to a maximum price of the equivalent in pesos of U$S 1 per common share and U$S 25 per ADR. The maximum amount was extended to U$S 65 million on August 30, 2019.
4. November 8, 2019 Share repurchase program: for a maximum amount of U$S 50 million and for an initial term of 120 calendar days. Shares may be acquired up to a maximum price of the equivalent in pesos of U$S 0.58 per common share and U$S 14.50 per ADR.

As part of the Share Repurchase Program, during fiscal years ended December 31, 2019 and 2018, the Company acquired the equivalent of 197,612,900 and 202,929,825 own shares for an amount of $ 7,070 million and $ 12,275 million, respectively.

13.1.1.3 Stock-based Compensation Plan

During the fiscal years ended December 31, 2018 and 2017, the Company repurchased 3,000,000 and 2,500,000 shares, respectively, corresponding to the Stock-based Compensation Plan benefiting officers and other key staff for an amount of $ 260 million and $ 126 million, respectively. As of December 31, 2019, the Company delivered the equivalent of 464,254 own shares as payments under this plan (see Note 19.2).

13.1.2 Other reserves

13.1.2.1 Acquisition of own ADRs by Edenor

On April 8, 2019, Edenor’s Board of Directors approved a new Share Repurchase Program for a maximum amount of $ 800 million and an initial term of 120 calendar days as from April 9, 2019. Under this program, treasury shares may not together exceed the 10% of the capital stock cap, and may be acquired up to a maximum price of the equivalent in pesos of U$S 23 per ADR or the amount in pesos equivalent to U$S 1.15 per common share.

In its meeting held on June 12, 2019, Edenor’s Board of Directors resolved to early terminate the term timely stipulated for the acquisition of own shares.

As of December 31, 2019, Edenor holds 31,380,871 Series B treasury shares, of which 8,269,740 have been acquired in this fiscal year, for a total amount of $ 599 million restated at constant currency.

F-168

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 13: (Continuation)

13.1.2.2 Acquisition of Edenor’s ADRs by the Company

During the fiscal years ended December 31, 2019 and 2018, the Company acquired a total number of 1,179,491 and 346,270 Edenor’s ADRs, each one equivalent to 20 Series B common shares, at an acquisition cost of U$S 6 million and U$S 9 million, respectively.

13.2 Earnings per share

13.2.1 Basic

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.

13.2.2 Diluted

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, 2019, 2018 and 2017, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

	12.31.2019	12.31.2018	12.31.2017
Earning for continuing operations attributable to the equity holders of the Company	692	146	341
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings per share from continuing operations	14.42	2.81	6.69
Earning (loss) for discontinued operations attributable to the equity holders of the Company	-	78	(55)
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings (loss) per share from discontinued operations	-	1.50	(1.07)
Total earning attributable to the equity holders of the Company	692	224	286
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings  per share	14.42	4.31	5.61

F-169

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 13: (Continuation)

13.3 profit distributions

13.3.1 Dividends

Pursuant to Law No. 27,430, enacted in December 2017, and the suspension provided for by Law No. 27,541 (Note 2.6.1.2), dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or after January 1, 2018 through December 31, 2021, are subject to a 7% withholding tax. The distribution of dividends is made based on the Company’s Stand-Alone Financial Statements.

NOTE 14:  STATEMENT OF CASH FLOWS’ COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit (loss) to cash flows generated by operating activities

	Note	12.31.2019	12.31.2018	12.31.2017
Income tax	10.6	48	17	(26)
Accrued interest		202	219	166
Depreciations and amortizations	9, 10.1 and 10.2	267	234	205
Constitution of allowances, net	10.4 and 10.1	25	28	12
Constitution (recovery) of provisions, net	10.4	27	31	(4)
Share of profit from joint ventures and associates	5.3.2	(101)	(118)	(48)
Income from the sale of companies	5.1	-	(28)	-
Accrual of defined benefit plans	9, 10.1 and 10.2	16	5	14
Net exchange differences	10.5	75	863	156
Result from measurement at present value	10.5	(54)	74	6
Changes in the fair value of financial instruments	10.5	(91)	(64)	(62)
Results from property, plant and equipment sale and decreases	10.4 and 10.3	5	4	1
Results for the repurchase of corporate bonds	10.5	(27)	(2)	-
Impairment of property, plant and equipment	11.1.1	62	32	-
Dividends received	10.4	(1)	(1)	(1)
Compensation agreements	10.1 and 10.2	(1)	5	26
Result from the sale of shareholdings in companies, property, plant and equipment	5.2.3	-	(44)	-
Agreement on the regularization of obligations		(285)	-	-
Other financial results of RDSA		(2)	(13)	-
Onerous contract (Ship or pay)	10.4	-	7	4
Gain on monetary position, net	10.5	(187)	(629)	(304)
Other		(8)	2	6
		(30)	622	151

F-170

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 14: (Continuation)

14.2 Changes in operating assets and liabilities

	12.31.2019	12.31.2018	12.31.2017
Increase (decrease) in trade receivables and other receivables	17	(172)	(65)
Increase in inventories	(28)	(18)	(11)
Increase in trade payables and other payables	97	22	10
Increase in deferred income	-	2	-
Decrease in salaries and social security payable	15	14	(1)
Decrease in defined benefit plans	(2)	(3)	(3)
(Decrease) increase in tax payables	20	35	(26)
(Increase) decrease in provisions	(9)	(60)	(48)
Income tax and minimum notional income tax paid	(87)	(49)	(56)
(Payments) proceeds from derivative financial instruments, net	9	(24)	23
Total changes in operating assets and liabilities	32	(253)	(177)

14.3 Significant non-cash transactions

	12.31.2019	12.31.2018	12.31.2017
Acquisition of property, plant and equipment through an increase in trade payables	(45)	17	(103)
Borrowing costs capitalized in property, plant and equipment	(17)	(7)	(16)
Decreases of  property, plant and equipment through an increase in other receivables	-	12	-
Agreement on the regularization of obligations	285	-	-
Increase in asset retirement obligation provision through an increase in property, plant and equipment	1	34	(2)
Constitution of guarantee of derivative financial instruments, net through the delivery of financial assets at fair value through profit or loss	3	(22)	19
Cancellation of other credits for capital contributions in associates	(17)	-	-
Compensation of investments at a cost cost through the transfer of other credits	(126)	-	-
Loan compensation through the transfer of sales credits	135	-	-
Increase of right-of-use assets through an increase in other debts	20	-	-
Significant non-cash transactions from discontinued operations :
Credit pending collection for sale of property, plant and equipment	-	-	15

F-171

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: CONTINGENT LIABILITIES AND ASSETS

We hereinafter detail the nature of significant proceedings as of December 31, 2019, 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.

-        Claims by former employees seeking a compensation under the plan on account of terminations due to changes in shareholding control.

-        Claims on considering that the index (IPC) used to update the plan benefits are ineffective to keep their “constant value”.

-        Claims on an alleged underfunding of the plan upon the elimination of the Company’s contributions based on earnings.

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.  

- Income tax refund: The Company, HIDISA, HINISA and CPB have filed several tax refund claims in the amount of $ 1,169 million for overpaid income taxes taking into considerations the effects of the inflation adjustment mechanism. On December 7, 2017, CPB collected the amount claimed for the 2002 period, which amounts to $ 4 million plus interest. However, upon joining the tax revaluation regime detailed in Note 2.6.1.4, on March 29, 2019 and April 3, 2019, Pampa and CPB, respectively, formally presented their waiver to the rights invoked in the mentioned tax refund claims in the amounts of $ 1,095 million and $ 1.6 million, respectively.  

- Minimum notional income tax refund: The Company and the former CTLL have filed several refund claims before the AFIP on account of the minimum notional income tax for fiscal periods 2008 and 2009 requesting the refund of $ 25 million, including the refund of payments timely made and the release of the offsetting payment made against several tax credits. As AFIP didn’t answer the claim, the Company and the former CTLL brought a tax refund claim before the competent National First-Instance Administrative Litigation Court.

F-172

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

On August 25, 2016 the former CTLL obtained a favorable ruling by the Chamber of Appeals, which upheld the first-instance decision sustaining the refund claim; however, the payment has not been collected as of the date hereof, and the Company is conducting the relevant proceedings in this respect. The Company considers it has a high probability of obtaining a favorable final and conclusive ruling.

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 U$S 547 million based on a PDUN 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 U$S 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 U$S 1 million, or the difference between the value of the allegedly affected lot and its valuation. The proceeding is in the evidentiary stage.

F-173

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

- 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 proceeding is pending the resolution of the admissibility of CSJN’s jurisdiction.  

- A group of neighbors of the City of Bahía Blanca instituted a complaint before the provincial courts of this city for alleged environmental damage having collective impact against the companies of the petrochemical complex, Consorcio de Gestión Del Puerto de Bahía Blanca and the Province of Buenos Aires. The plaintiffs seek the redress of collective moral injury (estimated at $ 52 million), the cessation of the alleged damage to the estuary of Bahía Blanca, and a comprehensive restoration to its previous state. In case this is not possible, the plaintiffs subsidiarily seek damages, the beneficiary of which would be the Environmental Compensation Fund. They also request a prohibition to install new industrial activities in the area and the development of a new and efficient industrial waste collection, disposal and treatment system. The proceeding is in the sentence stage.  

- 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 maintained its jurisdiction in the environmental issue and the Court’s jurisdiction regarding the compensation for the alleged damages.  

- 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 with a negative conflict of jurisdiction.  

- 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.

F-174

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

- 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 proceeding is in the lawsuit integration stage.  

- The Company initiated a legal claim against the Province of La Pampa requesting the annulment and revocation of administrative acts through which said Province through its Undersecretary of Hydrocarbons and Mining and its Undersecretariat of Environment, intends that the Company carries out definitive abandonment of 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.  

- Plaintiffs María Elena Baya de Rudd and David Rudd have filed a complaint against the Company, other companies and the joint venture made up by them for the repair of alleged damages caused in the Estancia Laguna Esperanza lot owned by them and the remediation of alleged environmental damage caused by the exploitation and abandonment of oil wells in the lot.  A sentence was issued in the appellate proceeding. We have filed a federal extraordinary appeal against that sentence, and have jointly requested with the plaintiff the suspension of the procedural time limits in order to negotiate a settlement, which suspension was granted.  

- 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 proceeding is currently in the evidentiary stage.   

- 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 has been filed and answered.   

15.4 Civil and Commercial Claims

- The “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of U$S 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 is appealing the Arbitration Court’s decision declaring the dismissal of the main claim upon the failure to pay the arbitration fee.

F-175

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

- The Company was notified of the institution of a collective action in the City of Rio de Janeiro, Brazil, by a lawyer of that nationality, Felipe Machado Caldeira, alleging that Petrobras Brasil has not conducted Petrobras Argentina’s sales process pursuant to a competitive bidding process in accordance with Brazilian laws applicable to mixed public-private firms in Brazil, for a nominal amount of R$ 1,000 million. In this proceeding, no specific accusation against Pampa has been filed. The proceeding is currently suspended in the integration and complaint answer stage.  Upon the death of the plaintiff and the Public Prosecution Service’s statement that it is not interested in pursuing the complaint, a legal notice was published so that any citizen may express its interest in pursuing it.  

- Messrs. Candoni, Giannasi, Pinasco and Torriani brought arbitration complaints against the Company before the Buenos Aires Stock Exchange’s Arbitration Court seeking to challenge the price and tender offer for the merger through absorption of Petrobras Argentina S.A. into Pampa Energía S.A. for a nominal amount of $ 148 million. The complaints have been joined. The Court issued a partial award upholding the challenge under the capital markets law used by the plaintiff to dispute the exchange ratio used in the merger and dismissed the Company’s position, which stated that the proper course of action would be to challenge the shareholders’ meeting pursuant to the Business Organizations Law. The Company filed an appeal against this partial award and filed a motion for appeal and nullity which will be resolved by the Chamber of Appeals in Commercial Matters.  

- Fees associated with the injunction granted in favor of Oil Combustibles: Oil Combustibles’ attorneys claimed an increase in their fees assessed by the first-instance judge and ratified by the Chamber of Appeals of Rosario. The Supreme Court of Santa Fe resolved to annul the Camber’s decision and ordered that a new judgment should be passed. A motion for clarification was filed against this judgment before the Supreme Court of Justice, as well as an extraordinary appeal before the CSJN. A settlement was reached and all pending motions were dismissed.  

- Consumidores Financieros Asociación Civil para su Defensa, claimes Edenor: i) the reimbursement of the VAT percentage paid on the illegally “widened” taxable basis due to the incorporation of the National Electrical Energy Fund that distribution companies, the defendants, had not paid this tax when CAMMESA invoiced them the electricity purchased for distribution purposes, ii) the reimbursement of part of the administrative surcharge on “second due date”, in those cases in which payment was made within the time period authorized for such second deadline (14 days) but without distinguishing the effective day of payment, and iii) the application of the “borrowing rate” in case of customer delay in complying with payment obligation, in accordance with the provisions of Law No. 26,361. The Federal Government, the AFIP and the ENRE are summoned as third-party defendants. These proceedings have been joined to those mentioned below. Without prejudice thereto, in the framework of the record of the proceedings, the case has been brought to trial.

F-176

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

- Asociación de Defensa de derechos de clientes y consumidores (ADDUC) requested that the Company be ordered by the Court to reduce or mitigate the default or late payment interest rates charged to customers who pay their bills after the first due date, inasmuch as they violate section 31 of Law N° 24,240, ordering both the non-application of pacts or accords that stipulate the interest rates that are being applied to the users of electricity –their unconstitutional nature– as well as the reimbursement of interest amounts illegally collected from the customers of the service from August 15, 2008 through the date on which the defendant complies with the order to reduce interest. It is also requested that the VAT and any other taxes charged on the portion of the surcharge illegally collected be reimbursed. These proceedings have been joined to those mentioned above and have been brought to trial. Prior to requesting that evidence be produced, it was ordered that the records be sent to the Tax Representative, in order for the latter to pronounce on the motion to dismiss for lack of standing to sue filed by Edenor. Once the records were sent back to the court hearing the case, the aforementioned motion was rejected. The Company appealed against the rejection of the motion in a timely manner.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2019 where the related inflows of economic benefits are estimated to be probable by the Company.

15.5 Administrative claims

- CTLL filed a contentious administrative complaint against the National Government for contractual breach during the January 2016-July 2017 period. CTLL claims that CAMMESA’s decision should be reversed regarding the renewal and recognition of costs associated with natural gas supply agreements, and that, susbsidiarily, sustained damages for an estimated amount of U$S 26.6 million should be redressed. Later, the complaint was expanded to include the contractual breach as of October 2018, for an estimated amount of U$S 22.1 million. As of the date hereof the total claimed amounts to U$S 48.7 million.  

- Upon the determination of the expiration of the Veta Escondida area concession granted by the Province of Neuquén, the Company filed a declaratory judgment action to achieve certainty under the original jurisdiction of the Federal Supreme Court of Justice pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. Both parties agreed to suspend the proceeding and settle a solution. Negotiations are currently in progress, and terms have been suspended for 20-day periods renewable until settling the conflict.

F-177

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 15: (Continuation)

15.6 Civil and commercial claims

- Edenor seeks to obtain the judicial annulment of the ENRE’s Resolution 32/11 that provided Edenor to: i) be fined in the amount of $ 750 thousands due to its failure to comply with the obligations arising from Section 25, sub-sections a, f and g, of the Concession Agreement and Section 27 of Law No. 24,065, ii) be fined in the amount of $ 375 thousands due to its failure to comply with the obligations arising from Section 25 of the Concession Agreement and ENRE Resolution No. 905/99 and iii) be ordered to pay customers as compensation for the power cuts suffered the following amounts: $ 180 to each small-demand residential customer (T1R) who suffered power cuts that lasted more than 12 continuous hours, $ 350 to those who suffered power cuts that lasted more than 24 continuous hours, and $ 450 to those who suffered power cuts that lasted more than 48 continuous hours. The course of these proceedings is currently suspended due to the fact that an “Agreement of parties” has been entered into with the ENRE. In view of the time elapsed since Edenor and the ENRE agreed to suspend the procedural time-limits, the court has requested that the parties express their stance on the issue. Based on the terms of the Agreement on the Regularization of Obligations entered into on May 10, 2019 by and between Edenor and the Federal Government, this action should be abandoned, with each party bearing its own court costs, as agreed in such Agreement.   At the closing date of the year ended December 31, 2019, Edenor made a provision for principal and interest accrued for an amount of U$S 1.5 million within the Non-current other liabilities account. Based on that which has been mentioned above, and once the regulatory authority has given its consent, such provision should no longer be recorded.  

- Edenor’s purpose is to sue for breach of contract due to the Federal Government’s failure to perform in accordance with the terms of the “Agreement on the Renegotiation of the Concession Agreement” (“Acta Acuerdo de Renegociación del Contrato de Concesion” – the “Adjustment Agreement”) entered into with the Company in 2006, and for damages caused as a result of such breach.   On September 16, 2019, in the framework of the judicial record of the motion to litigate in forma pauperis, Edenor filed a brief regarding the abandonment of the action and waiver of right, requesting at the same time that each party be held liable for its own court costs. The representatives of the Federal Government gave their consent to the terms of the brief. Taking account of the brief, on September 24, the Court terminated the proceedings.   Furthermore, in the main proceedings, Edenor, with the Federal Government’s consent, filed a brief, also on September 16, regarding the abandonment of the action and waiver of right, declaring that the concepts dealt with in the proceedings amount to $ 6,900 million; therefore, payment of court fees, which amount to $207 million was incorporated therein. The records were sent to the Tax Authorities for their approval, having attached the breakdown of the amounts comprising the reconciled principal be submitted.

F-178

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 16: INVESTMENT COMMITMENTS

16.1 New generation projects

Under the National Government’s call for the expansion of the generation offer, the Company participates in the following thermal generation projects:

16.1.1 PEPE II and PEPE III wind farms

On May 10, 2019, CAMMESA declared the commercial commissioning of PEPE II (Pampa Energía wind farm) for a 50.4 MW power capacity and PEPE III (de la Bahía wind farm) for a 28.8 MW power capacity, the commercial commissioning for a 50.4 MW power capacity of the latter being completed on June 10, 2019. PEPE II is located in an area adjacent to Mario Cebreiro Wind Farm, in the area known as Corti, 20 kilometers from the City of Bahía Blanca. PEPE III is located in Coronel Rosales, near the City of Bahía Blanca. Both projects called for an investment of U$S 130 million and have an approximate 100.8 MW joint installed capacity.

The production of both wind farms is sold under agreements between private parties pursuant to the Term Market of Electric Power from Renewable Sources (MATER) Regime within the framework of SEE Resolution No. 281/17. Non-contracted energy will be remunerated according to the spot market remuneration (see Notes 2 and 23).

16.1.2 PEPE IV wind farm

The Company, as assignee of the rights under the PEPE IV project, requested to CAMMESA an extension of the term for the commercial commissioning of the wind farm, as well as its relocation. The request was authorized by the SGE and, to make it effective, CAMMESA asked the Company to meet certain requirements, including making several disbursements and increasing the originally granted guarantee pursuant to SGE Resolution No. 230/19.

However, as a result of events occurred during 2019, including the devaluation of the peso and the increase in interest rates, which have resulted in a growing macroeconomic instability, the Company requested an extension of the term to meet the above-mentioned requirements in order to evaluate the feasibility of the project under the new conditions, as well as to negotiate changes proposed by work contractors and equipment suppliers. In this context, and based on a thorough evaluation of the renewable projects in progress, on September 11, 2019 the SSERyEE instructed CAMMESA to temporarily suspend the claims for non-compliance, and demanded the Company to extend the validity of the U$S 12.5 million guarantee for a term of 180 days. On October 4, 2019, the Company complied with the requested extension. On October 9, 2019, the SSERyEE canceled the suspension. On October 30, 2019, CAMMESA served on the Company a formal demand requiring certain payments associated with the postponement of the commercial commissioning of the project and its relocation under penalty of enforcing the guarantee. The Company rejected the demand served by CAMMESA awaiting SGE’s consideration of the extension request, and on December 9, 2019 it entered into an agreement with CAMMESA establishing a negotiation process to be developed until January 31, 2020 inclusive, during which CAMMESA should suspend the enforcement of the guarantee. The agreement term was extended until February 29, 2020.

F-179

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 16: (Continuation)

On the other hand, on September 2, 2019, the assignment of all CTB’s rights, receivables and debts under the project was formalized for a price of U$S 0.1 million, which were offset with receivables CTB held against the Company on account of loans and commercial debt.

16.1.3 Genelba Thermal Power Plant

On June 12, 2019, CAMMESA declared the commercial commissioning of Genelba power plant’s fourth gas turbine for a power capacity of up to 187.7 MW. Furthermore, CAMMESA enabled the 19 MW repowering of the existing gas turbine unit’s power capacity, as of June 1, 2019.These units are part of Genelba Plus’ closing to combined cycle project, which will include the placing in service of a steam turbine.

The Project was selected under SEE Resolution No. 926-E/17 within the framework of the “Call for the Execution of New Co-generation and Closing to Combined Cycles Projects” established by SEE Resolution No. 287-E/17. Upon the commercial commissioning of the closing to combined cycle, the Wholesale Power Purchase Agreement executed with CAMMESA for a maximum committed capacity of 377 MW and a term of 15 years will enter into effect.

The total investment for the project is estimated at U$S 350 million. After the completion of the project, Genelba Power Plant will have two combined cycles with a total installed capacity of approximately 1,226 MW.

16.1.4 Barragán Thermal Power Plant

Regarding the commitment to CTB’s closing to combined cycle project, detailed in Note 5.3.5, for increasing the installed power capacity from 567 MW to 847 MW, with an estimated investment of U$S 200 million, on September 27, 2019, CTB and a joint venture made up of SACDE and Techint Compañía Técnica Internacional S.A.C.E.I, executed an engineering, procurement, construction, commissioning and turnkey agreement for the execution of the closing of the combined cycle at CTEB (the “EPC Agreement”).

16.2 Investment commitment for the exploration and exploitation of hydrocarbons 

As of the issuance of these Consolidated Financial Statements, the Company has committed investments for an estimated total amount of U$S 354 million, based on its participation, to be disbursed between 2020 and 2023, mainly regarding the Sierra Chata, Las Tacanas, El Mangrullo and Rincón del Mangrullo areas.

F-180

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 17: RELATED PARTIES´ TRANSACTIONS

17.1Sales of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CTB (1)	1	-	-
Transener	-	1	1
TGS (2)	29	51	23
Greenwind	1	-	-
Refinor (3)	18	16	5
Other related parties
SACDE	-	1	-
	49	69	29

(1)	Corresponds mainly to advisory services for technical assistance.
(2)	Corresponds mainly to advisory services for technical assistance and purchase of gas. TGS’ Meeting of Shareholders held on October 17, 2019 approved certain amendments to the services agreement which extend the agreement’s term and entail a progressive reduction over the years of the remuneration collectable by the Company as technical operator.
(3)	Corresponds mainly to sales of gas and refined products.

17.2Purchases of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS (1)	(22)	(21)	(8)
SACME	(1)	(2)	(2)
Refinor (2)	(19)	(34)	(17)
Oldelval (3)	(1)	(2)	(3)
Other related parties
SACDE (4)	-	(2)	-
Orígenes Vida	-	-	(1)
	(43)	(61)	(31)

(1)	Corresponds mainly to natural gas transportation services.
(2)	Corresponds mainly to purchases of refined products.
(3)	Correspond mainly to oil transportation services.
(4)	Correspond mainly to construction services that include work execution and storage of materials, capitalized in Properties, plant and equipment.

F-181

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 17: (Continuation)

17.3Fees for services

	12.31.2019	12.31.2018	12.31.2017
Other related parties
Salaverri, Dellatorre, Burgio & Wetzler	(1)	(1)	(1)
	(1)	(1)	(1)

Corresponds to fees for legal advice.

17.4Other operating income (expenses), net

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
Greenwind	(1)	-	-
OCP (1)	-	(7)	-
Other related parties
SACDE	1	-	-
Foundation (2)	(2)	(2)	(1)
	(2)	(9)	(1)

⁽¹⁾Corresponds to onerous contract (Ship or Pay).

⁽²⁾Corresponds to donations.

17.5Finance income

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS	3	3	3
	3	3	3

Corresponds to finance leases.

F-182

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 17: (Continuation)

17.6Dividends received

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CIESA/TGS	56	18	-
OCP	14	-	-
Oldelval	-	1	-
Citelec	17	-	-
	87	19	-

17.7Payment of dividends

Other related parties	12.31.2019	12.31.2018	12.31.2017
EMESA	-	(2)	(2)
APCO Oil	-	-	(2)
	-	(2)	(4)

17.8Key management personnel remuneration

The total remuneration to executive directors accrued amounts to U$S 6 million (U$S 7 million loss for Directors' and Sindycs' fees and U$S 1 million net gain for the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plans) during the year ended December 31, 2019, U$S 9.6 million (U$S 4.6 million in Directors' and Sindycs' fees and U$S 5.0 million in the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plans) during the year ended December 31, 2018 and U$S 31.2 million (U$S 4.1 million in Directors' and Sindycs' fees and U$S 27.1 million in the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plan) during the year ended December 31, 2017.

F-183

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 17: (Continuation)

17.9Balances with related parties

As of December 31, 2019	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	4	34	5
CIESA	-	-	-
Greenwind	-	4	-
Refinor	2	-	-
OCP	-	15	-
Other related parties
SACDE	-	-	2
Other	-	-	1
	6	53	8
As of December 31, 2019	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
Greenwind	5	-	-
SACME	2	-	-
Citelec	-	-	14
OCP	-	5	-
Refinor	1	-	-
	8	5	14

According to paragraphs 25 and 26 of IAS 24, Edenor applied the disclosure exemption in relation to related party transactions with a governmental agency that has control, joint control or significant influence. As of December 31, 2019, ANSES holds Edenor's Notes due 2022 amounting to $ 752 million (U$S 20 million of nominal value).

F-184

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 17: (Continuation)

As of December 31, 2018	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	8	38	4
Greenwind	-	11	-
Refinor	2	-	-
Other related parties
SACDE	-	-	1
	10	49	5
As of December 31, 2018	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
TGS	3	-	-
Refinor	3	-	-
Other related parties
Orígenes Retiro	-	-	1
	6	-	1

NOTE 18: LEASES

18.1 Lessee

Edenor leases commercial offices, two warehouses, the headquarters building (which includes administrative, commercial and technical offices), the Energy Handling and Transformer Center (two buildings and a plot of land located within the perimeter of Central Nuevo Puerto and Puerto Nuevo) and Las Heras Substation. Edenor’s lease agreements include cancelable clauses and terms ranging between 2 and 13 years.

Furthermore, 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 recognized as of December 31, 2019 is disclosed below:

F-185

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 18: (Continuation)

18.1.1 Right of use assets

Original values
Type of good	At the beginning	Increase	At the end
		(1)
Machinery and equipment	-	13	13
Buildings	-	7	7
Total at 12.31.2019	-	20	20
	Depreciation
Type of good	At the beginning	For the year	At the end
Machinery and equipment	-	(2)	(2)
Buildings	-	(2)	(2)
Total at 12.31.2019	-	(4)	(4)
	Net book values
Type of good	At the end
Machinery and equipment	11
Buildings	5
Total at 12.31.2019	16

⁽¹⁾Includes U$S 8 million incorporated as of January 1, 2019 on the adoption of IFRS 16 (see Note 4.1.1)

18.1.2 Lease liabilities

	12.31.2019
At the beginning of the year	-
Incorporation by adoption of IFRS 16	8
Increases	13
Discounted value measurement (1)	3
Payments	(5)
Exchange differences on translation	(3)
At the end of the year	16

⁽¹⁾Included in the “Gains (losses) from present value measurement” under Other financial results

F-186

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 18: (Continuation)

As of December 31, 2019, this liability is disclosed under Other current payables in the amount of U$S 4 million and Other non-current payables for U$S 12 million.

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:

	12.31.2019
Less than three months	1
Three months to one year	4
One to two years	4
Two to three years	2
Three to four years	1
Four to five years	1
More than five years	16
Total	29

18.1.3 Short-term or low value leases

As of December 31, 2019, the Company has recognized administrative costs and expenses in the amount of U$S 10 million on account of lease payments associated with short-term leases and low-value underlying assets. 

18.2Lessor

18.2.1 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 U$S 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, 2019, this receivable is disclosed under Other current receivables in the amount of U$S 5 million and under Other non-current receivables for U$S 34 million.

F-187

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 18: (Continuation)

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:

	12.31.2019
Less than three months	2
Three months to one year	6
One to two years	7
Two to three years	7
Three to four years	7
Four to five years	7
More than five years	12
Total	48

18.2.2Operating leases

Edenor has entered into operating lease contracts with certain cable television companies granting them the right to use its network’s poles. Most of these contracts have an automatic renewal clause.

As of December 31, 2019 and 2018, future minimum collections regarding operating leases are those detailed below:

	12.31.2019	12.31.2018
2019	-	5
2020	5	-
Total future minimum lease collections	5	5

The total income from operating leases for the years ended December 31, 2019 and 2018 amounts to U$S 5 million and U$S 5, respectively.

F-188

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 19: COMPENSATION PLANS

19.1 Company-Value Compensation (Pampa as successor company of PEPASA)

On November 6, 2013, former PEPASA’s Extraordinary General Meeting of Shareholders resolved to approve a variable and contingent compensation to certain officers equivalent to 7% of the capital stock after the former PEPASA’s capital stock increase, valued based on the difference between the share’s market value at the time of exercising the right and a given value of U$S 0.1735 per share determined at the exact moment of the former PEPASA’s capital stock increase.

On January 13, 2014, the former PEPASA’s capital stock increase was carried out and the rights granted to officers to receive the Company-Value Compensation became effective for the equivalent to 8,359,000 shares.

On January 18, 2017, PEPASA's officers requested the monetization of the right for the equivalent to 5.737.000 shares, which was canceled by the Company on January 31, 2017.

Within the framework of the corporate reorganization process described in Note 5.1.1.1, Pampa, as the absorbing company, is the universal successor of all the rights and obligations of the absorbed companies, including PEPASA.

Therefore, as a consequence of the application of the exchange ratio of 2.2699 Pampa shares for each PEPASA share pursuant the merger, the officers who, by virtue of the agreement, had the option of monetizing their right over 2,985,000 PEPASA’ shares, have a post-merger option to monetize its right over a total of 6,775,652 Pampa’s shares at a U$S 0.0764 per share price.

On October 7, 2019, the officers agreed to terminate the aforementioned monetization option and as a result, the Company paid on October 11, 2019 a cash amount equivalent to the quoted value of such shares.

19.2 Stock-based Compensation Plan – Certain officers and other key staff (the “Compensation Plan”)

On February 8, 2017, the Company’s Board of Directors approved the creation of a stock-based compensation plan and the first Specific Program, whereby certain officers and other key staff covered by each Specific Program will receive a certain number of company shares within the stipulated term aiming to encourage the alignment of the employees performance with the Company’s strategy and to generate a clear and direct link between the creation of value for shareholders and the employees’ compensation.

Furthermore, the Company’s Board of Directors approved the acquisition of own shares in the market as a means of implementing the Plan (see Note 13.1.1.3).

On April 7, 2017, the Company's Shareholders’ Meeting ratified the approval of the Compensation Plan by the Board of Directors, as well as its terms and conditions; and approved the cancellation of the preferential offer to shareholders in respect to the disposition of such shares as authorized by Section 67 of Capital Markets' Act No. 26,831 for the purposes of implementing such Plan.

F-189

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 19: (Continuation)

The number of shares is calculated based on 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, provided the employment relationship continues at least as at each vesting date.

As of December 31, 2019, the Company has estimated a total quantity of 2,082,165 treasury shares pursuant to Compensation Plan to be delivered to employees 661,802, 668,626, 481,450 and 270,287 during 2020, 2021, 2022 and 2023, respectively.

As of December 31, 2019, the Company has acquired 717,750 treasury shares and 191,290 treasury ADRs, 290,363 and 173,891 of which were destined to officers’ compensation during 2019 and 2018, respectively.

19.3 Compensation agreements - Senior Management

On June 2, 2017, the Board of Directors approved the execution and signing of compensation agreements with the Company’s main officers (the “Senior Management”), conditional upon their approval by the Annual Ordinary Meeting of Shareholders to be held each year.

In accordance with international practices, the purpose of these agreements is to efficiently align the Senior Management’s interests with those of the Company and its shareholders, creating value for them only inasmuch as value is generated for shareholders, that is, if the Company’s market value increases.

Under these agreements, the Senior Management will be entitled to a fixed compensation and an annual, variable and contingent long-term compensation related to the Company’s annual market value appreciation, with a cap on the Company’s operating income.

With the purpose of avoiding duplication, any analogous compensation that the Senior Management had received from any of the Company’s subsidiaries, will be deducted from the compensation amount in proportion to the Company’s interests in such subsidiaries.

F-190

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 19: (Continuation)

19.4 Share-based Compensation Plan of Edenor

In 2016, Edenor’s Board of Directors proposed that the treasury shares be used for the implementation of a long-term incentive plan in favor of executive directors, managers or other personnel holding key executive positions in Edenor in an employment relationship with the latter and those who in the future are invited to participate, in accordance with the provisions of section 67 of Law No. 26,831 on Capital Markets. The plan was ratified and approved by the ordinary and extraordinary shareholders’ meeting held on April 18, 2017.

The fair value of the previously referred to shares at the award date, amounted to $ 75.9 million and has been recorded in the Salaries and social security taxes line item, with a contra account in Equity. The amount recorded in Equity is net of the tax effect.

NOTE 20: CONTRACTUAL RESOLUTION OF REAL ESTATE ASSET

With regard to the real estate asset to be constructed, acquired by Edenor in November 2015, the subsequent termination of the agreement due to RDSA’s default in August 2018, and the respective legal actions brought by Edenor against the seller and the insurance company. On September 30, 2019, Edenor entered into a settlement agreement pursuant to which Edenor receives from the insurer as sole, full and final compensation of U$S 15 million and the assignment in its favor of the insurer’s right to subrogate to the insured’s rights for the amount paid against the policyholder (RDSA).

As of December 31, 2019, Edenor has collected of U$S 14 million. The remaining balance will be collected in 6 quarterly installments, the first of them on April 21, 2020.

Furthermore, the claim duly filed by Edenor with the Arbitral Tribunal of the BCBA against RDSA in order to obtain the refund of price paid for the undelivered real property was suspended so that the claim can be allowed in RDSA’s insolvency proceedings, such claim was allowed by the court hearing the case for the sum of U$S 35 million. Additionally, a review incident was initiated for the amount that was declared inadmissible in the verifying resolution, for an additional amount of $ 895.7 million.

F-191

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 21: DOCUMENTATION KEEPING

On August 14, 2014, the National Securities Commission 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 and its subsidiary Edenor, 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, Provincia de 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.

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, 2019.

	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	8,804	10,534	4,746	10,168	13,550	20,702
Total at 12.31.2019	8,804	10,534	4,746	10,168	13,550	20,702

⁽¹⁾ In thousands of barrels.

⁽²⁾In millions of cubic meters.

F-192

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 23: SUBSEQUENT EVENTS

23.1 New Remuneration scheme at the Spot market for the generation segment

On February 27, 2020, SE Resolution No. 31/20 was published in the Official Gazette, superseding the remuneration scheme established by SRRYME Resolution No. 1/19.

The new scheme reduces prices ​​of the remuneration for available power capacity, and furthermore transfers the remuneration prices ​​to Argentine pesos by applying a 60 $/U$S exchange rate. However, it establishes that prices will be monthly updated through a factor contemplating a 60% adjustment by IPC and a 40% adjustment by IPIM.

Furthermore, it establishes an additional remuneration for the power generated in those hours of maximum thermal requirement of the month. In the case of thermal generators, the average generated power will be considered, and in the case of hydroelectric generators, the average operated power will be considered.

Finally, it maintains prices of the remuneration for generated and operated energy.

Resolution SE No. 31/20 amendments with an impact on the Company's remuneration scheme are detailed below:

23.1.1Remuneration for Available Power Capacity

23.1.1.1 Thermal Power Generators

The Resolution maintains in effect a remuneration made up of a minimum or base power capacity payment for generators with no availability commitments, and another for offered guaranteed power capacity.

Prices of 360 thousand and 270 thousand $/MW-month were established as remuneration for guaranteed power capacity for the summer-winter and autumn-spring periods, respectively, implying a 14% and 18% decreases for the summer-winter and autumn-spring periods, respectively for enabled generators, except for Internal Combustion Engines with capacity less than or equal to 42 MW, for which prices were established at 420 thousand and 330 thousand $/MW-month for the summer-winter and autumn-spring periods, respectively.

On the other hand, it establishes an additional remuneration for power generated in the hours of high thermal requirement of the month (hmrt), which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, with prices of 45 thousand and 22.5 thousand $/MW-hmrt for the first and second 25 hmrt block, respectively for the summer-winter periods and 7.5 thousand $/MW-hmrt only for the first 25 hmrt block for the autumn-spring periods.

Like SRRYME Resolution No. 1/19, Resolution SE No. 31/20, applies a coefficient derived from the unit’s average utilization factor during the last twelve months to the power capacity remuneration. Although it maintains the formula Resolution SRRYME 1/19 scheme, in case if the usage factor is lower than 30%, it establishes a 60% of the power capacity payment will be collected, except for Internal Combustion Engines with capacity less than or equal to 42 MW, that will collect 70% of the power capacity payment.

F-193

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 23: (Continuation)

23.1.1.2 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 at all hours within the period is considered to calculate availability.

The base remuneration is determined by the actual power capacity plus that under programmed and/or agreed maintenance, with prices ranging from 132,000 to 297,000 $/MW-month, depending on the scale and type of power plant, that considering the elimination of the additional remuneration set by SRRYME Resolution No. 1/19, implied a 45% and 12% decrease for conventional and pumping hydroelectric power plants, respectively. It should be noted that, in order to mitigate the incidence of plants’ programmed maintenance, and as a signal for their optimization, a 1.05 factor will be applied to power capacity prices.

In case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor will be applied to the plant at the headwaters.

On the other hand, it establishes an additional remuneration for power operated in the hours of high thermal requirement of the month, with a price of 32.5 thousand $/MW-hmrt applying a 1.2 and 0.6 factor for the first and second 25 hmrt block, respectively, for the summer-winter periods and 0.2 factor only for the first 25 hmrt block for the autumn-spring periods.

23.1.1.3 Wind power

No remuneration related to power capacity availability is set, establishing a single remuneration value for generated energy (see next item).

23.1.2 Remuneration for Generated and Operated Energy

It establishes a remuneration for Generated Energy with prices ranging between 240 and 420 $/MWh, depending on the type of fuel and a remuneration for Operated Energy applicable to the integration of hourly power capacities for the period, with an 84 $/MWh price for any type of fuel, thus maintaining prices established by SRRYME Resolution No. 1/19.

It should be noted that, in the event that the generation unit is dispatched outside the optimal dispatch, remuneration for generated energy will be set at 60% of the net installed power capacity, regardless of the energy delivered by the generation unit.

In the case of hydroelectric plants, prices for Energy Generated and Operated under Resolution SE No. 31/20 are remunerated at 210 $/MWh and 84 $/ MWh, respectively, maintaining prices ​​established by SRRYME Resolution No. 1/19. The remuneration for operated energy must correspond to the optimal dispatch of the system, however, the resolution does not indicate what the consequence would be otherwise.

F-194

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017 (Continuation)

(in millions of U$S– unless otherwise stated)

NOTE 23: (Continuation)

In the case of hydroelectric pumping plants, both the energy generated and the one consumed for pumping, by the energy pumped, and the energy operated are considered. In addition, if it functions as a synchronous compensator, 60 $/MVAr will be recognized for the megavolt exchanged with the network when required and 84 $/MWh for the energy operated.

As regards energy generated from unconventional sources, Resolution SE No. 31/20 establishes a single remuneration value of 1,680 $/MWh, irrespective of the source used, maintaining the value established by SRRYME Resolution No. 1/19. Energy generated prior to the commissioning by the OED will be remunerated at 50% of the above-mentioned remuneration.

23.2 Buyback of own shares

After the closing of the year, the Company acquired the equivalent of 52,241,300 own shares for an approximate value of U$S 27 million corresponding to the Buyback Program mentioned in Note 13.1.1.2.

23.3 Stock-based compensation plan

During January 2020, the Company delivered the equivalent of 163,466 own shares as payment under the stock-based compensation plan to officers and other key staff.

F-195

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

To the Board of Directors and Shareholders of

Transportadora de Gas del Sur S.A.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of financial position of Transportadora de Gas del Sur S.A. and its subsidiaries (together the “Company”) as of December 31, 2019 and 2018, 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, 2019, and the related notes (collectively referred to as the “consolidated financial statements”).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States of America) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated April 29, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit.  We are a public accounting firms registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.  Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.  Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.  We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

F-196

 

Impairment of long-lived assets related to Property, Plant & Equipment

At December 31, 2019, the Company’s book value of Property, Plant & Equipment (“PPE”) was Argentine Pesos 74,552.7 million. As discussed in Note 5 (c) to the consolidated financial statements, PPE is tested for impairment when an existing event or one that will take place in the near future indicates that the recoverable value of the PPE amounts may be affected. An asset’s recoverable amount is the higher of the fair value less costs to sell that asset, and its value-in-use. The value in use is calculated based on discounted future cash flows, which are prepared for each cash generating unit considering, among others, significant assumptions relating to projections of liquified petroleum gas prices, purchase cost of natural gas, future tariff adjustments based on negotiations, future expectation of the need of Vaca Muerta fields gas producers to evacuate untreated natural gas, discount rates and expected future macroeconomic variables such as inflation and foreign exchange rates.

The principal considerations for our determination that performing procedures relating to the impairment of long-lived assets related to PPE is a critical audit matter are there was significant judgment by management in estimating the value in use of the cash generating unit. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures to evaluate the significant assumptions in the value in use estimate, including projections of liquified petroleum gas prices, purchase cost of natural gas, future tariff adjustments, future expectation of the need of Vaca Muerta fields gas producers to evacuate untreated natural gas, discount rate and expected future macroeconomic variables such as inflation and foreign exchange rates. In addition, the audit effort involved professionals with specialized skill and knowledge to assist in performing the audit 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 audit procedures included obtaining an understanding, evaluating the design and testing the operating effectiveness of controls over the management’s impairment review process, including controls over the review of the significant assumptions.  These audit procedures also included, among others, evaluating the estimation methodology and testing the aforementioned significant assumptions and the completeness, accuracy, and relevance of underlying data used. The significant assumptions were compared to current available economic trends data and known regulatory changes and evaluations were made of how changes to such assumptions, and other factors would affect the outcomes.  It was also assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the value in use that would result from changes in the assumptions; the arithmetical correctness of the discounted cash flows model and the completeness of disclosures in the consolidated financial statements. Professionals with specialized skill and knowledge were used to assist in the evaluation of the methodology and the significant assumptions used in the future cash flows estimated by management.

/s/ Price Waterhouse & Co. S.R.L.	/s/ Pistrelli, Henry Martin y Asociados S.R.L
	PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L
/s/Fernando Alberto Rodriguez	Member of Ernst & Young Global

Price Waterhouse & Co. S.R.L (“PwC”) has served as the Company’s sole auditor since 2012. PwC and Pistrelli, Henry Martin y Asociados S.R.L have served as the Company’s joint auditors since 2017.

Buenos Aires, Argentina

April 29, 2020

F-197

 

TRANSPORTADORA DE GAS DEL SUR S.A.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(Stated in thousands of pesos as described in Note 3 and 4.d. except for share and per share information)

	Notes		2019			2018			2017
Revenues		8.h.		48,561,494			52,399,423			30,694,588
Cost of sales		8.i.		(24,375,503	)		(24,902,866	)		(18,360,946	)
Gross profit				24,185,991			27,496,557			12,333,642
Administrative expenses		8.j.		(1,260,300	)		(1,479,580	)		(1,128,936	)
Selling expenses		8.j.		(3,039,557	)		(2,714,682	)		(1,241,883	)
Other operating expenses		8.l.		(127,526	)		(1,370,319	)		(417,803	)
Operating profit				19,758,608			21,931,976			9,545,020
Net financial results
Financial income		8.k.		8,535,154			14,628,724			1,068,656
Financial expenses		8.k.		(17,700,134	)		(22,763,300	)		(3,020,602	)
Other financial results		8.k.		113,387			1,900,589			422,363
Gain on net monetary position		8.k.		6,154,172			1,855,519			716,821
Total				(2,897,421	)		(4,378,468	)		(812,762	)
Share of (loss) / profit from associates		11		(31,858	)		28,008			33,291
Net income before income tax				16,829,329			17,581,516			8,765,549
Income tax (expense) / benefit		14		(4,024,211	)		(20,261	)		81,650
Total comprehensive income for the year				12,805,118			17,561,255			8,847,199
Total comprehensive income attributable to:
Owners of the Company				12,805,105			17,561,249			8,847,196
Non-controlling interests				13			6			3
				12,805,118			17,561,255			8,847,199
Weighted average of outstanding ordinary shares *				776,121,341			788,405,563			794,495,283
Basic and diluted earnings per share				16.50			22.27			11.14

*The weighted average of the number of shares considers the effect of the weighted average of the changes originated in the transactions with treasury shares made during the year.

The accompanying notes are an integral part of these consolidated financial statements.

F-198

 

TRANSPORTADORA DE GAS DEL SUR S.A.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS OF DECEMBER 31, 2019 AND 2018

(Stated in thousands of pesos as described in Note 3 and 4.d.)

	Notes		2019			2018
ASSETS
Non-current assets
Property, plant and equipment		12		74,552,728			59,510,863
Investments in associates		9		78,660			111,790
Other financial assets at amortised cost		8.m.		5,403			13,476
Deferred income tax asset		14		15,600			6,967
Other receivables		8.a.		9,004			12,665
Total non-current assets				74,661,395			59,655,761
Current assets
Other receivables		8.a.		2,898,077			4,096,646
Inventories				307,640			554,218
Trade receivables		8.b.		6,473,759			4,791,109
Contract assets				177,269			241,012
Derivative financial instruments				274,024			335,773
Other financial assets at amortised cost		8.m.		1,043,960			8,790
Cash and cash equivalents		8.c.		9,765,201			25,605,137
Total current assets				20,939,930			35,632,685
Total Assets				95,601,325			95,288,446
EQUITY
Common stock				28,349,861			28,224,365
Treasury shares				366,086			491,582
Cost of adquisition of treasury shares				(730,764	)		(2,185,845	)
Additional paid-up capital				(791,712	)		-
Legal reserve				1,922,444			1,000,251
Future capital expenditures reserve				-			107,453
Future dividends reserve				-			1,525,444
Reserve for capital expenditures, acquisition of treasury shares and/or dividends				5,351,123			-
Accumulated retained earnings				13,616,403			18,440,641
Non-controlling interests				28			15
Total equity				48,083,469			47,603,906
LIABILITES
Non-current liabilities
Deferred tax liabilities		14		4,778,114			3,427,531
Contract liabilities		8.d.		2,926,826			2,259,876
Loans		13		31,860,717			31,003,715
Total non-current liabilities				39,565,657			36,691,122
Current liabilities
Provisions		15		589,118			570,977
Contract liabilities		8.d.		219,801			199,333
Other payables		8.e.		287,659			124,103
Taxes payables		8.f.		353,183			311,083
Income tax payable				18,329			3,759,987
Payroll and social security taxes payable		8.n.		648,451			590,156
Loans		13		1,722,087			681,225
Trade payables		8.g.		4,113,571			4,756,554
Total current liabilities				7,952,199			10,993,418
Total liabilities				47,517,856			47,684,540
Total equity and liabilities				95,601,325			95,288,446

The accompanying notes are an integral part of these consolidated financial statements.

F-199

 

TRANSPORTADORA DE GAS DEL SUR S.A.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(Stated in thousands of pesos as described in Note 3 and 4.d.)

		Shareholders Contributions																					Retained Earnings
		Outstanding shares						Treasury shares																						Reserve for
	Common stock			Inflation adjustment to common stock			Common stock (1)			Inflation adjustment to common stock (1)			Acquisition cost of treasury shares (1)			Additional paid-up capital (1)			Total common stock			Legal reserve		Future dividends Reserve			Future capital expenditures reserve			capital expenditures, acquisition of treasury shares and/or dividends			Accumulated retained earnings			Subtotal			Total			Non-Controlling interests		Total
Balances at December 31, 2016*		794,495			27,921,452			-			-			-			-			28,715,947			944,177		31,414			115,648			-			233,799			1,325,038			30,040,985			26		30,041,011
Resolutions of the Ordinary and Extraordinay Shareholders´
Meeting held on April 26,  2017
- Legal reserve		-			-			-			-			-			-			-			56,074		-			-			-			(56,074	)		-			-			-		-
- Future dividends reserve		-			-			-			-			-			-			-			-		2,364,126			-			-			(2,364,126	)		-			-			-		-
- Derecognition of reserves		-			-			-			-			-			-			-			-		-			(8,195	)		-			8,195			-			-			-		-
																																					-			-
Dividends payment to non-controlling interest		-			-			-			-			-			-			-			-		-			-			-			-			-			-			(11	)	(11	)
Comprehensive income for the year		-			-			-			-			-			-			-			-		-			-			-			8,847,196			8,847,196			8,847,196			3		8,847,199
Balances at December 31, 2017 *		794,495			27,921,452			-			-			-			-			28,715,947			1,000,251		2,395,540			107,453			-			6,668,990			10,172,234			38,888,181			18		38,888,199
Resolutions of the Ordinary and Extraordinay Shareholders´
Meeting held on April 10, 2018
- Future Dividends reserve		-			-			-			-			-			-			-			-		5,789,598			-			-			(5,789,598	)		-			-			-		-
Cash dividends distribution		-			-			-			-			-			-			-			-		(6,659,694	)		-			-			-			(6,659,694	)		(6,659,694	)		-		(6,659,694	)
Treasury shares purchase		(13,601	)		(477,981	)		13,601			477,981			(2,185,845	)		-			(2,185,845	)		-		-			-			-			-			-			(2,185,845	)		-		(2,185,845	)
Cash dividends distribution to non-controlling interest		-			-			-			-			-			-			-			-		-			-			-			-			-			-			(9	)	(9	)
Comprehensive income for the year		-			-			-			-			-			-			-			-		-			-						17,561,249			17,561,249			17,561,249			6		17,561,255
Balances at December 31, 2018		780,894			27,443,471			13,601			477,981			(2,185,845	)		-			26,530,102			1,000,251		1,525,444			107,453			-			18,440,641			21,073,789			47,603,891			15		47,603,906
Resolutions of the Ordinary Shareholders
Meeting held on April 11, 2019
Legal Reserve		-			-			-			-			-			-			-			922,193		-			-			-			(922,193	)		-			-			-		-
Dividends payment (2)		-			-			-			-			-			-			-			-		-			-			-			(9,185,852	)		(9,185,852	)		(9,185,852	)		-		(9,185,852	)
Reserve for capital expenditures, acquisition of treasury shares and/or dividends		-			-			-			-			-			-			-			-		-			-			9,154,195			(9,154,195	)		-			-			-		-
Derecognition of reserves		-			-			-			-			-			-			-			-		(1,525,444	)		(107,453	)		-			1,632,897			-			-			-		-
Treasury shares distribution (2)		29,445			860,761			(29,445	)		(860,761	)		4,045,739			(791,712	)		3,254,027			-		-			-			(3,228,002	)		-			(3,228,002	)		26,025			-		26,025
Dividends payment (2)		-			-			-			-			-			-			-			-		-			-			(575,070	)		-			(575,070	)		(575,070	)		-		(575,070	)
Treasury shares purchase		(25,731	)		(738,979	)		25,731			738,979			(2,590,658	)		-			(2,590,658	)		-		-			-			-			-			-			(2,590,658	)		-		(2,590,658	)
Comprehensive income for the year		-			-			-			-			-			-			-			-		-			-			-			12,805,105			12,805,105			12,805,105			13		12,805,118
Balances at December 31, 2019		784,608			27,565,253			9,887			356,199			(730,764	)		(791,712	)		27,193,471			1,922,444		-			-			5,351,123			13,616,403			20,889,970			48,083,441			28		48,083,469

* The Company has applied IFRS 15 and IFRS 9 for the first time on January 1, 2018. In accordance with the transition methods chosen, the comparative information has not been modified. See Note 4.a)

⁽¹⁾ As of December 31, 2019 and 2018 corresponds to 9,886,755 and 13,600,780 shares of par value Ps. 1 each, equivalent to 1.24% and 1,71% of the share capital, respectively. The acquisition cost of these shares amounted to Ps. 730,764 and 2,185,845, respectively. See Note 19.b) to the consolidated financial statements.

⁽²⁾ See Note 19.c).

The accompanying notes are an integral part of these consolidated financial statements.

F-200

 

TRANSPORTADORA DE GAS DEL SUR S.A.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(Stated in thousands of pesos as described in Note 3 and 4.d.)

	2019			2018			2017
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
Total comprehensive income for the year		12,805,118			17,561,255			8,847,199
Reconciliation of total comprehensive income to cash flows provided by operating activities:
Depreciation of property, plant and equipment		3,695,615			3,419,820			3,107,746
Derivative financial instrument results		19,172			(163,192	)		-
Disposal of property, plant and equipment		100,858			243,851			202,165
Share of profit / (loss) from associates		31,858			(28,008	)		(33,291	)
Increase in provisions		266,775			299,656			333,693
Interest expense accrual, net		1,908,169			2,444,361			1,120,891
Interest income on other financial assets other than cash and cash equivalents		(100,489	)		(694,566	)		(147,228	)
Income tax		4,024,211			20,261			(81,650	)
Doubtful accounts		2,435			203,860			(35,989	)
Foreign exchange loss, net		8,887,732			8,734,823			730,004
Gain on net monetary position		(6,606,675	)		(5,926,962	)		(1,332,478	)
Changes in assets and liabilities:
Trade receivables		(3,733,961	)		(2,286,449	)		(2,158,024	)
Other receivables		(1,838,443	)		(1,205,780	)		(576,187	)
Inventories		52,634			(362,774	)		14,996
Trade payables		140,873			2,479,008			554,773
Contract assets		(20,597	)		(241,012	)		-
Payroll and social security taxes		264,815			228,332			150,694
Taxes payables		(132,169	)		76,873			16,798
Other payables		206,985			72,497			67,528
Provisions		(7,590	)		1,211			(392,054	)
Interest paid		(2,039,877	)		(1,393,331	)		(464,817	)
Derivative financial instruments		21,929			(159,661	)		-
Income tax paid		(4,881,195	)		(4,273,266	)		(1,282,282	)
Contract liabilities		430,781			634,525			-
Advances from customers		-			-			(94,376	)
Cash flows provided by operating activities		13,498,964			19,685,332			8,548,111
CASH FLOWS USED IN INVESTING ACTIVITIES
Additions to property, plant and equipment		(15,932,000	)		(12,496,827	)		(2,986,295	)
Financial assets not considered cash equivalents		(711,899	)		5,218,620			(2,978,848	)
Cash flows used in investing activities		(16,643,899	)		(7,278,207	)		(5,965,143	)
CASH FLOWS (USED IN) / PROVIDED BY FINANCING ACTIVITIES
Payment of loans		-			(1,886,079	)		(92,109	)
Precancellation of loans		-			(7,378,176	)		-
Payment of leases		(18,751	)		-			-
Loans receive		1,051,809			21,261,978			-
Payment of acquisition of treasury shares		(2,590,658	)		(2,185,845	)		-
Dividends paid		(9,760,922	)		(6,659,694	)		(9	)
Cash flows (used in) / provided by financing activities		(11,318,522	)		3,152,184			(92,118	)
NET (DECREASE) / INCREASE IN CASH AND CASH EQUIVALENTS		(14,463,457	)		15,559,309			2,490,850
Cash and cash equivalents at the beginning of the year		25,605,137			6,025,226			4,415,596
Foreign exchange gain on Cash and cash equivalents		3,721,043			10,287,800			346,132
Monetary results effect on Cash and cash equivalents		(5,097,522	)		(6,267,198	)		(1,227,352	)
Cash and cash equivalents at the end of the year		9,765,201			25,605,137			6,025,226

The accompanying notes are an integral part of these consolidated financial statements.

For further information, see Note 6.

F-201

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

1. BUSINESS DESCRIPTION

Business Overview

Transportadora de Gas del Sur S.A. (“TGS” or the “Company”) is one of the companies created as a result of the privatization of Gas del Estado S.E. (“GdE”). TGS commenced operations on December 29, 1992 and it is mainly engaged in the Transportation of Natural Gas, and Production and Commercialization of natural gas Liquids (“Liquids”). TGS’s pipeline system connects major natural gas fields in southern and western Argentina with natural gas distributors and industries in those areas and in the greater Buenos Aires area. The natural gas transportation license to operate this system was exclusively granted to TGS for a period of thirty-five years (“the License”). TGS is entitled to a one-time extension of ten years provided that it has essentially met the obligations imposed by the License and by the Ente Nacional Regulador del Gas (National Gas Regulatory Body or “ENARGAS”). The General Cerri Gas Processing Complex (the “Cerri Complex”), where TGS processes natural gas by extracting liquids, was transferred from GdE along with the gas transmission assets. TGS also provides midstream services, which mainly consist of gas treatment, removal of impurities from the natural gas stream, gas compression, wellhead gas gathering and pipeline construction, operation and maintenance services. Also, telecommunications services are provided through the subsidiary Telcosur S.A. (“Telcosur”). These services consist of data transmission services through a network of digital terrestrial radio relay.

Subsequently, the corporate purpose of the Company was modified to incorporate the development of complementary activities, incidental, linked and / or derived from natural gas transportation, such as the generation and commercialization of electric power and the provision of other services for the hydrocarbon sector in general.

Major Shareholders

TGS’s controlling shareholder is Compañía de Inversiones de Energía S.A. (“CIESA”), which holds 51% of the common stock. Local and foreign investors hold the remaining ownership of TGS’s common stock. CIESA is under co-control of: (i) Pampa Energía S.A. (“Pampa Energía”), which holds 10% of CIESA’s common stock, (ii) CIESA Trust (whose trustee is Pampa Energía and whose beneficiary is PHA SAU, a wholly owned subsidiary of by Pampa Energía) (the “Trust”), who has a trust shareholding of 40% of the share capital of CIESA and (iii) Grupo Inversor Petroquímica S.L. (member of GIP Group, headed by Sielecki´s family; “GIP”), and PCT L.L.C. (“PCT”), which directly and together with WST S.A. (Member of Werthein Group, “WST”) indirectly through PEPCA S.A. (“PEPCA”), hold a 50% of the shareholding in CIESA in the following shares: GIP 27.10%, WST 4.58% and PCT 18.32%.

Macroeconomic context

The Company operates in an economic context whose main variables have recently had strong volatility as a result of political and economic events both nationally and internationally.

In the domestic market, particularly, the shares of the main contributing companies, sovereign bonds and the Argentine peso experienced a sharp drop in their value.

F-202

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

In this context and after the mandate of President Alberto Fernández began, on December 23, 2019, the National Congress passed Law No. 27,541 - “Law of social solidarity and productive reactivation” (the “Solidarity Law”). This law, based on the public emergency, grants the Executive Branch broad legislative powers to create the necessary conditions for economic recovery and achieve fiscal sustainability.

Among the measures adopted by this law are, among others:

1. Provisions regarding sovereign debt through which the Executive Branch is empowered to carry out the negotiations and make the necessary decisions to achieve the renegotiation of the Argentine public debt.

2. Freezing and tariff review of transportation and distribution services of natural gas and electric power (for more information, see Note 17.a).

3. Establishment of a cap on the export rights of hydrocarbons (for more information see Note 17.b).

4. Establishment of a regime of regularization of tax, social security and customs obligations.

5. Tax modifications concerning taxes on: personal property, financial income, income (for more information, see Note 14 and 19.c), on bank and internal credits and debits.

6. Creation of the Tax for an Inclusive and Solidarity Argentina that taxes foreign currency acquisition operations for treasury, acquisition of goods and services and tourism.

7. Modifications to customs taxes.

The Company’s Management permanently monitors the evolution of the situations that affect its business, in order to determine the possible actions to be taken and identify the possible impact financial situation and results of its operation. The financial statements of the Company must be read considering these circumstances.

2. CONSOLIDATED FINANCIAL STATEMENTS

TGS presents its consolidated financial statements including Telcosur S.A. (“Telcosur”) and CTG Energía S.A. (“CTG”), its consolidated subsidiaries, which are jointly referred to as “the Company”.

3. BASIS OF PRESENTATION

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards issued by the International Accounting Standards Board (“IASB”) and the International Financial Interpretations Committee (“IFRIC”), jointly the “IFRS”.

F-203

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The preparation of the consolidated financial statements in conformity with IFRS requires management to make accounting estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses during the reporting fiscal year. Estimates are used when accounting for the allowance for doubtful accounts, income taxes, provisions for legal claims and others, depreciation and recoverable value of assets. Actual results could be significantly different from such estimates.

The presentation in the statement of financial position distinguishes between current and non-current assets and liabilities. The assets and liabilities are those expected to be realized or settled within twelve months after the end of the reporting period under review, and those held for sale. The fiscal year begins on January 1 and ends on December 31 of each year. The economic and financial results are presented on a fiscal year basis.

The consolidated financial statements are stated in thousands of Argentine pesos (“Ps.” or “pesos”), which is the functional currency of the Company and its subsidiaries, unless otherwise stated. For further information, see Note 4.c.

4. SIGNIFICANT ACCOUNTING POLICIES

a) New accounting standards

New standards and interpretations issued by the IASB effective for the periods beginning on or after January 1, 2019 adopted by the Company

IFRS 16 – “Leases”

The Company has adopted IFRS 16 under the modified retrospective approach, from January 1, 2019, and accordingly has not modified comparatives for the 2018 and 2017 reporting periods as permitted under the specific transition provisions in the standard.

After the analysis performed by Management, no significant adjustments were made to the accumulated results or significant reclassifications were made.

Practical expedients applied

In applying IFRS 16 for the first time, the Company has used the following practical expedients permitted by the standard:

• Accounting for operating leases with a remaining lease term of less than 12 months as at January 1, 2019 as short-term leases.

• The Company has elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date (January 1, 2019), the Company relied on its assessment made applying IAS 17 – Leases and IFRIC 4 – Determining whether an arrangement contains a lease.

• This standard does not apply for those leases classified as low value contracts.

F-204

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Accounting policies applied

Until the year ended December 31, 2018, by application of IAS 17 and IFRIC 4, leases of property, plant and equipment were classified as financial leases (only if substantially all the risks and benefits of ownership of leased asset were assumed by the Company) or operating leases. Payments made under operating leases were charged to the Statement of Comprehensive Income in a straight line over the period of the lease.

As from January 1, 2019, leases are recognized as a right of use asset and a corresponding liability at the date at which the leased asset is available for use by the Company. Each lease payment is allocated between principal and finance cost. The finance cost is charged to profit or loss over the lease period so as to produce a constant periodic interest rate on the remaining balance of the liability for each period.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

a) Fixed payments less any lease incentive receivable;

b) Variable lease payments that depend on an index;

c) Amounts expected to be payable by the Company under residual value guarantees;

d) The exercise price of a purchase option; and

e) Payments of penalties for terminating the lease.

As of December 31, 2019, the Company has not recognized any lease liability including variable payments.

The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the Company’s incremental borrowing rate is used, being the rate that TGS would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment.

Right-of-use assets are measured at cost comprising the following:

a) The amount of the initial measurement of lease liability.

b) Any lease payment made at or before the commencement date less any lease incentives received.

c) Any initial direct cost, and

d) Restoration costs.

Leased assets, which are subject to the risk of impairment, are depreciated in a straight line over the shorter of the asset’s useful life and the lease term.

Payments associated with short-term leases and leases of low-value assets are recognized on a straight-line base as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets comprise IT-equipment, vehicles, small items of office furniture and rented offices.

The Company recognized right-of-use assets under the line item “Property, plant and equipment” of its balance sheet (see Note 12). The corresponding liability has been recognized under current and non-current Loans (see Note 13). For more information regarding the expense related to short-term and low-value leases and the interest expense of lease liabilities, see Note 8.j) and 8.k), respectively.

F-205

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

In addition to the aforementioned, on January 1, 2019, the following standards and interpretations, described in the consolidated financial statements as of December 31, 2018, were adopted without having a significant impact on the Company’s financial statements:

• IFRIC Interpretation 23 “Uncertainty over income tax treatments.”

• Annual improvements to IFRS Standards 2015 – 2017 Cycle.

• Amendments to IFRS 9 – Financial instruments.

New standards and interpretations issued by the IASB not yet effective for the period beginning on or after January 1, 2019

Below is a description of the standards, amendments and interpretations to existing standards that might impact the Company and are not mandatory for the Company’s fiscal years beginning on January 1, 2019 and which have not been early adopted by the Company:

Amendments to IAS 1 and IAS 8 regarding the definition of materiality

In October 2018 the IASB included certain amendments to IAS 1 “Presentation of financial statements” and IAS 8 “Accounting policies, changes in accounting estimates and errors” with the objective of clarifying the concept of materiality and aligning that definition with the amendments introduced in the Conceptual Framework.

Additionally, these amendments incorporate new concepts that helped both financial statement preparers and their users to prepare and interpret the financial information included in them.

These amendments are applied on prospective basis and are effective for annual periods beginning on or after January 1, 2020. Modifications to the concept of materiality are not expected to have a significant impact on the Company’s financial statements.

b) Consolidation

Subsidiaries

Subsidiaries are all entities over which the Company has control. The Company controls an entity when the Company is exposed to, or has rights to, variable returns from its involvement and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated from the date that control ceases. For this purpose and unless there are specific requirements, it is generally considered that TGS has control, when it has a participation equal to or greater than 50% of the available voting rights.

The accounting policies of the subsidiaries are consistent with the accounting policies adopted by the Company.

F-206

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Inter-company transactions, balances and gain/losses from transactions between group companies are eliminated. Unrealized gain/losses are also eliminated.

Detailed data reflecting subsidiary control as of December 31, 2019 and 2018 is as follows:

Company	% of shareholding and votes	Country	Closing date	Main activity
Telcosur	99.98	Argentina	December 31	Telecommunication Services
CTG (1)	100.00	Argentina	December 31	Electricity related services

⁽¹⁾ 100% of the shares of this company were acquired on August 8, 2017. At present, it is in the process of being transformed into S.A.U.

For consolidation purposes for the year ended December 31, 2019 and 2018, the financial statements of Telcosur have been used at those dates. The subsidiary CTG does not record operations or significant assets and liabilities as of December 31, 2019 and 2018.

Associates

Associates are entities over which the group has significant influence but not control, generally accompanying a shareholding of between 20% and 50% of the voting rights. Investments in associates are accounted for using the equity method of accounting. Under the equity method, the investment is initially recognized at cost, and the carrying amount is increased or decreased to recognize the investor’s share of the profit or loss of the investee after the date of acquisition.

The Company accounted for the investments in its associates, under the equity method on the basis on the financial statements as of September 30, 2019 of Gas Link S.A. (“Link”), Transporte y Servicios de Gas en Uruguay SA (“TGU”) and Emprendimientos de Gas del Sur S.A. (“EGS”), under liquidation. Accounting policies of associates have been changed where necessary to ensure consistency with the policies adopted by the Company. The Company’s management is not aware of any significant subsequent events which affected the financial statements as of September 30, 2019 of Link, TGU and EGS (in liquidation) from this date to December 31, 2019.

Associates with negative equity are disclosed under “Other liabilities” to the extent that the Company has incurred legal or constructive obligations, or made payments on behalf of the associate, as of the date of the financial statements. Unrealized gains and losses resulting from transactions between TGS and the associate or joint venture are eliminated to the extent of the interest in the associate or joint venture.

F-207

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

In the table below, associates are disclosed, together with the percentage of shareholding and voting as of December 31, 2019 and 2018:

Company	% of shareholding and voting	Country	Main activity	Closing date
TGU	49.00	Uruguay	Pipeline maintenance	December 31
EGS (“in liquidation”)	49.00	Argentina	Pipeline exploitation and construction	December 31
Link	49.00	Argentina	Pipeline exploitation and construction	December 31

Joint arrangement

As indicated in “Note 23 – Associates and Joint Arrangement”, on August 7, 2017, the Company proceeded to create a UT (similar to a joint operation) with SACDE Sociedad Argentina de Construcción y Desarrollo Estratégico S.A. (“SACDE”) (“UT”). This operation is evaluated as a joint agreement under the provisions included in “IFRS 11 - Joint Arrangements” since the parties have joint control of the operation, meaning that the decisions of the relevant activities are taken under the unanimous consent of the parties.

The Company has defined that the UT constitutes a joint operation given that it grants its participants a percentage of the rights over the assets and liabilities arising from each contract. Accordingly, the Company recognizes its share in the jointly operated assets, liabilities, revenues, costs and expenses.

Accounting policies applicable to the UT have been modified and adapted, if applicable, to ensure consistency with the policies adopted by the Company.

For further information regarding the UT, see Note 23.

c) Foreign currency translation

Functional and presentation currency

The consolidated financial statements are presented in thousands of Argentine Pesos, which is the Company’s functional currency. Each subsidiary or associate determines its own functional currency based on the currency of the primary economic environment in which these entities operate.

Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or valuation where items are remeasured. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the profit or loss for the year.

Foreign exchange gains and losses are presented in the statement of comprehensive income within financial income and financial expenses, as appropriate.

F-208

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Associates

The functional currency of the associate company located abroad, TGU, is the US dollar, because it is the currency in which it substantially generates its income and incur its expenses. Assets and liabilities were converted into Argentine pesos using the exchange rate prevailing at the end of each year, their common stock and retained earnings at their historical exchange rates and results at average exchange rates.

d) Restatement to constant currency - Comparative Information

Regulatory framework

The consolidated financial statements as of December 31, 2019, including comparative figures, have been restated to take into account changes in the general purchasing power of the Company’s functional currency (the Argentine peso) in accordance with IAS 29 “Financial Reporting in hyperinflationary economies” (“IAS 29”) and CNV General Resolution No. 777/2018. As a result, the financial statements are stated in terms of the current unit of measurement at the 2019 balance sheet date.

IAS 29 requires that the financial statements of an entity that reports in the currency of a hyperinflationary economy, regardless of whether they are based on the historical cost method or the current cost method, are expressed in terms of the current unit of measurement at the closing date of the reporting period. In order to conclude on the existence of a hyperinflationary economy, the standard details a series of factors to be considered, among which is a cumulative inflation rate over three years that approaches or exceeds 100%.

The accumulated inflation in three years is over 100%. Likewise, both the National Government projections and other available projections indicate that this trend will not be reversed in the short term.

To evaluate the aforementioned quantitative condition, and also to restate the financial statements, the CNV has established that the series of indexes to be used for the application of IAS 29 is determined by the FACPCE. This series of indexes combines the National Consumer Price Index (“CPI”) as of January 2017 (base month: December 2016) with the Domestic Wholesale Price Index (“IPIM”), both published by the Institute National Statistics and Census (“INDEC”) until that date. For the months of November and December 2015, for which there is no information from the INDEC on the evolution of the IPIM, the variation in the CPI of the Autonomous City of Buenos Aires was applied.

Considering the aforementioned index, inflation was 53.83%, 47.64% and 24.79% in the years ended December 31, 2019, 2018 and 2017 respectively.

Restatement mechanism

The financial statements must be adjusted to consider changes in the general purchasing power of the currency, so that they are expressed in the current unit of measurement at the end of the reporting period. Said requirements also include all the comparative information of the financial statements, without modifying the decisions made based on the financial information corresponding to those financial years.

F-209

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The figures as of December 31, 2018 and 2017, which are presented in these Consolidated Financial Statements for comparative purposes, arise from the restatement to the current unit of measure of the Financial Statements as of said dates, in accordance with IAS 29.

Restatement of the balance sheet

i. Monetary items (those with a fixed nominal value in local currency) are not restated, since they are already expressed in the current unit of measurement at the closing date of the reporting period. In an inflationary period, maintaining monetary assets generates loss of purchasing power and maintaining monetary liabilities generates a gain in purchasing power, provided that such items are not subject to an adjustment mechanism that compensates to some extent for these effects. The monetary loss or gain is included in the result of the period in which it is reported.

ii. The non-monetary items measured at their current values at the end of the reporting period are not restated for the purpose of their presentation in the balance sheet, but the adjustment process must be completed to determine in terms of a homogeneous unit of measurement the results produced by the holding of these non-monetary items.

iii. Non-monetary items measured at historical cost or at a fair value as of a date prior to the closing date of the reporting period are restated by coefficients that reflect the variation in the general price level from the date of acquisition or revaluation to the closing date, proceeding then to compare the restated amounts of those assets with the corresponding recoverable values.

iv. The restatement of non-monetary assets in the terms of the current unit of measurement at the end of the reporting period without an equivalent adjustment for tax purposes, results in a temporary taxable difference and the recognition of a deferred tax liability whose counterparty is recognized in the result of the period. For the closing of the subsequent period, the deferred tax items are restated for inflation to re-determine the charge to the result of the next period.

v. When the capitalization of costs for loans in non-monetary assets in accordance with IAS 23 is applicable, the portion of those costs that compensate the lender for the effects of inflation is not capitalized

Restatement of the Comprehensive Income Statement

Revenues and expenses (including interest and foreign exchange differences) are restated from the date of their booking, except for those items of the result that reflect or include in their determination the consumption of assets measured in purchasing power of a date before the consumption booked, which are restated based on the date of origin of the asset to which the item is related (for example, depreciation and other consumption of assets valued at historical cost); and also those results that arise from comparing two measurements expressed in purchasing power currency of different dates, for which it is necessary to identify the amounts compared, restate them separately, and make the comparison, but with the amounts already restated.

F-210

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The result of the exposure to the change in the purchasing power of the currency (monetary results) is presented in a separate line and reflects the effect of inflation on the monetary items.

Restatement of the statement of changes in equity

As of the transition date (January 1, 2016), the Company applied the following special rules:

i. The components of the capital stock were restated from the dates they were contributed.

ii. Reserved earnings were maintained at the date of transition at their nominal value (legal amount without restatement).

iii. The restated unallocated results were determined by the difference between the net assets restated at the transition date and the rest of the initial equity components expressed as indicated in the preceding sections.

iv. After the restatement at the transition date, all the components of the equity are restated by applying the general price index from the beginning of the period, and each variation of those components is restated from the date of contribution or from the moment in which is added by any other means.

Restatement of the statement of cash flows

IAS 29 requires that all items in this statement should be restated in terms of the current unit of measurement as of the closing date of the period for which it is reported.

The monetary result generated by cash and cash equivalents is presented in the statement of cash flows separately from cash flows from operating, investing and financing activities, as a specific item of the reconciliation between cash and cash equivalents at the beginning and at the end of the year.

e) Financial instruments

Financial assets

Recognition and initial measurement

Financial assets are classified, at the time of initial recognition, as:

ii. Financial assets subsequently measured at amortized cost, and

iii. Financial assets subsequently measured at fair value (either with changes in other comprehensive income or with changes in results).

The classification of financial assets at initial recognition depends on the financial asset’s contractual cash flow characteristics and the Company’s business model for managing them. For additional information, see Note 16.2.1.

F-211

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Subsequent measurement

After initial recognition, financial assets are measured according to their initial classification according to the following categories:

Financial assets at amortized cost

It is the most relevant category used by the Company, financial assets are classified and measure at amortized cost if both of the following conditions are met:

• The financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and

• The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Financial assets at amortized cost are subsequently measured using the effective interest method.

Gains and losses are recognized in the Statement of Comprehensive Income under financial results when the asset is derecognized, modified or impaired.

Financial assets at fair value through OCI (Debt instruments)

Corresponds to financial assets that are maintained in a business model whose objective is achieved by obtaining contractual cash flows and selling them.

Unrealized gains or losses arising from changes in fair value are recognized as other comprehensive income, except for the accrual of interest, exchange rate difference and the impairment of such assets that are recognized as financial results in the Statement of Comprehensive Income. At the time the asset is written off, the accumulated gain or loss is recognized as a financial result and it is eliminated from the respective reserve.

As of December 31, 2019 and 2018, the Company has not regonize any financial assets under this category.

Financial assets designated at fair value through OCI (equity instruments)

Upon initial recognition, the Company can elect to classify irrevocably its equity investments as equity instruments designated at fair value through OCI when they meet the definition of equity under IAS 32.

Gains and losses on these financial assets are never recycled to profit or loss. Dividends are recognized as other income in the Statement of Comprehensive Income when the right of payment has been established, except when the Company benefits from such proceeds as a recovery of part of the cost of the financial asset, in which case, such gains are recorded in OCI. Equity instruments designated at fair value through OCI are not subject to impairment assessment.

As of December 31, 2019 and 2018, the Company has not regonize any financial assets under this category.

F-212

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Financial assets at fair value through profit or loss

In the event that financial assets are not classified according to the aforementioned categories, they will be subsequently measured at fair value, presenting gains or losses arising from changes in fair value in the income statement within financial results in the year in which they are originated.

Impairment of financial assets

The Company applies the Expected Credit loss (“ECL”) model for those financial assets accounted for at amortized cost or at fair value through OCI. The ECL is based on the difference between the contractual cash flows due in accordance with the contract and the cash flows that the Company expects to receive, discounted at an approximation of the original effective interest rate. To this end, the Company evaluates various factors, including credit risk, historical trends and other available information.

The application of this model implies recognition of:

• Expected credit losses within of 12 months: these are expected credit losses that result from possible default events within 12 months after the filing date; and

• Expected credit losses during the life of the asset: these are expected credit losses that result from possible events of default during the expected life of a financial instrument.

In case a loss allowance is recognized, the carrying amount of the asset is reduced through an impairment account and the amount of the loss is presented in the Statement of Comprehensive Income at the time it occurs. Subsequent recoveries of amounts previously written off are credited in the same line item.

The impairment tests performed on accounts receivable are described in Note 4.h.

Financial liabilities

Includes trade payables, loans, other payables and certain payroll and social security taxes payable.

Recognition and initial measurement

Financial liabilities are classified, at initial recognition, as subsequently measured at amortized cost or at fair value through profit or loss, as appropriate.

All financial liabilities are recognized initially at fair value and, in case of measured at amortized cost, net of transaction costs.

They are classified in current liabilities, except those whose maturity exceeds twelve months, which are classified as non-current liabilities.

Subsequent measurement

Financial liabilities at fair value through profit or loss

Includes financial liabilities held for trading. As of December 31, 2019 and 2018, there are no instruments classified in this category.

F-213

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Financial liabilities at amortized cost

The Company includes financial liabilities with fixed or determinable payments that are not quoted in an active market. Current liabilities are included, except those whose maturity exceeds twelve months including premiums, discounts and direct expenses, which are included as non-current liabilities. They are measured using the effective interest method. As of December 31, 2019 and 2018, all of the Company’s financial liabilities were classified in this category.

Offsetting of financial instruments

Financial assets and liabilities are offset when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

f) Derivative financial instruments

Derivative financial instruments are recognized at their fair value at inception and subsequently measured at their fair value and disclosed as assets or liabilities depending if it is gain or loss. The results of derivative financial instruments are classified under “Financial gain / expenses” in the statement of comprehensive income, or in the other comprehensive income if hedge accounting is applied.

Derivative financial instruments are measured in accordance with IFRS 13 “Fair value measurement”.

The method of recognizing the resulting gain or loss depends on whether the derivative is designated as a hedging instrument or not and, according to the nature of the item being hedged.

As of December 31, 2019 and 2018, the Company maintained derivative financial instruments that are mentioned in Note 16.1.3 to these consolidated financial statements for which the application of hedge accounting has not been opted for as defined by IFRS 9.

g) Inventories

Inventories consist of natural gas (in excess of the “Line Pack”) classified as property, plant and equipment in the Company’s pipeline system, and the liquids stored obtained from natural gas processing at the Cerri Complex.

Inventories are measured at the lower of cost restated for the inflation effects as mentioned in Note 4.d. or net realizable value. Cost is determined using the weighted average cost method. The cost of inventories includes expenditure incurred in purchasing and production and other necessary costs to bring them to their existing location and condition.

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 recognized in the statement of comprehensive income when the inventories are overstated.

F-214

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

h) Trade receivables and other receivables

Trade receivables are amounts due from customers for goods and services performed in the ordinary course of business. Contract assets are unbilled amounts due to customers related to works in progress.

Trade receivables, contract assets and other receivables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, less allowance for trade receivables.

The Company applies the simplified approach to measuring expected credit losses for trade receivables, contract assets and other receivables. For this purpose, customers have been grouped based on shared credit risk characteristics, the existence of guarantees, historical credit losses experienced and the existence of judicial proceedings aimed at obtaining payment. Once each group was defined, an expected uncollectibility rate calculated based on historic default rates adjusted to future economic conditions was defined.

Impairment losses on trade receivables and contract assets are presented as net impairment losses within operating profit. Subsequent recoveries of amounts previously written off are credited against the same line item.

i) Cash and cash equivalents

Cash and cash equivalents includes cash in hand, deposits with banking institutions and other short-term, highly liquid investments with original maturities not exceeding three months and without being subject to a risk of a significant change of value.

j) Property, plant and equipment (“PPE”)

- Assets transferred from the privatization of GdE: The value of these assets was determined based on the price paid for the acquisition of 70% of the Company’s common stock, which amounted to U.S.$ 561.2 million. This price was the basis to determine a total value of common stock of U.S.$ 801.7 million, which, when added to the debt assumed under the Company’s privatization agreement (the “Transfer Agreement”) of U.S.$ 395.0 million, resulted in a total value for PPE of U.S.$ 1,196.7 million. Such value, converted at the exchange rate in effect as of the date of the Transfer Agreement, has been restated for the effects of inflation as mentioned in Note 4.d, and less accumulated depreciation.

- Line pack: It represents the natural gas in the transportation system that is necessary to keep the system at operating capacity, valued at acquisition cost and restated for the effects of inflation as mentioned in Note 4.d.

- Other items of PPE: have been valued at acquisition cost restated for the effects of inflation as mentioned in Note 4.d, and net of accumulated depreciation. They include, mainly, all the investments made to achieve system integrity and public safety equal to those required by international standards. Such investments included, among others, the costs of survey programs related to internal and external pipeline inspection, cathodic protection, pipeline replacement and recoating, and the facilities affected to the Production and Commercialization of Liquids and Other Services segment.

F-215

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

PPE additions are recorded at acquisition or construction cost less accumulated depreciation and impairment losses (if applicable), except land, which is recorded at historical cost acquisition minus any impairment (if applicable), all this restated for the effects of inflation as mentioned in Note 4.d. The cost includes the cost of replacing significant components and the borrowing costs derived from loans that finance its construction to the extent that the requirements for recognition as assets are met.

Subsequent costs restated for the effects of inflation as mentioned in Note 4.d. are included in the carrying amount of the asset or recognized as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Company and the cost of the item can be reliably measured. The carrying amount of a replaced component is written off. In the same way, when a major maintenance is carried out, they are added to the cost of the equipment if the recognition criteria are satisfied, eliminating any remaining non-depreciated remaining value restated for the effects of inflation as mentioned in Note 4.d, if any, of previous overhaul.

In this sense, Resolutions No. 1660/2000 (“Resolution 1660”) and No. 1903/2000 (“Resolution 1903”) issued by ENARGAS include definitions about the costs that should be considered as improvements or maintenance expenses. All other repairs and maintenance are charged to the statement of comprehensive income when incurred.

In accordance with IAS 23, the Company capitalizes financial expense on long term construction projects, until the moment in which the asset is in conditions for its use. Capitalization of borrowing costs is carried out considering the provisions of IAS 29, recording as an expense in the Statement of Comprehensive Income the part of the borrowing costs that compensates for inflation during the same period. For the year ended December 31, 2019, the Company capitalized Ps. 446,195 as borrowing costs. For the years ended December 31, 2018 and 2017, there have not been capitalized borrowing costs.

Depreciation related to natural gas transportation assets is computed under the straight-line method over the estimated useful lives of the specific assets, which are not exceeding the maximum useful lives established by ENARGAS through Resolutions 1660 and 1903.

For depreciation of all other PPE, the Company uses the straight-line method of depreciation based on the useful life assigned to each item.

Major maintenance costs are depreciated according to the estimated time until the next major maintenance planned. Regarding the capitalized financial costs, they are depreciated based on the remaining useful lives of those components of PPE that originated such capitalization.

The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. For further information, see Note 12.

The result generated by the disposal of PPE components is recognized in the year in which it is generated.

F-216

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

- Impairment of non-financial assets: The Company assesses at each reporting period whether there is an indication that an individual component or a group of PPE may be impaired.

If any indication exists, the Company estimates the asset´s recoverable amount. An asset´s recoverable amount is the higher of the fair value less costs to sell that asset, and its value-in-use.

That amount is determined for and individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets; in which case, the cash flows of the group of assets that form part of the cash-generating unit (“CGU”) to which the belong are taken.

Where the carrying amount of an individual asset or CGU exceeds its recoverable amount, the individual asset or CGU, as the case may be, is considered impaired and is written down to its recoverable amount. Impairment losses are recognized in the consolidated statement of comprehensive income.

