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Pampa Energía ● 2019 Annual Report ● 1



Contents

Glossary of Terms 5

1. 2019 Results and Future Outlook 11

2. Corporate Governance 14

3. Our Shareholders / Stock Performance 21

4. Macroeconomic Context 23

5. The Argentine Electricity Market 24

6. The Argentine Oil and Gas Market 46

7. Relevant Events 61

8. Description of Our Assets 81

9. Human Resources 105

10. Community and Pampa Energía Foundation 109

11. Information Technology 114

12. Quality, Safety, Environment and Labor Health 115

13. Results for the Fiscal Year 118

14. Dividend Policy 138

15. Board of Directors’ Proposal 139

Appendix I: Corporate Governance Report 140


2019 Annual Report

To the shareholders of Pampa Energía S.A. (‘Pampa’, the ‘Company’ or the ‘Group’):

Pursuant to the statutory rules and Bylaws currently in force, we submit to your consideration the Annual Report and Financial Statements for the 76th fiscal year ended December 31, 2019.


Glossary of Terms

Term Definition

+GC Panel ByMA’s Corporate Governance Plus Panel

ABOL Argentine Business Organizations Law No. 19,550

ADRs/ADSs American Depositary Receipts

AGIP Agip Oleoducto de Crudos Pesados BV

AR$ Argentine Pesos

Bbl Barrel

BCBA Bolsa de Comercio de Buenos Aires (Buenos Aires Stock Exchange)

BCRA Banco Central de la República Argentina (Central Bank of the Republic of Argentina)

BICE Banco de Inversión y Comercio Exterior (Investment and Foreign Trade Bank)

BNA Banco de la Nación Argentina (Argentine National Bank)

BO Boletín Oficial (Public Gazette)

Board of Directors/The Board

Pampa Energía’s Board of Directors

Boe Barrels of oil equivalent

BOPS Bi–orientated polystyrene

BTU British Thermal Unit

Buyback Programs Share buyback programs approved on April 27, 2018; June 22, 2018; March

27, 2019; August 12, 2019 and November 8, 2019

Bylaws Pampa Energía’s Bylaws

ByMA Bolsas y Mercados Argentinos (Buenos Aires Stock Exchange)

CAMMESA Compañía Administradora del Mercado Mayorista Eléctrico S.A. (Argentine Wholesale Electricity Market Clearing Company)

CAU Cargo de Acceso y Uso (Access and Use Position)

CBs Corporate Bonds

CC Combined Cycle

CEE Comité Ejecutivo de Emergencia (Emergency Executive Committee)

CEO Chief Executive Officer

CFO Chief Financial Officer

CH Hydroelectric power plant

CIESA Compañía de Inversiones de Energía S.A.

Citelec Compañía Inversora en Transmisión Eléctrica Citelec S.A.

CMA Capital Markets Act No. 26,831

CNG Compressed Natural Gas

CNV Comisión Nacional de Valores (National Securities and Exchange Commission)

Code Pampa’s Code of Corporate Governance


COPOLAD Cooperation Programme between Latin America, the Caribbean and the European Union on Drugs Policies

CPB Central Piedra Buena S.A.

CPD Costo Propio de Distribución (Own Distribution Cost)

CPI Consumer Price Index

CSJN Corte Suprema de Justicia de la Nación Argentina (Supreme Court of Justice of the Republic of Argentina)

CT Thermal power plant

CTBSA CT Barragán S.A.

CTEB Central Térmica Ensenada Barragán

CTEB Trust Supplementary agreement pursuant to the global administration and financial trusts program for the execution of energy infrastructure works-Series 1- ENARSA (Barragán)

CTG Central Térmica Güemes

CTGEBA Central Térmica Genelba

CTIW Central Térmica Ingeniero White

CTLL Central Térmica Loma De La Lata

CTP Central Térmica Piquirenda

CTPP Central Térmica Parque Pilar

CVP Costo Variable de Producción (Variable Production Cost)

DAD Desconexión Automática de Demanda de Exportación (Automatic Export Demand Disconnection)

DAG Desconexión Automática de Generación (Automatic Generation Disconnection)

Dam3 Cubic decameters

DIGO Guaranteed Availability Commitments

DisTro High-Voltage Electric Power Transmission System and/or Main Distribution Electric Power Transmission System

DNU Decreto de Necesidad y Urgencia (Necessity and Urgency Decree)

DoP Deliver or Pay

E&P Exploration and Production

EBITDA Earnings before interest, tax