In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted. To such end, the Company makes estimates and assumptions of the economic conditions that will prevail throughout the useful life of the assets.

As a result of the factors mentioned above, actual cash flows and values could vary significantly from projected cash flows and the values derived from the discounting techniques used.

Impairment losses, if any, are recognized in the statement of comprehensive income.

As of December 31, 2019 and 2018, the carrying value of PPE does not exceed their recoverable value.

Infrastructure used in the natural gas transportation service: for its measurement and disclosure, the Company has evaluated the application of Interpretation No. 12 “Service Concession Agreements” (IFRIC 12) that sets the guidelines for the accounting of private entities that provide public services through a service concession agreement or a contract of a similar nature.

Considering the current terms and conditions of the License, TGS concluded that the License is outside the scope of IFRIC 12, as it is considered in substance to provide for an indefinite term because the infrastructure will never revert to the grantor and due to the characteristics of renewal of the License that give a similar result to what which would result from having obtained a perpetual right to operate the infrastructure.

The evaluation carried out and the conclusions reached by TGS are consistent with those of other transportation and natural gas distribution companies in Argentina that are subject to the similar regulations and license agreements. The evaluation was carried out jointly, when the transportation and distribution companies adopted the IFRS in Argentina in 2012, together with the FACPCE, the Buenos Aires Stock Exchange (Bolsas y Mercados Argentinos -“BYMA”) and the CNV, considering the contributions of ENARGAS with respect to the regulatory aspects of the License agreements. In this regard, the CNV issued General Resolution No. 613/2012, ratifying that IFRIC 12 does not apply to natural gas transportation and distribution licenses established under the regulatory framework described in Note 17.

F-217

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

k) Leases

As mentioned in note 4.a), from January 1, 2019, the Company has adopted IFRS 16 to recognize the leases in which it participates. For more information regarding the new accounting policy adopted, see Note 4.a).

Until December 31, 2018, leases in which TGS assumed substantially all the risks and rewards of ownership of leased assets were classified as financial. To that purpose, an asset and a liability are recognized at the beginning for the same amount that corresponds to the lower value that results from comparing the fair value of the leased asset and the present value of the minimum lease payments.

Subsequently, each finance lease payment should be apportioned between the finance charge and the reduction of the outstanding liability (the finance charge to be allocated so as to produce a constant periodic rate of interest on the remaining balance of the liability). The corresponding lease payments, net of financial charges, are included in “Financial leases” in the current and non-current loans caption of the Statement of Financial Position. Interest on the financial cost is charged to the Statement of Comprehensive Income in the period of the lease in order to obtain a constant periodic interest rate on the debt pending amortization in each period.

Assets acquired through finance leases are restated for the effects of inflation as mentioned in Note 4.d. and are depreciated over the useful life of the assets received in accordance with current depreciation policies.

Until December 31, 2018, the remaining leases were classified as operating leases, so their charge was directly recognized in the Statement of Comprehensive Income.

IFRS 16 provides, for the so-called operating leases, the recognition of an asset, for the right to use the assets included in the lease contracts from the date they are available for use, and an equal liability at the present value of the payments to be made during the term of the contract, considering the discount rate implicit in the lease agreement, if it can be determined, or an incremental reference indebtedness rate.

l) Loans

Loans have been initially recorded at fair value net of direct attributable transaction costs. Subsequently, loans are valued at their amortized cost. Liabilities are disclosed as non-current when their maturity exceeds twelve months.

m) Trade payables

Trade payable are initially recognized at fair value. Subsequently they are measured at amortized cost using the effective tax method.

F-218

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

n) Income tax and deferred income tax

Income tax includes current tax and deferred income tax. Income tax is presented in the Statement of Comprehensive Income.

The current income tax is calculated on the basis of tax regulations in force at each reporting period. Management periodically evaluates positions taken in tax returns with respect to situations in which tax regulations are subject to interpretation and establishes provisions if applicable. As of December 31, 2019 and 2018, there are no provisions booked for this concept.

The Company has calculated income tax charges using the deferred tax method, which considers the effect of temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

Deferred income tax assets and liabilities are measured at undiscounted nominal value at the tax rates that are expected to apply in the year when the asset is realized or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting period rate (See note 14).

A deferred tax is recognized on the temporary differences arising from investments in subsidiaries and associates, except for deferred tax liabilities where the Company is able to control the timing of the reversal of the temporary difference and it is probable that the reversal will not occur in the foreseeable future.

Deferred tax assets and liabilities are offset if the Company has a legally enforceable right to offset recognized amounts and when deferred tax assets and liabilities relate to income tax levied by the same tax authority on the same taxable entity or different taxable entities that intend to settle tax assets and liabilities on a net basis. Deferred tax assets are recognized to the extent that it is probable that future taxable income will be generated against which the temporary differences can be used.

The assets and liabilities generated by the application of the deferred tax were valued at their nominal amount considering the restatements for inflation mentioned in Note 4.d) and are classified as non-current assets or liabilities.

o) Provisions

The Company has recorded provisions related to legal actions, judicial court, claims and administrative proceedings, including interpretive questions of the current legislation and those of regulatory nature.

Provisions for legal claims and/or claims by third parties (“legal claims and others”) are recorded at the expected cancellation value when the Company has a present obligation as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation; and the amount has been reliably estimated. Estimates are reviewed and adjusted, as the Company obtains additional information to be received.

p) Revenue recognition from contract with customers

Revenue is measured at the fair value of the consideration received or to be received, and represents amounts receivable for goods and/or services supplied. Revenue is recognized when the control of goods or services is transferred to the customer and the consideration is determined by an amount that reflects the consideration that the Company expects to receive.

F-219

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Tax on exports and turnover tax are disclosed as Selling Expenses.

The following are the accounting policies of the Company for the recognition of revenue of each of the business segments defined by our management:

Natural Gas Transportation

Natural Gas transportation services includes: (i) firm natural gas transportation, whose revenues are recognized when the capacity is reserved and paid for regardless of actual usage by the customer, (ii) interruptible natural gas transportation and exchange and displacement services whose revenues are recognized when services are rendered and (iii) the operation and maintenance service of the assets affected by the natural gas transportation service corresponding to the expansions promoted by the National Government and whose ownership corresponds to the trusts created for such purpose whose revenues are recognized when services are rendered.

The applicable rates arise from the tariff tables published by ENARGAS. Thus Company’s revenues are recognized by the amount for which it will be entitled to receive as consideration.

At the end of each month, TGS recognizes, over the time, its revenues from sales equivalent to the firm reserved capacity, the volumes of natural gas transported under the modalities of interruptible and exchange and displacement and by the operation and maintenance services. In return, a trade receivable is recognized which represents an unconditional right that the Company has to receive the consideration owed by the customer. On the other hand, the billing of the service is done monthly and according to the guidelines established by ENARGAS, the consideration is received within said calendar month.

Liquids Production and Commercialization

This business segment includes: (i) production and commercialization of liquids on our own account which revenues are recognized in a point in time, and (ii) other liquid services which revenues are recognized over the time.

Domestic Market

In the domestic market, TGS sells the production of propane and butane to LPG retailers in the framework of the programs created by the National Government to supply the domestic market. The sale prices are determined by the ex-Secretary of Hydrocarbon Resources (“SHR”). For more information, see Note 17 - Regulatory framework – b) Regulatory framework for non-regulated segments - to these consolidated financial statements.

The price of those tons of propane and butane that are not sold within the framework of the aforementioned programs is determined by the ex-Ministry of Energy and Mining (“ex MINEM”) based on the international reference prices.

F-220

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Regarding ethane sales, they are made to PBB Polisur S.R.L. (“PBB”), the only customer to whom this product is sold. To estimate transaction price, the Company uses the most probable amount method. In this regard, the Company only recognizes those transactions where it is highly probable that they will not be reversed in the future.

Foreign Market

In the foreign market, the Company markets propane, butane and natural gasoline to international traders (“traders”) and other clients of worldwide renown, some of them through trucks.

These sales are made under short-term contracts (less than one year), with the price determined as reference to international prices plus / minus a fixed amount per ton sold. There are no variable consideration components in these contracts.

For both domestic and foreign market sales, TGS transfers control and recognizes revenues when the products are delivered to the customer and therefore the product has been accepted and there is no evidence of the existence of pending obligations by the Company. It is at that moment when a trade receivable is recognized given that the receipt of the consideration is unconditional and only the passage of time is the only requirement for receiving the consideration owed by the customer.

Other liquids services

The Liquids production and commercialization segment also comprises reception, storage and dispatch of the liquids from the facilities located in Puerto Galván.

Revenues from sales are recognized when the service is effectively rendered, that is, after the dispatch to each vessel. The price is agreed by the parties being a fixed amount per ton of product dispatched, there being no variable components in them. These services are billed monthly, at which time an unconditional right to receive the consideration from the client arises.

Subsidies

As part of its participation in propane and butane supply programs in the local market carried out by the National Government, (for more information see “Note 17 - Regulatory Framework - b) Regulatory framework for non-regulated segments”), the Company receives from the Secretary of Energy a series of subsidies that are recognized in accordance with the provisions of IAS 20 “Accounting for government grants and disclosures of government assistance” because they correspond to economic compensations calculated as the difference between the sale prices of the products determined in accordance with the legislation in force and the reference prices calculated by the Secretary of Energy.

Subsidies are recognized at fair value whenever there is reasonable assurance that will be received and that the product has been delivered. They are presented within the caption “Revenue from sales” of the statement of comprehensive income.

F-221

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Other services

The services included in the Other Services segment consist mainly in (i) treatment, removal of impurities and natural gas compression, including the collection and transport of natural gas (ii) inspection and maintenance of pipelines and compressor plants, (iii) services of steam generation for electricity production and management services for expansion works and steam generation for the production of electricity and (iv) natural gas transportation services in Vaca Muerta.

Revenues from sales of this business segment are recognized over the time in the period in which the service is provided. The sale price is determined according to what arises from the contractual conditions agreed between TGS and its customers. In all cases, the recognition and billing of sales income is made on a monthly basis so that at that time a sales credit is recorded.

Revenue from the Company’s participation in the joint operation with SACDE which correspond to the construction activities provided by it, are recognized based on the physical progress of the work. To calculate the costs associated with such income, the UT adopts the criterion of applying the estimated final margin for the work to the accrued revenue in each period. The costs incurred in excess of the costs associated with the revenues are recognized in the Contract Assets caption.

Telecommunications

Revenues from the provision of Telecommunications services are recognized in the statement of comprehensive income at the time of effective performance of the service. The sale price is determined according to what arises from the contractual conditions agreed between TGS and its customers. The consideration is determined as a fixed monthly amount. In all cases, the recognition and billing of sales income is made on a monthly basis so that at that time a sales receivable is recorded.

Financial components

The Company does not have any contracts where the period between the transfer of the promised goods or services to the customer and payment by the customer exceeds one year. As a consequence, the Company does not adjust any of the transaction prices for the time value of money.

q) Contract liabilities

Mainly consist of pre-payments for services made by customers in order to finance the works to render the service. Contract liabilities are recognized initially at their fair value. Subsequent to initial recognition, advances  from customers are measured at their amortized cost based on the projections of the services to be provided that cancel the advances, restated for the inflation effects as mentioned in Note 4.d.

In case of prepayments received from customers to finance part of the works corresponding to the construction of an evacuation pipeline in Vaca Muerta, they are denominated in US dollars. The initial recognition of the contract liabilities is made at fair value. Subsequently, they are valued at their amortized cost based on the projections for the provision of the agreed services that cancel them and are measured using the selling exchange rate published by the Banco de la Nación Argentina at the date of the period reported.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Additionally, it includes the advance received by the UT from the Argentine Government as payment on account of the gas pipeline construction project. For more information, see “Note 23 - Associates and joint arrangements.”

r) Equity accounts

The activity in the Equity accounts reflects resolutions adopted by Shareholders in their meetings, or the effects of the laws or regulations in force. The equity accounts are restated for the inflation effects according to what is mentioned in Note 4.d, except the account Capital stock which is maintained at its original value.

Common stock and adjustment to common stock

The common stock consists of contributions made by shareholders represented by shares and comprises outstanding shares at their face value, net of treasury shares mentioned below.

Common stock accounts were restated in constant currency as mentioned in Note 4.d. Common stock account was kept at original value and the adjustment arising from such restatement is shown under “Inflation Adjustment to common stock”.

Common stock adjustment is not distributable in cash or in kind but may be capitalized through issuance of shares. In addition, this balance may be used to compensate accumulated losses.

Treasury shares and adjustments to treasury shares

Corresponds to the reclassification of the nominal value and corresponding restatement in constant peso (Inflation Adjustment to Common Stock) of shares issued and repurchased by the Company in market transactions, as required by the current regulations of the CNV.

Own equity instruments that are reacquired (treasury shares) are recognized at cost restated for the inflation effects as mentioned in Note 4.d., and deducted from equity. No gain or loss is recognized on the purchase, sale or cancellation of the Company’s treasury shares. Any difference between the carrying amount and the consideration, if reissued, is recognized as a premium on common stock or additional paid-up capital.

Additional paid-up capital

Corresponds to the difference between the carrying value of the treasury shares and the quoted value at the time were distributed (for more information see Note 19.b). It is restated according to what is mentioned in Note 4.d).

Legal Reserve

Pursuant to the provisions of the Argentine Business Association Law and the CNV, the Company is required to set up a legal reserve by providing at least 5% of the aggregate amount of net income for the year, prior year adjustments, transfers of other comprehensive income to retained earnings and accumulated losses of prior years, when this aggregate amount exceeds zero until the legal reserve equals 20% of the sum of Capital stock and Adjustment to capital stock balances.

F-223

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Distribution of dividends

The cash dividend is recognized as a liability in the Company’s financial statements in the year in which they are approved by the shareholders of the Company or the Board of Directors according to the powers delegated by the Shareholders’ Meeting, as appropriate.

Retained earnings

The outstanding balance of retained earnings includes accumulated gains or losses which were not allocated to a specific purpose reserve and, when positive, may be distributed pursuant to the decision of the Shareholders provided these retained earnings are not subject to legal restrictions, as mentioned above “Legal reserve”.

s) Basic and diluted earnings per share

Earnings per share as of December 31, 2019, 2018 and 2017 were calculated as follows:

	2019		2018		2017
Net income attributable to owners of the Company		12,805,105		17,561,249		8,847,196
Average number of outstanding shares (1)		776,121,341		788,405,563		794,495,283
Basic and diluited earnings per share		16.50		22.27		11.14

⁽¹⁾ The weighted average number of shares considers the effect of the weighted average of the changes originated in the transactions with the treasury shares made during the year.

As of the date of the issuance of these consolidated financial statements, there are no TGS instruments outstanding that imply the existence of potential ordinary shares, thus the basic net income per share for the years ended on December 31, 2019, 2018 and 2017 matches the diluted net income per share.

5. CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of the condensed interim consolidated financial statements in accordance with generally accepted accounting principles requires management to make accounting estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses during the reporting period. These estimates require management to make difficult, subjective or complex judgments and estimates about matters that are inherently uncertain. Management bases its estimates on various factors, including past trends, expectation of future events regarding the outcome of events and results and other assumptions that it believes are reasonable.

(a) Provisions for legal claims and others

The Company has certain liabilities with respect to existing court or out-of-court claims, lawsuits and other proceedings, including those involving legal and regulatory matters. The Company records liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such provisions are based on developments known at the date of the issuance of these consolidated financial statements, estimates of the outcome of these matters and the experience of its legal counsel in contesting, litigating and settling other matters. As the scope of the liabilities become better defined, there will be changes in the estimates of future costs, which could have a material effect on the Company’s future results of operations and financial condition or liquidity.

F-224

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

(b) Income Tax

Deferred tax assets are recognized for all tax losses to the extent that it is probable that there will be a tax benefit against which these losses can be utilized. Determining the amount of deferred tax assets that can be booked requires a considerable judgment by our management, based on the probable term and level of future taxable profits together with future tax planning strategies and macroeconomic variables affecting the business.

On December 29, 2017, the PEN promulgated and put into effect through Decree 1112/2017 a tax reform enacted in the National Congress through Law No. 27,430 (the “Tax Reform”). This reform establishes a gradual reduction of the applicable rate for the calculation of income tax. Subsequently, through the enactment of the Solidarity Law, the Argentine Government defined the postponement of the current tax rate for fiscal years that began on January 1, 2020.

Note 14 “Income tax and deferred tax” includes more detailed information on Income Tax.

(c) Impairment of PPE

As mentioned in Note 4.j, the Company periodically evaluates the existence of events or significant changes that could have adverse effects on the Company or will take place in the near future that could affect the recoverable value of the PPE amounts. An asset’s recoverable amount is the higher of the fair value less costs to sell that asset, and its value-in-use These evaluations are carried out at the lowest level for which there are identifiable cash flows, that is, for each single cash generating unit or CGU. TGS considers each of its business segments to be a CGU.

When assessing whether an impairment indicator may exist, TGS evaluates both internal and external sources of information, such as the following:

• Whether significant decreases in the market values of PPE elements took place.

• Whether prices of the main products and services that are marketed decreased.

• Whether significant changes in the regulatory framework were introduced.

• Whether operating costs suffered a materially increase.

• Whether evidence of obsolescence or physical damage has occurred.

• Whether the macroeconomic situation in which TGS carries out its activities, including significant variations in the sale prices of products, raw materials, interest rates, etc, has worsen.

Since August 2019, the main macroeconomic and business variables of Argentina suffered a significant deterioration which led the Argentine Government to take measures accordingly even affecting the regulatory framework of the Natural Gas Transportation segment (see Notes 1 and 17). Given these indicators of impairment of the recorded amounts of PPE, the recoverable value of each of the CGUs has been calculated based on its value in use.

F-225

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The value in use is calculated on the basis of discounted future cash flows. The projected cash flows are prepared taking into account: (i) for assets associated with the Liquids and Commercialization segment, projections of the prices of liquids and purchase cost of natural gas used as raw material; (ii) for assets associated with the Natural Gas Transportation segment, estimates of future tariff adjustments and the recognition of cost adjustments; (iii) for assets associated with the Other Services segment, future expectation of the need of Vaca Muerta gas producers to evacuate untreated natural gas; (iv) projections of the future costs to be incurred, (iv) expected macroeconomic variables such as interest rates, inflation, foreign exchange rates. The discount rate is based on a weighted average cost of capital (“WACC”).

In performing the analysis for the Natural Gas Transportation segment, the Company considered among others: (i) the status of negotiations with the Argentine Government, (ii) the contractual rights derived from the License, (iii) Management´s expectations regarding the procedures and actions initiated, (iv) the Company´s expectations regarding the new RTI process required by the Argentine Government and (v) the impact of a cost monitoring scheme that allows the realization of semiannual adjustments to current tariffs.

The Company has prepared three different estimates of expected cash flows by sensitizing its main variables and thus determining a baseline scenario that allows its comparison with the book value of the Natural Gas Transportation segment. In addition, the Company performed a sensitivity analysis of the probability of occurrence of each scenario and concluded that an increase of up to 70 percentage points in the weighted probability of the pessimistic case (from 30% to 100%) and a reduction in the probability of occurrence of the optimistic scenario and in the probability of occurrence of the base scenario (reducing each to zero) would not generate a value that would require an adjustment in carrying amount for impairment.

In performing the analysis for the Production and Commercialization of Liquids segment, the Company based it on, among others, future evolution of international liquid prices based on available public information, and projections of the future costs to be incurred to acquire natural gas for gas processing.

In performing the analysis for the Other Services segment, the Company based it on future expectation of the need of Vaca Muerta gas producers to evacuate untreated natural gas to extend the current firm shipping contracts, and projections of the contractual tariffs based on international inflation index.

Based on the analysis performed the Company did not identify the need for recording any impairment of the PPE amounts as of December 31, 2019.

The estimated recoverable values are sensitive to the significant variation of the assumptions applied, including the determination of future tariffs by the Argentine Government on the Natural Gas Transportation business segment, and the expectation of the development of Vaca Muerta gas fields on our Other Services business segment. In any case, we cannot assure with certainty that actual cash flows will be in line with the assumptions applied. Therefore, significant differences could arise in the future in relation to the estimated values in use.

F-226

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

No impairment indicators were identified during the years ended December 31, 2018 and 2017.

6. SUPPLEMENTAL CASH FLOW INFORMATION

For purposes of the consolidated statement of cash flows, the Company considers all highly liquid temporary investments with an original maturity of three months or less at the time of purchase to be cash equivalents. The cash flow statement has been prepared using the indirect method, which requires a series of adjustments to reconcile net income for the period to net cash flows from operating activities.

Non-cash investing and financing activities for the years ended December 31, 2019, 2018 and 2017 are presented below:

	2019		2018		2017
Unpaid acquisition of PPE		1,331,105		473,413		460,879
Principal payment of financial lease (1)		149,238		156,861		101,645
Capitalization of finance costs		446,195		-		-

⁽¹⁾ Cancelled through compensation with trade receivables with the creditor. See Note 13.

Note 13 to these consolidated financial statements includes a reconciliation between the initial and final balance of the financial liabilities arising from financing activities.

For additional information regarding dividend distribution made in treasury shares for an amount of Ps. 3,228,002, see Note 19.c. to these consolidated financial statements.

7. CONSOLIDATED BUSINESS SEGMENT INFORMATION

IFRS 8 “Operating Segments” requires an entity to report financial and descriptive information about its reportable segments, which are operating segments or aggregations of operating segments that meet specified criteria. Operating segments are components of an entity about which separate financial information is available that is evaluated regularly by the CODM in deciding how to allocate resources and in assessing performance. The Company’s CODM is the Board of Directors.

The Company analyzes its businesses into four segments: (i) Natural Gas Transportation Services, subject to ENARGAS regulations, (ii) Liquids Production and Commercialization, (iii) Other Services including midstream, among others, and (iv) Telecommunications. These last three business segments are not regulated by ENARGAS. Production and Commercialization of Liquids segment is regulated by the SE.

F-227

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Detailed information on each business segment for the years ended December 31, 2019, 2018 and 2017 is disclosed below:

Year ended December 31, 2019
	Natural Gas Transportation			Production and Commercialization of Liquids			Other Services			Telecommunications			Eliminations			Total
Revenues from sales		22,620,423			23,138,182			2,526,643			276,246			-			48,561,494
Intersegment revenues		615,993			-			-			-			(615,993	)		-
Cost of sales		(8,667,640	)		(14,661,541	)		(1,524,445	)		(137,870	)		615,993			(24,375,503	)
Administrative expenses		(1,043,519	)		(144,313	)		(61,021	)		(11,447	)		-			(1,260,300	)
Selling expenses		(1,343,560	)		(1,390,215	)		(264,396	)		(41,386	)		-			(3,039,557	)
Other operating (expenses) / income		(136,926	)		3,200			3,576			2,624			-			(127,526	)
Operating profit		12,044,771			6,945,313			680,357			88,167			-			19,758,608
Depreciation of property, plant and equipment		(2,998,224	)		(246,720	)		(450,671	)		-			-			(3,695,615	)

	Natural Gas Transportation		Commercialization of Liquids		Other Services		Telecommunications		Total
Identifiable assets		64,431,193		10,865,257		20,090,627		214,248		95,601,325
Identifiable liabilities		29,338,859		3,093,226		15,020,159		65,612		47,517,856

Year ended December 31, 2018
	Natural Gas Transportation			Production and Commercialization of Liquids			Other Services			Telecommunications			Eliminations			Total
Revenue from sales		23,785,660			25,578,373			2,784,534			250,856			-			52,399,423
Intersegment revenues		920,555			-			-			-			(920,555	)		-
Cost of sales		(7,944,333	)		(16,130,863	)		(1,621,770	)		(126,455	)		920,555			(24,902,866	)
Administrative expenses		(1,284,707	)		(129,315	)		(55,348	)		(10,210	)		-			(1,479,580	)
Selling expenses		(1,467,144	)		(984,794	)		(220,674	)		(42,070	)		-			(2,714,682	)
Other operating (expenses) / income		(240,414	)		(1,117,949	)		(8,375	)		(3,581	)		-			(1,370,319	)
Operating profit		13,769,617			7,215,452			878,367			68,540			-			21,931,976
Depreciation of property, plant and equipment		(2,892,621	)		(174,964	)		(352,235	)		-			-			(3,419,820	)

 

	Natural Gas Transportation		Production and Commercialization of Liquids		Other Services		Telecommunications		Total
Identifiable assets		69,603,664		13,907,967		11,621,495		155,320		95,288,446
Identifiable liabilities		25,748,537		2,301,679		19,563,528		70,796		47,684,540

Year ended December 31, 2017
	Natural Gas Transportation			Production and Commercialization of Liquids			Other Services			Telecommunications			Eliminations			Total
Revenue from sales		11,469,824			17,189,194			1,844,712			190,858			-			30,694,588
Intersegment revenues		377,137			-			-			-			(377,137	)		-
Cost of sales		(6,428,448	)		(11,186,009	)		(1,008,879	)		(114,747	)		377,137			(18,360,946	)
Administrative expenses		(918,567	)		(144,172	)		(56,110	)		(10,087	)		-			(1,128,936	)
Selling expenses		(645,435	)		(408,173	)		(164,471	)		(23,804	)		-			(1,241,883	)
Other operating (expenses) / income		(503,409	)		99,520			(14,150	)		236			-			(417,803	)
Operating profit		3,351,102			5,550,360			601,102			42,456			-			9,545,020
Depreciation of property, plant and equipment		(2,607,632	)		(146,630	)		(353,484	)		-			-			(3,107,746	)

F-228

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

8. DETAIL OF SIGNIFICANT STATEMENT OF FINANCIAL POSITION AND STATEMENT OF COMPREHENSIVE INCOME CAPTIONS

a) Other receivables

	2019				2018
	Current		Non Current		Current		Non Current
Turnover tax balance		50,711		-		-		-
Income tax credit balance (1)		42,607		-		-		-
VAT credit balance		1,018,621		-		461,916		-
Other tax receivables		1,227		1,401		15,365		3,144
Prepaid expenses		90,714		-		73,464		-
Advances to suppliers		1,181,972		-		2,847,433		-
Subsidies receivables		143,829		-		450,523		-
Other Receivables UT		39,009		-		45,697		-
Others		329,387		7,603		202,248		9,521
Total		2,898,077		9,004		4,096,646		12,665

⁽¹⁾ Provision, net of advances paid, withholdings and perceptions.

b) Trade receivables

	2019					2018
	Current			Non Current		Current			Non Current
Commons		6,329,258			-		4,788,890			-
UT		13,813			-		31,446			-
Natural Gas Transportation		3,774,497			-		2,549,704			-
Production and Commercialization of Liquids		1,903,005			-		1,680,674			-
Other services		637,943			-		527,066			-
Related parties (Note 21)		279,457			-		206,079
Natural Gas Transportation		154,009			-		112,671			-
Production and Commercialization of Liquids		53,744			-		12,497			-
Other services		71,704			-		80,911			-
Allowance for doubtful accounts		(134,956	)		-		(203,860	)		-
Total		6,473,759			-		4,791,109			-

The movement of the allowance for doubtful accounts is as follows:

Balances as of December 31, 2017	-
Additions (1)	203,860
Applications	-
Reversals	-
Balances as of December 31, 2018	203,860
Inflation adjustment restatement	(71,339	)
Additions (1)	2,435
Applications	-
Reversals	-
Balances as of December 31, 2019	134,956

⁽¹⁾ The total amount is recorded in Selling Expenses

F-229

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

c) Cash and cash equivalents

	2019		2018
Cash and banks		1,123,051		9,174,577
UT Cash and banks		2,758		235
Time deposits		-		938,544
Mutual funds in Argentine Pesos		1,029,644		3,302,476
Interest-bearing accounts		7,609,748		12,167,206
UT Mutual funds		-		22,099
Total		9,765,201		25,605,137

d) Contract liabilities

	2019				2018
	Current		Non Current		Current		Non Current
Natural Gas Transportation		98,460		1,744,944		104,572		1,844,227
Production and Commercialization of Liquids		38,387		341,698		39,249		392,388
Other services		62,386		840,184		3,104		23,261
UT		20,568		-		52,408		-
Total		219,801		2,926,826		199,333		2,259,876

During 2019 and 2018 financial years, the Company recognized Ps. 139,207 and Ps. 182,784, respectively, in revenues for sales from contracts with clients in the Statement of Comprehensive Income, which had been included in the balance at the beginning of each year.

e) Other payables

	2019				2018
	Current		Non Current		Current		Non Current
Payable for compensation for the Board of Directors and Supervisory Committee		8,498		-		8,321		-
Others		1,744		-		2,529		-
UT Other liabilities		277,417		-		113,253		-
Total		287,659		-		124,103		-

f) Taxes payables

	2019				2018
	Current		Non Current		Current		Non Current
Health and safety tax		12,989		-		13,522		-
Withholdings and perceptions made to third parties		148,052		-		170,174		-
Turnover Tax		85,283		-		96,474		-
Withholding Tax		71,998		-		-		-
UT Others		341		-		4,233		-
Others		34,520		-		26,680		-
Total		353,183		-		311,083		-

F-230

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

g) Trade payables

	2019				2018
	Current		Non Current		Current		Non Current
Suppliers		3,875,928		-		4,304,927		-
UT Suppliers		109,876		-		138,837		-
Customers (credit balances)		6,164		-		3,438		-
Related companies		121,603		-		309,352		-
Total		4,113,571		-		4,756,554		-

h) Revenues

	2019		2018		2017
Sales of goods and services		48,359,045		51,773,746		30,159,782
Subsidies		202,449		625,677		534,806
Total		48,561,494		52,399,423		30,694,588

Disaggregation of revenues

Below is a table in which revenues are disaggregated considering the type of market and the opportunity to satisfy performance obligations:

Year ended December 31, 2019
	Natural Gas Transportation		Production and Commercialization of Liquids		Other Services		Telecommunications		Total
Primary geographical market:
External market		-		9,144,860		-		-		9,144,860
Local market		22,620,423		13,993,322		2,526,643		276,246		39,416,634
Total		22,620,423		23,138,182		2,526,643		276,246		48,561,494
Timing of revenue recognition:
Over the time		22,620,423		1,226,814		2,526,643		276,246		26,650,126
At a point in time		-		21,911,368		-		-		21,911,368
Total		22,620,423		23,138,182		2,526,643		276,246		48,561,494

Year ended December 31, 2018
	Natural Gas Transportation		Production and Commercialization of Liquids		Other Services		Telecommunications		Total
Primary geographical market:
External market		-		9,269,086		-		-		9,269,086
Local market		23,785,660		16,309,287		2,784,534		250,856		43,130,337
Total		23,785,660		25,578,373		2,784,534		250,856		52,399,423
Timing of revenue recognition:
Over the time		23,785,660		1,084,994		2,784,534		250,856		27,906,044
At a point in time		-		24,493,379		-		-		24,493,379
Total		23,785,660		25,578,373		2,784,534		250,856		52,399,423

 

Year ended December 31, 2017
	Natural Gas Transportation		Production and Commercialization of Liquids		Other Services		Telecommunications		Total
Primary geographical market:
External market		-		6,664,863		-		-		6,664,863
Local market		11,469,824		10,524,331		1,844,712		190,858		24,029,725
Total		11,469,824		17,189,194		1,844,712		190,858		30,694,588
Timing of revenue recognition:
Over the time		11,469,824		822,760		1,844,712		190,858		14,328,154
At a point in time		-		16,366,434		-		-		16,366,434
Total		11,469,824		17,189,194		1,844,712		190,858		30,694,588

Detailed information of revenues on each business segment for the years ended December 31, 2019, 2018 and 2017 is disclosed below:

F-231

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

i. Natural Gas Transportation:

	2019		2018		2017
Firm		18,521,215		18,834,776		8,971,393
Access and Charge		835,721		870,398		666,979
Interruptible and Others		3,263,487		4,080,486		1,831,452
Total		22,620,423		23,785,660		11,469,824

ii. Production and Commercialization of Liquids:

	2019		2018		2017
Product		21,708,919		23,867,702		15,776,153
Services		1,226,814		1,084,994		878,235
Government grants		202,449		625,677		534,806
Total		23,138,182		25,578,373		17,189,194

iv. Other services:

	2019		2018		2017
Conditioning and treatment		1,273,070		1,130,820		841,091
Operation and maintenance		651,665		738,568		637,752
Steam sales		231,565		210,387		148,582
Construction		11,899		32,799		213,270
UT Construction		187,686		666,402		-
Transportation and conditioning of Naural Gas in Vaca Muerta		165,725		-		-
Others		5,033		5,558		4,017
Total		2,526,643		2,784,534		1,844,712

i) Cost of sales

	2019			2018			2017
Inventories at the beginning of the year		554,218			282,659			371,470
Purchases		12,052,590			13,630,238			9,250,971
Operating costs (Note 8.i.)		12,076,335			11,544,187			9,021,164
Inventories at the end of the year		(307,640	)		(554,218	)		(282,659	)
Total		24,375,503			24,902,866			18,360,946

F-232

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

j) Expenses by nature – Information required under art. 64 paragraph I, clause B) Commercial Companies Law

	2019
				Operating expenses
Accounts	Total			Regulated Activities		Non Regulated Activities		Administrative expenses		Selling expenses			Financial expenses
Salaries, wages and other compensations		3,193,390			1,463,206		953,222		604,578		172,384			-
Social security taxes		595,112			271,610		170,506		117,055		35,941			-
Compensation to Directors and Supervisory Committee		32,528			-		-		32,528		-			-
Professional services fees		483,128			15,383		248,648		186,970		32,127			-
Technical operator assistance fees		1,144,777			776,200		368,577		-		-			-
Materials		387,772			169,415		218,357		-		-			-
Third parties services		435,870			180,037		222,864		24,485		8,484			-
Telecommunications and post expenses		44,810			12,956		6,097		23,952		1,805			-
Rents		43,758			12,717		21,141		8,888		1,012			-
Transports and freight		115,986			73,000		40,551		2,435		-			-
Easements		91,941			87,367		4,574		-		-			-
Offices supplies		13,332			4,019		2,310		5,183		1,820			-
Travels expenses		132,485			65,497		35,936		27,340		3,712			-
Insurance		96,399			47,111		38,101		6,391		4,796			-
Property, plant and equipment maintenance		2,566,969			2,233,041		298,406		35,522		-			-
Depreciation of property, plant and equipment		3,695,615			2,842,666		697,391		155,558		-			-
Taxes and contributions		3,044,070			334,176		24,473		3,903		2,681,518	(1)		-
Advertising		90,137			-		-		-		90,137			-
Doubtful accounts		2,435			-		-		-		2,435			-
Banks expenses		19,308			-		-		19,308		-			-
Interests expense		2,509,815			-		-		-		-			2,509,815
Foreign exchange loss		15,636,514			-		-		-		-			15,636,514
Capitalized financial costs		(446,195	)		-		-		-		-			(446,195	)
Costs of services rendered to third parties		13,664			-		13,664		-		-			-
Other expenses		132,706			79,239		43,877		6,204		3,386			-
Total 2019		34,076,326			8,667,640		3,408,695		1,260,300		3,039,557			17,700,134

(1)Includes tax on exports for Ps. 843,418 for the year ended December 31, 2019.

F-233

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	2018
			Operating expenses
Accounts	Total		Regulated Activities		Non Regulated Activities		Administrative expenses		Selling expenses			Financial expenses
Salaries, wages and other contributions		2,942,737		1,370,862		873,457		549,048		149,370			-
Social security taxes		492,620		222,669		130,665		107,092		32,194			-
Compensation to Directors and Supervisory Committee		39,718		-		-		39,718		-			-
Professional services fees		422,573		10,841		208,637		192,647		10,448			-
Technical operator assistance fees		2,026,244		1,289,165		737,079		-		-			-
Materials		344,492		105,664		238,828		-		-			-
Third parties services		402,701		157,394		200,379		30,443		14,485			-
Telecommunications and post expenses		33,498		6,455		4,395		21,933		715			-
Rents		38,129		11,779		15,846		9,147		1,357			-
Transports and freight		104,751		64,965		35,357		4,429		-			-
Easements		83,186		83,186		-		-		-			-
Offices supplies		10,763		3,647		1,324		4,815		977			-
Travels expenses		131,177		58,722		41,135		25,222		6,098			-
Insurance		101,944		58,713		36,451		6,775		5			-
Property, plant and equipment maintenance		1,946,371		1,700,665		221,697		24,009		-			-
Depreciation of property, plant and equipment		3,419,820		2,481,136		527,193		411,491		-			-
Taxes and contributions		2,578,080		262,317		30,893		3,274		2,281,596	(1)		-
Advertising		7,470		-		-		-		7,470			-
Doubtful accounts		203,860		-		-		-		203,860			-
Banks expenses		18,691		-		-		18,691		-			-
Interests expense		2,577,365		-		-		-		-			2,577,365
Foreign exchange loss		20,185,935		-		-		-		-			20,185,935
Costs of services rendered to third parties		254,250		-		254,250		-		-			-
Other expenses		135,374		56,152		42,269		30,846		6,107			-
Year ended Deccember 31, 2018		38,501,749		7,944,332		3,599,855		1,479,580		2,714,682			22,763,300

⁽¹⁾ Includes tax on exports of Ps. 382,863 for the year ended December 31, 2018.

F-234

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	2017
				Operating expenses
Accounts	Total			Regulated Activities		Non Regulated Activities		Administrative expenses		Selling expenses			Financial expenses
Salaries, wages and other compensations		2,755,821			1,329,370		721,780		550,569		154,102			-
Social security taxes		474,525			208,944		123,835		108,080		33,666			-
Compensation to Directors and Supervisory Committee		21,253			-		-		21,253		-			-
Professional services fees		153,215			3,706		7,585		129,187		12,737			-
Technical operator assistance fees		887,901			400,020		487,881		-		-			-
Materials		149,305			46,117		103,188		-		-			-
Third parties services		317,596			132,233		159,075		26,288		-			-
Telecommunications and post expenses		24,756			3,307		3,034		17,223		1,192			-
Rents		16,828			4,863		2,432		8,372		1,161			-
Transports and freight		89,022			52,995		30,416		5,560		51			-
Easements		54,249			54,249		-		-		-			-
Offices supplies		8,633			2,561		900		4,027		1,145			-
Travels expenses		47,741			21,350		7,865		13,831		4,695			-
Insurance		81,007			47,294		26,962		6,013		738			-
Property, plant and equipment maintenance		1,546,413			1,331,530		198,875		13,290		2,718			-
Depreciation of property, plant and equipment		3,107,746			2,414,921		500,115		192,710		-			-
Taxes and contributions		1,413,444			327,852		20,606		1,824		1,063,162	(1)		-
Advertising		1,180			-		5		-		1,175			-
Doubtful accounts		(35,989	)		-		-		-		(35,989	)		-
Banks expenses		11,102			-		-		11,102		-			-
Interests expense		1,301,985			-		-		-		-			1,301,985
Foreign exchange loss		1,718,617			-		-		-		-			1,718,617
Other financial charges		258,315			-		-		-		-			258,315
Costs of services rendered to third parties		177,326			-		177,326		-		-			-
Other expenses		88,909			47,134		20,838		19,607		1,330			-
Total 2017		14,670,900			6,428,446		2,592,718		1,128,936		1,241,883			3,278,917

(1) Includes tax on exports for Ps. 1,978 for the year ended December 31, 2017

F-235

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

k) Net financial results

	2019			2018			2017
Financial income
Interest income		719,559			2,069,473			204,776
Foreign exchange gain		7,815,595			12,559,251			863,880
Subtotal		8,535,154			14,628,724			1,068,656
Financial expenses
Interest expense		(2,509,815	)		(2,577,365	)		(1,301,985	)
Foreign exchange loss		(15,636,514	)		(20,185,935	)		(1,718,617	)
less: Capitalized finance costs		446,195			-			-
Subtotal		(17,700,134	)		(22,763,300	)		(3,020,602	)
Other financial results
Derivative financial instruments results		(19,172	)		163,192			-
Fair value gains on financial instruments through profit or loss		542,218			2,112,016			680,678
Others		(409,659	)		(374,619	)		(258,315	)
Subtotal		113,387			1,900,589			422,363
Gain on net monetary position		6,154,172			1,855,519			716,821
Total		(2,897,421	)		(4,378,468	)		(812,762	)

In accordance with the provisions of IAS 29, the Company opted to present the gain on the monetary position in a single line included in the financial results. This exposure implies that the nominal magnitudes of the financial results have been adjusted for inflation. The real magnitudes of financial results are different from the components of financial results presented above. For additional information see Note 4.d., to these consolidated financial statements.

l) Other operating expenses

	2019			2018			2017
Net increase in provisions (1)		(156,124	)		(1,185,743	)		(351,039	)
Recovery of insurance		-			36,726			299,495
Write off of other receivables		-			-			(161,596	)
Others		28,598			(221,302	)		(204,663	)
Total		(127,526	)		(1,370,319	)		(417,803	)

⁽¹⁾ Including interest and legal expenses

m) Other financial assets at amortized cost

	2019				2018
	Current		Non Current		Current		Non Current
VRD bonds		3,355		5,403		8,790		13,476
US Treasury Bills		1,040,605		-		-		-
Total		1,043,960		5,403		8,790		13,476

n) Payroll and social security taxes payable

 

	2019				2018
	Current		Non Current		Current		Non Current
Vacation benefit payable		305,847		-		262,577		-
Annual bonus payable		205,541		-		205,159		-
Social security taxes payable		130,942		-		103,654		-
UT		6,121				18,766
Total		648,451		-		590,156		-

F-236

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

9. INVESTMENTS IN ASSOCIATES

	2019																			2018
									Issuer Information
	Description of securities								Last financial statemets issued
Name and issuer	Face value		Amount		Cost		Book value		Main business	Date	Common stock		Net (loss) / income for the year / period			Shareholders equity		% of Common Stock		Book value
Transporte y Servicios de Gas en Uruguay S.A.	Ps. Uru. 1			196,000		182		6,627	Pipeline maintenance	09/30/2019		28		(783	)		14,308		49.00		8,919
Emprendimientos de Gas del Sur S.A. (in liquidation)	$	1		116,130		2,025		418	Pipeline constructionand operation services	09/30/2019		237		(186	)		854		49.00		498
Gas Link S.A.	$	1		502,962		8,595		71,615	Pipeline construction and operation services	09/30/2019		1,026		6,990			396,461		49.00		102,373
Total								78,660													111,790

10. JOINT ARRANGEMENTS

TGS jointly with SACDE applied for the public tender launched by the Argentine Government for the construction of a connection pipeline in the province of Santa Fe. This tender was finally obtained by the UT whose sole purpose is the execution of such works. For further information, see Note 23.

The Company participates in the UT in a percentage of 51% on the rights of the assets and on the obligations related to them. TGS consolidates line by line assets, liabilities and results of the UT based on the aforementioned percentage of participation.

The breakdown of the amounts included in the statements of financial position related to the Company’s participation in the UT and its results is the following:

	2019		2018
Consolidated Statements of financial position
Non Current assets		-		-
Current Assets		232,849		300,649
Total		232,849		300,649
Non Current Liabilities		-		-
Current Liabilities		414,323		261,274
Total		414,323		261,274

	2019			2018		2017
Consolidated Statements of comprehensive income
Gross (loss) / profit		(154,303	)		52,112		1,226
Operating  (loss) / profit		(172,298	)		37,517		(38	)
Net Financial results		(21,069	)		1,611		348
Comprehensive (loss) / income		(193,367	)		39,128		310

 

11. PROFIT FROM ASSOCIATES

	2019			2018			2017
EGS (in liquidation)		(80	)		4,770			32
TGU		(664	)		(68	)		438
Link		(31,114	)		23,306			32,821
Total		(31,858	)		28,008			33,291

F-237

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

12. PROPERTY, PLANT AND EQUIPMENT

	2019
	Cost											Depreciation
Account	Beginning of the year		Additions		Retirements		Transfers			End of the year		Accumulated at the beginning of the year		Retirements		For the year		rate %		Accumulated at the end of the year		Net book value
Pipelines		61,419,814		-		13,330		1,933,215			63,339,699		29,732,526		7,747		1,518,032		2.2		31,242,811		32,096,888
Compressor plants		23,468,780		399,897		179,885		2,033,984			25,722,776		16,260,945		108,445		1,067,625	3.3 to 25			17,220,125		8,502,651
Other plants		26,488		-		-		-			26,488		8,039		-		899		3.3		8,938		17,550
Stations of regulation and/or measurement of pressure		2,091,798		-		-		76,900			2,168,698		1,668,370		-		57,681		4.0		1,726,051		442,647
Other technical installations		413,717		-		-		7,440			421,157		353,051		-		9,250		6.7		362,301		58,856
Subtotal assets related to natural gas transportation service		87,420,597		399,897		193,215		4,051,539			91,678,818		48,022,931		116,192		2,653,487				50,560,226		41,118,592
Non-regulated segment Pipelines		124,829		-		-		10,109,995			10,234,824		63,362		-		62,977		2.2		126,339		10,108,485
Non-regulated segment Compressor plants		1,910,728		-		-		145,605			2,056,333		582,695		-		217,431	3.3 to 25			800,126		1,256,207
Non-regulated segment Other plants		13,326,401		-		-		4,726,393			18,052,794		9,976,456		-		312,521		3.3		10,288,977		7,763,817
Non-regulated segment Stations of regulation and/or measurement of pressure		160,534		11,284		-		457,977			629,795		32,186		-		11,582		4.0		43,768		586,027
Non-regulated segment Other technical installations		254,016		-		-		-			254,016		75,525		-		22,868		6.7		98,393		155,623
Subtotal assets related to Other Services and
Production and Commercialization of Liquids		15,776,508		11,284		-		15,439,970			31,227,762		10,730,224		-		627,379				11,357,603		19,870,159
Lands		165,136		189,003		-		-			354,139		-		-		-		-		-		354,139
Buildings and constructions		3,119,619		-		948		428,387			3,547,058		1,761,692		11		58,976		2.0		1,820,657		1,726,401
Facilities and features in building		263,700		-		-		97			263,797		105,381		-		10,927		4.0		116,308		147,489
Machinery, equipment and tools		933,683		172,586		7,758		6,207			1,104,718		578,196		7,758		80,007	6.7 to 10			650,445		454,273
UT Machinery, equipment and tools		909		-		-		-			909		686		-		223	6.7 to 10			909		-
Computers and Telecommunication systems		4,177,609		3,440		-		662,582			4,843,631		3,420,768		-		221,927	6.7 to 20			3,642,695		1,200,936
Vehicles		455,370		80,860		24,497		-			511,733		320,725		23,144		41,452		20		339,033		172,700
Furniture		228,540		-		-		-			228,540		221,308		-		1,237		10		222,545		5,995
Materials		2,363,440		2,259,125		21,545		(1,458,699	)		3,142,321		-		-		-		-		-		3,142,321
Line pack		578,707		-		-		(84,156	)		494,551		27,646		-		-		-		27,646		466,905
Works in progress		9,216,602		15,722,143		-		(19,045,927	)		5,892,818		-		-		-		-		-		5,892,818
Total		124,700,420		18,838,338		247,963		-			143,290,795		65,189,557		147,105		3,695,615				68,738,067		74,552,728

F-238

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	2018
	Cost											Depreciation
Account	Beginning of the year		Additions		Retirements		Transfers			End of the year		Accumulated at the beginning of the year		Retirements		For the year		rate %		Accumulated at the end of the year		Net book value
Pipelines		60,167,955		-		27,845		1,279,704			61,419,814		28,257,137		461		1,475,850		2.2		29,732,526		31,687,288
Compressor plants		22,369,570		-		474,819		1,574,029			23,468,780		15,721,120		429,105		968,930	3.3 to 25			16,260,945		7,207,835
Other plants		26,488		-		-		-			26,488		7,141		-		898		3.3		8,039		18,449
Stations of regulation and/or measurement of pressure		2,093,130		1,663		9,150		6,155			2,091,798		1,620,632		7,942		55,680		4.0		1,668,370		423,428
Other technical installations		407,598		-		2,046		8,165			413,717		346,264		2,046		8,833		6.7		353,051		60,666
Subtotal assets related to
natural gas transportation service		85,064,741		1,663		513,860		2,868,053			87,420,597		45,952,294		439,554		2,510,191				48,022,931		39,397,666
Non-regulated segment Pipelines		124,829		-		-		-			124,829		61,868		-		1,494		2.2		63,362		61,467
Non-regulated segment Compressor plants		1,898,166		-		4,330		16,892			1,910,728		395,448		808		188,055	3.3 to 25			582,695		1,328,033
Non-regulated segment Other plants		13,744,847		9,207		1,029,228		601,575			13,326,401		10,676,085		950,340		250,711		3.3		9,976,456		3,349,945
Non-regulated segment Stations of regulation and/or
measurement of pressure		160,534		-		-		-			160,534		25,765		-		6,421		4.0		32,186		128,348
Non-regulated segment Other technical installations		254,016		-		-		-			254,016		52,658		-		22,867		6.7		75,525		178,491
Subtotal assets related to Other Services and Production and Commercialization of Liquids		16,182,392		9,207		1,033,558		618,467			15,776,508		11,211,824		951,148		469,548				10,730,224		5,046,284
Lands		110,509		54,627		-		-			165,136		-		-		-		-		-		165,136
Buildings and constructions		3,053,615		-		73,980		139,984			3,119,619		1,765,318		58,701		55,075		2.0		1,761,692		1,357,927
Facilities and features in building		255,239		-		18,078		26,539			263,700		103,710		9,419		11,090		4.0		105,381		158,319
Machinery, equipment and tools		790,333		199,925		73,467		16,892			933,683		609,507		73,206		41,895	6.7 to 10			578,196		355,487
UT Machinery, equipment and tools		-		909		-		-			909		-		-		686	6.7 to 10			686		223
Computers and Telecommunication systems		5,762,314		258		2,085,323		500,360			4,177,609		5,203,218		2,078,177		295,727	6.7 to 20			3,420,768		756,841
Vehicles		405,725		58,593		8,948		-			455,370		294,870		8,465		34,320		20		320,725		134,645
Furniture		228,380		-		-		160			228,540		220,020		-		1,288		10		221,308		7,232
Materials		2,419,633		880,423		55,307		(881,309	)		2,363,440		-		-		-		-		-		2,363,440
Line pack		236,471		-		-		342,236			578,707		27,646		-		-		-		27,646		551,061
Works in progress		3,429,298		9,418,686		-		(3,631,382	)		9,216,602		-		-		-		-		-		9,216,602
Total		117,938,650		10,624,291		3,862,521		-			124,700,420		65,388,407		3,618,670		3,419,820				65,189,557		59,510,863

F-239

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

As of December 31, 2018, the assets allocated to the natural gas treatment and compression service include the following amounts in which the Company is a financial lease under the terms of leasing contracts:

	2018
Capitalized financial lease		2,501,165
Accumulated depreciaton		(560,091	)
Total		1,941,074

As of December 31, 2019 and January 1, 2019, date of the first application of IFRS 16, the assets related to the Other Services and Production and Commercialization of Liquids segments contains the following assets for right of use:

	12/31/2019		1/1/2019
Other plants		448,306		515,552
Compressor plants		1,113,024		1,279,978
Other technical installations		126,560		145,544
Total		1,687,890		1,941,074

The book value variation of the rights-of use accounted during the year ended on December 31, 2019 corresponds to its depreciation:

	12/31/2019
Other plants		(67,246	)
Compressor plants		(166,954	)
Other technical installations		(18,984	)
Total		(253,184	)

13. LOANS

Short-term and long-term loans as of December 31, 2019 and 2018 comprise the following:

	2019		2018
Current Loans
2018 Notes Interest		336,881		349,375
Pre-export finance		1,021,325		-
Leasing (Note 22)		363,881		331,850
Total Current loans		1,722,087		681,225
Non Current Loans
2018 Notes		29,847,160		28,789,009
Leasing (Note 22)		2,013,557		2,214,706
Total non current loans		31,860,717		31,003,715
Total (1)		33,582,804		31,684,940

⁽¹⁾ Net of issuance expenses of Ps. 97,840 and Ps. 185,243 as of December 31, 2019 and 2018, respectively.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The activity of the loans as of December 31, 2019 and 2018 is the following:

	2019
	Leases liabilities			Other payables			2018
Beggining balance		2,546,556			29,138,384			10,218,503
Inflation adjustment restatement		(891,146	)		(13,298,217	)		(10,931,986	)
Accrued interest		194,944			2,061,631			2,305,265
Effect of foreign exchange rate change		1,178,710			13,935,368			19,765,612
VAT unpaid installments		15,988			-			29,388
Procceds from loans		-			1,051,809			21,261,978
Payment of loans (1)		(167,989	)		-			(2,042,940	)
Payment of redemption of loans		-			-			(7,378,176	)
Interest paid (2)		(159,164	)		(2,024,070	)		(1,542,704	)
Ending balance		2,717,899			30,864,905			31,684,940

⁽¹⁾ For the years ended on December 31, 2019 and 2018, Ps. 149,238 and Ps. 156,861 respectively were cancelled through the offseting of debit balances maintained with the creditor (Pampa Energía).

⁽²⁾ For the years ended on December 31, 2019 and 2018, Ps. 143,357 and Ps. 149,373, respectively, were cancelled through the offseting of debit balances maintained with the creditor (Pampa Energía).

The maturities of the current and non-current loans as of December 31, 2019 are as follows, not including issuance expenses:

			To due
	Due at 12/31/2019		From 1/01/2020 to 12/31/2020		From 1/01/2021 to 12/31/2021		From 1/01/2022 to 12/31/2022		From 1/01/2023 to 12/31/2023		From 1/01/2024 onwards		Total
2018 Notes		-		336,881		-		-		-		29,847,160		30,184,041
Financial Leasing		90,363		273,518		296,515		321,370		348,380		1,047,292		2,377,438
Pre-export finance		-		1,021,325		-		-		-		-		1,021,325
Total		90,363		1,631,724		296,515		321,370		348,380		30,894,452		33,582,804

The following table sets reconciliation between the total of future minimum lease payments as of December 31, 2019, and their present book value:

	12/31/2019
As of 12/31/2020		538,339
From 1/01/2021 to 12/31/2021		448,037
From 1/01/2022 to 12/31/2022		448,037
From 1/01/2023 to 12/31/2023		448,037
From 1/01/2024 onwards		1,163,723
Total minimum future payments		3,046,173
Future financial charges on financial leases		(668,735	)
Book Value financial leases		2,377,438

Description of the indebtedness of the Company

Class 2 Notes (“2018 Notes”)

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The Ordinary General Shareholders’ Meeting held on April 26, 2017, ordered the increase of up to US$ 700,000,000 (or its equivalent in other currencies) of the 2017 Program authorized by the CNV by Resolution No. 17,262 dated January 3, 2014, whose amount until the Shareholders´ Meeting was held was US$ 400,000,000 (the “2017 Program”).

On May 2, 2018, within the framework of the 2017 Program, the Company issued the 2018 Notes according to the following characteristics:

	2018 Notes
Amount in U.S.$	500,000,000
Interest Rate	6.75% annual
Issuance price	99.725%

	Scheduled payment date	Percentage of the principal to be paid
Amortization	May 2, 2025	100%
Frequency of interest payment	Semiannual, payable on May 2 and November 2 of each year.
Guarantor	None

The authorization for the public offering of the 2017 Program was granted by the CNV through Resolutions No. 17,262 and 18,938 dated January 3, 2014 and September 15, 2017, respectively. On October 31, 2018, through Disposition No. DI-2018-55-APN-GE#CNV, the CNV granted the extension of the 2017 Program until January 3, 2024.

The Ordinary General Shareholders´ Meeting held on August 15, 2019 decided to increase the 2017 Program from US$ 700 million to US$ 1.2 billion. This increase was authorized by the CNV on October 9, 2019 through Resolution RESFC-2019-20486-APN-DIR # CNV.

Funds obtained by the Company are applied to:

i. The repurchase of the Class 1 Notes (the “2014 Notes”) for U.S.$ 86,511,165;

ii. the cancellation and total redemption of the 2014 Notes for U.S.$ 120,786,581;

iii. the balance of net funds to make investments in capital expenditures.

The value of the financial debt is based on its amortized cost calculated as cash flows discounted at an effective rate of 7.088%.

Covenants

As of the date of issuance of these consolidated financial statements, the Company has complied with a series of restrictions derived from its current financial agreements, which include, among others, those related to obtaining new loans, payment of dividends, granting of guarantees, disposal of certain assets and make certain transactions with related parties.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The Company may contract new debts under the following conditions, among others:

a. To the extent that after the new debt has been incurred (i) the consolidated coverage ratio (calculated as the quotient of the consolidated adjusted EBITDA -earnings before financial results, income tax, depreciation and amortization- and the consolidated interest expense) is equal or higher than 2.0:1; and (ii) the consolidated debt ratio (calculated as the quotient of the consolidated debt and the consolidated EBITDA) is equal to or lower than 3.5:1.

b. For the refinancing of the outstanding financial debt.

c. Originated by customer advances.

The Company may pay dividends under the following conditions: (i) the Company is not in default under 2018 Notes, and (ii) immediately after any dividend payment, the Company may incur new debts according to the provisions in point a. of the preceding paragraph.

Lease liability

Corresponds to the financing obtained for the acquisition of the corresponding assets to the treatment and compression plant located in the area of Río Neuquén. Said agreement was concluded on August 11, 2016 with Petrobras (currently Pampa Energía) and consists of the payment of 119 consecutive monthly installments of U.S.$ 623,457 without taxes and an option to purchase for the same amount payable at the end of the 120th month of the effectiveness of the contract.

Pre-export finance

On November 5, 2019, the Company agreed with Itaú Unibanco S.A. the granting of a loan for US $ 17 million in order to pre-finance the exports of propane, butane and natural gasoline made. The characteristics of this loan are as follows:

Amount in US$	17,000,000
Interest Rate	LIBOR + 1.95%

	Scheduled payment date	Percentage of the principal to be paid
Amortization	March 4, 2020	100%
Frecuency of interest payment	Monthly, payable on December 4,2019, January 6, 2020, February 4, 2020 and March 4, 2020
Guarantor	US Treasury bills *
* Included in “Other financial assets at amortized cost.”

As of the date of issuance of these Financial Statements, this loan is fully paid.

F-243

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

14. INCOME TAX AND DEFERRED TAX

Tax Reform

The Tax Reform sanctioned in Argentina in 2017, with some amendments introduced in December 2018 after the issuance of Law No. 27,468, brought with it a series of modifications in the taxation and calculation of the income tax to which the Company is subject in the normal course of its activities. Subsequently, on the occasion of the enactment of the Solidarity Law, new modifications were introduced with impact as of the fiscal year beginning on January 1, 2019. The main changes are the following:

Reduction in the applicable rate

Until the fiscal year ended on December 31, 2017, the income tax rate remained at 35%. The tax reform establishes a gradual reduction of the applicable rate for the calculation of income tax, being 30% and 25% for fiscal periods beginning on January 1, 2018 and 2019 and January 1, 2020 onwards, respectively.

The reduction in the applicable rate is complemented by the application of a tax on the distribution of dividends made to human persons and foreign beneficiaries, which the Company must withhold and enter the Tax authority as a single and definitive payment when the dividends are paid. This additional tax will be 7% or 13%, depending on whether the dividends distributed correspond to earnings of a fiscal period in which the Company was reached at the rate of 30% or 25%, respectively. For these purposes it is considered, without admitting proof to the contrary, that the dividends that are made available correspond, firstly, to the oldest accumulated earnings.

Solidarity Law suspended until fiscal years starting from 1st January 2021 inclusive, reduced to 25% of the applicable rate and retention of 13% on dividends.

Tax adjustment for inflation

This section was subsequently modified by Law No. 27,468, which establishes that in the net taxable income of the periods beginning on or after January 1, 2018, the adjustment for inflation obtained by the application of the income tax law may be deducted or incorporated into the tax result for the fiscal year. This adjustment will proceed only if the percentage variation in the IPC, will accumulate (a) a percentage higher than 100% in the 36 months prior to the end of the year, or (b) regarding the first, second and third fiscal year that starts from its effective date, an accumulated variation of the IPC that exceeds 55%, 30% or 15% of said 100%, respectively.

For the fiscal year ended December 31, 2019, the CPI has exceeded the 30% threshold mentioned above, so the Company has measured the tax charge to earnings for the year ended December 31, 2019 considering the application of the adjustment for fiscal inflation.

According to the Solidarity Law, the positive or negative result generated by the application of the inflation adjustment corresponding to the first and second fiscal year beginning on January 1, 2019 will be charged in a sixth in that fiscal period and the five sixths remaining in equal parts in the following 5 fiscal periods.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Adjustment of acquisitions and investments made in fiscal years beginning on or after January 1, 2018

A cost adjustment mechanism is established for assets acquired or investments made in fiscal years beginning on or after January 1, 2018. The adjustment will be made based on the percentage variations of the WPI. This adjustment mechanism will have a significant impact on the calculation of future taxable profits on which the Company must pay the income tax.

Tax revaluation

It established the possibility of carrying out a tax revaluation, for a single time, of certain assets that are part of the assets as of December 31, 2017, in order to adjust their value.

This revaluation was optional, and to carry out the tax revaluation, a special tax must be paid. The special tax varied between 8% and 15%, depending on the type of asset to be re-evaluated between the difference of the residual revalued tax value and the residual tax value of origin.

Once the option for a certain good is exercised, all other goods in the same category must be revalued.

This tax is not deductible from income tax, and the asset increase that originates the revaluation is neither taxable for income tax nor taxable for the purposes of the TOMPI liquidation.

The taxpayers that exercised the revaluation option has waived to promote any judicial or administrative process for which the adjustment for tax inflation is claimed.

The Board of Directors decided to make use of this option, which implies a one-time payment of Ps. 1,612,164. Said tax paid and the tax revaluation benefit of Ps. 6,447,872, were recorded under the line “Income Tax” of the Statement of Financial Position for the year ended December 31, 2018.

Deferred Tax

The reconciliation between the charge computed for tax purposes and the income tax expense charged to the statement of comprehensive income in the years ended December 31, 2019, 2018 and 2017 is as follows:

	2019			2018			2017
Current income tax		(2,682,261	)		(4,920,109	)		(3,757,523	)
Special revaluation tax		-			(1,612,164	)		-
Deferred income tax		(1,341,950	)		6,512,012			3,839,173
Total income tax		(4,024,211	)		(20,261	)		81,650

F-245

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The analysis of the net deferred tax assets and liabilities is as follows:

	2019			2018
Deferred tax assets:
Deferred tax assets to be recovered after more than 12 months		996,567			1,044,262
Deferred tax assets to be recovered after less than 12 months		273,287			231,200
Deferred tax liabilities:
Deferred tax liabilities to be recovered after more than 12 months		(6,002,822	)		(4,527,584	)
Deferred tax liabilities to be recovered after less than 12 months		(29,546	)		(168,442	)
Deferred tax liabilities, net		(4,762,514	)		(3,420,564	)

The components of the net deferred tax assets and liabilities as of December 31, 2019, 2018 and 2017 are the following:

Deferred tax assets	Allowance for doubtful accounts		Tax credits discounted value loss			Account receivables discounted value			Provisions for legal claims and other provisions			Financial lease			Contract liabilities		Tax inflation adjustment		Total
As of December 31, 2017		-		-			-			173,575			516,052			436,324		-		1,125,951
Charge in results		-		596			3,497			(18,349	)		110,929			52,838		-		149,511
As of December 31, 2018		-		596			3,497			155,226			626,981			489,162		-		1,275,462
Charge in results		731		(240	)		(2,766	)		(375	)		(26,711	)		14,925		8,828		(5,608	)
As of December 31, 2019		731		356			731			154,851			600,270			504,087		8,828		1,269,854

Deferred tax liabilities	Deferred sales			Loans			Property, Plant and Equipment			Cash and cash equivalents			Inventaries			Other financial assets at amortized cost			Tax inflation adjustment			Total
As of December 31, 2017		-			(5,633	)		(11,016,028	)		(25,325	)		(11,541	)		-			-			(11,058,527	)
Charge in results		4,367			(42,180	)		6,527,245			(120,683	)		(6,248	)		-			-			6,362,501
As of December 31, 2018		4,367			(47,813	)		(4,488,783	)		(146,008	)		(17,789	)		-			-			(4,696,026	)
Charge in results		(4,367	)		21,547			139,697			143,880			(2,346	)		(1,864	)		(1,632,889	)		(1,336,342	)
As of December 31, 2019		-			(26,266	)		(4,349,086	)		(2,128	)		(20,135	)		(1,864	)		(1,632,889	)		(6,032,368	)

Income tax expense computed at the statutory tax rate on pre-tax income differs from the income tax expense for the years ended December 31, 2019, 2018 and 2017 as follows:

	2019			2018			2017
Pre tax income		16,829,329			17,581,516			8,765,549
Statutory income tax rate		30	%		30	%		35	%
Pre tax income at statutory income tax rate
		(5,048,799	)		(5,274,455	)		(3,067,942	)
Tax effects due to:
- Restatement by inflation		2,039,603			371,340			(287,676	)
- Tax revalution benefit		-			6,447,872			-
- Special revalution tax		-			(1,612,164	)		-
- Adjustment affidavit previous year		136,641			(464	)		-
- Change in the taxe rate		-			-			3,437,625
- Tax inflation adjustment		(1,998,487	)		-			-
- Others		846,831			47,610			(357	)
Total income tax		(4,024,211	)		(20,261	)		81,650

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

15. PROVISIONS

The total amount of the Provisions are included in current liabilities.

	For legal claims and others
Balances as of 12/31/2017		445,962
Inflation adjustment restatement		(173,430	)
Additions		300,213		(1)
Uses		(1,211	)
Decreases		(557	)	(2)
Balances as of 12/31/2018		570,977
Inflation adjustment restatement		(241,044	)
Additions		272,477		(3)
Uses		(7,590	)
Decreases		(5,702	)	(2)
Balances as of 12/31/2019		589,118

⁽¹⁾ Ps. 185,473 are included in “Other operating expenses” and Ps. 114,740 in “Financial expenses”.

⁽²⁾ The total are included in “Other operating expenses”.

⁽³⁾ Ps. 161,826 are included in “Other operating expenses” and Ps. 110,651 in “Financial expenses”.

16. FINANCIAL RISK MANAGEMENT

1. Financial risk factors

The Company’s activities and the market in which it operates expose it to a series of financial risks: market risk (including foreign exchange risk, interest rate risk, and commodity price risk), credit risk and liquidity risk.

The Company’s risk management framework establishes that a risk map is determined that measures the potential impact of each of them on the financial situation and results of operations. Based on this, the Executive Officers are responsible for defining the policies, procedures, limits and measures aimed at mitigating the impact of said risks.

The sensitivity analyzes included below are based on the change in one of the factors while all others remain constant. In practice, this is unlikely to happen, and changes in several factors can be correlated, for example, in variations in the interest rate and variations in the foreign currency exchange rate.

Sensitivity analysis only provides limited vision, at one point in time. The actual impact on the Company’s financial instruments could vary significantly with respect to the impact shown in the sensitivity analysis.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

2. Foreign exchange risk

The Company is primarily exposed to the fluctuation of the exchange rate of the U.S. dollar against the Argentine Peso due to the fact that almost its entire financial indebtedness is denominated in U.S. dollars. The exposure to other currencies is not significant.

As regards to the revenue derived from the Natural Gas Transportation segment, the tariffs charged by the Company are currently denominated in Argentine pesos. On the other hand, revenues in US dollars derived from the Liquids Production and Commercialization segment accounted for approximately 87%, 77% and 76% of the segment’s total revenues for the years ended December 31, 2019, 2018 and 2017, respectively. Total revenues denominated in Argentine Pesos accounted for 53%, 59% and 51% for the years ended December 31, 2019, 2018 and 2017, respectively.

TGS’s financial risk management policies are defined with the objective of mitigating the impact that the variation in the exchange rate has on the Company’s position in foreign currency. For this purpose, alternative investment evaluations are regularly carried out to diversify investments in financial instruments portfolio between US dollar-denominated instruments or, although denominated in Argentine pesos, to obtain positive returns in real terms.

Additionally, in the event that it is considered appropriate, the Company contracts derivative financial instruments that allow TGS to hedge the fluctuation of the US dollar over long-term positions in such currency. During the years 2019, 2018 and 2017, the Company did not contract derivative financial instruments to cover this risk.

However, the Company managed to mitigate the impact on the exchange rate variation by placing funds in assets denominated in US dollars. As of December 31, 2019, for mitigating this foreign exchange risk, 88% of the Company’s fund placements are denominated in US dollars.

Considering the net liability financial position described in the table below, the Company estimated that, other factors being constant, a 10% appreciation of the US dollar against the Argentine Peso for the years ended December 31, 2019, 2018 and 2017 would have decreased the Company’s pretax income for the year in approximately Ps. 2,564,896, Ps. 1,138,128, and Ps. 399,846, respectively. A 10% depreciation of the US dollar against the Argentine Peso would have an equal and opposite effect on the pre-tax income. Actual results may differ significantly from these theoretical sensitivity scenarios.

1.2          Interest rate risk

The management of interest rate risk seeks to reduce financial costs and limit the Company’s exposure to an increase in interest rates. Currently, the Company’s exposure to interest rate risk is limited due to the fact that 100% of its outstanding financial indebtedness bears fixed interest rates. The interest rate profile of the Company’s borrowings is set out in Note 13.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

The main objective of the Company’s financial investment activities is to obtain the highest return by investing in low risk and high liquidity instruments. The Company maintains a short-term portfolio of cash equivalents and investments made up of investments in mutual funds and deposits in remunerated bank accounts, public and private securities. The risk of these instruments is low given the short-term nature and high liquidity in well-known financial institutions.

As a consequence of the application of IAS 29, maintaining monetary assets generates loss of purchasing power, provided that such items are not subject to an adjustment mechanism that compensates to some extent the loss of purchasing power. This loss of purchasing power is included in the result of the period under gain on the net monetary position. On the contrary, maintaining monetary liabilities generates a gain in purchasing power, which are also included in such line item.

The Company’s risk management policy is defined with the objective of reducing the impact of the loss of purchasing power. During the 2017, 2018 and 2019 fiscal years the Company has maintained a liability monetary position. As a consequence, TGS has recorded a net gain from exposure to inflation in the monetary items.

The following table shows a breakdown of the Company’s fixed-rate and floating-rate financial assets and liabilities as of December 31, 2019 and 2018:

	Financial assets (1)				Financial liabilities (2)
	2019		2018		2019		2018
Fix interest rate		8,650,353		13,114,538		30,184,039		29,138,384
Variable interest rate		1,038,402		22,264		1,021,325		-
Total		9,688,755		13,136,802		31,205,364		29,138,384

⁽¹⁾ Includes mutual funds, Letes, Lebacs and bank accounts. Trade receivables do no bear interests, except for Ps. 8,758 and Ps. 22,264, which bears CER plus a spread of 8% as of December 31, 2019 and 2018, respectively.

⁽²⁾ Includes loans, issuance expenses and financial leasing

In view of the nature of the Company’s financial assets which bear variable interest, an immediate 100 basis points decrease in the interest rate would not have a significant impact on the total value of the financial assets.

1.3          Commodity price risk

Commercial operations performed by the Company in its Liquids Production and Commercialization segment are affected by a number of factors beyond its control, including changes in the international prices of the products sold, and government regulations on prices, taxes and other charges, among others.

The sale prices of propane and butane (“LPG”) and natural gasoline the Company exports in its Liquids Production and Commercialization segment are referenced to international prices (Mont Belvieu for the LPG and NWE ARA for the natural gasoline). Additionally, approximately 59% of the total sales of propane and butane that are made in the domestic market are made at prices fixed by the Hydrocarbon Resources Secretariat (“SRH” for its acronym in Spanish) based on export parity prices.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

These prices have historically been cyclical, reflecting overall economic conditions and changes in capacity within the industry, which may affect the profitability of TGS.

Based on the volume of sales for the years ended December 31, 2019, 2018 and 2017, the Company estimated that, other factors being constant, a decrease of U.S.$50/ton in the international price of LPG and natural gasoline, respectively, would have decreased the Company’s net comprehensive income in its Liquids Production and Commercialization segment in Ps. 1,153,105, Ps.849,161 and Ps. 233,323 respectively. On the other hand, an increase of U.S.$50/ton in the international price would have had the opposite effect.

Derivated financial instruments

On July 23, 2018, TGS entered into an agreement with a recognized financial institution to hedge export prices for propane, butane and natural gasoline (put contracts), in order to offset potential losses that could arise if export prices fall below breakeven prices (those that balance costs). This agreement is valid between October 2018 and April 2020, according to the following monthly short tons:

Period	Propane		Butane		Natural gasoline
October 2018 – April 2019		6,663		4,967		2,976
May 2019 – September 2019		-		-		4,519
October 2019		9,996		7,727		4,630
November 2019 – April 2020		14,438		11,038		6,614

In order to arrange such operation, the Company paid a premium of U.S.$ 3 million, which was classified as a financial asset measured at fair value through profit or loss, being recorded under “Derivative financial instruments”. The Company has not designated those instruments for the application of hedge accounting in accordance with the provisions of IFRS 9.

As of December 31, 2019 and 2018, the balance is Ps. 274,024 and Ps. 335,773, respectively, and is recorded under the item “Derivative Financial instruments”.

1.4          Credit risk

The Company’s exposures to credit risk takes the form of a loss that would be recognized if counterparties failed to, or were unable to, meet their payment obligations. These risks may arise in certain agreements in relation to amounts owed for physical product sales, the use of derivative instruments, and the investment of surplus cash balances. This risk mainly results from economic and financial factors or from a possible default of counterparty.

The Company is subject to credit risk arising from outstanding receivables, cash and cash equivalents and deposits with banks and financial institutions, and from the use of derivative financial instruments. The Company’s policy is to manage credit exposure to trading counterparties within defined trading limits.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Trade and Other Receivables

If any of the Company’s customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, the Company assesses the credit quality of the customer taking into account its financial position, past experience and other factors. The Company may seek cash collateral, letter of credit or parent company guarantees, as considered appropriate.

As of December 31, 2019 and 2018, the balance of current and non-current trade receivables, net of allowances of doubtful accounts are as follows:

	2019			2018
Current trade receivables		6,608,715			4,994,969
Allowances for doubful accounts		(134,956	)		(203,860	)
Total		6,473,759			4,791,109

The Company, in the normal course of business, renders natural gas transportation services, principally to gas distribution companies, CAMMESA and to Pampa Energía. Significant customers in terms of revenues and trade receivables (net of allowances of doubtful accounts) from natural gas transportation for the years ended December 31, 2019, 2018 and 2017 are as follows:

	2019				2018				2017
	Revenues		Trade receivables		Revenues		Trade receivables		Revenues
MetroGas		5,849,138		1,459,410		4,957,415		577,764		2,948,056
Camuzzi Gas Pampeana S.A.		4,353,024		729,137		3,682,320		430,212		2,167,208
Naturgy Argentina		3,496,055		567,429		2,971,396		368,782		1,556,829
CAMMESA		1,337,997		206,403		2,057,838		281,896		1,368,671
Pampa Energía		803,610		258,007		676,180		141,040		68,737
Camuzzi Gas del Sur S.A.		1,075,744		150,838		822,176		87,574		477,222

Revenues from Liquids Production and Commercialization customers net of allowances of doubtful accounts) for the years ended December 31, 2019, 2018 and 2017 are as follows:

	2019				2018				2017
	Revenues		Trade receivables		Revenues		Trade receivables		Revenues
PBB Polisur		6,338,222		841,338		8,102,817		1,090,359		5,667,118
Petredec		1,003,264		-		1,321,183		-		2,119,267
Geogas Trading S.A.		1,691,910		375,723		1,695,707		-		878,783
Shell Trading (US) Company		-		-		138,246		-		2,192,301
YPF		1,239,102		26,501		729,113		30,968		-
Petrobras Global Trading BV		4,446,241		397,172		2,682,539		211,387		-

Cash and financial placements

The Company is exposed to counterparty credit risk on cash and cash equivalent balances. The Company holds cash on deposit with a number of financial institutions. The Company manages its credit risk exposure by limiting individual deposits to clearly defined limits in various financial institutions. The Company considers that this risk is limited because it has short-term funds policies whose main objective is to obtain an adequate return in terms of market characteristics and minimizing exposure. The Company only deposits with high quality banks and financial institutions with a high credit rating. The maximum exposure to credit risk is represented by the carrying amount of cash and cash equivalents in the statement of financial position.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Below is a detail of the maturities of the financial assets included in: (i) cash and cash equivalents, (ii) other financial assets, (iii) trade receivables, (iv) other receivables and (v) derivate financial instruments, as of December 31, 2019 and 2018:

December 31, 2019
	Cash and cash equivalents		Other financial assets		Credits (1) (2)
Without specified maturity		9,650,787		-		21,607
With specified maturity
Overdue
Until 12-31-2018		-		-		144,596
From 01-01-19 to 03-31-19		-		-		1,538
From 04-01-19 to 06-30-19		-		-		4,245
From 07-01-19 to 09-30-19		-		-		343,827
From 10-01-19 to 12-31-19		-		-		791,533
Total overdue		-		-		1,285,739
Non-due
From 01-01-20 to 03-31-20		114,414		1,315,640		5,271,983
From 04-01-20 to 06-30-20		-		796		482,630
From 07-01-20 to 09-30-20		-		775		8,105
From 10-01-20 to 12-31-20		-		773		10,092
During 2021		-		3,043		6,943
During 2022		-		1,911		-
During 2023		-		449		-
During 2024		-		-		-
From 2025 onwards		-		-		-
Total non-due		114,414		1,323,387		5,779,753
Total with specified maturity		114,414		1,323,387		7,065,492
Total		9,765,201		1,323,387		7,087,099

⁽¹⁾ The total amount of the receivables without specified maturity is recorded in Non-current assets.

⁽²⁾ Includes financial assets recorded in trade receivables and other receivables, excluding allowance for doubtful accounts.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

December 31, 2018
	Cash and  cash equivalents		Other financial assets		Credits (1) (2)
Without specified maturity		22,283,431		-		718
With specified maturity
Overdue
Until 12-31-2017		-		-		205,783
From 01-01-18 to 03-31-18		-		-		477
From 04-01-18 to 06-30-18		-		-		6,184
From 07-01-18 to 09-30-18		-		-		17,537
From 10-01-18 to 12-31-18		-		-		823,940
Total overdue		-		-		1,053,921
Non-due
From 01-01-19 to 03-31-19		3,321,706		338,073		4,530,803
From 04-01-19 to 06-30-19		-		2,300		63,313
From 07-01-19 to 09-30-19		-		2,300		-
From 10-01-19 to 12-31-19		-		1,894		-
During 2020		-		5,161		8,505
During 2021		-		4,683		-
During 2022		-		2,940		-
During 2023		-		688		-
From 2024 onwards		-		-		-
Total non-due		3,321,706		358,039		4,602,621
Total with specified maturity		3,321,706		358,039		5,656,542
Total		25,605,137		358,039		5,657,260

⁽¹⁾ The total amount of the receivables without specified maturity is recorded in Non-current assets.

⁽²⁾ Includes financial assets recorded in trade receivables and other receivables, excluding allowance for doubtful accounts.

1.5          Liquidity risk

This risk implies the difficulties that TGS may have in fulfilling its commercial and financial obligations. To this purpose, the expected flow of funds is regularly monitored.

The Company has funding policies whose main objectives are to meet the financing needs at the lowest cost possible according to market conditions. The main objective of the Company is its financial solvency. Given the current financial market conditions, the Company believes that the availability of resources (including available credit lines) and the positive cash flow from operations are sufficient to meet its current obligations.

Additionally, TGS applies a methodology for analyzing and assigning credit limits to individual financial institutions in order to minimize the associated credit risk. In line with this, the Company invests its liquid funds in certain financial institutions with an appropriate credit rating.

The tables below include a detail of the maturities of the obligations corresponding to financial liabilities corresponding to: trade payables, payroll payables, other payables and loans as of December 31, 2019 and 2018. The amounts disclosed in the table are the contractual undiscounted cash flows and as a result, they do not reconcile to the amounts disclosed on the statement of  financial position. These tables are made based on available information at the end of each year and may not reflect the actual amounts in the future. Therefore, the amounts disclosed are provided for illustrative purposes only:

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

December 31, 2019
	Loans		Other financial liabilities		Leases liabilities
Without specified maturity		-		-		-
With specified maturity
Overdue
Until 12-31-2018		-		130,829		-
From 01-01-19 to 03-31-19		-		311		-
From 04-01-19 to 06-30-19		-		311		-
From 07-01-19 to 09-30-19		-		311		-
From 10-01-19 to 12-31-19		-		311		90,363
Total overdue		-		132,073		90,363
Non-due
From 01-01-20 to 03-31-20		1,027,502		3,745,057		111,994
From 04-01-20 to 06-30-20		1,010,644		32,769		111,994
From 07-01-20 to 09-30-20		-		-		111,994
From 10-01-20 to 12-31-20		1,010,644		-		111,994
During 2021		2,021,288		-		448,037
During 2022		2,021,288		-		448,037
During 2023		2,021,288		-		448,037
During 2024		2,021,288		-		448,037
From 2025 onwards		30,955,641		-		715,686
Total non-due		42,089,583		3,777,826		2,955,810
Total with specified maturity		42,089,583		3,909,899		3,046,173
Total		42,089,583		3,909,899		3,046,173

December 31, 2018
	Loans		Other financial liabilities		Financial leases
Without specified maturity		-		-		-
With specified maturity
Overdue
Until 12-31-2017		-		159,366		-
From 01-01-18 to 03-31-18		-		478		-
From 04-01-18 to 06-30-18		-		478		-
From 07-01-18 to 09-30-18		-		478		-
From 10-01-18 to 12-31-18		-		478		87,517
Total overdue		-		161,278		87,517
Non-due
From 01-01-19 to 03-31-19		-		5,157,610		108,450
From 04-01-19 to 06-30-19		978,663		33,442		108,450
From 07-01-19 to 09-30-19		-		-		108,450
From 10-01-19 to 12-31-19		978,663		-		108,450
During 2020		1,957,325		-		433,860
During 2021		1,957,325		-		433,860
During 2022		1,957,325		-		433,860
During 2023		1,957,325		-		433,860
From 2024 onwards		31,933,396		-		1,126,898
Total non-due		41,720,022		5,191,052		3,296,138
Total with specified maturity		41,720,022		5,352,330		3,383,655
Total		41,720,022		5,352,330		3,383,655

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Capital risk management

The objective of the Company in capital management are to safeguard the ability to continue as a going concern, achieve an optimal cost of capital structure and support the capital expenditures process in order to provide returns to the shareholders and benefits for other stakeholders.

The Company seeks to maintain a level of cash generation from operating activities, which may allow it to meet all of its commitments.

The Company monitors capital on the basis of the gearing ratio. This ratio is calculated as total financial debt (including current and non-current loans as shown in the consolidated statement of financial position, if applicable) divided by total capital. Total capital is calculated as equity, as shown in the consolidated statement of financial position, plus total debt.

During the year ended December 31, 2019 and 2018, the gearing ratio was as follows:

	2019		2018
Total debt (Note 13)		33,582,804		31,684,940
Total Equity		48,083,469		47,603,906
Total Capital		81,666,273		79,288,846
Gearing Ratio		0.41		0.4

2. FINANCIAL INSTRUMENTS BY CATEGORY AND HIERARCHY

2.1          Financial instrument categories

Accounting policies for the categorization of financial instruments are explained in Note 4.e. According to the provisions of IFRS 7, IAS 32 and IFRS 9 (IAS 39 as of December 31, 2017), non-financial assets and liabilities such as PPE, investments in associates, inventories, advances from customers, deferred income tax, taxes and social taxes payables and provisions are not included.

The categories of financial assets and liabilities as of December 31, 2019 and 2018 are as follows:

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	December 31, 2019
	Financial assets at fair value		Financial assets at amortizef cost		Total
CURRENT ASSETS
Trade receivables		-		6,473,759		6,473,759
Other receivables		-		473,216		473,216
Derivative financial instruments		274,024		-		274,024
Other financial assets at amortized cost		-		1,043,960		1,043,960
Cash and cash equivalents		1,029,644		8,735,557		9,765,201
Total current assets		1,303,668		16,726,492		18,030,160
NON-CURRENT ASSETS
Other receivables		-		7,603		7,603
Other financial assets at amortized cost		-		5,403		5,403
Total non-current assets		-		13,006		13,006
Total assets		1,303,668		16,739,498		18,043,166

	Financial liabilities at fair value		Other financial liabilities		Total
CURRENT LIABILITIES
Trade payables		-		4,113,571		4,113,571
Loans		-		1,722,087		1,722,087
Payroll and social security taxes payables		-		533,497		533,497
Other payables		-		287,659		287,659
NON-CURRENT LIABILITIES
Loans		-		31,860,717		31,860,717
Total non-current liabilities		-		31,860,717		31,860,717
Total liabilities		-		38,517,531		38,517,531

F-256

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	2018
	Financial assets at fair value		Financial assets at amortirzed cost		Total
CURRENT ASSETS
Trade receivables		-		4,791,109		4,791,109
Other receivables		-		652,771		652,771
Derivative financial instruments		335,773		-		335,773
Other financial assets at amortized cost		-		8,790		8,790
Cash and cash equivalents		3,324,575		22,280,562		25,605,137
Total current assets		3,660,348		27,733,232		31,393,580
NON-CURRENT ASSETS
Other receivables		-		9,521		9,521
Other financial assets at amortized cost		-		13,476		13,476
Total non-current assets		-		22,997		22,997
Total assets		3,660,348		27,756,229		31,416,577

	Financial liabilities at fair value		Other financial liabilities		Total
CURRENT LIABILITIES
Trade payables		-		4,756,554		4,756,554
Loans		-		681,225		681,225
Payroll and social security taxes payables		-		475,882		475,882
Other payables		-		124,103		124,103
Total current liabilities		-		6,037,764		6,037,764
NON-CURRENT LIABILITIES
Loans		-		31,003,715		31,003,715
Total non-current liabilities		-		31,003,715		31,003,715
Total liabilities		-		37,041,479		37,041,479

2.2          Fair value measurement hierarchy and estimates

According to IFRS 13, the fair value hierarchy introduces three levels of inputs. These levels are:

• Level 1: includes financial assets and liabilities whose fair values are estimated using quoted prices (unadjusted) in active markets for identical assets and liabilities. The instruments included in this level primarily include balances in mutual funds and public or private bonds listed on the BYMA. The mutual funds mainly carry out their placements in bonds issued by the Central Bank of the Argentine Republic (“BCRA”).

• Level 2: includes financial assets and liabilities whose fair value is estimated using different assumptions quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (for example, derived from prices). Within this level, the Company includes those derivate financial instruments for which it was not able to find an active market.

F-257

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

• Level 3: includes financial instruments for which the assumptions used in estimating fair value are not based on observable market information.

During 2019 and 2018, there were neither transfers between the different hierarchies of fair values nor reclassifications between financial instruments categories.

The table below shows different assets and liabilities at their fair value classified by hierarchy as of December 31, 2019 and 2018:

	As of December 31, 2019
	Level 1		Level 2		Level 3		Total
Financial assets at fair value
Cash and cash equivalents		1,029,644		-		-		1,029,644
Derivative financial instruments		-		274,024		-		274,024
Total		1,029,644		274,024		-		1,303,668

	As of December 31, 2018
	Level 1		Level 2		Level 3		Total
Financial assets at fair value
Cash and cash equivalents		3,324,575		-		-		3,324,575
Derivative financial instruments		-		335,773		-		335,773
Total		3,324,575		335,773		-		3,660,348

The fair value of the financial assets and liabilities is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

As of December 31, 2019, the carrying amount of certain financial instruments used by the Company including cash, cash equivalents, other investments, receivables, payables and short-term loans are representative of fair value because of the short-term nature of these instruments.

The following table reflects the carrying amount and estimated fair value of the 2018 Notes as of December 31, 2019, based on their quoted market price:

	As of December 31, 2019
	Carrying amount		Fair value
2018 Notes		30,184,039		26,266,856

17. REGULATORY FRAMEWORK

a) General framework of the natural gas transportation segment:

General aspects

Regarding TGS’ Natural Gas Transportation business, it is regulated by Law No. 24,076 (“the Natural Gas Act”), its regulatory Decree No. 1,738/92 and the Regulatory framework for the transportation and distribution of natural gas in Argentina. The Natural Gas Act created ENARGAS, which is entitled, among other things, to set the basis for the calculation, monitoring, approval of tariffs and the power to verify compliance with the Natural Gas Law and its regulations. On January 28, 2016, Resolution No. 7 of the MINEM of Argentina repealed the Resolution 2000/2005 of the former Ministry of MPFIPyS which provided that all tariff increases should have the prior intervention of the Undersecretary of Coordination and Management Control.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

TGS License has been granted for an original period of 35 years beginning on December 28, 1992. However, the Natural Gas Act provides that TGS may apply to ENARGAS for a renewal of its license for an additional period of ten years. ENARGAS should evaluate at that time the performance of TGS and raise a recommendation to the Executive Branch. At the end of the period of validity of the license, 35 or 45, as appropriate, the Natural Gas Act requires a call for a new tender for the granting of a new license, in which TGS, provided the Company fulfilled substantially with the obligations resulting from the license, would have the option of matching the best offer that the Government received in this bidding process.

Tariff situation

Prior the enactment of the Public Emergency Law, and according to the Regulatory Framework, transportation tariffs were to be calculated in US dollars and converted into Argentine pesos at the time the customer was billed using the exchange rate prevailing at the date of the billing. The basic natural gas transportation tariffs charged by TGS had been established at the time of the privatization of GdE and were to be adjusted, subject to prior authorization, in the following cases: (i) semiannually to reflect changes in the US producer price index (“PPI”) and (ii) every five years according to efficiency and investment factors determined by ENARGAS. The “efficiency factor” was a reduction to the base tariff resulting from future efficiency programs while the “investment factor” increased the tariffs to compensate the licensees for future investments which were not repaid through tariffs. Also, subject to ENARGAS approval, tariffs were to be adjusted to reflect non-recurrent circumstances or tax changes, other than income tax.

The terms and conditions as described in the precedent paragraph in connection with tariff adjustments contemplated within the Regulatory Framework are no longer effective since the enactment of the Public Emergency Law in early 2002, which, among other provisions, eliminated tariff increases based on US dollar exchange rate fluctuations, foreign price indexes or any other indexing procedure and established a conversion rate of one peso to one US dollar for tariffs. The Public Emergency Law also granted the Executive Branch power to renegotiate contracts entered into with private utility companies, pursuant to the framework included in such law as long as it is in force, which expired on December 31, 2017, after several extensions.

Between July 2003 and March 2018, the Company received a series of temporary tariff increases under the framework of the Integral Tariff Review (“RTI” for its acronym in Spanish) process initiated after the Public Emergency Law was passed.

F-259

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

On March 27, 2018, the Executive Branch of the Argentine Government issued the Decree No. 250/2018 (the “Decree 250”) ratifying the 2017 Integral Agreement. This decree represents the conclusion of the RTI process and the completion of the 2017 Transitional Agreement, and thus, the final renegotiation of the license after seventeen years of negotiations.

The 2017 Integral Agreement sets the guidelines for the provision of the natural gas transportation service until the end of the License. Among these guidelines:

• The RTI Process, which will culminate in the signing of the integral agreement, was approved. As a result of this RTI, a new tariff schedule was also approved. This new tariff schedule applicable to the Company determined a total tariff increase of 214.2% and 37%, in the event that it had been granted in a single installment as of April 1, 2017, on the tariff of the natural gas transportation service and the CAU, respectively.

• The Five-Year Investment Plan was approved. Resolution 4362 obliged TGS for the execution of the Five-Year Plan, which requires a high level of essential investments for the operation and maintenance of the pipeline system, to provide quality, safe and reliable service. The Five-Year Plan shall be for the period from April 1, 2017 to March 31, 2022 and will amount to Ps. 6,786,543, expressed in December 31, 2016 currency terms.

• A non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments were approved. This adjustment must be approved by ENARGAS and for its calculation, the evolution of the WPI published by INDEC will be considered.

• TGS and its shareholders must withdraw any claim against the Government related to the natural gas transportation business, including the arbitration proceedings before the ICSID. The Company desisted from it on June 26, 2018.

As it is mentioned above the tariff increase was granted in 3 installments according to the following resolutions:

• Effective as of April 1, 2017, 64.2% of the tariff for the natural gas transport service, the CAU not being adjusted, in accordance with the provisions of Resolution No. 4362/2017 (“Resolution 4362”).

• Effective as of December 1, 2017, after the issuance of Resolution 120, 81.1% on the tariff for the natural gas transport service and 29.7% on the CAU, which includes the first adjustment by WPI.

 

• Effective as of April 1, 2018, an increase of 50% over the tariff for the natural gas transport service and the CAU within the framework of the provisions of Resolution No. 310/2018 issued by ENARGAS.

F-260

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Semiannual tariff increase

This increase is granted within the framework of the semi-annual tariff adjustment of the natural gas transportation service in accordance with the provisions of the RTI process.

In the public hearing held on September 4, 2018, in which the Company requested, based on the variation of the WPI recorded for the period February - August 2018, a tariff increase of approximately 30%. Considering the hearing, on September 27, 2018, ENARGAS issued Resolution No. 265/2018 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 WPI, the Construction Cost Index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018.

It is noteworthy that ENARGAS supported the determination of the aforementioned tariff increase in the provisions of Resolution 4362, 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 WPI to determine the tariff increase. TGS notified ENARGAS its disagreement with respect to the methodology for calculating the semi-annual adjustment.

On March 29, 2019, ENARGAS issued Resolution No. 192/2019 (“Resolution 192”) that approved, effective as of April 1, 2019, a 26% increase in the tariff chart applicable to the public service of natural gas transportation by TGS in force as of March 31, 2019.

In accordance with current regulations, ENARGAS has considered the evolution of the wholesale price index update index (“WPI”) between the months of August 2018 and February 2019, in order to define the semi-annual adjustments applicable to TGS tariffs.

Regarding the semi-annual tariff adjustment that was to be enforced as from October 1, 2019, on September 3, 2019, the SE issued Resolution No. 521/2019 (“Resolution 521”) postponing it to February 1, 2020.

The deferral also meant that the Company reviewed and fit, in equal proportion to the revenue that is no longer received, the execution of the Five-Year Investment Plan. As of the date of the issuance of these Consolidated Financial Statements, TGS made the proposal to ENARGAS and the corresponding approval resolution have not yet been issued.

Nevertheless, the Solidarity Law establishes that natural gas transportation and distribution tariffs will remain unadjusted for a maximum period of 180 days from December 23, 2019. In this sense, the Executive Branch is authorized to renegotiate them, either within the framework of the current RTI or through an extraordinary review in accordance with the provisions of the Natural Gas Law.

At the date of issuance of these financial statements, the administrative steps to normalize the Company’s tariff situation have not occurred.

Additionally, the Solidarity Law provides for the administrative intervention of ENARGAS.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Deferral of collections

On June 21, 2019, the Secretary of Energy issued Resolution N° 336/2019, which ordered the deferral of payment of 22% of the invoices issued between July 1, 2019 and October 31, 2019 corresponding to residential natural gas users.

The deferrals are recovered from the invoices issued from December 1, 2019 in five consecutive monthly installments in equal amount. As compensation, the National Government will pay the licensees, as a subsidy, an economic compensation for the financial cost involved in the deferral.

On August 22, 2019, the SE issued Resolution No. 488/2019 establishing the procedure for the calculation to be carried out by the distribution and sub-distribution companies of natural gas of the deferral provided by Resolution 336. Likewise, this resolution instructs the Undersecretariat of Hydrocarbons and Fuels of the Secretariat of Non-renewable Resources and Fuel Market of the SE to implement the procedure by which the compensation mentioned above will be calculated and paid. As of the date of the issuance of these consolidated financial statements, the regulations for the calculation and payment methodology of the economic compensation mentioned above were not issued.

As of December 31, 2019, the Company has trade receivables with natural gas distribution companies for Ps. 1,206,030 for such concepts.

b)          General Framework for non-regulated segments

Domestic market

The Production and Commercialization of Liquids segment is not subject to regulation by ENARGAS, and as it is provided in the Transfer Agreement, is organized as a separate business unit within TGS, keeping accounting information separately. However, over recent years, the Argentine Government enacted regulations which significantly impacted on it.

In April 2005, the Argentine Government enacted Law No. 26,020 which sets forth the regulatory framework for the industry and commercialization of LPG. Among other things, the Law No. 26,020 creates the framework through which the Secretary of Hydrocarbon Resources (“SHR”) (formerly the Federal Energy Bureau) establishes regulations meant to cause LPG suppliers to guarantee sufficient supply of LPG in the domestic market at low prices. Law No. 26,020 creates a price regime pursuant to which the SRH periodically publish reference prices for LPG sold in the domestic market. It also sets forth LPG volumes to be sold in the domestic market.

On March 30, 2015, the Executive Branch issued Decree No. 470/2015, regulated by Resolution No. 49/2015 issued by the Federal Energy Bureau, which created the Programa Hogares con Garrafa (the “Households with Bottles Program”) which replaced the programs in force until that time. The Households with Bottles Program was implemented through Resolutions No. 49/2015 and No. 470/2015 issued by the Federal Energy Bureau.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Within the framework of the Households with Bottles Program, a maximum reference price was determined for the members of the commercialization chain in order to guarantee the supply to low-income residential users, forcing producers to supply with LPG at a certain price and at a certain quantity defined for each of them. Additionally, the payment of compensation to the participating producers of the Households with Bottles Program was established.

The current price of butane and propane marketed under this program, after successive modifications and according to Provision No. 104/2019 issued by the SHR and Fuels, is $ 9,895 and $ 9,656 per ton, respectively. No compensation has been set for these products.

In this context, the Company 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, the Company 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 by which it undertakes to supply propane to the domestic market at a lower price to the market. In compensation, the Company receives an economic compensation calculated as the difference between the sales price and the export parity determined by the ex-MINEM.

On March 31, 2017, the MINEM issued Resolutions No. 74 and 474-E/2017 (“Resolution 474”) that stipulate increases in the price of undiluted propane gas destined to the Propane for Networks Agreement as of April 1 and December 1, 2017, respectively. From those dates onwards, the price of undiluted propane gas has been set at Ps. 1,267/ton and Ps. 2,832/ton (in accordance with Resolution 74) and Ps. 1,941.20/ton and Ps. 3,694/ton (in accordance with Resolution 474), respectively, depending on the client to whom the undiluted propane gas is delivered.

Finally, in May 2018, the Company signed the sixteenth extension by which the methodology for determining the price and volumes for the period April 1, 2018 - December 31, 2019 is established. Additionally, this last extension set the price for which the propane destined for this program was marketed to the client. At the date of issuance of these Financial Statements, a new agreement has not been concluded. Notwithstanding the foregoing, on January 14, 2020 TGS received the instruction issued by the Ministry of Energy to continue with propane deliveries in accordance with the conditions of the sixteenth extension of the Propane Agreement for Networks.

During 2019 and 2018, the Company received the amount of Ps. 468,494 and Ps. 625,678, for subsidies for the programs mentioned above, respectively.

As mentioned earlier, participation in the Households with Bottles Program implies economic and financial damages for the Company, because under certain circumstances the sale of the products would be carried out at prices that are below the production costs.

F-263

 

TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

As of December 31, 2019, the Argentine Government owes the Company Ps. 143,829 for these concepts.

Foreign market

On September 3, 2018, the Executive Branch issued Decree No. 793/2018, which, between September 4, 2018 and December 31, 2020, sets an export duty of 12% on the exported amount of propane, butane and natural gasoline. This withholding is capped at $4 for each dollar of the tax base or the official FOB price.

Subsequently, on the occasion of the enactment of the Solidarity Law, an 8% cap was established for the rate applicable to hydrocarbons as of December 23, 2019.

Decree No. 2,067 / 08

Through Presidential Decree No. 2,067/08, the Executive Branch created a tariff charge to be paid by (i) the users of regulated services of transportation and / or distribution, (ii) natural gas consumers receiving natural gas directly from producers without making use of transportation systems or natural gas distribution, (iii) the natural gas processing companies in order to finance the import of natural gas. The tariff charge sets forth in this decree finance the higher price of the natural gas imports required to compensate the injection of natural gas necessary to meet national requirements (the “Charge”). When the Charge was created, TGS paid it in accordance with the provisions of Resolution I-563/2008, at Ps. 0.0492/m3.

The payment of the natural gas processing tariff charge was selectively subsidized from 2008 according to the destination of the natural gas. In November 2011, however, ENARGAS issued Resolution No. 1,982/11 and 1,991/11 (the “Subsidy Beneficiaries Resolutions”) which modified the list of the subsidy beneficiaries, and thus, involved a cost increase for many of our clients and for us (for certain of our consumption for our own account). The natural gas processing tariff charge increased from Ps. 0.0492 to Ps. 0.405 per cubic meter of natural gas effective from December 1, 2011, representing a significant increase in our variable costs of natural gas processing.

In order to avoid this damage, TGS appealed against the Presidential Decree and the Resolutions including National Government, ENARGAS and ex MPFIPyS as defendants.

For further information regarding the legal action filed the Company, see Note 20.b).

On March 28, 2016, the MINEM issued Resolution No. 28/16 (“Resolution 28”), which instructs ENARGAS to take all the necessary measures to derogate the tariff charge created by Decree No. 2,067/08 as from April 1, 2016. However, such Resolution does not repeal or declare illegitimate this decree and the Subsidy Beneficiaries Resolutions for which the judicial action is still ongoing.

c)          Essential assets

A substantial portion of the assets transferred by GdE has been defined as essential for the performance of the natural gas transportation service. Therefore, TGS is required to keep separated and maintain these assets, together with any future improvements, in accordance with certain standards defined in the License.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

TGS may not, for any reason, dispose of, encumber, lease, sublease or loan essential assets nor use such assets for purposes other than the provision of the licensed service without ENARGAS´s prior authorization. Any expansion or improvements that it makes to the gas pipeline system may only be encumbered to secure loans that have a term of more than one year to finance such extensions or improvements.

Upon expiration of the License, TGS will be required to transfer to the Argentine government or its designee, the essential assets listed in an updated inventory as of the expiration date, free of any debt, encumbrances or attachments. If the Company decides not to continue with the license, TGS will receive a compensation equal to the lower of the following two amounts:

i) the net book value of the essential assets determined on the basis of the price paid by the acquiring joint arrangements, and the original cost of subsequent investments carried in US dollars and adjusted by the PPI, net of accumulated depreciation according to the calculation rules to be determined by ENARGAS; or

ii) the net proceeds of a new competitive bidding (the “New Bidding”).

Once the period of the extension of the License expires, TGS will be entitled to participate in the New Bidding, and thus, it shall be entitled to:

(i) that its bid in the New Bidding be computed at an equal to the appraisal value to be determined by an investment bank selected by ENARGAS, which represents the value of the business of providing the licensed service as it is driven by the Licensee at the valuation date, as a going concern and without regard to the debts;

(ii) to obtain the new License, without payment, in the event that any bid submitted in the New Bidding exceeds the appraised value;

(iii) to match the best bid submitted by third parties in the New Bidding, if it would be higher than its bid mentioned in (i) paying the difference between both values to obtain the new License;

(iv) if the Company is unwilling to match the best bid made by a third party, to receive the appraisal value mentioned in (i) as compensation for the transfer of the Essential Assets to the new licensee.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

18. ASSETS AND LIABILITIES IN FORREIGN CURRENCY

The balances in foreign currency as of December 31, 2019 and 2018 are detailed below:

	2019							2018
	Foreign currency and amount (in thousands)		Exchange rate			Amount in local currency		Foreign currency and amount (in thousands)		Amount in local currency
CURRENT ASSETS
Cash and cash equivalents	US$	143,920		59.690	(1)		8,590,585	US$	361,017		20,826,043
Derivative financial instruments	US$	4,591		59.690	(1)		274,024	US$	5,821		335,773
Other financial assets at amortized cost	US$	17,433		59.690	(1)		1,040,605		-		-
Trade receivables	US$	43,091		59.690	(1)		2,572,102	US$	30,380		1,752,536
Other receivables	US$	325		59.690	(1)		19,399	US$	1,693		97,665
Total current assets	US$	209,360					12,496,715	US$	398,911		23,012,017
CURRENT LIABILITIES
Trade payables	US$	59,595		59.890	(2)		3,569,145	US$	42,184		2,446,454
Loans	US$	28,754		59.890	(2)		1,722,087	US$	11,746		681,225
Contract liabilities	US$	990		59.890	(2)		59,283		-		-
Total current liabilities	US$	89,339					5,350,515	US$	53,930		3,127,679
NON CURRENT LIABILITIES
Loans	US$	531,987		59.890	(2)		31,860,717	US$	534,595		31,003,715
Contract liabilities	US$	13,692		59.890	(2)		820,025		-		-
Total non current liabilities	US$	545,679					32,680,742	US$	534,595		31,003,715
TOTAL LIABILITIES	US$	635,018					38,031,257	US$	588,525		34,131,394

⁽¹⁾ Buy exchange rate at the end of fiscal year

⁽²⁾ Sell exchange rate at the end of fiscal year

US$: United States of America dollars

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

19. COMMON STOCK AND DIVIDENDS

a) Common stock structure and shares’ public offer

As of December 31, 2019 and 2018, TGS’ common stock was as follows:

Common Stock structure as of December 31, 2018
Shares Class	Amount of common stock, subscribed, issued, paid in, and authorized for
	public offer
Common Shares Class
(Face value $ 1, 1 vote)	Outstandings shares		Treasury Shares		Common Stock
Class “A”		405,192,594		-		405,192,594
Class “B”		375,701,909		13,600,780		389,302,689
Total		780,894,503		13,600,780		794,495,283

Common Stock structure as of December 31, 2019
Shares Class	Amount of common stock, subscribed, issued, paid in, and authorized for
	public offer
Common Shares Class
(Face value $ 1, 1 vote)	Outstandings shares		Treasury Shares		Common Stock
Class “A”		405,192,594		-		405,192,594
Class “B”		379,415,934		9,886,755		389,302,689
Total		784,608,528		9,886,755		794,495,283

TGS’s shares are traded on the BYMA and under the form of the American Depositary Receipts (“ADS”) (registered in the SEC and representing 5 shares each) on the New York Stock Exchange.

b) Acquisition of treasury shares

During fiscal year 2018, the Board of Directors of the Company approved two programs for the acquisition of treasury shares, on May 9 and September 6, which were executed in accordance with the conditions established therein. For the definition of these programs, the Board of Directors considered the solid cash position and investments that the Company has. This program was approved by virtue of the distortion evidenced between the economic value of the Company, measured by its current businesses and derivatives of projects under development, and the price of the price of their shares in the market.

Subsequently, on March 27, 2019, the Board of Directors of the Company approved a third Program for the acquisition of treasury shares in the markets where TGS makes a public offering (the “Third Share Repurchase Program”) for a maximum amount to be invested in Ps. 1,500 million (at the moment of its creation).

On August 26, 2019, after concluding the Third Buy Program, the Board of Directors of the Company approved a new program for the acquisition of treasury shares for a total of Ps. 3,200 million (at the moment of its creation).

As mentioned in “c. Distribution of dividends”, the treasury shares acquired as of October 31, 2019 were used to pay a dividend in shares.

Finally, on November 19, 2019, a fifth program of acquisition of treasury shares was approved (the “Fifth Share Repurchase Program”) for a total of Ps. 4,000 million (at the time of its creation). This program is valid for 120 days from its creation.

As of December 31, 2019, the Company has 9,886,755 treasury shares, representing 1.24% of the total share capital. The acquisition cost of the treasury shares in the market amounted to Ps. 730,764 which, in accordance with the provisions of Title IV, Chapter III, Article 3.11.c of the Rules, restricts the amount of the realized and liquid gains mentioned above that the Company may distribute.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

c) Dividends distribution

Cash dividends

During the year ended December 31, 2019, the Company paid dividends as follows:

• The Ordinary General Shareholders´ Meeting of the Company at its meeting held on April 11, 2019 approved the payment of Ps. 9,185,584 (Ps. 11,7671 per share).

• The Board of Directors of the Company at its meeting held on April 11, 2019 approved the payment of Ps. 318,732 (Ps. 0,4083 per share).

• On October 31, 2019, the Board of Directors of the Company approved, together with the distribution mentioned below, to make available to the shareholders as of November 13, 2019 a cash dividend amounting to Ps. 256,338 (Ps. 0,3351 per share). This dividend was compensated -in the corresponding cases- with the withholding of income tax by virtue of the distribution of treasury shares (article 46 of the Income Tax Law and article 66.2 of the Regulatory Decree), in the case that it should be done.

Treasury shares distribution

On October 17, 2019, the Ordinary and Extraordinary General Shareholders´ Meeting of the Company decided to distribute among all shareholders in proportion to their holdings, in the terms provided in Article 67 of Law No. 26,831 all of the treasury shares in the portfolio for 29,444,795 class B shares and also delegated to the Board of Directors the broadest powers to effect the distribution of the shares indicated in accordance with current regulations, including the determination of the timing of such payment.

Subsequently, on October 31, 2019, the Board of Directors of TGS decided to make available to shareholders, as of November 13, 2019, the treasury shares, making it known that said distribution constitutes 0.0385 shares per ordinary share and 0.192 shares per ADR, both outstanding, representing approximately 3.706% of the share capital of TGS, which amounts to Ps. 794,495.

The market value of these shares amounted to Ps. 3,228,002 being its acquisition cost of Ps. 4,045,739. This transaction was accounted for as an equity transaction generating a decrease of Ps. 791,712, which was charged to the heading “Additional paid-up capital” of the shareholders´ equity of the Company.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

d) Restrictions on distribution of retained earnings

Pursuant to the General Companies Act and CNV Rules, we are required to allocate a legal reserve (“Legal Reserve”) equal to at least 5% of each year’s net income (as long as there are no losses for prior fiscal years pending to be absorbed) until the aggregate amount of such reserve equals 20% of the sum of (i) “common stock nominal value” plus (ii) “inflation adjustment to common stock,” as shown in our consolidated statement of changes in equity. If there are any losses pending to be absorbed from prior fiscal years, such 5% should be calculated on any excess of the net income over such losses, if any. Dividends may not be paid if the legal reserve has been impaired, nor until it has been fully replenished. The Legal Reserve is not available for distribution as a dividend.

The General Shareholders´ Meeting held on April 11, 2019, which decided to create the “Reserve for capital expenditures, acquisition of treasury shares and/or dividends” and delegated to the Board of Directors of the Company the decision of the distribution of dividends, provided as maximum limit for such distribution up to 80% of said reserve restated according to the General Resolution N° 777/2018 of the CNV.

The Company has access to the foreign exchange market to pay dividends to non-resident shareholders, without the prior consent of the BCRA only to the extent that the total amount of transfers executed through the exchange market regulated by the BCRA for payment of dividends to non-resident shareholders may not exceed 30% of the total value of any new capital contributions made in the Company that had been entered and settled through such exchange market. The total amount paid to non-resident shareholders shall not exceed the corresponding amount denominated in Argentine Pesos that was determined by the related shareholders’ meeting.

Finally, and as mentioned in subsection b of this note, the amounts subject to distribution are restricted up to the acquisition cost of treasury shares and the additional paid-up capital.

20. LEGAL CLAIMS AND OTHER MATTERS

a) Turnover tax calculated on the natural gas price consumed by TGS

The Company has interpretative differences with several provinces regarding the liquidation of the turnover tax calculated on the natural gas used by TGS as fuel to render its transportation services. In this framework there have been initiated several lawsuits against TGS, which have adversely concluded by the Company.

During fiscal year 2017 and 2016, the Company continued to receive several claims from different provinces, which meant that TGS paid Ps. 148.5 million and Ps. 27.6 million to provincial agencies (stated at their original values), respectively.

On May 24, 2017, ENARGAS issued Resolution No. 5041/2017, which approved the tariff methodology for turnover tax on gas withheld from those determinations or liquidations that the Company receives as of its date of issue.

As of December 31, 2019 and 2018, the Company recorded a provision of Ps. 515.1 million and Ps. 474.4 million, respectively, in respect of this contingency under the line item “Provisions.” Those amounts were determined in accordance with the estimations of tax and interests, that would be payable as of such date.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

b) Action for annulment of ENARGAS Resolutions No. I-1,982/11 and No. I-1,991/11 (the “Resolutions”)

After the issuance of the Resolutions, TGS filed a judicial action before the National Court of First Instance in Federal Administrative Litigation No. 1 (the “Court”) in order to obtain the declaration of nullity of the Executive Decree No. 2067/08 and the Resolutions as well as the unconstitutionality of the administrative acts that created the Charge. The probative stage of these proceedings was concluded and the allegations are currently being carried out.

On July 5, 2012, the Court issued in favor of TGS a precautionary measure by which the suspension of the Charge was ordered in the terms set forth in the Resolutions. This decision was appealed in different opportunities by the National Government, by virtue of which the dictating of the precautionary measure was limited to the validity of six months. However, at maturity, the Company is entitled to obtain a new precautionary measure for a similar period.

As a result, on September 19, 2017, a new extension of the injunction was obtained (which prevented the Government to claim TGS of the payment of the amounts resulting from the new value of the Charge for the period between the November 2011 and March 2016), thus extending the validity until March 2018.

On the other hand, the National Court of Appeals in Contentious Administrative Dismissal rejected the extraordinary appeal filed by the National Government against the judgment of that court that confirmed the rejection made by the Court at the request of ENARGAS to declare abstract the legal action initiated by TGS in accordance with the precedent “Alliance” issued by the Supreme Court in December 2014.

On March 26, 2019, TGS was notified of the judgment of first instance issued by the Federal Contentious-Administrative Court No. 1 in its claim initiated by which TGS requested the unconstitutionality of Decree No. 2,067/08; Resolutions and of any other rule or act issued or to be issued, that is caused by the mentioned rules (the “Cause”).

The first instance judgment declares the unconstitutionality of both Articles 53 and 54 of Law 26,784, as well as the aforementioned rules and of any other act tending to execute said provision, and consequently, the nullity of said rules (the “sentence”).

The Judgment was appealed by the National Government on March 29, 2019, and the appeal was granted on April 3, 2019, which has not been resolved as of the closing date of the year.

On October 29, 2019, the intervening judge decided, considering what was decided in the judgment and attending to the reasons invoked by TGS, to extend the validity of the precautionary measure issued for six more months of processing in said ordinary process and / or until the sentence passed is firm.

TGS’s Management believes it has sufficient valid arguments to defend its position, and thus, the Company has not recorded the increase of the charge for natural gas consumptions from the date of obtaining the injunction until April 1, 2016, effective date of Resolution 28.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

c) Recovery action of VAT and income tax

On October 9, 2008, TGS signed the 2008 Transitional Agreement with ex UNIREN that contemplated a tariff increase of 20%, applicable as from September 1, 2008. On December 3, 2009, the Executive Branch ratified this transitional agreement through the Presidential Decree No. 1,918/09. By means of this decree, TGS was able to bill the tariff increase to its clients as soon as ENARGAS would have published the new tariffs schedule and set the methodology to bill the retroactive effect. Finally, this administrative act did not become effective and therefore in September 2010 TGS filed an acción de amparo (a summary proceeding to guarantee constitutional rights). Due to the passing of time since the enactment of Decree No. 1918/09, on December 16, 2010, the Board of Directors of the Company resolved to discontinue the recognition of the tariff increase revenue and to reverse the receivable of the tariff increase revenue already accrued. The reversal of the tariff increase did not imply any resignation to the Company´s rights resulting from the Decree No. 1,918/09.

On May 24, 2013, TGS filed a tax recovery appeal with respect to the income tax and VAT credits generated by the reversal of the tariff increase credit mentioned above. The total amount claimed by TGS amounted to Ps. 433.3 million plus compensatory interests. After the omission to pass judgment on the claim within the three months of the filing of the tax recovery appeal, on October 9, 2013, TGS filed an appeal before the Federal Tax Bureau. On June 6, 2017, the Tax Court of the Nation rejected the claim for recovery filed by the Company. This resolution was appealed by TGS.

On May 7, 2019, the National Court of Appeals for Federal Administrative Disputes made the appeal filed by TGS and revoked the judgment of first instance, with costs to the defeated defendant. On May 23, 2019, the Treasury filed an Extraordinary Appeal - which was granted on September 26, 2019 in relation to the interpretation of the federal norms at stake in the case, but was denied as to the arbitrariness of judgment - and then Complaint Appeal. As of the date of issuance of these financial statements, the case is being resolved by the Supreme Court of Justice of the Nation.

At December 31, 2019 and 2018 there are no account receivables booked per this recovery action.

d) Turnover tax withholding in the Province of Buenos Aires

The Company was notified by ARBA regarding the initiation of various determinative procedures in which TGS is claimed for a total of Ps. 4.9 million (without fine or interest) for the omission as agent of withholding and collection of the turnover tax corresponding to the period July 2009 - June 2011. Given this determination, the Company presented to ARBA various elements of evidence that allow reducing substantially the amount claimed. As of the date of issuance of these consolidated financial statements, the Tax Court has not resolved the issue.

In March 2017, TGS partially canceled the debt claimed by ARBA, paying Ps. 2.9 million (stated in its original value) through the adhesion to the payment plans offered by the Province of Buenos Aires through Law 14,890. Adherence to these payment plans allowed partial cancellation of compensatory interest and all fines and charges claimed by ARBA.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

As of the date of the issuance of these Consolidated Financial Statements, only two files remain in relation to the alleged failure of TGS to act as withholding and collection agent during 2009 and 2010. The Company’s Management considers that it has sufficient arguments to assert its defense so at December 31, 2019 and 2018 it has no recorded any provision for this concept.

e) Environmental matters

The Company is subject to extensive environmental regulations in Argentina. TGS’ management believes that its current operations are in material compliance with applicable environmental requirements, as currently interpreted and enforced. The Company has not incurred in any material environmental liabilities as a result of its operations to date.

f) Others

In addition to the matters discussed above, the Company is a party to certain lawsuits and administrative proceedings which involve taxation, labor claims, social security, administrative and others arising in the ordinary course of business. The Company’s Management and its legal advisors estimate that the outcome of these differences will not have significant adverse effects on the Company’s financial position or results of operations. As of December 31, 2019 and 2018, the total amount of these provisions amounted Ps. 74.0 million and Ps. 91.9 million, respectively.

21. BALANCES AND TRANSACTIONS WITH RELATED COMPANIES

Technical, Financial and Operational Assistance Agreement

Pampa Energía is TGS’s technical operator, according to the approval of ENARGAS in June 2004, and subject to the terms and conditions of the Technical Assistance Agreement which provides that Pampa Energía is in charge of providing services related to the operation and maintenance of the natural gas transportation system and related facilities and equipment, to ensure that the performance of the system is in conformity with international standards and in compliance with certain environmental standards. For these services, the Company pays a monthly fee based on a percentage of the operating income of the Company.

The Ordinary and Extraordinary General Shareholders´ Meeting held on October 17, 2019 ratified the proposal approved by the Board of Directors at its meeting on September 17, 2019 made to Pampa Energía that implies an extension in the contract and a modification in the determination of the remuneration received by Pampa Energía.

Such modifications, without implying a modification in the scope of the tasks performed, will mean a progressive reduction over the years in the remuneration that Pampa Energía will receive in its role of Technical Operator.

According to the modifications made, TGS will pay Pampa Energía the greater of: (i) an annual fixed sum of US$ 0.5 million or (ii) the variable compensation that arises from applying to comprehensive income before results and income taxes for the year but after deducting also the above fixed amount) the following scheme:

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

From 12/28/2019 to 12/27/2020: 6.5%

•          From 12/28/2020 to 12/27/2021: 6%

•          From 12/28/2021 to 12/27/2022: 5.5%

•          From 12/28/2022 to 12/27/2023: 5%

•          From 12/28/2023 to 12/27/2024 and onwards: 4.5%

Commercial transactions

In the normal course of its activity, TGS celebrated with Pampa Energía and other companies related to it, agreements to transfer natural gas and its richness. The price, which is denominated in US dollars, is determined according to common market practices.

In addition, in the normal course of business, TGS carries out liquid sales, natural gas transportation services and other services with its associated companies, Pampa Energía and related companies.

Financial lease agreement with Pampa Energía

As mentioned in Note 13 to these Consolidated Financial Statements, on August 11, 2016, the Company entered into a finance lease agreement with Pampa Energía (formerly Petrobras Argentina).

Key management compensation

The accrued amounts corresponding to the compensation of the members of the Board of Directors, the Statutory Committee and the Executive Committee for the years ended December 31, 2019, 2018 and 2017 were Ps. 142,116, Ps. 128,942 and Ps. 79,094, respectively.

Balances and transactions with related parties

The detail of significant outstanding balances for transactions entered into by TGS and its related parties as of December 31, 2019, 2018 and 2017 is as follows:

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

	2019				2018
Company	Accounts receivable		Accounts payable		Accounts receivable		Accounts payable
Controlling shareholder:
CIESA		37		-		-		-
Associate which exercises joint control on the controlling shareholder:
Pampa Energía (1)		210,126		2,489,507		141,040		2,846,676
Associate which exercises significant influence on the controlling shareholder:
Link		668		-		9,971		-
EGS		-		-		-		-
TGU		-		9,534		-		9,232
Other related companies:
SACDE Sociedad Argentina de Construcción (2)		23,344		-		329,429		-
Pampa Comercializadora S.A.		43,843		-		10,942		-
CT Barragán S.A.		8,131		-		-		-
Oleoductos del Valle S.A.		3,348		-		4,816		-
Central Piedra Buena S.A.		13,304		-		39,170		-
Transener S.A.		-		-		140		-
Total		302,801		2,499,041		535,508		2,855,908

⁽¹⁾ Accounts payable includes Ps. 2,377,438 and Ps. 2,546,556 corresponding to the financial leasing recorded as “Loans” as of December 31, 2019 and 2018, respectively.

⁽²⁾ Corresponds to advance payments delivered to the supplier recorded as “Other credits”.

The detail of significant transactions with related parties for the years ended December 31, 2019, 2018 and 2017 is as follows:

Year ended December 31, 2019:

	Revenues						Costs						Financial results
Company	Natural Gas Transportation		Production and commercialization  of liquids		Other services		Gas purchase and others		Compensation for technical assistance		Revenues for administrative services		Interest expense
Controlling shareholder:
CIESA		-		-		-		-		-		146		-
Associate which exercises joint control on the controlling shareholder:
Pampa Energía		803,610		269,511		268,991		575,857		1,144,777		-		194,944
Associates with significant influence:
Link		-		-		14,073		-		-		-		-
Other related companies:
Oleoductos del Valle S.A.		5,469		-		-		-		-		-		-
Pampa Comercializadora S.A.		52,051		-		-		-		-		-		-
Central Piedra Buena S.A.		121,367		-		-		-		-		-		-
Experta ART		-		-		-		20,080		-		-		-
Total		982,497		269,511		283,064		595,937		1,144,777		146		194,944

Additionally, during the year ended December 31, 2019, the Company received from SACDE Sociedad Argentina de Construcción, construction engineering services for Ps. 1,726,356, which are capitalised within the facilities related to the Vaca Muerta Projects.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

Year ended December 31, 2018:

	Revenues						Costs						Financial results
Company	Natural Gas Transportation		Production and commercialization of liquids		Other services		Gas purchase and others		Compensation for technical assistance		Revenues for administrative services		Interest expense
Controlling shareholder:
CIESA		-		-		-		-		-		225		-
Associate which exercises joint control on the controlling shareholder:
Pampa Energía		676,180		2,035		355,245		949,283		2,026,244		-		193,009
Associates with significant influence:
Link		-		-		13,213		-		-		-		-
Other related companies:
Oleoductos del Valle S.A.		9,459		-		12,733		-		-		-		-
Transener S.A.		-		-		18,481		-		-		-		-
Petrolera Entre Lomas S.A.		-		-		-		3,103		-		-		-
Pampa Comercializadora S.A.		41,333		-		-		-		-		-		-
Central Térmica Piedrabuena S.A.		103,337		-		-		-		-		-		-
Experta ART		-		-		-		18,321		-		-		-
Total		830,309		2,035		399,672		970,707		2,026,244		225		193,009

Additionally, during 2018, the Company received from SACDE S.A. Construcciones engineering services for Ps 263,580 which are capitalized in the caption Work in progress.

Year ended December 31, 2017:

Revenues							Costs						Financial results
Company	Natural Gas Transportation		Production and commercialization of liquids		Other services		Gas purchase and others		Compensation for technical assistance		Revenues for administrative services		Interest expense
Controlling shareholder:
CIESA		-		-		-		-		-		238		-
Associate which exercises joint control on the controlling shareholder:
Pampa Energía		68,736		143,945		178,731		349,268		887,901		-		165,726
Jointly control entity:
UT		-		-		-		-		-		3,253		-
Associates with significant influence:
Link		-		-		11,516		-		-		-		-
Other related companies:
Oleoductos del Valle S.A.		11,476		-		2,616		-		-		-		-
Refinor S.A.		-		-		-		8,230		-		-		-
Petrolera Pampa S.A.		-		-		-		62,062		-		-		-
Petrolera Entre Lomas S.A.		-		-		-		27,384		-		-		-
Pampa Comercializadora S.A.		16,575		-		-		-		-		-		-
Central Piedra Buena S.A.		20,245		-		-		-		-		-		-
Central Térmica Loma La Lata S.A.		-		-		598		-		-		-		-
Experta ART		-		-		-		18,381		-		-		-
Total		117,032		143,945		193,462		465,325		887,901		3,491		165,726

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

22. CONTRACTUAL OBLIGATIONS

As of December 31, 2019, the Company had the following contractual commitments:

	Estimated maturity date
	Total		Due less than one year		Less than one year		1-2 years		3-5 years		More than 5 years
Financial indebtedness (1)		42,089,583		-		3,048,790		6,063,863		32,976,930		-
Purchase obligations (2)		7,358,968		-		842,255		6,516,713		-		-
Financial Leases		3,046,173		90,363		447,976		896,074		896,074		715,686
Total		52,494,724		90,363		4,339,021		13,476,650		33,873,004		715,686

⁽¹⁾ Corresponds to the cancellation of principal and interest of the financial indebtedness. For further information, see Note 13.

⁽²⁾ Corresponds to purchase of natural gas contracts for the processing of liquids.

The totality of the financial indebtedness of TGS and the obligations corresponding to gas purchases are denominated in U.S. dollars which have been translated into Argentine pesos at the exchange rate as of December 31, 2019 (US$ 1.00 = Ps. 59.89). The amounts to be paid in pesos could vary depending on the actual fluctuations in the exchange rate.

For further information, see Note 17.a).

23. ASSOCIATES AND JOINT ARRANGEMENTS

Link:

Link was created in February 2001, with the purpose of the operation of a natural gas transportation system, which links TGS’s natural gas transportation system with the Cruz del Sur S.A. pipeline. The connection pipeline extends from Buchanan, located in the high-pressure ring that surrounds the city of Buenos Aires, which is part of TGS’s pipeline system, to Punta Lara. TGS’s ownership interest in such company is 49% and Dinarel S.A. holds the remaining 51%.

TGU:

TGU is a company incorporated in Uruguay. This company rendered operation and maintenance services to Gasoducto Cruz del Sur S.A. and its contract terminated in 2010. TGS holds 49% of its common stock and Pampa Energía holds the remaining 51%.

EGS (in liquidation):

In September 2003, EGS, a company registered in Argentina, was incorporated. The ownership is distributed between TGS (49%) and TGU (51%).

EGS operates its own pipeline, which connects TGS’s main pipeline system in the Province of Santa Cruz with a delivery point on the border with Chile.

In October 2012, ENARGAS issued a resolution which authorizes EGS to transfer the connection pipeline and service offerings in operation to TGS. On November 13, 2013, the sale of all the fixed assets of EGS to TGS for an amount of US$ 350,000 was made, the existing natural gas transportation contracts were transferred and the procedures to dissolve the Company were initiated.

The Board of Directors Meeting held on January 13, 2016, approved to initiate the necessary steps for the dissolution of EGS. The Special Shareholders Meeting held on March 10, 2016 appointed EGS’ liquidator.

UT:

The Board of Directors of TGS approved the agreement to set up the UT together with SACDE. The objective of the UT is the assembly of pipes for the construction of the project of “Expansion of the System of Transportation and Distribution of Natural Gas” in the Province of Santa Fe, called by National Public Bid No. 452-0004-LPU17 by the MINEM (the “Work”).

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

On October 27, 2017, TGS - SACDE UT signed the corresponding work contract with the MINEM.

The validity of the UT will be until it has fulfilled its purpose, once the Work is completed and until the end of the guarantee period, set at 18 months from the provisional reception.

As of December 31, 2019, works are in progress.

24. SUBSEQUENT EVENTS

The financial statements were authorized for issuance by the Board of Directors on April 29, 2020.

There are no subsequent events between the closing date of the annual period and the approval (issuance) of these financial statements, other than the ones already disclosed and those mentioned below:

Buyback program

On March 6, 2020, the Board of Directors of the Company approved a sixth treasury shares repurchase program for a maximum amount of up Ps. 2,500,000 stated at its original value and for the term of 180 calendar days.

As of April 24, 2020, the Company held 30,856,815 treasury shares, representing 3.88% of the total common stock.

Coronavirus (Covid-19) outbreak

During the first quarter of 2020 the spread of the Covid-19 has impacted several countries with increasing severity. In March 2020, the World Health Organization declared Covid-19 a global pandemic. During this period countries and organizations have taken considerable measures to mitigate risk for communities, employees and business operations. This situation and the measures adopted have created macro-economic uncertainties with regards, among others, to international prices and demand for oil, natural gas and LPG products.

Regarding the Argentine energy situation, given the compulsory social quarantine as from March 20, 2020, allowing circulation only of those people linked to the provision / production of essential products and services, the demand for hydrocarbons has decreased significantly and it is uncertain how it will evolve in the near future. Current well-head natural gas prices have shown a sustained downward trend, compared to the prices of the end of 2019, as well as industrial and commercial gas consumption. Local oil prices, which use international values as a reference, have fallen sharply and their future is uncertain. The Argentine Government stated that this quarantine could be extendable in light of the outbreak situation.

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TRANSPORTADORA DE GAS DEL SUR S.A.

Notes to the Consolidated Financial Statements as of December 31, 2019 and comparative information

(Stated in thousands of pesos as described in Note 3 and 4.d., unless otherwise stated)

In view of these circumstances, the Company has adopted a series of short-term measures aimed at guaranteeing the continuity of its operations, the health of its employees, and preserving its financial situation.

Although there are negative effects in the short term: (i) in the Production and Commercialization of Liquids segment, as this business is suffering the sharp reduction of the international prices of propane, butane and natural gasoline, and (ii) certain delays in collections of receivables in the Natural Gas Transportation segment; they are not currently expected to affect business continuity. Given the current financial position of the Company, although there are negative economic impacts in the short term, it is estimated that the Company will be able to continue meeting its financial commitments during the year 2020.

The Company is in process of adapting its business projections as new information arises.

The estimated values in use of our PPE are sensitive to the significant variation of the assumptions applied, including the determination of future tariffs by the Argentine Government on the Natural Gas Transportation business segment, and the expectation of the development of Vaca Muerta gas fields on our Other Services business segment.

In the Natural Gas Transportation segment, a less favorable scenario is being considered taking into account the current regulatory framework and the measures taken by the Argentine Government subsequent to year-end, which implied that the current tariffs would not be adjusted in line with the estimated future inflation during 2020.

In the Production and Commercialization of Liquids segment, we are considering the current drop of future international liquid prices based on available public information.

In any case, we cannot assure with certainty that actual cash flows will be in line with the assumptions applied. Therefore, significant differences could arise in the future in relation to the estimated values in use.

The full extent, consequences, and duration of the Covid-19 pandemic and the resulting operational and economic impact for TGS cannot be reasonably predicted at the time of issuance of these Financial Statements, but could impact our earnings, cash flow and financial condition which will depend on the severity of the health emergency and the success of the measures taken and those that will be taken in the future. The Company will continue to monitor events that may have an impact on its business or the recoverability of assets which would be recognized as they arise.

Annual Ordinary Shareholders’ Meeting

On April 21, 2020, the Annual Ordinary Shareholders’ Meeting (the “2020 Shareholders´ Meeting”) approved the increase in the legal reserve of Ps. 690,192 and the allocation of Ps. 19,756,710 to the reserve for capital expenditures, acquisition of treasury shares and/or dividends (the “Reserve”). The Board of Directors can release the Reserve to TGS’ shareholders in the form of dividend payments.

It is noteworthy that the above mentioned decisions made by the 2020 Shareholders’ Meeting were taken considering current CNV regulations (Resolution No. 777/2018) which states accumulated results have to be adjusted by inflation using the rates as of the month before the meeting was held. In case of 2020 Shareholders’ Meeting, TGS used the inflation rate as of March 31, 2020.

F-278

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 as well as the equity shares in its associates valued by the equity method.

Through the acquisition of Petrobras Argentina, Pampa also acquired interests in mixed companies in Venezuela. However, as of the issuance of these annual report, the Company has not obtained the timely requested authorizations regarding the change in indirect control. Notwithstanding that, the Company has submitted the requested technical, legal and financial information, as well as development plans and financing proposals, to the consideration of CVPSA (Corporación Venezolana de Petróleo S.A.)’s majority shareholder, without obtaining a favorable answer. Furthermore, CVPSA has expressed that, in view of the time elapsed, the Company should begin a new process for the presentation of plans under the guidelines to be provided by the Ministry of People’s Power for Oil of the Bolivarian Republic of Venezuela, which have not been informed to the Company yet. Given these circumstances, the Company has expressed to the Venezuelan Government’s authorities that it is no longer interested in submitting investments and/or financing proposals in mixed companies and that it is willing to negotiate the transfer of its shares to CVPSA. As a result, Pampa is currently unable to obtain accurate information about the mixed companies and, consequently, has not disclosed information on oil and gas activities regarding Venezuela for the year ended December 31, 2019 and 2018 (See Note 5.3.6.1 to the consolidated financial statements).

We changed our functional and presentation currencies from the Peso to the U.S. dollar, therefore, as from January 1, 2019, we record our operations in U.S. dollars. The comparative information has been stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29, since the Peso was our functional currency up to that date, and was translated into U.S. Dollars using the exchange rate as of that date (See Note 3 and Note 4.3 to the consolidated financial statements).

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, 2019, 2018 and 2017 (including capitalized and expensed costs incurred in relation to oil and gas assets maintained as held for sale as of December 31,2017 and discontinued operations - See Note 5.2.1 to the consolidated financial statements). 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.

	12.31.2019	12.31.2018	12.31.2017
	Consolidated companies	Consolidated companies	Consolidated companies	Equity method investment
	Argentina	Argentina	Argentina	Venezuela
	(in million of US$)
Acquisition of properties
Proved	-	-	-	-
Unproved	-	-	-	-
Total property acquisition	-	-	-	-
Exploration	34	9	9	-
Development	159	183	174	7
Total costs incurred	193	192	183	7

S-1

Capitalized cost

The following table presents the capitalized costs as of December 31, 2019, 2018 and 2017, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates (including capitalized costs related to oil and gas assets maintained as held for sale as of December 31, 2017 - See Note 5.2.1 to the consolidated financial statements).

	12.31.2019	12.31.2018	12.31.2017
	Consolidated companies	Consolidated companies	Consolidated companies	Equity method investment
	Argentina	Argentina	Argentina	Venezuela
	(in million of US$)
Proved properties
Equipment, camps and other facilities	126	140	98	-
Mineral interests and wells	892	813	828	385
Other uncompleted projects	146	109	69	-
Unproved properties	33	19	12	-
Gross capitalized costs	1,197	1,081	1,007	385
Accumulated depreciation	(585)	(527)	(322)	(265)
Total net capitalized costs	612	554	685	120

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, 2019, 2018 and 2017 (including results of operations related to oil and gas discontinued operations - See Note 5.2.1 to the consolidated financial statements). Income tax for the years presented was calculated utilizing the statutory tax rates.

	12.31.2019	12.31.2018	12.31.2017
	Consolidated companies	Consolidated companies	Consolidated companies	Equity method investment
	Argentina	Argentina	Argentina	Venezuela
	(in million of US$)
Revenue	174	524	702	15
Intersegment sales	270	63	19	-
Surplus Gas Injection Compensation	-	24	116	-
Production costs, excluding depreciation
Operating costs and others	(193)	(203)	(370)	(42)
Royalties	(56)	(83)	(96)	(4)
Total production costs	(249)	(286)	(466)	(46)
Exploration expenses	(9)	(1)	(3)	-
Depreciation, depletion and amortization	(112)	(92)	(163)	(8)
Results of operations before income tax	74	232	205	(39)
Income tax	(22)	(70)	(72)	-
Results of oil and gas operations	52	162	133	(39)

S-2

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, 2019 was audited by Gaffney, Cline & Associates. Gaffney, Cline & Associates is an independent petroleum engineering consulting firm. The independent audit covered 94% 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.

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, 2019, 2018 and 2017:

	Reserves as of December 31, 2019		Reserves as of December 31, 2018		Reserves as of December 31, 2017
	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	8.8	372.0	9.2	409.8	32.9	446.6
PROVED Undeveloped	4.7	359.1	5.8	282.2	8.7	306.1
Total proved reseves (developed and undeveloped)	13.6	731.1	15.0	692.0	41.6	752.7

The following table sets forth the reconciliation of our reserves data between December 31, 2017, December 31, 2018 and December 31, 2019:

S-3

	Crude Oil, Condensate and natural gas liquids			Natural Gas
	Consolidated companies	Equity method investment		Consolidated companies	Equity method investment
	Argentina	Venezuela	Total	Argentina	Venezuela	Total
Proved reserves (developed and undeveloped)	(in thousand of barrels)			(in millions of cubic feet)
Reserves as of December 31, 2016 (*)	46,925	-	46,925	582,076	-	582,076
Increase (decrease) attributable to:
Revisions of previous estimates	978	465	1,443	(5,516)	-	(5,516)
Improved recovery	64	-	64	219	-	219
Extension and discoveries	224	-	224	232,477	-	232,477
Purchases of proved reserves in place	585	-	585	46,386	-	46,386
Year's production	(7,146)	(465)	(7,610)	(102,956)	-	(102,956)
Reserves as of December 31, 2017 (*)	41,631	-	41,631	752,686	-	752,686
Increase (decrease) attributable to:
Revisions of previous estimates	1,003	-	1,003	(54,588)	-	(54,588)
Extension and discoveries	1,943	-	1,943	99,950	-	99,950
Purchases of proved reserves in place	81	-	81	65,115	-	65,115
Sales of proved reserves in place	(27,814)	-	(27,814)	(85,125)	-	(85,125)
Year's production	(1,845)	-	(1,845)	(86,073)	-	(86,073)
Reserves as of December 31, 2018 (*)	14,997	-	14,997	691,965	-	691,965
Increase (decrease) attributable to:
Revisions of previous estimates	(645)	-	(645)	1,247	-	1,247
Improved recovery	-	-	-	3,530	-	3,530
Extension and discoveries	970	-	970	128,832	-	128,832
Year's production	(1,771)	-	(1,771)	(94,491)	-	(94,491)
Reserves as of December 31, 2019 (*)	13,551	-	13,551	731,082	-	731,082
(*) Includes proved developed reserves:
As of December 31, 2017	32,935	-	32,935	446,594	-	446,594
As of December 31, 2018	9,179	-	9,179	409,782	-	409,782
As of December 31, 2019	8,805	-	8,805	372,000	-	372,000

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 2019, 2018 and 2017 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 the 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.

	12.31.2019	12.31.2018	12.31.2017
	(in million of US$)
Future cash inflows	2,965	4,063	4,027
Future production costs	(1,306)	(1,634)	(2,009)
Future development and abandonment costs	(451)	(508)	(469)
Future income tax	(178)	(445)	(394)
Undiscounted future net cash flows	1,030	1,476	1,155
10% annual discount	(390)	(594)	(440)
Standarized measure of discounted future net cash flows	640	882	715

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, 2019, 2018 and 2017:

	12.31.2019	12.31.2018	12.31.2017
	Consolidated companies	Consolidated companies	Consolidated companies	Equity method investment
	Argentina	Argentina	Argentina	Venezuela	Total
	(in million of US$)
Standarized measure at the beginning of year	882	715	852	-	852
Changes related to Oil & Gas Activities:
Sales Net of Production costs	(195)	(324)	(404)	28	(376)
Net Change in sales prices, net of future production costs	(619)	159	(146)	(31)	(177)
Changes in future development costs	(84)	(215)	(180)	(7)	(187)
Extensions, discoveries and improved recovery, net of futures production and assocciated costs	201	212	338	-	338
Development costs incurred	159	183	174	7	181
Revisions of quantity estimates	(8)	(66)	(10)	-	(10)
Purchase of reserves in place	-	98	70	-	70
Sale of reserves in place	-	(168)	-	-	-
Net change in income tax	175	33	71	-	71
Accretion of discount	117	107	115	-	115
Changes in production rates	3	51	(32)	-	(32)
Other changes	9	97	(133)	3	(130)
Standarized measure at the end of year	640	882	715	-	715

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.

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)

See “Item 10 – Additional Information – Memorandum and Articles of Association – Preemptive and Accretion Rights” in the annual report to which this exhibit is attached.

1

 

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 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.

2

 

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.

3

 

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.

·CommonShares. 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 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.

4

 

·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 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.

5

 

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.

6

 

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 neither we nor the depositary nor 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

·     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.

7

 

Requirements for Depositary Actions

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.

8

EX-8.1

 

EX-8.12 exhibits8_1.htm EXHIBIT 8.1

LIST OF SUBSIDIARIES OF PAMPA ENERGÍA S.A.

Subsidiaries	Country	Direct and indirect participation %
Central Piedra Buena S.A.	Argentina	100%
Corod Producción S.A.	Venezuela	100%
CPB Energía S.A.	Argentina	100%
EcuadorTLC S.A.	Ecuador	100%
Empresa Distribuidora y Comercializadora Norte S.A.	Argentina	56.32%
Enecor S.A.	Argentina	69.99%
Hidroeléctrica Diamante S.A.	Argentina	61%
Hidroeléctrica Los Nihuiles S.A.	Argentina	52.04%
Pampa Cogeneración S.A.	Argentina	100%
Pampa Comercializadora S.A.	Argentina	100%
Pampa Inversiones S.A.	Uruguay	100%
Pampa Participaciones S.A.	Argentina	100%
Pampa Energía Bolivia S.A.	Bolivia	100%
Petrobras Energía Ecuador LTD	Grand Cayman	100%
Energía Operaciones ENOPSA S.A.	Ecuador	100%
PHA S.A.U	Argentina	100%
Petrolera San Carlos S.A.	Venezuela	100%
Transelec Argentina S.A.	Argentina	100%
Transporte y Servicios de Gas en Uruguay S.A.	Uruguay	100%
Trenerec Energía Bolivia S.A.	Bolivia	100%
Trenerec S.A.	Ecuador	100%
2) Joint Ventures
Citelec S.A.	Argentina	50%
Compañía de Inversiones de Energía S.A.	Argentina	50%
CT Barragán S.A. (ex PEA)	Argentina	50%
Greenwind S.A.	Argentina	50%
Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires S.A.	Argentina	26.33%
Compañía de Transporte de Energía Eléctrica en Alta Tensión S.A.	Argentina	26.33%
Transportadora Gas del Sur S.A.	Argentina	27.19%
3) Associates
Oleoducto de Crudos Pesados	Ecuador	15.91%
Oleoductos del Valle S.A.	Argentina	2.10%
Refinería del Norte S.A.	Argentina	28.50%

EX-12.1

 

Exhibit 12.1

Chief Financial Officer Certification

I, Gabriel Cohen, 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 30, 2020.

/s/ Gabriel Cohen

Chief Financial Officer

EX-12.2

 

Exhibit 12.2

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 30, 2020.

/s/ Gustavo Mariani

Chief Executive 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, 2019 (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 30, 2020

	/s/ Gustavo Mariani
	Title: Chief Executive Officer
Date: April 30, 2020
	/s/ Gabriel Cohen
	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

6. RISKS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfVariationOfTheResultOfTheYearExposureToPriceRiskLineItems [Line Items]
Variation of the result for the year	$ 37	$ 42
Shares
DisclosureOfVariationOfTheResultOfTheYearExposureToPriceRiskLineItems [Line Items]
Variation of the result for the year	2	1
Government securities
DisclosureOfVariationOfTheResultOfTheYearExposureToPriceRiskLineItems [Line Items]
Variation of the result for the year	11	30
Investment funds
DisclosureOfVariationOfTheResultOfTheYearExposureToPriceRiskLineItems [Line Items]
Variation of the result for the year	$ 24	$ 11

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 12) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Liabilities, beginning	$ 35	$ 44	$ 50
Items classified in profit or loss
Current services cost	3	2	3
Cost for interest	13	8	11
Past services cost		(5)	1
Items classified in other comprehensive income
Actuarial (gains) losses	(2)	4	(1)
Exchange differences on translation			0
Benefit payments	(2)	(3)	(2)
Reclassification to liabilities associated to assets classified as held for sale			(7)
(Gain) loss on net monetary position	(16)		(11)
Increase for subsidiaries acquisition		(15)
Liabilities, ending	31	35	44
Present value of the obligation
Disclosure of net defined benefit liability (asset) [line items]
Liabilities, beginning	40	47	58
Items classified in profit or loss
Current services cost	3	2	3
Cost for interest	15	9	12
Past services cost		(5)	1
Items classified in other comprehensive income
Actuarial (gains) losses	(2)	6	(1)
Exchange differences on translation			1
Benefit payments	(2)	(3)	(2)
Reclassification to liabilities associated to assets classified as held for sale			(11)
(Gain) loss on net monetary position	(18)		(14)
Increase for subsidiaries acquisition		(16)
Liabilities, ending	36	40	47
Present value of assets
Disclosure of net defined benefit liability (asset) [line items]
Liabilities, beginning	(5)	(3)	(8)
Items classified in profit or loss
Current services cost	0	0	0
Cost for interest	(2)	(1)	(1)
Past services cost		0	0
Items classified in other comprehensive income
Actuarial (gains) losses	0	(2)	0
Exchange differences on translation			(1)
Benefit payments	0	0	0
Reclassification to liabilities associated to assets classified as held for sale			4
(Gain) loss on net monetary position	2		3
Increase for subsidiaries acquisition		1
Liabilities, ending	$ (5)	$ (5)	$ (3)

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18. LEASES (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets depreciation, beginning	$ 0
Depreciation	(4)
Right of use assets depreciation, ending	(4)
Net book value	16	$ 0
Machinery and equipment
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets depreciation, beginning	0
Depreciation	(2)
Right of use assets depreciation, ending	(2)
Net book value	11
Buildings
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets depreciation, beginning	0
Depreciation	(2)
Right of use assets depreciation, ending	(2)
Net book value	$ 5

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17. RELATED PARTIES TRANSACTIONS (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
EMESA
Disclosure of transactions between related parties [line items]
Payment of dividends	$ 0	$ (2)	$ (2)
APCO Oil
Disclosure of transactions between related parties [line items]
Payment of dividends	0	0	(2)
Total related parties
Disclosure of transactions between related parties [line items]
Payment of dividends	$ 0	$ (2)	$ (4)

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11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 16) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Non current salaries and social security payable	$ 4	$ 4
Current salaries and social security payable	65	72
Seniority - based bonus
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Non current salaries and social security payable	3	4
Early retirements payable
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Non current salaries and social security payable	1	0
Salaries and social security contributions
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Current salaries and social security payable	22	24
Provision for vacations
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Current salaries and social security payable	17	19
Provision for gratifications and annual bonus for efficiency
DisclosureOfSalariesAndSocialSecurityPayableLineItems [Line Items]
Current salaries and social security payable	$ 26	$ 29

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6. RISKS (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Risks
Current assets	$ 1,362	$ 1,521
Current liabilities	$ 854	$ 1,182
Liquidity index	1.59%	1.29%

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18. LEASES (Details 5) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
OperatingLeaseFutureCollectionsLineItems [Line Items]
Total future minimum lease collections	$ 5	$ 5
2019
OperatingLeaseFutureCollectionsLineItems [Line Items]
Total future minimum lease collections	0	5
2020
OperatingLeaseFutureCollectionsLineItems [Line Items]
Total future minimum lease collections	$ 5	$ 0

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22. OIL AND GAS RESERVES (Information not covered by the auditors' report) (Tables)

12 Months Ended

Dec. 31, 2019

Oil And Gas Reserves

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	8,804	10,534	4,746	10,168	13,550	20,702
Total at 12.31.2019	8,804	10,534	4,746	10,168	13,550	20,702

⁽¹⁾ In thousands of barrels.

⁽²⁾ In millions of cubic meters.

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12. FINANCIAL ASSETS AND LIABILITIES (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Financial Assets And Liabilities
Allowance for the impairment of other receivables, beginning	$ 8	$ 6	$ 10
Allowance for impairment	1	7	1
Gain on monetary position, net	(1)	(3)	0
Decreases	0	0	(1)
Reversal of unused amounts	(2)	(2)	(5)
Allowance for the impairment of other receivables, ending	$ 6	$ 8	$ 6

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 8) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Book value	$ 1,947	$ 2,177	$ 1,683	$ 1,269
Corporate bonds 1
Disclosure of detailed information about borrowings [line items]
Instrument name	2022 CB	2022 CB
Company name	Edenor	Edenor
Residual value	$ 166	$ 166
Interest	Fixed	Fixed
Rate	9.75%	9.75%
Expiration	2022	2022
Book value	$ 139	$ 170
Corporate bonds 2
Disclosure of detailed information about borrowings [line items]
Instrument name	Class E CB	Class E CB
Company name	PAMPA	PAMPA
Residual value	$ 575	$ 607
Interest	Variable	Variable
Rate	Badlar	Badlar
Expiration	Nov-20	Nov-20
Book value	$ 10	$ 16
Corporate bonds 3
Disclosure of detailed information about borrowings [line items]
Instrument name	Class 1 CB	Class 1 CB
Company name	PAMPA	PAMPA
Residual value	$ 687	$ 747
Interest	Fixed	Fixed
Rate	7.50%	7.50%
Expiration	Jan-27	Jan-27
Book value	$ 698	$ 510
Corporate bonds 4
Disclosure of detailed information about borrowings [line items]
Instrument name	T Series  CB	T Series  CB
Company name	PAMPA	PAMPA
Residual value	$ 487	$ 500
Interest	Fixed	Fixed
Rate	7.38%	7.38%
Expiration	Jul-23	Jul-23
Book value	$ 497	$ 753
Corporate bonds 5
Disclosure of detailed information about borrowings [line items]
Instrument name	Serie 3 CB
Company name	PAMPA
Residual value	$ 293
Interest	Fixed
Rate	9.13%
Expiration	Apr-29
Book value	$ 291
Corporate bonds 6
Disclosure of detailed information about borrowings [line items]
Instrument name		Class 4 CB
Company name		PAMPA
Residual value		$ 34
Interest		Fixed
Rate		6.25%
Expiration		Oct-20
Book value		$ 34
Regulatory 1
Disclosure of detailed information about borrowings [line items]
Company name	PAMPA
Residual value	$ 84
Interest	Fixed
Rate	Between 4.25% and 7.65%
Expiration	Jan-20 to May-20
Book value	$ 88
Regulatory 2
Disclosure of detailed information about borrowings [line items]
Company name	PAMPA
Residual value	$ 39
Interest	Fixed and variable
Rate	4.21% + Libor
Expiration	May-24
Book value	$ 39
Regulatory 3
Disclosure of detailed information about borrowings [line items]
Company name	PAMPA
Residual value	$ 7,775
Interest	Fixed
Rate	Between 40% and 44.14%
Expiration	Apr-21 to Apr-22
Book value	$ 146
Regulatory 4
Disclosure of detailed information about borrowings [line items]
Company name	PAMPA
Residual value	$ 13
Interest	Fixed
Rate	6.00%
Expiration	2020
Book value	$ 14
Regulatory 5
Disclosure of detailed information about borrowings [line items]
Instrument name		CAMMESA 2014 Agreement
Company name		PAMPA
Residual value		$ 855
Interest		Variable
Rate		CAMMESA
Expiration		Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
Book value		$ 57
Regulatory 6
Disclosure of detailed information about borrowings [line items]
Instrument name		CAMMESA Mapro
Company name		PAMPA
Residual value		$ 174
Interest		Variable
Rate		CAMMESA
Expiration		Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
Book value		$ 7
Regulatory 7
Disclosure of detailed information about borrowings [line items]
Instrument name		CAMMESA Mapro
Company name		CPB
Residual value		$ 1,085
Interest		Variable
Rate		CAMMESA
Expiration		Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
Book value		$ 59
Financial loans 1
Disclosure of detailed information about borrowings [line items]
Company name		PAMPA
Residual value		$ 17,116
Interest		Fixed
Rate		Between 3.6% and 6.8%
Expiration		Feb-19 to May-21
Book value		$ 459
Financial loans 2
Disclosure of detailed information about borrowings [line items]
Company name		PAMPA
Residual value		$ 1,746
Interest		Fixed and variable
Rate		6% + Libor
Expiration		May-24
Book value		$ 46
Financial loans 3
Disclosure of detailed information about borrowings [line items]
Company name		PAMPA
Residual value		$ 550
Interest		Fixed
Rate		22.25%
Expiration		Sep-19 to Oct-19
Book value		$ 15
Financial loans 4
Disclosure of detailed information about borrowings [line items]
Company name	Edenor	Edenor
Residual value	$ 1,885	$ 1,885
Interest	Variable	Variable
Rate	Libor + 4.27%	Libor + 4.27%
Expiration	Oct-20	Oct-20
Book value	$ 25	$ 51
Corporate bonds
Disclosure of detailed information about borrowings [line items]
Book value	1,635	1,483
Regulatory
Disclosure of detailed information about borrowings [line items]
Book value	287	123
Financial loans
Disclosure of detailed information about borrowings [line items]
Book value	$ 25	$ 571

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13. EQUITY COMPONENTS (Tables)

12 Months Ended

Dec. 31, 2019

Equity Components

Earnings (loss) per share

	12.31.2019	12.31.2018	12.31.2017
Earning for continuing operations attributable to the equity holders of the Company	692	146	341
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings per share from continuing operations	14.42	2.81	6.69
Earning (loss) for discontinued operations attributable to the equity holders of the Company	-	78	(55)
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings (loss) per share from discontinued operations	-	1.50	(1.07)
Total earning attributable to the equity holders of the Company	692	224	286
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings  per share	14.42	4.31	5.61

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4. ACCOUNTING POLICIES (Details 1)	12 Months Ended
	Dec. 31, 2019
Buildings
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	50 years
Substations
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	35 years
High voltage lines
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	40 - 45 years
Medium voltage lines
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	35 - 45 years
Low voltage lines
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	30 - 40 years
Transformer centrals
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	25 - 35 years
Meters
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	25 years
Vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	5 years
Furniture, fittings and communication equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	5 - 20 years
Computer equipment and software
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	3 years
Tools
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	10 years
Gas Plant and Pipeline
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment estimated useful lives	20 years

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4. ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies

New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2019 and adopted by the Company

The Company has first applied the following standards and/or amendments as from January 1, 2019:

- IFRS 16 – “Leases” (issued in January 2016).

- IFRIC 23 – “Uncertainty over Income Tax Treatments” (issued in June 2017)

- IFRS 9 – “Financial Instruments” (application guideline amended in October 2017)

- IAS 28 – “Investments in Associates and Joint Ventures” (amended in October 2017)

- Annual Improvements to IFRS Standards 2015–2017 Cycle (issued in December 2017)

- IAS 19 – “Employee Benefits” (amended in February 2018)

The impact of the initial application of IFRS 16 in the Company’s operating results and financial position as from January 1, 2019 is detailed below.

The application of the remaining standards, amendments or interpretations did not have any impact on the results of the operations or the financial position of the Company.

4.1.1    Impacts of the adoption of IFRS 16

The Company has opted to apply IFRS 16, using the simplified approach, in relation to lease contracts previously identified as such under IAS 17, retrospectively with the cumulative effect recognized as an adjustment to the opening balance of retained earnings as of January 1, 2019, without restating comparative information.

Until December 31, 2018, only contracts classified as financial leases under IAS 17 were capitalized by the Company, that is, contracts where the Company had substantially all of the risks and rewards of ownership of the leased asset. At the financial lease´s inception, the Company recorded an asset and a liability for the same value, corresponding to the leased property’s fair value, or, if lower, the present value of the minimum lease payments. The corresponding rental obligations, net of finance charges, were included in other liabilities. Each lease payment was allocated between the liability and the finance cost. The finance cost was charged to profit or loss over the lease period so as to produce a constant periodic interest rate on the remaining liability balance for each period. Property, plant and equipment acquired under financial leases were depreciated over the asset’s useful life or, if lower, over the lease term. Leases in which a significant portion of the risks and rewards of ownership were not transferred to the Company were classified as operating leases. Payments made under operating leases (net of any incentive received from the lessor) were charged to profit or loss on a straight-line basis over the lease period.

Management has reviewed effective lease contracts and has recognized a right-of-use asset in the amount of U$S 8 million corresponding to the amount of the lease liability as of the adoption date (which equals the present value of the remaining lease payments), as detailed below:

Operating lease commitments as of 12.31.2018	10.5
Discount using incremental borrowing rate of 58.16% as of 01.01.2019	(2.4)
Exchange differences on translation	(0.1)
Lease liability recognised as of 01.01.2019	8

The rest of the identified lease commitments correspond to contracts ending within 12 months of the date of initial application, which continue to be recognized by the Company on a straight-line basis.

As of the adoption date, the Company has maintained the recorded book value for right-of-use assets and lease liabilities which were classified as finance leases under IAS 17.

Finally, no transition adjustments were made for leases in which the Company acts as a lessor.

Consequently, the Company has not recognized any adjustment to retained earnings upon the initial application of IFRS 16.

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. 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, 2021, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. The Company estimates that its application will not have a significant impact on the Company’s operating results or financial position.

-     Conceptual Framework: in March 2018, the IASB published a revised conceptual framework which will supersede the current one. However, this framework is not a standard in itself and will not override any existing standard. The concepts of the revised conceptual framework will be immediately taken into consideration in the issuance of future standards by the IASB and the Interpretations Committee. Preparers of financial statements under IFRS will consider the revised conceptual framework for the development of accounting policies on matters not specifically addressed by the IFRS for annual periods beginning on or after January 1, 2020.

-      IFRS 3 – “Business Combinations”: amended in October 2018. It clarifies the definition of business and establishes guidelines for determining whether a transaction should be accounted for as a business combination or as an acquisition of assets. It applies to acquisition transactions as from January 1, 2020, and allows for its early adoption.

-      IAS 1 – “Presentation of Financial Statements” and IAS 8 – “Accounting Policies, Changes in Accounting Estimates and Errors”: amended in October 2018. They clarify the definition of materiality and incorporate the concept of “information shadowing” when there is an effect similar to omitting or reporting inaccurate information. They apply prospectively to annual periods starting on or after January 1, 2020, and allow for early adoption.

-      Amendments to IFRS 9 – “Financial Instruments”, IAS 39 – “Financial instruments: Presentation” and IFRS 7 – “Financial Instruments: Disclosures”: it incorporates temporary exemptions in the case of hedge relationships affected by the interest rate benchmark reform pursuant to the recommendations published by the Financial Stability Board (FSB) in July 2014. Amendments are applicable to fiscal years starting on or after January 1, 2020, allowing for early adoption.

Effects of changes in foreign exchange rates

4.3.1 Functional and presentation currency

The information included in these Consolidated Financial Statements is recorded and presented in U.S. Dollars, which is the Company’s functional currency, that is, the currency of the primary economic environment where the entity operates.

4.3.2 Foreign-currency transactions and balances

Foreign currency transactions are translated into the functional currency at the exchange rates prevailing on each transaction date or valuation date, when items are remeasured. Foreign exchange gains and losses arising on the settlement of monetary items and on translating monetary items at the closing of the fiscal year using year-end exchange rate are recognized within the financial results in the statement of comprehensive income, with the exception of capitalized amounts.

4.3.3 Group companies’ 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 recognized under “Other comprehensive income”.

4.3.4 Classification 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

4.4.1 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 cease 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 companies 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 recognized at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according IFRS 11 “Joint Arrangements”. 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 (see Note 4.4.4 below), after initially being recognized at cost.

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognized at cost and adjusted thereafter 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. Dividends received or receivable from associates and joint ventures are recognized 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 at 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 recognized 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 recognized 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 recognized 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 may mean 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 recognized in other comprehensive income are reclassified to profit or loss where appropriate.

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 person/ 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

Property, Plant and Equipment is measured following the cost model. It is recognized 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, net of any income obtained from the sale of commercially valuable production during the launching 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
Substations:	35 years
High voltage lines:	40 - 45 years
Medium voltage lines:	35 - 45 years
Low voltage lines:	30 - 40 years
Transformer centrals:	25 - 35 years
Meters:	25 years
Vehicles:	5 years
Furniture, fittings and communication equipment:	5- 20 years
Computer equipment and software:	3 years
Tools:	10 years
Gas Plant and Pipeline:	20 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 Asset retirement obligations

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 recognized. 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 recognized immediately in profit or loss.

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 at 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 CGUs 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 Edenor and 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 each asset’s 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 at the moment of the acquisition of companies. Identified assets meet the criteria established in IFRS for capitalization less depreciation a 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.

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

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 recognized 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

4.10.1     Classification

The Group classifies its financial assets in the following categories:

i.	those that are subsequently measured at fair value (either through other comprehensive income or through profit or loss), 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 Statement of 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 trade date, that is, the date on which the Company undertakes to purchase or sell the asset, or at settlement date. Financial assets are derecognized 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 amortised cost and is not part of a hedging relationship is recognized 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 recognized 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 recognized 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

Trade receivables and other receivables are recognized at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognises 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.

Receivables arising from services billed to customers but not collected by Edenor, as well as those arising from services rendered but unbilled at the closing date of each financial year are recognized at fair value and subsequently measured at amortized cost using the effective interest rate method. 

Receivables from electricity supplied to low-income areas and shantytowns are recognized, also in line with revenue, when the Framework Agreement has been renewed for the period in which the service was provided.

Where applicable, allowances for doubtful tax credits have been recognized 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

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 recognized assets or liabilities or over firm commitment (fair value hedge);
ii.	cash flow hedges of a particular risk associated with recognized 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 recognized in equity. The gain or loss related to the ineffective portion is recognized immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognized in profit or loss.

The Company has not formally designated financial instruments as hedging instruments.

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 and Distribution of Energy business segments.

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 recognized 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

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 recognised for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognised 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 recognised. The gain or loss not previously recognised by the date of the sale of the non-current asset is recognised at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they be 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 recognized.

Non-current assets classified 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

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

Equity’s movements have been 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 detailed in Note 3.1, the Company has 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. Ordinary shares are classified as equity.

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 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, the related adjustment of share capital. When for any reason, the amount of this reserve will be shorter, 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 (Accumulated losses)

Retained earnings comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of the Shareholders' meeting, as long as they are not subject to legal restrictions. These earnings comprise 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 recognized as a liability in the Consolidated Financial Statements 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.

Compensation plans

Note 19 details the conditions applicable to the different compensation agreements and the main variables considered in the corresponding valuation model.

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

-	Compensations payable in cash:
i.	Compensation agreements – Senior Management: the reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton valuation model. The fair value of the amount payable under the compensation agreements 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.
ii.	Company Value Sharing (“Company-Value Compensation”) – Pampa (as PEPASA´s successor company): the Black-Scholes-Merton financial valuation model was used to make this estimate, taking into consideration the enforceability of the remuneration. The fair value of the amount payable for the compensation plan is accrued and acknowledged as an expense, with the recognition of an increase in liabilities. Liabilities are revalued on each balance sheet date and at their settlement date. Any change in the fair value of liabilities is disclosed under profit or loss.
iii.	Annual Variable Compensation granted to certain officers for the performance of technical and administrative duties amounting to 7% of the EBDA accrued (EBITDA less paid income tax, less total net financial costs, less interest on its own capital, considering an annual 10% dollar-denominated rate) of PEPASA´s continuing business in Pampa. The Company recognizes a provision (liability) and an expense for this EBDA Compensation based on the previously mentioned formula.
-	Compensations payable in shares
i.	Stock-based Compensation Plan – Officers and other key staff: the fair value of the received services is measured at the fair value of shares at the time of granting, and is disclosed during the vesting period, together with the corresponding increase in equity.
ii.	Stock-based Compensation Plan -Edenor: The fair value of the services received is disclosed as an expense and determined by reference to the fair value of the granted shares. When the employees provide the services before the shares are granted, the fair value at the grant date is estimated in order to recognize the respective result.

Trade payables and other payables

Trade payables and other payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, except for particular matters described below.

4.18.1   Customer guarantees

Customer guarantees are initially recognized at fair value and subsequently measured at amortized cost using the effective interest method.

In accordance with the Concession Agreement, Edenor is allowed to receive customer guarantees in the following cases:

i.	When the power supply is requested and the user is unable to provide evidence of his legal ownership of the premises;
ii.	When service has been suspended more than once in one-year period;
iii.	When the power supply is reconnected and Edenor is able to verify the illegal use of the service (fraud).
iv.	When the customer is undergoing liquidated bankruptcy or reorganization proceedings.

Edenor has decided not to request customer guarantees from residential tariff customers.

Customer guarantees may be either paid in cash or through the customer’s bill and accrue monthly interest at a specific rate of BNA for each customer category.

When the conditions for which Edenor is allowed to receive customer guarantees no longer exist, the customer’s account is credited for the principal amount plus any interest accrued thereon, after deducting, if appropriate, any amounts receivable which Edenor has with the customer.

4.18.2   Edenor’s customer refundable contributions

Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements and the provisions of ENRE Resolution No. 215/12. These contributions are initially recognized as trade payables at fair value against Property, plant and equipment, and are subsequently measured at amortized cost using the effective interest rate method.

4.18.3   Edenor’s particular matters

The recorded liabilities for penalties accrued, whether imposed or not yet issued by the ENRE (Note 2.3), and other provisions are the best estimate of the settlement value of the present obligation in the framework of IAS 37 provisions at the date of these Consolidated Financial Statements.

The balances of ENRE Penalties and Discounts are adjusted in accordance with the regulatory framework applicable thereto and are based on Edenor’s estimate of the outcome of the RTI process described in Note 2.3.

Borrowings

Borrowings are recognized 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 recognized 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, cancelled 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.

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.

Deferred revenues

Non-refundable customer contributions: Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements. The assets received are recognized by Edenor as Property, plant and equipment with a contra-account in deferred revenue, the accrual of which depends on the nature of the identifiable services, in accordance with the following:

i.	Customer connection to the network: revenue is accrued until such connection is completed;
ii.	Continuous provision of the electric power supply service: throughout the shorter of the useful life of the asset and the term for the provision of the service.

Employee benefits

4.21.1   Short-term obligations

Liabilities for wages and salaries, including non-monetary benefits and accumulating sick leave that are expected to be settled wholly within 12 months after the end of the period in which the employees render the related service are recognised in respect of employees’ services up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liabilities are presented as current salaries and social security payable in the consolidated statement of financial position.

4.21.2   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 recognized 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 recognized in other comprehensive income (loss) in the period in which they arise and past service costs are recognized immediately in the statement of income (loss).

Provisions, contingent liabilities and contingent assets

Provisions are recognized 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 each 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. The increase in the provision due to the passage of time is recognised as 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 no 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

4.23.1   Generation segment:

4.23.1.1 Revenues from sales to the spot market (SRRYME Resolution No. 1/19)

The Company recognizes revenues from i) power availability 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 applicable depending on the technology of each plant and, in the case of thermal power plants, the application of the coefficient derived from the average usage factor over the last 12 months on the power capacity remuneration specified in the Resolution. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 45 days, which is consistent with market practice.

4.23.1.2 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 45 days, which is consistent with market practice.

4.23.1.3 Revenues from sales contracts with large users within the MAT (energy plus Resolution SE No. 1,281/06)

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.

4.23.2   Distribution segment

4.23.2.1 Revenues from contracts with customers

Edenor's revenue is measured at the fair value of the consideration collected or to be collected, taking into account the estimated amount of any discount, thus determining the net amounts.

Edenor recognizes, on a monthly basis, revenues from electricity distribution as energy is distributed to each client based on the applicable tariff and procedures established by the ENRE. Such revenue includes energy delivered, whether billed or unbilled, at the end of each period. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

Edenor recognizes revenues related to energy supply to low-income areas and shantytowns, only to the extent that the Framework Agreement has been renewed for the period in which the service was rendered. As of the date of issuance of these Consolidated Financial Statements, the Framework Agreement is not currently in effect.

4.23.2.2. Edenor’s other revenues from contracts with customers

Edenor recognizes other revenues from contracts with customers in relation to connection and reconnection services, rights of use on poles and transport of energy to other distribution companies on a monthly basis as services are rendered based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

4.23.3   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 recognized 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 30 days, which is consistent with market practice.

4.23.4 Petrochemical segment

The Company recognizes revenues from the sale of petrochemical products, whether in local or foreign market, 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:

(a)	when the products are dispatched and transported by and in charge of the client, or,
(b)	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 recognized 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 28 days, which is consistent with market practice.

4.23.5 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

4.24.1   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. There are no unfulfilled conditions or other contingencies attaching to the following grants. The group did not benefit directly from any other forms of government assistance.

4.24.1.1 Recognition of Compensation from Natural Gas Injection Promotion Programs

The Company recognizes revenues from Natural Gas Injection Promotion Programs when the delivery of the gas is effective based on the price established in the applicable regulation, only to the extent that it is highly probable that a significant reversal will not occur and it is probable that the consideration will be collected, that is, as the procedure established by Government is formally complied with. Although the consideration Programs´ collection depends on the Argentine Government’s payment capacity that has incurred in important delays in the cancellation of the credits in the past, revenues are not adjusted for the effect of financing components, which is consistent with market practice.

The recognition of income from Natural Gas Injection Promotion Programs is covered by IAS 20 since it involves a compensation as a result of the production increase committed.

This item has been disclosed under Natural Gas Injection Promotion Programs under Other operating income, in the Consolidated Statement of Comprehensive Income. Furthermore, ítem Extroardinary Canon disclosed within Other operating expenses includes fiscal costs related to these Programs.

4.24.2   Interest income

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 carrying amount net of impairment provision.

4.24.3   Dividends

Dividends are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognized 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 and minimum notional income tax

4.25.1   Current and deferred income tax

The tax expenses for the year include current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case, the tax is also recognized 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 recognized, 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 recognized 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 recognized 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 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 recognized on account of gains or losses from fiscal tax inflation which, pursuant to Law No. 27,541, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1.5).

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset the recognized 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), Venezuela, Ecuador, Bolivia, Spain and Uruguay are 30%, 50%, 25%, 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.

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.

4.25.2 Minimum notional income tax

The Company assessed the minimum notional income tax until December 31, 2018, by applying the current 1% rate over the assets computable at the closing of the year. As this tax supplements the income tax, the Company does not assess it for the periods where no income is evidenced on the income tax, based on the case law established by the “Hermitage” decision (CSJN, June 15, 2010), which ruled on the unconstitutionality of this tax when tax losses are disclosed for the period.

The Company’s tax obligation for each year will be the higher of the two taxes. If in a fiscal year, however, minimum notional income tax obligation exceeds income tax liability, the surplus will be computable as a payment in advance of income tax through the next ten years.

Pursuant to section 76 of Law No. 27,430, the effectiveness of this tax has been abrogated for fiscal years beginning on or after January 1, 2019, without affecting the remaining term for computing any payments made in excess during its life as payments on account of income tax.

As of the closing date hereof, the Company’s Management analyzed the receivable’s recoverability, and allowances are created in as long as it is estimated that the amounts paid for this tax will not be recoverable within the statutory limitation period taking into consideration the Company’s current business plans. The Company’s Management will evaluate the evolution of this recoverability in future fiscal years.

Leases

In leases where the Company is a lessee (Note 18.1), a right-of-use asset and a lease liability are recognized 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 “Lease liability” under “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 18.2.1). Financial leases are recognized 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 recognized as a profit or a loss 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 derecognized 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 18.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

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16. INVESTMENT COMMITMENTS

12 Months Ended

Dec. 31, 2019

Investment Commitments

INVESTMENT COMMITMENTS

16.1 New generation projects

Under the National Government’s call for the expansion of the generation offer, the Company participates in the following thermal generation projects:

16.1.1 PEPE II and PEPE III wind farms

On May 10, 2019, CAMMESA declared the commercial commissioning of PEPE II (Pampa Energía wind farm) for a 50.4 MW power capacity and PEPE III (de la Bahía wind farm) for a 28.8 MW power capacity, the commercial commissioning for a 50.4 MW power capacity of the latter being completed on June 10, 2019. PEPE II is located in an area adjacent to Mario Cebreiro Wind Farm, in the area known as Corti, 20 kilometers from the City of Bahía Blanca. PEPE III is located in Coronel Rosales, near the City of Bahía Blanca. Both projects called for an investment of U$S 130 million and have an approximate 100.8 MW joint installed capacity.

The production of both wind farms is sold under agreements between private parties pursuant to the Term Market of Electric Power from Renewable Sources (MATER) Regime within the framework of SEE Resolution No. 281/17. Non-contracted energy will be remunerated according to the spot market remuneration (see Notes 2 and 23).

16.1.2 PEPE IV wind farm

The Company, as assignee of the rights under the PEPE IV project, requested to CAMMESA an extension of the term for the commercial commissioning of the wind farm, as well as its relocation. The request was authorized by the SGE and, to make it effective, CAMMESA asked the Company to meet certain requirements, including making several disbursements and increasing the originally granted guarantee pursuant to SGE Resolution No. 230/19.

However, as a result of events occurred during 2019, including the devaluation of the peso and the increase in interest rates, which have resulted in a growing macroeconomic instability, the Company requested an extension of the term to meet the above-mentioned requirements in order to evaluate the feasibility of the project under the new conditions, as well as to negotiate changes proposed by work contractors and equipment suppliers. In this context, and based on a thorough evaluation of the renewable projects in progress, on September 11, 2019 the SSERyEE instructed CAMMESA to temporarily suspend the claims for non-compliance, and demanded the Company to extend the validity of the U$S 12.5 million guarantee for a term of 180 days. On October 4, 2019, the Company complied with the requested extension. On October 9, 2019, the SSERyEE canceled the suspension. On October 30, 2019, CAMMESA served on the Company a formal demand requiring certain payments associated with the postponement of the commercial commissioning of the project and its relocation under penalty of enforcing the guarantee. The Company rejected the demand served by CAMMESA awaiting SGE’s consideration of the extension request, and on December 9, 2019 it entered into an agreement with CAMMESA establishing a negotiation process to be developed until January 31, 2020 inclusive, during which CAMMESA should suspend the enforcement of the guarantee. The agreement term was extended until February 29, 2020.

On the other hand, on September 2, 2019, the assignment of all CTB’s rights, receivables and debts under the project was formalized for a price of U$S 0.1 million, which were offset with receivables CTB held against the Company on account of loans and commercial debt.

16.1.3 Genelba Thermal Power Plant

On June 12, 2019, CAMMESA declared the commercial commissioning of Genelba power plant’s fourth gas turbine for a power capacity of up to 187.7 MW. Furthermore, CAMMESA enabled the 19 MW repowering of the existing gas turbine unit’s power capacity, as of June 1, 2019.These units are part of Genelba Plus’ closing to combined cycle project, which will include the placing in service of a steam turbine.

The Project was selected under SEE Resolution No. 926-E/17 within the framework of the “Call for the Execution of New Co-generation and Closing to Combined Cycles Projects” established by SEE Resolution No. 287-E/17. Upon the commercial commissioning of the closing to combined cycle, the Wholesale Power Purchase Agreement executed with CAMMESA for a maximum committed capacity of 377 MW and a term of 15 years will enter into effect.

The total investment for the project is estimated at U$S 350 million. After the completion of the project, Genelba Power Plant will have two combined cycles with a total installed capacity of approximately 1,226 MW.

16.1.4 Barragán Thermal Power Plant

Regarding the commitment to CTB’s closing to combined cycle project, detailed in Note 5.3.5, for increasing the installed power capacity from 567 MW to 847 MW, with an estimated investment of U$S 200 million, on September 27, 2019, CTB and a joint venture made up of SACDE and Techint Compañía Técnica Internacional S.A.C.E.I, executed an engineering, procurement, construction, commissioning and turnkey agreement for the execution of the closing of the combined cycle at CTEB (the “EPC Agreement”).

16.2 Investment commitment for the exploration and exploitation of hydrocarbons 

As of the issuance of these Consolidated Financial Statements, the Company has committed investments for an estimated total amount of U$S 354 million, based on its participation, to be disbursed between 2020 and 2023, mainly regarding the Sierra Chata, Las Tacanas, El Mangrullo and Rincón del Mangrullo areas.

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20. CONTRACTUAL RESOLUTION OF REAL ESTATE ASSET

12 Months Ended

Dec. 31, 2019

Contractual Resolution Of Real Estate Asset

CONTRACTUAL RESOLUTION OF REAL ESTATE ASSET

With regard to the real estate asset to be constructed, acquired by Edenor in November 2015, the subsequent termination of the agreement due to RDSA’s default in August 2018, and the respective legal actions brought by Edenor against the seller and the insurance company. On September 30, 2019, Edenor entered into a settlement agreement pursuant to which Edenor receives from the insurer as sole, full and final compensation of U$S 15 million and the assignment in its favor of the insurer’s right to subrogate to the insured’s rights for the amount paid against the policyholder (RDSA).

As of December 31, 2019, Edenor has collected of U$S 14 million. The remaining balance will be collected in 6 quarterly installments, the first of them on April 21, 2020.

Furthermore, the claim duly filed by Edenor with the Arbitral Tribunal of the BCBA against RDSA in order to obtain the refund of price paid for the undelivered real property was suspended so that the claim can be allowed in RDSA’s insolvency proceedings, such claim was allowed by the court hearing the case for the sum of U$S 35 million. Additionally, a review incident was initiated for the amount that was declared inadmissible in the verifying resolution, for an additional amount of $ 895.7 million.

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7. SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2019

Disclosure of operating segments [abstract]

Operating segments

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	819	1,502	174	321	20	-	2,836
Intersegment revenue	-	-	270	-	-	(270)	-
Cost of sales	(466)	(1,225)	(313)	(298)	-	270	(2,032)
Gross profit	353	277	131	23	20	-	804
Selling expenses	(3)	(122)	(12)	(9)	(2)	-	(148)
Administrative expenses	(36)	(65)	(47)	(4)	(22)	-	(174)
Exploration expenses	-	-	(9)	-	-	-	(9)
Other operating income	9	10	8	4	9	-	40
Other operating expenses	(11)	(43)	(11)	(9)	(12)	-	(86)
Impairment of property, plant and equipment	(52)	-	(10)	-	-	-	(62)
Share of profit from associates and joint ventures	13	-	21	-	67	-	101
Agreement on the regularization of obligations	-	285	-	-	-	-	285
Operating income	273	342	71	5	60	-	751
Gain on net monetary position, net	-	187	-	-	-	-	187
Finance income	51	20	18	1	7	(1)	96
Finance costs	(82)	(112)	(94)	(8)	(4)	1	(299)
Other financial results	86	(62)	84	18	(13)	-	113
Financial results, net	55	33	8	11	(10)	-	97
Profit before income tax	328	375	79	16	50	-	848
Income tax	(80)	(178)	(16)	(5)	231	-	(48)
Profit for the year	248	197	63	11	281	-	800
Depreciation and amortization	71	79	112	1	-	-	263

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit attributable to:
Owners of the company	239	98	63	11	281	-	692
Non - controlling interest	9	99	-	-	-	-	108
Consolidated statement of financial position as of December 31, 2019
Assets	1,472	1,480	1,261	136	1,527	(192)	5,684
Liabilities	1,226	1,792	465	122	(160)	(170)	3,275
Additional consolidated information as of December 31, 2019
Increases in property, plant and equipment, intangibles assets and right-of-use assets	240	173	191	4	3	-	611
Net book values of property, plant and equipment	1,152	1,691	612	18	34	-	3,507

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	604	1,484	458	338	36	-	2,920
Intersegment revenue	2	-	63	-	-	(65)	-
Cost of sales	(273)	(1,136)	(287)	(334)	-	63	(1,967)
Gross profit  (loss)	333	348	234	4	36	(2)	953
Selling expenses	(1)	(134)	(19)	(13)	(4)	-	(171)
Administrative expenses	(41)	(76)	(56)	(6)	(27)	-	(206)
Exploration expenses	-	-	(1)	-	-	-	(1)
Other operating income	11	9	141	5	15	-	181
Other operating expenses	(17)	(44)	(114)	(20)	(6)	1	(200)
Impairment of property, plant and equipment	-	-	-	(32)	-	-	(32)
Share of profit (loss) from joint ventures and associates	(11)	-	37	-	92	-	118
Income from the sale of associates	-	-	28	-	-	-	28
Operating income (loss)	274	103	250	(62)	106	(1)	670
Gain on net monetary position	233	226	107	49	12	2	629
Finance income	52	18	15	1	14	(1)	99
Finance costs	(85)	(132)	(79)	(15)	(6)	1	(316)
Other financial results	(365)	(50)	(512)	(39)	108	-	(858)
Financial results, net	(165)	62	(469)	(4)	128	2	(446)
Profit (loss) before income tax	109	165	(219)	(66)	234	1	224
Income tax	(3)	(49)	57	12	(34)	-	(17)
Profit (loss) for the year from continuing operations	106	116	(162)	(54)	200	1	207
Profit for the year from discontinued operations	-	-	49	-	31	-	80
Profit (loss) for the year	106	116	(113)	(54)	231	1	287
Depreciation and amortization	66	69	92	6	1	-	234

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the company	100	61	(115)	(54)	231	1	224
Non - controlling interest	6	55	2	-	-	-	63
Consolidated statement of financial position as of December 31,2018
Assets	1,414	2,133	1,237	153	872	(137)	5,672
Liabilities	1,054	1,241	1,273	198	247	(136)	3,877
Additional consolidated information as of December 31, 2018
Increases in property, plant and equipment	235	227	192	4	7	-	665
Net book values of property, plant and equipment	1,036	1,657	554	15	54	-	3,316

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	351	1,050	443	314	17	-	2,175
Intersegment revenue	2	-	19	-	-	(21)	-
Cost of sales	(195)	(799)	(310)	(290)	(1)	21	(1,574)
Gross profit	158	251	152	24	16	-	601
Selling expenses	(4)	(95)	(17)	(12)	-	1	(127)
Administrative expenses	(32)	(66)	(54)	(16)	(30)	-	(198)
Exploration expenses	-	-	(2)	-	-	-	(2)
Other operating income	19	4	110	3	13	-	149
Other operating expenses	(9)	(33)	(38)	(10)	(13)	-	(103)
Share of profit (loss) from joint ventures and associates	(2)	-	1	-	49	-	48
Operating income (loss)	130	61	152	(11)	35	1	368
Gain (loss) on net monetary position	17	145	(18)	2	158	-	304
Finance income	39	12	6	-	7	(2)	62
Finance costs	(69)	(69)	(78)	(10)	(8)	2	(232)
Other financial results	(34)	1	(93)	(6)	32	-	(100)
Financial results, net	(47)	89	(183)	(14)	189	-	34
Profit (loss) before income tax	83	150	(31)	(25)	224	1	402
Income tax	(4)	(12)	24	19	(1)	-	26
Profit (loss) for the year from continuing operations	79	138	(7)	(6)	223	1	428
(Loss) profit for the year from discontinued operations	-	-	(35)	-	(16)	1	(50)
Profit (loss) for the year	79	138	(42)	(6)	207	2	378
Depreciation and amortization	54	58	87	4	2	-	205

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the Company	75	73	(62)	(6)	207	2	289
Non - controlling interest	4	65	20	-	-	-	89
Consolidated statement of financial position as of December 31,2017
Assets	1,115	1,972	1,154	141	1,475	(200)	5,657
Liabilities	333	1,166	444	94	1,850	(200)	3,687
Additional consolidated information as of December 31, 2017
Increases in property, plant and equipment	275	225	140	5	12	-	657

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2. REGULATORY FRAMEWORK (Tables)

12 Months Ended

Dec. 31, 2019

Regulatory Framework

Generating units in operation

In operation:
Generator	Generating unit	Tecnology	Power	Applicable regime (2)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1281/06 (1)
CTG	GUEMTV11	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV12	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV13	TV	>100 MW	SE Resolutions No. 1/19
Piquirenda	PIQIDI 01-10	MG	30 MW	SE Resolution No. 220/07 (1)
CPB	BBLATV29	TV	>100 MW	SE Resolutions No. 1/19
CPB	BBLATV30	TV	>100 MW	SE Resolutions No. 1/19
CT Ing. White	BBLMD01-06	MG	100 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATG01	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG02	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG03	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG04	TG	105 MW	SEE Res. 220/07 (75%), SEE Res. 1/19 (25%)
CTLL	LDLATG05	TG	105 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATV01	TV	180 MW	SE Resolution No. 220/07 (1)
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	SE Resolutions No. 1/19
CTGEBA	GEBATG03	TG	188 MW	Energy Plus Res. No. 1281/06 (1)
CTGEBA	GEBATG04	TG	>100 MW	SE Resolutions No. 1/19 (3)
Ecoenergía	CERITV01	TV	Renewable  = 50	Energy Plus Res. N° 1281/06 (1)
CT Parque Pilar	PILBD01-06	MG	100 MW	SE Resolutions No. 1/19 (3)
CTB	EBARTG01 - TG02	TG	HI – Small  50<P≤120	SE Resolution No. 220/07 (1)
HIDISA	AGUA DEL TORO	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	EL TIGRE	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	LOS REYUNOS	HB	HB – Media  120<P≤300	SE Resolutions No. 1/19
HINISA	NIHUIL I - II - III	HI	HI – Chica  50<P≤120	SE Resolutions No. 1/19
HPPL	PPLEHI	HI	HI – Media  120<P≤300	SE Resolutions No. 1/19
P.E. M. Cebreiro	CORTEO	Eólica	100 MW	Renovar (1)
PEPE II	PAMEEO	Eólica	53 MW	SEE Resolution No. 281/17
PEPE III	BAHIEO	Eólica	53 MW	SEE Resolution No. 281/17
(1) Uncommitted power and energy is remunerated according to Resolution No. 1/19.
(2) Resolution No. 1/19 entered into force as of February 19. During the month of January 2019, it was remunerated under Resolution No. 19/17.
(3) Once the combined cycle is commercially enabled, the supply agreements with CAMMESA will come into force under Resolution No. 287/17.

Generating units in construction

In construction:
Generator	Generating unit	Tecnology	Applicable regime
CTLL	MG	15 MW	SE Resolutions No. 1/19
CTGEBA	CC	176 MW	SE Resolution No. 287/17
CTB	CC	280 MW	SE Resolution No. 220/07

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Millions	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
Beginning balance at Dec. 31, 2016	$ 51	$ 287	$ 421	$ 0	$ 0	$ 0	$ 15	$ 250	$ 9	$ (4)	$ 114	$ 1,143	$ 464	$ 1,607
Constitution of legal reserve - Shareholders' meeting							4				(4)	0	0	0
Constitution of voluntary reserve - Shareholders' meeting								83			(83)	0	0	0
Stock compensation plans			1						1			2	0	2
Acquisition of own shares						(3)						(3)	0	(3)
Merger with subsidiaries	4	2	69									75	(75)	0
Dividends provided for pay												0	(4)	(4)
Profit for the year											286	286	92	378
Other comprehensive income (loss) for the year										(6)		(6)	(5)	(11)
Ending balance at Dec. 31, 2017	55	289	491	0	0	(3)	19	333	10	(10)	313	1,497	472	1,969
Change in accounting policies											(1)	(1)	(1)	(2)
Beginning balance	55	289	491	0	0	(3)	19	333	10	(10)	312	1,496	471	1,967
Constitution of legal reserve - Shareholders' meeting							5				(5)	0	0	0
Constitution of voluntary reserve - Shareholders' meeting								128			(128)	0	0	0
Stock compensation plans												0	0	0
Acquisition of own shares	(5)	(29)		5	29	(332)			(23)			(355)	(14)	(369)
Dividends provided for pay												0	(2)	(2)
Capital reduction				(5)	(25)	296		(266)				0	0	0
Sale of interest in subsidiaries												0	(93)	(93)
Profit for the year											224	224	63	287
Other comprehensive income (loss) for the year										1		1	4	5
Ending balance at Dec. 31, 2018	50	260	491	0	4	(39)	24	195	(13)	(9)	403	1,366	429	1,795
Constitution of legal and voluntary reserve - Shareholders' meeting							18	351			(369)	0	0	0
Stock compensation plans									1			1	0	1
Acquisition of own shares	(4)		19	4		(135)			(6)			(122)	(29)	(151)
Dividends provided for pay												0	(1)	(1)
Capital reduction				(3)	(3)	130		(124)				0	0	0
Profit for the year											692	692	108	800
Other comprehensive income (loss) for the year										(20)		(20)	(15)	(35)
Ending balance at Dec. 31, 2019	$ 46	$ 260	$ 510	$ 1	$ 1	$ (44)	$ 42	$ 422	$ (18)	$ (29)	$ 726	$ 1,917	$ 492	$ 2,409

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11. NON-FINANCIAL ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

Non-financial Assets And Liabilities

Changes in property plant and equipment

	Original values
Type of good	At the beginning	Increases	Impairment	Transfers (1)	Decreases	Traslation effect	At the end
Land	22	-	-	-	(8)	-	14
Buildings	207	1	(8)	4	(1)	(1)	202
Equipment and machinery	1,051	1	(90)	297	(5)	-	1,254
High, medium and low voltage lines	1,010	3	-	72	(4)	(32)	1,049
Substations	365	-	-	14	-	(12)	367
Transforming chamber and platforms	208	4	-	15	(1)	(7)	219
Meters	209	1	-	23	-	(7)	226
Wells	562	24	-	94	(8)	-	672
Mining property	267	-	(14)	-	-	-	253
Vehicles	22	1	-	-	-	(1)	22
Furniture and fixtures and software equipment	67	4	-	4	-	(1)	74
Communication equipments	15	-	-	-	-	-	15
Materials and spare parts	32	19	-	(14)	-	-	37
Distribution storage center	10	-	-	-	(10)	-	-
Petrochemical industrial complex	15	-	-	(1)	-	-	14
Work in progress	783	510	-	(487)	(3)	(11)	792
Advances to suppliers	19	23	-	(23)	-	(1)	18
Other goods	4	-	-	2	-	-	6
Total at 12.31.2019	4,868	591	(112)	-	(40)	(73)	5,234
Total at 12.31.2018	4,317	665	(56)	-	(58)	-	4,868

⁽¹⁾   Includes the transfer of materials and spare parts to the item "Inventories" of the current asset.

	Depreciation
							Net book values
Type of good	At the beginning	Decreases	Impairment	For the year	Traslation effect	At the end	At the end	At 12.31.2018
Land	-	-	-	-	-	-	14	22
Buildings	(74)	1	5	(7)	-	(75)	127	133
Equipment and machinery	(384)	4	41	(72)	-	(411)	843	667
High, medium and low voltage lines	(323)	4	-	(35)	10	(344)	705	687
Substations	(105)	-	-	(13)	3	(115)	252	260
Transforming chamber and platforms	(57)	-	-	(8)	2	(63)	156	151
Meters	(80)	-	-	(10)	3	(87)	139	129
Wells	(321)	-	-	(65)	-	(386)	286	241
Mining property	(119)	-	4	(29)	-	(144)	109	148
Vehicles	(16)	-	-	(5)	-	(21)	1	6
Furniture and fixtures and software equipment	(48)	-	-	(9)	-	(57)	17	19
Communication equipments	(10)	-	-	-	-	(10)	5	5
Materials and spare parts	(2)	-	-	(1)	-	(3)	34	30
Distribution storage center	(2)	3	-	-	-	1	1	8
Petrochemical industrial complex	(7)	-	-	(1)	-	(8)	6	8
Work in progress	-	-	-	-	-	-	792	783
Advances to suppliers	-	-	-	-	-	-	18	19
Other goods	(4)	-	-	-	-	(4)	2	-
Total at 12.31.2019	(1,552)	12	50	(255)	18	(1,727)	3,507
Total at 12.31.2018	(1,358)	9	24	(227)	-	(1,552)		3,316

Changes in intangible assets

Original values
Type of good	At the beginning	Traslate Effect	At the end
Concession agreements	272	(2)	270
Goodwill	35	-	35
Intangibles identified in acquisitions of companies	7	-	7
Total at 12.31.2019	314	(2)	312
Total at 12.31.2018	314	-	314
	Depreciation
Type of good	At the beginning	For the year	At the end
Concession agreements	(151)	(8)	(159)
Intangibles identified in acquisitions of companies	(2)	-	(2)
Total at 12.31.2019	(153)	(8)	(161)
Total at 12.31.2018	(146)	(7)	(153)
	Net book values
Type of good	At the end	At 12.31.2018
Concession agreements	111	121
Goodwill	35	35
Intangibles identified in acquisitions of companies	5	5
Total at 12.31.2019	151
Total at 12.31.2018		161

Deferred tax assets and liabilities

	12.31.2018	Profit (loss)	Gain on monetary position, net	12.31.2019
Tax loss carryforwards	52	59	-	111
Trade and other receivables	14	(1)	-	13
Trade and other payables	52	(37)	(2)	13
Salaries and social security payable	1	1	-	2
Defined benefit plans	9	(2)	-	7
Provisions	32	7	-	39
Taxes payable	6	(6)	-	-
Adjustment for tax inflation	-	8	-	8
Other	2	(2)	-	-
Deferred tax asset	168	27	(2)	193
Property, plant and equipment	(334)	(55)	5	(384)
Adjustment for tax inflation	-	(99)	-	(99)
Investments in companies	(19)	11	-	(8)
Intangible assets	(193)	175	5	(13)
Inventory	-	(10)	-	(10)
Trade and other receivables	(9)	5	-	(4)
Financial assets at fair value through profit and loss	(9)	(2)	-	(11)
Cash and cash equivalents	-	-	-	-
Borrowings	(3)	3	-	-
Taxes payable	-	(4)	-	(4)
Other	(6)	6	-	-
Deferred tax liabilities	(573)	30	10	(533)

	12.31.2017	Profit (loss)	Other comprehensive income (loss)	12.31.2018
Tax los-carryforwards	64	(12)	-	52
Trade and other receivables	4	10	-	14
Derivative financial instruments	-	-	-	-
Financial assets at fair value through profit and loss	-	-	-	-
Trade and other payables	46	6	-	52
Salaries and social security payable	-	1	-	1
Defined benefit plans	11	(3)	1	9
Provisions	29	3	-	32
Taxes payable	7	(1)	-	6
Liabilities associated to assets classified as held for sale	14	(14)	-	-
Other	2	-	-	2
Deferred tax asset	177	(10)	1	168
Property, plant and equipment	(443)	108	-	(335)
Investments in companies	(52)	35	(2)	(19)
Intangible assets	(2)	(190)	-	(192)
Trade and other receivables	(27)	17	-	(10)
Financial assets at fair value through profit and loss	(3)	(6)	-	(9)
Borrowings	(5)	2	-	(3)
Assets classified as held for sale	(33)	33	-	-
Other	(4)	(1)	-	(5)
Deferred tax liabilities	(569)	(2)	(2)	(573)

Net deferred tax assets and liabilities

	12.31.2019	12.31.2018
Deferred tax asset	28	2
Deferred tax liabilities	(368)	(407)
Deferred tax liabilities, net	(340)	(405)

Inventories

	12.31.2019	12.31.2018
Materials and spare parts	95	94
Advances to suppliers	21	2
In process and finished products	37	40
Stock crude oil	-	1
Total	153	137

Provisions

	12.31.2019	12.31.2018
Non-Current
Provisions for contingencies	123	125
Asset retirement obligation and dismantling of wind turbines	20	20
Environmental remediation	1	1
Other provisions	1	-
	145	146
Current
Provisions for contingencies	16	17
Asset retirement obligation and dismantling of wind turbines	2	2
Environmental remediation	2	4
Other provisions	-	-
	20	23

Changes in provisions

	12.31.2019
	For contingencies	Asset retirement obligation and dismantling of wind turbines	For environmental remediation
At the beginning of the year	142	22	5
Increases	41	3	-
Decreases	(10)	-	(2)
Exchange differences on translation	(4)	-	-
Gain on monetary position, net	(17)	-	-
Reversal of unused amounts	(13)	(3)	-
At the end of the year	139	22	3
	12.31.2018
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	141	42	6
Increases	106	37	6
Reclasification	-	(18)	-
Gain on monetary position, net	(52)	(18)	(2)
Decreases	(23)	(5)	(5)
Reversal of unused amounts	(30)	(16)	-
At the end of the year	142	22	5
	12.31.2017
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	199	91	17
Increases	43	29	4
Reclasification	(9)	(1)	1
Reclasification to liabilities associated to assets classified as held for sale	-	(34)	(7)
Gain on monetary position, net	(37)	(18)	(3)
Decreases	(39)	(7)	(6)
Reversal of unused amounts	(16)	(18)	-
At the end of the year	141	42	6

Income tax and minimum notional income tax liability

	12.31.2019	12.31.2018
Non-current
Income tax, net of witholdings and advances	10	27
Total non current	10	27
Current
Income tax, net of witholdings and advances	53	25
Minimum notional income tax, net of witholdings and advances	-	4
Total current	53	29

Tax liabilities

	12.31.2019	12.31.2018
Non-current
Value added tax	-	4
Sales tax	1	1
Payment plans	-	2
Extraordinary Canon	3	7
Total non-current	4	14
Current
Value added tax	38	21
Municipal, provincial and national contributions	3	3
Personal assets tax provision	3	-
Payment plans	1	1
Municipal taxes	2	3
Tax withholdings to be deposited	6	9
Royalties	4	5
Extraordinary Canon	12	10
Other	3	2
Total current	72	54

Defined benefit plan information

	12.31.2019
	Present value of the obligation	Fair value of plan assets	Net liability at the end of the year
Liabilities at the beginning	40	(5)	35
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	15	(2)	13
Items classified in other comprehensive  income
Actuarial (gains) losses	(2)	-	(2)
Benefit payments	(2)	-	(2)
Gain on monetary position, net	(18)	2	(16)
At the end	36	(5)	31
	12.31.2018
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	47	(3)	44
Items classified in profit or loss
Current services cost	2	-	2
Cost for interest	9	(1)	8
Past services cost	(5)	-	(5)
Items classified in other comprehensive  income
Actuarial losses (gains)	6	(2)	4
Benefit payments	(3)	-	(3)
Increase for subsidiries acquisition	(16)	1	(15)
At the end	40	(5)	35

	12.31.2017
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	58	(8)	50
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	12	(1)	11
Past services cost	1	-	1
Items classified in other comprehensive income
Actuarial losses (gains)	(1)	-	(1)
Exchange differences on translation	1	(1)	-
Benefit payments	(2)	-	(2)
Reclasification to liabilities associated to assets classified as hed for sale	(11)	4	(7)
Gain (loss) on net monetary position	(14)	3	(11)
At the end	47	(3)	44

Estimated expected benefits payments

	12.31.2019
Less than one year	4
One to two years	3
Two to three years	2
Three to four years	2
Four to five years	2
Six to ten years	11

Principal actuarial assumptions

	12.31.2019	12.31.2018	12.31.2017
Discount rate	5%	5%	5%
Salaries increase	1%	1%	1%
Average inflation	50%	27%	21%

Sensitivity analyses on actuarial assumptions variations

	12.31.2019
Discount rate: 4%	39
Obligation	3
Variation	10%
Discount rate: 6%	33
Obligation	(3)
Variation	(9%)
Salaries increase: 0%	34
Obligation	(2)
Variation	(5%)
Salaries increase: 2%	38
Obligation	2
Variation	6%

Salaries and social security payable

	12.31.2019	12.31.2018
Non-current
Seniority - based bonus	3	4
Early retirements payable	1	-
Total non-current	4	4
Current
Salaries and social security contributions	22	24
Provision for vacations	17	19
Provision for gratifications and annual bonus for efficiency	26	29
Total current	65	72

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3. BASIS OF PREPARATION

12 Months Ended

Dec. 31, 2019

Basis Of Preparation

BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS issued by IASB.

These Consolidated Financial Statements have been approved for issue by the Board of Directors dated March 9, 2020. Significant accounting policies adopted in the preparation of these Consolidated Financial Statements are described in Note 4, which have been consistently applied in these Consolidated Financial Statements, except as mentioned in Note 3.1.

These accounting policies have been applied consistently by all Group companies.

3.1 Change in Functional Currency

The Company changed its functional and presentation currencies from the Peso to the U.S. dollar commencing on January 1, 2019 following a change in facts and circumstances relevant to its business operations. Therefore, as from January 1, 2019, the Company records its operations in U.S. dollars, the new functional currency, and also presents its Consolidated Financial Statements in U.S. dollars.

For purposes of effecting this change, the Company has considered the following factors that have influenced the environment in which the entity operates and its sales prices:

i.	the divestment in the refining and distribution segment in 2018, which has historically been subject to regulations by the Argentine Government and prices set in Pesos;
ii.	the growing trend of the execution of agreements denominated in U.S. dollars in line with the Company’s strategy to focus investments and resources on the expansion of its power generation installed capacity; and
iii.	the keeping in effect of the remuneration scheme for generation during 2019, with prices directly established in U.S. dollars by the Argentine Government, despite the context of instability both at the local and international levels, including the significant exchange rate stress that the Argentine economy has endured.

The Company effected the change in functional currency prospectively as from January 1, 2019, as required by IAS 21 “The effects of changes in foreign exchange rates”.

Upon the change in the functional currency, all transactions in currencies other than the functional currency are considered “foreign currency transactions”.

After the closing of the fiscal year, Resolution SE No. 31/20, as detailed in Note 23, exclusively modified the remuneration scheme for sales in the spot market established by SRRYME Resolution No. 1/19 as from the commercial transaction corresponding to February 1, 2020.

It is worth highlighting that even if the above-mentioned modification adversely affects the profitability of the generation business, the management has concluded that it does not constitute a change to the underlying primary economic environment in which the entity operates due to: i) the higher incidence in 2019 of revenues from dollar-denominated contracts compared to revenues from sales in the spot market in the generation segment as a result of the commissioning of PEPE II and PEPE III wind farms for 106 MW in May and June 2019, which will increase in 2020 through the entry into effect of the contract remunerating the extension and closing to combined cycle of the CTGEBA for 383 MW; and ii) the fact that the dollar remains the basis for setting sales prices and costs in the oil & gas and petrochemicals segments.

3.2 Comparative information

The comparative information has been stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29 "Financial reporting in hyperinflationary economies", since the Peso was the Company’s functional currency up to that date.

The inflation adjustment was calculated taking into consideration the indexes set by the FACPCE based on the price indexes published by the INDEC. As of December 31, 2018, the price index increased to 184.255, with an annual inflation rate of 47.6%.

As from the change in functional currency detailed in Note 3.1, the Company has discontinued the preparation and presentation of financial statements in accordance with IAS 29, and has treated the amounts expressed in terms of the measuring unit current as of December 31, 2018 as the basis for the carrying amounts in subsequent financial statements.

The information as of December 31, 2018 and 2017 disclosed for comparative purposes arises from the Consolidated Financial Statements denominated in Pesos stated in terms of the measuring unit current as of December 31, 2018 in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

Certain not significant reclassifications have been made to those financial statements to keep the consistency in the presentation with the amounts of the current year.

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8. REVENUE

12 Months Ended

Dec. 31, 2019

Revenue [abstract]

REVENUE

	12.31.2019	12.31.2018	12.31.2017
Energy sales to the Spot Market	251	274	231
Energy sales by supply contracts	285	278	114
Fuel self-supply	281	51	4
Other sales	2	1	2
Generation sales subtotal	819	604	351
Energy sales	1,496	1,477	1,042
Right of use of poles	5	5	6
Connection and reconnection charges	1	2	2
Distribution of energy sales subtotal	1,502	1,484	1,050
Oil, gas and liquid sales	171	454	418
Other sales	3	4	25
Oil and gas sales subtotal	174	458	443
Technical assistance services  and administartion sales	20	36	17
Holding and others subtotal	20	36	17
Petrochemicals sales	321	338	314
Petrochemicals sales subtotal	321	338	314
Total revenue	2,836	2,920	2,175

Revenue is recognized:

1)	At a point in time, that is the effective delivery of the energy, the product or the provision of connection or reconnection services for a total amount of U$S 2,464 million, U$S 2,542 million and U$S 1,976 million as of December 31, 2019, 2018 and 2017, respectively;
2)	Over time in case of power availability, technical assistance services and right to use poles for a total of U$S 372 million, U$S 378 million and U$S 199 million as of December 31, 2019, 2018 and 2017, respectively.

XML

12. FINANCIAL ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2019

Financial Assets And Liabilities

FINANCIAL ASSETS AND LIABILITIES

12.1 Financial assets at amortized cost

	12.31.2019	12.31.2018
Non-current
Public securities (1)	18	-
Total non-current	18	-
Current
Time deposits	-	35
Public securities (1)	54	-
Total current	54	35

⁽¹⁾   The public securities were received in accordance with the mechanism set forth by SGE Resolution No. 54/19 for the settlement of receivables under Natural Gas Surplus Injection Promotion Programs. See Note 2.4.3.1.

12.2 Financial assets at fair value through profit and loss

	12.31.2019	12.31.2018
Non-current
Shares	11	11
Total non-current	11	11
Current
Government securities	113	298
Shares	8	1
Investment funds	244	106
Total current	365	405

12.3 Trade and other receivables

	Note	12.31.2019	12.31.2018
Non-Current
CAMMESA Receivable (1)		-	70
Other		8	23
Trade receivables, net		8	93
Non-Current
Tax credits		3	13
Related parties	17	53	49
Prepaid expenses		1	1
Financial credit		-	1
Receivable for sale of property, plant and equipment		-	3
Natural Gas Surplus Injection Promotion Program (2)		-	71
Credit with RDSA	20	35	20
Allowance for doubtful accounts		(35)	-
Other		14	2
Other receivables, net		71	160
Total non-current		79	253

Current	Note	12.31.2019	12.31.2018
Receivables from energy distribution sales		226	223
Receivables from MAT		17	27
CAMMESA		168	131
CAMMESA Receivable (1)		-	15
Receivables from oil and gas sales (3)		48	78
Receivables from refinery and distribution sales		-	6
Receivables from petrochemistry sales		54	67
Related parties	17	6	10
Government of the PBA and CABA by Social Rate		4	-
Other		10	4
Allowance for doubtful accounts		(33)	(34)
Trade receivables, net		500	527
Tax credits		10	27
Advances to suppliers		-	2
Related parties	17	8	5
Prepaid expenses		2	2
Receivables for non-electrical activities		11	14
Financial credit		5	6
Guarantee deposits		5	13
Natural Gas Surplus Injection Promotion Program (2)		-	71
Insurance to recover		-	6
Expenses to be recovered		10	11
Credits for the sale of property, plant and equipment		1	21
Credit with RDSA	20	1	-
Other		14	6
Allowance for other receivables		(6)	(8)
Other receivables, net		61	176
Total current		561	703

(1)	CAMMESA receivables were settled in pursuant to the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
(2)	Receivables under the Natural Gas Surplus Injection Promotion Programs were settled through the delivery of public securities pursuant to the mechanism set forth by SGE Resolution No. 54/19 (see Note 2.4.3.1).
(3)	Including U$S 14.6 million corresponding to the receivables with gas distributors pursuant to the procedure set forth by PEN Executive Order No. 1,053/18 and regulated by ENARGAS Resolution No. 466/19 (see Note 2.4.3.2).

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 allowance for the impairment of trade receivables are as follows:

	12.31.2019	12.31.2018	12.31.2017
At the beginning	34	26	21
Allowance for impairment	23	34	13
Utilizations	(13)	(10)	(3)
Reversal of unused amounts	(2)	(1)	-
Exchange differences on translation	(1)	-	-
Reclasification to  assets held   for sale	-	-	(5)
Gain on monetary position, net	(8)	(15)	(5)
At the end of the year	33	34	21

The movements in the allowance for the impairment of other receivables are as follows:

	12.31.2019	12.31.2018	12.31.2017
At the beginning	8	6	10
Allowance for impairment	1	7	1
Gain on monetary position, net	(1)	(3)	-
Decreases	-	-	(1)
Reversal of unused amounts	(2)	(2)	(5)
At the end of the year	6	8	5

12.4 Cash and cash equivalents

	12.31.2019	12.31.2018
Banks	57	83
Investment funds	4	-
Time deposits	164	158
Total	225	241

12.5 Borrowings

Non-Current	Note	12.31.2019	12.31.2018
Financial borrowings		161	258
Corporate bonds (1)		1,603	1,457
CAMMESA financing		-	120
		1,764	1,835
Current
Financial borrowings		137	313
Corporate bonds		32	25
CAMMESA financing		-	3
Related parties	17	14	1
		183	342
Total		1,947	2,177

⁽¹⁾   Net of the repurchase of Corporate Bonds of Pampa Energía for a nominal value of U$S 81 million and U$S 9 million and the repurchase of Edenor’s Corporate Bonds for a nominal value of U$S 29 million and U$S 10 million as of December 31, 2019 and 2018, respectively.

As of December 31, 2019 and 2018, the fair values of the Company’s Corporate Bonds amount approximately to U$S 1,436 million and U$S 1,300 million, respectively. Such values were calculated on the basis of the determined market price of the Company’s corporate notes at the end of each year (fair value level 1 and 2).

The carrying amounts of short-term borrowings approximate their fair value due to their short-term maturity.

The other long-term borrowings were measured at amortized cost, which does not differ significantly from its fair value.

The movements in the borrowings are as follows:

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning		2,177	1,683	1,269
Proceeds from borrowings		556	245	1,250
Payment of borrowings		(550)	(240)	(733)
Accrued interest		185	179	143
Payment of borrowings' interests		(148)	(133)	(108)
Net foreign currency exchange difference		50	1,244	227
Results for the repurchase of corporate bonds	12.5.2	(27)	(2)	-
Costs capitalized in property, plant and equipment	11.1	17	8	14
Decrease through offsetting  with trade receivables		(135)	-	-
Gain on monetary position, net		(88)	(795)	(379)
Repurchase and redemption of corporate bonds		(91)	(13)	(1)
Other financial results		1	1	1
At the end of the year		1,947	2,177	1,683

As of the date of issuance of these Consolidated Financial Statements, the Company is in compliance with the covenants established in its indebtedness

12.5.1 Details of borrowings:

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2019
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	139
Class E CB	PAMPA	ARS	575	Variable	Badlar	Nov-20	10
Class 1 CB	PAMPA	U$S	687	Fixed	7.50%	Ene-27	698
T Series  CB	PAMPA	U$S	487	Fixed	7.38%	Jul-23	497
Serie 3 CB (1)	PAMPA	U$S	293	Fixed	9.13%	Abr-29	291
							1,635
Regulatory:
Thrid parties:
	PAMPA	U$S	84	Fixed	Between 4.25% and 7.65%	Jan-2020 to May-2020	88
	PAMPA	U$S	39	Fixed and variable	4.21% + Libor	May-2024	39
	PAMPA	ARS	7,775	Fixed	Between 40% and 44.14%	Apr-2021 to Apr-2022	146
							273
Related parties:
	PAMPA	U$S	13	Fixed	6.0%	2020	14
Financial loans:
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	25
							25
							1,947

⁽¹⁾   On June 10, 2019, the Company issued Series 3 Corporate Bonds for a face value of U$S 300 million. These corporate bonds accrue interest at a fixed rate of 9.125% payable semi-annually, and the principal will be payable in a single installment upon maturity, in April 2029.

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2018
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	170
Class 4 CB (1)	PAMPA	U$S	34	Fixed	6.25%	Oct 20	34
Class E CB	PAMPA	ARS	607	Fixed	Badlar	Nov-20	16
T Series  CB	PAMPA	U$S	500	Fixed	7.38%	Jul-23	753
Class 1  CB	PAMPA	U$S	747	Fixed	7.50%	Jan-27	510
							1,483
Regulatory:
CAMMESA 2014 Agreement	PAMPA	ARS	855	Variable	CAMMESA	(2)	57
CAMMESA Mapro	PAMPA	ARS	174	Variable	CAMMESA	(2)	7
CAMMESA Mapro	CPB	ARS	1,085	Variable	CAMMESA	(2)	59
							123
Financial loans:
	PAMPA	U$S	17,116	Fixed	Between 3.6% and 6.8%	Feb-2019 to May-2021	459
	PAMPA	U$S	1,746	Fixed and variable	6% + Libor	May-2024	46
	PAMPA	ARS	550	Fixed	22.25%	Sep-2019 to Oct-2019	15
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	51
							571
							2,177

(1)	On July 12, 2019, the Company provided for the early redemption of Series 4 Corporate Bonds for a value of U$S 34 million.
(2)	Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).

12.5.2 Acquisition of own Corporate Bonds

As of the closing of fiscal year 2019, Pampa held in its portfolio: Series T Corporate Bonds maturing in 2023 for a face value of U$S 13.5 million, repurchased at an average clean price of U$S 74.55 per face value of U$S 100; Series 1 Corporate Bonds maturing in 2027 for a face value of U$S 63.03 million, repurchased at an average clean price of U$S 74.27 per face value of U$S 100; Series 3 Corporate Bonds for U$S 7.33 million, repurchased at an average clean price of U$S 78.63 per face value of U$S 100.

During fiscal years ended December 31, 2019 and 2018, the Company and its subsidiaries purchased and/or redeemed own or different subsidiaries’ Corporate Bonds at their respective market values for a total face value of U$S 91 million and U$S 13.2 million, respectively. As a result of these repurchase and/or redemption transactions, the Company reported consolidated losses for U$S 27 million and U$S 2 million in the fiscal years ended December 31, 2019 and 2018, respectively, which are disclosed in the “Results from the repurchase of corporate bonds” item under Other financial results (see Note 10.5).

12.5.3 Edenor - Global Program for the Issuance of Corporate Bonds

On August 8, 2019, Edenor’s General Ordinary Shareholders’ Meeting approved the creation of Edenor’s Global Program for the Issuance of Corporate Bonds effective for a term of five years and for a maximum outstanding amount of U$S 750 million, or its equivalent value in other currencies. 

12.5.4 Financial loans

In 2019, Pampa paid off Banking debt (including pre-export finance facilities) for U$S 420 million and $ 550 million, and took on new debt for U$S 25 million and $ 8,349 million. As of December 31, 2019, approximately 60% of the bank debt is denominated in pesos. 

As of December 31, 2019, Pampa’s short-term principal maturities amounted to U$S 92 million and $ 575.2 million, whereas Edenor’s short-term maturities amounted to U$S 25 million.

After the closing of the fiscal year, Pampa repaid financing at maturity for a total amount of U$S 25 million.

12.6.  Trade and other payables

Non-Current		12.31.2019	12.31.2018
Customer contributions		3	3
Funding contributions for substations		-	1
Customer guarantees		4	4
Trade payables		7	8
ENRE Penalties and discounts		64	138
Loans (mutuums) with CAMMESA		-	61
Compensation agreements		7	7
Liability with FOTAE		-	5
Payment agreement with ENRE		-	1
Lease liability		12	-
Other		-	-
Other payables		83	212
Total non-current		90	220
Current	Note	12.31.2019	12.31.2018
Suppliers		212	250
CAMMESA		155	316
Customer contributions		1	-
Discounts to customers		-	1
Customer advances		7	6
Related parties	17	8	6
Other		-	1
Trade payables		383	580
ENRE Penalties and discounts		57	49
Related parties	17	5	-
Compensation agreements		3	13
Payment agreements with ENRE		1	2
Other creditors		-	8
Lease liability		4	-
Other		1	5
Other payables		71	77
Total current		454	657

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, except non-current customer contributions.

The fair values of non-current customer contributions as of December 31, 2019 and 2018 amount to U$S 0.8 million and U$S 2.9 million, respectively. The fair values are determined based on estimated discounted cash flows in accordance with a market rate for this type of transactions. This fair value is classified as level 3.

The book value of the compensation agreements approximates their fair value given the valuation characteristics (Note 4.17).

12.7 Financial instruments by category

The following chart presents financial instruments by category:

As of December 31, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	622	4	626	14	640
Financial assets at fair value through profit and loss
Government securities	-	113	113	-	113
Shares	-	19	19	-	19
Investment funds	-	244	244	-	244
Derivative financial instruments	-	4	4	-	4
Cash and cash equivalents	221	4	225	-	225
Total	843	388	1,231	14	1,245
Liabilities
Trade and other liabilities	408	7	415	129	544
Borrowings	1,947	-	1,947	-	1,947
Derivative financial instruments	-	3	3	-	3
Total	2,355	10	2,365	129	2,494
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	909	3	912	44	956
Financial assets at amortized cost
Government securities	35	-	35	-	35
Financial assets at fair value through profit and loss
Government securities	-	298	298	-	298
Shares	-	12	12	-	12
Investment funds	-	106	106	-	106
Cash and cash equivalents	241	-	241	-	241
Total	1,185	419	1,604	44	1,648
Liabilities
Trade and other liabilities	610	15	625	252	877
Borrowings	2,177	-	2,177	-	2,177
Instrumentos financieros derivados	-	1	1	-	1
Total	2,787	16	2,803	252	3,055

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, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	93	3	96	-	96
Interest expense	(275)	-	(275)	(20)	(295)
Foreign exchange, net	(92)	14	(78)	3	(75)
Results from financial instruments at fair value	-	91	91	-	91
Gains (losses) from present value measurement	54	-	54	-	54
Other financial results	37	-	37	2	39
Total	(183)	108	(75)	(15)	(90)
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	94	5	99	-	99
Interest expense	(289)	-	(289)	(22)	(311)
Foreign exchange, net	(865)	86	(779)	(84)	(863)
Results from financial instruments at fair value	-	64	64	-	64
Gains (losses) from present value measurement	(74)	-	(74)	-	(74)
Other financial results	12	-	12	(2)	10
Total	(1,122)	155	(967)	(108)	(1,075)
As of December 31, 2017	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	55	7	62	-	62
Interest expense	(217)	-	(217)	(11)	(228)
Foreign exchange, net	(191)	49	(142)	(14)	(156)
Results from financial instruments at fair value	-	62	62	-	62
Gains (losses) from present value measurement	(6)	-	(6)	-	(6)
Other financial results	(2)	-	(2)	(2)	(4)
Total	(361)	118	(243)	(27)	(270)

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, 2019 and 2018:

As of Dectember 31, 2019	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	113	-	-	113
Shares	8	-	11	19
Investment funds	244	-	-	244
Cash and cash equivalents
Investment funds	4	-	-	4
Derivative financial instruments	-	4	-	4
Other receivables	4	-	-	4
Total assets	373	4	11	388
Liabilities
Derivative financial instruments	-	3	-	3
Total liabilities	-	3	-	3
As of December 31, 2018	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	298	-	-	298
Trust	1	-	11	12
Investment funds	106	-	-	106
Other receivables	3	-	-	3
Total assets	408	-	11	419
Liabilities
Derivative financial instruments	-	1	-	1
Total liabilities	-	1	-	1

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 income, 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: they were determined based on Income approach through the Indirect Cash Flow method (net present value of expected future cash flows) and the discount rates used were estimated taking the WAAC rate as a parameter.

XML

10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	$ 40	$ 181	$ 149
Other operating expenses	(86)	(200)	(103)
Provision for contingencies
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(28)	(35)	(20)
Decrease in property, plant and equipment
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(1)	(6)	(1)
Allowance for tax credits
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(4)	0	(1)
Tax on bank transactions
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(29)	(30)	(27)
Cost for services provided to third parties
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(2)	(2)	(2)
Compensation agreements
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	0	0	(2)
Donations and contributions
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(2)	(2)	(2)
Institutional promtion
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(2)	(3)	(3)
Extraordinary Canon
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	0	(3)	(14)
Contingent consideration
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	0	0	(8)
Onerous contract (Ship or pay)
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	0	(7)	(4)
Tax contingencies in Ecuador
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	0	(69)	0
Other
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating expenses	(18)	(43)	(19)
Compensation for transaction agreement in Ecuador
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	0	99	0
Recovery of doubtful accounts
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	0	0	4
Insurance recovery
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	6	0	0
Surplus Gas Injection Compensation
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	0	23	101
Commissions on municipal tax collections
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	2	2	1
Services to third parties
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	13	13	8
Profit for property, plant and equipment sale
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	0	3	0
Dividends received
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	1	1	1
Reversal of contingencies and taxes payables
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	1	4	24
Other
DisclosureOfOtherOperatingIncomeAndExpensesLineItems [Line Items]
Other operating income	$ 17	$ 36	$ 10

XML

18. LEASES (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Leases
Operating lease income	$ 5	$ 5

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, plant and equipment
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	$ (334)	$ (443)
Profit (loss)	(55)	108
Gain on monetary position, net	5
Other comprehensive income (loss)		0
Deferred tax liability, ending	(384)	(334)
Adjustment for tax inflation
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	0
Profit (loss)	(99)
Gain on monetary position, net	0
Deferred tax liability, ending	(99)	0
Investments in joint ventures and associates
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(19)	(52)
Profit (loss)	11	35
Gain on monetary position, net	0
Other comprehensive income (loss)		(2)
Deferred tax liability, ending	(8)	(19)
Intangible assets
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(193)	(2)
Profit (loss)	175	(190)
Gain on monetary position, net	5
Other comprehensive income (loss)		0
Deferred tax liability, ending	(13)	(193)
Inventories
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	0
Profit (loss)	(10)
Gain on monetary position, net	0
Deferred tax liability, ending	(10)	0
Trade and other receivables
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(9)	(27)
Profit (loss)	5	17
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax liability, ending	(4)	(9)
Financial assets at fair value through profit and loss
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(9)	(3)
Profit (loss)	(2)	(6)
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax liability, ending	(11)	(9)
Cash and cash equivalents
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	0
Profit (loss)	0
Gain on monetary position, net	0
Deferred tax liability, ending	0	0
Borrowings
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(3)	(5)
Profit (loss)	3	2
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax liability, ending	0	(3)
Taxes payable
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	0
Profit (loss)	(4)
Gain on monetary position, net	0
Deferred tax liability, ending	(4)	0
Other
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(6)	(4)
Profit (loss)	6	(1)
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax liability, ending	0	(6)
Deferred tax liabilities
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	(573)	(569)
Profit (loss)	30	(2)
Gain on monetary position, net	10
Other comprehensive income (loss)		(2)
Deferred tax liability, ending	(533)	(573)
Assets classified as held for sale
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax liability, beginning	0	(33)
Profit (loss)		33
Other comprehensive income (loss)		0
Deferred tax liability, ending		0
Tax loss-carryforwards
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	52	64
Profit (loss)	59	(12)
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	111	52
Trade and other receivables
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	14	4
Profit (loss)	(1)	10
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	13	14
Trade and other payables
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	52	46
Profit (loss)	(37)	6
Gain on monetary position, net	(2)
Other comprehensive income (loss)		0
Deferred tax asset, ending	13	52
Salaries and social security payable
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	1	0
Profit (loss)	1	1
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	2	1
Defined benefit plans
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	9	11
Profit (loss)	(2)	(3)
Gain on monetary position, net	0
Other comprehensive income (loss)		1
Deferred tax asset, ending	7	9
Provisions
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	32	29
Profit (loss)	7	3
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	39	32
Taxes payable
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	6	7
Profit (loss)	(6)	(1)
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	0	6
Adjustment for tax inflation
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	0
Profit (loss)	8
Gain on monetary position, net	0
Deferred tax asset, ending	8	0
Other
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	2	2
Profit (loss)	(2)	0
Gain on monetary position, net	0
Other comprehensive income (loss)		0
Deferred tax asset, ending	0	2
Deferred tax asset
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	168	177
Profit (loss)	27	(10)
Gain on monetary position, net	(2)
Other comprehensive income (loss)		1
Deferred tax asset, ending	193	168
Derivative financial instruments
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	0	0
Profit (loss)		0
Other comprehensive income (loss)		0
Deferred tax asset, ending		0
Financial assets at fair value through profit and loss
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	0	0
Profit (loss)		0
Other comprehensive income (loss)		0
Deferred tax asset, ending		0
Liabilities associated to assets classified as held for sale
DisclosureOfDeferredTaxAssetsAndLiabilitiesLineItems [Line Items]
Deferred tax asset, beginning	$ 0	14
Profit (loss)		(14)
Other comprehensive income (loss)		0
Deferred tax asset, ending		$ 0

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	$ (1,552)	$ (1,358)
Decreases	12	9
Impairment	50	24
Depreciation for the year	(255)	(227)
Translation effect	18	0
Property, plant and equipment depreciation, ending	(1,727)	(1,552)
Net book value	3,507	3,316
Land
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	0
Decreases	0
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	0	0
Net book value	14	22
Buildings
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(74)
Decreases	1
Impairment	5
Depreciation for the year	(7)
Translation effect	0
Property, plant and equipment depreciation, ending	(75)	(74)
Net book value	127	133
Equipment and machinery
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(384)
Decreases	4
Impairment	41
Depreciation for the year	(72)
Translation effect	0
Property, plant and equipment depreciation, ending	(411)	(384)
Net book value	843	667
High, medium and low voltage lines
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(323)
Decreases	4
Impairment	0
Depreciation for the year	(35)
Translation effect	10
Property, plant and equipment depreciation, ending	(344)	(323)
Net book value	705	687
Substations
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(105)
Decreases	0
Impairment	0
Depreciation for the year	(13)
Translation effect	3
Property, plant and equipment depreciation, ending	(115)	(105)
Net book value	252	260
Transforming chamber and platforms
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(57)
Decreases	0
Impairment	0
Depreciation for the year	(8)
Translation effect	2
Property, plant and equipment depreciation, ending	(63)	(57)
Net book value	156	151
Meters
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(80)
Decreases	0
Impairment	0
Depreciation for the year	(10)
Translation effect	3
Property, plant and equipment depreciation, ending	(87)	(80)
Net book value	139	129
Wells
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(321)
Decreases	0
Impairment	0
Depreciation for the year	(65)
Translation effect	0
Property, plant and equipment depreciation, ending	(386)	(321)
Net book value	286	241
Mining property
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(119)
Decreases	0
Impairment	4
Depreciation for the year	(29)
Translation effect	0
Property, plant and equipment depreciation, ending	(144)	(119)
Net book value	109	148
Vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(16)
Decreases	0
Impairment	0
Depreciation for the year	(5)
Translation effect	0
Property, plant and equipment depreciation, ending	(21)	(16)
Net book value	1	6
Furniture, fittings and communication equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(48)
Decreases	0
Impairment	0
Depreciation for the year	(9)
Translation effect	0
Property, plant and equipment depreciation, ending	(57)	(48)
Net book value	17	19
Communication equipments
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(10)
Decreases	0
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	(10)	(10)
Net book value	5	5
Materials and spare parts
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(2)
Decreases	0
Impairment	0
Depreciation for the year	(1)
Translation effect	0
Property, plant and equipment depreciation, ending	(3)	(2)
Net book value	34	30
Distribution storage center
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(2)
Decreases	3
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	1	(2)
Net book value	1	8
Petrochemical Industrial Complex
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(7)
Decreases	0
Impairment	0
Depreciation for the year	(1)
Translation effect	0
Property, plant and equipment depreciation, ending	(8)	(7)
Net book value	6	8
Work in progress
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	0
Decreases	0
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	0	0
Net book value	792	783
Advances to suppliers
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	0
Decreases	0
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	0	0
Net book value	18	19
Other goods
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment depreciation, beginning	(4)
Decreases	0
Impairment	0
Depreciation for the year	0
Translation effect	0
Property, plant and equipment depreciation, ending	(4)	(4)
Net book value	$ 2	$ 0

XML

9. COST OF SALES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfCostOfSalesLineItems [Line Items]
Inventory, beginning	$ 137	$ 113	$ 164
Charges for the year	2,048	1,991	1,523
Gain on monetary position	1	0	0
Less: Inventories at the end of the year	(153)	(137)	(113)
Total cost of sales	2,032	1,967	1,574
Purchases of inventories, energy and gas
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	1,305	1,224	874
Salaries and social security charges
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	163	181	202
Benefits to the employees
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	9	6	7
Accrual of defined benefit plans
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	7	4	7
Work contracts, fees and compensation for services
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	103	98	84
Depreciation of property, plant and equipment
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	232	206	195
Intangible assets amortization
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	7	7	1
Right-of-use assets amortization
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	2	0	0
Transport of energy
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	4	4	3
Transportation and freights
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	18	14	3
Consumption of materials
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	48	64	29
Penalties
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	25	56	11
Maintenance
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	27	24	18
Canons and Royalties
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	59	74	56
Environmental control
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	3	5	3
Rental and insurance
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	21	13	11
Surveillance and security
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	6	6	6
Taxes, rates and contributions
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	4	5	3
Other
DisclosureOfCostOfSalesLineItems [Line Items]
Charges for the year	$ 5	$ 0	$ 10

XML

5. GROUP STRUCTURE (Details 10) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Group Structure
Interests in associates and joint ventures, beginning	$ 403	$ 315	$ 255
Reclassifications	(16)	0	12
Dividends	(75)	(19)	0
Decreases	0	(10)	0
Increases	108	0	0
Share of profit	101	118	48
Other comprehensive loss	0	(1)	0
Exchange differences on translation	(14)	0	0
Interests in associates and joint ventures, ending	$ 507	$ 403	$ 315

XML

5. GROUP STRUCTURE (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Group Structure
Net cash (used in) generated by operating activities	$ 0	$ (46)	$ 87
Net cash used in investing activities	0	0	(50)
Net cash generated by (used in) financing activities	0	42	(31)
(Decrease) increase in cash and cash equivalents from discontinued operations		(4)	6
Cash and cash equivalents at the begining of the year	$ 0	6	4
Loss on net monetary position generated by cash and cash equivalents		(2)	(4)
(Decrease) increase in cash and cash equivalents		(4)	6
Cash and cash equivalents at the end of the year		$ 0	$ 6

XML

17. RELATED PARTIES TRANSACTIONS (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Salaverri, Dellatorre, Burgio & Wetzler
Disclosure of transactions between related parties [line items]
Fees for services	$ (1)	$ (1)	$ (1)
Total related parties
Disclosure of transactions between related parties [line items]
Fees for services	$ (1)	$ (1)	$ (1)

XML

14. STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement Of Cash Flows Complementary Information
Increase (decrease) in trade receivables and other receivables	$ 17	$ (172)	$ (65)
Increase in inventories	(28)	(18)	(11)
Increase in trade payables and other payables	97	22	10
Increase in deferred income	0	2	0
Decrease in salaries and social security payable	15	14	(1)
Decrease in defined benefit plans	(2)	(3)	(3)
(Decrease) increase in tax payables	20	35	(26)
(Increase) decrease in provisions	(9)	(60)	(48)
Income tax and minimum notional income tax paid	(87)	(49)	(56)
(Payments) proceeds from derivative financial instruments, net	9	(24)	23
Total changes in operating assets and liabilities	$ 32	$ (253)	$ (177)

XML

5. GROUP STRUCTURE (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Net cash generated by operating activities	$ 802	$ 610	$ 439
Net cash used in investing activities	(369)	19	(846)
Net cash used in financing activities	(390)	(470)	372
(Decrease) increase in cash and cash equivalents	43	159	(35)
Cash and cash equivalents at the beginning of the year	241	31	69
Loss on net monetary position generated by cash and cash equivalents	(59)	53	14
Cash and cash equivalents at the end of the year	225	241	31
Edenor
Disclosure of subsidiaries [line items]
Net cash generated by operating activities	170	255	78
Net cash used in investing activities	(86)	(221)	(63)
Net cash used in financing activities	(85)	(56)	(13)
(Decrease) increase in cash and cash equivalents	(1)	(22)	2
Cash and cash equivalents at the beginning of the year	0	7	3
Loss on net monetary position generated by cash and cash equivalents	7	19	2
Cash and cash equivalents at the end of the year	$ 7	$ 0	$ 7

XML

12. FINANCIAL ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

Financial Assets And Liabilities

Financial assets at amortized cost

	12.31.2019	12.31.2018
Non-current
Public securities (1)	18	-
Total non-current	18	-
Current
Time deposits	-	35
Public securities (1)	54	-
Total current	54	35

⁽¹⁾   The public securities were received in accordance with the mechanism set forth by SGE Resolution No. 54/19 for the settlement of receivables under Natural Gas Surplus Injection Promotion Programs. See Note 2.4.3.1.

Financial assets at fair value through profit and loss

	12.31.2019	12.31.2018
Non-current
Shares	11	11
Total non-current	11	11
Current
Government securities	113	298
Shares	8	1
Investment funds	244	106
Total current	365	405

Trade and other receivables

	Note	12.31.2019	12.31.2018
Non-Current
CAMMESA Receivable (1)		-	70
Other		8	23
Trade receivables, net		8	93
Non-Current
Tax credits		3	13
Related parties	17	53	49
Prepaid expenses		1	1
Financial credit		-	1
Receivable for sale of property, plant and equipment		-	3
Natural Gas Surplus Injection Promotion Program (2)		-	71
Credit with RDSA	20	35	20
Allowance for doubtful accounts		(35)	-
Other		14	2
Other receivables, net		71	160
Total non-current		79	253

Current	Note	12.31.2019	12.31.2018
Receivables from energy distribution sales		226	223
Receivables from MAT		17	27
CAMMESA		168	131
CAMMESA Receivable (1)		-	15
Receivables from oil and gas sales (3)		48	78
Receivables from refinery and distribution sales		-	6
Receivables from petrochemistry sales		54	67
Related parties	17	6	10
Government of the PBA and CABA by Social Rate		4	-
Other		10	4
Allowance for doubtful accounts		(33)	(34)
Trade receivables, net		500	527
Tax credits		10	27
Advances to suppliers		-	2
Related parties	17	8	5
Prepaid expenses		2	2
Receivables for non-electrical activities		11	14
Financial credit		5	6
Guarantee deposits		5	13
Natural Gas Surplus Injection Promotion Program (2)		-	71
Insurance to recover		-	6
Expenses to be recovered		10	11
Credits for the sale of property, plant and equipment		1	21
Credit with RDSA	20	1	-
Other		14	6
Allowance for other receivables		(6)	(8)
Other receivables, net		61	176
Total current		561	703

(1)	CAMMESA receivables were settled in pursuant to the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).
(2)	Receivables under the Natural Gas Surplus Injection Promotion Programs were settled through the delivery of public securities pursuant to the mechanism set forth by SGE Resolution No. 54/19 (see Note 2.4.3.1).
(3)	Including U$S 14.6 million corresponding to the receivables with gas distributors pursuant to the procedure set forth by PEN Executive Order No. 1,053/18 and regulated by ENARGAS Resolution No. 466/19 (see Note 2.4.3.2).

Allowance for the impairment of trade receivables

	12.31.2019	12.31.2018	12.31.2017
At the beginning	34	26	21
Allowance for impairment	23	34	13
Utilizations	(13)	(10)	(3)
Reversal of unused amounts	(2)	(1)	-
Exchange differences on translation	(1)	-	-
Reclasification to  assets held   for sale	-	-	(5)
Gain on monetary position, net	(8)	(15)	(5)
At the end of the year	33	34	21

Allowance for the impairment of other receivables

	12.31.2019	12.31.2018	12.31.2017
At the beginning	8	6	10
Allowance for impairment	1	7	1
Gain on monetary position, net	(1)	(3)	-
Decreases	-	-	(1)
Reversal of unused amounts	(2)	(2)	(5)
At the end of the year	6	8	5

Cash and cash equivalents

	12.31.2019	12.31.2018
Banks	57	83
Investment funds	4	-
Time deposits	164	158
Total	225	241

Borrowings

Non-Current	Note	12.31.2019	12.31.2018
Financial borrowings		161	258
Corporate bonds (1)		1,603	1,457
CAMMESA financing		-	120
		1,764	1,835
Current
Financial borrowings		137	313
Corporate bonds		32	25
CAMMESA financing		-	3
Related parties	17	14	1
		183	342
Total		1,947	2,177

⁽¹⁾   Net of the repurchase of Corporate Bonds of Pampa Energía for a nominal value of U$S 81 million and U$S 9 million and the repurchase of Edenor’s Corporate Bonds for a nominal value of U$S 29 million and U$S 10 million as of December 31, 2019 and 2018, respectively.

Changes in borrowings

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning		2,177	1,683	1,269
Proceeds from borrowings		556	245	1,250
Payment of borrowings		(550)	(240)	(733)
Accrued interest		185	179	143
Payment of borrowings' interests		(148)	(133)	(108)
Net foreign currency exchange difference		50	1,244	227
Results for the repurchase of corporate bonds	12.5.2	(27)	(2)	-
Costs capitalized in property, plant and equipment	11.1	17	8	14
Decrease through offsetting  with trade receivables		(135)	-	-
Gain on monetary position, net		(88)	(795)	(379)
Repurchase and redemption of corporate bonds		(91)	(13)	(1)
Other financial results		1	1	1
At the end of the year		1,947	2,177	1,683

Borrowings composition

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2019
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	139
Class E CB	PAMPA	ARS	575	Variable	Badlar	Nov-20	10
Class 1 CB	PAMPA	U$S	687	Fixed	7.50%	Ene-27	698
T Series  CB	PAMPA	U$S	487	Fixed	7.38%	Jul-23	497
Serie 3 CB (1)	PAMPA	U$S	293	Fixed	9.13%	Abr-29	291
							1,635
Regulatory:
Thrid parties:
	PAMPA	U$S	84	Fixed	Between 4.25% and 7.65%	Jan-2020 to May-2020	88
	PAMPA	U$S	39	Fixed and variable	4.21% + Libor	May-2024	39
	PAMPA	ARS	7,775	Fixed	Between 40% and 44.14%	Apr-2021 to Apr-2022	146
							273
Related parties:
	PAMPA	U$S	13	Fixed	6.0%	2020	14
Financial loans:
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	25
							25
							1,947

⁽¹⁾   On June 10, 2019, the Company issued Series 3 Corporate Bonds for a face value of U$S 300 million. These corporate bonds accrue interest at a fixed rate of 9.125% payable semi-annually, and the principal will be payable in a single installment upon maturity, in April 2029.

Type of instrument	Company	Currency	Residual value	Interest	Rate	Expiration	Book value as of 12.31.2018
Corporate bonds:
2022 CB	Edenor	U$S	166	Fixed	9.75%	2022	170
Class 4 CB (1)	PAMPA	U$S	34	Fixed	6.25%	Oct 20	34
Class E CB	PAMPA	ARS	607	Fixed	Badlar	Nov-20	16
T Series  CB	PAMPA	U$S	500	Fixed	7.38%	Jul-23	753
Class 1  CB	PAMPA	U$S	747	Fixed	7.50%	Jan-27	510
							1,483
Regulatory:
CAMMESA 2014 Agreement	PAMPA	ARS	855	Variable	CAMMESA	(2)	57
CAMMESA Mapro	PAMPA	ARS	174	Variable	CAMMESA	(2)	7
CAMMESA Mapro	CPB	ARS	1,085	Variable	CAMMESA	(2)	59
							123
Financial loans:
	PAMPA	U$S	17,116	Fixed	Between 3.6% and 6.8%	Feb-2019 to May-2021	459
	PAMPA	U$S	1,746	Fixed and variable	6% + Libor	May-2024	46
	PAMPA	ARS	550	Fixed	22.25%	Sep-2019 to Oct-2019	15
	Edenor	U$S	1,885	Variable	Libor + 4.27%	Oct-20	51
							571
							2,177

(1)	On July 12, 2019, the Company provided for the early redemption of Series 4 Corporate Bonds for a value of U$S 34 million.
(2)	Regulatory financing was settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).

Trade and other payables

Non-Current		12.31.2019	12.31.2018
Customer contributions		3	3
Funding contributions for substations		-	1
Customer guarantees		4	4
Trade payables		7	8
ENRE Penalties and discounts		64	138
Loans (mutuums) with CAMMESA		-	61
Compensation agreements		7	7
Liability with FOTAE		-	5
Payment agreement with ENRE		-	1
Lease liability		12	-
Other		-	-
Other payables		83	212
Total non-current		90	220
Current	Note	12.31.2019	12.31.2018
Suppliers		212	250
CAMMESA		155	316
Customer contributions		1	-
Discounts to customers		-	1
Customer advances		7	6
Related parties	17	8	6
Other		-	1
Trade payables		383	580
ENRE Penalties and discounts		57	49
Related parties	17	5	-
Compensation agreements		3	13
Payment agreements with ENRE		1	2
Other creditors		-	8
Lease liability		4	-
Other		1	5
Other payables		71	77
Total current		454	657

Financial instruments

As of December 31, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	622	4	626	14	640
Financial assets at fair value through profit and loss
Government securities	-	113	113	-	113
Shares	-	19	19	-	19
Investment funds	-	244	244	-	244
Derivative financial instruments	-	4	4	-	4
Cash and cash equivalents	221	4	225	-	225
Total	843	388	1,231	14	1,245
Liabilities
Trade and other liabilities	408	7	415	129	544
Borrowings	1,947	-	1,947	-	1,947
Derivative financial instruments	-	3	3	-	3
Total	2,355	10	2,365	129	2,494
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non financial assets/liabilities	Total
Assets
Trade receivables and other receivables	909	3	912	44	956
Financial assets at amortized cost
Government securities	35	-	35	-	35
Financial assets at fair value through profit and loss
Government securities	-	298	298	-	298
Shares	-	12	12	-	12
Investment funds	-	106	106	-	106
Cash and cash equivalents	241	-	241	-	241
Total	1,185	419	1,604	44	1,648
Liabilities
Trade and other liabilities	610	15	625	252	877
Borrowings	2,177	-	2,177	-	2,177
Instrumentos financieros derivados	-	1	1	-	1
Total	2,787	16	2,803	252	3,055

Income, expenses, gains and losses from financial instruments

As of December 31, 2019	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	93	3	96	-	96
Interest expense	(275)	-	(275)	(20)	(295)
Foreign exchange, net	(92)	14	(78)	3	(75)
Results from financial instruments at fair value	-	91	91	-	91
Gains (losses) from present value measurement	54	-	54	-	54
Other financial results	37	-	37	2	39
Total	(183)	108	(75)	(15)	(90)
As of December 31, 2018	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	94	5	99	-	99
Interest expense	(289)	-	(289)	(22)	(311)
Foreign exchange, net	(865)	86	(779)	(84)	(863)
Results from financial instruments at fair value	-	64	64	-	64
Gains (losses) from present value measurement	(74)	-	(74)	-	(74)
Other financial results	12	-	12	(2)	10
Total	(1,122)	155	(967)	(108)	(1,075)
As of December 31, 2017	Financial assets/liabilities at amortized cost	Financial assets/liabilities at fair value through profit and losss	Subtotal financial assets/liabilities	Non Financial assets/ liabilities	Total
Interest income	55	7	62	-	62
Interest expense	(217)	-	(217)	(11)	(228)
Foreign exchange, net	(191)	49	(142)	(14)	(156)
Results from financial instruments at fair value	-	62	62	-	62
Gains (losses) from present value measurement	(6)	-	(6)	-	(6)
Other financial results	(2)	-	(2)	(2)	(4)
Total	(361)	118	(243)	(27)	(270)

Fair value of financial instruments

As of Dectember 31, 2019	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	113	-	-	113
Shares	8	-	11	19
Investment funds	244	-	-	244
Cash and cash equivalents
Investment funds	4	-	-	4
Derivative financial instruments	-	4	-	4
Other receivables	4	-	-	4
Total assets	373	4	11	388
Liabilities
Derivative financial instruments	-	3	-	3
Total liabilities	-	3	-	3
As of December 31, 2018	Level 1	Level 2	Level 3	Total
Assets
Financial assets at fair value through profit and losss
Government securities	298	-	-	298
Trust	1	-	11	12
Investment funds	106	-	-	106
Other receivables	3	-	-	3
Total assets	408	-	11	419
Liabilities
Derivative financial instruments	-	1	-	1
Total liabilities	-	1	-	1

XML

4. ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2019

Accounting Policies

ACCOUNTING POLICIES

The main accounting policies used in the preparation of these consolidated Consolidated Financial Statements are explained below.

4.1   New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2019 and adopted by the Company

The Company has first applied the following standards and/or amendments as from January 1, 2019:

- IFRS 16 – “Leases” (issued in January 2016).

- IFRIC 23 – “Uncertainty over Income Tax Treatments” (issued in June 2017)

- IFRS 9 – “Financial Instruments” (application guideline amended in October 2017)

- IAS 28 – “Investments in Associates and Joint Ventures” (amended in October 2017)

- Annual Improvements to IFRS Standards 2015–2017 Cycle (issued in December 2017)

- IAS 19 – “Employee Benefits” (amended in February 2018)

The impact of the initial application of IFRS 16 in the Company’s operating results and financial position as from January 1, 2019 is detailed below.

The application of the remaining standards, amendments or interpretations did not have any impact on the results of the operations or the financial position of the Company.

4.1.1    Impacts of the adoption of IFRS 16

The Company has opted to apply IFRS 16, using the simplified approach, in relation to lease contracts previously identified as such under IAS 17, retrospectively with the cumulative effect recognized as an adjustment to the opening balance of retained earnings as of January 1, 2019, without restating comparative information.

Until December 31, 2018, only contracts classified as financial leases under IAS 17 were capitalized by the Company, that is, contracts where the Company had substantially all of the risks and rewards of ownership of the leased asset. At the financial lease´s inception, the Company recorded an asset and a liability for the same value, corresponding to the leased property’s fair value, or, if lower, the present value of the minimum lease payments. The corresponding rental obligations, net of finance charges, were included in other liabilities. Each lease payment was allocated between the liability and the finance cost. The finance cost was charged to profit or loss over the lease period so as to produce a constant periodic interest rate on the remaining liability balance for each period. Property, plant and equipment acquired under financial leases were depreciated over the asset’s useful life or, if lower, over the lease term. Leases in which a significant portion of the risks and rewards of ownership were not transferred to the Company were classified as operating leases. Payments made under operating leases (net of any incentive received from the lessor) were charged to profit or loss on a straight-line basis over the lease period.

Management has reviewed effective lease contracts and has recognized a right-of-use asset in the amount of U$S 8 million corresponding to the amount of the lease liability as of the adoption date (which equals the present value of the remaining lease payments), as detailed below:

Operating lease commitments as of 12.31.2018	10.5
Discount using incremental borrowing rate of 58.16% as of 01.01.2019	(2.4)
Exchange differences on translation	(0.1)
Lease liability recognised as of 01.01.2019	8

The rest of the identified lease commitments correspond to contracts ending within 12 months of the date of initial application, which continue to be recognized by the Company on a straight-line basis.

As of the adoption date, the Company has maintained the recorded book value for right-of-use assets and lease liabilities which were classified as finance leases under IAS 17.

Finally, no transition adjustments were made for leases in which the Company acts as a lessor.

Consequently, the Company has not recognized any adjustment to retained earnings upon the initial application of IFRS 16.

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. 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, 2021, allowing for its early adoption for entities already applying IFRS 9 and IFRS 15. The Company estimates that its application will not have a significant impact on the Company’s operating results or financial position.

-     Conceptual Framework: in March 2018, the IASB published a revised conceptual framework which will supersede the current one. However, this framework is not a standard in itself and will not override any existing standard. The concepts of the revised conceptual framework will be immediately taken into consideration in the issuance of future standards by the IASB and the Interpretations Committee. Preparers of financial statements under IFRS will consider the revised conceptual framework for the development of accounting policies on matters not specifically addressed by the IFRS for annual periods beginning on or after January 1, 2020.

-      IFRS 3 – “Business Combinations”: amended in October 2018. It clarifies the definition of business and establishes guidelines for determining whether a transaction should be accounted for as a business combination or as an acquisition of assets. It applies to acquisition transactions as from January 1, 2020, and allows for its early adoption.

-      IAS 1 – “Presentation of Financial Statements” and IAS 8 – “Accounting Policies, Changes in Accounting Estimates and Errors”: amended in October 2018. They clarify the definition of materiality and incorporate the concept of “information shadowing” when there is an effect similar to omitting or reporting inaccurate information. They apply prospectively to annual periods starting on or after January 1, 2020, and allow for early adoption.

-      Amendments to IFRS 9 – “Financial Instruments”, IAS 39 – “Financial instruments: Presentation” and IFRS 7 – “Financial Instruments: Disclosures”: it incorporates temporary exemptions in the case of hedge relationships affected by the interest rate benchmark reform pursuant to the recommendations published by the Financial Stability Board (FSB) in July 2014. Amendments are applicable to fiscal years starting on or after January 1, 2020, allowing for early adoption.

4.3   Effects of changes in foreign exchange rates

4.3.1 Functional and presentation currency

The information included in these Consolidated Financial Statements is recorded and presented in U.S. Dollars, which is the Company’s functional currency, that is, the currency of the primary economic environment where the entity operates.

4.3.2 Foreign-currency transactions and balances

Foreign currency transactions are translated into the functional currency at the exchange rates prevailing on each transaction date or valuation date, when items are remeasured. Foreign exchange gains and losses arising on the settlement of monetary items and on translating monetary items at the closing of the fiscal year using year-end exchange rate are recognized within the financial results in the statement of comprehensive income, with the exception of capitalized amounts.

4.3.3 Group companies’ 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 recognized under “Other comprehensive income”.

4.3.4 Classification 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 cease 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 companies 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 recognized at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according IFRS 11 “Joint Arrangements”. 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 (see Note 4.4.4 below), after initially being recognized at cost.

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognized at cost and adjusted thereafter 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. Dividends received or receivable from associates and joint ventures are recognized 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 at 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 recognized 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 recognized 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 recognized 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 may mean 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 recognized 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 person/ 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 recognized 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, net of any income obtained from the sale of commercially valuable production during the launching 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
Substations:	35 years
High voltage lines:	40 - 45 years
Medium voltage lines:	35 - 45 years
Low voltage lines:	30 - 40 years
Transformer centrals:	25 - 35 years
Meters:	25 years
Vehicles:	5 years
Furniture, fittings and communication equipment:	5- 20 years
Computer equipment and software:	3 years
Tools:	10 years
Gas Plant and Pipeline:	20 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 Asset retirement obligations

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 recognized. 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 recognized 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 at 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 CGUs 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 Edenor and 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 each asset’s 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 at the moment of the acquisition of companies. Identified assets meet the criteria established in IFRS for capitalization less depreciation a 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.

4.8   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 recognized 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 (either through other comprehensive income or through profit or loss), 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 Statement of 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 trade date, that is, the date on which the Company undertakes to purchase or sell the asset, or at settlement date. Financial assets are derecognized 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 amortised cost and is not part of a hedging relationship is recognized 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 recognized 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 recognized 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 recognized at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognises 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.

Receivables arising from services billed to customers but not collected by Edenor, as well as those arising from services rendered but unbilled at the closing date of each financial year are recognized at fair value and subsequently measured at amortized cost using the effective interest rate method. 

Receivables from electricity supplied to low-income areas and shantytowns are recognized, also in line with revenue, when the Framework Agreement has been renewed for the period in which the service was provided.

Where applicable, allowances for doubtful tax credits have been recognized 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 recognized assets or liabilities or over firm commitment (fair value hedge);
ii.	cash flow hedges of a particular risk associated with recognized 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 recognized in equity. The gain or loss related to the ineffective portion is recognized immediately in profit or loss. Changes in the measurement of derivative instruments that do not qualify for hedge accounting are recognized 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 and Distribution of Energy business segments.

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 recognized 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 recognised for any initial or subsequent write-down of the asset until fair value less costs to sell. A gain is recognised 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 recognised. The gain or loss not previously recognised by the date of the sale of the non-current asset is recognised at the date of derecognition.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they be 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 recognized.

Non-current assets classified 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 have been 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 detailed in Note 3.1, the Company has 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. Ordinary shares are classified as equity.

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 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, the related adjustment of share capital. When for any reason, the amount of this reserve will be shorter, 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 (Accumulated losses)

Retained earnings comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of the Shareholders' meeting, as long as they are not subject to legal restrictions. These earnings comprise 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 recognized as a liability in the Consolidated Financial Statements 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.

4.17   Compensation plans

Note 19 details the conditions applicable to the different compensation agreements and the main variables considered in the corresponding valuation model.

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

-	Compensations payable in cash:
i.	Compensation agreements – Senior Management: the reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton valuation model. The fair value of the amount payable under the compensation agreements 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.
ii.	Company Value Sharing (“Company-Value Compensation”) – Pampa (as PEPASA´s successor company): the Black-Scholes-Merton financial valuation model was used to make this estimate, taking into consideration the enforceability of the remuneration. The fair value of the amount payable for the compensation plan is accrued and acknowledged as an expense, with the recognition of an increase in liabilities. Liabilities are revalued on each balance sheet date and at their settlement date. Any change in the fair value of liabilities is disclosed under profit or loss.
iii.	Annual Variable Compensation granted to certain officers for the performance of technical and administrative duties amounting to 7% of the EBDA accrued (EBITDA less paid income tax, less total net financial costs, less interest on its own capital, considering an annual 10% dollar-denominated rate) of PEPASA´s continuing business in Pampa. The Company recognizes a provision (liability) and an expense for this EBDA Compensation based on the previously mentioned formula.
-	Compensations payable in shares
i.	Stock-based Compensation Plan – Officers and other key staff: the fair value of the received services is measured at the fair value of shares at the time of granting, and is disclosed during the vesting period, together with the corresponding increase in equity.
ii.	Stock-based Compensation Plan -Edenor: The fair value of the services received is disclosed as an expense and determined by reference to the fair value of the granted shares. When the employees provide the services before the shares are granted, the fair value at the grant date is estimated in order to recognize the respective result.

4.18   Trade payables and other payables

Trade payables and other payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method, except for particular matters described below.

4.18.1   Customer guarantees

Customer guarantees are initially recognized at fair value and subsequently measured at amortized cost using the effective interest method.

In accordance with the Concession Agreement, Edenor is allowed to receive customer guarantees in the following cases:

i.	When the power supply is requested and the user is unable to provide evidence of his legal ownership of the premises;
ii.	When service has been suspended more than once in one-year period;
iii.	When the power supply is reconnected and Edenor is able to verify the illegal use of the service (fraud).
iv.	When the customer is undergoing liquidated bankruptcy or reorganization proceedings.

Edenor has decided not to request customer guarantees from residential tariff customers.

Customer guarantees may be either paid in cash or through the customer’s bill and accrue monthly interest at a specific rate of BNA for each customer category.

When the conditions for which Edenor is allowed to receive customer guarantees no longer exist, the customer’s account is credited for the principal amount plus any interest accrued thereon, after deducting, if appropriate, any amounts receivable which Edenor has with the customer.

4.18.2   Edenor’s customer refundable contributions

Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements and the provisions of ENRE Resolution No. 215/12. These contributions are initially recognized as trade payables at fair value against Property, plant and equipment, and are subsequently measured at amortized cost using the effective interest rate method.

4.18.3   Edenor’s particular matters

The recorded liabilities for penalties accrued, whether imposed or not yet issued by the ENRE (Note 2.3), and other provisions are the best estimate of the settlement value of the present obligation in the framework of IAS 37 provisions at the date of these Consolidated Financial Statements.

The balances of ENRE Penalties and Discounts are adjusted in accordance with the regulatory framework applicable thereto and are based on Edenor’s estimate of the outcome of the RTI process described in Note 2.3.

4.19   Borrowings

Borrowings are recognized 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 recognized 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, cancelled 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.

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   Deferred revenues

Non-refundable customer contributions: Edenor receives assets or facilities (or the cash necessary to acquire or built them) from certain customers for services to be provided, based on individual agreements. The assets received are recognized by Edenor as Property, plant and equipment with a contra-account in deferred revenue, the accrual of which depends on the nature of the identifiable services, in accordance with the following:

i.	Customer connection to the network: revenue is accrued until such connection is completed;
ii.	Continuous provision of the electric power supply service: throughout the shorter of the useful life of the asset and the term for the provision of the service.

4.21   Employee benefits

4.21.1   Short-term obligations

Liabilities for wages and salaries, including non-monetary benefits and accumulating sick leave that are expected to be settled wholly within 12 months after the end of the period in which the employees render the related service are recognised in respect of employees’ services up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liabilities are presented as current salaries and social security payable in the consolidated statement of financial position.

4.21.2   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 recognized 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 recognized in other comprehensive income (loss) in the period in which they arise and past service costs are recognized immediately in the statement of income (loss).

4.22   Provisions, contingent liabilities and contingent assets

Provisions are recognized 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 each 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. The increase in the provision due to the passage of time is recognised as 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 no 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.

4.23   Revenue from contracts with customers

4.23.1   Generation segment:

4.23.1.1 Revenues from sales to the spot market (SRRYME Resolution No. 1/19)

The Company recognizes revenues from i) power availability 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 applicable depending on the technology of each plant and, in the case of thermal power plants, the application of the coefficient derived from the average usage factor over the last 12 months on the power capacity remuneration specified in the Resolution. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 45 days, which is consistent with market practice.

4.23.1.2 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 45 days, which is consistent with market practice.

4.23.1.3 Revenues from sales contracts with large users within the MAT (energy plus Resolution SE No. 1,281/06)

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.

4.23.2   Distribution segment

4.23.2.1 Revenues from contracts with customers

Edenor's revenue is measured at the fair value of the consideration collected or to be collected, taking into account the estimated amount of any discount, thus determining the net amounts.

Edenor recognizes, on a monthly basis, revenues from electricity distribution as energy is distributed to each client based on the applicable tariff and procedures established by the ENRE. Such revenue includes energy delivered, whether billed or unbilled, at the end of each period. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

Edenor recognizes revenues related to energy supply to low-income areas and shantytowns, only to the extent that the Framework Agreement has been renewed for the period in which the service was rendered. As of the date of issuance of these Consolidated Financial Statements, the Framework Agreement is not currently in effect.

4.23.2.2. Edenor’s other revenues from contracts with customers

Edenor recognizes other revenues from contracts with customers in relation to connection and reconnection services, rights of use on poles and transport of energy to other distribution companies on a monthly basis as services are rendered based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales’ payments are not deferred over time, which is consistent with market practice.

4.23.3   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 recognized 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 30 days, which is consistent with market practice.

4.23.4 Petrochemical segment

The Company recognizes revenues from the sale of petrochemical products, whether in local or foreign market, 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:

(a)	when the products are dispatched and transported by and in charge of the client, or,
(b)	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 recognized 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 28 days, which is consistent with market practice.

4.23.5 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.

4.24   Other Income

4.24.1   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. There are no unfulfilled conditions or other contingencies attaching to the following grants. The group did not benefit directly from any other forms of government assistance.

4.24.1.1 Recognition of Compensation from Natural Gas Injection Promotion Programs

The Company recognizes revenues from Natural Gas Injection Promotion Programs when the delivery of the gas is effective based on the price established in the applicable regulation, only to the extent that it is highly probable that a significant reversal will not occur and it is probable that the consideration will be collected, that is, as the procedure established by Government is formally complied with. Although the consideration Programs´ collection depends on the Argentine Government’s payment capacity that has incurred in important delays in the cancellation of the credits in the past, revenues are not adjusted for the effect of financing components, which is consistent with market practice.

The recognition of income from Natural Gas Injection Promotion Programs is covered by IAS 20 since it involves a compensation as a result of the production increase committed.

This item has been disclosed under Natural Gas Injection Promotion Programs under Other operating income, in the Consolidated Statement of Comprehensive Income. Furthermore, ítem Extroardinary Canon disclosed within Other operating expenses includes fiscal costs related to these Programs.

4.24.2   Interest income

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 carrying amount net of impairment provision.

4.24.3   Dividends

Dividends are received from financial assets measured at fair value through profit or loss or through other comprehensive income. Dividends are recognized as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

4.25    Income tax and minimum notional income tax

4.25.1   Current and deferred income tax

The tax expenses for the year include current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case, the tax is also recognized 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 recognized, 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 recognized 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 recognized 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 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 recognized on account of gains or losses from fiscal tax inflation which, pursuant to Law No. 27,541, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1.5).

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset the recognized 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), Venezuela, Ecuador, Bolivia, Spain and Uruguay are 30%, 50%, 25%, 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.

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.

4.25.2 Minimum notional income tax

The Company assessed the minimum notional income tax until December 31, 2018, by applying the current 1% rate over the assets computable at the closing of the year. As this tax supplements the income tax, the Company does not assess it for the periods where no income is evidenced on the income tax, based on the case law established by the “Hermitage” decision (CSJN, June 15, 2010), which ruled on the unconstitutionality of this tax when tax losses are disclosed for the period.

The Company’s tax obligation for each year will be the higher of the two taxes. If in a fiscal year, however, minimum notional income tax obligation exceeds income tax liability, the surplus will be computable as a payment in advance of income tax through the next ten years.

Pursuant to section 76 of Law No. 27,430, the effectiveness of this tax has been abrogated for fiscal years beginning on or after January 1, 2019, without affecting the remaining term for computing any payments made in excess during its life as payments on account of income tax.

As of the closing date hereof, the Company’s Management analyzed the receivable’s recoverability, and allowances are created in as long as it is estimated that the amounts paid for this tax will not be recoverable within the statutory limitation period taking into consideration the Company’s current business plans. The Company’s Management will evaluate the evolution of this recoverability in future fiscal years.

4.26   Leases

In leases where the Company is a lessee (Note 18.1), a right-of-use asset and a lease liability are recognized 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 “Lease liability” under “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 18.2.1). Financial leases are recognized 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 recognized as a profit or a loss 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 derecognized 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 18.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2019 shares
Document And Entity Information
Entity Registrant Name	Pampa Energy Inc.
Entity Central Index Key	0001469395
Document Type	20-F
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Annual Report	true
Document Transition Report	false
Document Shell Company Report	false
Is Entity a Well-known Seasoned Issuer?	Yes
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Interactive Data Current	Yes
Entity Incorporation, State or Country Code	C1
Entity Common Stock, Shares Outstanding	1,677,112,043
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019

XML

8. REVENUE (Tables)

12 Months Ended

Dec. 31, 2019

Revenue [abstract]

Revenue

	12.31.2019	12.31.2018	12.31.2017
Energy sales to the Spot Market	251	274	231
Energy sales by supply contracts	285	278	114
Fuel self-supply	281	51	4
Other sales	2	1	2
Generation sales subtotal	819	604	351
Energy sales	1,496	1,477	1,042
Right of use of poles	5	5	6
Connection and reconnection charges	1	2	2
Distribution of energy sales subtotal	1,502	1,484	1,050
Oil, gas and liquid sales	171	454	418
Other sales	3	4	25
Oil and gas sales subtotal	174	458	443
Technical assistance services  and administartion sales	20	36	17
Holding and others subtotal	20	36	17
Petrochemicals sales	321	338	314
Petrochemicals sales subtotal	321	338	314
Total revenue	2,836	2,920	2,175

XML

4. ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies

Impacts of the adoption of new accounting standard

Operating lease commitments as of 12.31.2018	10.5
Discount using incremental borrowing rate of 58.16% as of 01.01.2019	(2.4)
Exchange differences on translation	(0.1)
Lease liability recognised as of 01.01.2019	8

Property, plant and equipment estimated useful lives

Buildings:	50 years
Substations:	35 years
High voltage lines:	40 - 45 years
Medium voltage lines:	35 - 45 years
Low voltage lines:	30 - 40 years
Transformer centrals:	25 - 35 years
Meters:	25 years
Vehicles:	5 years
Furniture, fittings and communication equipment:	5- 20 years
Computer equipment and software:	3 years
Tools:	10 years
Gas Plant and Pipeline:	20 years

XML

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Profit of the year from continuing operations	$ 800	$ 207	$ 428
Profit (loss) of the year from discontinued operations	0	80	(50)
Adjustments to reconcile net profit (loss) to cash flows generated by operating activities:	(30)	622	151
Changes in operating assets and liabilities	32	(253)	(177)
Net cash used in operating activities from discontinued operations	0	(46)	87
Net cash generated by operating activities	802	610	439
Cash flows from investing activities:
Payment for property, plant and equipment	(582)	(674)	(485)
Collection (payment) for financial assets	217	(31)	(109)
Payments for capital integration in associates and joint ventures	(108)	0	0
Proceeds from sale of intangible assets	0	2	0
Collections for sales of shares in companies and property, plant and equipment	42	457	15
Dividends received	87	19	1
Colletion (proceeds) from loans	7	(4)	1
Recovery of investment funds, net	(32)	250	(219)
Net cash used in investing activities from discontinued operations	0	0	(50)
Net cash (used in) generated by investing activities	(369)	19	(846)
Cash flows from financing activities:
Proceeds from borrowings	556	245	1,250
Payment of borrowings	(550)	(240)	(733)
Payment of borrowings interests	(148)	(133)	(108)
Payment for acquisition of own shares	(151)	(369)	(3)
Payments of dividends from subsidiaries to third parties	(1)	(2)	(2)
Repurchase and redemption of corporate bonds	(91)	(13)	(1)
Payments of leases	(5)	0	0
Net cash generated by (used in) financing activities from discontinued operations	0	42	(31)
Net cash (used in) generated by financing activities	(390)	(470)	372
Increase (decrease) in cash and cash equivalents	43	159	(35)
Cash and cash equivalents at the beginning of the year	241	31	69
Cash and cash equivalents at the begining of the year reclasified to assets classified as held for sale	0	6	(6)
Exchange difference generated by cash and cash equivalents	(59)	53	14
Loss on net monetary position generated by cash and cash equivalents	0	(8)	(11)
Increase (decrease) in cash and cash equivalents	43	159	(35)
Cash and cash equivalents at the end of the year	$ 225	$ 241	$ 31

XML

7. SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2019

Disclosure of operating segments [abstract]

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, we were able to identify the following business segments:

Electricity Generation, consisting of the Company’s direct and indirect interests in CPB, HINISA, HIDISA, Greenwind, Enecor, TMB, TJSM, CTB and through its own electricity generation activities through thermal plants Güemes, Piquirenda, Loma de la Lata, Genelba and Ecoenergía, Pilar, I. White, the Pichi Picún Leufú hydroelectric complex and Pampa Energía I and II wind farms.

Electricity Distribution, consisting of the Company’s direct interest in Edenor.

Oil and Gas, consisting of the Company’s own interests in oil and gas areas and through its direct interest in PACOSA and Oldelval and indirectly interest in OCP. As of December 31, 2018 and 2017, the Company has classified the results corresponding to the divestment mentioned in Note 5.2.1 as discontinued operations.

Petrochemicals, comprising of the Company’s own styrenics operations and the catalytic reformer plant operations conducted in Argentine plants.

Holding and Other Business, principally consisting of financial investment transactions, holding activities, and 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. As of December 31, 2018 and 2017, includes the results corresponding to the divestment mentioned in Note 5.2.2 as discontinued operations.

The Company manages its operating segment based on its individual net results. 

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	819	1,502	174	321	20	-	2,836
Intersegment revenue	-	-	270	-	-	(270)	-
Cost of sales	(466)	(1,225)	(313)	(298)	-	270	(2,032)
Gross profit	353	277	131	23	20	-	804
Selling expenses	(3)	(122)	(12)	(9)	(2)	-	(148)
Administrative expenses	(36)	(65)	(47)	(4)	(22)	-	(174)
Exploration expenses	-	-	(9)	-	-	-	(9)
Other operating income	9	10	8	4	9	-	40
Other operating expenses	(11)	(43)	(11)	(9)	(12)	-	(86)
Impairment of property, plant and equipment	(52)	-	(10)	-	-	-	(62)
Share of profit from associates and joint ventures	13	-	21	-	67	-	101
Agreement on the regularization of obligations	-	285	-	-	-	-	285
Operating income	273	342	71	5	60	-	751
Gain on net monetary position, net	-	187	-	-	-	-	187
Finance income	51	20	18	1	7	(1)	96
Finance costs	(82)	(112)	(94)	(8)	(4)	1	(299)
Other financial results	86	(62)	84	18	(13)	-	113
Financial results, net	55	33	8	11	(10)	-	97
Profit before income tax	328	375	79	16	50	-	848
Income tax	(80)	(178)	(16)	(5)	231	-	(48)
Profit for the year	248	197	63	11	281	-	800
Depreciation and amortization	71	79	112	1	-	-	263

Consolidated profit and loss information for the year ended  December 31, 2019	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit attributable to:
Owners of the company	239	98	63	11	281	-	692
Non - controlling interest	9	99	-	-	-	-	108
Consolidated statement of financial position as of December 31, 2019
Assets	1,472	1,480	1,261	136	1,527	(192)	5,684
Liabilities	1,226	1,792	465	122	(160)	(170)	3,275
Additional consolidated information as of December 31, 2019
Increases in property, plant and equipment, intangibles assets and right-of-use assets	240	173	191	4	3	-	611
Net book values of property, plant and equipment	1,152	1,691	612	18	34	-	3,507

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	604	1,484	458	338	36	-	2,920
Intersegment revenue	2	-	63	-	-	(65)	-
Cost of sales	(273)	(1,136)	(287)	(334)	-	63	(1,967)
Gross profit  (loss)	333	348	234	4	36	(2)	953
Selling expenses	(1)	(134)	(19)	(13)	(4)	-	(171)
Administrative expenses	(41)	(76)	(56)	(6)	(27)	-	(206)
Exploration expenses	-	-	(1)	-	-	-	(1)
Other operating income	11	9	141	5	15	-	181
Other operating expenses	(17)	(44)	(114)	(20)	(6)	1	(200)
Impairment of property, plant and equipment	-	-	-	(32)	-	-	(32)
Share of profit (loss) from joint ventures and associates	(11)	-	37	-	92	-	118
Income from the sale of associates	-	-	28	-	-	-	28
Operating income (loss)	274	103	250	(62)	106	(1)	670
Gain on net monetary position	233	226	107	49	12	2	629
Finance income	52	18	15	1	14	(1)	99
Finance costs	(85)	(132)	(79)	(15)	(6)	1	(316)
Other financial results	(365)	(50)	(512)	(39)	108	-	(858)
Financial results, net	(165)	62	(469)	(4)	128	2	(446)
Profit (loss) before income tax	109	165	(219)	(66)	234	1	224
Income tax	(3)	(49)	57	12	(34)	-	(17)
Profit (loss) for the year from continuing operations	106	116	(162)	(54)	200	1	207
Profit for the year from discontinued operations	-	-	49	-	31	-	80
Profit (loss) for the year	106	116	(113)	(54)	231	1	287
Depreciation and amortization	66	69	92	6	1	-	234

Consolidated profit and loss information for the year ended  December 31, 2018	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the company	100	61	(115)	(54)	231	1	224
Non - controlling interest	6	55	2	-	-	-	63
Consolidated statement of financial position as of December 31,2018
Assets	1,414	2,133	1,237	153	872	(137)	5,672
Liabilities	1,054	1,241	1,273	198	247	(136)	3,877
Additional consolidated information as of December 31, 2018
Increases in property, plant and equipment	235	227	192	4	7	-	665
Net book values of property, plant and equipment	1,036	1,657	554	15	54	-	3,316

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Revenue	351	1,050	443	314	17	-	2,175
Intersegment revenue	2	-	19	-	-	(21)	-
Cost of sales	(195)	(799)	(310)	(290)	(1)	21	(1,574)
Gross profit	158	251	152	24	16	-	601
Selling expenses	(4)	(95)	(17)	(12)	-	1	(127)
Administrative expenses	(32)	(66)	(54)	(16)	(30)	-	(198)
Exploration expenses	-	-	(2)	-	-	-	(2)
Other operating income	19	4	110	3	13	-	149
Other operating expenses	(9)	(33)	(38)	(10)	(13)	-	(103)
Share of profit (loss) from joint ventures and associates	(2)	-	1	-	49	-	48
Operating income (loss)	130	61	152	(11)	35	1	368
Gain (loss) on net monetary position	17	145	(18)	2	158	-	304
Finance income	39	12	6	-	7	(2)	62
Finance costs	(69)	(69)	(78)	(10)	(8)	2	(232)
Other financial results	(34)	1	(93)	(6)	32	-	(100)
Financial results, net	(47)	89	(183)	(14)	189	-	34
Profit (loss) before income tax	83	150	(31)	(25)	224	1	402
Income tax	(4)	(12)	24	19	(1)	-	26
Profit (loss) for the year from continuing operations	79	138	(7)	(6)	223	1	428
(Loss) profit for the year from discontinued operations	-	-	(35)	-	(16)	1	(50)
Profit (loss) for the year	79	138	(42)	(6)	207	2	378
Depreciation and amortization	54	58	87	4	2	-	205

Consolidated profit and loss information for the year ended  December 31, 2017	Generation	Distribution of energy	Oil and gas	Petrochemicals	Holding and others	Eliminations	Consolidated
Total profit (loss) attributable to:
Owners of the Company	75	73	(62)	(6)	207	2	289
Non - controlling interest	4	65	20	-	-	-	89
Consolidated statement of financial position as of December 31,2017
Assets	1,115	1,972	1,154	141	1,475	(200)	5,657
Liabilities	333	1,166	444	94	1,850	(200)	3,687
Additional consolidated information as of December 31, 2017
Increases in property, plant and equipment	275	225	140	5	12	-	657

Accounting criteria used by the subsidiaries to measure results, assets and liabilities of the segments is consistent with that used in the Consolidated Financial Statements. Transactions between different segments are conducted under market conditions. Assets and liabilities are allocated based on the segment’s activity.

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11. NON-FINANCIAL ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2019

Non-financial Assets And Liabilities

NON-FINANCIAL ASSETS AND LIABILITIES

11.1. Property, plant and equipment

	Original values
Type of good	At the beginning	Increases	Impairment	Transfers (1)	Decreases	Traslation effect	At the end
Land	22	-	-	-	(8)	-	14
Buildings	207	1	(8)	4	(1)	(1)	202
Equipment and machinery	1,051	1	(90)	297	(5)	-	1,254
High, medium and low voltage lines	1,010	3	-	72	(4)	(32)	1,049
Substations	365	-	-	14	-	(12)	367
Transforming chamber and platforms	208	4	-	15	(1)	(7)	219
Meters	209	1	-	23	-	(7)	226
Wells	562	24	-	94	(8)	-	672
Mining property	267	-	(14)	-	-	-	253
Vehicles	22	1	-	-	-	(1)	22
Furniture and fixtures and software equipment	67	4	-	4	-	(1)	74
Communication equipments	15	-	-	-	-	-	15
Materials and spare parts	32	19	-	(14)	-	-	37
Distribution storage center	10	-	-	-	(10)	-	-
Petrochemical industrial complex	15	-	-	(1)	-	-	14
Work in progress	783	510	-	(487)	(3)	(11)	792
Advances to suppliers	19	23	-	(23)	-	(1)	18
Other goods	4	-	-	2	-	-	6
Total at 12.31.2019	4,868	591	(112)	-	(40)	(73)	5,234
Total at 12.31.2018	4,317	665	(56)	-	(58)	-	4,868

⁽¹⁾   Includes the transfer of materials and spare parts to the item "Inventories" of the current asset.

	Depreciation
							Net book values
Type of good	At the beginning	Decreases	Impairment	For the year	Traslation effect	At the end	At the end	At 12.31.2018
Land	-	-	-	-	-	-	14	22
Buildings	(74)	1	5	(7)	-	(75)	127	133
Equipment and machinery	(384)	4	41	(72)	-	(411)	843	667
High, medium and low voltage lines	(323)	4	-	(35)	10	(344)	705	687
Substations	(105)	-	-	(13)	3	(115)	252	260
Transforming chamber and platforms	(57)	-	-	(8)	2	(63)	156	151
Meters	(80)	-	-	(10)	3	(87)	139	129
Wells	(321)	-	-	(65)	-	(386)	286	241
Mining property	(119)	-	4	(29)	-	(144)	109	148
Vehicles	(16)	-	-	(5)	-	(21)	1	6
Furniture and fixtures and software equipment	(48)	-	-	(9)	-	(57)	17	19
Communication equipments	(10)	-	-	-	-	(10)	5	5
Materials and spare parts	(2)	-	-	(1)	-	(3)	34	30
Distribution storage center	(2)	3	-	-	-	1	1	8
Petrochemical industrial complex	(7)	-	-	(1)	-	(8)	6	8
Work in progress	-	-	-	-	-	-	792	783
Advances to suppliers	-	-	-	-	-	-	18	19
Other goods	(4)	-	-	-	-	(4)	2	-
Total at 12.31.2019	(1,552)	12	50	(255)	18	(1,727)	3,507
Total at 12.31.2018	(1,358)	9	24	(227)	-	(1,552)		3,316

Edenor’s direct own costs capitalized in the book value of property, plant and equipment during the year ended December 31, 2019 and 2018 amounted to U$S 18.8 million and U$S 27.1 million respectively.

Borrowing costs capitalized in the book value of property, plant and equipment during the year ended December 31, 2019 and 2018 amounted to U$S 17 million and U$S 8 million, respectively (see Note 12.5).

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 Generation segment, a reduction in prices in the spot market was verified in 2019, which was deepened by the drop in the product’s excess demand resulting from the slowdown in the economic activity that impacted on the decrease in Energía Plus contracts (with higher prices) and, consequently, on the segment’s profitability margins.

On the other hand, in the Distribution of Energy segment, Edenor has been affected by the enactment by the PEN of the new measures, mentioned in Notes 1.2 and 2.3.2.

Furthermore, in the Oil & Gas segment, an oversupply in the natural gas market against the domestic demand was verified in 2019 as a consequence of higher production in unconventional blocks, which affected the production of gas thus generating a decrease in natural gas sale price in the domestic market.

Additionally, in the Petrochemicals segment, a drop in margins was recorded in 2018 as a result of the sustained increase in operating costs, which has had a significant impact on the cost of the raw material processed in the Catalytic Reformer unit, as well as a decline in benchmark international prices. This in turn led to the recognition of an impairment loss in 2018. During 2019, the Company did not identify indications of reversal or decrease of the impairment loss recognized in 2018.

Therefore, in view of the above-mentioned indications of impairment, the Company has determined the recoverable amount of the CGUs making up the Generation, Distribution of Energy and Oil & Gas segments as of December 31, 2019 and, for the Petrochemicals segment, as of December 31, 2018.

The methodology used in the estimation of the recoverable amount consisted on 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.

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) nature, timing, and modality of the electricity rate increases and/or recognition of cost adjustments in Edenor; (iii) demand projections per type of product; (iv) costs evolution; (v) investment needs appropriate to the service quality levels required by the Edenor´s regulatory authority, and; (vi) macroeconomic variables such as inflation and exchange rates, etc.

11.1.1.1 Generation segment

As of December 31, 2019, the recoverability assessment of the Güemes, Piquirenda and Piedra Buena power plants, in the Generation segment, resulted in the recognition of impairment losses in the amount of U$S 52 million.

The key assumptions used in the calculation of the recoverable amount as of December 31, 2019 consider: i) a reduction in the spot market prices consistently with Resolution SE No. 31/20, detailed in Note 23, and ii) a 11.0% WACC discount rate before tax.

As regards projections, it is worth highlighting that the Management has considered: i) that the Energía Plus contracted volume remains allocated to Genelba to maximize efficiency in cost structure, and ii) the entry into effect of co-generation and closing to combined cycle projects under SEE Resolution No. 287/17 and the resulting dispatch reduction for less efficient power plants such as Güemes and Piedra Buena.

The Company has conducted a sensitivity analysis of the segment’s recoverable amount regarding: i) the discount rate: a 1% increase or decrease in the discount rate would involve U$S 8 million impairment losses decrease or increase, respectively, and ii) the price of energy in the spot market: a 2% increase or decrease in the spot market price would involve a would involve U$S 8 million impairment losses increase or decrease, respectively.

11.1.1.2 Distribution of Energy segment

The future increase in electricity rates used by Edenor to assess the recoverability of its non-financial long-lived assets on balances as of December 31, 2019 is based on the contractual rights held by Edenor deriving from the concession agreement. Furthermore, the new announcements made by government officials and the adopted measures described in Notes 1 and 2 to these Consolidated Financial Statements have been taken into account.

Edenor has made its projections under the assumption that it will obtain better electricity rates in the next few years. However, given the complexity of the country’s macroeconomic scenario, Edenor’s Management is not in a position to ensure that the future performance of the assumptions used in making its projections will be in line with what it has estimated at the date of preparation of these Consolidated Financial Statements.

In order to consider the estimation risk included in the projections of the aforementioned variables, Edenor has taken into consideration three alternative probability-weighted scenarios, which are detailed below:

i.	Pessimistic scenario: Edenor forecasts that 80% of the CPD increases fixed by the RTI will be transferred to tariffs as from January 2022. Furthermore, as from the aforementioned date, 80% of the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 18 monthly installments. From February 2021, 80% of the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 20%.
ii.	Intermediate scenario: Edenor forecasts that the CPD increases fixed by the RTI will be transferred to tariffs as from January 2021. Furthermore, as from the aforementioned date, the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 18 monthly installments. From February 2021, the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 60%.
iii.	Optimistic scenario: Edenor forecasts that the CPD increases fixed by the RTI will be transferred to tariffs as from January 2020. As from January 2021, the outstanding balances, net of the debt with CAMMESA generated in 2020 plus interest, would begin to be recovered in 12 monthly installments. From February 2021, the CPD adjustments related to each period would be transferred to tariffs. A declining inflation rate is used for the projected years. Probability of occurrence assigned 20%.

Edenor has assigned to these three scenarios the previously described probability of occurrence percentages based mainly on experience and giving consideration to the current economic and financial situation.

The discount rate before tax (WACC) in pesos used by Edenor in all the scenarios varies for each year of the projection. For the first 5 years, the average of these rates is 41%.

The main factors that could result in impairment charges in future periods are: i) a distortion in the nature, timing, and modality of the electricity rate increases and recognition of cost adjustments, ii) the development of the costs to be incurred, and iii) the investment needs appropriate to the service quality levels required by the regulatory authority in the RTI, among other factors. These factors have been taken into account in the aforementioned weight of scenarios. Due to the uncertainty inherent in these assumptions, Edenor estimates that any sensitivity analysis that considers changes in any of them taken individually could lead to distorting conclusions.

11.1.1.3 Oil & Gas segment

As of December 31, 2019, the assessment of assets recoverability in the Oil & Gas segment, specifically in the Sierra Chata area, resulted in the recognition of impairment losses in the amount of U$S 10 million.

The key assumptions used in the calculation of the recoverable amount as of December 31, 2019 consider i) a 2020 price of natural gas similar to the 2019 price, and a 20-25% gas price increase for 2021, price that is maintained in subsequent years considering a moderate development of unconventional resources (Vaca Muerta) tending to achieve gas domestic demand supply and a decrease in gas imports, and ii) a 14.1% WACC discount rate before tax. It is worth highlighting that the gas price is maintained in the projections, which in turn affects the estimated investment profile.

The Company has conducted a sensitivity analysis of the segment’s recoverable amount regarding: i) the discount rate: a 1% increase or decrease in the discount rate would involve U$S 2 million impairment losses decrease or increase, respectively, and ii) the gas price: a 2% increase or decrease in the gas price would involve U$S 2 million impairment losses increase or decrease, respectively.

Finally, it is important to highlight that as of December 31, 2019, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value. 

11.1.1.4 Petrochemicals segment

As of December 31, 2018, the assessment of recoverability of the Petrochemicals segment’s assets resulted in the recognition of impairment losses for U$S 32 million.

Key assumptions used in the calculation of the recoverable value as of December 31, 2018 are as follows:

-	Gross margin	7%
-	Discount rate before tax (WACC)	12.8%
-	International Average Styrene Price	1,138 U$S/tn
-	Average gasoline 87 octane price	2.06 U$S/gallon

As regards these assumptions, the Company’s management has determined the estimated gross margin based on past yields and its market growth expectations (including projections of demand, prices and costs); the discount rate used reflects specific risks associated with the Petrochemicals segment.

11.2 Intangible assets

Original values
Type of good	At the beginning	Traslate Effect	At the end
Concession agreements	272	(2)	270
Goodwill	35	-	35
Intangibles identified in acquisitions of companies	7	-	7
Total at 12.31.2019	314	(2)	312
Total at 12.31.2018	314	-	314
	Depreciation
Type of good	At the beginning	For the year	At the end
Concession agreements	(151)	(8)	(159)
Intangibles identified in acquisitions of companies	(2)	-	(2)
Total at 12.31.2019	(153)	(8)	(161)
Total at 12.31.2018	(146)	(7)	(153)
	Net book values
Type of good	At the end	At 12.31.2018
Concession agreements	111	121
Goodwill	35	35
Intangibles identified in acquisitions of companies	5	5
Total at 12.31.2019	151
Total at 12.31.2018		161

11.3 Deferred tax assets and liabilities, income tax and minimum notional income tax

The composition of the deferred tax assets and liabilities is as follows:

	12.31.2018	Profit (loss)	Gain on monetary position, net	12.31.2019
Tax loss carryforwards	52	59	-	111
Trade and other receivables	14	(1)	-	13
Trade and other payables	52	(37)	(2)	13
Salaries and social security payable	1	1	-	2
Defined benefit plans	9	(2)	-	7
Provisions	32	7	-	39
Taxes payable	6	(6)	-	-
Adjustment for tax inflation	-	8	-	8
Other	2	(2)	-	-
Deferred tax asset	168	27	(2)	193
Property, plant and equipment	(334)	(55)	5	(384)
Adjustment for tax inflation	-	(99)	-	(99)
Investments in companies	(19)	11	-	(8)
Intangible assets	(193)	175	5	(13)
Inventory	-	(10)	-	(10)
Trade and other receivables	(9)	5	-	(4)
Financial assets at fair value through profit and loss	(9)	(2)	-	(11)
Cash and cash equivalents	-	-	-	-
Borrowings	(3)	3	-	-
Taxes payable	-	(4)	-	(4)
Other	(6)	6	-	-
Deferred tax liabilities	(573)	30	10	(533)

	12.31.2017	Profit (loss)	Other comprehensive income (loss)	12.31.2018
Tax los-carryforwards	64	(12)	-	52
Trade and other receivables	4	10	-	14
Derivative financial instruments	-	-	-	-
Financial assets at fair value through profit and loss	-	-	-	-
Trade and other payables	46	6	-	52
Salaries and social security payable	-	1	-	1
Defined benefit plans	11	(3)	1	9
Provisions	29	3	-	32
Taxes payable	7	(1)	-	6
Liabilities associated to assets classified as held for sale	14	(14)	-	-
Other	2	-	-	2
Deferred tax asset	177	(10)	1	168
Property, plant and equipment	(443)	108	-	(335)
Investments in companies	(52)	35	(2)	(19)
Intangible assets	(2)	(190)	-	(192)
Trade and other receivables	(27)	17	-	(10)
Financial assets at fair value through profit and loss	(3)	(6)	-	(9)
Borrowings	(5)	2	-	(3)
Assets classified as held for sale	(33)	33	-	-
Other	(4)	(1)	-	(5)
Deferred tax liabilities	(569)	(2)	(2)	(573)

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 amounts, determined after their adequate offset, are disclosed in the statement of financial position:

	12.31.2019	12.31.2018
Deferred tax asset	28	2
Deferred tax liabilities	(368)	(407)
Deferred tax liabilities, net	(340)	(405)

11.4 Inventories

	12.31.2019	12.31.2018
Materials and spare parts	95	94
Advances to suppliers	21	2
In process and finished products	37	40
Stock crude oil	-	1
Total	153	137

11.5 Provisions

	12.31.2019	12.31.2018
Non-Current
Provisions for contingencies	123	125
Asset retirement obligation and dismantling of wind turbines	20	20
Environmental remediation	1	1
Other provisions	1	-
	145	146
Current
Provisions for contingencies	16	17
Asset retirement obligation and dismantling of wind turbines	2	2
Environmental remediation	2	4
Other provisions	-	-
	20	23

	12.31.2019
	For contingencies	Asset retirement obligation and dismantling of wind turbines	For environmental remediation
At the beginning of the year	142	22	5
Increases	41	3	-
Decreases	(10)	-	(2)
Exchange differences on translation	(4)	-	-
Gain on monetary position, net	(17)	-	-
Reversal of unused amounts	(13)	(3)	-
At the end of the year	139	22	3
	12.31.2018
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	141	42	6
Increases	106	37	6
Reclasification	-	(18)	-
Gain on monetary position, net	(52)	(18)	(2)
Decreases	(23)	(5)	(5)
Reversal of unused amounts	(30)	(16)	-
At the end of the year	142	22	5
	12.31.2017
	For contingencies	Asset retirement obligation	For environmental remediation
At the beginning of the year	199	91	17
Increases	43	29	4
Reclasification	(9)	(1)	1
Reclasification to liabilities associated to assets classified as held for sale	-	(34)	(7)
Gain on monetary position, net	(37)	(18)	(3)
Decreases	(39)	(7)	(6)
Reversal of unused amounts	(16)	(18)	-
At the end of the year	141	42	6

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.

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

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 commercial, tax 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.

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, 2019, amount to U$S 89.3 million.

We hereinafter detail the nature of significant proceedings for which provisions have been recorded as of December 31, 2019:

-     Relevant Customs Summary Proceedings - Gasoline Exports: there is an important number of customs summary proceedings and 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’s position involves a higher export duty rate. As December 31, 2019, the associated provision amounts to U$S 84.7 million.

11.6 Income tax and minimum notional income tax liability

	12.31.2019	12.31.2018
Non-current
Income tax, net of witholdings and advances	10	27
Total non current	10	27
Current
Income tax, net of witholdings and advances	53	25
Minimum notional income tax, net of witholdings and advances	-	4
Total current	53	29

11.6.1 Income tax

Pampa and HIDISA and HINISA has assessed income tax for the fiscal period 2012 to 2018, respectively taking into consideration the application of the inflation adjustment mechanisms set forth in Title VI of the Income Tax Act, the update of Property, plant and equipment amortizations (Sections 83, 84 and 89), a cost restatement on account of the disposal of shares and mutual funds quotas (Sections 58, 61 and 89), and the update of intangible assets amortizations (Sections 81.c, 84 and 89, and Section 128 of its regulatory decree), to such effect using the IPIM published by the INDEC and the IPC of the Autonomous City of Buenos Aires for the November-December 2015 period, based on the similarity with the parameters put forward in the matter of “Candy S.A.” heard by the National Supreme Court of Justice, which on July 3, 2009 ruled for the application of the inflation adjustment mechanism.

As a consequence of adherence to the tax revaluation optional regime detailed in Note 2.6.1.4, on March 29, 2019, Pampa withdrew from the actions promoted and on April 4, 2019, paid the income tax corresponding to the 2016 fiscal period, without considering the application of the fiscal inflation adjustment, plus related interests in an amount of U$S 10.8 million.

As of December 31, 2019, HIDISA and HINISA hold a provision for the additional income tax liabilities assessable for fiscal years mentioned in case the inflation adjustment had not been deducted. This provision amounts to U$S 9.9 million including compensatory interest and was disclosed in the line “Income tax liability and minimum notional income tax non-current”.

11.7 Tax liabilities

	12.31.2019	12.31.2018
Non-current
Value added tax	-	4
Sales tax	1	1
Payment plans	-	2
Extraordinary Canon	3	7
Total non-current	4	14
Current
Value added tax	38	21
Municipal, provincial and national contributions	3	3
Personal assets tax provision	3	-
Payment plans	1	1
Municipal taxes	2	3
Tax withholdings to be deposited	6	9
Royalties	4	5
Extraordinary Canon	12	10
Other	3	2
Total current	72	54

11.7.1 Gross Income Tax

The Company has differences in interpretation with Argentine Provincial Treasuries regarding certain taxes applicable to the Company’s activity. Particularly, HIDISA and HINISA have filed a note to the Province of Neuquén’s Revenue Department informing that they consider that the electric power generation activity conducted in that province should be covered by the provisions of Section 12 of Law No. 15,336. Thus, and pursuant to this section, revenues resulting from the generation of electric power are exempted from the provincial gross income tax. However, they hold a provision for gross income tax that would have applied.

The Company’s management estimates that the resolution of these issues will not have a material adverse effect on its financial position or operating results.

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 US 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 US 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 choice to use it, in which case it may have to notify the trustee thereof.

As of December 31, 2019, 2018 and 2017, the most relevant actuarial information corresponding to the described benefit plans is the following:

	12.31.2019
	Present value of the obligation	Fair value of plan assets	Net liability at the end of the year
Liabilities at the beginning	40	(5)	35
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	15	(2)	13
Items classified in other comprehensive  income
Actuarial (gains) losses	(2)	-	(2)
Benefit payments	(2)	-	(2)
Gain on monetary position, net	(18)	2	(16)
At the end	36	(5)	31
	12.31.2018
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	47	(3)	44
Items classified in profit or loss
Current services cost	2	-	2
Cost for interest	9	(1)	8
Past services cost	(5)	-	(5)
Items classified in other comprehensive  income
Actuarial losses (gains)	6	(2)	4
Benefit payments	(3)	-	(3)
Increase for subsidiries acquisition	(16)	1	(15)
At the end	40	(5)	35

	12.31.2017
	Present value of the obligation	Present value of assets	Net liability at the end of the year
Liabilities at the beginning	58	(8)	50
Items classified in profit or loss
Current services cost	3	-	3
Cost for interest	12	(1)	11
Past services cost	1	-	1
Items classified in other comprehensive income
Actuarial losses (gains)	(1)	-	(1)
Exchange differences on translation	1	(1)	-
Benefit payments	(2)	-	(2)
Reclasification to liabilities associated to assets classified as hed for sale	(11)	4	(7)
Gain (loss) on net monetary position	(14)	3	(11)
At the end	47	(3)	44

As of December 31, 2019, the breakdown of net liabilities per type of plan is as follows: a) U$S 21 million correspond to the Pension and Retirement Benefits Plan and b) U$S 10 million correspond to the Compensatory Plan.

As of December 31, 2018, net liability by type of plan, is as follows: a) U$S 24 million corresponding to Pension and Retirement Benefits Plan and b) U$S 11 million corresponding to Compensatory Plan.

As of December 31, 2017, net liability by type of plan, is as follows: a) U$S 33 million corresponding to Pension and Retirement Benefits Plan and b) U$S 11 million corresponding to Compensatory Plan.

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.

	12.31.2019
Less than one year	4
One to two years	3
Two to three years	2
Three to four years	2
Four to five years	2
Six to ten years	11

Significant actuarial assumptions used were as follows:

	12.31.2019	12.31.2018	12.31.2017
Discount rate	5%	5%	5%
Salaries increase	1%	1%	1%
Average inflation	50%	27%	21%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount: 

	12.31.2019
Discount rate: 4%	39
Obligation	3
Variation	10%
Discount rate: 6%	33
Obligation	(3)
Variation	(9%)
Salaries increase: 0%	34
Obligation	(2)
Variation	(5%)
Salaries increase: 2%	38
Obligation	2
Variation	6%

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

	12.31.2019	12.31.2018
Non-current
Seniority - based bonus	3	4
Early retirements payable	1	-
Total non-current	4	4
Current
Salaries and social security contributions	22	24
Provision for vacations	17	19
Provision for gratifications and annual bonus for efficiency	26	29
Total current	65	72

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10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfFinancialResultsLineItems [Line Items]
Gain on monetary position, net	$ 187	$ 629	$ 304
Financial income	96	99	62
Financial costs	(299)	(316)	(232)
Other financial results	113	(858)	(100)
Total financial results, net	97	(446)	34
Commercial interest
DisclosureOfFinancialResultsLineItems [Line Items]
Financial income	61	58	43
Financial costs	(52)	(78)	(45)
Financial interest
DisclosureOfFinancialResultsLineItems [Line Items]
Financial income	22	34	14
Financial costs	(227)	(210)	(162)
Other interest
DisclosureOfFinancialResultsLineItems [Line Items]
Financial income	13	7	5
Financial costs	(10)	(15)	(10)
Fiscal interest
DisclosureOfFinancialResultsLineItems [Line Items]
Financial costs	(6)	(8)	(11)
Other financial expenses
DisclosureOfFinancialResultsLineItems [Line Items]
Financial costs	(4)	(5)	(4)
Foreign currency exchange difference, net
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	(75)	(863)	(156)
Changes in the fair value of financial instruments
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	91	64	62
Gains (losses) from present value measurement
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	54	(74)	(6)
Other financial results of RDSA
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	2	13	0
Result from repurchase of Corporate Bonds
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	27	2	0
Other financial results
DisclosureOfFinancialResultsLineItems [Line Items]
Other financial results	$ 14	$ 0	$ 0

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11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 6) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Non-financial Assets And Liabilities
Deferred tax asset	$ 28	$ 2
Deferred tax liabilities	(368)	(407)
Deferred tax liabilities, net	$ (340)	$ (405)

XML

22. OIL AND GAS RESERVES (Information not covered by the auditors' report) (Details)	Dec. 31, 2019 MBbls MMcm
Oil and LNG
DisclosureOfProvedReservesLineItems [Line Items]
Proved developed reserves | MBbls	8,804
Proved undeveloped reserves | MBbls	4,746
Proved reserves | MBbls	13,550
Natural Gas
DisclosureOfProvedReservesLineItems [Line Items]
Proved developed reserves | MMcm	10,534
Proved undeveloped reserves | MMcm	10,168
Proved reserves | MMcm	20,702
Argentina | Oil and LNG
DisclosureOfProvedReservesLineItems [Line Items]
Proved developed reserves | MBbls	8,804
Proved undeveloped reserves | MBbls	4,746
Proved reserves | MBbls	13,550
Argentina | Natural Gas
DisclosureOfProvedReservesLineItems [Line Items]
Proved developed reserves | MMcm	10,534
Proved undeveloped reserves | MMcm	10,168
Proved reserves | MMcm	20,702

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about intangible assets [line items]
Intangible assets, beginning	$ 314	$ 314
Translation effect	(2)	0
Intangible assets, ending	312	314
Concession agreements
Disclosure of detailed information about intangible assets [line items]
Intangible assets, beginning	272
Translation effect	(2)
Intangible assets, ending	270	272
Goodwill
Disclosure of detailed information about intangible assets [line items]
Intangible assets, beginning	35
Translation effect	0
Intangible assets, ending	35	35
Intangibles identified in acquisitions of companies
Disclosure of detailed information about intangible assets [line items]
Intangible assets, beginning	7
Translation effect	0
Intangible assets, ending	$ 7	$ 7

XML

10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	$ 148	$ 171	$ 127
Salaries and social security charges
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	22	26	27
Benefits to employees
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	1	0	0
Accrual of defined benefit plans
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	1	0	1
Work contracts, fees and compensation for services
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	29	30	26
Compensation agreements
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	(1)	2	6
Depreciation of property, plant and equipment
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	9	9	3
Right-of-use assets amortization
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	1	0	0
Taxes, rates and contributions
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	25	33	28
Communications
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	6	7	8
Penalties
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	22	28	12
Net impairment losses on financial assets
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	21	28	11
Transport
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	9	6	4
Other
DisclosureOfSellingExpensesLineItems [Line Items]
Selling expenses	$ 3	$ 2	$ 1

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5. GROUP STRUCTURE (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfGroupStructureLineItems [Line Items]
Revenue	$ 2,836	$ 2,920	$ 2,175
Cost of sales	(2,032)	(1,967)	(1,574)
Gross profit	804	953	601
Selling expenses	(148)	(171)	(127)
Administrative expenses	(174)	(206)	(198)
Exploration expenses	(9)	(1)	(2)
Other operating income	40	181	149
Other operating expenses	(86)	(200)	(103)
Operating income (loss)	751	670	368
Gain (loss) on monetary position	187	629	304
Financial income	96	99	62
Financial costs	(299)	(316)	(232)
Other financial results	113	(858)	(100)
Financial results, net	97	(446)	34
Income (loss) before income tax	848	224	402
Income tax	(48)	(17)	26
Profit (loss) of the year from discontinued operations	0	80	(50)
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Income tax	0	1	0
Exchange differences on translation	(15)	0	0
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Total comprehensive income (loss) of the year from discontinued operations	765	292	367
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Discontinued operations	0	78	(55)
Total comprehensive income (loss) of the year attributable to from discontinued operations
Discontinued operations	$ 0	84	(62)
Oil and gas
DisclosureOfGroupStructureLineItems [Line Items]
Revenue		66	259
Cost of sales		(33)	(251)
Gross profit		33	8
Selling expenses		(2)	(8)
Administrative expenses		(1)	(6)
Exploration expenses			(1)
Other operating income		1	16
Other operating expenses		(6)	(8)
Result from the sale of share of profit and property, plant and equipment		44	0
Operating income (loss)		69	1
Gain (loss) on monetary position		7
Financial income		4	1
Financial costs		(1)	0
Other financial results		(4)	(10)
Financial results, net		6	(9)
Income (loss) before income tax		75	(8)
Income tax		(26)	(28)
Profit (loss) of the year from discontinued operations		49	(36)
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Income tax		(2)	2
Reclasification from exchange differences on translation		6
Exchange differences on translation		4	(16)
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Other comprehensive income (loss) of the year from discontinued operations		8	(14)
Total comprehensive income (loss) of the year from discontinued operations		57	(50)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company		47	(41)
Non - controlling interest		2	5
Discontinued operations		49	(36)
Total comprehensive income (loss) of the year attributable to from discontinued operations
Owners of the company		53	(48)
Non - controlling interest		4	(2)
Discontinued operations		57	(50)
Refining and distribution
DisclosureOfGroupStructureLineItems [Line Items]
Revenue		422	728
Cost of sales		(361)	(618)
Gross profit		61	110
Selling expenses		(33)	(82)
Administrative expenses		(4)	(19)
Exploration expenses			0
Other operating income		6	10
Other operating expenses		(10)	(13)
Result from the sale of share of profit and property, plant and equipment		0	(28)
Operating income (loss)		20	(22)
Gain (loss) on monetary position		2
Financial income		1	1
Financial costs		0	(1)
Other financial results		22	(1)
Financial results, net		25	(1)
Income (loss) before income tax		45	(23)
Income tax		(14)	8
Profit (loss) of the year from discontinued operations		31	(15)
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Income tax		0	0
Reclasification from exchange differences on translation		0
Exchange differences on translation		0	0
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Other comprehensive income (loss) of the year from discontinued operations		0	0
Total comprehensive income (loss) of the year from discontinued operations		31	(15)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company		31	(15)
Non - controlling interest		0	0
Discontinued operations		31	0
Total comprehensive income (loss) of the year attributable to from discontinued operations
Owners of the company		31	(15)
Non - controlling interest		0	0
Discontinued operations		31	(15)
Eliminations
DisclosureOfGroupStructureLineItems [Line Items]
Revenue		(90)	(296)
Cost of sales		91	297
Gross profit		1	1
Selling expenses		0	0
Administrative expenses		0	0
Exploration expenses			0
Other operating income		0	0
Other operating expenses		0	0
Result from the sale of share of profit and property, plant and equipment		0	0
Operating income (loss)		1	1
Gain (loss) on monetary position		(1)
Financial income		0	0
Financial costs		0	0
Other financial results		0	0
Financial results, net		(1)	0
Income (loss) before income tax		0	1
Income tax		0	0
Profit (loss) of the year from discontinued operations		0	1
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Income tax		0	0
Reclasification from exchange differences on translation		0
Exchange differences on translation		0	0
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Other comprehensive income (loss) of the year from discontinued operations		0	0
Total comprehensive income (loss) of the year from discontinued operations		0	1
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company		0	1
Non - controlling interest		0	0
Discontinued operations		0	1
Total comprehensive income (loss) of the year attributable to from discontinued operations
Owners of the company		0	1
Non - controlling interest		0	0
Discontinued operations		0	1
Total
DisclosureOfGroupStructureLineItems [Line Items]
Revenue		398	691
Cost of sales		(303)	(572)
Gross profit		95	119
Selling expenses		(35)	(90)
Administrative expenses		(5)	(25)
Exploration expenses			(1)
Other operating income		7	26
Other operating expenses		(16)	(21)
Result from the sale of share of profit and property, plant and equipment		44	(28)
Operating income (loss)		90	(20)
Gain (loss) on monetary position		8
Financial income		5	2
Financial costs		(1)	(1)
Other financial results		18	(11)
Financial results, net		30	(10)
Income (loss) before income tax		120	(30)
Income tax		(40)	(20)
Profit (loss) of the year from discontinued operations		80	(50)
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Income tax		(2)	2
Reclasification from exchange differences on translation		6
Exchange differences on translation		4	(16)
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Other comprehensive income (loss) of the year from discontinued operations		8	(14)
Total comprehensive income (loss) of the year from discontinued operations		88	(64)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company		78	(55)
Non - controlling interest		2	5
Discontinued operations		80	(50)
Total comprehensive income (loss) of the year attributable to from discontinued operations
Owners of the company		84	(62)
Non - controlling interest		4	(2)
Discontinued operations		$ 88	$ (64)

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17. RELATED PARTIES TRANSACTIONS (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Refinor
Disclosure of transactions between related parties [line items]
Purchases of goods and services	$ (19)	$ (34)	$ (17)
Oldelval
Disclosure of transactions between related parties [line items]
Purchases of goods and services	(1)	(2)	(3)
Origenes Vida
Disclosure of transactions between related parties [line items]
Purchases of goods and services	0	0	(1)
Total related parties
Disclosure of transactions between related parties [line items]
Purchases of goods and services	(43)	(61)	(31)
TGS
Disclosure of transactions between related parties [line items]
Purchases of goods and services	(22)	(21)	(8)
SACME
Disclosure of transactions between related parties [line items]
Purchases of goods and services	(1)	(2)	(2)
SACDE
Disclosure of transactions between related parties [line items]
Purchases of goods and services	$ 0	$ (2)	$ 0

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14. STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement Of Cash Flows Complementary Information
Income tax	$ 48	$ 17	$ (26)
Accrued interest	202	219	166
Depreciations and amortizations	263	234	205
Constitution of allowances, net	25	28	12
Constitution (recovery) of provisions, net	27	31	(4)
Share of profit from associates and joint ventures	(101)	(118)	(48)
Income from sale of companies	0	(28)	0
Accrual of defined benefit plans	16	5	14
Net exchange differences	75	863	156
Result from measurement at present value	(54)	74	6
Changes in the fair value of financial instruments	(91)	(64)	(62)
Results from property, plant and equipment sale and decreases	5	4	1
Results for the repurchase of corporate bonds	(27)	(2)	0
ImImpairment of property, plant and equipment	62	32	0
Dividends received	(1)	(1)	(1)
Compensation agreements	(1)	5	26
Result from sale of shareholdings in companies and property, plant, and equipment	0	(44)	0
Agreement on the regularization of obligations	(285)	0	0
Other financial results of RDSA	(2)	(13)	0
Onerous contract (Ship or pay)	0	7	4
Gain on monetary position, net	(187)	(629)	(304)
Other	(8)	2	6
Adjustments to reconcile net profit (loss) to cash flows generated by operating activities:	$ (30)	$ 622	$ 151

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5. GROUP STRUCTURE (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Revenue	$ 2,836	$ 2,920	$ 2,175
Interest income	96	99	62
Interest expense	299	316	232
Profit before income tax	848	224	402
Income tax	48	17	(26)
Profit for the year	800	287	378
Other comprehensive loss	(35)	5	(11)
Total comprehensive income of the year	765	292	367
Income of the year attributable to non-controlling interest	108	63	92
Comprehensive income of the year attributable to non-controlling interest	93	67	86
Edenor
Disclosure of subsidiaries [line items]
Revenue	1,502	1,484	1,050
Depreciation	(77)	(68)	(57)
Interest income	20	18	12
Interest expense	(113)	(132)	(68)
Profit before income tax	381	164	148
Income tax	(178)	(50)	(14)
Profit for the year	203	114	134
Other comprehensive loss	0	(1)	0
Total comprehensive income of the year	203	113	134
Income of the year attributable to non-controlling interest	98	55	65
Other comprehensive income of the year attributable to non-controlling interest	0	(1)	0
Comprehensive income of the year attributable to non-controlling interest	$ 98	$ 54	$ 65

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5. GROUP STRUCTURE (Details 9) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of joint ventures [line items]
Share of profit (loss) of associates	$ 19	$ 34	$ (2)
Share of profit (loss) of joint ventures	82	84	50
Share of profit (loss) of associates and joint ventures	101	118	48
CIESA
Disclosure of joint ventures [line items]
Share of profit (loss) of joint ventures	50	74	25
CTB
Disclosure of joint ventures [line items]
Share of profit (loss) of joint ventures	13	0	0
Citelec
Disclosure of joint ventures [line items]
Share of profit (loss) of joint ventures	19	21	27
Greenwind
Disclosure of joint ventures [line items]
Share of profit (loss) of joint ventures	0	(11)	(2)
Oldelval
Disclosure of joint ventures [line items]
Share of profit (loss) of associates	0	3	1
Refinor
Disclosure of joint ventures [line items]
Share of profit (loss) of associates	(3)	(4)	(3)
OCP
Disclosure of joint ventures [line items]
Share of profit (loss) of associates	21	35	0
TGS
Disclosure of joint ventures [line items]
Share of profit (loss) of associates	$ 1	$ 0	$ 0

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18. LEASES (Details 4) $ in Millions	Dec. 31, 2019 USD ($)
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	$ 48
Less than three months
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	2
Three months to one year
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	6
One to two years
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	7
Two to three years
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	7
Three to four years
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	7
Four to five years
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	7
More than five years
DisclosureOfLeaseReceivablesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease receivables contractual undiscounted cash flows	$ 12

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5. GROUP STRUCTURE (Details 13) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Group Structure
Exploratory well costs, beginning	$ 19	$ 15	$ 16
Increases	30	8	8
Transferred to development	(11)	0	(8)
Loss of the year	(5)	(1)	(1)
Exploratory well costs, ending	$ 33	$ 19	$ 15
Number of wells at the end of the year	9	7	7

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18. LEASES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets, beginning	$ 0
Increase	20
Right of use assets, ending	20
Machinery and equipment
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets, beginning	0
Increase	13
Right of use assets, ending	13
Buildings
Disclosure of quantitative information about right-of-use assets [line items]
Right of use assets, beginning	0
Increase	7
Right of use assets, ending	$ 7

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 11) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, non current	$ 4	$ 14
Taxes payables, current	72	54
Value added tax
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, non current	0	4
Taxes payables, current	38	21
Sales tax
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, non current	1	1
Municipal, provincial and national contributions
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	3	3
Personal assets tax provision
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	3	0
Payment plans
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, non current	0	2
Taxes payables, current	1	1
Municipal taxes
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	2	3
Tax withholdings to be deposited
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	6	9
Royalties
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	4	5
Extraordinary Canon
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, non current	3	7
Taxes payables, current	12	10
Other
DisclosureOfTaxLiabilitiesLineItems [Line Items]
Taxes payables, current	$ 3	$ 2

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 15) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Discount rate: 4%
Disclosure of defined benefit plans [line items]
Obligation	$ 39
Variation	$ 3
Percentage of variation	10.00%
Discount rate: 6%
Disclosure of defined benefit plans [line items]
Obligation	$ 33
Variation	$ (3)
Percentage of variation	(9.00%)
Salaries increase: 0%
Disclosure of defined benefit plans [line items]
Obligation	$ 34
Variation	$ (2)
Percentage of variation	(5.00%)
Salaries increase: 2%
Disclosure of defined benefit plans [line items]
Obligation	$ 38
Variation	$ 2
Percentage of variation	6.00%

XML

17. RELATED PARTIES TRANSACTIONS (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CIESA/TGS
Disclosure of transactions between related parties [line items]
Dividends received	$ 56	$ 18	$ 0
OCP
Disclosure of transactions between related parties [line items]
Dividends received	14	0	0
Oldeval
Disclosure of transactions between related parties [line items]
Dividends received	0	1	0
Citelec
Disclosure of transactions between related parties [line items]
Dividends received	17	0	0
Total related parties
Disclosure of transactions between related parties [line items]
Dividends received	$ 87	$ 19	$ 0

XML

6. RISKS (Details 3) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Financial assets
AllowanceAccountForCreditLossesOfFinancialAssetsLineItems [Line Items]
Loss allowance under IAS 39	$ 22
Adjustment to the opening balance of retained earnings	4
Loss allowance calculated under IFRS 9	26
Other receivables
AllowanceAccountForCreditLossesOfFinancialAssetsLineItems [Line Items]
Loss allowance under IAS 39	7
Adjustment to the opening balance of retained earnings	(1)
Loss allowance calculated under IFRS 9	$ 6

XML

5. GROUP STRUCTURE (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Refining and distribution
DisclosureOfGroupStructureLineItems [Line Items]
Sale price	$ 28
Book value of assets sold and costs associated with the transaction	(28)
Result for sale	0
PELSA
DisclosureOfGroupStructureLineItems [Line Items]
Sale price	270
Book value of assets sold and costs associated with the transaction	(226)
Result for sale	44
Interests	4
Income tax	(22)
Included in results	26
Other comprehensive income (loss)
Reclassification from exchange differences on translation	6
Income tax	(2)
Included in other comprehensive income	4
Total comprehensive income	$ 30

XML

2. REGULATORY FRAMEWORK (Details)	12 Months Ended
	Dec. 31, 2019
Generator in operation 1
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTG
Generating unit	GUEMTG01
Tecnology	TG
Power	100 MW
Applicable regime	Energy Plus Res. No. 1281/06
Generator in operation 2
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTG
Generating unit	GUEMTV11
Tecnology	TV
Power	=< 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 3
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTG
Generating unit	GUEMTV12
Tecnology	TV
Power	=< 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 4
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTG
Generating unit	GUEMTV13
Tecnology	TV
Power	< 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 5
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	Piquirenda
Generating unit	PIQIDI 01-10
Tecnology	MG
Power	30 MW
Applicable regime	SE Resolution No. 220/07
Generator in operation 6
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CPB
Generating unit	BBLATV29
Tecnology	TV
Power	> 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 7
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CPB
Generating unit	BBLATV30
Tecnology	TV
Power	> 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 8
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CT Ing. White
Generating unit	BBLMD01-06
Tecnology	MG
Power	100 MW
Applicable regime	SEE Resolution No. 21/16
Generator in operation 9
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATG01
Tecnology	TG
Power	> 50 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 10
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATG02
Tecnology	TG
Power	> 50 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 11
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATG03
Tecnology	TG
Power	> 50 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 12
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATG04
Tecnology	TG
Power	105 MW
Applicable regime	SEE Res. 220/07 (75%), SEE Res. 1/19 (25%)
Generator in operation 13
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATG05
Tecnology	TG
Power	105 MW
Applicable regime	SEE Resolution No. 21/16
Generator in operation 14
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	LDLATV01
Tecnology	TV
Power	180 MW
Applicable regime	SE Resolution No. 220/07
Generator in operation 15
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTGEBA
Generating unit	GEBATG01/TG02/TV01
Tecnology	CC
Power	> 150 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 16
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTGEBA
Generating unit	GEBATG03
Tecnology	TG
Power	188 MW
Applicable regime	Energy Plus Res. No. 1281/06
Generator in operation 17
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTGEBA
Generating unit	GEBATG04
Tecnology	TG
Power	> 100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 18
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	Ecoenergía
Generating unit	CERITV01
Tecnology	TV
Power	Renewable  =< 50
Applicable regime	Energy Plus Res. N° 1281/06
Generator in operation 19
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CT Parque Pilar
Generating unit	PILBD01-06
Tecnology	MG
Power	100 MW
Applicable regime	SE Resolutions No. 1/19
Generator in operation 20
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTB
Generating unit	EBARTG01 - TG02
Tecnology	TG
Power	HI - Small 50<P=<120
Applicable regime	SE Resolution No. 220/07
Generator in operation 21
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	HIDISA
Generating unit	AGUA DEL TORO
Tecnology	HI
Power	HI - Small 50<P=<120
Applicable regime	SE Resolutions No. 1/19
Generator in operation 22
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	HIDISA
Generating unit	EL TIGRE
Tecnology	HI
Power	HI - Small 50<P=<120
Applicable regime	SE Resolutions No. 1/19
Generator in operation 23
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	HIDISA
Generating unit	LOS REYUNOS
Tecnology	HB
Power	HB - Media 120<P=<300
Applicable regime	SE Resolutions No. 1/19
Generator in operation 24
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	HINISA
Generating unit	NIHUIL I - II - III
Tecnology	HI
Power	HI - Chica 50<P=<120
Applicable regime	SE Resolutions No. 1/19
Generator in operation 25
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	HPPL
Generating unit	PPLEHI
Tecnology	HI
Power	HI - Media 120<P=<300
Applicable regime	SE Resolutions No. 1/19
Generator in operation 26
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	P.E. M. Cebreiro
Generating unit	CORTEO
Tecnology	Eólica
Power	100 MW
Applicable regime	Renovar
Generator in operation 27
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	PEPE II
Generating unit	PAMEEO
Tecnology	Eólica
Power	53 MW
Applicable regime	SEE Resolution No. 281/17
Generator in operation 28
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	PEPE III
Generating unit	BAHIEO
Tecnology	Eólica
Power	53 MW
Applicable regime	SEE Resolution No. 281/17

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 5) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
DisclosureOfCashAndCashEquivalentsLineItems [Line Items]
Cash and cash equivalents	$ 225	$ 241	$ 31	$ 69
Banks
DisclosureOfCashAndCashEquivalentsLineItems [Line Items]
Cash and cash equivalents	57	83
Investment funds
DisclosureOfCashAndCashEquivalentsLineItems [Line Items]
Cash and cash equivalents	4	0
Time deposits
DisclosureOfCashAndCashEquivalentsLineItems [Line Items]
Cash and cash equivalents	$ 164	$ 158

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 9) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current trade payables	$ 7	$ 8
Non current other payables	83	212
Non current trade and other payables	90	220
Current trade payables	383	580
Current other payables	71	77
Current trade and other payables	454	657
Customer contributions
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current trade payables	3	3
Current trade payables	1	0
Funding contributions for substations
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current trade payables	0	1
Customer guarantees
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current trade payables	4	4
ENRE Penalties and discounts
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	64	138
Current other payables	57	49
Loans (mutuums) with CAMMESA
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	0	61
Compensation agreements
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	7	7
Current other payables	3	13
Liability with FOTAE
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	0	5
Payment agreement with ENRE
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	0	1
Current other payables	1	2
Lease liability
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	12	0
Current other payables	4	0
Other
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Non current other payables	0	0
Current trade payables	0	1
Current other payables	1	5
Suppliers
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current trade payables	212	250
CAMMESA
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current trade payables	155	316
Discounts to customers
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current trade payables	0	1
Customer advances
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current trade payables	7	6
Related parties
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current trade payables	8	6
Current other payables	5	0
Other creditors
DisclosureOfTradeAndOtherPayablesLineItems [Line Items]
Current other payables	$ 0	$ 8

XML

14. STATEMENT OF CASH FLOWS' COMPLEMENTARY INFORMATION (Tables)

12 Months Ended

Dec. 31, 2019

Statement Of Cash Flows Complementary Information

Adjustments to reconcile net profit (loss) to cash flows generated by operating activities

	Note	12.31.2019	12.31.2018	12.31.2017
Income tax	10.6	48	17	(26)
Accrued interest		202	219	166
Depreciations and amortizations	9, 10.1 and 10.2	267	234	205
Constitution of allowances, net	10.4 and 10.1	25	28	12
Constitution (recovery) of provisions, net	10.4	27	31	(4)
Share of profit from joint ventures and associates	5.3.2	(101)	(118)	(48)
Income from the sale of companies	5.1	-	(28)	-
Accrual of defined benefit plans	9, 10.1 and 10.2	16	5	14
Net exchange differences	10.5	75	863	156
Result from measurement at present value	10.5	(54)	74	6
Changes in the fair value of financial instruments	10.5	(91)	(64)	(62)
Results from property, plant and equipment sale and decreases	10.4 and 10.3	5	4	1
Results for the repurchase of corporate bonds	10.5	(27)	(2)	-
Impairment of property, plant and equipment	11.1.1	62	32	-
Dividends received	10.4	(1)	(1)	(1)
Compensation agreements	10.1 and 10.2	(1)	5	26
Result from the sale of shareholdings in companies, property, plant and equipment	5.2.3	-	(44)	-
Agreement on the regularization of obligations		(285)	-	-
Other financial results of RDSA		(2)	(13)	-
Onerous contract (Ship or pay)	10.4	-	7	4
Gain on monetary position, net	10.5	(187)	(629)	(304)
Other		(8)	2	6
		(30)	622	151

Changes in operating assets and liabilities

	12.31.2019	12.31.2018	12.31.2017
Increase (decrease) in trade receivables and other receivables	17	(172)	(65)
Increase in inventories	(28)	(18)	(11)
Increase in trade payables and other payables	97	22	10
Increase in deferred income	-	2	-
Decrease in salaries and social security payable	15	14	(1)
Decrease in defined benefit plans	(2)	(3)	(3)
(Decrease) increase in tax payables	20	35	(26)
(Increase) decrease in provisions	(9)	(60)	(48)
Income tax and minimum notional income tax paid	(87)	(49)	(56)
(Payments) proceeds from derivative financial instruments, net	9	(24)	23
Total changes in operating assets and liabilities	32	(253)	(177)

Significant non-cash transactions

	12.31.2019	12.31.2018	12.31.2017
Acquisition of property, plant and equipment through an increase in trade payables	(45)	17	(103)
Borrowing costs capitalized in property, plant and equipment	(17)	(7)	(16)
Decreases of  property, plant and equipment through an increase in other receivables	-	12	-
Agreement on the regularization of obligations	285	-	-
Increase in asset retirement obligation provision through an increase in property, plant and equipment	1	34	(2)
Constitution of guarantee of derivative financial instruments, net through the delivery of financial assets at fair value through profit or loss	3	(22)	19
Cancellation of other credits for capital contributions in associates	(17)	-	-
Compensation of investments at a cost cost through the transfer of other credits	(126)	-	-
Loan compensation through the transfer of sales credits	135	-	-
Increase of right-of-use assets through an increase in other debts	20	-	-
Significant non-cash transactions from discontinued operations :
Credit pending collection for sale of property, plant and equipment	-	-	15

XML

15. CONTINGENT LIABILITIES AND ASSETS

12 Months Ended

Dec. 31, 2019

Contingent Liabilities And Assets

CONTINGENT LIABILITIES AND ASSETS

We hereinafter detail the nature of significant proceedings as of December 31, 2019, 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.

-        Claims by former employees seeking a compensation under the plan on account of terminations due to changes in shareholding control.

-        Claims on considering that the index (IPC) used to update the plan benefits are ineffective to keep their “constant value”.

-        Claims on an alleged underfunding of the plan upon the elimination of the Company’s contributions based on earnings.

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.

-        Income tax refund: The Company, HIDISA, HINISA and CPB have filed several tax refund claims in the amount of $ 1,169 million for overpaid income taxes taking into considerations the effects of the inflation adjustment mechanism. On December 7, 2017, CPB collected the amount claimed for the 2002 period, which amounts to $ 4 million plus interest. However, upon joining the tax revaluation regime detailed in Note 2.6.1.4, on March 29, 2019 and April 3, 2019, Pampa and CPB, respectively, formally presented their waiver to the rights invoked in the mentioned tax refund claims in the amounts of $ 1,095 million and $ 1.6 million, respectively.

-        Minimum notional income tax refund: The Company and the former CTLL have filed several refund claims before the AFIP on account of the minimum notional income tax for fiscal periods 2008 and 2009 requesting the refund of $ 25 million, including the refund of payments timely made and the release of the offsetting payment made against several tax credits. As AFIP didn’t answer the claim, the Company and the former CTLL brought a tax refund claim before the competent National First-Instance Administrative Litigation Court.

On August 25, 2016 the former CTLL obtained a favorable ruling by the Chamber of Appeals, which upheld the first-instance decision sustaining the refund claim; however, the payment has not been collected as of the date hereof, and the Company is conducting the relevant proceedings in this respect. The Company considers it has a high probability of obtaining a favorable final and conclusive ruling.

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 U$S 547 million based on a PDUN 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 U$S 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 U$S 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 proceeding is pending the resolution of the admissibility of CSJN’s jurisdiction.

-        A group of neighbors of the City of Bahía Blanca instituted a complaint before the provincial courts of this city for alleged environmental damage having collective impact against the companies of the petrochemical complex, Consorcio de Gestión Del Puerto de Bahía Blanca and the Province of Buenos Aires. The plaintiffs seek the redress of collective moral injury (estimated at $ 52 million), the cessation of the alleged damage to the estuary of Bahía Blanca, and a comprehensive restoration to its previous state. In case this is not possible, the plaintiffs subsidiarily seek damages, the beneficiary of which would be the Environmental Compensation Fund. They also request a prohibition to install new industrial activities in the area and the development of a new and efficient industrial waste collection, disposal and treatment system. The proceeding is in the sentence stage.

-        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 maintained its jurisdiction in the environmental issue and the Court’s jurisdiction regarding the compensation for the alleged damages.

-        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 with a negative conflict of jurisdiction.

-        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 proceeding is in the lawsuit integration stage.

-        The Company initiated a legal claim against the Province of La Pampa requesting the annulment and revocation of administrative acts through which said Province through its Undersecretary of Hydrocarbons and Mining and its Undersecretariat of Environment, intends that the Company carries out definitive abandonment of 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.

-        Plaintiffs María Elena Baya de Rudd and David Rudd have filed a complaint against the Company, other companies and the joint venture made up by them for the repair of alleged damages caused in the Estancia Laguna Esperanza lot owned by them and the remediation of alleged environmental damage caused by the exploitation and abandonment of oil wells in the lot.  A sentence was issued in the appellate proceeding. We have filed a federal extraordinary appeal against that sentence, and have jointly requested with the plaintiff the suspension of the procedural time limits in order to negotiate a settlement, which suspension was granted.

-        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 proceeding is currently in the evidentiary stage. 

-        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 has been filed and answered.   

15.4 Civil and Commercial Claims

-        The “Consumidores Financieros Asociación Civil Para Su Defensa” claim the nominal amount of U$S 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 is appealing the Arbitration Court’s decision declaring the dismissal of the main claim upon the failure to pay the arbitration fee.

-        The Company was notified of the institution of a collective action in the City of Rio de Janeiro, Brazil, by a lawyer of that nationality, Felipe Machado Caldeira, alleging that Petrobras Brasil has not conducted Petrobras Argentina’s sales process pursuant to a competitive bidding process in accordance with Brazilian laws applicable to mixed public-private firms in Brazil, for a nominal amount of R$ 1,000 million. In this proceeding, no specific accusation against Pampa has been filed. The proceeding is currently suspended in the integration and complaint answer stage.  Upon the death of the plaintiff and the Public Prosecution Service’s statement that it is not interested in pursuing the complaint, a legal notice was published so that any citizen may express its interest in pursuing it.

-        Messrs. Candoni, Giannasi, Pinasco and Torriani brought arbitration complaints against the Company before the Buenos Aires Stock Exchange’s Arbitration Court seeking to challenge the price and tender offer for the merger through absorption of Petrobras Argentina S.A. into Pampa Energía S.A. for a nominal amount of $ 148 million. The complaints have been joined. The Court issued a partial award upholding the challenge under the capital markets law used by the plaintiff to dispute the exchange ratio used in the merger and dismissed the Company’s position, which stated that the proper course of action would be to challenge the shareholders’ meeting pursuant to the Business Organizations Law. The Company filed an appeal against this partial award and filed a motion for appeal and nullity which will be resolved by the Chamber of Appeals in Commercial Matters.

-        Fees associated with the injunction granted in favor of Oil Combustibles: Oil Combustibles’ attorneys claimed an increase in their fees assessed by the first-instance judge and ratified by the Chamber of Appeals of Rosario. The Supreme Court of Santa Fe resolved to annul the Camber’s decision and ordered that a new judgment should be passed. A motion for clarification was filed against this judgment before the Supreme Court of Justice, as well as an extraordinary appeal before the CSJN. A settlement was reached and all pending motions were dismissed.

-        Consumidores Financieros Asociación Civil para su Defensa, claimes Edenor: i) the reimbursement of the VAT percentage paid on the illegally “widened” taxable basis due to the incorporation of the National Electrical Energy Fund that distribution companies, the defendants, had not paid this tax when CAMMESA invoiced them the electricity purchased for distribution purposes, ii) the reimbursement of part of the administrative surcharge on “second due date”, in those cases in which payment was made within the time period authorized for such second deadline (14 days) but without distinguishing the effective day of payment, and iii) the application of the “borrowing rate” in case of customer delay in complying with payment obligation, in accordance with the provisions of Law No. 26,361. The Federal Government, the AFIP and the ENRE are summoned as third-party defendants. These proceedings have been joined to those mentioned below. Without prejudice thereto, in the framework of the record of the proceedings, the case has been brought to trial.

-        Asociación de Defensa de derechos de clientes y consumidores (ADDUC) requested that the Company be ordered by the Court to reduce or mitigate the default or late payment interest rates charged to customers who pay their bills after the first due date, inasmuch as they violate section 31 of Law N° 24,240, ordering both the non-application of pacts or accords that stipulate the interest rates that are being applied to the users of electricity –their unconstitutional nature– as well as the reimbursement of interest amounts illegally collected from the customers of the service from August 15, 2008 through the date on which the defendant complies with the order to reduce interest. It is also requested that the VAT and any other taxes charged on the portion of the surcharge illegally collected be reimbursed. These proceedings have been joined to those mentioned above and have been brought to trial. Prior to requesting that evidence be produced, it was ordered that the records be sent to the Tax Representative, in order for the latter to pronounce on the motion to dismiss for lack of standing to sue filed by Edenor. Once the records were sent back to the court hearing the case, the aforementioned motion was rejected. The Company appealed against the rejection of the motion in a timely manner.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2019 where the related inflows of economic benefits are estimated to be probable by the Company.

15.5 Administrative claims

-        CTLL filed a contentious administrative complaint against the National Government for contractual breach during the January 2016-July 2017 period. CTLL claims that CAMMESA’s decision should be reversed regarding the renewal and recognition of costs associated with natural gas supply agreements, and that, susbsidiarily, sustained damages for an estimated amount of U$S 26.6 million should be redressed. Later, the complaint was expanded to include the contractual breach as of October 2018, for an estimated amount of U$S 22.1 million. As of the date hereof the total claimed amounts to U$S 48.7 million.

-        Upon the determination of the expiration of the Veta Escondida area concession granted by the Province of Neuquén, the Company filed a declaratory judgment action to achieve certainty under the original jurisdiction of the Federal Supreme Court of Justice pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. Both parties agreed to suspend the proceeding and settle a solution. Negotiations are currently in progress, and terms have been suspended for 20-day periods renewable until settling the conflict.

15.6 Civil and commercial claims

-        Edenor seeks to obtain the judicial annulment of the ENRE’s Resolution 32/11 that provided Edenor to: i) be fined in the amount of $ 750 thousands due to its failure to comply with the obligations arising from Section 25, sub-sections a, f and g, of the Concession Agreement and Section 27 of Law No. 24,065, ii) be fined in the amount of $ 375 thousands due to its failure to comply with the obligations arising from Section 25 of the Concession Agreement and ENRE Resolution No. 905/99 and iii) be ordered to pay customers as compensation for the power cuts suffered the following amounts: $ 180 to each small-demand residential customer (T1R) who suffered power cuts that lasted more than 12 continuous hours, $ 350 to those who suffered power cuts that lasted more than 24 continuous hours, and $ 450 to those who suffered power cuts that lasted more than 48 continuous hours. The course of these proceedings is currently suspended due to the fact that an “Agreement of parties” has been entered into with the ENRE. In view of the time elapsed since Edenor and the ENRE agreed to suspend the procedural time-limits, the court has requested that the parties express their stance on the issue. Based on the terms of the Agreement on the Regularization of Obligations entered into on May 10, 2019 by and between Edenor and the Federal Government, this action should be abandoned, with each party bearing its own court costs, as agreed in such Agreement. At the closing date of the year ended December 31, 2019, Edenor made a provision for principal and interest accrued for an amount of U$S 1.5 million within the Non-current other liabilities account. Based on that which has been mentioned above, and once the regulatory authority has given its consent, such provision should no longer be recorded.

-        Edenor’s purpose is to sue for breach of contract due to the Federal Government’s failure to perform in accordance with the terms of the “Agreement on the Renegotiation of the Concession Agreement” (“Acta Acuerdo de Renegociación del Contrato de Concesion” – the “Adjustment Agreement”) entered into with the Company in 2006, and for damages caused as a result of such breach. On September 16, 2019, in the framework of the judicial record of the motion to litigate in forma pauperis, Edenor filed a brief regarding the abandonment of the action and waiver of right, requesting at the same time that each party be held liable for its own court costs. The representatives of the Federal Government gave their consent to the terms of the brief. Taking account of the brief, on September 24, the Court terminated the proceedings. Furthermore, in the main proceedings, Edenor, with the Federal Government’s consent, filed a brief, also on September 16, regarding the abandonment of the action and waiver of right, declaring that the concepts dealt with in the proceedings amount to $ 6,900 million; therefore, payment of court fees, which amount to $207 million was incorporated therein. The records were sent to the Tax Authorities for their approval, having attached the breakdown of the amounts comprising the reconciled principal be submitted.

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19. COMPENSATION PLANS

12 Months Ended

Dec. 31, 2019

Compensation Plans

COMPENSATION PLANS

19.1 Company-Value Compensation (Pampa as successor company of PEPASA)

On November 6, 2013, former PEPASA’s Extraordinary General Meeting of Shareholders resolved to approve a variable and contingent compensation to certain officers equivalent to 7% of the capital stock after the former PEPASA’s capital stock increase, valued based on the difference between the share’s market value at the time of exercising the right and a given value of U$S 0.1735 per share determined at the exact moment of the former PEPASA’s capital stock increase.

On January 13, 2014, the former PEPASA’s capital stock increase was carried out and the rights granted to officers to receive the Company-Value Compensation became effective for the equivalent to 8,359,000 shares.

On January 18, 2017, PEPASA's officers requested the monetization of the right for the equivalent to 5.737.000 shares, which was canceled by the Company on January 31, 2017.

Within the framework of the corporate reorganization process described in Note 5.1.1.1, Pampa, as the absorbing company, is the universal successor of all the rights and obligations of the absorbed companies, including PEPASA.

Therefore, as a consequence of the application of the exchange ratio of 2.2699 Pampa shares for each PEPASA share pursuant the merger, the officers who, by virtue of the agreement, had the option of monetizing their right over 2,985,000 PEPASA’ shares, have a post-merger option to monetize its right over a total of 6,775,652 Pampa’s shares at a U$S 0.0764 per share price.

On October 7, 2019, the officers agreed to terminate the aforementioned monetization option and as a result, the Company paid on October 11, 2019 a cash amount equivalent to the quoted value of such shares.  

19.2 Stock-based Compensation Plan – Certain officers and other key staff (the “Compensation Plan”)

On February 8, 2017, the Company’s Board of Directors approved the creation of a stock-based compensation plan and the first Specific Program, whereby certain officers and other key staff covered by each Specific Program will receive a certain number of company shares within the stipulated term aiming to encourage the alignment of the employees performance with the Company’s strategy and to generate a clear and direct link between the creation of value for shareholders and the employees’ compensation.

Furthermore, the Company’s Board of Directors approved the acquisition of own shares in the market as a means of implementing the Plan (see Note 13.1.1.3).

On April 7, 2017, the Company's Shareholders’ Meeting ratified the approval of the Compensation Plan by the Board of Directors, as well as its terms and conditions; and approved the cancellation of the preferential offer to shareholders in respect to the disposition of such shares as authorized by Section 67 of Capital Markets' Act No. 26,831 for the purposes of implementing such Plan.

The number of shares is calculated based on 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, provided the employment relationship continues at least as at each vesting date.

As of December 31, 2019, the Company has estimated a total quantity of 2,082,165 treasury shares pursuant to Compensation Plan to be delivered to employees 661,802, 668,626, 481,450 and 270,287 during 2020, 2021, 2022 and 2023, respectively.

As of December 31, 2019, the Company has acquired 717,750 treasury shares and 191,290 treasury ADRs, 290,363 and 173,891 of which were destined to officers’ compensation during 2019 and 2018, respectively.

19.3 Compensation agreements - Senior Management

On June 2, 2017, the Board of Directors approved the execution and signing of compensation agreements with the Company’s main officers (the “Senior Management”), conditional upon their approval by the Annual Ordinary Meeting of Shareholders to be held each year.

In accordance with international practices, the purpose of these agreements is to efficiently align the Senior Management’s interests with those of the Company and its shareholders, creating value for them only inasmuch as value is generated for shareholders, that is, if the Company’s market value increases.

Under these agreements, the Senior Management will be entitled to a fixed compensation and an annual, variable and contingent long-term compensation related to the Company’s annual market value appreciation, with a cap on the Company’s operating income.

With the purpose of avoiding duplication, any analogous compensation that the Senior Management had received from any of the Company’s subsidiaries, will be deducted from the compensation amount in proportion to the Company’s interests in such subsidiaries.

19.4 Share-based Compensation Plan of Edenor

In 2016, Edenor’s Board of Directors proposed that the treasury shares be used for the implementation of a long-term incentive plan in favor of executive directors, managers or other personnel holding key executive positions in Edenor in an employment relationship with the latter and those who in the future are invited to participate, in accordance with the provisions of section 67 of Law No. 26,831 on Capital Markets. The plan was ratified and approved by the ordinary and extraordinary shareholders’ meeting held on April 18, 2017.

The fair value of the previously referred to shares at the award date, amounted to $ 75.9 million and has been recorded in the Salaries and social security taxes line item, with a contra account in Equity. The amount recorded in Equity is net of the tax effect.

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23. SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2019

Subsequent Events

SUBSEQUENT EVENTS

23.1 New Remuneration scheme at the Spot market for the generation segment

On February 27, 2020, SE Resolution No. 31/20 was published in the Official Gazette, superseding the remuneration scheme established by SRRYME Resolution No. 1/19.

The new scheme reduces prices ​​of the remuneration for available power capacity, and furthermore transfers the remuneration prices ​​to Argentine pesos by applying a 60 $/U$S exchange rate. However, it establishes that prices will be monthly updated through a factor contemplating a 60% adjustment by IPC and a 40% adjustment by IPIM.

Furthermore, it establishes an additional remuneration for the power generated in those hours of maximum thermal requirement of the month. In the case of thermal generators, the average generated power will be considered, and in the case of hydroelectric generators, the average operated power will be considered.

Finally, it maintains prices of the remuneration for generated and operated energy.

Resolution SE No. 31/20 amendments with an impact on the Company's remuneration scheme are detailed below:

23.1.1 Remuneration for Available Power Capacity

23.1.1.1 Thermal Power Generators

The Resolution maintains in effect a remuneration made up of a minimum or base power capacity payment for generators with no availability commitments, and another for offered guaranteed power capacity.

Prices of 360 thousand and 270 thousand $/MW-month were established as remuneration for guaranteed power capacity for the summer-winter and autumn-spring periods, respectively, implying a 14% and 18% decreases for the summer-winter and autumn-spring periods, respectively for enabled generators, except for Internal Combustion Engines with capacity less than or equal to 42 MW, for which prices were established at 420 thousand and 330 thousand $/MW-month for the summer-winter and autumn-spring periods, respectively.

On the other hand, it establishes an additional remuneration for power generated in the hours of high thermal requirement of the month (hmrt), which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, with prices of 45 thousand and 22.5 thousand $/MW-hmrt for the first and second 25 hmrt block, respectively for the summer-winter periods and 7.5 thousand $/MW-hmrt only for the first 25 hmrt block for the autumn-spring periods.

Like SRRYME Resolution No. 1/19, Resolution SE No. 31/20, applies a coefficient derived from the unit’s average utilization factor during the last twelve months to the power capacity remuneration. Although it maintains the formula Resolution SRRYME 1/19 scheme, in case if the usage factor is lower than 30%, it establishes a 60% of the power capacity payment will be collected, except for Internal Combustion Engines with capacity less than or equal to 42 MW, that will collect 70% of the power capacity payment.

23.1.1.2 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 at all hours within the period is considered to calculate availability.

The base remuneration is determined by the actual power capacity plus that under programmed and/or agreed maintenance, with prices ranging from 132,000 to 297,000 $/MW-month, depending on the scale and type of power plant, that considering the elimination of the additional remuneration set by SRRYME Resolution No. 1/19, implied a 45% and 12% decrease for conventional and pumping hydroelectric power plants, respectively. It should be noted that, in order to mitigate the incidence of plants’ programmed maintenance, and as a signal for their optimization, a 1.05 factor will be applied to power capacity prices.

In case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor will be applied to the plant at the headwaters.

On the other hand, it establishes an additional remuneration for power operated in the hours of high thermal requirement of the month, with a price of 32.5 thousand $/MW-hmrt applying a 1.2 and 0.6 factor for the first and second 25 hmrt block, respectively, for the summer-winter periods and 0.2 factor only for the first 25 hmrt block for the autumn-spring periods.

23.1.1.3 Wind power

No remuneration related to power capacity availability is set, establishing a single remuneration value for generated energy (see next item).

23.1.2 Remuneration for Generated and Operated Energy

It establishes a remuneration for Generated Energy with prices ranging between 240 and 420 $/MWh, depending on the type of fuel and a remuneration for Operated Energy applicable to the integration of hourly power capacities for the period, with an 84 $/MWh price for any type of fuel, thus maintaining prices established by SRRYME Resolution No. 1/19.

It should be noted that, in the event that the generation unit is dispatched outside the optimal dispatch, remuneration for generated energy will be set at 60% of the net installed power capacity, regardless of the energy delivered by the generation unit.

In the case of hydroelectric plants, prices for Energy Generated and Operated under Resolution SE No. 31/20 are remunerated at 210 $/MWh and 84 $/ MWh, respectively, maintaining prices ​​established by SRRYME Resolution No. 1/19. The remuneration for operated energy must correspond to the optimal dispatch of the system, however, the resolution does not indicate what the consequence would be otherwise.

In the case of hydroelectric pumping plants, both the energy generated and the one consumed for pumping, by the energy pumped, and the energy operated are considered. In addition, if it functions as a synchronous compensator, 60 $/MVAr will be recognized for the megavolt exchanged with the network when required and 84 $/MWh for the energy operated.

As regards energy generated from unconventional sources, Resolution SE No. 31/20 establishes a single remuneration value of 1,680 $/MWh, irrespective of the source used, maintaining the value established by SRRYME Resolution No. 1/19. Energy generated prior to the commissioning by the OED will be remunerated at 50% of the above-mentioned remuneration.

23.2 Buyback of own shares

After the closing of the year, the Company acquired the equivalent of 52,241,300 own shares for an approximate value of U$S 27 million corresponding to the Buyback Program mentioned in Note 13.1.1.2.

23.3 Stock-based compensation plan

During January 2020, the Company delivered the equivalent of 163,466 own shares as payment under the stock-based compensation plan to officers and other key staff.

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13. EQUITY COMPONENTS

12 Months Ended

Dec. 31, 2019

Equity Components

EQUITY COMPONENTS

13.1 Share capital and reserves

13.1.1 Share capital

On October 2, 2018, the Company’s Extraordinary General Meeting of Shareholders approved a capital reduction through the cancellation of 182,820,250 treasury shares it held as a result of the Share Repurchase Programs, the Company’s capital stock thus decreasing from 2,082,690,514 shares to 1,899,870,264 shares (1,874,434,580 of which are outstanding shares and 25,435,684 treasury shares). This reduction was registered with the IGJ on November 22, 2018. Furthermore, on January 9, 2019, the CNV granted the partial cancellation of the public offering regarding the reduced shares.

On October 1, 2019, the Company’s Extraordinary General Meeting of Shareholders resolved to reduce the capital stock through the cancellation of own shares held in treasury as of the last business day prior to the holding of the meeting which had been acquired under the Share Repurchase Programs dated June 22, 2018, and March 27 and August 12, 2019. In this sense, the capital stock was reduced through the cancellation of 151,997,025 treasury shares, the capital stock thus decreasing from 1,899,870,264 shares to 1,747,873,239 shares. This reduction was registered with the IGJ on November 20, 2019, the partial cancellation by the CNV of the public offering regarding the reduced shares still pending as of December 31, 2019.

As of December 31, 2019, treasury shares amount to 4.05% of the capital stock, of which 65,725,450 shares correspond to the Share Repurchase Program and 5,035,746, to the Stock-based Compensation Plan for officers and other key staff.

13.1.1.1 Publicly traded shares

The Company’s shares are listed for trading on Buenos Aires Stock Exchange, forming part of the Merval Index. Also, on August 5, 2009, the SEC authorized the Company for the registration of ADSs representing 25 common shares each. On October 9, 2009, the Company started to market its ADSs on the NYSE.

The listing of the ADSs with the NYSE is part of the Company’s strategic plan to increase its liquidity and the tradable volume of its shares.

13.1.1.2 Company Share Repurchase Programs

In view of the fact that the Company’s share price does not reflect either the value or the economic reality its assets currently or potentially have, this being detrimental to the interests of the Company’s shareholders, and taking into consideration the Company’s strong cash position and fund availability, the Company’s Board of Directors has approved the share repurchase programs that are detailed below, in all cases taking into consideration that treasury shares may not cumulatively exceed the 10% of the share capital:

1.	April 27, 2018 Share repurchase program: for a maximum amount of U$S 200 million and for an initial term of 120 calendar days; extended on June 22, 2018 for an additional maximum amount of up to U$S 200 million for an initial term of 120 calendar days. Shares may be purchased for a maximum price of the amount, in Argentine pesos, equivalent to U$S 2.40 per common share and U$S 60 per ADR, for the initial program, and U$S 2.20 per common share and U$S 55 per ADR for the extension.
2.	March 27, 2019 Share repurchase program: for a maximum amount of U$S 100 million and for an initial term of 120 calendar days. Shares may be purchased for a maximum price of the amount, in Argentine pesos, equivalent to U$S 1.04 per common share and of U$S 26 per ADR. On June 12, 2019, this program was suspended as the listing of the Company’s shares and ADRs had reached values exceeding the repurchase cap set.
3.	August 12, 2019 Share repurchase program: for a maximum amount of U$S 50 million and for an initial term of 120 calendar days. Shares may be acquired up to a maximum price of the equivalent in pesos of U$S 1 per common share and U$S 25 per ADR. The maximum amount was extended to U$S 65 million on August 30, 2019.
4.	November 8, 2019 Share repurchase program: for a maximum amount of U$S 50 million and for an initial term of 120 calendar days. Shares may be acquired up to a maximum price of the equivalent in pesos of U$S 0.58 per common share and U$S 14.50 per ADR.

As part of the Share Repurchase Program, during fiscal years ended December 31, 2019 and 2018, the Company acquired the equivalent of 197,612,900 and 202,929,825 own shares for an amount of $ 7,070 million and $ 12,275 million, respectively.

13.1.1.3 Stock-based Compensation Plan

During the fiscal years ended December 31, 2018 and 2017, the Company repurchased 3,000,000 and 2,500,000 shares, respectively, corresponding to the Stock-based Compensation Plan benefiting officers and other key staff for an amount of $ 260 million and $ 126 million, respectively. As of December 31, 2019, the Company delivered the equivalent of 464,254 own shares as payments under this plan (see Note 19.2).

13.1.2 Other reserves

13.1.2.1 Acquisition of own ADRs by Edenor

On April 8, 2019, Edenor’s Board of Directors approved a new Share Repurchase Program for a maximum amount of $ 800 million and an initial term of 120 calendar days as from April 9, 2019. Under this program, treasury shares may not together exceed the 10% of the capital stock cap, and may be acquired up to a maximum price of the equivalent in pesos of U$S 23 per ADR or the amount in pesos equivalent to U$S 1.15 per common share.

In its meeting held on June 12, 2019, Edenor’s Board of Directors resolved to early terminate the term timely stipulated for the acquisition of own shares.

As of December 31, 2019, Edenor holds 31,380,871 Series B treasury shares, of which 8,269,740 have been acquired in this fiscal year, for a total amount of $ 599 million restated at constant currency.

13.1.2.2 Acquisition of Edenor’s ADRs by the Company

During the fiscal years ended December 31, 2019 and 2018, the Company acquired a total number of 1,179,491 and 346,270 Edenor’s ADRs, each one equivalent to 20 Series B common shares, at an acquisition cost of U$S 6 million and U$S 9 million, respectively.

13.2           Earnings per share

13.2.1 Basic

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.

13.2.2 Diluted

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, 2019, 2018 and 2017, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

	12.31.2019	12.31.2018	12.31.2017
Earning for continuing operations attributable to the equity holders of the Company	692	146	341
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings per share from continuing operations	14.42	2.81	6.69
Earning (loss) for discontinued operations attributable to the equity holders of the Company	-	78	(55)
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings (loss) per share from discontinued operations	-	1.50	(1.07)
Total earning attributable to the equity holders of the Company	692	224	286
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings  per share	14.42	4.31	5.61

13.3 profit distributions

13.3.1 Dividends

Pursuant to Law No. 27,430, enacted in December 2017, and the suspension provided for by Law No. 27,541 (Note 2.6.1.2), dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or after January 1, 2018 through December 31, 2021, are subject to a 7% withholding tax. The distribution of dividends is made based on the Company’s Stand-Alone Financial Statements.

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5. GROUP STRUCTURE

12 Months Ended

Dec. 31, 2019

Group Structure

GROUP STRUCTURE

5.1. Business combinations

5.1.1 Corporate reorganization

The corporate reorganizations mentioned below are carried out in order to obtain important benefits for the Company and all its corporate group, as they will allow for enhanced operating efficiency; an optimized use of available resources; the leveraging of technical, administrative and financial structures; and the implementation of converging policies, strategies and goals. Furthermore, the complementarity between the participating companies could be leveraged, thus reducing costs resulting from the duplication and overlapping of operating and administrative structures.

The following reorganizations were perfected by means of a merger through absorption process, under the terms of tax neutrality pursuant to articles 80 and following of the Income Tax Law, whereby the absorbed companies will be dissolved without liquidation subject to the stipulations of the PMC and the provisions of sections 82 to 87 of Argentine Commercial Companies General Law, the CNV provisions, the BCBA Listing Rules and other provisions, the IGJ provisions and all other applicable legal and regulatory provisions.

5.1.1.1 2017 Reorganization

On September 22, 2017, the Company’s Board of Directors informed that the companies which would take part in the merger would be the Company, as absorbing company, and BLL, CTG, CTLL, EG3 Red, INDISA, INNISA, IPB, PP II and PEPASA, as absorbed companies.

The merger became effective on October 1, 2017, date as from which the transfer of the absorbed companies’ equity to the absorbing company became effective and, therefore, all their rights and obligations, assets and liabilities will become incorporated into the absorbing company’s equity, all of which subject to the corresponding corporate approvals under the applicable law and the registration with the Public Registry of Commerce of the merger and the dissolution without liquidation of the absorbed companies.

On December 21, 2017, the Board of Directors of Pampa Energía, as absorbing company and BLL, CTG, CTLL, EG3 Red, INDISA, INNISA, IPB, PP II and PEPASA, as absorbed companies, approved the Previous Fusion Commitment, and on April 27, 2018, the Extraordinary General Meetings of Shareholders approved the merger in agreement with the terms of the Previous Fusion Commitment.

On June 1, 2018, the final merger agreement was entered into between Pampa and the absorbed companies and was filed for registration before the applicable controlling authorities. On July 20, 2018 the CNV’s authorization on merger publication was obtained and on August 2, 2018, the Public Registry registered the merger. On August 15, 2018, the exchange of PEPASA, CTG, INNISA and INDISA shares for 144,322,083 of the Company was effected, with 1,880 shares remaining as treasury shares since they were fractional or decimal shares which were paid in cash. As of December 31, 2018, in accordance with current regulations, the Company proceeded to sell those shares. There was no exchange ratio for the remaining companies, as Pampa direct and indirect held 100% of the capital stock of these companies.

5.1.1.2 PAMPA – PEFM merger

On August 30, 2019, the Company and PEFM’s respective Boards of Directors approved the merger through absorption between the Company, as absorbing company, and PEFM, as absorbed company, establishing July 1, 2019 as the merger's effective date, as from which all PEFM’s rights and obligations, assets and liabilities were incorporated into the Company’s equity. There was no exchange ratio as the Company directly and indirectly held 100% of PEFM’s capital stock.

On October 15, 2019, the Company and PEFM’s respective Shareholders’ Meetings approved the merger process. On February 19, 2020, the CNV’s authorization on merger publication was obtained, its registration with the Public Registry remains pending.

5.1.1.3 PAMPA – CPB merger

On October 8, 2019, the Company’s Board of Directors instructed to move forward with the tasks allowing to assess the benefits of a merger through absorption process between the Company, as absorbing company, and CPB, as absorbed company, establishing January 1, 2020 as the merger's effective date.

5.1.2 Sale of participations and plant

5.1.2.1 Sale of interest in Greenwind

With the purpose of incorporating into the project a strategic partner contributing part of the investments necessary for the development of the Mario Cebreiro Wind Farm, on March 10, 2017, CTLL and PP entered into an agreement with Valdatana Servicios y Gestiones S.L.U., an entity which later changed its name to Viento Solutions S.L. for the sale of 50% of Greenwind’s capital stock and rights for a total amount of U$S 11.2 million.

5.1.2.2 Sale of interest in Oldelval

On November 2, 2018, the Company entered into an agreement with ExxonMobil Exploration Argentina S.R.L. for the sale of 21% of Oldelval’s capital stock and rights, maintaining the remaining 2.1% interest.

Subsequently, on November 27, 2018, the transaction was closed upon the meeting of the applicable precedent conditions, the purchase price paid by the purchaser amounted to U$S 36.4 million. As a result of the transaction, the Company has recognized a U$S 28 million gain, before taxes.

5.1.2.3     Sale of the Dock Sud storage terminal

On March 6, 2019, the Company agreed with Raízen Argentina, a licensee of the Shell brand, on the sale, subject to the meeting of certain conditions precedent which are customary for this kind of transactions, of the Dock Sud storage terminal, which tank yard has a total installed capacity of 228 thousand m3.

On March 30, 2019, after the meeting of all precedent conditions, the transfer of the Dock Sud Terminal to the purchaser was completed at a price of U$S 19.5 million, plus U$S 2 million on account of products. The transaction resulted in profits before income tax in the amount of U$S 1 million, which are disclosed in item “Gains/losses on the sale of Property, plant and equipment” under “Other operating income”.

5.2 Discontinued operations

As of December 31, 2018 and 2017, the results of operations related to divestment transactions detailed below, have been disclosed within “Discontinued Operations” in the consolidated statement of comprehensive income.

5.2.1 Sale of PELSA shares and certain oil areas

On January 16, 2018, the Company agreed to sell to Vista Oil & Gas S.A.B. de C.V. (“Vista”) its direct 58.88% interest in PELSA and its direct interests in the Entre Lomas, Bajada del Palo, Agua Amarga and Medanito-Jagüel de los Machos blocks, in line with the Company's strategy to focus its investments and human resources both on the expansion of its power generation installed capacity and on the exploration and production of natural gas, placing a special focus on the development and exploitation of unconventional gas reserves, as well as to continue investing on the development of its utility concessions.

On April 4, 2018, upon the meeting of all applicable conditions precedent, the transaction was closed. The price paid by Vista, considering the agreed adjustments regarding interests in PELSA, amounted to U$S 389 million. This transaction generated a profit comprehensive income net of taxes in the amount of U$S 30 million, as follows:

	12.31.2018
Sale price (2)	270
Book value of assets sold and costs associated with the transaction	(226)
Result for sale	44
Interests (1)	4
Income tax	(22)
Imputed in results	26
Other comprehensive income (loss)
Reclasification exchange differences on translation	6
Income tax	(2)
Imputed in Other comprehensive income	4
Total comprehensive income	30

(1)	Are exposed in "Financial income" in the consolidated statement of comprehensive income related to discontinued operations.
(2)	Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

5.2.2 Sale of assets in the Refining and Distribution segment

On December 7, 2017, the Company executed with Trafigura Ventures B.V and Trafigura Argentina S.A. an agreement for the sale of certain assets in the Company’s refining and distribution segment based on the conviction that the oil refining and distribution business calls for a larger scale to attain sustainability.

The assets subject-matter of the transaction were: (i) the Ricardo Eliçabe refinery; (ii) the Avellaneda lubricants plant; (iii) the Caleta Paula reception and dispatch plant; and (iv) the network of gas stations currently operated under Petrobras branding. The Dock Sud storage facility was excluded from the sale, as well as the Company's investment in Refinería del Norte S.A.

Pursuant to the foregoing, and in relation with the measurement of the assets and liabilities subject to this transaction at the lower of fair value less cost to sell and the carrying value, as of December 31, 2017, the Company recognized an impairment of Intangible assets and Property, plant and equipment in the amount of U$S 28 million.

On May 9, 2018, upon the meeting of all applicable precedent conditions the transaction was subject to, the closing of the sale to Trafigura was carried out. After applying the adjustments stipulated in the purchase and sale agreement, the transaction price amounted to U$S 124.5 million. Furthermore, after the closing of the transaction, Trafigura paid to Pampa U$S 56 million for the purchase of crude oil.

As of December 31, 2018, the closing of the transaction did not generate additional profits or losses, according to the following detail:

	12.31.2018
Sale price (1)	28
Book value of assets sold and costs associated with the transaction	(28)
Result for sale	-

⁽¹⁾ Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

The Company considers that under IFRS it has transferred control over the whole assets since, pursuant to the participation agreements entered into with Trafigura, it has not retained the power to redirect their use or substantially derive other benefits. However, as of the issuance of these Consolidated Financial Statements the process for the legal transfer and actual assignment of the agreements associated with three gas stations has started with the rebranding of to the “Puma” brand, owned by Trafigura, this process is expected to end during the first semester of 2020.

5.2.3 Relevant information on discontinued operations

As of December 31, 2018:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	66	422	(90)	398
Cost of sales	(33)	(361)	91	(303)
Gross profit	33	61	1	95
Selling expenses	(2)	(33)	-	(35)
Administrative expenses	(1)	(4)	-	(5)
Other operating income	1	6	-	7
Other operating expenses	(6)	(10)	-	(16)
Result from the sale of share of profit and property, plant and equipment	44	-	-	44
Operating income	69	20	1	90
Gain on monetary position, net	7	2	(1)	8
Finance income	4	1	-	5
Finance costs	(1)	-	-	(1)
Other financial results	(4)	22	-	18
Financial results, net	6	25	(1)	30
Income before income tax	75	45	-	120
Income tax	(26)	(14)	-	(40)
Profit  of the year from discontinued operations	49	31	-	80
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	(2)	-	-	(2)
Reclasification exchange differences on translation	6	-	-	6
Exchange differences on translation	4	-	-	4
Other comprehensive income of the year from discontinued operations	8	-	-	8
Total comprehensive income  of the year from discontinued operations	57	31	-	88
	Oil and gas	Refining and distribution	Eliminations	Total
Total income of the year from discontinued operations attributable to:
Owners of the company	47	31	-	78
Non - controlling interest	2	-	-	2
	49	31	-	80
Total comprehensive income of the year from discontinued operations attributable to:
Owners of the company	53	31	-	84
Non - controlling interest	4	-	-	4
	57	31	-	88

As of December 31, 2017:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	259	728	(296)	691
Cost of sales	(251)	(618)	297	(572)
Gross profit	8	110	1	119
Selling expenses	(8)	(82)	-	(90)
Administrative expenses	(6)	(19)	-	(25)
Exploration expenses	(1)	-	-	(1)
Other operating income	16	10	-	26
Other operating expenses	(8)	(13)	-	(21)
Result from the sale of  property, plant and equipment	-	(28)	-	(28)
Operating income (loss)	1	(22)	1	(20)
Financial income	1	1	-	2
Financial expenses	-	(1)	-	(1)
Other financial results	(10)	(1)	-	(11)
Financial results, net	(9)	(1)	-	(10)
Income (loss) before income tax	(8)	(23)	1	(30)
Income tax	(28)	8	-	(20)
Profit (loss) of the year from discontinued operations	(36)	(15)	1	(50)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	2	-	-	2
Exchange differences on translation	(16)	-	-	(16)
Other comprehensive loss of the year from discontinued operations	(14)	-	-	(14)
Total comprehensive income (loss) of the year from discontinued operations	(50)	(15)	1	(64)
	Oil and gas	Refining and distribution	Eliminations	Total
Total income (loss) of the year from discontinued operations attributable to:
Owners of the company	(41)	(15)	1	(55)
Non - controlling interest	5	-	-	5
	(36)	(15)	1	(50)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company	(48)	(15)	1	(62)
Non - controlling interest	(2)	-	-	(2)
	(50)	(15)	1	(64)

The consolidated statement of cash flows related to discontinued operations is presented below:

	12.31.2018	12.31.2017
Net cash (used in) generated by operating activities	(46)	87
Net cash used in investing activities	-	(50)
Net cash generated by (used in) financing activities	42	(31)
(Decrease) increase in cash and cash equivalents from discontinued operations	(4)	6
Cash and cash equivalents at the begining of the year	6	4
Loss on net monetary position generated by cash and cash equivalents	(2)	(4)
(Decrease) increase in cash and cash equivalents	(4)	6
Cash and cash equivalents at the end of the year	-	6

5.3.  Interest in subsidiaries, associates and joint ventures

5.3.1 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.
 

			12.31.2019	12.31.2018
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Corod	Argentina	Oil	100.00%	100.00%
CPB	Argentina	Generation	100.00%	100.00%
CPB Energía S.A.	Argentina	Generation	100.00%	100.00%
EcuadorTLC	Ecuador	Oil	100.00%	100.00%
Edenor (1)(7)	Argentina	Distribution of energy	56.32%	52.18%
Enecor S.A.	Argentina	Transportation of electricity	69.99%	69.99%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
PACOSA	Argentina	Trader	100.00%	100.00%
PEA (2)	Argentina	Generation	-	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PACOGEN	Argentina	Investment	100.00%	100.00%
PEFM (3)	Argentina	Generation	-	100.00%
Petrobras Energía Colombia Gran Cayman (4)	Colombia	Oil	-	100.00%
Petrobras Energía Ecuador	Gran Cayman	Investment	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
PHA (5)	Argentina	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
PP	Argentina	Investment	100.00%	100.00%
PPSL (6)	Spain	Investment	-	100.00%
TGU	Uruguay	Gas transportation	100.00%	100.00%
Transelec	Argentina	Investment	100.00%	100.00%
Trenerec Energía Bolivia S.A.	Bolivia	Investment	100.00%	100.00%
Trenerec S.A.	Ecuador	Investment	100.00%	100.00%

(1)	Corresponds to effective interest considering the treasury shares in Edenor´s effect (54.3664% nominal interest)
(2)	On May 29, 2019, PEA’s Shareholders’ Meetings resolved to change its corporate name to CTB. In the month of June 2019, the Company sold to PACOGEN and YPF 48% and 50%, respectively, of its interest in CTB, whereas PP sold to PACOGEN 2% of its interest in CTB.
(3)	See Note 5.1.1.2.
(4)	Liquidated in January 2019.
(5)	On March 28, 2019, the Company approved PHA’s international address change from Madrid (Spain), to the Autonomous City of Buenos Aires (Republic of Argentina), and on September 20, 2019, the change of jurisdiction was registered with the Public Registry.
(6)	Liquidated in December 2019.
(7)	As of December 31, 2019, the quotation of Edenor's ordinary shares and ADR published on the BCBA and the NYSE was $ 24.05 and U$S 6.26 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 149 million. It should be noted that, as of December 31, 2019, participation in Edenor does not exceed its recoverable value.

5.3.1.1 Summarised financial information for each subsidiary that has significant non-controlling interest

Non-controlling interests in subsidiaries are not significant for the Company, except for Edenor with 54.3664% equity interest.

Edenor is registered in Argentina, which is also the place where it develops its activities.

5.3.1.1.1 Edenor’s Summary statement of financial position
 

	12.31.2019	12.31.2018
Non Current
Total non current assets	1,696	1,679
Borrowings	137	191
Other non current liabilities	460	474
Total non current liabities	597	665
Current
Cash and cash equivalents	7	1
Other current assets	292	363
Total current assets	299	364
Borrowings	28	29
Other current liabilities	383	528
Total current liabilities	411	557
Total equity	988	821
Non-controlling interest	451	396

5.3.1.1.2 Edenor’s Summary statement of comprehensive income

	12.31.2019	12.31.2018	12.31.2017
Revenue	1,502	1,484	1,050
Depreciation	(77)	(68)	(57)
Interest income	20	18	12
Interest expense	(113)	(132)	(68)
Profit for the year before tax	381	164	148
Income tax	(178)	(50)	(14)
Profit for the year	203	114	134
Other comprehensive loss	-	(1)	-
Total comprehensive profit of the year	203	113	134
Income of the year attributable to non-controlling interest	98	55	65
Other comprehensive income of the year attributable to non-controlling interest	-	(1)	-
Comprehensive income of the year attributable to non-controlling interest	98	54	65

5.3.1.1.3 Edenor’s Summary statement of cash flow

	12.31.2019	12.31.2018	12.31.2017
Net cash generated by operating activities	170	255	78
Net cash used in investing activities	(86)	(221)	(63)
Net cash used in financing activities	(85)	(56)	(13)
(Decrease) increase  in cash and cash equivalents	(1)	(22)	2
Cash and cash equivalents at the begining of the year	1	3	3
Loss on net monetary position generated by cash and cash equivalents	7	19	2
Cash and cash equivalents at the end of the year	7	-	7

5.3.2  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 period / year	Equity	Direct and indirect participation %
Associates
Refinor	Refinery	09.30.2019	2	(3)	57	28.50%
OCP (1)	Investment	12.31.2019	100	22	266	15.91%
TGS (2)(5)	Transport of gas	12.31.2019	13	214	803	27.193%
Joint ventures
CIESA (2)	Investment	12.31.2019	11	109	405	50.00%
Citelec (3)	Investment	12.31.2019	9	38	176	50.00%
Greenwind	Generation	12.31.2019	-	(1)	(11)	50.00%
CTB (4)	Generation	12.31.2019	143	40	227	50.00%

(1)	The Company holds an indirect interest of 15.91% through PEB.
(2)	The Company holds a direct and indirect interest of 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. therefore, the Company has an indirect participation of 25.50% in TGS. The Company holds a direct and indirect interest of 1.693% in TGS.
(3)	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.
(4)	The Company holds an indirect interest of 50% through PACOGEN.
(5)	As of December 31, 2019, the quotation of TGS's ordinary shares and ADR published on the BCBA and the NYSE was $ 108.65 and U$S 7.17 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 306 million.

The details of the balances of investments in associates and joint ventures are as follows:

	12.31.2019	12.31.2018
Disclosed in non-current assets
Associates
Refinor	20	25
OCP	33	35
TGS	21	-
	74	60
Joint ventures
CIESA	235	259
Citelec	88	88
CTB	114	-
	437	347
	511	407
Disclosed in non-current liabilities
Greenwind (1)	4	4
	4	4

⁽¹⁾    The Company provides financial assistance to this company.

The following tables show the breakdown of the result from investments in associates and joint ventures:

	12.31.2019	12.31.2018	12.31.2017
Associates
Oldelval	-	3	1
Refinor	(3)	(4)	(3)
OCP	21	35	-
TGS	1	-	-
	19	34	(2)
Joint ventures
CIESA	50	74	25
CTB	13	-	-
Citelec	19	21	27
Greenwind	-	(11)	(2)
	82	84	50

The evolution of investments in associates and joint ventures is as follows:

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year		403	315	255
Reclassifications (1)		(16)	-	12
Dividends	17	(75)	(19)	-
Decreases		-	(10)	-
Increases		108	-	-
Share of profit		101	118	48
Other comprehensive loss		-	(1)	-
Exchange differences on translation		(14)	-	-
At the end of the year		507	403	315

⁽¹⁾ In 2019, mainly corresponds to the financial credit with OCP acquired in the transaction with AGIP (see Note 5.3.6.2), and in 2017 corresponds to the deconsolidation for sale of the interest in Greenwind.

5.3.3 Investment in CIESA-TGS

5.3.3.1 Issuance of Corporate Bonds

On May 2, 2018, under the Short and Medium-Term Corporate Bonds Program for a maximum amount of U$S 700 million approved by the CNV, TGS issued Class 2 corporate bonds for U$S 500 million at an annual 6.75% rate. Collected funds will be destined by TGS to: (i) the repurchase of Class 1 corporate bonds, (ii) the redemption of Class 1 corporate bonds; and (iii) capital expenditures.

TGS General Shareholders' Meeting held on August 15, 2019 approved the extension of TGS´s Corporate Bonds Program from U$S 700 million to U$S 1.2 billion. This extension was authorized on October 9, 2019, by the CNV.

5.3.3.2 Acquisition of own shares in TGS

During 2018, TGS’ Board of Directors approved two programs for the repurchase of own shares, on May 9, 2018 and September 6, 2018, which were executed according to the programs established terms. For the definition of these programs, the TGS’ Board of Directors considered TGS’ strong cash position and fund availability, in view of the fact that the TGS’ share price does not reflect either the value or the economic reality its business currently or potentially have.

On March 27, 2019, TGS’ Board of Directors approved a third program for the repurchase of own shares, for a maximum amount of up to $ 1,500 million (in terms of the constitution date).

On August 26, 2019, after terminating the third repurchase program, the TGS’ Board of Directors approved a forth program for the repurchase of own shares for a total amount of $ 3,200 million (in terms of the constitution date).

TGS’s own shares acquired as of October 31, 2019 were distributed as dividend in shares.

Finally, on November 19, 2019, a fifth program for the repurchase of own shares was approved for a total amount of $ 4,000 million (in terms of the constitution date). This program has a 120 days term.

As of December 31, 2019, TGS holds 9,886,755 treasury shares in its portfolio, which represent 1.24% of its total capital stock.

5.3.3.3 Acquisition of TGS’s ADRs by the Company

During the fiscal year ended December 31, 2019, the Company acquired a total number of 1,130,365 TGS’s ADRs, at an acquisition cost of U$S 8 million.

5.3.3.4 Vaca Muerta Project

During 2019, TGS successfully completed the assembly and pressurization works on the facilities of an important project at Vaca Muerta that involves a total investment of approximately U$S 260 million and will materially impact on the development of the Vaca Muerta natural gas reserves.

The project consisted in the construction of a gas collector pipeline that will allow to transport natural gas extracted by natural gas producers to the regulated transport systems operated by TGS and TGN and a gas conditioning plant in Tratayén city.

The Vaca Muerta system have two collector pipelines; the first of them with an extension of 115 kilometers, a 36" diameter and 35 MMm3/d transport capacity (the "Northern Trench") and the second one with an extension of 33 kilometers, 30" diameter and 25 MMm3/d transport capacity (the "South Trench"). The gas transported by these pipelines system will be treated in the new conditioning plant that TGS constructed in Tratayén city, Province of Neuquén with 5.0 MMm3/d of initial capacity.

For the development of this project, the implementation of long-term service agreements with different producers was essential to establish the terms and conditions for the provision of transportation and natural gas conditioning services in order to meet ENERGAS’ regulatory requirements to access to the regulated transport system. In this way, TGS becomes the First Midstreamer of Vaca Muerta.

Additionally, in February 2020, TGS approved an investment project with a 1-year execution estimated period and U$S 15 million estimated investment. The project will consist in the conditioning plant capacity increase by 2.6 MM3/d, the installation of a butane extraction unit and the construction of facilities for the storage and dispatch of liquids.

5.3.4 Investment in CITELEC

5.3.4.1 Employee Shareholding Program – Transba S.A.

In the year 1997, the Executive Branch of the Province of Buenos Aires awarded 100% of Transba’s Series “A”, “B” and “C” shares to Transener. Series “C” shares were awarded subject to the obligation to transfer them to the Employee Shareholding Program benefiting certain Transba employees, Transener holding 89.99% of Transba’s capital stock.

On June 28, 2019, Transener acquired all the shares under such program. Consequently, Transener holds 99.99% of Transba’s capital stock.

5.3.4.2 Repurchase of own Corporate Bonds - Transener

As of December 31, 2019 Transener’s Corporate Bonds Class 2 amounted to U$S 98.5 million, of which U$S 5 million and U$S 2 million have been acquired and by Transba S.A and Transener S.A., respectively.

5.3.5 Investment in CTB

5.3.5.1 Acquisition of CTEB

On May 29, 2019, the Company, after filing a joint offer, received a notification from IEASA whereby PISA, a subsidiary of the Company, through its subsidiary, PACOGEN, and YPF, were awarded National and International Public Tender No. 02/2019, launched pursuant to SGE Resolution No. 160/19, regarding the sale and transfer by IEASA of CTEB. The acquisition of CTEB also involves the assignment in favor of the awardee of the contractual capacity as trustor under the Enarsa-Barragán Financial Trust, the VRDs of which (excluding the VRDs to be acquired by the awardee) amount to U$S 229 million.

CTEB, 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.

The awardee will have to obtain the commissioning of the closing of the combined cycle within a term of 30 months as from the Seventh Amendment to the Trust Agreement’s effective date, thus increasing the installed power capacity to 847 MW, with an estimated investment of U$S 200 million.

Both the open and the closed cycle have effective power purchase agreements with CAMMESA under Resolution No. 220/07 issued by the former SE: the first one, entered into on March 26, 2009 and terminating on April 27, 2022, as amended and modified from time to time, and the second one dated March 26, 2013 for a term of 10 years as from the commercial operation of the combined cycle.

On June 26, 2019, the acquisition by CTB, a company co-controlled by YPF and PACOGEN, of CTEB transferred by IEASA was completed. The acquisition’s relative price was U$S 282 million, an amount which includes the final (cash) amount offered in the Tender and the acquired VRDs’ purchase price, paid with a contribution of U$S 200 million received by CTB, settled in equal parts by its co-controlling companies, and with a loan received by CTB from a bank syndicate of U$S 170 million.

The Power Plant will be managed and operated by Pampa and YPF on a rotational basis over 4-year periods. Pampa will be responsible for managing CTEB’s operations until 2023. And YPF, through its subsidiary YPF Energía Eléctrica S.A., will supervise the necessary works for the closing of the combined cycle.

The following table details the consideration transferred and the fair value of the assets acquired and the liabilities assumed by CTB as of June 26, 2019:

	in million U$S
Total consideration transferred (1)	(272)
Financial assets at fair value	16
Property, plant and equipment	477
Inventories	8
VRDs	(229)
Fair value of net assets	272

⁽¹⁾    Includes U$S 53 million for the purchase of the acquired VRDs and considers a U$S 10 million of a price adjustment in favor of CTB.

The fair value of property, plant and equipment items and inventories was calculated considering mainly the depreciated replacement cost of the acquired goods. For this purpose, CTB was assisted by an independent specialist engaged by management.

The replacement cost approach was applied to measure buildings, equipment, installations and works in progress. The methodology applied to determine their fair value entailed:

i. the calculation of replacement costs (mainly based on consultations with suppliers and the analysis of specialized publications and information),

ii. an estimate of residual values at the end of their useful life (based on the interest generated by the asset at the end of its useful life and the owner’s disposal policy), and

iii. the application of deductions for physical, functional and/or economic impairment, if applicable.

The methodology for the determination of the remaining useful life was focused on the analysis of aging, wear and loss of service capacity of the assets resulting from normal use in the activities where they operate.

Regarding the work in progress for the closing of the combined cycle, which will allow a 280 MW rated power capacity increase, an estimate of the work progress’ percentage and the depreciation of the installed equipment was made based on physical inspections and the information supplied by the contracts to complete civil and electromechanical works for the closing of the combined cycle.

Lastly, a comparative sales approach was used to measure lands and vehicles. For this purpose relevant market data was gathered, mainly sales prices of lands in surrounding areas and published sales prices for vehicles.

Additionally, CTB has calculated the weighted present value of future cash flows it expects to receive from the assets to confirm that its fair value does not exceed their recoverable value.

As a result of the described process, CTB has not recorded intangible assets associated with the business acquisition.

5.3.5.2 Financial Trust Agreement

As a result of CTEB’s award, 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 financial trust, on April 25, 2011, Series B VRDs with public offering for a face value of U$S 582,920,167 were issued. The trust’s underlying flow is made up of the collection rights resulting from the Power Purchase Agreements originally entered into between ENARSA and CAMMESA, where CTB substitutes ENARSA (currently IEASA) as counterparty.

Pursuant to the agreement currently in force, CAMMESA will deposit the amounts required by the Trustee in the trust account, which will be destined to the payment of the Trust’s expenses and taxes, the replenishment of expense, reserve and settlement reserve funds, and the payments of Series B VRDs pursuant to the payment schedule.

On June 26, 2019, CTB entered into a VRDs transfer agreement with IEASA whereby CTB acquired the outstanding Series B VRDs for a price of U$S 53.5 million (equivalent to 109,628,836 Series B VRDs with a face value of U$S 1 each), thus becoming the holder of such VDRs (the “Trustor’s VRDs”).

On August 22, 2019, the seventh amendment to the Trust Agreement was executed, which incorporated several modifications, including the following:

-        as regards the VRDs: i) the granting of a 24-month grace period (during which only interest will be payable); ii) the modification of the interest rate by the Libor rate plus 6.5%; iii) the determination of capital amortization repayments over a 60-month period (to derive constant debt services);

-        the obligation to complete the closing of the combined cycle within a term of 30 months, the breach of this obligation resulting in the acceleration of the VRDs;

-        the incorporation of additional collection rights regarding both the open and the closed-cycle power purchase agreements;

-        establishing that payments to the Trust should be transferred simultaneously, with the same payment priority and in the same kind than under the Syndicated Loan (and any other debt allowed under the Trust);

-        providing that upon the occurrence of a CAMMESA Event (pursuant to the definition of this term in the Trust Agreement): (i) CTB may request funds to meet the power plant’s operating expenses, and (ii) VRDs payments will be rescheduled in case funds received as collection rights are insufficient;

-        modifying the amount of the Reserve Fund (pursuant to the definition of this term in the Trust Agreement) to the amount equivalent to the estimate of the next two services under the VRDs.

In accordance with the commitment undertaken in the Trust Agreement, pursuant to a resolution dated October 24, 2019, the CNV authorized the cancellation of the Trustor’s VRDs, which was effected on October 29, 2019. Consequently, on October 31, 2019, the eighth amendment to the Trust Agreement was entered into in order to include the new payment schedule effective as from such cancellation.

As of the date of issuance of these Consolidated Financial Statements, IEASA holds VRDs with a face value of 473,291,331.

5.3.5.3 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 U$S 170 million maturing on June 26, 2022, with U$S 136 million accruing a fixed 10.25% interest rate and U$S 34 million accruing a variable LIBOR rate+6.25.

On June 25, 2019, the Company executed a share pledge agreement in favor of the Lenders. Additionally, on August 22, 2019, YPF and PACOGEN entered into an amendment to the pledge agreement to include VRD holders as beneficiaries.

CTB endorsed the insurance policy, which covers CTEB’s open cycle’s operating risk, so that secured creditors should be the recipients of any payment, compensation and/or damages under such policy.

Additionally, CTB and Citibank, N.A.’s Branch (incorporated in the Republic of Argentina), in its capacity as trustee and sole beneficiary of the lenders, executed a trust assignment security agreement, which includes the assignment of the collection rights assigned to the Trustor for up to 42% of the amount to be settled, which CTB is entitled to collect pursuant to the power purchase agreements, net of added-value tax.

Finally, in order to coordinate the execution of the rights shared by the VRD holders and the Lenders under the Share Pledge Agreement and the endorsement of the policy, on August 22, 2019 BICE Fideicomisos S.A., in its capacity as Trustee under the Enarsa-Barragán Trust, executed with the Lenders an inter-creditor agreement that includes certain commitments regarding the exercise of its rights associated with the distribution of funds collected as a result of the possible execution of the guarantees shared by the VRD holders and the Lenders, and their interests in the payments to be made under such guarantees.

5.3.5.4 Granted guarantees

YPF and Pampa jointly guarantee, at 50% each, the timely and proper performance of all payment obligations under i) the Financial Trust Agreement, and ii) the Syndicated Loan Agreement, in case the closing of the combined cycle’s commissioning is not achieved i) within 30 months as from the seventh amendment to the agreement’s effective date, and ii) by December 26, 2021, respectively.

5.3.6 Other interest in Associates

5.3.6.1 Interests in mixed companies in Venezuela:

Interests in Petroritupano S.A. (22%), Petrowayú S.A. (36%), Petroven-Bras S.A. (34.49%) and Petrokariña S.A. (34.49%), companies organized as a result of the migration of operating agreements regulating the exploitation in Venezuela of the Oritupano Leona, La Concepción, Acema and Mata areas, respectively, were incorporated with the purchase of PPSL’s capital stock.

Given that as of the date of the acquisition of PPSL, the authorizations regarding the change of indirect control by the Government of Venezuela were not obtained, and considering the fact that the contracts of mixed companies provide the mandatory transfer of the shares for these cases, the Company has determined market value for its investment as of the date of acquisition was zero, considering: i) the monetary and fiscal policies implemented by the Venezuelan government together with the significant drop in international oil prices since 2014 that have eroded the ability of the mixed companies to efficiently operate the producing fields that resulted in increasing losses and reduction of equity in those investments, and ii) that there is very unlikely to acquire these assets in a stand-alone transaction, as conversion contracts establish that the transfer of direct control of the shares without obtaining prior approval of Venezuelan Government, implies that such participation is considered finished and all of the shares shall be transferred without any consideration in exchange for those shares.

Pampa has not recognized any share in the additional losses from these investments as it has not incurred any legal or implicit obligations or made any payments in the name of these mixed companies as from the acquisition date.

Additionally, under the agreements migration process, in 2006 the Venezuelan Government recognized in favor of the participating Company an interest-free severable and transferable credit in the amount of U$S 88.5 million which may be used to pay acquisition bonds under any new mixed company projects for the development of oil exploration and production activities, or licenses for the development of gas exploration and production operations in Venezuela. Since no projects have been undertaken for its use, negotiations for its transfer to third parties have been unsuccessful, and there are no other foreseen application alternatives, the Company keeps this credit valued at zero.

The Company has submitted the requested technical, legal and financial information, as well as development plans and financing proposals, to the consideration of CVPSA’s (Corporación Venezolana de Petróleo S.A.) majority shareholder, without obtaining, at the date of issuance of these Consolidated Financial Statements, the authorizations regarding the change of indirect control. Furthermore, CVPSA has expressed that, in view of the time elapsed, the Company should begin a new process for the presentation of plans under the guidelines to be provided by the Ministry of People’s Power for Oil of the Bolivarian Republic of Venezuela, which have not been informed to the Company yet. Given these circumstances, the Company has expressed to the Venezuelan Government’s authorities that it is no longer interested in submitting investments and/or financing proposals in mixed companies and that it is willing to negotiate the transfer of its shares to CVPSA. As of the date of issuance of these Consolidated Financial Statements, the Company has not received notifications in this regard.

5.3.6.2 Investment in OCP

The Company has an equity interest in OCP, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.

On December 6, 2018, OCP entered into a settlement agreement with the Republic of Ecuador to terminate all claims and legal actions brought by the parties regarding discrepancies with the Ecuadorian Treasury. This agreement stipulated a total settlement amount of U$S 182 million, of which U$S 64 million were offseted with receivables from income tax withholdings made by OCP in the 2004-2005 and 2007-2014 periods and U$S 7 million with a payment previously made by OCP corresponding to the determination of the 2003 fiscal year, and the remaining U$S 111 million were paid in cash in two installments. After satisfactorily meeting the stipulated obligations, on December 21, 2018, the parties executed a settlement agreement letter. As a result of the agreement, OCP has recorded profits for U$S 387 million.

In this regard, the Company has resumed recognising its 11.42% interest in OCP’s profits, through PEB, after recording previously unrecognized losses related to OCP´s negative equity, and being the investment valued at zero by the Company as a consequence of not making any capital contributions or financial assistance commitments to OCP, therefore, it has recognised profits for the participation in OCP’s results in the amount U$S 35 million as of December 31, 2018.

On the other hand, on December 5, 2018, and before the execution of the agreement between OCP and the Ecuadorian Government detailed above, the Company, through its subsidiary PEB, executed an agreement with Agip Oleoducto de Crudos Pesados ​​BV (“AGIP”) for the purchase of shares representing 4.49% OCP’s capital stock and of the financial credit that AGIP held with respect to the subordinated debt issued by OCP, in consideration of a base price equivalent to U$S 1 (one U.S. dollar).

On June 20, 2019, after meeting of all precedent conditions the transaction was subject to, including the notification received by OCP on March 19, 2019 regarding the authorization by the Ecuadorian Government on March 8, 2019, the transaction was closed and registered with the Shareholders’ Registry Book.

Pursuant to the agreement, in case the above-mentioned financial credit was collected by PEB before its maturity in 2021, PEB should reimburse AGIP 50% or 25% of the collected amount if collection occurs in 2019 or 2020, respectively.

Taking into consideration the timeliness of the agreement with AGIP, which was executed prior to the reversal of the above-mentioned situation, the closing of the transaction involved the recognition of a profit of U$S 25 million under IAS 28.

In order to estimate the 4.49% share in the fair value of identifiable assets and liabilities assumed in OCP, PEB has calculated the present value of future cash flows expected to be obtained through the collection of dividends considering the concession term that extends until 2023 and a discount rate of 15.3%.

The following table details the consideration transferred and the fair value of the assets acquired and the profit recorded by PEB as of June 20, 2019:

	in million  U$S
Acquisition cost (1)	(0.4)
Contingent consideration (2)	(0.1)
Total consideration	(0.5)
Share value of the interest in the fair value of associates’s identifiable assets and liabilities	9.0
Financial credit with OCP	14.2
Dividends to be received	2.5
Assets fair value	25.7
Profit (3)	25.2

(1)	Including expenses paid by PEB to the Ecuadorian Government (Ministry of the Environment) of U$S 0.1 million for the granting of the authorization to transfer the shares held by AGIP and other advisory expenses related to the transaction.
(2)	Contingent consideration calculated based on the estimated of the likelihood of collection of the financial credit with OCP prior to maturity.
(3)	Disclosed under “Share of profit (loss) from associates and joint ventures”

Furthermore, as of December 31, 2019, PEB recorded an impairment loss regarding the 11.42% interest in OCP (before the acquisition of the additional 4.49%) of U$S 6.7 million in connection with the present value of future cash flows expected to be obtained from such interest. Thus, the book value does not exceed the investment’s recoverable value.

5.4     OPERATIONS IN OIL AND GAS CONSORTIUMS

5.4.1 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.

According to Law No.17,319, royalties equivalent to 12% of the wellhead price of crude oil and natural gas are paid in Argentina. 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. 

5.4.2 Oil and gas participation details

As of December 31, 2019, the Company and associates are part of the joint operations and consortia for the exploration and production of oil and gas as indicated below:

			Participation
Name	Note	Location	Direct	Indirect	Operator	Duration Up To
Argentine production
Río Neuquén		Río Negro and Neuquén	31.43% 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		Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala		Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento		Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro		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
Foreign (1)
Oritupano - Leona		Venezuela	-	22.00%	PDVSA	2025
Acema		Venezuela	-	34.49%	PDVSA	2025
La Concepción		Venezuela	-	36.00%	PDVSA	2025
Mata		Venezuela	-	34.49%	PDVSA	2025
Argentine exploration
Parva Negra Este (2)		Neuquén	42.50%	-	PAMPA	2019
Chirete (3)		Salta	50.00%	-	High Luck Group Limited	2019
Río Atuel		Mendoza	33.33%	-	Petrolera El Trebol	2020
Borde del Limay (4)		Neuquén	85.00%	-	PAMPA	2015
Los Vértices (4)		Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte		Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾   Participation in mixed companies in Venezuela (see Note 5.3.6.1).

⁽²⁾   In the process of requesting appraisal.

⁽³⁾   In the process of requesting an exploration concession.

⁽⁴⁾   In the process of being transferred to GyP.

5.4.3 New concessions and changes in oil and gas participations

5.4.3.1 Parva Negra Area

The exploration license for Parva Negra Este, an area located in the Province of Neuquén granted under concession to GyP and operated by Pampa since April 2014 for a term of 4 years, expired in the month of April 2018. As the original agreement had stipulated the possibility to extend it for a year, GyP requested such extension in due time and manner.

Upon the expiration of the exploration license’s extension in the month of April 2019, on March 29, 2019 GyP requested that the block should be classified as an evaluation block for a 3-year period.

5.4.3.2 Las Tacanas Norte area

On January 4, 2019, with the publication in the BO of Executive Order No. 2315/18 passed by the Executive Branch of the Province of Neuquén, this exploratory agreement, effective for a term of 4 years, entered into force. Pampa is the operator of Las Tacanas Norte area with a 90% interest, and GyP is the permit holder with a 10% interest.

The block has a 120 km2 surface and is adjacent to El Mangrullo block, which is currently operated by the Company. The accepted offer consists of a perforation of up to 8 wells with the objective toward Vaca Muerta formation, and other exploratory studies.

5.4.3.3 Río Atuel

As a result of the delay in the approval of the drilling project filed on December 19, 2018, Petrolera el Trebol, the area operator, on June 19, 2019 requested, to the applicable authorities, for the suspension of the term of the second exploratory period in progress. On June 7, 2019, the approval of the drilling project was obtained. On June 19, 2019, the suspension of the second exploration period requested was established by the relevant authorities, determining December 7, 2019 as the new expiration date.

Subsequently, upon operator´s request, on November 11, 2019, the Hydrocarbons Department granted a 12-months term extension, effective as from December 18, 2019, for the third exploratory period. In this same administrative decision, the applicable authority accepted the 50% reversal of the area.

5.4.3.4 Chirete

After the discovery of oil in late 2018, on February 22, 2019 the applicable authorities granted a 12-months term extension, effective as from November 18, 2018, for the third exploratory period. Since the field discovered in this block turned out to be commercially exploitable, on April 26, 2019 an application was filed for the granting of a hydrocarbon exploitation concession over the “Los Blancos” block, with a 95-km2 surface, and on April 30, 2019 a three-year extension of the third exploratory period for the permit’s remaining area was requested. which had been extended for 12 months from November 18, 2018. As of the date of issuance of these Consolidated Financial Statements, the above mentioned granting of exploitation concession is in process.

5.4.3.5 Anticlinal Campamento

On December 1, 2010, YPF, owner of the exploitation concession over the block, organized on December 1, 2010, a Joint Venture for the drilling of 9 wells, in which the company has a 15% interest. On August 1, 2019, the concession over the “Anticlinal Campamento” block was transferred from YPF to Oilstone Energía S.A, including the transfer of operations and agreements thus remaining unchanged Pampa´s participation in the Anticlinal Campamento.

5.4.3.6 Sierra Chata

On December 27, 2019, through Decree 129/19, the province of Neuquén has approved the assignment of Total Austral´s participation to Mobil Argentina SA, resulting in a Mobil participation of 54.4477% in the area.

5.5 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2019, 2018 and 2017:

	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year	19	12	16
Increases	30	8	8
Transferred to development	(11)	-	(8)
Loss of the year	(5)	(1)	(1)
At the end of the year	33	19	15
Number of wells at the end of the year	9	7	7

5.6 Operations in Ecuador

As from 2006 the Ecuadorian government implemented far-reaching tax and regulatory reforms in connection with hydrocarbon activities, which involved material changes in the conditions set forth at the time of execution of participation agreements.

5.6.1 Amendatory Agreements and Law amending the Hydrocarbon Law

On October 31, 2008, EcuadorTLC, Teikoku Oil Ecuador and Petroecuador, among others, executed the Amendatory Agreements regulating the operation of Block 18 and Palo Azul while the parties negotiated the migration to a new contract modality.

As a result of the negotiation process mentioned above, the Company decided not to accept the final proposal received from the Ecuadorian government, as this is insufficient to migrate to Service Agreements in Block 18 and Palo Azul Unified Field. Consequently, through Resolution dated November 25, 2010 the Hydrocarbon Secretary notified EcuadorTLC the termination of the Participation Agreements and instructed Petroamazonas EP to undertake the operational transition process; the Ecuadorian government must compensate the terminated parties in an amount equivalent to unamortized investments adjusted by 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 bringing several administrative and judicial proceedings, not having reached an agreement with the Ecuadorian government, EcuadorTLC, Cayman International Exploration Company and Teikoku Oil Ecuador, members of the joint operation, presented, on February 26, 2014 the request for arbitration against Ecuador and EP Petroecuador under the arbitration Rules of the United Nations Commission on International Trade Law.

On January 16, 2018 the Arbitration Court issued the Award, which determined a Settlement Value of U$S 176 million for EcuadorTLC based on its interest in the Block.

As regards the Arbitration, on March 19, 2018, the Republic of Ecuador and the Plaintiff Partners entered into an agreement (the “Agreement”) whereunder the Plaintiff Partners will not seek the collection of the Award in consideration of the award of consequential damages, which for EcuadorTLC consist of: (i) the release from tax and labor claims in dispute in the amount of U$S 132 million, and (ii) the additional collection of U$S 54 million in three installments payable in the months of March, April and May. Additionally, the parties agreed that EcuadorTLC would be the sole beneficiary of the collection of the amount of U$S 9 million corresponding to an obligation undertaken by Petromanabí (a member of the Block 18 Consortium but not a plaintiff). This receivable has not been recognized in view of its contingent nature.

Furthermore, the Republic of Ecuador has declared and recognized in the Agreement: (i) that the Agreement is fully valid and binding on the Republic of Ecuador, (ii) that any payment default by the Republic of Ecuador under the Agreement will enable the Plaintiff Partners to fully enforce the Final Award, and (iii) there are no other obligations pending performance regarding the operation and exploitation of Block 18 by the Plaintiff Partners.

As a result of the Agreement, the Company has disclosed net profits for U$S 40 million as of December 31, 2018, made up of: i) profits of U$S 133 million as consequential damages after writing off the receivable of U$S 53 million to be recovered from the Ecuadorian Government pursuant to the Amending Agreements, and ii) a U$S 93 million loss associated with the agreement to the terms of the tax claims assigned to EcuadorTLC in accordance with the Agreement.

As of May 3, 2018, EcuadorTLC has collected the three installments and has 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, EcuadorTLC was notified of the payment on employee participation profits from 2002 to 2010, to the former consortium workers.

5.6.2 Crude Oil Transportation Agreement with OCP

The Company holds a contract with OCP, whereby it assumed a commitment to an oil transport capacity of 80,000 barrels/day for a term of 15 years counted as from November 10, 2003.

The transport contract is a “Ship or Pay” contract, so the Company must meet its contractual obligations for the total volume agreed upon, regardless of the real volume transported, and has to pay, the same as the other producers, a rate that covers the operating costs and financial services of OCP, among others.

EcuadorTLC had the right to sell the transport capacity in the heavy crude oil pipeline (OCP) to mitigate the negative impact of its non-use. On December 31, 2008, the Company entered into a contract with Petroecuador whereby the Ecuadorian State assumed a commitment to charge, effective January 1, 2009, the available crude owned by it and transported through the heavy crude oil pipeline to the oil transport capacity hired by the Company, up to a maximum volume of 70,000 barrels/day. In addition, the Company sold transport capacity of approximately 8,000 barrels/day of oil for the period from July 2004 to January 2012. As a result of the contract non-compliance by the buyers, the Company is making the pertinent claims to Petroecuador. To such effect, a mediation proceeding has been brought before the Center for Mediation of the Attorney General’s Office of the Government of Ecuador sitting in the City of Quito.

In January 2018, EcuadorTLC assigned to the subsidiary Energía Operaciones ENOPSA S.A. (“ENOPSA”) a transportation capacity of 10,000 barrels/day, and ENOPSA declared the Equity Expropriation Event, whereby, under certain circumstances stipulated in the agreement, the Company, in its capacity as guarantor, will bear the payments for the capital charges associated with the assigned transportation capacity.

The agreement terminated on November 10, 2018 and, therefore collaterals held to ensure compliance with related financial commitments were gradually released as those commitments become extinguished.

5.6.3 Investment in OCP - Ecuador

The Company has a 15.91% equity interest in OCP, an oil pipeline in Ecuador that has a transportation capacity of 450,000 barrels/day.  See detail in Note 5.3.6.2.

XML

9. COST OF SALES

12 Months Ended

Dec. 31, 2019

Cost Of Sales

COST OF SALES

	12.31.2019	12.31.2018	12.31.2017
Inventories at the beginning of the year	137	113	164
Plus: Charges for the year
Purchases of inventories, energy and gas	1,305	1,224	874
Salaries and social security charges	163	181	202
Benefits to employees	9	6	7
Accrual of defined benefit plans	7	4	7
Works contracts, fees and compensation for services	103	98	84
Depreciation of property, plant and equipment	232	206	195
Intangible assets amortization	7	7	1
Right-of-use assets amortization	2	-	-
Transport of energy	4	4	3
Transportation and freights	18	14	3
Consumption of materials	48	64	29
Penalties	25	56	11
Maintenance	27	24	18
Canons and royalties	59	74	56
Environmental control	3	5	3
Rental and insurance	21	13	11
Surveillance and security	6	6	6
Taxes, rates and contributions	4	5	3
Other	5	-	10
Subtotal	2,048	1,991	1,523
Gain on monetary position	1	-	-
Less: Inventories at the end of the year	(153)	(137)	(113)
Total cost of sales	2,032	1,967	1,574

XML

CONSOLIDATED STATEMENT OF FINANCIAL POSITION - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
NON CURRENT ASSETS
Property, plant and equipment	$ 3,507	$ 3,316
Intangible assets	151	161
Right-of-use assets	16	0
Deferred tax assets	28	2
Investments in joint ventures and associates	511	407
Financial assets at amortized cost	18	0
Financial assets at fair value through profit and loss	11	11
Other assets	1	1
Trade and other receivables	79	253
Total non current assets	4,322	4,151
CURRENT ASSETS
Inventories	153	137
Financial assets at amortized cost	54	35
Financial assets at fair value through profit and loss	365	405
Derivative financial instruments	4	0
Trade and other receivables	561	703
Cash and cash equivalents	225	241
Total current assets	1,362	1,521
Total assets	5,684	5,672
SHAREHOLDERS' EQUITY
Share capital	46	50
Share capital adjustment	260	260
Share premium	510	491
Treasury shares	1	0
Treasury shares adjustment	1	4
Treasury shares cost	(44)	(39)
Legal reserve	42	24
Voluntary reserve	422	195
Other reserves	(18)	(13)
Retained earnings	726	403
Other comprehensive income	(29)	(9)
Equity attributable to owners of the company	1,917	1,366
Non-controlling interest	492	429
Total equity	2,409	1,795
NON CURRENT LIABILITIES
Investments in joint ventures and associates	4	4
Provisions	145	146
Income tax and minimum notional income tax provision	10	27
Deferred revenue	5	7
Taxes payables	4	14
Deferred tax liabilities	368	407
Defined benefit plans	27	31
Salaries and social security payable	4	4
Borrowings	1,764	1,835
Trade and other payables	90	220
Total non current liabilities	2,421	2,695
CURRENT LIABILITIES
Provisions	20	23
Income tax and minimum notional income tax provision	53	29
Taxes payables	72	54
Defined benefit plans	4	4
Salaries and social security payable	65	72
Derivative financial instruments	3	1
Borrowings	183	342
Trade and other payables	454	657
Total current liabilities	854	1,182
Total liabilities	3,275	3,877
Total liabilities and equity	$ 5,684	$ 5,672

XML

10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2019

Other Items Of Statement Of Comprehensive Income

Selling expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	22	26	27
Benefits to employees	1	-	-
Accrual of defined benefit plans	1	-	1
Fees and compensation for services	29	30	26
Compensation agreements	(1)	2	6
Depreciation of property, plant and equipment	9	9	3
Right-of-use assets amortization	1	-	-
Taxes, rates and contributions	25	33	28
Communications	6	7	8
Penalties	22	28	12
Net impairment losses on financial assets	21	28	11
Transport	9	6	4
Other	3	2	1
Total selling expenses	148	171	127

Administrative expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	62	81	77
Benefits to employees	8	5	5
Accrual of defined benefit plans	8	1	6
Fees and compensation for services	52	68	53
Compensation agreements	-	3	20
Directors' and Syndicates' fees	7	5	4
Depreciation of property, plant and equipment	14	12	6
Consumption of materials	3	4	3
Maintenance	2	2	2
Transport and per diem	2	2	2
Rental and insurance	5	6	6
Surveillance and security	2	5	4
Taxes, rates and contributions	2	8	4
Communications	2	2	2
Right-of-use assets amortization	2	-	-
Institutional advertising and promotion	-	1	2
Other	3	1	2
Total administrative expenses	174	206	198

Exploration expenses

	12.31.2019	12.31.2018	12.31.2017
Geological and geophysical expenses	4	-	1
Decrease in unproductive wells	5	1	1
Total exploration expenses	9	1	2

Other operating income and expenses

Other operating income	Note	12.31.2019	12.31.2018	12.31.2017
Compensation for transaction agreement in Ecuador (1)		-	99	-
Recovery of doubtful accounts		-	-	4
Insurrance recovery		6	-	-
Natural Gas Surplus Injection Promotion Program	4.24.1.1	-	23	101
Commissions on municipal tax collections		2	2	1
Services to third parties		13	13	8
Profit for property, plant and equipment sale		-	3	-
Dividends received		1	1	1
Reversal of contingencies and taxes payables (2)		1	4	24
Other		17	36	10
Total other operating income		40	181	149
Other operating expenses
Provision for contingencies		(28)	(35)	(20)
Decrease in property, plant and equipment		(1)	(6)	(1)
Allowance for tax credits		(4)	-	(1)
Tax on bank transactions		(29)	(30)	(27)
Cost for services provided to third parties		(2)	(2)	(2)
Compensation agreements		-	-	(2)
Donations and contributions		(2)	(2)	(2)
Institutional promotion		(2)	(3)	(3)
Extraordinary canon		-	(3)	(14)
Contingent consideration		-	-	(8)
Onerous contract (Ship or Pay)		-	(7)	(4)
Tax contingencies in Ecuador (1)		-	(69)	-
Other		(18)	(43)	(19)
Total other operating expenses		(86)	(200)	(103)

(1)	Pursuant to Agreement executed on March 19, 2018 between the Republic of Ecuador and the Plaintiff Partners, including EcuadorTLC (see Note 5.6.1). Figures recorded as of December 31, 2018 arises from the Consolidated Financial Statements denominated in pesos in accordance with IAS 29, and was translated into U.S. dollars using the exchange rate as of that date.
(2)	In 2017, includes gains on releasing tax fines and reducing compensatory interests, related to benefits for the adhesion to the regularization regime (moratorium) (see Note 2.6.4).

Financial results

	12.31.2019	12.31.2018	12.31.2017
Gain on monetary position, net	187	629	304
Finance income
Commercial interest	61	58	43
Financial interest	22	34	14
Other interest	13	7	5
Total finance income	96	99	62
Finance cost
Commercial interest	(52)	(78)	(45)
Fiscal interest	(6)	(8)	(11)
Financial interest (1)	(227)	(210)	(162)
Other interest	(10)	(15)	(10)
Other financial expenses	(4)	(5)	(4)
Total financial expenses	(299)	(316)	(232)
Other financial results
Foreign currency exchange difference, net	(75)	(863)	(156)
Changes in the fair value of financial instruments	91	64	62
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results of RDSA	2	13	-
Results for the repurchase of corporate bonds	27	2	-
Other financial results	14	-	-
Total other financial results	113	(858)	(100)
Total financial results, net	97	(446)	34

 ⁽¹⁾ Net of U$S 16.8 million, U$S 7.5 million and U$S 16 million capitalized in property, plant and equipment for the years ended December 31, 2019, 2018 and 2017, respectively.

Income tax benefit expense

The breakdown of income tax charge is:

	12.31.2019	12.31.2018	12.31.2017
Current tax	70	39	55
Deferred tax	(57)	(19)	(72)
Other comprehensive income	-	1	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	1	(4)	(12)
Direct charges for income tax	-	-	3
Optional tax revaluation	34	-	-
Total loss (gain) income tax	48	17	(26)

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2019	12.31.2018	12.31.2017
Profit before income tax	848	224	402
Current tax rate	30%	30%	35%
Result at the tax rate	254	67	141
Share of profit of associates and joint ventures	(25)	(3)	(117)
Non-taxable results	(38)	7	(59)
Effects of exchange differences and traslation effect of property, plant and equipment and intangible assets, net	93	-	-
Adjustment of valuation of property, plant and equipment and intangible assets	(202)	-	-
Gain (loss) on monetary position, net	17	(38)	66
Effect of tax rate change in deferred tax	37	(26)	(21)
Adjustment effect for tax inflation	129	-	-
Payment of optional tax revaluation	34	-	-
Special tax, revaluation of property, plant and equipment	(169)	-	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	(86)	4	(20)
Deferred tax not previously recognized	-	4	(31)
Non-deductible cost	-	-	9
Non-deductible provisions	-	-	5
Other	4	2	1
Total  loss (gain) income tax	48	17	(26)

Consolidated accumulated tax losses

Fiscal year generation	Fiscal year prescription	12.31.2019	12.31.2018
2015	2020	-	3
2016	2021	4	18
2017	2022	3	4
2018	2023	38	27
2019	2024	66	-
Recognized Tax loss-carryforwards		111	52

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6. RISKS (Tables)

12 Months Ended

Dec. 31, 2019

Risks

Exposure to the price risk

	Increase of the result for the year
Financial assets	12.31.2019	12.31.2018
Shares	2	1
Government securities	11	30
Investment funds	24	11
Variation of the result of the year	37	42

Borrowings classified by interest rate

	12.31.2019	12.31.2018
Fixed interest rate:
Argentinian pesos	143	15
U.S dollar	1,687	1,861
Subtotal loans granted at a fixed interest rate	1,830	1,876
Floating interest rates:
Argentinian pesos	10	108
U.S dollar	64	131
Subtotal loans granted at a floating interest rate	74	239
Non interest accrued
U.S dollar	17	30
Argentinian pesos	26	32
Subtotal no interest accrued	43	62
Total borrowings	1,947	2,177

Expected credit loss on trade receivables and financial assets rates

12.31.2019	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.10%	0.35%	1.99%	2.95%	4.03%	5.59%	9.79%	16.13%
Oil and Gas	0.53%	1.49%	9.45%	18.03%	18.50%	18.81%	18.90%	18.92%
Distribution of energy	3.00%	3.00%	8.00%	18.00%	20.00%	45.00%	72.00%	72.00%
Petrochemicals	0.39%	0.73%	6.88%	16.66%	25.32%	29.59%	30.97%	43.05%
Holding	1.85%	2.81%	6.84%	17.15%	26.77%	43.21%	49.89%	65.29%
12.31.2018	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.04%	0.09%	2.62%	3.39%	9.37%	13.56%	19.82%	28.88%
Oil and Gas	2.20%	4.42%	11%	20.42%	42.85%	47.32%	49.20%	56.32%
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Petrochemicals	0.03%	0.08%	1.41%	4.98%	11.52%	20.36%	24.91%	25.24%
Holding	0.96%	1.25%	2.03%	2.85%	19.86%	26.41%	32.95%	32.97%

In 2017 fiscal year, the calculation of the loss allowance for trade receivables and other receivables was assessed based on the incurred loss model, and considered the existence of objective evidence of default for the recognition of losses in the statement of comprehensive income. The expected credit loss as of January 1, 2018 (IFRS 9 amended adoption date) was determined based on credit loss rates calculated for days past due detailed below:

Rates	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+180 days
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Rest of business segments	0.32%	0.93%	8.11%	19.61%	35.69%	45.63%	59.00%	63.01%

Loss allowance for financial assets and other receivables

	Financial assets	Other receivables
Loss allowance under IAS 39 as of 12.31.2017	22	7
Adjustment to the opening balance of retained earnings	4	(1)
Loss allowance calculated under IFRS 9 as of 01.01.2018	26	6

Liquidity index

	12.31.2019	12.31.2018
Current assets	1,362	1,521
Current liabilities	854	1,182
Index	1.59	1.29

Financial liabilities contractual undiscounted cash flows maturity

As of December 31, 2019	Trade and other payables (1)	Borrowings	Total
Less than three months	-	95	95
Three months to one year	454	188	642
One to two years	11	288	299
Two to five years	70	834	904
More than five years	9	1,233	1,242
Total	544	2,638	3,182
As of December 31, 2018	Trade and other payables	Borrowings	Total
Less than three months	331	112	443
Three months to one year	534	318	852
One to two years	9	242	251
Two to five years	3	892	895
More than five years	-	977	977
Total	877	2,541	3,418

(1) Includes Lease Liabilities (see Note 18.1.2)

Financial leverage ratios

	12.31.2019	12.31.2018
Total borrowings	1,947	2,177
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(590)	(646)
Net debt	1,357	1,531
Total capital attributable to owners	3,274	2,897
Leverage ratio	41.45%	52.85%

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2. REGULATORY FRAMEWORK

12 Months Ended

Dec. 31, 2019

Regulatory Framework

REGULATORY FRAMEWORK

2.1 Generation

2.1.1 Generation units

The Company’s 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, replaced by SRRYME Resolution No. 1/19 as from March 2019); 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.

The Company’s generating units are detailed below:

In operation:
Generator	Generating unit	Tecnology	Power	Applicable regime (2)
CTG	GUEMTG01	TG	100 MW	Energy Plus Res. No. 1281/06 (1)
CTG	GUEMTV11	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV12	TV	≤100 MW	SE Resolutions No. 1/19
CTG	GUEMTV13	TV	>100 MW	SE Resolutions No. 1/19
Piquirenda	PIQIDI 01-10	MG	30 MW	SE Resolution No. 220/07 (1)
CPB	BBLATV29	TV	>100 MW	SE Resolutions No. 1/19
CPB	BBLATV30	TV	>100 MW	SE Resolutions No. 1/19
CT Ing. White	BBLMD01-06	MG	100 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATG01	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG02	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG03	TG	>50 MW	SE Resolutions No. 1/19
CTLL	LDLATG04	TG	105 MW	SEE Res. 220/07 (75%), SEE Res. 1/19 (25%)
CTLL	LDLATG05	TG	105 MW	SEE Resolution No. 21/16 (1)
CTLL	LDLATV01	TV	180 MW	SE Resolution No. 220/07 (1)
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	SE Resolutions No. 1/19
CTGEBA	GEBATG03	TG	188 MW	Energy Plus Res. No. 1281/06 (1)
CTGEBA	GEBATG04	TG	>100 MW	SE Resolutions No. 1/19 (3)
Ecoenergía	CERITV01	TV	Renewable  = 50	Energy Plus Res. N° 1281/06 (1)
CT Parque Pilar	PILBD01-06	MG	100 MW	SE Resolutions No. 1/19 (3)
CTB	EBARTG01 - TG02	TG	HI – Small  50<P≤120	SE Resolution No. 220/07 (1)
HIDISA	AGUA DEL TORO	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	EL TIGRE	HI	HI – Small  50<P≤120	SE Resolutions No. 1/19
HIDISA	LOS REYUNOS	HB	HB – Media  120<P≤300	SE Resolutions No. 1/19
HINISA	NIHUIL I - II - III	HI	HI – Chica  50<P≤120	SE Resolutions No. 1/19
HPPL	PPLEHI	HI	HI – Media  120<P≤300	SE Resolutions No. 1/19
P.E. M. Cebreiro	CORTEO	Eólica	100 MW	Renovar (1)
PEPE II	PAMEEO	Eólica	53 MW	SEE Resolution No. 281/17
PEPE III	BAHIEO	Eólica	53 MW	SEE Resolution No. 281/17
(1) Uncommitted power and energy is remunerated according to Resolution No. 1/19.
(2) Resolution No. 1/19 entered into force as of February 19. During the month of January 2019, it was remunerated under Resolution No. 19/17.
(3) Once the combined cycle is commercially enabled, the supply agreements with CAMMESA will come into force under Resolution No. 287/17.
In construction:
Generator	Generating unit	Tecnology	Applicable regime
CTLL	MG	15 MW	SE Resolutions No. 1/19
CTGEBA	CC	176 MW	SE Resolution No. 287/17
CTB	CC	280 MW	SE Resolution No. 220/07

2.1.2 Remuneration at the Spot market

On February 2, 2017, the SEE issued Resolution No. 19/17, which superseded the remuneration scheme set forth by Resolution No. 22/16 and established guidelines for the remuneration to generation plants as from the commercial transaction corresponding to February 1, 2017.

Later, on March 1, 2019, SRRYME Resolution No. 1/19 was published in the BO, which abrogated, effective as from March 1, 2019, the remuneration scheme established by SEE Resolution No. 19/17.

Both resolutions provide for remunerative items based on technology and scale, establishing U$S-denominated prices payable in pesos by applying BCRA’s exchange rate effective on the last business day of the month of the applicable economic transaction, adjusted through credit or debit notes, as appropriate, to consider the BCRA’s exchange rate of the day before the expiration date, in accordance with CAMMESA’s procedures.

2.1.2.1 Remuneration for Available Power Capacity

2.1.2.1.1 Thermal Power Generators

The SEE Resolution No. 19/17 provides for a minimum remuneration for power capacity based on technology and scale and allows generating, co-generating and self-generating agents owning conventional thermal power stations to offer Guaranteed Availability Commitments for the energy and power capacity generated by their units not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA.

Availability Commitments for each unit should be declared for a term of three years, together with information for the Summer Seasonal Programming, with the possibility to offer different availability values for the summer and winter six-month periods. The committed thermal generators’ remuneration for power capacity will be proportional to their compliance.

The Minimum Remuneration applies to generators with no availability commitments, with prices ranging from U$S3,050 to U$S5,700/MW-month, depending on the technology and scale.

The Base Remuneration applies to generators with availability commitments, with a price of U$S 6,000/MW-month during the May-October 2017 period, and U$S 7,000/MW-month as from November 2017.

The Additional Remuneration is a remuneration for the additional available power capacity aiming to encourage availability commitments for the periods with a higher system demand. CAMMESA will define a monthly thermal generation goal for the set of qualified generators on a bi-monthly basis, and will call for additional power capacity availability offers with prices not exceeding the additional price. The additional price amounts to U$S 1,000/MW-month between May and October, 2017, and to U$S2,000/MW-month as from November 2017.

The SRRYME Resolution No. 1/19 maintains in effect a remuneration made up of a minimum or base power capacity payment for generators with no availability commitments, and another for offered guaranteed power capacity, although with lower values than under the previous resolution:

-        The minimum remuneration for power capacity was reduced from U$S 5,700/MW-month to U$S 5,200/MW-month for small steam turbine units (≤ 100MW) and internal combustion engines.

-        The price of the remuneration for guaranteed power capacity decreased from U$S 7,000/MW-month to U$S 5,500 U$S/MW-month, only for the autumn and spring periods.

Furthermore, the current remuneration scheme, applies a coefficient derived from the unit’s average utilization factor during the last twelve months to the power capacity remuneration: a minimum 70% utilization factor is required to collect 100% of the power capacity payment; if the utilization factor ranges between 30% and 70%, the power capacity payment will range between 70% and 100%; and if the usage factor is lower than 30%, 70% of the power capacity payment will be collected. Additionally, Availability Commitments should be declared for each unit on a quarterly basis.

Finally, the current remuneration scheme, abrogates the additional remuneration scheme to encourage the guaranteed power capacity offered in the periods with a higher system demand.

2.1.2.1.2 Hydroelectric Generators

In the case of hydroelectric power plants, a base remuneration and an additional remuneration for power capacity were established by the SEE Resolution No. 19/17.

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 following is considered to calculate availability: i) the operation as turbine at all hours within the period, and ii) the availability as pump at off-peak hours every day and on non-business days.

The base remuneration is determined by the actual power capacity plus that under programmed and/or agreed maintenance, with prices ranging from U$S2,000 to U$S8,000/MW-month, depending on the scale and type of power plant.

In case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor will be applied to the plant at the headwaters.

The additional remuneration applies to power plants of any scale for their actual availability and based on the applicable period, with prices ranging from U$S0 to U$S500/MW-month between May and October 2017, and U$S500 or U$S1,000/MW-month as from November 2017 for pumping or conventional hydroelectric power plants, respectively.

As from November 2017, the allocation and collection of 50% of the additional remuneration will be conditional upon the generator taking out insurance, to CAMMESA’s satisfaction, to cover for major incidents on critical equipment, and the progressive updating of the plant’s control systems pursuant to an investment plan to be submitted based on criteria to be defined by the SEE.

SRRYME Resolution No. 1/19 maintains power capacity prices set forth by SEE Resolution No. 19/17; nevertheless, the hours in which a hydroelectric generator is not available due to programmed and agreed maintenance will no longer be computed for the calculation of the power capacity remuneration. However, in order to mitigate such incidence, in May 2019, by means of SME Note No. 46631495/19, a 1.05 factor was applied to power capacity prices.

2.1.2.1.3 Wind power

The remuneration under the SEE Resolution No. 19/17 is made up of a base price of U$S7.5/MWh and an additional price of U$S17.5/MWh, which are associated with the availability of the installed equipment with an operating permanence longer than 12 months as from the beginning of the summer seasonal programming.

Later on, SRRYME Resolution No. 1/19 establishes a single remuneration value for generated energy (see next item).

2.1.2.2 Remuneration for Generated and Operated Energy

The SEE Resolution No. 19/17 establishes a remuneration for Generated Energy with prices ranging between U$S5 and U$S10/MWh, depending on the technology, scale and type of fuel. Pursuant to SRRYME Resolution No. 1/19, these values are reduced to U$S 4/MWh and U$S 7/MWh, respectively.

Under the SEE Resolution No. 19/17, the remuneration for Operated Energy applies to the integration of hourly power capacities for the period, and is valued at U$S2.0/MWh for any type of fuel. Under the scheme set forth by SRRYME Resolution No. 1/19, the above-mentioned price is reduced to U$S 1.4/MWh.

In the case of hydroelectric plants, prices for Generated and Operated Energy under the SEE Resolution No. 19/17, are remunerated U$S3.5 and U$S1.4/MWh, respectively regardless of scale. Under the scheme set forth by SRRYME Resolution No. 1/19, the above-mentioned prices are maintained.

As regards energy generated from unconventional sources, SRRYME Resolution No. 1/19 establishes a single remuneration value of U$S 28/MWh, irrespective of the source used. Energy generated prior to the commissioning by the OED will be remunerated at 50% of the above-mentioned remuneration.

2.1.2.3 Additional Remuneration for Efficiency and for Low-Use Thermal Generators

The “Efficiency” incentive established in the SEE Resolution No. 19/17 consists of the acknowledgment of an additional remuneration equivalent to the remuneration for the generated energy by the percentage difference between the actual consumption and the reference consumption determined for each unit and fuel type. This comparison will be made on a quarterly basis. In the case of higher consumptions, the general remuneration will not be affected.

The mentioned Resolution also provides for an additional remuneration for low-use thermal generators having frequent startups based on the monthly generated energy for a price of U$S2.6/MWh multiplied by the usage/startup factor.

Under the scheme set forth by SRRYME Resolution No. 1/19, the efficiency and low-use/frequent startups incentives are canceled.

2.1.2.4 Repayment of Overhauls Financing

The SEE Resolution No. 19/17 provides that, as regards the repayment of outstanding loans applicable to thermal and hydroelectric generators, credits already accrued and/or committed to the cancellation of such maintenance works will be applied first. The balance will be repaid by discounting U$S1/MWh for the energy generated until the total cancellation of the financing.

Later on, as regards the repayment of funds supplied to generators under the loan agreements for the execution of overhauls in their units, SRRYME Resolution No. 1/19 provides for: (i) the application of all receivables accrued in favor of generators for their settlement, and (ii) a discount scheme in the generator’s revenues equivalent to U$S 1/MWh for each generated MW or U$S 700/MW-month for the unit’s actual availability, whichever is higher.

The overhauls financing owed by the Company were canceled under the Agreement for the Regularization and Settlement of Receivables with the WEM (see Note 2.1.7).

2.1.2.5 Suspension of contracts within the MAT

The suspension of contracts within the MAT (excluding those resulting from a differential remuneration scheme) provided for by SE Resolution No. 95/13 was not modified by SRRYME Resolution No. 1/19, this suspension thus remained in effect during 2019.

2.1.3 Sales contracts with large users within the MAT

2.1.3.1 Energy Plus

With the purpose of encouraging new generation works, in 2006 the SE approved Resolution No. 1,281/06 establishing a specific regime which would remunerate newly installed generation sold to a certain category of Large Users at higher prices.

To such effect, it established certain restrictions on the sale of electricity and implemented the Energy Plus service, which consists of the offer of additional generation availability by the generating agents. These measures imply that:

-         Generating, co-generating and self-generating agents which, as of the date of issuance of SE Resolution No. 1,281/06, are neither WEM agents nor have facilities or an interconnection with the WEM, will qualify;

-         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.

Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 280 MW. The values of Energía Plus contracts are mostly denominated in U.S. dollars. It is worth pointing out that Güemes has transferred, since May 2019, its contracts to Genelba, selling electricity in the spot market.

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.

Furthermore, SE Note No. 567/07, as amended, provided that GU300 not purchasing their Surplus Demand within the MAT should pay the CMIDE, and that the difference between the actual cost and the CMIDE would be accumulated in an individual account on a monthly basis for each GU300 within CAMMESA's scope.

Pursuant to SE Note No. 111/16, until May 2018, the CMIDE was $ 650/MWh for GUMA and GUME and $ 0/MWh for GUDI. As from June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $ 1,200/MWh or the temporary dispatch surcharge. Additionally, it was provided that, until further instructed, movements in the individual account of each GU300 would temporarily not be recorded.

Due to the decrease in surplus demand as a consequence of the decrease in economic activity, there are GU300 that decide not to make Energy Plus contracts (with higher prices), and generators have to sell their energy at the spot market, thus reducing their profitability. Additionally, the Energy Plus contracts were affected by the growth of Renewable MAT contracts, by the GU300 surplus energy.

2.1.3.2 Renewable Energy Term Market (“Renewable MAT” Regime)

Pursuant to Resolution No. 281/17, the MEyM regulated the Renewable MAT 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 MAT of electric power from renewable sources or self-generation from renewable sources.

Furthermore, this resolution regulates the conditions applicable to projects for the generation, self-generation and co-generation of electric power from renewable sources. Specifically, the RENPER was created for the registration of such projects.

Projects destined to the supply of electric power from renewable sources under the Renewable MAT regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy will be sold in the spot market.

Finally, contracts executed under the Renewable MAT regime will be 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— may be freely agreed between the parties, although the committed electricity volumes will be 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.

For further information on the projects PEPE II and PEPE III conducted under this resolution, see Note 16.1.1.

2.1.4 Supply Agreements with CAMMESA

2.1.4.1 SE Resolution No. 220/07 (“Agreement Res.220”)

Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into 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 the investments made by the agent at a rate of return to be accepted by the SE.

Under this regulation, the Company, through its thermal power plants Loma de La Lata, Piquirenda and Barragán, has executed Agreement Res.220 to sell energy and power capacity for a total amount of 856 MW.

For further information on the project to the closing of the combined cycle at CTB conducted under this resolution, see Note 16.1.4.

2.1.4.2 SEE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector, the SEE 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.

Successful bidders will enter into a wholesale power purchase agreement with CAMMESA for a term of 10 years. The remuneration will be 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. 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.

2.1.4.3 SEE Resolution No. 287/17

On May 10, 2017 the SEE 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.

Awarded projects will be remunerated under a wholesale power purchase agreement which will be effective for a term of 15 years. The remuneration will be 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. Surplus power capacity is sold in the spot market.

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 wholesale power purchase agreements, with a limit of 180 days as from the originally committed commissioning date. However, the Company has ratified the originally committed date.

For further information on the project to the closing of the combined cycle at Genelba conducted under this resolution, see Note 16.1.3.

2.1.4.4 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).

Successful bidders will enter into renewable electric power supply agreements for the sale of a committed annual electric power block for a term of 20 years.

Additionally, several measures have been established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, accelerated depreciation of 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.

Under this regulation, the Company, through Greenwind, has a supply agreement in place with CAMMESA for a total 100 MW.

2.1.5 Electricity transmission cost payable by Generators

On November 28, 2017, SEE Resolution No. 1,085/17 approved a new cost distribution methodology that represents the transmission service’s remuneration within the WEM.

In this regard, the SEE amended the original regulation of the WEM transmission system, which provided that transmission service costs would be allocated to the Demand and electric power Generation, and resolved that generators should stop paying costs associated with transmission, and start paying a charge representing operating and maintenance costs for connection and transformation equipment linking with the high-voltage transmission system as from December 1, 2017. This amendment implied a cost reduction for the Company.

2.1.6 Fuel Self-Supply for Thermal Power Plants

SGE Resolution No. 70/18, published in the BO on November 6, 2018, empowered generating, co-generating and self-generating agents within the WEM to acquire fuels, without distinction, required for own generation. This resolution superseded Section 8 of Resolution No. 95/13 of the former SE, which provided that the supply of fuels for electric power generation would be centralized in CAMMESA (with the exception of the generation covered under the Energy Plus regime). Likewise, CAMMESA remained in charge of the commercial management and the dispatch of fuel for generators which do not or cannot make use of such capacity.

Under the scheme set forth by SGE Resolution No. 70/18, the cost of generation with own fuels was valued according to the mechanism for the recognition of the Variable Production Costs recognized by CAMMESA. For implementation, maximum prices at the PIST for natural gas destined to the generation of electricity to be sold in the WEM, set by MINEM Resolution No. 46/18 and SGE Notes No. 66680075/18 and 07973690/19.

In case the generator has opted to supply its own fuel for generation and such fuel is not available at the time of dispatch, the calculation of the power capacity availability will be reduced to 50% of the actual availability. Similarly, it will lose its dispatch order, and in case the OED assigns it fuel for generation, the generated energy will be remunerated at just 50% of the approved non-fuel variable costs.

In the seasonal programming conducted on November 12, 2018, the Company has opted to make use of this self-supply capacity and has destined a significant part of its natural gas production as an input to its thermal units’ dispatch.

The scheme set forth by SGE Resolution No. 70/18 was in effect during 2019; however, on December 27, 2019, the Ministry of Productive Development passed Resolution No. 12/19, which abrogated, effective as from December 30, 2019, SGE Resolution No. 70/18, and re-established the validity of section 8 and section 4 of SE Resolutions No. 95/13 and 529/14, respectively, thus restoring the CAMMESA centralization scheme for the supply of fuels for generation purposes.

2.1.7 Agreement for the Regularization and Settlement of Receivables with the WEM

On August 5, 2019 and under the call to Generators, the Company and certain subsidiaries executed with CAMMESA an Agreement for the Regularization and Settlement of Receivables with the WEM (the “Agreement”), as instructed through SGE Note NO-2019-66843995-APN-SGE#MHA.

Pursuant to the Agreement, CAMMESA undertook to pay the outstanding LVFVDs after discounting the debts taken on with the WEM under the Financing Agreements, Loan Agreements and Receivables Assignment Agreements executed by generators, and applying a 18% write-off on the balance. In this sense, the parties have agreed a total net settlement amount for the outstanding LVFVDs taking into consideration the interest update as of July 31, 2019 and the effects of the mentioned write-off, which amounts to $ 2,122.7 million, before tax withholdings for a total amount of $ 392.9 million. Finally, on August 7, 2019, the total agreed amount was collected, net of tax withholdings, for an amount of $ 1,729.8 million (U$S 39.4 million) corresponding to outstanding LVFVDs.

In furtherance of the undertaken commitments, the Company and certain subsidiaries have waived all submitted claims and have irrevocably dismissed their rights to file any kind of claim (whether administrative and/or judicial) against the Federal Government, the SGE and/or CAMMESA regarding the outstanding LVFDVs.

As a result of the Agreement, the Company has recognized revenues in the amount of U$S 5.9 million and net financial profits for U$S 71.1 million.

2.1.8      Loosening up of charges and interests in late payment of the economic transaction

SRRYME Resolution No. 29/2019 provided for a relaxation in the application of penalty interest and charges in case of delays in the payment of economic transactions within the WEM.

i.

Reduction of surcharges: the 50% reduction in surcharges for agents with overdue and unpaid debts is postponed until April 30, 2020.

ii.

Compensatory and penalty interest: only compensatory interest will apply, with a rate equivalent to the rate fixed by the BNA for its 30-day discount transactions, for agents registering a delay in payment but having promptly paid the last three immediately preceding debt maturities, provided the payment is made within 15 days after the invoice maturity date; additionally, penalty interest of 1% will apply for each day of delay, with a cap equivalent to the surcharges provided for in the CAMMESA procedures when the payment is made after such term. It is worth highlighting that the previous scheme provided for increasing penalty interest based on the time elapsed.

            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.

2.2   Transmission

2.2.1 Tariff situation

During 2019, pursuant to the provisions of the RTI, the ENRE continued applying the semi-annual tariff update mechanism in accordance with the applicable formula, which depends on the IPIM, the IPC and the Salary Index, as long as compliance with the trigger clause is verified.

On March 22, 2019, the ENRE issued Resolutions No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 25.15% and 26.53% against the previous semester, reaching a cumulative 78.41% and 81.26% increase, respectively, for the December 2016 – December 2018 period, applicable to the remuneration scheme as from February 2019.

On September 25, 2019, the ENRE issued Resolutions No. 269/19 and No. 267/19 updating Transener and Transba’s remunerations by 18.83% and 18.81% against the previous semester, reaching a cumulative 112.41% and 115.75% increase, respectively, for the December 2016 – June 2019 period, applicable to the remuneration scheme as from August 2019.

On the other hand, on July 3, 2018, the ENRE informed the beginning of the procedure to determine the remuneration of the Independent Carriers in exploitation stage: TIBA (Transba), Fourth Line (Transener), YACYLEC and LITSA. In this regard, on October 8, 2018, the costs, investments and expected tariff corresponding to Fourth Line and TIBA were presented to the ENRE. As of the date hereof, the ENRE has not issued the resolution with the results of the analysis of the requested information.

As of the date of issuance of these Consolidated Financial Statements, the ENRE Resolution has not yet been issued with respect to the tariff update corresponding to the semester July-December 2019, applicable to the remuneration scheme as from February 2020.

2.2.2 SADI Service Outage

On June 16, 2019, at 07:07 a.m., the SADI experienced a total outage.

This total outage was a result of the concurrence of multiple shortcomings within the SADI, some of them external to the Transmission System operated and maintained by Transener.

As regards the transmission system under the responsibility of Transener, the fault was due to a specific technical problem, and not to the lack of investment and maintenance. Following the change in the configuration of the littoral corridor due to the 500 kV Colonia Elía – Campana / Colonia Elía – Manuel Belgrano lines bypass, the DAG mechanism was not properly adjusted and failed to recognize signals sent out by the protection system. This bypass was made on account of the relocation of tower 412 to support the highest possible power transmission capacity in the littoral corridor.

Due to the great volume of electricity dispatched from this corridor and the DAG failure, there was an imbalance between supply and demand which could not be redressed by the system’s other restraint barriers external to the electric power transmission service, resulting in a total outage.

The 500 kV Transmission System was available immediately after the disruption, and 100% of the transmission lines were available to come into operation and allow for the restoration of the system. Service restoration was overall fast (within 8:30 hours, 75% of the country’s demand had been restored).

Transener estimates that the above-mentioned event will give rise to a U$S 0.1 million penalty, which has been registered by Transener. This estimate is based on the application of the High-Voltage Transmission System’s Service Quality and Penalties Regime attached to Transener’s Concession Agreement as sub-annex II-B. As of the date of these Consolidated Financial Statements, the ENRE has not applied the penalty to Transener, which may differ from Transener’s estimates. 

This event will have an impact on 2020-year figures related to penalties, which will be increased, and premiums, which will be reduced, due to the Additional Service Quality and Sanctions Regime established by Resolutions No. 552/16 and No. 580/16.

2.3   Energy distribution

2.3.1 General

Edenor Concession was granted in 1992 for a 95-year term, which may be extended for an additional maximum period of 10 years. The ENRE is empowered to control the quality levels of the technical product and service, the commercial service and the compliance with public safety regulations, as provided for in the Concession Agreement. If the Distribution Company fails to comply with the obligations assumed, the ENRE may apply the penalties stipulated in the aforementioned Agreement.

2.3.2 Edenor’s economic and financial situation

In the last four years, Edenor recorded negative working capital. This situation was not reversed after the application from February 1, 2017 of the new tariff arising from RTI, due mainly to the constant increase of its operating costs, necessary to maintain the level of service, the Argentine economy’s inflationary environment, and the sustained recession since mid-2018, with the consequent impact on the decline in income, the extension of collection periods and the steady increase in levels of energy theft. (See Note 1.2).

Despite the previously described situation, it is worth pointing out that, in general terms, the quality of the electricity distribution service has been improved, both in duration and in interruption frequency. In view of the continuous increase of the costs associated with the provision of the service, as well as the need for additional investments to meet the greater seasonal demand, Edenor has taken a series of measures aimed at mitigating the negative effects of this situation on its financial structure, minimizing the impact on the sources of employment, the execution of the investment plan, and the carrying out of the essential operation, maintenance and improvement-related works that are necessary to maintain the provision of the public service, object of the concession, in a satisfactory manner in terms of quality and safety.

Additionally, on December 23, 2019, the PEN enacted Law No. 27,541, which has a direct impact on Edenor’s financial solvency.

Taking into account that the realization of the measures necessary to reverse the manifested negative trend depends on the occurrence of certain events that are not under Edenor’s control, the Edenor’s Board of Directors has raised substantial doubt about Edenor’s ability to continue as a going concern, which may result in Edenor being obliged to defer certain payment obligations or unable to meet expectations for salary increases recorded in third-party costs.

Nevertheless, the Company’s Consolidated Financial Statements have been prepared assuming that Edenor will continue to operate as a going concern, and do not include the effects of the adjustments or reclassifications that might result from the final outcome of these uncertainties.

2.3.3 Electricity rate situation

In the last days of 2019, the PEN enacted, in the framework of the Economic Emergency and as mentioned in note 1, Law No. 27,541 on Social Solidarity and Production Reactivation, pursuant to which is authorized to initiate either a renegotiation process of the tariff structure in effect or an extraordinary review, as from the date on which the law comes into effect, and for a maximum term of up to one hundred and eighty days, with the aim of reducing the actual tariff burden on households, shops and industries for 2020.

In this context, on December 27, 2019, the ENRE instructed Edenor not to apply the electricity rate schedules from January 1, 2020, resulting from the provisions of the Electricity Rate Schedules Maintenance Agreement entered into by and between Edenor and the Federal Government on September 19, 2019, as such agreement had lost its applicability due to the electricity rate emergency provided for in the aforementioned law, with the electricity rate schedule that had been approved by ENRE Resolution No. 104/19 dated April 30, 2019 remaining in effect.

The aforementioned Electricity Rate Schedules Maintenance Agreement provided for the following:

-        To maintain the electricity rate schedules that were in effect prior to August 1, 2019 for all electricity rate categories;

-        To postpone until January 1, 2020 the application of the CPD that was to be applied as from August 1, 2019 (adjustment mechanism set forth in ENRE Resolution No. 63/17), relating to the January-June 2019 period, which amounted to 19.05%;

-        To update the electricity rate schedules in relation to seasonal energy prices as from January 1, 2020;

-        To recover the difference of the CPD and the seasonal energy prices generated on August 1, 2019-December 31, 2019 period, in seven monthly and consecutive installments as from January 1, 2020, for the August 1, 2019-December 31, 2019 period, which will be recovered in seven monthly and consecutive installments as from January 1, 2020 and will be adjusted in accordance with the relevant CPD adjustment and the methodology set forth in late payment procedures applied by CAMMESA, respectively;

-        Commitment to maintain the quality of the service and meet the quality parameters set forth in the Concession Agreement;

-        To postpone until March 1, 2020 the payment by Edenor of any penalty at its original value plus the relevant adjustments applicable at the time of payment.

Additionally, and within this framework, on October 22, 2019 SRRyME Resolution No. 38/19 approved the seasonal scheduling for the November 2019 – April 2020 periods and provided as well that the power reference price, the energy reference price for residential consumers and the energy reference price for the Distribution Company’s Large Users and for the other non-residential consumers, in effect since August 2019, would remain unchanged until April 2020.

Moreover, the referred to ENRE Resolution No.104/19, approved the values of Edenor’s Electricity Rate Schedule and the electricity rate values applicable to Edenor’s self-management metering system, effective from May 1, 2019, and informed Edenor of the value of the average electricity rate as from May 1, 2019, under the terms of Energy Government Secretariat Resolution No. 366/18, which modifies the prices at which Distributors acquire energy in the MEM, and which amounts to $ 4.343/KWh.

In this framework, the provisions of Resolution No. 14/19 dated April 30, 2019 of the Electricity Market and Renewable Resources Secretariat, which, among other issues, approve the MEM definitive winter scheduling and modify the Power Reference Prices and the Stabilized Price of Energy (SPE) relating to the May 1-October 31, 2019 period, are taken into consideration.

This Resolution provides that the increases of the SPE relating to the May-October 2019 six-month period that had been authorized by Resolution 366/18 for Residential customers, are to be absorbed by the Federal Government, whereas the increases established for non-residential customers with supplies lower than 300 kW and those relating to customers with supplies higher than 300 kW, GUDI customers, were modified for the May-July and August-October 2019 three-month periods.

With regard to the supplies lower than 300 kW (non-residential customers), and those higher than 300 kW, GUDI Customers, the values of the SPE were increased for the May-July 2019 and August-October 2019 three-month periods.

The following resolutions issued by the ENRE in the months of January and February complete the 2019 regulatory context:

-        Resolution No. 25/19, which approved, under the terms of ENRE Resolution No. 366/18, the values of Edenor Electricity Rate Schedule, effective from February 1, 2019, and informed of the value of the average electricity rate as from February 1, 2019, under the terms of Energy Government Secretariat Resolution No. 366/18, which modifies the prices at which Distributors acquire energy in the MEM.

-        Resolution No. 27/19, which approved the CPD value of February 2019 together with the stimulus factor, whose application was deferred until March 2019. Additionally, it determined the value to be applied for the 36 remaining installments resulting from the gradual application system established in ENRE Resolution No. 63/17, and provided as well that the 50% of the CPD that should have been applied in August 2019 would be recovered in 6 CPD variation-adjusted installments.

With regard to the discounts under the system of caps applicable to customers benefited from the Social Tariff that the Federal Government owed to this Distributor, Edenor recorded revenue for U$S 19.4 million, considering the related peso-figures stated in constant values, relating to the December 2017-December 2018 period, as a consequence of the implementation and subsequent cancellation thereof by virtue of the Agreement on the Regularization of Obligations.

As of December 31, 2019, the Company recognized revenue from the Social Tariff for U$S 66.7 million. Additionally, Edenor has a receivable for U$S 4.2 million for the same concept.

2.3.4 Change of Jurisdiction and Regularization of Obligations

On February 28, 2019, the Federal Government, the PBA and the CABA entered into an agreement to initiate the process of transferring the public service of electricity distribution, duly awarded by the Federal Government to Edenor under a concession, to the joint jurisdiction of the PBA and the CABA, with the latter two jointly assuming the capacity as Grantor of the concession of the service. In the aforementioned agreement, the PBA and the CABA agreed to set up a new bipartite agency in charge of the regulation and control of the distribution service, and the Federal Government agreed to take the necessary steps and carry out the necessary administrative procedures to provide a solution to the pending claims with both Distribution companies.

In the framework of such agreement, on May 9, 2019, the Federal Government, the CABA and the PBA entered into an agreement, the Agreement on the Implementation of the Transfer of Jurisdiction, pursuant to which the CABA and the PBA jointly assume, as from the date on which the agreement comes into effect with the relevant ratifications, the regulation and control and the capacity as grantor over the distribution service granted to Edenor under a concession. Furthermore, it is provided that the Concession Agreement will remain in full force and effect and the national regulations and provisions issued by both the Energy Secretariat and the ENRE until the effective date of the transfer will be regarded as the applicable regulatory framework; and that the pledge of the class A shares, duly pledged as collateral to secure the performance of the obligations assumed by the Holder of the Concession and/or the majority shareholders under the Concession Agreement, is assigned on an undivided basis by the Federal Government to the CABA and the PBA.

Edenor was notified of and assented to the arrangement made by the Federal Government and the new Grantors of the concession in relation to the Transfer and the Implementation Agreements, and undertook both to indemnify them against any claims and to obtain the agreement of the majority of its shareholders. The Agreement on the Implementation of the Transfer of Jurisdiction was ratified by the Provincial Executive Power and the City’s Legislative Power by means of Executive Order No. 1,289/19 (published in the Official Gazette of the Province of Buenos Aires on October 2, 2019) and Legislative Resolution No. 161/19 (published in the Official Gazette of the CABA on July 17, 2019), respectively.

With the enactment of Law No. 27,541, the ENRE is granted jurisdiction over the public service of electricity distribution during the term the emergency law is in force.

Furthermore, within the framework of the change of jurisdiction and as a condition for the transfer, on May 10, 2019, Edenor and the Energy Government Secretariat, on behalf of the Federal Government, entered into an Agreement on the Regularization of Obligations, putting an end to the mutual pending claims originated in the 2006-2016 Transitional Tariff Period.

By virtue of this Agreement, Edenor: (i) waives any rights to which it may be entitled and abandons any actions against the Federal Government, including the complaint filed by Edenor in 2013 for failure to comply with the obligations resulting from the Agreement on the Renegotiation of the Concession Agreement (the "Adjustment Agreement”) entered into on February 13, 2006; (ii) binds itself to settle debts for works and loans for consumption (“mutuums”) originated in the transition period; (iii) undertakes to pay users certain penalty and compensation amounts relating to that period; and (iv) agrees to make investments, in addition to those agreed upon in the RTI, aimed at contributing to improving the reliability and safety of the service.

In return, the Federal Government partially recognizes the claim duly made by Edenor -referred to in caption (i) of the previous paragraph-, by fully offsetting pending obligations with the MEM for electric power purchases made during the transition period, partially cancelling the mutuums for investments granted by CAMMESA also during that period, and cancelling penalties payable to the National Treasury.

The implementation of this agreement implied, on a one-time-only basis, the partial recognition of the claim made by Edenor for an amount of $ 8,674 million as compensation for the Federal Government’s failure to comply with obligations for 10 years during the Transitional Tariff Period, as well as the adjustment of the liabilities recorded at the time of the agreement, replicating the conditions applied to all the sector’s distributors, generating a profit of $ 7,736 million. Additionally, $ 362 million from the Federal Government and $ 323 million from the Province of Buenos Aires were recognized. These effects are disclosed in the “Agreement on the Regularization of Obligations” line item of the Statement of Comprehensive Income, for U$S 285 million, considering the related peso-figures stated in constant values, and do not imply any inflow of funds whatsoever for Edenor; on the contrary, Edenor must comply in the next 5 years with the investment plan stipulated in the above-mentioned agreement, which will be aimed at contributing to the improvement of the reliability and/or safety of the service as a whole, in addition to complying with the Investment Plan duly agreed upon in the tariff structure review (RTI) approved by Resolution No. 63/17, which, together with the penalties payable to users, the settlement of liabilities for mutuums and works, and the payment of the generated income tax amount, implies an actual disbursement of funds for a total approximate amount of $ 7,600 million, in a 5-year term.

Additionally, it was agreed that the receivable amounts in favor of Edenor for the consumption of shantytowns with community meters generated from July 2017 through December 31, 2018 -exclusively with respect to the percentage undertaken by the Federal Government-, relating to the Framework Agreement for $ 470.8 million, and the receivable amount resulting from applying the cap to the bills of users benefited from the Social Tariff for $ 923 million, would be offset against both part of the debt Edenor held with CAMMESA for loans received for the carrying out of works, and the debts Edenor held with CAMMESA for the investments made in the Costanera – Puerto Nuevo – Malaver 220kV Interconnection works, carried out through the FOTAE, and for the carrying out of the Tecnópolis Substation’s works.

In this regard, and based on the terms of the second clause of the aforementioned agreement, as of December 31, 2019 Edenor recorded the update of the amounts related to “penalties to be used for investments” for a total of U$S 24.5 million, totaling a liability pending application of U$S 77.6 million, which was charged to finance interest cost.

In this framework, Edenor Extraordinary Shareholders’ Meeting dated June 10, 2019 not only ratified the actions taken by the Board of Directors in the negotiations and signing of the Agreement on the Implementation of the transfer of jurisdiction and the Agreement on the Regularization of obligations, but also approved the waiver of rights, actions and claims against the Federal Government originated in the Transitional Tariff Period, and the abandonment of the lawsuit filed in 2013 against the Federal Government.

2.3.5 Penalties

The ENRE is empowered to control the quality levels of the technical product and service, the commercial service and the compliance with public safety regulations, as provided for in the Concession Agreement. If the Distribution Company fails to comply with the obligations assumed, the ENRE may apply the penalties stipulated in the aforementioned Agreement.

As of December 31, 2019, 2018 and 2017, Edenor has recognized in its Financial Statements the penalties accrued, whether imposed or not yet issued by the ENRE, relating to the control periods elapsed as of those dates, which may differ from those that ultimately result.

Furthermore, ENRE Resolution No. 63/17 has set out the control procedures, the service quality assessment methodologies, and the penalty system, applicable as from February 1, 2017, for the 2017 – 2021 period.

In accordance with the provisions of Sub-Appendix XVI to the referred to Resolution, Edenor is required to submit in a term of 60 calendar days the calculation of global indicators, interruptions for which force majeure had been alleged, the calculation of individual indicators, and will determine the related discounts, crediting the amounts thereof within 10 business days. In turn, the ENRE will examine the information submitted by Edenor, and in the event that the crediting of such discounts were not verified will impose a fine, payable to the Federal Government, equivalent to twice the value that should have been recorded.

In this regard, the ENRE has implemented an automatic penalty mechanism in order that the discounts on account of deviations from the established limits may be credited to customers within a term of 60 days as from the end of the controlled six-month period.

The penalty system provides that penalties are updated in accordance with the variation of Distributor’s CPD or by the energy tariff average price, as the case may be.

Subsequently, in different resolutions concerning penalties relating to the commercial service and the safety on streets and public spaces, the Regulatory Entity provided for the application of increases and adjustments, applying for such purpose a criterion different from the one applied by Edenor.

Additionally, and subsequent to the Tariff Structure Review, the ENRE regulated and/or issued new penalty procedures, such as:

-      ENRE Resolution No. 118/18: It regulated the Compensation for extraordinary service provision interruptions.

-      ENRE Resolution No. 170/18: It regulated the Penalty System for Deviations from the Investment Plan, a procedure whereby real investments are assessed by comparison with the annual investment plan submitted by Edenor, and the investment plan carried out for the 5-year rate period is assessed as against the five-year period plan proposed in the RTI.

-      ENRE Resolution No. 198/18: New Supplementary Penalty Procedure of Technical Service Quality, which penalizes deviations from quality parameters at feeder level.

-      ENRE Resolution No. 91/18: Through the filing of charges, the ENRE informs Edenor about the penalty procedure to be applied for failure to comply with meter-reading and billing time periods.

-      ENRE Resolution No. 5/19: Through the filing of charges, the ENRE notifies Edenor of the penalty system to be applied for failure to comply with customer service times in commercial offices (Intelligent Routing and Consumer Service System – Sistema Inteligente de Direccionamiento y Atención de Usuarios (SIDyAA))

The effects of the resolutions detailed in this note were quantified by Edenor and recognized as of December 31, 2019, without implying consent to the criteria applied.

Finally, and in accordance with the provisions of the electricity rate schedule maintenance agreement, it is agreed that Edenor will maintain the quality of the service and comply with the quality parameters set forth in the Concession Agreement, and that the payment of any penalty will be postponed until March 1, 2020 and paid in 6 installments at its original value plus any adjustments that may apply at the time of payment.

2.3.6 Framework agreement

In 2019, Edenor and the Federal Government entered into different extension addenda to the new Framework Agreement, extending the term thereof until May 31, 2019.

Additionally, the above-mentioned addenda provided for the following:

-      The Federal Government’s commitment to settle the amounts of its economic contribution for the supply of electricity to shantytowns, after deducting the energy associated with the Social Tariff;  

-      That Edenor may assign the receivable amounts recognized by this extension to Edesur. In this regard, the relevant agreement on the assignment of receivables was signed, whereby Edesur, in consideration for the assigned receivables, paid Edenor the sole, full and final sum of $ 167.8 million.

Consequently, as of December 31, 2019 Edenor recognized revenue from the sale of electricity under the Framework Agreement until December 31, 2018 for U$S 9.9 million, and for the first five months of 2019 for U$S 3.7, both related to the Federal Government’s participation.

Furthemore, within the framework of the transfer of jurisdiction of the public service of electricity distribution that had been provided for by Law No. 27,467, the Government of the Province of Buenos Aires enacted Law No. 15,078 on General Budget, which provided that the Province of Buenos Aires would pay as from January 1, 2019 for the low-income areas and shantytowns’ consumption of electricity the same amount as that paid back in 2018, and that any amount in excess of that would have to be borne by the Municipalities in whose territories the particular shantytowns were located. Such consumption had to be previously approved by the regulatory agencies or local authorities having jurisdiction in each area. In this regard, Edenor has become aware that on November 27, 2019, the Municipality of General San Martín filed a petition for the granting of a provisional remedy with the Supreme Court claiming that the section of Law No. 15,078 that refers to this topic was unconstitutional. As of December 31, 2019, Edenor did not recognize revenue for this concept.

Finally, in view of the recent measures adopted by national and provincial authorities as of the date of issuance of these Consolidated Financial Statements, Edenor does not know which guidelines will be followed concerning the consumption of electricity by low-income areas and shantytowns relating to the periods that have not been recognized as well as future periods.

2.4.  Oil and gas

2.4.1 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:

a)    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

-      Exploration in the continental shelf and the territorial sea: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

b)   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.

c)        Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.

d)       Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

e)    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.

f)    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.

g)    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.

h)   Extends the benefits of the Investment Promotion Regime for the Exploitation of Hydrocarbon to projects involving a minimum of U$S 250 million direct investment denominated in foreign currency to be invested during its first 3 years.

2.4.2 Sale of crude oil and natural gas

In January 2017, the Federal Government executed the Agreement for the Transition to International Price in the Argentine Hydrocarbon Industry with producers and refineries of crude oil with the same purpose of generating a gradual convergence of the price of the crude oil barrel traded in Argentina towards the international price. On September 22, 2017, and as a result of fulfilling the condition that the Brent crude oil price exceeds the value of U$S 55/bbl for 10 consecutive days, the MEyM notified the suspension of the Agreement for the Transition to International Price of the Argentine Hydrocarbons Industry as from October 1, 2017. Since then, the internal price of a crude oil barrel as a refining raw material and the supplier price are determined according to the domestic market rules.

On August 15, 2019 Executive Order No. 566/19 was issued, which provided that, during a 90-day period:

-         deliveries of crude oil in the domestic market should be billed and paid applying a reference exchange rate of $ 45.19 /U$S and a reference Brent crude oil price of U$S 59/bbl

-         prices of gasoline and diesel oil sold in the domestic market may not exceed the price effective as of August 9, 2019.

-         hydrocarbon production companies, refineries, and wholesalers and retailers should meet the domestic demand of crude oil and liquid fuels, respectively, at the established prices.

On August 30, 2019, Executive Order No. 601/19 was issued, which updated the reference exchange rate set by Executive Order No. 566/19 to $ 46.69/U$S for the sale of crude oil in the domestic market, effective from its publication to November 13, 2019.

Furthermore, on September 13, 2019 SGE Resolution No. 552/19 was issued, and established a transfer of $ 116.10 per oil barrel supplied to the domestic market in the month of September 2019, 88% of which to be paid to the oil company and 12% to the province where the oil producing concession is located. The transfer request should be accompanied by waivers by the oil company and the granting province to any administrative, judicial, extrajudicial or arbitration claim, proceeding or right, in the Republic of Argentina, abroad or at the international level, associated with the application of Executive Orders No. 566/19 and No. 601/19.

Later, on September 18, 2019, Resolution No. 557/19 issued by the Ministry of Finance was published, which updated the reference exchange rate set by Executive Order No. 601/19 to $ 49.30/U$S, and allowed for an increase of up to 4% compared to the prices effective as of August 9, 2019 for all qualities of gasoline and diesel oil at points of sale, effective from its publication to November 13, 2019.

Pampa has decided not to adhere to the compensation established by SGE Resolution No. 552/19 and is currently evaluating the possible courses of action.

2.4.3 Gas Market

2.4.3.1 Natural Gas Surplus injection promotion programs

2.4.3.1.1 Gas Plan I

On February 14, 2013, Resolution No. 1/13 was published in the BO. This resolution creates the Gas Plan I, which aims to evaluate and approve projects furthering the national self-supply of hydrocarbons through a gas production into the domestic market, as well as to generate higher levels of activity, investment and employment in this sector. Gas Plan I was regulated by Resolution No. 3/13 issued by the National Plan for Hydrocarbon Investments’ Strategic Planning and Coordination Committee, (the “Committee”) and published in the BO on April 26, 2013.

Gas Plan I provides that the National Government undertakes to pay a monthly compensation resulting from: (i) the difference between the Surplus Injection price (U$S 7.5/MBTU) and the price actually collected from the sale of the Surplus Injection, plus; (ii) the difference between the Base Price and the price actually collected from the sale of the Adjusted Base Injection. These projects will be in force for a maximum term of 5 years, with the possibility for renewal.

On August 7, 2013, pursuant to Resolution No. 27/13, the Committee approved a project for an increase in the total natural gas injection submitted by former subsidiary PEPASA, with retroactive effects to March 1, 2013.

2.4.3.1.2 Gas Plan II

In November 2013, the Committee issued Resolution No. 60/13 creating Gas Plan II. Such program was directed to companies without previous production or with a maximum injection limit of 3.5 MMm3/d and included price incentives in the case of production increases, as well as penalties involving LNG imports in case of non-compliance with committed volumes. Resolution No. 60/13 (as amended by SE Resolution No. 22/14 y No. 139/14), established a price ranging from U$S 4/MBTU to U$S 7.5/MBTU, based on the highest production curve attained.

On March 6, 2014 and January 30, 2015, former subsidiaries PELSA and Petrobras were registered with this program pursuant to Resolution No. 20/14 and 13/15, respectively, of the Secretariat of Economic Policies and Development Planning of the Ministry of Economy and Public Finances, respectively.

However, the receivables registered by the Company, during 2017, under the above-mentioned natural gas surplus injection promotion programs, were not timely collected.

In this regard, on April 3, 2018, MINEM Resolution No. 97/18 was published, which approves the procedure for the cancellation of compensations pending settlement and/or the payment for the year 2017 under the above-mentioned natural gas surplus injection promotion programs. Beneficiary companies opting for the application of the procedure should state their decision to adhere within a term of twenty (20) business days, waiving all present or future administrative and/or judicial actions, remedies, rights or claims regarding the payment of obligations arising from the programs. The cancellation procedure established in the Resolution provides that the amounts will be payable in thirty equal and consecutive installments as from January 1, 2019. 

On May 2, 2018, the Group filed with the Ministry of Energy the application form to join the payment procedure set forth by MINEM Resolution No. 97/18, expressing its consent to and acceptance of its terms and scope, the amount of the compensation to the Group established by this resolution being estimated at U$S 148 million.

On February 21, 2019, SGE Resolution No. 54/19 was published, which modifies the procedure for the cancellation of compensations pending settlement and/or the payment for the year 2017 (MINEM Resolution No. 97/18), the main modification being that cancellations would be instrumented through the delivery of public debt bonds.

On April 17, 2019 and July 16, 2019, bonds were credited in favor of the Company for a face value of U$S 89 million and U$S 54 million, respectively. These bonds do not accrue interest and are repayable in 29 monthly and consecutive installments, the first one for 6.66%, the following eighteen installments for 3.33%, and the remaining ten installments for 3.34% of the original face value.

As of December 31, 2019, the Company collected U$S 36 million and U$S 21 million, respectively, as repayments, 18 installments still pending collection, which are disclosed in “Public debt securities” under “Investments at amortized cost”.

2.4.3.1.3 Unconventional Gas Plan

On March 6, 2017, MEyM Resolution No. 46-E/2017 was published, which created the Program for the Encouragement of Investments in the Development of Natural Gas Production from Unconventional Reservoirs (the “Unconventional Gas Plan”) seeking to encourage investments for the production of natural gas through unconventional methods in the Neuquén Basin and effective until December 31, 2021.

On November 2, 2017, MEyM Resolution No. 419/17 was published in the BO. This resolution amends Resolution No. 46/17 and classifies concessions into pilot and developing, with an initial production equal to or higher than 500,000 m3/day (monthly average between July 2016 and June 2017). Undeveloped concessions may obtain a guaranteed minimum price for their whole production provided they reach an annual average production equal to or higher than 500,000 m3/day during a twelve-month period by December 31, 2019. Developing concessions may only apply for the benefit for the incremental portion of their initial production. The reference price for the incentive will be calculated using the domestic market’s weighted average reported by the MEyM’s Secretariat of Hydrocarbon Resources.

On November 17, 2017, MEyM Resolution No. 447/17 was published in the BO. This resolution extends the application of the Unconventional Gas Plan created by Resolution No. 46/17 and amended by Resolution No. 419/17 to natural gas production from unconventional reservoirs in the austral basin and on January 20, 2018, MEyM Resolution No. 12/18 was published, which introduces certain modifications with the purpose of extending the Unconventional Gas Plan created by MEyM Resolution No. 46/17, as amended, for adjacent concessions operated on a joint basis.

The Company has requested the SGE to include the following exploitation projects timely approved by the provincial enforcement authority in the Unconventional Gas Plan: (i) “Río Neuquén”, filed on February 5, 2018, as owner of 33.07% of production, (ii) “El Mangrullo”, filed on July 26, 2018, as operator and owner of 100% of production; and (iii) “Sierra Chata”, filed on July 30, 2018, as operator and owner of 45.55% of production.

However, on January 30, 2019, in a meeting called by the SGE, affected gas producers (including the Company) were informed that no new projects would be approved under the Unconventional Gas Plan.

2.4.3.2 Natural Gas for the Residential Segment and CNG

2.4.3.2.1 Administration of the Priority Demand

In June, 2016, MEyM Resolution No. 89/16 was published in the BO, which established the criteria for the standardization of natural gas purchases within the PIST by distribution service providers in order to meet the Priority Demand. Additionally, criteria were established to guarantee the meeting of the Priority Demand through the CEE in case of operational emergencies which may affect its normal supply.

In June, 2017 ENARGAS Resolution No. 4,502/17 was published, which approved the procedure for dispatch administration in the CEE. In case the CEE does not reach an agreement, ENARGAS will define the supply taking into consideration each producer’s available quantities minus the amounts previously purchased to meet the Priority Demand, with a progressive allocation until matching the proportional quota of each producer/importer in the Priority Demand.

2.4.3.2.2 Natural Gas Prices within the PIST

In early January, 2018, the extension period set forth by Law No. 27,200 to the public emergency declared in 2002 terminated and, therefore, Law No. 24,076 was reinstated, which provides that the price of natural gas supply agreements will be determined by the free interaction of supply and demand. However, on account of the significant devaluation of the Argentine peso and the impossibility to transfer this new exchange rate on to final users’ tariff schemes, in early October, 2018, prices with gas distributors began to be agreed in the spot market on a daily basis.

Furthermore, ENARGAS Resolutions No. 280-289 and No. 292/18 were issued, which established, effective for a six-month period beginning October 1, 2018, the new natural gas final tariffs considering a price for natural gas as input ranging between U$S 1.74/MBTU and U$S 3.98/MBTU, including the differential tariff.

Furthermore, on November 15, 2018 Executive Order No. 1,053/18 was issued by the PEN, which established, on a one-off basis, that the National Government assumes the difference between the price of gas purchased by gas distributors and the price of gas recognized in distributors’ final tariffs for the April 2018 – March 2019 period. ENARGAS will determine the net amount, which will be transferred to each Distributor in 30 monthly and consecutive installments as from October 1, 2019 updated using the BNA’s 30-day interest rate; once an installment has been received, Distributors must immediately make the corresponding payments to gas suppliers, and must inform and credit them monthly before the ENARGAS.

On August 15, 2019, ENARGAS Resolution No. 466/2019 was published, which, together with its amending resolutions (Resolutions No. 554/19, No. 624/19 and No. 636/19), provides for the methodology to determine the amount payable by the National Government for the differences generated by exchange rate variations between the value of gas purchased by natural gas distributors and the value set in the tariff schemes effective between April 1, 2018 and March 31, 2019, pursuant to the provisions of Executive Order No. 1,053/18.

On October 25, 2019, the Company adhered to the collection procedure established by PEN Executive Order No. 1,053/18 regulated by ENARGAS Resolution No. 466/19, the net amount of the receivable pending collection by the Company and ascertained by ENARGAS Resolution No. 735/19 on November 14, 2019 reaching $ 1,219 million. As of December 31, 2019, the Company collected the first installment of U$S 0.7 million, with the 29 installments and the corresponding update still pending collection, for which it keeps a receivable of U$S 14.6 million, which is disclosed under “Trade and other receivables.”

Pampa is currently claiming to Natural Gas Distributors the payment of certain items not covered by Executive Order No. 1,053/18, including: VAT, gross receipts, Trust Fund, Withheld Gas and Unrecognized Natural Gas.

Through ENARGAS Resolutions No. 193-199, No. 201-202 and No. 205-207/19, natural gas tariff since April 2019 effective for a six-months period were established, considering a price of natural gas as a raw material ranging between U$S 2.14/MBTU and U$S 4.69/MBTU, including the differential tariff. Subsequently, 27% and 12% discounts were established in the PIST gas price for April and May 2019, respectively, through subsidies, and deferral of 22% in invoices issued between July and October 2019, to be recovered in five consecutives installments beginning December 2019.

Regarding the tariff update corresponding to October 2019, it was deferred until February 1, 2020, and provided for by Law 27,541 gas tariffs under Federal jurisdiction would remain unchanged, since December 23, 2019 and a renegotiation or extraordinary review process of the current RTI for up to 180-day term would begin.

2.4.3.3 Tender for Firm Gas Supply

By mid-February 2019, firm gas supply to distributors was auctioned. For the Northwest Basin, 9.4 and 3.8 million m3 per day were allocated for winter (April - September 2019) and summer (October 2019 - April 2020), respectively, at an average price of U$S 4,35/MBTU. And for the rest of the basins, 36.1 and 14.4 million m3 per day were allocated for winter and summer, respectively, at an average price of U$S 4,62/MBTU. Pampa took part in this auctions and was awarded.

According to ENARGAS Resolution No. 72/19, on February 12, 2019, the methodology for passing the gas price on to tariffs considers BNA’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 rates stipulated in the agreements. However, the exchange rate update applicable from October 1, 2019, was deferred and finally subject to the 180-day period from the enactment of Law No. 27,541.

2.4.3.4 Acquisition of Natural Gas for Generation

Since November 2018, the Company has opted to make use of its self-supply capacity, provided for by SGE Resolution No. 70/18, and has destined a significant part of its natural gas production to its thermal units’ dispatch (see Note 2.1.6).

On the other hand, on December 27, 2018, under a CAMMESA auction conducted for the year 2019, offers for a total 222 million m3 interruptible gas-day were received, at seasonal PIST prices with a maximum price of U$S5.2/MBTU and a minimum price of U$S3.2/MBTU for the June-August 2019 period, and with a maximum price of U$S3.7/MBTU and a minimum price of U$S2.2/MBTU for the rest of the year. For implementation of this auction, reference PIST maximum seasonal prices, based on the source basin, were considered according to SGE Note No. 66680075/18, effective as of January 2019. Pampa took part in this auction.

Finally, on December 27, 2019, the Ministry of Productive Development passed Resolution No. 12/19, which abrogated, effective as from December 30, 2019, SGE Resolution No. 70/18, thus restoring the CAMMESA centralization scheme for the supply of fuels for generation purposes.

On December 27, 2019, CAMMESA’s auction only for January 2020 took place. Offers prices for a total 260 million m³ of interruptible gas-day were received, with a weighted average PIST price of U$S 1.83/MBTU. Furthermore, on January 29, 2020, CAMMESA’s auction for February-2020 took place, on a partially firm basis. Offers prices for a total 84 million m³ of gas-day were received, with a weighted average PIST price of U$S 2.50/MBTU. Pampa took part in both auctions.

2.4.3.5 Natural Gas Exports

Through MEyM Resolution No. 104/18 and SGE Resolution No. 9/18, subsequently replaced in July 2019 by the SGE Resolution No. 417/19, a Procedure for the Authorization of Natural Gas Exports was established. Authorizations, considering in all cases the security of supply to the Argentine domestic market, may consist of short-term (up to 1 year) or long-term (1 to 10 years) exports, whether on an interruptible basis or on a firm basis for summer periods (October - April for a term of up to 5 years), or operational exchanges in emergency situations. Furthermore, in the case of projects covered by the Unconventional Gas Plan, exported natural gas may not be computed as part of and/or within the production applicable to such program. Likewise, in August 2019, through the SHC Provision No. 168/19, the terms and conditions for firm gas exports to Chile until May 15, 2020, were approved.

In December 2018 and January 2019, the Company was authorized pursuant to SGE Resolution No. 252/18 and No. 12/19 to export natural gas to Chile and Uruguay, on an interruptible basis, respectively. Furthermore, in September 2019, Pampa obtained permission to export natural gas, on a firm basis, to ENAP Refineries in Chile. Pampa took place in IESA’s auctions to export natural gas in a partially firm basis to ANCAP in Uruguay between January and April 2020, but it was not awarded.

On October 31, 2019, SSHC Resolution No. 284/19 was published in the BO, which approves the operating procedure for natural gas exports effective until September 30, 2021 seeking to:

-              ensure the security of the supply to the domestic market;

-              ascertain the scope of any need to restrict gas exports which are operationally useful in case of lack of supply to the domestic market (the “Useful Interruption”) to meet the unsatisfied domestic market demand on a certain day;

-              organize, document, and provide predictability to natural gas restriction or interruption procedures; and

-              coordinate the actions to be implemented to ensure supply to the domestic market.

Under this proceeding, the SSHC, ENARGAS, Transport Licensees and Exporters should hold weekly/bi-weekly meetings to analyze the supply domestic status and its implications in gas exports, taking into consideration the projection of the operational status of the gas transportation system and subsystems, the domestic demand, and any event involving potential drawbacks.

The procedure establishes that should the security of the supply to the domestic market be at stake, producers should adjust their exports pursuant to what is resolved under such procedure, and the mere notice of Useful Interruption served by a reliable means will entail the abide by producers.

In case of incurring higher costs for the use of alternative fuels to generate electricity by the WEM (imported LNG, coal, FO or GO), whose cost was borne by the National Government, exporters must pay compensation to CAMMESA. Through SGE Resolution No. 506/19 issued on August 29, 2019, a minimum of U$S 0.1/MBTU and a maximum of U$S 0.2/MBTU for the exported volume were set, that could be offset with receivables for gas sale in in the domestic market with CAMMESA. Such compensation would be included in WEM’s cost of energy.

It should be pointed out that from September 4, 2018 to December 31, 2020, Executive Order No. 793/18 regulated the application of a 12% export tax rate with a cap of $ 4 over each exported U$S for natural gas exports. On December 14, 2019, Executive Order No. 37/19 voided the ceiling of $ 4 for each U$S exported, established in Article 2 of Decree No. 793/18 as amended.

Law No. 27,541 authorized the PEN to modify the Export Duties corresponding to hydrocarbons sold in the external market and ratified the validity of Executive Order No. 793/18 and No. 37/19.

2.5 Gas Transportation

2.5.1 General aspect

TGS’ license has been granted for an original term of 35 years starting December 28, 1992. However, upon termination TGS may request to the ENARGAS a License extension for an additional ten-year period. Upon termination of the License’s life, whether it be 35 or 45 years, the Natural Gas Law and Executive Order No. 2,458/92 require the call for a new bid for the granting of a new license, where TGS —provided it has substantially met its obligations resulting from the License— will have the option to match the best offer received by the National Government during the bidding process.

2.5.2 TGS’s Tariff situation

2.5.2.1   Integral Agreement

On March 30, 2017, within the framework of the tariff renegotiation process, TGS executed the 2017 Integral Agreement which, after being approved by the different intervening government agencies and the National Congress, was ratified on March 27, 2018, through PEN Decree No. 250/18. This decree represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS, and thus, the final renegotiation of the license after seventeen years of negotiations.

The 2017 Integral Agreement sets the guidelines for the provision of the natural gas transportation service until the end of the License. Among these guidelines:

-        The RTI Process, which will culminate in the signing of the integral agreement, was approved. As a result of this RTI, a new tariff schedule was also approved. This new tariff schedule applicable to the Company determined a total tariff increase of 214.2% and 37%, in the event that it had been granted in a single installment as of April 1, 2017, on the tariff of the natural gas transportation service and the CAU, respectively.

-        A Five-Year Investment Plan to be executed by TGS is approved, the plan requires a high level of essential investments for the operation and maintenance of the pipeline system, to provide quality, safe and reliable service. The Five-Year Plan shall be for the period from April 1, 2017 to March 31, 2022 and will amount to $ 6,786 million (valued at December 31, 2016).

-        A non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments were approved. This adjustment must be approved by ENARGAS and for its calculation, the evolution of the WPI published by INDEC will be considered.

-        TGS and its shareholders must withdraw any claim against the Government related to the natural gas transportation business, including the arbitration proceedings before the ICSID. The Company desisted from it on June 26, 2018.

As it is mentioned above the tariff increase was granted in 3 installments according to the following resolutions:

-        Effective as of April 1, 2017, 64.2% of the tariff for the natural gas transport service, the CAU not being adjusted, in accordance with the provisions of Resolution No. 4,362/17.

-        Effective as of December 1, 2017, after the issuance of Resolution No. 120/17, 81.1% on the tariff for the natural gas transport service and 29.7% on the CAU, which includes the first adjustment by WPI.

-        Effective as of April 1, 2018, an increase of 50% over the tariff for the natural gas transport service and the CAU within the framework of the provisions of Resolution No. 310/18 issued by the ENARGAS.

2.5.2.2 Semi-annual tariff increase

This increase is granted within the framework of the semi-annual tariff adjustment of the natural gas transportation service in accordance with the provisions of the RTI process.

In the public hearing held on September 4, 2018, in which the Company requested, based on the variation of the WPI 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 WPI, the Construction Cost Index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018.

It is noteworthy that 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 WPI to determine the tariff increase. TGS notified ENARGAS 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 has 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 SGE issued Resolution No. 521/19, later amended by Resolution No. 751/19, which postpones its application until February 1, 2020.

This deferral will result in TGS having to review and adjust, in the same proportion as the foregone income, the execution of the Five-Year Investment Plan. As of the issuance of these Consolidated Financial Statements, TGS has submitted the works adjustment proposal to ENARGAS, without the corresponding approval resolution being issued as of the date hereof.

However, the Law No. 27.541 provides that natural gas transportation and distribution tariffs will remain unchanged for a maximum term of 180 days as from December 23, 2019. In this sense, the PEN is vested with the power to renegotiate them, whether under the current RTI or through an extraordinary review pursuant to the provisions of the Natural Gas Law.

As of the date of issuance of these Consolidated Financial Statements, there has not been any administrative actions to regularize the TGS’s rate situation.

Additionally, the Law No. 27.541 provides for the administrative intervention of the ENARGAS.

2.5.2.3 Collection Deferrals

On June 21, 2019, the SGE issued Resolution No. 336/19, which provided for a 22% payment deferral in bills issued from July 1, 2019 to October 31, 2019 for services provided to natural gas residential users.

The described deferrals will be recoverable in bills issued as from December 1, 2019 in five monthly, equal and consecutive installments. As compensation, the National Government will pay licensees an economic compensation, in the form of a subsidy, for the financial cost resulting from the deferral.

On August 22, 2019, the SGE issued Resolution No. 488/19 establishing the procedure for the calculation applicable by natural gas distributors and subdistributors of the deferral provided for by Resolution No. 336/19. Furthermore, this resolution instructs the Undersecretariat of Hydrocarbon and Fuels to implement the procedure to be used for the calculation and payment of the previously mentioned compensation. As of the issuance of these Consolidated Financial Statements, no regulations for the calculation and methodology applicable to the payment of the above-mentioned economic compensation have been passed.

As of December 31, 2019, TGS’ sales receivables from natural gas distributors amount to $ 1,206 million under these items.

2.5.2.4 Non-regulated segments

2.5.2.4.1 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 SRH (former Secretary of Hydrocarbon Resources), that sets 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 by the SRH. 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 marketing 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.

After successive modifications and pursuant to Provision No. 104/19 issued by the Undersecretariat of Hydrocarbons and Fuels, the current price for butane and propane sold under this program amounts to $ 9,895 and $ 9,656 per ton, respectively. No compensation has been set for these products.

In this context, 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 by which it undertakes to supply propane to the domestic market 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 MINEM.

Within the gradual subsidies reduction path granted by MINEM, on March 31, 2017, the MINEM issued Resolutions No. 74 and No. 474/17 that stipulate increases in the price of undiluted propane gas destined to the Propane for Networks Agreement as of April 1 and December 1, 2017, respectively.

From those dates onwards, the price of undiluted propane gas has been set at $ 1,267/tn and $ 2,832/tn and $ 1,941.20/tn and $ 3,964/tn, respectively, depending on the client to whom the undiluted propane gas is delivered.

Finally, in May 2018, TGS initiated the sixteenth extension by which the methodology for determining the price and volumes for the period April 1, 2018 - December 31, 2019 is established. Additionally, this last extension established the propane sale price to customers under this program. Notwithstanding the foregoing, on January 14, 2020 TGS received an instruction issued by the SE to proceed with propane deliveries in accordance with set conditions by the sixteenth extension, also indicating that the SE is working on the extension of the terms of the agreement at least until June 30, 2020.

During 2019 and 2018, TGS received the amount of $ 469 million and $ 626 million, for subsidies for the programs mentioned above, respectively.

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, 2019, the Argentine Government owes TGS $ 144 million under these items.

2.5.2.4.2 Foreign market

On September 3, 2018, the Executive Branch issued Decree No. 793/18, which, between September 4, 2018 and December 31, 2020, sets an export duty of 12% on the exported amount of propane, butane and natural gasoline. This withholding is capped at $4 for each dollar of the tax base or the official FOB price.

Later, as a result of the enactment Law No. 27,541, an 8% cap was set for the rate applicable to hydrocarbons effective as from December 23, 2019.

2.6 Tax reform

On December 29, 2017 the PEN issued Law No. 27,430 that introduced several modifications in tax treatment, the key components of which are described below:

2.6.1 Income tax

2.6.1.1 Income tax rate

According to Law No. 27,430, the income tax rate for Argentine companies will be gradually reduced from 35% to 30% for fiscal years beginning as from January 1, 2018 until December 31, 2019, and to 25% for fiscal years beginning as from January 1, 2020.

However, Law No. 27,541 suspended the reduction in the rate projected for fiscal years beginning on or after January 1, 2021, providing that during the suspension period the tax rate will remain at 30%.

The effect of the application of the income tax rate changes on deferred tax assets and liabilities pursuant to the above-mentioned tax reform was recognized, based on their expected realization year, in “Effect of tax rate change in the deferred tax” under Income tax and Minimum notional income tax of the Consolidated Statement of Comprehensive Income (Note 10.6).

2.6.1.2 Tax on dividends

According to Law No. 27,430, the tax on dividends or earnings distributed by, among others, Argentine companies or permanent establishments to individuals, undivided estates or beneficiaries residing abroad is introduced based on the following considerations: (i) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2018 until December 31, 2019, will be subject to a 7% withholding; and (ii) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2020 will be subject to a 13% withholding.

Pursuant to the suspension of the Income Tax rate provided for by Law No. 27,541, the 7% withholding will remain in effect for fiscal years beginning on or before January 1, 2021.

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 Transfer prices

Controls are established for the import and export of goods through international intermediaries different from the exporter at the point of origin or the importer at destination.

Furthermore, the Law sets out the obligation to provide documentation allowing for the verification of the characteristics of the transaction for the import and export of goods and the export of commodities, in both cases when they are conducted through an international intermediary different from the exporter at the point of origin or the importer at destination.

2.6.1.4 Optional Tax revaluation

Law No. 27,430 provides that Companies may opt to make a tax revaluation of assets located in the country and subject to the generation of taxable earnings existing as of December 31, 2017. The special tax on the revaluation amount depends on the asset, and will amount to 8% for real estate not accounted for as inventories, 15% for real estate accounted for as inventories, and 10 % for personal property and the remaining assets. Once the option is exercised for a certain asset, all assets within the same category should be revalued.

The tax result from the revaluation will not be subject to income tax, and the special tax on the amount of the revaluation will not be deductible from such tax.

Several regulations (Decrees No. 353/18, No. 613/18 and No. 143/19 and AFIP General Resolution No. 4,287), have repeatedly postponed the date for exercising this option based on the international context and the greater volatility in financial variables affecting decision-making regarding the exercise of the option.

On March 27, 2019, Pampa and CPB, based on their evaluation of the domestic context and the evolution of financial variables (including the inflation rate), exercised their option to adhere to the tax revaluation regime on their property, plant and equipment existing as of December 31, 2017 pursuant to Title X of Law No. 27,430, the tax cost of such property thus increasing to $ 15,311 million.

On exercising this option, Pampa and CPB have paid the special tax for a principal amount of U$S 34.5 million plus interest for U$S 1 million.

Additionally, Pampa and CPB had to waive all lawsuits and rights invoked in any previously brought judicial or administrative proceedings seeking the application of updating mechanisms on the income tax (see Notes 11.6.1 and 15.2). Furthermore, Pampa and CPB had to waive their rights to initiate any judicial or administrative proceeding seeking the application of such updating mechanisms regarding fiscal years ended before December 31, 2017.

2.6.1.5 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 IPC 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 one hundred percent (100%) over the thirty-six (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 fifty-five percent (55%), thirty percent (30%) and fifteen percent (15%) for the years 2018, 2019 and 2020, respectively.

Law No. 27,541 provides 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 (1/6) should be charged in that fiscal period and the remaining five sixths (5/6), in equal parts, in the five immediately following fiscal periods.

As of the end of fiscal year 2018, an accumulated variation in the price index exceeding the foreseen 55% condition for the application of the comprehensive adjustment in such first fiscal year was not evidenced. However, the costs of goods acquired during fiscal year 2018 have been adjusted in accordance with the procedure stated in subsection (i).

As of December 31, 2019, the cumulative variation in the IPC exceeds the 30% condition set for the second transition year, and, therefore, the Group has applied the tax inflation adjustment in the calculation of the current and deferred income tax provision, except for the Company and its subsidiary PEFM, which, taking into consideration the merger process described in Note 5.1.1.2, have not exceeded the established legal parameter for the interim six-month period ended on June 30, 2019.

2.6.2 Value-added tax

A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity.

2.6.3 Fuel tax

Certain modifications are introduced to the fuel tax, incorporating a tax on the emission of carbon dioxide. Tax on Fuels comprises the Tax on Liquid Fuels ("ICL") and the Carbon Dioxide Tax ("IDC"). The reform simplifies the fuel taxation structure, keeping the same tax burden effective prior to the reform.

By means of Law No. 27,430, subsection c) of Section 7 of Chapter I of Title III of Law No. 23,966 was modified, establishing the fuel tax exemption for the transfers of certain taxable products used as raw material in petrochemical processes. Later, Decree No. 501/18, regulated Law No. 23,966 and established that transfers of virgin naphtha and pyrolysis gasoline are exempted from the fuel tax when are destined to a petrochemical catalytic reform process.

This regulatory modification allowed a significant financial saving for the Company as a consequence of the tax exemption on the purchase of virgin naphtha as raw material.

2.6.4 Regularization regime (Moratorium)

Between the 29 and the 31 of March 2017, the Company adhered to the regularization regime (moratorium) provided for Law No. 27,260 in relation to certain tax claims and provisions. The Company related liabilities were mainly attributable to contingencies identified in Petrobras’s acquisition process including interpretation differences with the Argentine tax authority regarding i) the time of recording well abandonment expenses for income tax purposes, ii) the exemption from the Tax on Personal Assets as Substitute Taxpayer for the shareholder PPSL; iii) the Tariff heading used by the Company for certain exported products; and iv) inaccurate customs regarding the importation of a turbine supplied by Siemens Germany, including certain spare parts that had not been required nor declared by the Company. In relation to the last matter described before, the Company entered into an agreement with Siemens pursuant to which Pampa received the reimbursement of related incurred costs.

As the adhesion to the regularization regime established benefits of releasing tax fines and reducing compensatory interests, the Company has recorded, during 2017 fiscal year, a net gain after income tax effects of U$S 14.8 million. 

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5. GROUP STRUCTURE (Details 3)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Subsidiary 1
Disclosure of subsidiaries [line items]
Subsidiary name	Corod	Corod
Country	Argentina	Argentina
Main activity	Oil	Oil
Direct and indirect participation	100.00%	100.00%
Subsidiary 2
Disclosure of subsidiaries [line items]
Subsidiary name	CPB	CPB
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	100.00%	100.00%
Subsidiary 3
Disclosure of subsidiaries [line items]
Subsidiary name	CPB Energía S.A.	CPB Energía S.A.
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	100.00%	100.00%
Subsidiary 4
Disclosure of subsidiaries [line items]
Subsidiary name	EcuadorTLC	EcuadorTLC
Country	Ecuador	Ecuador
Main activity	Oil	Oil
Direct and indirect participation	100.00%	100.00%
Subsidiary 5
Disclosure of subsidiaries [line items]
Subsidiary name	Edenor	Edenor
Country	Argentina	Argentina
Main activity	Distribution of energy	Distribution of energy
Direct and indirect participation	56.32%	52.18%
Subsidiary 6
Disclosure of subsidiaries [line items]
Subsidiary name	Enecor S.A.	Enecor S.A.
Country	Argentina	Argentina
Main activity	Transportation of electricity	Transportation of electricity
Direct and indirect participation	69.99%	69.99%
Subsidiary 7
Disclosure of subsidiaries [line items]
Subsidiary name	HIDISA	HIDISA
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	61.00%	61.00%
Subsidiary 8
Disclosure of subsidiaries [line items]
Subsidiary name	HINISA	HINISA
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	52.04%	52.04%
Subsidiary 9
Disclosure of subsidiaries [line items]
Subsidiary name	PACOSA	PACOSA
Country	Argentina	Argentina
Main activity	Trader	Trader
Direct and indirect participation	100.00%	100.00%
Subsidiary 10
Disclosure of subsidiaries [line items]
Subsidiary name	PEA	PEA
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	0.00%	100.00%
Subsidiary 11
Disclosure of subsidiaries [line items]
Subsidiary name	PEB	PEB
Country	Bolivia	Bolivia
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 12
Disclosure of subsidiaries [line items]
Subsidiary name	PACOGEN	PACOGEN
Country	Argentina	Argentina
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 13
Disclosure of subsidiaries [line items]
Subsidiary name	PEFM	PEFM
Country	Argentina	Argentina
Main activity	Generation	Generation
Direct and indirect participation	0.00%	100.00%
Subsidiary 14
Disclosure of subsidiaries [line items]
Subsidiary name	Petrobras Energía Colombia Gran Cayman	Petrobras Energía Colombia Gran Cayman
Country	Colombia	Colombia
Main activity	Oil	Oil
Direct and indirect participation	0.00%	100.00%
Subsidiary 15
Disclosure of subsidiaries [line items]
Subsidiary name	Petrobras Energía Ecuador	Petrobras Energía Ecuador
Country	Gran Cayman	Gran Cayman
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 16
Disclosure of subsidiaries [line items]
Subsidiary name	Energía Operaciones ENOPSA S.A.	Energía Operaciones ENOPSA S.A.
Country	Ecuador	Ecuador
Main activity	Oil	Oil
Direct and indirect participation	100.00%	100.00%
Subsidiary 17
Disclosure of subsidiaries [line items]
Subsidiary name	Petrolera San Carlos S.A.	Petrolera San Carlos S.A.
Country	Venezuela	Venezuela
Main activity	Oil	Oil
Direct and indirect participation	100.00%	100.00%
Subsidiary 18
Disclosure of subsidiaries [line items]
Subsidiary name	PHA	PHA
Country	Argentina	Argentina
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 19
Disclosure of subsidiaries [line items]
Subsidiary name	PISA	PISA
Country	Uruguay	Uruguay
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 20
Disclosure of subsidiaries [line items]
Subsidiary name	PP	PP
Country	Argentina	Argentina
Main activity	Investment	Investment
Direct and indirect participation	0.00%	100.00%
Subsidiary 21
Disclosure of subsidiaries [line items]
Subsidiary name	PPSL	PPSL
Country	Spain	Spain
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 22
Disclosure of subsidiaries [line items]
Subsidiary name	TGU	TGU
Country	Uruguay	Uruguay
Main activity	Gas transportation	Gas transportation
Direct and indirect participation	100.00%	100.00%
Subsidiary 23
Disclosure of subsidiaries [line items]
Subsidiary name	Transelec	Transelec
Country	Argentina	Argentina
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 24
Disclosure of subsidiaries [line items]
Subsidiary name	Trenerec Energía Bolivia S.A.	Trenerec Energía Bolivia S.A.
Country	Bolivia	Bolivia
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%
Subsidiary 25
Disclosure of subsidiaries [line items]
Subsidiary name	Trenerec S.A.	Trenerec S.A.
Country	Ecuador	Ecuador
Main activity	Investment	Investment
Direct and indirect participation	100.00%	100.00%

XML

14. STATEMENT OF CASH FLOWS COMPLEMENTARY INFORMATION (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Significant non-cash transactions from continued operations:
Acquisition of property, plant and equipment through an increase in trade payables	$ (45)	$ 17	$ (103)
Borrowing costs capitalized in property, plant and equipment	(17)	(7)	(16)
Decreases of property, plant and equipment through an increase in other receivables	0	12	0
Agreement on the regularization of obligations	285	0	0
Increase in asset retirement obligation provision through an increase in property, plant and equipment	1	34	(2)
Constitution of guarantee of derivative financial instruments, net through the delivery of financial assets at fair value through profit or loss	3	(22)	19
Cancellation of other credits for capital contributions in associates	(17)	0	0
Compensation of investments at a cost cost through the transfer of other credits	(126)	0	0
Loan compensation through the transfer of sales credits	135	0	0
Increase of right-of-use assets through an increase in other debts	20	0	0
Significant non-cash transactions from discontinued operations:
Credit pending collection for sale of property, plant and equipment	$ 0	$ 0	$ 15

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12. FINANCIAL ASSETS AND LIABILITIES (Details 12) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	$ 388	$ 419
Total assets	1,231	1,604
Total liabilities	2,365	2,803
Level 1
Disclosure of financial assets [line items]
Investment funds	4
Derivative financial instruments	0
Other receivables	4	3
Total assets	373	408
Derivative financial instruments	0	0
Total liabilities	0	0
Level 2
Disclosure of financial assets [line items]
Investment funds	0
Derivative financial instruments	4
Other receivables	0	0
Total assets	4	0
Derivative financial instruments	3	1
Total liabilities	3	1
Level 3
Disclosure of financial assets [line items]
Investment funds	0
Derivative financial instruments	0
Other receivables	0	0
Total assets	11	11
Derivative financial instruments	0	0
Total liabilities	0	0
Total
Disclosure of financial assets [line items]
Investment funds	4
Derivative financial instruments	4
Other receivables	4	3
Total assets	388	419
Derivative financial instruments	3	1
Total liabilities	3	1
Government securities
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	113	298
Government securities | Level 1
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	113	298
Government securities | Level 2
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	0	0
Government securities | Level 3
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	0	0
Shares
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	19	12
Shares | Level 1
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	8	1
Shares | Level 2
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	0	0
Shares | Level 3
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	11	11
Investment funds
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	244	106
Investment funds | Level 1
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	244	106
Investment funds | Level 2
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	0	0
Investment funds | Level 3
Disclosure of financial assets [line items]
Financial assets at fair value through profit and loss	$ 0	$ 0

XML

5. GROUP STRUCTURE (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of joint ventures [line items]
Share capital	$ 46	$ 50
Profit (loss) for the year	800	287	$ 378
Total equity	$ 2,409	$ 1,795	$ 1,969	$ 1,607
Joint Venture 1
Disclosure of joint ventures [line items]
Joint venture name	CIESA
Main activity	Investment
Share capital	$ 11
Profit (loss) for the year	109
Total equity	$ 405
Direct and indirect participation	50.00%
Joint Venture 2
Disclosure of joint ventures [line items]
Joint venture name	Citelec
Main activity	Investment
Share capital	$ 9
Profit (loss) for the year	38
Total equity	$ 176
Direct and indirect participation	50.00%
Joint Venture 3
Disclosure of joint ventures [line items]
Joint venture name	Greenwind
Main activity	Generation
Share capital	$ 0
Profit (loss) for the year	(1)
Total equity	$ (11)
Direct and indirect participation	50.00%
Joint Venture 4
Disclosure of joint ventures [line items]
Joint venture name	CTB
Main activity	Generation
Share capital	$ 143
Profit (loss) for the year	40
Total equity	$ 227
Direct and indirect participation	50.00%
Associate 1
Disclosure of joint ventures [line items]
Associate name	Refinor
Main activity	Refinery
Share capital	$ 2
Profit (loss) for the year	(3)
Total equity	$ 57
Direct and indirect participation	28.50%
Associate 2
Disclosure of joint ventures [line items]
Associate name	OCP
Main activity	Investment
Share capital	$ 100
Profit (loss) for the year	22
Total equity	$ 266
Direct and indirect participation	15.91%
Associate 3
Disclosure of joint ventures [line items]
Associate name	TGS
Main activity	Transport of gas
Share capital	$ 13
Profit (loss) for the year	214
Total equity	$ 803
Direct and indirect participation	27.19%

XML

17. RELATED PARTIES TRANSACTIONS (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	$ 86	$ 200	$ 103
Greenwind
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	(1)	0	0
OCP
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	0	(7)	0
SACDE
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	1	0	0
Foundation
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	(2)	(2)	(1)
Total related parties
Disclosure of transactions between related parties [line items]
Other operating income (expenses), net	$ (2)	$ (9)	$ (1)

XML

10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfExplorationExpensesLineItems [Line Items]
Exploration expenses	$ 9	$ 1	$ 2
Geological and geophysical expenses
DisclosureOfExplorationExpensesLineItems [Line Items]
Exploration expenses	4	0	1
Decrease in unproductive wells
DisclosureOfExplorationExpensesLineItems [Line Items]
Exploration expenses	$ 5	$ 1	$ 1

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 4) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about intangible assets [line items]
Intangible assets	$ 151	$ 161
Concession agreements
Disclosure of detailed information about intangible assets [line items]
Intangible assets	111	121
Goodwill
Disclosure of detailed information about intangible assets [line items]
Intangible assets	35	35
Intangibles identified in acquisitions of companies
Disclosure of detailed information about intangible assets [line items]
Intangible assets	$ 5	$ 5

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	$ 4,868	$ 4,317
Increases	591	665
Impairment	(112)	(56)
Transfers	0	0
Decreases	(40)	(58)
Translation effect	(73)	0
Property, plant and equipment, ending	5,234	$ 4,868
Land
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	22
Increases	0
Impairment	0
Transfers	0
Decreases	(8)
Translation effect	0
Property, plant and equipment, ending	14
Buildings
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	207
Increases	1
Impairment	(8)
Transfers	4
Decreases	(1)
Translation effect	(1)
Property, plant and equipment, ending	202
Equipment and machinery
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	1,051
Increases	1
Impairment	(90)
Transfers	297
Decreases	(5)
Translation effect	0
Property, plant and equipment, ending	1,254
High, medium and low voltage lines
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	1,010
Increases	3
Impairment	0
Transfers	72
Decreases	(4)
Translation effect	(32)
Property, plant and equipment, ending	1,049
Substations
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	365
Increases	0
Impairment	0
Transfers	14
Decreases	0
Translation effect	(12)
Property, plant and equipment, ending	367
Transforming chamber and platforms
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	208
Increases	4
Impairment	0
Transfers	15
Decreases	(1)
Translation effect	(7)
Property, plant and equipment, ending	219
Meters
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	209
Increases	1
Impairment	0
Transfers	23
Decreases	0
Translation effect	(7)
Property, plant and equipment, ending	226
Wells
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	562
Increases	24
Impairment	0
Transfers	94
Decreases	(8)
Translation effect	0
Property, plant and equipment, ending	672
Mining property
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	267
Increases	0
Impairment	(14)
Transfers	0
Decreases	0
Translation effect	0
Property, plant and equipment, ending	253
Vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	22
Increases	1
Impairment	0
Transfers	0
Decreases	0
Translation effect	(1)
Property, plant and equipment, ending	22
Furniture, fittings and communication equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	67
Increases	4
Impairment	0
Transfers	4
Decreases	0
Translation effect	(1)
Property, plant and equipment, ending	74
Communication equipments
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	15
Increases	0
Impairment	0
Transfers	0
Decreases	0
Translation effect	0
Property, plant and equipment, ending	15
Materials and spare parts
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	32
Increases	19
Impairment	0
Transfers	(14)
Decreases	0
Translation effect	0
Property, plant and equipment, ending	37
Distribution storage center
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	10
Increases	0
Impairment	0
Transfers	0
Decreases	(10)
Translation effect	0
Property, plant and equipment, ending	0
Petrochemical Industrial Complex
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	15
Increases	0
Impairment	0
Transfers	(1)
Decreases	0
Translation effect	0
Property, plant and equipment, ending	14
Work in progress
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	783
Increases	510
Impairment	0
Transfers	(487)
Decreases	(3)
Translation effect	(11)
Property, plant and equipment, ending	792
Advances to suppliers
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	19
Increases	23
Impairment	0
Transfers	(23)
Decreases	0
Translation effect	(1)
Property, plant and equipment, ending	18
Other goods
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning	4
Increases	0
Impairment	0
Transfers	2
Decreases	0
Translation effect	0
Property, plant and equipment, ending	$ 6

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8. REVENUE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfRevenueLineItems [Line Items]
Revenue	$ 2,836	$ 2,920	$ 2,175
Generation
DisclosureOfRevenueLineItems [Line Items]
Revenue	819	604	351
Generation | Energy sales to the Spot Market
DisclosureOfRevenueLineItems [Line Items]
Revenue	251	274	231
Generation | Energy sales by supply contracts
DisclosureOfRevenueLineItems [Line Items]
Revenue	285	278	114
Generation | Fuel self-supply
DisclosureOfRevenueLineItems [Line Items]
Revenue	281	51	4
Generation | Other sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	2	1	2
Distribution
DisclosureOfRevenueLineItems [Line Items]
Revenue	1,502	1,484	1,050
Distribution | Energy sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	1,496	1,477	1,042
Distribution | Right of use of poles
DisclosureOfRevenueLineItems [Line Items]
Revenue	5	5	6
Distribution | Connection and reconnection charges
DisclosureOfRevenueLineItems [Line Items]
Revenue	1	2	2
Oil and gas
DisclosureOfRevenueLineItems [Line Items]
Revenue	174	458	443
Oil and gas | Other sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	3	4	25
Oil and gas | Oil, Gas and liquid sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	171	454	418
Holding and others
DisclosureOfRevenueLineItems [Line Items]
Revenue	20	338	314
Holding and others | Other sales
DisclosureOfRevenueLineItems [Line Items]
Revenue		36	17
Holding and others | Technical assistance services and administartion sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	20	36	17
Petrochemicals
DisclosureOfRevenueLineItems [Line Items]
Revenue	321	2,920	2,175
Petrochemicals | Petrochemicals sales
DisclosureOfRevenueLineItems [Line Items]
Revenue	$ 321	$ 338	$ 314

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 8) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfProvisionsLineItems [Line Items]
Provisions, non current	$ 145	$ 146
Provisions, current	20	23
Provisions for contingencies
DisclosureOfProvisionsLineItems [Line Items]
Provisions, non current	123	125
Provisions, current	16	17
Asset retirement obligation and dismantling of wind turbines
DisclosureOfProvisionsLineItems [Line Items]
Provisions, non current	20	20
Provisions, current	2	2
Environmental remediation
DisclosureOfProvisionsLineItems [Line Items]
Provisions, non current	1	1
Provisions, current	2	4
Other provisions
DisclosureOfProvisionsLineItems [Line Items]
Provisions, non current	1	0
Provisions, current	$ 0	$ 0

XML

10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Items Of Statement Of Comprehensive Income
Profit (loss) before income tax	$ 848	$ 224	$ 402
Current tax rate	30.00%	30.00%	35.00%
Result at the tax rate	$ 254	$ 67	$ 141
Share of profit of associates and joint ventures	(25)	(3)	(117)
Non-taxable results	(38)	7	(59)
Effects of exchange differences and traslation effect of property, plant and equipment and intangible assets, net	93	0	0
Adjustment of valuation of property, plant and equipment and intangible assets	(202)	0	0
Gain (loss) on monetary position	17	(38)	66
Effect of tax rate change in deferred tax	37	(26)	(21)
Adjustment effect for tax inflation	129	0	0
Payment of optional tax revaluation	34	0	0
Special tax, revaluation of property, plant and equipment	(169)	0	0
Difference in the estimate of previous fiscal year income tax and the income tax statement	(86)	4	(20)
Deferred tax not previously recognized	0	4	(31)
Non-deductible costs	0	0	9
Non-deductible provisions	0	0	5
Other	4	2	1
Income tax expense (benefit)	$ 48	$ 17	$ (26)

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12. FINANCIAL ASSETS AND LIABILITIES (Details 11) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about financial instruments [line items]
Interest income	$ 96	$ 99	$ 62
Interest expense	(295)	(311)	(228)
Foreign exchange, net	(75)	(863)	(156)
Results from financial instruments at fair value	91	64	62
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results	39	10	(4)
Total	(90)	(1,075)	(270)
Financial assets/liabilities at amortized cost
Disclosure of detailed information about financial instruments [line items]
Interest income	93	94	55
Interest expense	(275)	(289)	(217)
Foreign exchange, net	(92)	(865)	(191)
Results from financial instruments at fair value	0	0	0
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results	37	12	(2)
Total	(183)	(1,122)	(361)
Financial assets/liabilities at fair value through profit and loss
Disclosure of detailed information about financial instruments [line items]
Interest income	3	5	7
Interest expense	0	0	0
Foreign exchange, net	14	86	49
Results from financial instruments at fair value	91	64	62
Gains (losses) from present value measurement	0	0	0
Other financial results	0	0	0
Total	108	155	118
Subtotal financial assets/liabilities
Disclosure of detailed information about financial instruments [line items]
Interest income	96	99	62
Interest expense	(275)	(289)	(217)
Foreign exchange, net	(78)	(779)	(142)
Results from financial instruments at fair value	91	64	62
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results	37	12	(2)
Total	(75)	(967)	(243)
Non Financial assets/liabilities
Disclosure of detailed information about financial instruments [line items]
Interest income	0	0	0
Interest expense	(20)	(22)	(11)
Foreign exchange, net	3	(84)	(14)
Results from financial instruments at fair value	0	0	0
Gains (losses) from present value measurement	0	0	0
Other financial results	2	(2)	(2)
Total	$ (15)	$ (108)	$ (27)

XML

4. ACCOUNTING POLICIES (Details) $ in Millions	Dec. 31, 2018 USD ($)
Accounting Policies
Operating lease commitments	$ 10.5
Discount using incremental borrowing rate of 58.16% as of 01.01.2019	(2.4)
Exchange differences on translation	(0.1)
Lease liability	$ 8.0

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Financial Assets And Liabilities
Allowance for the impairment of trade receivables, beginning	$ 34	$ 21	$ 21
Allowance for impairment	23	34	13
Utilizations	(13)	(10)	(3)
Reversal of unused amounts	(2)	(1)	0
Exchange differences on translation	(1)	0	0
Reclassification to assets held for sale	0	0	(5)
Gain on monetary position, net	(8)	(15)	(5)
Allowance for the impairment of trade receivables, ending	$ 33	$ 34	$ 21

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 7) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Financial Assets And Liabilities
Borrowings, beginning	$ 2,177	$ 1,683	$ 1,269
Proceeds from borrowings	556	245	1,250
Payment of borrowings	(550)	(240)	(733)
Accrued interest	185	179	143
Payment of borrowings' interests	(148)	(133)	(108)
Net foreign currency exchange difference	50	1,244	227
Results for the repurchase of corporate bonds	(27)	(2)	0
Costs capitalized in property, plant and equipment	17	8	14
Decrease through offsetting with trade receivables	(135)	0	0
Gain on net monetary position, net	(88)	(795)	(379)
Repurchase and redemption of corporate bonds	(91)	(13)	(1)
Other financial results	1	1	1
Borrowings, ending	$ 1,947	$ 2,177	$ 1,683

XML

18. LEASES (Tables)

12 Months Ended

Dec. 31, 2019

Leases

Right of use assets

Original values
Type of good	At the beginning	Increase	At the end
		(1)
Machinery and equipment	-	13	13
Buildings	-	7	7
Total at 12.31.2019	-	20	20
	Depreciation
Type of good	At the beginning	For the year	At the end
Machinery and equipment	-	(2)	(2)
Buildings	-	(2)	(2)
Total at 12.31.2019	-	(4)	(4)
	Net book values
Type of good	At the end
Machinery and equipment	11
Buildings	5
Total at 12.31.2019	16

⁽¹⁾ Includes U$S 8 million incorporated as of January 1, 2019 on the adoption of IFRS 16 (see Note 4.1.1)

Lease liabilities

	12.31.2019
At the beginning of the year	-
Incorporation by adoption of IFRS 16	8
Increases	13
Discounted value measurement (1)	3
Payments	(5)
Exchange differences on translation	(3)
At the end of the year	16

⁽¹⁾ Included in the “Gains (losses) from present value measurement” under Other financial results

Lease liabilities payments by maturity

	12.31.2019
Less than three months	1
Three months to one year	4
One to two years	4
Two to three years	2
Three to four years	1
Four to five years	1
More than five years	16
Total	29

Lease receivables by maturity

	12.31.2019
Less than three months	2
Three months to one year	6
One to two years	7
Two to three years	7
Three to four years	7
Four to five years	7
More than five years	12
Total	48

Future minimum collections from operating leases

	12.31.2019	12.31.2018
2019	-	5
2020	5	-
Total future minimum lease collections	5	5

XML

6. RISKS (Details 5) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	$ 544	$ 877
Borrowings	2,638	2,541
Total	3,182	3,418
Less than three months
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	0	331
Borrowings	95	112
Total	95	443
Three months to one year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	454	534
Borrowings	188	318
Total	642	852
One to two years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	11	9
Borrowings	288	242
Total	299	251
Two to five years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	70	3
Borrowings	834	892
Total	904	895
More than five years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Trade and other payables	9	0
Borrowings	1,233	977
Total	$ 1,242	$ 977

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfFinancialAssetsAtAmotizedCostLineItems [Line Items]
Non current financial assets at amortized cost	$ 18	$ 0
Current financial assets at amortized cost	54	35
Time deposits
DisclosureOfFinancialAssetsAtAmotizedCostLineItems [Line Items]
Current financial assets at amortized cost	0	35
Public securities
DisclosureOfFinancialAssetsAtAmotizedCostLineItems [Line Items]
Non current financial assets at amortized cost	18	0
Current financial assets at amortized cost	$ 54	$ 0

XML

5. GROUP STRUCTURE (Details 11) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
OCP
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Acquisition cost	$ (0.4)
Contingent consideration	(0.1)
Total consideration transferred	(0.5)
Fair value of net assets	25.7
Profit	(25.2)
Share value of the interest in the fair value of associates's identifiable assets and liabilities | OCP
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	9.0
Financial credit with OCP | OCP
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	14.2
Dividends to be received | OCP
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	2.5
CTB
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Total consideration transferred	(272.0)
Fair value of net assets	272.0
CTB | Financial assets at fair value
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	16.0
CTB | Property, plant and equipment
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	477.0
CTB | Inventories
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	8.0
CTB | VRDs
DisclosureOfInvestmentAquisitionsLineItems [Line Items]
Fair value of net assets	$ (229.0)

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 9) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Provisions for contingencies
DisclosureOfProvisionsLineItems [Line Items]
Provisions, beginning	$ 142	$ 141	$ 199
Increases	41	106	43
Reclassification		0	(9)
Decreases	(10)	(23)	(39)
Exchange differences on translation	(4)
Gain on net monetary position, net	(17)	(52)	(37)
Reclassification to liabilities associated with assets classified as held for sale			0
Reversal of unused amounts	(13)	(30)	(16)
Provisions, ending	139	142	141
Asset retirement obligation and dismantling of wind turbines
DisclosureOfProvisionsLineItems [Line Items]
Provisions, beginning	22	42	91
Increases	3	37	29
Reclassification		(18)	(1)
Decreases	0	(5)	(7)
Exchange differences on translation	0
Gain on net monetary position, net	0	(18)	(18)
Reclassification to liabilities associated with assets classified as held for sale			(34)
Reversal of unused amounts	(3)	(16)	(18)
Provisions, ending	22	22	42
Environmental remediation
DisclosureOfProvisionsLineItems [Line Items]
Provisions, beginning	5	6	17
Increases	0	6	4
Reclassification		0	1
Decreases	(2)	(5)	(6)
Exchange differences on translation	0
Gain on net monetary position, net	0	(2)	(3)
Reclassification to liabilities associated with assets classified as held for sale			(7)
Reversal of unused amounts	0	0	0
Provisions, ending	$ 3	$ 5	$ 6

XML

18. LEASES (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Leases
Lease liability, beginning	$ 0
Incorporation by adoption of IFRS 16	8
Increases	13
Discounted value measurement	3
Payments	(5)	$ 0	$ 0
Exchange differences on translation	(3)
Lease liability, ending	$ 16	$ 0

XML

17. RELATED PARTIES TRANSACTIONS (Details 7) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of transactions between related parties [line items]
Trade receivables, current	$ 500	$ 527
Other receivables, non current	71	160
Other receivables, current	61	176
Trade payables, current	454	657
Other payables, current	71	77
Borrowings, current	183	342
Refinor
Disclosure of transactions between related parties [line items]
Trade receivables, current	2	2
Other receivables, non current	0	0
Other receivables, current	0	0
Trade payables, current	1	3
Other payables, current	0	0
Borrowings, current	0	0
OCP
Disclosure of transactions between related parties [line items]
Trade receivables, current	0
Other receivables, non current	15
Other receivables, current	0
Trade payables, current	0
Other payables, current	5
Borrowings, current	0
SACDE
Disclosure of transactions between related parties [line items]
Trade receivables, current	0	0
Other receivables, non current	0	0
Other receivables, current	2	1
Other
Disclosure of transactions between related parties [line items]
Trade receivables, current	0
Other receivables, non current	0
Other receivables, current	1
Origenes Retiro
Disclosure of transactions between related parties [line items]
Trade payables, current		0
Other payables, current		0
Borrowings, current		1
Total related parties
Disclosure of transactions between related parties [line items]
Trade receivables, current	6	10
Other receivables, non current	53	49
Other receivables, current	8	5
Trade payables, current	8	6
Other payables, current	5	0
Borrowings, current	14	1
TGS
Disclosure of transactions between related parties [line items]
Trade receivables, current	4	8
Other receivables, non current	34	38
Other receivables, current	5	4
Trade payables, current		3
Other payables, current		0
Borrowings, current		0
CIESA
Disclosure of transactions between related parties [line items]
Trade receivables, current	0
Other receivables, non current	0
Other receivables, current	0
Greenwind
Disclosure of transactions between related parties [line items]
Trade receivables, current	0	0
Other receivables, non current	4	11
Other receivables, current	0	$ 0
Trade payables, current	5
Other payables, current	0
Borrowings, current	0
SACME
Disclosure of transactions between related parties [line items]
Trade payables, current	2
Other payables, current	0
Borrowings, current	0
Citelec
Disclosure of transactions between related parties [line items]
Trade payables, current	0
Other payables, current	0
Borrowings, current	$ 14

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 13) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Less than one year
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	$ 4
One to two years
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	3
Two to three years
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	2
Three to four years
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	2
Four to five years
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	2
Six to ten years
Disclosure of defined benefit plans [line items]
Estimated expected benefits payment	$ 11

XML

6. RISKS (Details 1) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Total borrowings	$ 1,947	$ 2,177	$ 1,683	$ 1,269
Fixed interest rate
Disclosure of detailed information about borrowings [line items]
Total borrowings	1,830	1,876
Fixed interest rate | Argentinian pesos
Disclosure of detailed information about borrowings [line items]
Total borrowings	143	15
Fixed interest rate | US Dollar
Disclosure of detailed information about borrowings [line items]
Total borrowings	1,687	1,861
Floating interest rates
Disclosure of detailed information about borrowings [line items]
Total borrowings	74	239
Floating interest rates | Argentinian pesos
Disclosure of detailed information about borrowings [line items]
Total borrowings	10	108
Floating interest rates | US Dollar
Disclosure of detailed information about borrowings [line items]
Total borrowings	64	131
Non interest accrual
Disclosure of detailed information about borrowings [line items]
Total borrowings	43	62
Non interest accrual | Argentinian pesos
Disclosure of detailed information about borrowings [line items]
Total borrowings	17	30
Non interest accrual | US Dollar
Disclosure of detailed information about borrowings [line items]
Total borrowings	$ 26	$ 32

XML

17. RELATED PARTIES' TRANSACTIONS

12 Months Ended

Dec. 31, 2019

Related party transactions [abstract]

RELATED PARTIES' TRANSACTIONS

17.1   Sales of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CTB (1)	1	-	-
Transener	-	1	1
TGS (2)	29	51	23
Greenwind	1	-	-
Refinor (3)	18	16	5
Other related parties
SACDE	-	1	-
	49	69	29

(1)	Corresponds mainly to advisory services for technical assistance.
(2)	Corresponds mainly to advisory services for technical assistance and purchase of gas. TGS’ Meeting of Shareholders held on October 17, 2019 approved certain amendments to the services agreement which extend the agreement’s term and entail a progressive reduction over the years of the remuneration collectable by the Company as technical operator.
(3)	Corresponds mainly to sales of gas and refined products.

17.2   Purchases of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS (1)	(22)	(21)	(8)
SACME	(1)	(2)	(2)
Refinor (2)	(19)	(34)	(17)
Oldelval (3)	(1)	(2)	(3)
Other related parties
SACDE (4)	-	(2)	-
Orígenes Vida	-	-	(1)
	(43)	(61)	(31)

(1)	Corresponds mainly to natural gas transportation services.
(2)	Corresponds mainly to purchases of refined products.
(3)	Correspond mainly to oil transportation services.
(4)	Correspond mainly to construction services that include work execution and storage of materials, capitalized in Properties, plant and equipment.

17.3   Fees for services

	12.31.2019	12.31.2018	12.31.2017
Other related parties
Salaverri, Dellatorre, Burgio & Wetzler	(1)	(1)	(1)
	(1)	(1)	(1)

Corresponds to fees for legal advice.

17.4   Other operating income (expenses), net

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
Greenwind	(1)	-	-
OCP (1)	-	(7)	-
Other related parties
SACDE	1	-	-
Foundation (2)	(2)	(2)	(1)
	(2)	(9)	(1)

⁽¹⁾ Corresponds to onerous contract (Ship or Pay).

⁽²⁾ Corresponds to donations.

17.5   Finance income

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS	3	3	3
	3	3	3

Corresponds to finance leases.

17.6   Dividends received

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CIESA/TGS	56	18	-
OCP	14	-	-
Oldelval	-	1	-
Citelec	17	-	-
	87	19	-

17.7   Payment of dividends

Other related parties	12.31.2019	12.31.2018	12.31.2017
EMESA	-	(2)	(2)
APCO Oil	-	-	(2)
	-	(2)	(4)

17.8     Key management personnel remuneration

The total remuneration to executive directors accrued amounts to U$S 6 million (U$S 7 million loss for Directors' and Sindycs' fees and U$S 1 million net gain for the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plans) during the year ended December 31, 2019, U$S 9.6 million (U$S 4.6 million in Directors' and Sindycs' fees and U$S 5.0 million in the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plans) during the year ended December 31, 2018 and U$S 31.2 million (U$S 4.1 million in Directors' and Sindycs' fees and U$S 27.1 million in the accrual of the Company-Value Compensation, EBDA Compensation and Stock-based Compensation Plan) during the year ended December 31, 2017.

17.9     Balances with related parties

As of December 31, 2019	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	4	34	5
CIESA	-	-	-
Greenwind	-	4	-
Refinor	2	-	-
OCP	-	15	-
Other related parties
SACDE	-	-	2
Other	-	-	1
	6	53	8
As of December 31, 2019	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
Greenwind	5	-	-
SACME	2	-	-
Citelec	-	-	14
OCP	-	5	-
Refinor	1	-	-
	8	5	14

According to paragraphs 25 and 26 of IAS 24, Edenor applied the disclosure exemption in relation to related party transactions with a governmental agency that has control, joint control or significant influence. As of December 31, 2019, ANSES holds Edenor's Notes due 2022 amounting to $ 752 million (U$S 20 million of nominal value).

As of December 31, 2018	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	8	38	4
Greenwind	-	11	-
Refinor	2	-	-
Other related parties
SACDE	-	-	1
	10	49	5
As of December 31, 2018	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
TGS	3	-	-
Refinor	3	-	-
Other related parties
Orígenes Retiro	-	-	1
	6	-	1

XML

21. DOCUMENTATION KEEPING

12 Months Ended

Dec. 31, 2019

Documentation Keeping

DOCUMENTATION KEEPING

On August 14, 2014, the National Securities Commission 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 and its subsidiary Edenor, 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, Provincia de 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.

XML

2. REGULATORY FRAMEWORK (Details 1)	12 Months Ended
	Dec. 31, 2019
Generator in construction 1
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTLL
Generating unit	MG
Tecnology	15 MW
Applicable regime	SE Resolutions No. 1/19
Generator in construction 2
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTGEBA
Generating unit	CC
Tecnology	176 MW
Applicable regime	SE Resolution No. 287/17
Generator in construction 3
DisclosureOfRegulatoryFrameworkLineItems [Line Items]
Generator	CTB
Generating unit	CC
Tecnology	280 MW
Applicable regime	SE Resolution No. 220/07

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 2) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current trade receivables	$ 8	$ 93
Non current other receivables	71	160
Non current trade and other receivables	79	253
Current trade receivables	500	527
Current other receivables	61	176
Current trade and other receivables	561	703
CAMMESA Receivable
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current trade receivables	0	70
Current trade receivables	0	15
Other
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current trade receivables	8	23
Non current other receivables	14	2
Current trade receivables	10	4
Current other receivables	14	6
Tax credits
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	3	13
Current other receivables	10	27
Related parties
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	53	49
Current trade receivables	6	10
Current other receivables	8	5
Prepaid expenses
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	1	1
Current other receivables	2	2
Financial credit
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	0	1
Current other receivables	5	6
Guarantee deposits
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	5	13
Receivable for sale of property, plant and equipment
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	0	3
Current other receivables	1	21
Natural Gas Surplus Injection Promotion Program
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	0	71
Current other receivables	0	71
Credit with RDSA
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	35	20
Current other receivables	1	0
Receivables from energy distribution
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	226	223
Receivables from MAT
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	17	27
CAMMESA
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	168	131
Receivables from oil and gas sales
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	48	78
Receivables from refinery and distribution
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	0	6
Receivables from petrochemistry
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	54	67
Government of the PBA and CABA by Social Rate
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current trade receivables	4	0
Allowance for doubtful accounts
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Non current other receivables	(35)	0
Current trade receivables	(33)	(34)
Advances to suppliers
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	0	2
Receivables for non-electrical activities
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	11	14
Insurance to recover
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	0	6
Expenses to be recovered
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	10	11
Allowance for other receivables
DisclosureOfTradeAndOtherReceivablesLineItems [Line Items]
Current other receivables	$ (6)	$ (8)

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 6) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about borrowings [line items]
Non current borrowings	$ 1,764	$ 1,835
Current borrowings	183	342
Financial borrowings
Disclosure of detailed information about borrowings [line items]
Non current borrowings	161	258
Current borrowings	137	313
Corporate bonds
Disclosure of detailed information about borrowings [line items]
Non current borrowings	1,603	1,457
Current borrowings	32	25
CAMMESA financing
Disclosure of detailed information about borrowings [line items]
Non current borrowings	0	120
Current borrowings	0	3
Related parties
Disclosure of detailed information about borrowings [line items]
Current borrowings	$ 14	$ 1

XML

17. RELATED PARTIES' TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2019

Related party transactions [abstract]

Sales of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CTB (1)	1	-	-
Transener	-	1	1
TGS (2)	29	51	23
Greenwind	1	-	-
Refinor (3)	18	16	5
Other related parties
SACDE	-	1	-
	49	69	29

(1)	Corresponds mainly to advisory services for technical assistance.
(2)	Corresponds mainly to advisory services for technical assistance and purchase of gas. TGS’ Meeting of Shareholders held on October 17, 2019 approved certain amendments to the services agreement which extend the agreement’s term and entail a progressive reduction over the years of the remuneration collectable by the Company as technical operator.
(3)	Corresponds mainly to sales of gas and refined products.

Purchases of goods and services

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS (1)	(22)	(21)	(8)
SACME	(1)	(2)	(2)
Refinor (2)	(19)	(34)	(17)
Oldelval (3)	(1)	(2)	(3)
Other related parties
SACDE (4)	-	(2)	-
Orígenes Vida	-	-	(1)
	(43)	(61)	(31)

(1)	Corresponds mainly to natural gas transportation services.
(2)	Corresponds mainly to purchases of refined products.
(3)	Correspond mainly to oil transportation services.
(4)	Correspond mainly to construction services that include work execution and storage of materials, capitalized in Properties, plant and equipment.

Fees for services

	12.31.2019	12.31.2018	12.31.2017
Other related parties
Salaverri, Dellatorre, Burgio & Wetzler	(1)	(1)	(1)
	(1)	(1)	(1)

Other operating income (expenses)

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
Greenwind	(1)	-	-
OCP (1)	-	(7)	-
Other related parties
SACDE	1	-	-
Foundation (2)	(2)	(2)	(1)
	(2)	(9)	(1)

⁽¹⁾ Corresponds to onerous contract (Ship or Pay).

⁽²⁾ Corresponds to donations.

Financial income

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
TGS	3	3	3
	3	3	3

Dividends received

	12.31.2019	12.31.2018	12.31.2017
Associates and joint ventures
CIESA/TGS	56	18	-
OCP	14	-	-
Oldelval	-	1	-
Citelec	17	-	-
	87	19	-

Payment of dividends

Other related parties	12.31.2019	12.31.2018	12.31.2017
EMESA	-	(2)	(2)
APCO Oil	-	-	(2)
	-	(2)	(4)

Balances with related parties

As of December 31, 2019	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	4	34	5
CIESA	-	-	-
Greenwind	-	4	-
Refinor	2	-	-
OCP	-	15	-
Other related parties
SACDE	-	-	2
Other	-	-	1
	6	53	8
As of December 31, 2019	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
Greenwind	5	-	-
SACME	2	-	-
Citelec	-	-	14
OCP	-	5	-
Refinor	1	-	-
	8	5	14

As of December 31, 2018	Trade receivables	Other receivables
	Current	Non Current	Current
Associates and joint ventures
TGS	8	38	4
Greenwind	-	11	-
Refinor	2	-	-
Other related parties
SACDE	-	-	1
	10	49	5
As of December 31, 2018	Trade payables	Other payables	Borrowings
	Current	Current	Current
Associates and joint ventures
TGS	3	-	-
Refinor	3	-	-
Other related parties
Orígenes Retiro	-	-	1
	6	-	1

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 10) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	$ 843	$ 1,185
Financial assets at fair value through profit and loss	388	419
Subtotal financial assets	1,231	1,604
Non financial assets	14	44
Total assets	1,245	1,648
Financial liabilities at amortized cost	2,355	2,787
Financial liabilities at fair value through profit and loss	10	16
Subtotal financial liabilities	2,365	2,803
Non financial liabilities	129	252
Total liabilities	2,494	3,055
Trade and other liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities at amortized cost	408	610
Financial liabilities at fair value through profit and loss	7	15
Subtotal financial liabilities	415	625
Non financial liabilities	129	252
Total liabilities	544	877
Borrowings
Disclosure of detailed information about financial instruments [line items]
Financial liabilities at amortized cost	1,947	2,177
Financial liabilities at fair value through profit and loss	0	0
Subtotal financial liabilities	1,947	2,177
Non financial liabilities	0	0
Total liabilities	1,947	2,177
Derivative financial instruments
Disclosure of detailed information about financial instruments [line items]
Financial liabilities at amortized cost	0	0
Financial liabilities at fair value through profit and loss	3	1
Subtotal financial liabilities	3	1
Non financial liabilities	0	0
Total liabilities	3	1
Trade receivables and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	622	909
Financial assets at fair value through profit and loss	4	3
Subtotal financial assets	626	912
Non financial assets	14	44
Total assets	640	956
Government securities
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	0
Financial assets at fair value through profit and loss	113
Subtotal financial assets	113
Non financial assets	0
Total assets	113
Government securities | Financial assets at amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost		35
Financial assets at fair value through profit and loss		0
Subtotal financial assets		35
Non financial assets		0
Total assets		35
Government securities | Financial assets at fair value through profit and loss
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost		0
Financial assets at fair value through profit and loss		298
Subtotal financial assets		298
Non financial assets		0
Total assets		298
Shares
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	0	0
Financial assets at fair value through profit and loss	19	12
Subtotal financial assets	19	12
Non financial assets	0	0
Total assets	19	12
Investment funds
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	0	0
Financial assets at fair value through profit and loss	244	106
Subtotal financial assets	244	106
Non financial assets	0	0
Total assets	244	106
Derivative financial instruments
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	0
Financial assets at fair value through profit and loss	4
Subtotal financial assets	4
Non financial assets	0
Total assets	4
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets at amortized cost	221	241
Financial assets at fair value through profit and loss	4	0
Subtotal financial assets	225	241
Non financial assets	0	0
Total assets	$ 225	$ 241

XML

5. GROUP STRUCTURE (Details 12)	12 Months Ended
	Dec. 31, 2019
Argentinian production 1
Disclosure of joint operations [line items]
Joint operation name	Río Neuquén
Location	Río Negro and Neuquén
Direct participation		[1]
Indirect participation	0.00%
Operator name	YPF
Duration up to	2027/2051
Argentinian production 2
Disclosure of joint operations [line items]
Joint operation name	Sierra Chata
Location	Neuquén
Direct participation	45.55%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2053
Argentinian production 3
Disclosure of joint operations [line items]
Joint operation name	El Mangrullo
Location	Neuquén
Direct participation	100.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2053
Argentinian production 4
Disclosure of joint operations [line items]
Joint operation name	La Tapera - Puesto Quiroga
Location	Chubut
Direct participation	35.67%
Indirect participation	0.00%
Operator name	Tecpetrol
Duration up to	2027
Argentinian production 5
Disclosure of joint operations [line items]
Joint operation name	El Tordillo
Location	Chubut
Direct participation	35.67%
Indirect participation	0.00%
Operator name	Tecpetrol
Duration up to	2027
Argentinian production 6
Disclosure of joint operations [line items]
Joint operation name	Aguaragüe
Location	Salta
Direct participation	15.00%
Indirect participation	0.00%
Operator name	Tecpetrol
Duration up to	2023/2027
Argentinian production 7
Disclosure of joint operations [line items]
Joint operation name	Gobernador Ayala
Location	Mendoza
Direct participation	22.51%
Indirect participation	0.00%
Operator name	Pluspetrol
Duration up to	2036
Argentinian production 8
Disclosure of joint operations [line items]
Joint operation name	Anticlinal Campamento
Location	Neuquén
Direct participation	15.00%
Indirect participation	0.00%
Operator name	Oilstone
Duration up to	2026
Argentinian production 9
Disclosure of joint operations [line items]
Joint operation name	Estación Fernández Oro
Location	Río Negro
Direct participation	15.00%
Indirect participation	0.00%
Operator name	YPF
Duration up to	2026
Argentinian production 10
Disclosure of joint operations [line items]
Joint operation name	Río Limay este (Ex Senillosa)
Location	Neuquén
Direct participation	85.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2040
Argentinian production 11
Disclosure of joint operations [line items]
Joint operation name	Veta Escondida y Rincón de Aranda
Location	Neuquén
Direct participation	55.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2027
Argentinian production 12
Disclosure of joint operations [line items]
Joint operation name	Rincón del Mangrullo
Location	Neuquén
Direct participation	50.00%
Indirect participation	0.00%
Operator name	YPF
Duration up to	2052
Foreign 1
Disclosure of joint operations [line items]
Joint operation name	Oritupano - Leona
Location	Venezuela
Direct participation	0.00%
Indirect participation	22.00%
Operator name	PDVSA
Duration up to	2025
Foreign 2
Disclosure of joint operations [line items]
Joint operation name	Acema
Location	Venezuela
Direct participation	0.00%
Indirect participation	34.49%
Operator name	PDVSA
Duration up to	2025
Foreign 3
Disclosure of joint operations [line items]
Joint operation name	La Concepción
Location	Venezuela
Direct participation	0.00%
Indirect participation	36.00%
Operator name	PDVSA
Duration up to	2025
Foreign 4
Disclosure of joint operations [line items]
Joint operation name	Mata
Location	Venezuela
Direct participation	0.00%
Indirect participation	34.49%
Operator name	PDVSA
Duration up to	2025
Argentinian exploration 1
Disclosure of joint operations [line items]
Joint operation name	Parva Negra Este
Location	Neuquén
Direct participation	42.50%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2019
Argentinian exploration 2
Disclosure of joint operations [line items]
Joint operation name	Chirete
Location	Salta
Direct participation	50.00%
Indirect participation	0.00%
Operator name	High Luck Group Limited
Duration up to	2019
Argentinian exploration 3
Disclosure of joint operations [line items]
Joint operation name	Río Atuel
Location	Mendoza
Direct participation	33.33%
Indirect participation	0.00%
Operator name	Petrolera El Trebol
Duration up to	2020
Argentinian exploration 4
Disclosure of joint operations [line items]
Joint operation name	Borde del Limay
Location	Neuquén
Direct participation	85.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2015
Argentinian exploration 5
Disclosure of joint operations [line items]
Joint operation name	Los Vértices
Location	Neuquén
Direct participation	85.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2015
Argentinian exploration 6
Disclosure of joint operations [line items]
Joint operation name	Las Tacanas Norte
Location	Neuquén
Direct participation	90.00%
Indirect participation	0.00%
Operator name	PAMPA
Duration up to	2023

[1] 31.43% and 33.07%

XML

18. LEASES (Details 3) $ in Millions	Dec. 31, 2019 USD ($)
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	$ 29
Less than three months
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	1
Three months to one year
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	4
One to two years
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	4
Two to three years
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	2
Three to four years
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	1
Four to five years
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	1
More than five years
DisclosureOfLeaseLiabilitiesContractualUndiscountedCashFlowsLineItems [Line Items]
Lease liabilities contractual undiscounted cash flows	$ 16

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 10) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfIncomeTaxAndMinimumNotionalIncomeTaxLiabilityLineItems [Line Items]
Non current income tax and minimum notional income tax provision	$ 10	$ 27
Current income tax and minimum notional income tax provision	53	29
Income tax, net of witholdings and advances
DisclosureOfIncomeTaxAndMinimumNotionalIncomeTaxLiabilityLineItems [Line Items]
Non current income tax and minimum notional income tax provision	10	27
Current income tax and minimum notional income tax provision	$ 53	25
Minimum notional income tax, net of witholdings and advances
DisclosureOfIncomeTaxAndMinimumNotionalIncomeTaxLiabilityLineItems [Line Items]
Current income tax and minimum notional income tax provision		$ 4

XML

11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 14)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non-financial Assets And Liabilities
Discount rate	5.00%	5.00%	5.00%
Salaries increase	1.00%	1.00%	1.00%
Average inflation	50.00%	27.00%	21.00%

XML

17. RELATED PARTIES TRANSACTIONS (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related party transactions [abstract]
Total remuneration to executive directors	$ 6.0	$ 9.6	$ 31.2

XML

6. RISKS (Details 2)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Undue | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	0.10%	0.04%
Undue | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	0.53%	2.20%
Undue | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	3.00%	8.00%	8.00%
Undue | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	0.39%	0.03%
Undue | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	1.85%	0.96%
Undue | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			0.32%
30 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	0.35%	0.09%
30 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	1.49%	4.42%
30 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	3.00%	8.00%	8.00%
30 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	0.73%	0.08%
30 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	2.81%	1.25%
30 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			0.93%
60 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	1.99%	2.62%
60 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	9.45%	11.00%
60 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	8.00%	12.00%	12.00%
60 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	6.88%	1.41%
60 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	6.84%	2.03%
60 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			8.11%
90 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	2.95%	3.39%
90 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.03%	20.42%
90 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.00%	19.00%	19.00%
90 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	16.66%	4.98%
90 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	17.15%	2.85%
90 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			19.61%
120 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	4.03%	9.37%
120 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.50%	42.85%
120 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	20.00%	26.00%	26.00%
120 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	25.32%	11.52%
120 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	26.77%	19.86%
120 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			35.69%
150 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	5.59%	13.56%
150 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.81%	47.32%
150 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	45.00%	59.00%	59.00%
150 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	29.59%	20.36%
150 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	43.21%	26.41%
150 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			45.63%
180 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	9.79%	19.82%
180 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.90%	49.20%
180 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	72.00%	69.00%	69.00%
180 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	30.97%	24.91%
180 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	49.89%	32.95%
180 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			59.00%
+180 days | Generation
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	16.13%	28.88%
+180 days | Oil and Gas
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	18.92%	56.32%
+180 days | Distribution of energy
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	72.00%	69.00%	69.00%
+180 days | Petrochemicals
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	43.05%	25.24%
+180 days | Holding
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets	65.29%	32.97%
+180 days | Rest of business segments
DisclosureOfCreditLossRatesOnTradeReceivablesAndFinancialAssetsLineItems [Line Items]
Credit loss on trade receivables and financial assets			63.01%

XML

6. RISKS (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Risks
Total borrowings	$ 1,947	$ 2,177	$ 1,683	$ 1,269
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(590)	(646)
Net debt	1,357	1,531
Total capital attributable to owners	$ 3,274	$ 2,897
Leverage ratio	41.45%	52.85%

XML

12. FINANCIAL ASSETS AND LIABILITIES (Details 1) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfFinancialAssetsatFairValueThrougProfitorLossLineItems [Line Items]
Non current financial assets at fair value through profit and loss	$ 11	$ 11
Current financial assets at fair value through profit and loss	365	405
Government securities
DisclosureOfFinancialAssetsatFairValueThrougProfitorLossLineItems [Line Items]
Current financial assets at fair value through profit and loss	113	298
Shares
DisclosureOfFinancialAssetsatFairValueThrougProfitorLossLineItems [Line Items]
Non current financial assets at fair value through profit and loss	11	11
Current financial assets at fair value through profit and loss	8	1
Investment funds
DisclosureOfFinancialAssetsatFairValueThrougProfitorLossLineItems [Line Items]
Current financial assets at fair value through profit and loss	$ 244	$ 106

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18. LEASES

12 Months Ended

Dec. 31, 2019

Leases

LEASES

18.1 Lessee

Edenor leases commercial offices, two warehouses, the headquarters building (which includes administrative, commercial and technical offices), the Energy Handling and Transformer Center (two buildings and a plot of land located within the perimeter of Central Nuevo Puerto and Puerto Nuevo) and Las Heras Substation. Edenor’s lease agreements include cancelable clauses and terms ranging between 2 and 13 years.

Furthermore, 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 recognized as of December 31, 2019 is disclosed below:

18.1.1 Right of use assets

Original values
Type of good	At the beginning	Increase	At the end
		(1)
Machinery and equipment	-	13	13
Buildings	-	7	7
Total at 12.31.2019	-	20	20
	Depreciation
Type of good	At the beginning	For the year	At the end
Machinery and equipment	-	(2)	(2)
Buildings	-	(2)	(2)
Total at 12.31.2019	-	(4)	(4)
	Net book values
Type of good	At the end
Machinery and equipment	11
Buildings	5
Total at 12.31.2019	16

⁽¹⁾ Includes U$S 8 million incorporated as of January 1, 2019 on the adoption of IFRS 16 (see Note 4.1.1)

18.1.2 Lease liabilities

	12.31.2019
At the beginning of the year	-
Incorporation by adoption of IFRS 16	8
Increases	13
Discounted value measurement (1)	3
Payments	(5)
Exchange differences on translation	(3)
At the end of the year	16

⁽¹⁾ Included in the “Gains (losses) from present value measurement” under Other financial results

As of December 31, 2019, this liability is disclosed under Other current payables in the amount of U$S 4 million and Other non-current payables for U$S 12 million.

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:

	12.31.2019
Less than three months	1
Three months to one year	4
One to two years	4
Two to three years	2
Three to four years	1
Four to five years	1
More than five years	16
Total	29

18.1.3 Short-term or low value leases

As of December 31, 2019, the Company has recognized administrative costs and expenses in the amount of U$S 10 million on account of lease payments associated with short-term leases and low-value underlying assets. 

18.2     Lessor

18.2.1 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 U$S 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, 2019, this receivable is disclosed under Other current receivables in the amount of U$S 5 million and under Other non-current receivables for U$S 34 million.

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:

	12.31.2019
Less than three months	2
Three months to one year	6
One to two years	7
Two to three years	7
Three to four years	7
Four to five years	7
More than five years	12
Total	48

18.2.2     Operating leases

Edenor has entered into operating lease contracts with certain cable television companies granting them the right to use its network’s poles. Most of these contracts have an automatic renewal clause.

As of December 31, 2019 and 2018, future minimum collections regarding operating leases are those detailed below:

	12.31.2019	12.31.2018
2019	-	5
2020	5	-
Total future minimum lease collections	5	5

The total income from operating leases for the years ended December 31, 2019 and 2018 amounts to U$S 5 million and U$S 5, respectively.

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22. OIL AND GAS RESERVES (Information not covered by the auditors' report)

12 Months Ended

Dec. 31, 2019

Oil And Gas Reserves

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, 2019.

	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	8,804	10,534	4,746	10,168	13,550	20,702
Total at 12.31.2019	8,804	10,534	4,746	10,168	13,550	20,702

⁽¹⁾ In thousands of barrels.

⁽²⁾ In millions of cubic meters.

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6. RISKS

12 Months Ended

Dec. 31, 2019

Risks

RISK

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 raw materials, oil and gas, international petrochemical product’s price, the regulatory framework for the energy industry (mainly expected price recognition and compensation costs methodology), 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 asset or 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 / Minimum notional 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 recognized figures, such differences will have an effect on income tax and deferred income tax at the year of such determination.

Deferred tax assets are reviewed at each reporting date and reduced in accordance with the probability that the sufficient taxable base will be available to allow 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 those 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. Periodically, the Company reviews the status of each contingency and assesses potential financial liability, applying the criteria indicated in Note 4.22, 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 our 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

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’ 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

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 generation segment the Company mainly considers the ability of CAMMESA to meet its payment obligations to generators, and the resolutions issued by SGE, which allow the Company to collect its credits with CAMMESA through different mechanisms.

Future adjustments to the allowance may be necessary if future 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 recognized 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.

6.1.7 ENRE Penalties and discounts

Edenor considers its applicable accounting policy for the recognition of ENRE penalties and discounts critical because it depends on penalizable events, which are valued on the basis of Edenor’s management best estimate of the expenditure required to settle the present obligation at the date of these Consolidated Financial Statements. The balances of ENRE penalties and discounts are adjusted in accordance with the regulatory framework applicable thereto and have been estimated based on the description made in Note 2.3.

6.1.8 Revenue recognition

In the distribution of energy business segment, revenue is recognized on an accrual basis upon delivery to customers, which includes the estimated amount of unbilled distribution of electricity at the end of each year. We consider our accounting policy for the recognition of estimated revenue critical because it depends on the amount of electricity effectively delivered to customers which is valued on the basis of applicable tariffs. Unbilled revenue is classified as current trade receivables.

In the oil and gas business segment, the fair value of the consideration receivable corresponding to revenues from gas sales to Distributors is recognized based on the volume of gas delivered and the price established by the SE (in accordance with applicable resolutions).

6.1.9 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 exploitation rights, including oil and gas volumes related to those service agreements under which the Company has no ownership rights on the reserves or the hydrocarbons obtained and those estimated to be produced for the contracting company under service contracts. 

There are numerous uncertainties in estimating proved 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 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, including 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 oil and gas segment (see Notes 4.6 to 4.9).

6.1.10 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 (which considers those costs) 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. The provision is recognized on the basis that a future remediation commitment will 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.

6.1.11 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 comprised 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.

Taking into consideration that the Company, (excluding the Distribution segment’s balances), has a net asset position in Argentine pesos, as of December 31, 2019 the Company recorded net foreign exchange losses in the amount of U$S 5 million. The Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values a (decrease)/increase of U$S 11 million in the 2019 fiscal year’s income/(loss), before income tax.

In the Distribution segment, the subsidiary Edenor collects revenues in pesos pursuant to regulated tariffs which are not indexed to the U.S. dollar, whereas a significant portion of its existing financial debt is denominated in U.S. dollar, which exposes Edenor to a risk of loss resulting from a devaluation of the Argentine peso. Edenor can manage this risk through the execution of forward contracts denominated in foreign currency.

As of the year ended December 31, 2019, Edenor has not hedged its exposure to the U.S. dollar. Edenor does not currently hedge its exposure to currency risk. Therefore, any devaluation of the peso could significantly increase its debt service burden, which, in turn, could have a substantial adverse effect on its financial and cash position (including its ability to repay its Corporate Notes) and the results of its operations. During 2019, U.S. dollar currency appreciated by approximately 58.9% against the Argentine peso, from $ 37.70 in December 2018 to $ 59.89 in December 2019 and as of December 31, 2019 Edenor recorded net foreign exchange losses in the amount of U$S 70 million. Edenor estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values an increase/(decrease) of U$S 21 million in the 2019 fiscal year’s income/(loss), 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 on account of the current regulatory, economic, governmental and other policies in force, gas domestic prices are not 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 2019 fiscal year’s income/(loss), 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	12.31.2019	12.31.2018
Shares	2	1
Government securities	11	30
Investment funds	24	11
Variation of the result of the year	37	42

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, 2019, on consolidated basis net of Corporate Bonds’ repurchase, only approximately 4% of the indebtedness was subject to variable interest rates. Most of the Company’s indebtedness subject to variable interest rates is denominated in U.S. dollar, based on Libor rate plus an applicable margin and a small portion is denominated in pesos accruing interest based on the private Badlar 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 chart shows the breakdown of the Company’s borrowings classified by interest rate and the currency in which they are denominated:
 

	12.31.2019	12.31.2018
Fixed interest rate:
Argentinian pesos	143	15
U.S dollar	1,687	1,861
Subtotal loans granted at a fixed interest rate	1,830	1,876
Floating interest rates:
Argentinian pesos	10	108
U.S dollar	64	131
Subtotal loans granted at a floating interest rate	74	239
Non interest accrued
U.S dollar	17	30
Argentinian pesos	26	32
Subtotal no interest accrued	43	62
Total borrowings	1,947	2,177

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 2019 fiscal year's year’s income/(loss), before income tax, of U$S 0.9 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, 2019, the Company’s trade receivables, excluding Edenor, totaled U$S 299 million, out of which 97% are short-term receivables and the remaining 3% are classified as non-current. With the exception of CAMMESA, which represents approximately 56% 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 risk control area evaluates the customer’s creditworthiness, based on past experiences and other factors.

As of December 31, 2019, Edenor’s trade receivables totaled U$S 204 million. No single customer accounted for more than 10% of sales. The collectibility of trade receivables balances related to the Framework Agreement, which amount to U$S 0.2 million, is subject to such agreement’s being in force and the compliance with it terms.

Edenor’s allowance for impairment of receivables is assessed based on the delinquent balance, which comprises all such debt arising from the bills for electricity consumption of small-demand (T1), medium-demand (T2), and large-demand (T3) customers that remain unpaid 7 working days after their first due dates. Edenor’s Management records an allowance applying to the delinquent balances of each customer category an uncollectibility rate that is determined according to each customer category based on the historical comparison of collections made. Additionally, the amounts related to the Framework Agreement are not considered within delinquent balances.

Additionally, and faced with temporary and/or exceptional situations, Edenor’s Management may redefine the amount of the allowance, specifying and supporting the criteria used in all the cases.

One of the significant items of Edenor’s delinquent balances is that related to the receivable amounts with Municipalities, in respect of which Edenor either applies different offsetting mechanisms against municipal taxes it collects on behalf of the municipalities, or implements debt refinancing plans, with the aim of reducing them.

The inability to collect the accounts receivable in the future could have an adverse effect on Edenor’s results of operations and its financial position, which, in turn, could have an adverse effect on Edenor’s ability to repay loans, including payment of the Corporate Notes.

The Company applies the simplified approach of IFRS 9 to measure the expected credit losses 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, 2019 and 2018 amounts to U$S 24 million and U$S 41 million, respectively (Note 12.3) and was determined based on credit loss rates calculated for days past due detailed below:

12.31.2019	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.10%	0.35%	1.99%	2.95%	4.03%	5.59%	9.79%	16.13%
Oil and Gas	0.53%	1.49%	9.45%	18.03%	18.50%	18.81%	18.90%	18.92%
Distribution of energy	3.00%	3.00%	8.00%	18.00%	20.00%	45.00%	72.00%	72.00%
Petrochemicals	0.39%	0.73%	6.88%	16.66%	25.32%	29.59%	30.97%	43.05%
Holding	1.85%	2.81%	6.84%	17.15%	26.77%	43.21%	49.89%	65.29%
12.31.2018	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.04%	0.09%	2.62%	3.39%	9.37%	13.56%	19.82%	28.88%
Oil and Gas	2.20%	4.42%	11%	20.42%	42.85%	47.32%	49.20%	56.32%
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Petrochemicals	0.03%	0.08%	1.41%	4.98%	11.52%	20.36%	24.91%	25.24%
Holding	0.96%	1.25%	2.03%	2.85%	19.86%	26.41%	32.95%	32.97%

In 2017 fiscal year, the calculation of the loss allowance for trade receivables and other receivables was assessed based on the incurred loss model, and considered the existence of objective evidence of default for the recognition of losses in the statement of comprehensive income. The expected credit loss as of January 1, 2018 (IFRS 9 amended adoption date) was determined based on credit loss rates calculated for days past due detailed below:

Rates	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+180 days
Distribution of energy	8.00%	8.00%	12.00%	19.00%	26.00%	59.00%	69.00%	69.00%
Rest of business segments	0.32%	0.93%	8.11%	19.61%	35.69%	45.63%	59.00%	63.01%

The loss allowance for financial assets and other receivables adjustment as of January 1, 2018 for the application of the expected credit losses methodology to the loss allowance as of December 31, 2017, is detailed as follows:

	Financial assets	Other receivables
Loss allowance under IAS 39 as of 12.31.2017	22	7
Adjustment to the opening balance of retained earnings	4	(1)
Loss allowance calculated under IFRS 9 as of 01.01.2018	26	6

The detailed adjustments to the opening balance in equity as a result of the application of IFRS 9, are disclosed net of tax effect for a total amount of U$S 2 million, with counterpart in retained earnings of U$S 1 million and in non-controlling interest of U$S 1 million.

Finally, although cash, cash equivalents and financial assets are also subject to the impairment requirements of IFRS 9, the identified impairment loss is immaterial.

Loss allowance evolution as of December 31, 2019, 2018 and 2017, 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 U$S 1.5 million (decrease)/increase in 2019 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 for 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 local and international, capital market as well as 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 provide a sufficient margin as determined in the previously mentioned 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 is worth to highlight that restrictions, both current and future new restrictions that could be imposed, affecting the access to the single and free-floating foreign exchange markets ingle market and free of change by companies could affect the Company's ability to pay debt’s capital and interest and additional transfers of funds abroad (including payments related to Corporate Bonds) or could otherwise affect the Company’s business and results of operations.

The determination of the Company’s liquidity index for fiscal years ended December 31, 2019 and 2018 is detailed below:

	12.31.2019	12.31.2018
Current assets	1,362	1,521
Current liabilities	854	1,182
Index	1.59	1.29

The following table includes an analysis of the Company 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, 2019	Trade and other payables (1)	Borrowings	Total
Less than three months	-	95	95
Three months to one year	454	188	642
One to two years	11	288	299
Two to five years	70	834	904
More than five years	9	1,233	1,242
Total	544	2,638	3,182
As of December 31, 2018	Trade and other payables	Borrowings	Total
Less than three months	331	112	443
Three months to one year	534	318	852
One to two years	9	242	251
Two to five years	3	892	895
More than five years	-	977	977
Total	877	2,541	3,418

(1) Includes Lease Liabilities (see Note 18.1.2)

6.3 Capital risk management

The aims of managing capital are 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, 2019 and 2018 were as follows:

	12.31.2019	12.31.2018
Total borrowings	1,947	2,177
Less: cash and cash equivalents, and financial assets at fair value through profit and loss	(590)	(646)
Net debt	1,357	1,531
Total capital attributable to owners	3,274	2,897
Leverage ratio	41.45%	52.85%

6.4 Regulatory risk factors

Pursuant to caption C of Section 37 of the Edenor’s Concession Agreement, the Grantor of the Concession may, without prejudice to other rights to which he is entitled thereunder, foreclose on the collateral granted by Edenor when the cumulative value of the penalties imposed to Edenor in the previous one-year period exceeds 20% of its annual billing, net of taxes and rates.

Edenor’s Management evaluates the development of this indicator on an annual basis. As of the date of issuance of these Consolidated Financial Statements, there are no events of non-compliance by Edenor that could lead to that situation.

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10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2019

Other Items Of Statement Of Comprehensive Income

OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	22	26	27
Benefits to employees	1	-	-
Accrual of defined benefit plans	1	-	1
Fees and compensation for services	29	30	26
Compensation agreements	(1)	2	6
Depreciation of property, plant and equipment	9	9	3
Right-of-use assets amortization	1	-	-
Taxes, rates and contributions	25	33	28
Communications	6	7	8
Penalties	22	28	12
Net impairment losses on financial assets	21	28	11
Transport	9	6	4
Other	3	2	1
Total selling expenses	148	171	127

10.2 Administrative expenses

	12.31.2019	12.31.2018	12.31.2017
Salaries and social security charges	62	81	77
Benefits to employees	8	5	5
Accrual of defined benefit plans	8	1	6
Fees and compensation for services	52	68	53
Compensation agreements	-	3	20
Directors' and Syndicates' fees	7	5	4
Depreciation of property, plant and equipment	14	12	6
Consumption of materials	3	4	3
Maintenance	2	2	2
Transport and per diem	2	2	2
Rental and insurance	5	6	6
Surveillance and security	2	5	4
Taxes, rates and contributions	2	8	4
Communications	2	2	2
Right-of-use assets amortization	2	-	-
Institutional advertising and promotion	-	1	2
Other	3	1	2
Total administrative expenses	174	206	198

10.3 Exploration expenses

	12.31.2019	12.31.2018	12.31.2017
Geological and geophysical expenses	4	-	1
Decrease in unproductive wells	5	1	1
Total exploration expenses	9	1	2

10.4 Other operating income and expenses

Other operating income	Note	12.31.2019	12.31.2018	12.31.2017
Compensation for transaction agreement in Ecuador (1)		-	99	-
Recovery of doubtful accounts		-	-	4
Insurrance recovery		6	-	-
Natural Gas Surplus Injection Promotion Program	4.24.1.1	-	23	101
Commissions on municipal tax collections		2	2	1
Services to third parties		13	13	8
Profit for property, plant and equipment sale		-	3	-
Dividends received		1	1	1
Reversal of contingencies and taxes payables (2)		1	4	24
Other		17	36	10
Total other operating income		40	181	149
Other operating expenses
Provision for contingencies		(28)	(35)	(20)
Decrease in property, plant and equipment		(1)	(6)	(1)
Allowance for tax credits		(4)	-	(1)
Tax on bank transactions		(29)	(30)	(27)
Cost for services provided to third parties		(2)	(2)	(2)
Compensation agreements		-	-	(2)
Donations and contributions		(2)	(2)	(2)
Institutional promotion		(2)	(3)	(3)
Extraordinary canon		-	(3)	(14)
Contingent consideration		-	-	(8)
Onerous contract (Ship or Pay)		-	(7)	(4)
Tax contingencies in Ecuador (1)		-	(69)	-
Other		(18)	(43)	(19)
Total other operating expenses		(86)	(200)	(103)

(1)	Pursuant to Agreement executed on March 19, 2018 between the Republic of Ecuador and the Plaintiff Partners, including EcuadorTLC (see Note 5.6.1). Figures recorded as of December 31, 2018 arises from the Consolidated Financial Statements denominated in pesos in accordance with IAS 29, and was translated into U.S. dollars using the exchange rate as of that date.
(2)	In 2017, includes gains on releasing tax fines and reducing compensatory interests, related to benefits for the adhesion to the regularization regime (moratorium) (see Note 2.6.4).

10.5. Financial results

	12.31.2019	12.31.2018	12.31.2017
Gain on monetary position, net	187	629	304
Finance income
Commercial interest	61	58	43
Financial interest	22	34	14
Other interest	13	7	5
Total finance income	96	99	62
Finance cost
Commercial interest	(52)	(78)	(45)
Fiscal interest	(6)	(8)	(11)
Financial interest (1)	(227)	(210)	(162)
Other interest	(10)	(15)	(10)
Other financial expenses	(4)	(5)	(4)
Total financial expenses	(299)	(316)	(232)
Other financial results
Foreign currency exchange difference, net	(75)	(863)	(156)
Changes in the fair value of financial instruments	91	64	62
Gains (losses) from present value measurement	54	(74)	(6)
Other financial results of RDSA	2	13	-
Results for the repurchase of corporate bonds	27	2	-
Other financial results	14	-	-
Total other financial results	113	(858)	(100)
Total financial results, net	97	(446)	34

 ⁽¹⁾ Net of U$S 16.8 million, U$S 7.5 million and U$S 16 million capitalized in property, plant and equipment for the years ended December 31, 2019, 2018 and 2017, respectively.

10.6 Income tax and minimum notional income tax

The breakdown of income tax charge is:

	12.31.2019	12.31.2018	12.31.2017
Current tax	70	39	55
Deferred tax	(57)	(19)	(72)
Other comprehensive income	-	1	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	1	(4)	(12)
Direct charges for income tax	-	-	3
Optional tax revaluation	34	-	-
Total loss (gain) income tax	48	17	(26)

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

	12.31.2019	12.31.2018	12.31.2017
Profit before income tax	848	224	402
Current tax rate	30%	30%	35%
Result at the tax rate	254	67	141
Share of profit of associates and joint ventures	(25)	(3)	(117)
Non-taxable results	(38)	7	(59)
Effects of exchange differences and traslation effect of property, plant and equipment and intangible assets, net	93	-	-
Adjustment of valuation of property, plant and equipment and intangible assets	(202)	-	-
Gain (loss) on monetary position, net	17	(38)	66
Effect of tax rate change in deferred tax	37	(26)	(21)
Adjustment effect for tax inflation	129	-	-
Payment of optional tax revaluation	34	-	-
Special tax, revaluation of property, plant and equipment	(169)	-	-
Difference in the estimate of previous fiscal year income tax and the income tax statement	(86)	4	(20)
Deferred tax not previously recognized	-	4	(31)
Non-deductible cost	-	-	9
Non-deductible provisions	-	-	5
Other	4	2	1
Total  loss (gain) income tax	48	17	(26)

As of December 31, 2019 and 2018 consolidated accumulated tax losses amount to U$S 444 million and U$S 176 million, respectively, which may be offset, pursuant to the applicable tax laws, with tax profits corresponding to future fiscal years, at the tax rate that is estimated to apply, based on the following breakdown:

Fiscal year generation	Fiscal year prescription	12.31.2019	12.31.2018
2015	2020	-	3
2016	2021	4	18
2017	2022	3	4
2018	2023	38	27
2019	2024	66	-
Recognized Tax loss-carryforwards		111	52

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14. STATEMENT OF CASH FLOWS' COMPLEMENTARY INFORMATION

12 Months Ended

Dec. 31, 2019

Statement Of Cash Flows Complementary Information

STATEMENT OF CASH FLOWS' COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit (loss) to cash flows generated by operating activities

	Note	12.31.2019	12.31.2018	12.31.2017
Income tax	10.6	48	17	(26)
Accrued interest		202	219	166
Depreciations and amortizations	9, 10.1 and 10.2	267	234	205
Constitution of allowances, net	10.4 and 10.1	25	28	12
Constitution (recovery) of provisions, net	10.4	27	31	(4)
Share of profit from joint ventures and associates	5.3.2	(101)	(118)	(48)
Income from the sale of companies	5.1	-	(28)	-
Accrual of defined benefit plans	9, 10.1 and 10.2	16	5	14
Net exchange differences	10.5	75	863	156
Result from measurement at present value	10.5	(54)	74	6
Changes in the fair value of financial instruments	10.5	(91)	(64)	(62)
Results from property, plant and equipment sale and decreases	10.4 and 10.3	5	4	1
Results for the repurchase of corporate bonds	10.5	(27)	(2)	-
Impairment of property, plant and equipment	11.1.1	62	32	-
Dividends received	10.4	(1)	(1)	(1)
Compensation agreements	10.1 and 10.2	(1)	5	26
Result from the sale of shareholdings in companies, property, plant and equipment	5.2.3	-	(44)	-
Agreement on the regularization of obligations		(285)	-	-
Other financial results of RDSA		(2)	(13)	-
Onerous contract (Ship or pay)	10.4	-	7	4
Gain on monetary position, net	10.5	(187)	(629)	(304)
Other		(8)	2	6
		(30)	622	151

14.2 Changes in operating assets and liabilities

	12.31.2019	12.31.2018	12.31.2017
Increase (decrease) in trade receivables and other receivables	17	(172)	(65)
Increase in inventories	(28)	(18)	(11)
Increase in trade payables and other payables	97	22	10
Increase in deferred income	-	2	-
Decrease in salaries and social security payable	15	14	(1)
Decrease in defined benefit plans	(2)	(3)	(3)
(Decrease) increase in tax payables	20	35	(26)
(Increase) decrease in provisions	(9)	(60)	(48)
Income tax and minimum notional income tax paid	(87)	(49)	(56)
(Payments) proceeds from derivative financial instruments, net	9	(24)	23
Total changes in operating assets and liabilities	32	(253)	(177)

14.3 Significant non-cash transactions

	12.31.2019	12.31.2018	12.31.2017
Acquisition of property, plant and equipment through an increase in trade payables	(45)	17	(103)
Borrowing costs capitalized in property, plant and equipment	(17)	(7)	(16)
Decreases of  property, plant and equipment through an increase in other receivables	-	12	-
Agreement on the regularization of obligations	285	-	-
Increase in asset retirement obligation provision through an increase in property, plant and equipment	1	34	(2)
Constitution of guarantee of derivative financial instruments, net through the delivery of financial assets at fair value through profit or loss	3	(22)	19
Cancellation of other credits for capital contributions in associates	(17)	-	-
Compensation of investments at a cost cost through the transfer of other credits	(126)	-	-
Loan compensation through the transfer of sales credits	135	-	-
Increase of right-of-use assets through an increase in other debts	20	-	-
Significant non-cash transactions from discontinued operations :
Credit pending collection for sale of property, plant and equipment	-	-	15

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of comprehensive income [abstract]
Revenue	$ 2,836	$ 2,920	$ 2,175
Cost of sales	(2,032)	(1,967)	(1,574)
Gross profit	804	953	601
Selling expenses	(148)	(171)	(127)
Administrative expenses	(174)	(206)	(198)
Exploration expenses	(9)	(1)	(2)
Other operating income	40	181	149
Other operating expenses	(86)	(200)	(103)
Impairment of property, plant and equipment	(62)	(32)	0
Share of profit from associates and joint ventures	101	118	48
Income from the sale of associates	0	28	0
Agreement on the regularization of obligations	285	0	0
Operating income	751	670	368
Gain on monetary position, net	187	629	304
Finance income	96	99	62
Finance costs	(299)	(316)	(232)
Other financial results	113	(858)	(100)
Financial results, net	97	(446)	34
Profit before income tax	848	224	402
Income tax	(48)	(17)	26
Profit of the year from continuing operations	800	207	428
Profit (loss) of the year from discontinued operations	0	80	(50)
Profit of the year	800	287	378
Other comprehensive income (loss) items that will not be reclassified to profit or loss
Results related to defined benefit plans	2	(4)	0
Income tax	0	1	0
Share of loss from joint ventures	0	(1)	0
Exchange differences on translation	(15)	0	0
Other comprehensive income (loss) Items that may be reclassified to profit or loss
Exchange differences on translation	(22)	1	3
Other comprehensive income (loss) of the year from continuing operations	(35)	(3)	3
Other comprehensive income of the year from discontinued operations	0	8	(14)
Other comprehensive income (loss) of the year	(35)	5	(11)
Total comprehensive income of the year	765	292	367
Total income of the year attributable to:
Owners of the company	692	224	286
Non - controlling interest	108	63	92
Total income (loss) of the year	800	287	378
Total income (loss) of the year attributable to owners of the company:
Continuing operations	692	146	341
Discontinued operations	0	78	(55)
Total income of the year attributable to owners of the company	692	224	286
Total comprehensive income of the year attributable to:
Owners of the company	672	225	281
Non - controlling interest	93	67	86
Total comprehensive income of the year	765	292	367
Total comprehensive income (loss) of the year attributable to owners of the company:
Continuing operations	672	141	343
Discontinued operations	0	84	(62)
Total comprehensive income (loss) of the year attributable to owners of the company	$ 672	$ 225	$ 281
Earnings per share attributable to the equity holders of the company during the year
Basic and diluted earnings per share from continuing operations	$ 14.42	$ 2.81	$ 6.69
Basic and diluted earnings (loss) per share from discontinued operations	.00	1.50	(1.07)
Total basic and diluted earnings per share	$ 14.42	$ 4.31	$ 5.61

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9. COST OF SALES (Tables)

12 Months Ended

Dec. 31, 2019

Cost Of Sales

Cost of sales

	12.31.2019	12.31.2018	12.31.2017
Inventories at the beginning of the year	137	113	164
Plus: Charges for the year
Purchases of inventories, energy and gas	1,305	1,224	874
Salaries and social security charges	163	181	202
Benefits to employees	9	6	7
Accrual of defined benefit plans	7	4	7
Works contracts, fees and compensation for services	103	98	84
Depreciation of property, plant and equipment	232	206	195
Intangible assets amortization	7	7	1
Right-of-use assets amortization	2	-	-
Transport of energy	4	4	3
Transportation and freights	18	14	3
Consumption of materials	48	64	29
Penalties	25	56	11
Maintenance	27	24	18
Canons and royalties	59	74	56
Environmental control	3	5	3
Rental and insurance	21	13	11
Surveillance and security	6	6	6
Taxes, rates and contributions	4	5	3
Other	5	-	10
Subtotal	2,048	1,991	1,523
Gain on monetary position	1	-	-
Less: Inventories at the end of the year	(153)	(137)	(113)
Total cost of sales	2,032	1,967	1,574

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5. GROUP STRUCTURE (Tables)

12 Months Ended

Dec. 31, 2019

Group Structure

Sale of subsidiary and areas

	12.31.2018
Sale price (2)	270
Book value of assets sold and costs associated with the transaction	(226)
Result for sale	44
Interests (1)	4
Income tax	(22)
Imputed in results	26
Other comprehensive income (loss)
Reclasification exchange differences on translation	6
Income tax	(2)
Imputed in Other comprehensive income	4
Total comprehensive income	30

(1)	Are exposed in "Financial income" in the consolidated statement of comprehensive income related to discontinued operations.
(2)	Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

	12.31.2018
Sale price (1)	28
Book value of assets sold and costs associated with the transaction	(28)
Result for sale	-

⁽¹⁾ Sale price recorded as of December 31, 2018 arises from the financial statements denominated in pesos in accordance with IAS 29, and was translated into U.S. Dollars using the exchange rate as of that date.

Consolidated statement of comprehensive income related to discontinued operations

As of December 31, 2018:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	66	422	(90)	398
Cost of sales	(33)	(361)	91	(303)
Gross profit	33	61	1	95
Selling expenses	(2)	(33)	-	(35)
Administrative expenses	(1)	(4)	-	(5)
Other operating income	1	6	-	7
Other operating expenses	(6)	(10)	-	(16)
Result from the sale of share of profit and property, plant and equipment	44	-	-	44
Operating income	69	20	1	90
Gain on monetary position, net	7	2	(1)	8
Finance income	4	1	-	5
Finance costs	(1)	-	-	(1)
Other financial results	(4)	22	-	18
Financial results, net	6	25	(1)	30
Income before income tax	75	45	-	120
Income tax	(26)	(14)	-	(40)
Profit  of the year from discontinued operations	49	31	-	80
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	(2)	-	-	(2)
Reclasification exchange differences on translation	6	-	-	6
Exchange differences on translation	4	-	-	4
Other comprehensive income of the year from discontinued operations	8	-	-	8
Total comprehensive income  of the year from discontinued operations	57	31	-	88
	Oil and gas	Refining and distribution	Eliminations	Total
Total income of the year from discontinued operations attributable to:
Owners of the company	47	31	-	78
Non - controlling interest	2	-	-	2
	49	31	-	80
Total comprehensive income of the year from discontinued operations attributable to:
Owners of the company	53	31	-	84
Non - controlling interest	4	-	-	4
	57	31	-	88

As of December 31, 2017:

	Oil and gas	Refining and distribution	Eliminations	Total
Revenue	259	728	(296)	691
Cost of sales	(251)	(618)	297	(572)
Gross profit	8	110	1	119
Selling expenses	(8)	(82)	-	(90)
Administrative expenses	(6)	(19)	-	(25)
Exploration expenses	(1)	-	-	(1)
Other operating income	16	10	-	26
Other operating expenses	(8)	(13)	-	(21)
Result from the sale of  property, plant and equipment	-	(28)	-	(28)
Operating income (loss)	1	(22)	1	(20)
Financial income	1	1	-	2
Financial expenses	-	(1)	-	(1)
Other financial results	(10)	(1)	-	(11)
Financial results, net	(9)	(1)	-	(10)
Income (loss) before income tax	(8)	(23)	1	(30)
Income tax	(28)	8	-	(20)
Profit (loss) of the year from discontinued operations	(36)	(15)	1	(50)
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Income tax	2	-	-	2
Exchange differences on translation	(16)	-	-	(16)
Other comprehensive loss of the year from discontinued operations	(14)	-	-	(14)
Total comprehensive income (loss) of the year from discontinued operations	(50)	(15)	1	(64)
	Oil and gas	Refining and distribution	Eliminations	Total
Total income (loss) of the year from discontinued operations attributable to:
Owners of the company	(41)	(15)	1	(55)
Non - controlling interest	5	-	-	5
	(36)	(15)	1	(50)
Total comprehensive income (loss) of the year from discontinued operations attributable to:
Owners of the company	(48)	(15)	1	(62)
Non - controlling interest	(2)	-	-	(2)
	(50)	(15)	1	(64)

Consolidated statement of cash flows related to discontinued operations

	12.31.2018	12.31.2017
Net cash (used in) generated by operating activities	(46)	87
Net cash used in investing activities	-	(50)
Net cash generated by (used in) financing activities	42	(31)
(Decrease) increase in cash and cash equivalents from discontinued operations	(4)	6
Cash and cash equivalents at the begining of the year	6	4
Loss on net monetary position generated by cash and cash equivalents	(2)	(4)
(Decrease) increase in cash and cash equivalents	(4)	6
Cash and cash equivalents at the end of the year	-	6

Subsidiaries information

			12.31.2019	12.31.2018
Company	Country	Main activity	Direct and indirect participation %	Direct and indirect participation %
Corod	Argentina	Oil	100.00%	100.00%
CPB	Argentina	Generation	100.00%	100.00%
CPB Energía S.A.	Argentina	Generation	100.00%	100.00%
EcuadorTLC	Ecuador	Oil	100.00%	100.00%
Edenor (1)(7)	Argentina	Distribution of energy	56.32%	52.18%
Enecor S.A.	Argentina	Transportation of electricity	69.99%	69.99%
HIDISA	Argentina	Generation	61.00%	61.00%
HINISA	Argentina	Generation	52.04%	52.04%
PACOSA	Argentina	Trader	100.00%	100.00%
PEA (2)	Argentina	Generation	-	100.00%
PEB	Bolivia	Investment	100.00%	100.00%
PACOGEN	Argentina	Investment	100.00%	100.00%
PEFM (3)	Argentina	Generation	-	100.00%
Petrobras Energía Colombia Gran Cayman (4)	Colombia	Oil	-	100.00%
Petrobras Energía Ecuador	Gran Cayman	Investment	100.00%	100.00%
Energía Operaciones ENOPSA S.A.	Ecuador	Oil	100.00%	100.00%
Petrolera San Carlos S.A.	Venezuela	Oil	100.00%	100.00%
PHA (5)	Argentina	Investment	100.00%	100.00%
PISA	Uruguay	Investment	100.00%	100.00%
PP	Argentina	Investment	100.00%	100.00%
PPSL (6)	Spain	Investment	-	100.00%
TGU	Uruguay	Gas transportation	100.00%	100.00%
Transelec	Argentina	Investment	100.00%	100.00%
Trenerec Energía Bolivia S.A.	Bolivia	Investment	100.00%	100.00%
Trenerec S.A.	Ecuador	Investment	100.00%	100.00%

(1)	Corresponds to effective interest considering the treasury shares in Edenor´s effect (54.3664% nominal interest)
(2)	On May 29, 2019, PEA’s Shareholders’ Meetings resolved to change its corporate name to CTB. In the month of June 2019, the Company sold to PACOGEN and YPF 48% and 50%, respectively, of its interest in CTB, whereas PP sold to PACOGEN 2% of its interest in CTB.
(3)	See Note 5.1.1.2.
(4)	Liquidated in January 2019.
(5)	On March 28, 2019, the Company approved PHA’s international address change from Madrid (Spain), to the Autonomous City of Buenos Aires (Republic of Argentina), and on September 20, 2019, the change of jurisdiction was registered with the Public Registry.
(6)	Liquidated in December 2019.
(7)	As of December 31, 2019, the quotation of Edenor's ordinary shares and ADR published on the BCBA and the NYSE was $ 24.05 and U$S 6.26 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 149 million. It should be noted that, as of December 31, 2019, participation in Edenor does not exceed its recoverable value.

Summary statement of financial position for subsidiaries with significant non-controlling interest

	12.31.2019	12.31.2018
Non Current
Total non current assets	1,696	1,679
Borrowings	137	191
Other non current liabilities	460	474
Total non current liabities	597	665
Current
Cash and cash equivalents	7	1
Other current assets	292	363
Total current assets	299	364
Borrowings	28	29
Other current liabilities	383	528
Total current liabilities	411	557
Total equity	988	821
Non-controlling interest	451	396

Summary statement of comprehensive income (loss) for subsidiaries with significant non-controlling interest

	12.31.2019	12.31.2018	12.31.2017
Revenue	1,502	1,484	1,050
Depreciation	(77)	(68)	(57)
Interest income	20	18	12
Interest expense	(113)	(132)	(68)
Profit for the year before tax	381	164	148
Income tax	(178)	(50)	(14)
Profit for the year	203	114	134
Other comprehensive loss	-	(1)	-
Total comprehensive profit of the year	203	113	134
Income of the year attributable to non-controlling interest	98	55	65
Other comprehensive income of the year attributable to non-controlling interest	-	(1)	-
Comprehensive income of the year attributable to non-controlling interest	98	54	65

Summary statement of cash flow for subsidiaries with significant non controlling interest

	12.31.2019	12.31.2018	12.31.2017
Net cash generated by operating activities	170	255	78
Net cash used in investing activities	(86)	(221)	(63)
Net cash used in financing activities	(85)	(56)	(13)
(Decrease) increase  in cash and cash equivalents	(1)	(22)	2
Cash and cash equivalents at the begining of the year	1	3	3
Loss on net monetary position generated by cash and cash equivalents	7	19	2
Cash and cash equivalents at the end of the year	7	-	7

Investments in associates and joint ventures information

		Information about the issuer
	Main activity	Date	Share capital	Profit (loss) of the period / year	Equity	Direct and indirect participation %
Associates
Refinor	Refinery	09.30.2019	2	(3)	57	28.50%
OCP (1)	Investment	12.31.2019	100	22	266	15.91%
TGS (2)(5)	Transport of gas	12.31.2019	13	214	803	27.193%
Joint ventures
CIESA (2)	Investment	12.31.2019	11	109	405	50.00%
Citelec (3)	Investment	12.31.2019	9	38	176	50.00%
Greenwind	Generation	12.31.2019	-	(1)	(11)	50.00%
CTB (4)	Generation	12.31.2019	143	40	227	50.00%

(1)	The Company holds an indirect interest of 15.91% through PEB.
(2)	The Company holds a direct and indirect interest of 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. therefore, the Company has an indirect participation of 25.50% in TGS. The Company holds a direct and indirect interest of 1.693% in TGS.
(3)	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.
(4)	The Company holds an indirect interest of 50% through PACOGEN.
(5)	As of December 31, 2019, the quotation of TGS's ordinary shares and ADR published on the BCBA and the NYSE was $ 108.65 and U$S 7.17 per share, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of U$S 306 million.

Interest in associates and joint ventures

	12.31.2019	12.31.2018
Disclosed in non-current assets
Associates
Refinor	20	25
OCP	33	35
TGS	21	-
	74	60
Joint ventures
CIESA	235	259
Citelec	88	88
CTB	114	-
	437	347
	511	407
Disclosed in non-current liabilities
Greenwind (1)	4	4
	4	4

⁽¹⁾    The Company provides financial assistance to this company.

Result from interests in associates and joint ventures

	12.31.2019	12.31.2018	12.31.2017
Associates
Oldelval	-	3	1
Refinor	(3)	(4)	(3)
OCP	21	35	-
TGS	1	-	-
	19	34	(2)
Joint ventures
CIESA	50	74	25
CTB	13	-	-
Citelec	19	21	27
Greenwind	-	(11)	(2)
	82	84	50

Evolution of interests in associates and joint ventures

	Note	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year		403	315	255
Reclassifications (1)		(16)	-	12
Dividends	17	(75)	(19)	-
Decreases		-	(10)	-
Increases		108	-	-
Share of profit		101	118	48
Other comprehensive loss		-	(1)	-
Exchange differences on translation		(14)	-	-
At the end of the year		507	403	315

⁽¹⁾ In 2019, mainly corresponds to the financial credit with OCP acquired in the transaction with AGIP (see Note 5.3.6.2), and in 2017 corresponds to the deconsolidation for sale of the interest in Greenwind.

Consideration transferred and the fair value of the assets acquired and the liabilities assumed

The following table details the consideration transferred and the fair value of the assets acquired and the liabilities assumed by CTB as of June 26, 2019:

	in million U$S
Total consideration transferred (1)	(272)
Financial assets at fair value	16
Property, plant and equipment	477
Inventories	8
VRDs	(229)
Fair value of net assets	272

⁽¹⁾    Includes U$S 53 million for the purchase of the acquired VRDs and considers a U$S 10 million of a price adjustment in favor of CTB.

The following table details the consideration transferred and the fair value of the assets acquired and the profit recorded by PEB as of June 20, 2019:

	in million  U$S
Acquisition cost (1)	(0.4)
Contingent consideration (2)	(0.1)
Total consideration	(0.5)
Share value of the interest in the fair value of associates’s identifiable assets and liabilities	9.0
Financial credit with OCP	14.2
Dividends to be received	2.5
Assets fair value	25.7
Profit (3)	25.2

(1)	Including expenses paid by PEB to the Ecuadorian Government (Ministry of the Environment) of U$S 0.1 million for the granting of the authorization to transfer the shares held by AGIP and other advisory expenses related to the transaction.
(2)	Contingent consideration calculated based on the estimated of the likelihood of collection of the financial credit with OCP prior to maturity.
(3)	Disclosed under “Share of profit (loss) from associates and joint ventures”

Participation in exploration and production of oil and gas areas

			Participation
Name	Note	Location	Direct	Indirect	Operator	Duration Up To
Argentine production
Río Neuquén		Río Negro and Neuquén	31.43% 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		Salta	15.00%	-	Tecpetrol	2023/2027
Gobernador Ayala		Mendoza	22.51%	-	Pluspetrol	2036
Anticlinal Campamento		Neuquén	15.00%	-	Oilstone	2026
Estación Fernández Oro		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
Foreign (1)
Oritupano - Leona		Venezuela	-	22.00%	PDVSA	2025
Acema		Venezuela	-	34.49%	PDVSA	2025
La Concepción		Venezuela	-	36.00%	PDVSA	2025
Mata		Venezuela	-	34.49%	PDVSA	2025
Argentine exploration
Parva Negra Este (2)		Neuquén	42.50%	-	PAMPA	2019
Chirete (3)		Salta	50.00%	-	High Luck Group Limited	2019
Río Atuel		Mendoza	33.33%	-	Petrolera El Trebol	2020
Borde del Limay (4)		Neuquén	85.00%	-	PAMPA	2015
Los Vértices (4)		Neuquén	85.00%	-	PAMPA	2015
Las Tacanas Norte		Neuquén	90.00%	-	PAMPA	2023

⁽¹⁾   Participation in mixed companies in Venezuela (see Note 5.3.6.1).

⁽²⁾   In the process of requesting appraisal.

⁽³⁾   In the process of requesting an exploration concession.

⁽⁴⁾   In the process of being transferred to GyP.

Exploratory well costs

	12.31.2019	12.31.2018	12.31.2017
At the beginning of the year	19	12	16
Increases	30	8	8
Transferred to development	(11)	-	(8)
Loss of the year	(5)	(1)	(1)
At the end of the year	33	19	15
Number of wells at the end of the year	9	7	7

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1. GENERAL INFORMATION AND GROUP STRUCTURE

12 Months Ended

Dec. 31, 2019

General Information And Group Structure

GENERAL INFORMATION AND GROUP STRUCTURE

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, has a 4,751 MW installed capacity, which represents approximately 12% of Argentina’s installed capacity, and is the second largest independent generator in the country. Additionally, the Company is currently undergoing a process to expand its capacity by 471 MW.

In the distribution segment, the Company has a controlling interest in Edenor, the largest electricity distributor in Argentina, which has more than 3.1 million customers and a concession area covering the Northern part of the City of Buenos Aires and Northwestern Greater Buenos Aires.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, with operations in 12 production areas and 6 exploratory areas reaching a production level of 7.3 million m3/day of natural gas and 5,000 barrels/day of oil equivalent for oil in Argentina, as of December 31, 2019. Its main natural gas production blocks are located in the Provinces of Neuquén and Río Negro. The results and cash flows for 2018 and 2017 associated with the divestment mentioned in Note 5.2.1 are disclosed under discontinued operations.

In the petrochemicals segment, operations are located in the Republic of Argentina, where the Company operates three high-complexity plants producing styrene, synthetic rubber and polystyrene, with a domestic market share ranging between 89% and 100%.

Finally, through the holding and others segment, the Company participates in the transmission and gas transportation businesses. In the transmission business, the Company jointly controls Citelec, which has a controlling interest in Transener, a company engaged in the operation and maintenance of a 20,981 km high-voltage electricity transmission network in Argentina with an 85% 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 9,231 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. Additionally, the segment includes advisory services provided to related companies.

The results and cash flows for 2018 and 2017 associated with the divestment of the main assets of the refining and distribution segment mentioned in Note 5.2.2 are disclosed under discontinued operations in the Holding and others segment.  

1.2   Economic context in which the Company operates

The Company operates in a complex economic context which main variables have recently suffered significant volatility both in the domestic and international spheres.

At the domestic level, a 2.5% year-on-year drop in the GDP was recorded in the first semester of 2019, cumulative inflation in 2019 reached 53.8% (IPC), and the significant devaluation of the peso as from August generated an unexpected draining of dollar-denominated deposits from the financial system (and, consequently, a drop in BCRA’s reserves) and an increase in the benchmark interest rate, which came to exceed 80% over the year (and being at about 60% as of the closing hereof).

On December 10, 2019 a new Federal Government took office, which declared a public emergency in economic, financial, fiscal, administrative, pension, tariff, energy, health and social matters until December 31, 2020 and implemented a series of measures, which are summarized below:

-        The delegation to the PEN of the power to maintain electricity and gas tariffs which are under federal jurisdiction, and to begin a process for the renegotiation or an extraordinary review of the current RTI, for a term of 180 days, with the purpose of reducing the actual tariff burden on households, businesses and industries for 2020;

-        The delegation to the PEN of the power to conduct an administrative intervention of the ENRE and the ENARGAS for a term of one year;

-        The suspension of the application of section 124, second paragraph, of Law No. 27,467, which divested the ENRE, effective as from Edenor and Edesur’s transfer to the jurisdiction of the Province of Buenos Aires and the Autonomous City of Buenos Aires, of its powers and functions associated with the electricity distribution utility, which powers it will keep for a year;

-        The establishment of a regime for the regularization of tax, social security and customs obligations for micro, small and middle-sized companies;

-        The suspension of the unification of employer contribution rates;

-        The PEN’s capacity to provide for mandatory minimum salary increases in the private sector (with the temporary exemption from the payment of contributions to the Argentine social security system of the salary increases granted under this capacity or under collective bargaining agreements);

-        The suspension until fiscal years starting on or after January 1, 2021 of the decrease in the income tax rate, which will remain at 30%, and the keeping of the 7% withholdings on dividends during such period (see Note 2.6.1.2);

-        The setting of a new mechanism for allocating the tax inflation adjustment for the first and second fiscal years starting on or after January 1, 2019 (see Note 2.6.1.5);

-        An increase in export duties (with the exception of hydrocarbons and mining) and in personal assets tax rates;

-        The reinstatement of the value-added tax on basic food basket products and the suspension of the pension mobility;

-        The modification of the schedular taxation system and the restoration of income tax exemptions for certain securities and bonds;

-        The creation of the Tax for an Inclusive and Supportive Argentina (PAIS) for a term of five fiscal periods.

-        The extended life of BCRA’s regulations regarding the inflow and outflow of foreign exchange in the foreign exchange market.

Additionally, the Federal Government is preparing a proposal for the renegotiation of the external debt with international creditors.

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 Consolidated Financial Statements should be read in the light of these circumstances.

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17. RELATED PARTIES TRANSACTIONS (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of transactions between related parties [line items]
Finance income	$ 96	$ 99	$ 62
Total related parties
Disclosure of transactions between related parties [line items]
Finance income	3	3	3
TGS
Disclosure of transactions between related parties [line items]
Finance income	$ 3	$ 3	$ 3

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5. GROUP STRUCTURE (Details 4) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non Current
Total non current assets	$ 4,322	$ 4,151
Borrowings	1,764	1,835
Total non current liabities	2,421	2,695
Current
Cash and cash equivalents	225	241	$ 31	$ 69
Total current assets	1,362	1,521
Borrowings	183	342
Total current liabilities	854	1,182
Total equity	2,409	1,795	$ 1,969	$ 1,607
Non-controlling interest	492	429
Edenor
Non Current
Total non current assets	1,696	1,679
Borrowings	137	191
Other non current liabilities	460	474
Total non current liabities	597	665
Current
Cash and cash equivalents	7	1
Other current assets	292	363
Total current assets	299	364
Borrowings	28	29
Other current liabilities	383	528
Total current liabilities	411	557
Total equity	988	821
Non-controlling interest	$ 451	$ 396

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17. RELATED PARTIES TRANSACTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Refinor
Disclosure of transactions between related parties [line items]
Sales of goods and services	$ 18	$ 16	$ 5
Total related parties
Disclosure of transactions between related parties [line items]
Sales of goods and services	49	69	29
CTB
Disclosure of transactions between related parties [line items]
Sales of goods and services	1	0	0
Transener
Disclosure of transactions between related parties [line items]
Sales of goods and services	0	1	1
TGS
Disclosure of transactions between related parties [line items]
Sales of goods and services	29	51	23
Greenwind
Disclosure of transactions between related parties [line items]
Sales of goods and services	1	0	0
SACDE
Disclosure of transactions between related parties [line items]
Sales of goods and services	$ 0	$ 1	$ 0

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13. EQUITY COMPONENTS (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Components
Earnings for continuing operations attributable to the equity holders of the Company	$ 692	$ 146	$ 341
Weighted average amount of outstanding shares, continuing operations	48	52	51
Basic and diluted earnings per share from continuing operations	$ 14.42	$ 2.81	$ 6.69
(Loss) earnings for discontinued operations attributable to the equity holders of the Company	$ 0	$ 78	$ (55)
Weighted average amount of outstanding shares, discontinued operations	48	52	51
Basic and diluted earnings per share for discontinued operations	$ .00	$ 1.50	$ (1.07)
Total earnings attributable to the equity holders of the Company	$ 692	$ 224	$ 286
Weighted average amount of outstanding shares	48	52	51
Basic and diluted earnings per share	$ 14.42	$ 4.31	$ 5.61

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5. GROUP STRUCTURE (Details 8) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of joint ventures [line items]
Interests in associates	$ 74	$ 60
Interests in joint ventures	437	347
Interests in associates and joint ventures	511	407
Investments in joint ventures and associates	4	4
CIESA
Disclosure of joint ventures [line items]
Interests in joint ventures	235	259
Citelec
Disclosure of joint ventures [line items]
Interests in joint ventures	88	88
CTB
Disclosure of joint ventures [line items]
Interests in joint ventures	114	0
Greenwind
Disclosure of joint ventures [line items]
Investments in joint ventures and associates	4	4
Refinor
Disclosure of joint ventures [line items]
Interests in associates	20	25
OCP
Disclosure of joint ventures [line items]
Interests in associates	33	35
TGS
Disclosure of joint ventures [line items]
Interests in associates	$ 21	$ 0

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11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 7) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
DisclosureOfInventoryLineItems [Line Items]
Inventories	$ 153	$ 137	$ 113	$ 164
Materials and spare parts
DisclosureOfInventoryLineItems [Line Items]
Inventories	95	94
Advances to suppliers
DisclosureOfInventoryLineItems [Line Items]
Inventories	21	2
In process and finished products
DisclosureOfInventoryLineItems [Line Items]
Inventories	37	40
Stock of crude oil
DisclosureOfInventoryLineItems [Line Items]
Inventories	$ 0	$ 1

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10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Items Of Statement Of Comprehensive Income
Current tax	$ 70	$ 39	$ 55
Deferred tax	(57)	(19)	(72)
Other comprehensive income	0	1	0
Difference in the estimate of previous fiscal year income tax and the income tax statement	1	(4)	(12)
Direct changes for income tax	0	0	3
Optional tax revaluation	34	0	0
Income tax expense (benefit)	$ 48	$ 17	$ (26)

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10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	$ 174	$ 206	$ 198
Salaries and social security charges
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	62	81	77
Benefits to the employees
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	8	5	5
Accrual of defined benefit plans
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	8	1	6
Work contracts, fees and compensation for services
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	52	68	53
Compensation agreements
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	0	3	20
Directors and Syndicates fees
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	7	5	4
Depreciation of property, plant and equipment
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	14	12	6
Consumption of materials
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	3	4	3
Maintenance
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	2	2
Transport and per diem
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	2	2
Rental and insurance
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	5	6	6
Surveillance and security
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	5	4
Taxes, rates and contributions
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	8	4
Communications
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	2	2
Right-of-use assets amortization
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	2	0	0
Institutional advertising and promotion
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	0	1	2
Other
DisclosureOfAdministrativeExpensesLineItems [Line Items]
Administrative expenses	$ 3	$ 1	$ 2

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11. NON-FINANCIAL ASSETS AND LIABILITIES (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about intangible assets [line items]
Intangible assets amortization, beginning	$ (153)	$ (146)
Amortization for the year	(8)	(7)
Intangible assets amortization, ending	(161)	(153)
Concession agreements
Disclosure of detailed information about intangible assets [line items]
Intangible assets amortization, beginning	(151)
Amortization for the year	(8)
Intangible assets amortization, ending	(159)	(151)
Intangibles identified in acquisitions of companies
Disclosure of detailed information about intangible assets [line items]
Intangible assets amortization, beginning	(2)
Amortization for the year	0
Intangible assets amortization, ending	$ (2)	$ (2)

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10. OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME (Details 7) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	$ 111	$ 52
2020
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	0	3
2021
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	4	18
2022
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	3	4
2023
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	38	27
2024
DisclosureOfTaxLossCarryforwardsLineItems [Line Items]
Recognized tax loss-carryforwards	$ 66	$ 0

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7. SEGMENT INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of operating segments [line items]
Revenue	$ 2,836	$ 2,920	$ 2,175
Intersegment sales	0	0	0
Cost of sales	(2,032)	(1,967)	(1,574)
Gross profit (loss)	804	953	601
Selling expenses	(148)	(171)	(127)
Administrative expenses	(174)	(206)	(198)
Exploration expenses	(9)	(1)	(2)
Other operating income	40	181	149
Other operating expenses	(86)	(200)	(103)
Impairment of property, plant and equipment and intangible assets	(62)	(32)	0
Share of profit (loss) of associates and joint ventures	101	118	48
Income from the sale of associates	0	28	0
Agreement on the regularization of obligations	285	0	0
Operating income (loss)	751	670	368
Gain (loss) on net monetary position, net	187	629	304
Financial income	96	99	62
Financial costs	(299)	(316)	(232)
Other financial results	113	(858)	(100)
Financial results, net	97	(446)	34
Profit (loss) before income tax	848	224	402
Income tax	(48)	(17)	26
Profit (loss) for the year from continuing operations	800	207	428
Profit (loss) for the year from discontinued operations	0	80	(50)
Profit (loss) for the year	800	287	378
Depreciation and amortization	263	234	205
Total profit (loss) attributable to:
Owners of the company	692	224	286
Non - controlling interest	108	63	92
Assets	5,684	5,672	5,657
Liabilities	3,275	3,877	3,687
Increases in property, plant and equipment, intangibles assets and right-of-use assets	611	665	657
Net book values of property, plant and equipment	3,507	3,316
Generation
Disclosure of operating segments [line items]
Revenue	819	604	351
Intersegment sales	0	2	2
Cost of sales	(466)	(273)	(195)
Gross profit (loss)	353	333	158
Selling expenses	(3)	(1)	(4)
Administrative expenses	(36)	(41)	(32)
Exploration expenses	0	0	0
Other operating income	9	11	19
Other operating expenses	(11)	(17)	(9)
Impairment of property, plant and equipment and intangible assets	(52)	0
Share of profit (loss) of associates and joint ventures	13	(11)	(2)
Income from the sale of associates		0
Agreement on the regularization of obligations	0
Operating income (loss)	273	274	130
Gain (loss) on net monetary position, net	0	233	17
Financial income	51	52	39
Financial costs	(82)	(85)	(69)
Other financial results	86	(365)	(34)
Financial results, net	55	(165)	(47)
Profit (loss) before income tax	328	109	83
Income tax	(80)	(3)	(4)
Profit (loss) for the year from continuing operations		106	79
Profit (loss) for the year from discontinued operations		0	0
Profit (loss) for the year	248	106	79
Depreciation and amortization	71	66
Total profit (loss) attributable to:
Owners of the company	239	100	75
Non - controlling interest	9	6	4
Assets	1,472	1,414	1,115
Liabilities	1,226	1,054	333
Increases in property, plant and equipment, intangibles assets and right-of-use assets	240	235	275
Net book values of property, plant and equipment	1,152	1,036
Distribution of energy
Disclosure of operating segments [line items]
Revenue	1,502	1,484	1,050
Intersegment sales	0	0	0
Cost of sales	(1,225)	(1,136)	(799)
Gross profit (loss)	277	348	251
Selling expenses	(122)	(134)	(95)
Administrative expenses	(65)	(76)	(66)
Exploration expenses	0	0	0
Other operating income	10	9	4
Other operating expenses	(43)	(44)	(33)
Impairment of property, plant and equipment and intangible assets	0	0
Share of profit (loss) of associates and joint ventures	0	0	0
Income from the sale of associates		0
Agreement on the regularization of obligations	285
Operating income (loss)	342	103	61
Gain (loss) on net monetary position, net	187	226	145
Financial income	20	18	12
Financial costs	(112)	(132)	(69)
Other financial results	(62)	(50)	1
Financial results, net	33	62	89
Profit (loss) before income tax	375	165	150
Income tax	(178)	(49)	(12)
Profit (loss) for the year from continuing operations		116	138
Profit (loss) for the year from discontinued operations		0	0
Profit (loss) for the year	197	116	138
Depreciation and amortization	79	69
Total profit (loss) attributable to:
Owners of the company	98	61	73
Non - controlling interest	99	55	65
Assets	1,480	2,133	1,972
Liabilities	1,792	1,241	1,166
Increases in property, plant and equipment, intangibles assets and right-of-use assets	173	227	225
Net book values of property, plant and equipment	1,691	1,657
Oil and gas
Disclosure of operating segments [line items]
Revenue	174	458	443
Intersegment sales	270	63	19
Cost of sales	(313)	(287)	(310)
Gross profit (loss)	131	234	152
Selling expenses	(12)	(19)	(17)
Administrative expenses	(47)	(56)	(54)
Exploration expenses	(9)	(1)	(2)
Other operating income	8	141	110
Other operating expenses	(11)	(114)	(38)
Impairment of property, plant and equipment and intangible assets	(10)	0
Share of profit (loss) of associates and joint ventures	21	37	1
Income from the sale of associates		28
Agreement on the regularization of obligations	0
Operating income (loss)	71	250	152
Gain (loss) on net monetary position, net	0	107	(18)
Financial income	18	15	6
Financial costs	(94)	(79)	(78)
Other financial results	84	(512)	(93)
Financial results, net	8	(469)	(183)
Profit (loss) before income tax	79	(219)	(31)
Income tax	(16)	57	24
Profit (loss) for the year from continuing operations		(162)	(7)
Profit (loss) for the year from discontinued operations		49	(35)
Profit (loss) for the year	63	(113)	(42)
Depreciation and amortization	112	92
Total profit (loss) attributable to:
Owners of the company	63	(115)	(62)
Non - controlling interest	0	2	20
Assets	1,261	1,237	1,154
Liabilities	465	1,273	444
Increases in property, plant and equipment, intangibles assets and right-of-use assets	191	192	140
Net book values of property, plant and equipment	612	554
Petrochemicals
Disclosure of operating segments [line items]
Revenue	321	338	314
Intersegment sales	0	0	0
Cost of sales	(298)	(334)	(290)
Gross profit (loss)	23	4	24
Selling expenses	(9)	(13)	(12)
Administrative expenses	(4)	(6)	(16)
Exploration expenses	0	0	0
Other operating income	4	5	3
Other operating expenses	(9)	(20)	(10)
Impairment of property, plant and equipment and intangible assets	0	(32)
Share of profit (loss) of associates and joint ventures	0	0	0
Income from the sale of associates		0
Agreement on the regularization of obligations	0
Operating income (loss)	5	(62)	(11)
Gain (loss) on net monetary position, net	0	49	2
Financial income	1	1	0
Financial costs	(8)	(15)	(10)
Other financial results	18	(39)	(6)
Financial results, net	11	(4)	(14)
Profit (loss) before income tax	16	(66)	(25)
Income tax	(5)	12	19
Profit (loss) for the year from continuing operations		(54)	(6)
Profit (loss) for the year from discontinued operations		0	0
Profit (loss) for the year	11	(54)	(6)
Depreciation and amortization	1	6
Total profit (loss) attributable to:
Owners of the company	11	(54)	(6)
Non - controlling interest	0	0	0
Assets	136	153	141
Liabilities	122	198	94
Increases in property, plant and equipment, intangibles assets and right-of-use assets	4	4	5
Net book values of property, plant and equipment	18	15
Holding and others
Disclosure of operating segments [line items]
Revenue	20	36	17
Intersegment sales	0	0	0
Cost of sales	0	0	(1)
Gross profit (loss)	20	36	16
Selling expenses	(2)	(4)	0
Administrative expenses	(22)	(27)	(30)
Exploration expenses	0	0	0
Other operating income	9	15	13
Other operating expenses	(12)	(6)	(13)
Impairment of property, plant and equipment and intangible assets	0	0
Share of profit (loss) of associates and joint ventures	67	92	49
Income from the sale of associates		0
Agreement on the regularization of obligations	0
Operating income (loss)	60	106	35
Gain (loss) on net monetary position, net	0	12	158
Financial income	7	14	7
Financial costs	(4)	(6)	(8)
Other financial results	(13)	108	32
Financial results, net	(10)	128	189
Profit (loss) before income tax	50	234	224
Income tax	231	(34)	(1)
Profit (loss) for the year from continuing operations		200	223
Profit (loss) for the year from discontinued operations		31	(16)
Profit (loss) for the year	281	231	207
Depreciation and amortization	0	1
Total profit (loss) attributable to:
Owners of the company	281	231	207
Non - controlling interest	0	0	0
Assets	1,527	872	1,475
Liabilities	(160)	247	1,850
Increases in property, plant and equipment, intangibles assets and right-of-use assets	3	7	12
Net book values of property, plant and equipment	34	54
Eliminations
Disclosure of operating segments [line items]
Revenue	0	0	0
Intersegment sales	(270)	(65)	(21)
Cost of sales	270	63	21
Gross profit (loss)	0	(2)	0
Selling expenses	0	0	1
Administrative expenses	0	0	0
Exploration expenses	0	0	0
Other operating income	0	0	0
Other operating expenses	0	1	0
Impairment of property, plant and equipment and intangible assets	0	0
Share of profit (loss) of associates and joint ventures	0	0	0
Income from the sale of associates		0
Agreement on the regularization of obligations	0
Operating income (loss)	0	(1)	1
Gain (loss) on net monetary position, net	0	2	0
Financial income	(1)	(1)	(2)
Financial costs	1	1	2
Other financial results	0	0	0
Financial results, net	0	2	0
Profit (loss) before income tax	0	1	1
Income tax	0	0	0
Profit (loss) for the year from continuing operations		1	1
Profit (loss) for the year from discontinued operations		0	1
Profit (loss) for the year	0	1	2
Depreciation and amortization	0	0
Total profit (loss) attributable to:
Owners of the company	0	1	2
Non - controlling interest	0	0	0
Assets	(192)	(137)	(200)
Liabilities	(170)	(136)	(200)
Increases in property, plant and equipment, intangibles assets and right-of-use assets	0	0	$ 0
Net book values of property, plant and equipment	$ 0	$ 0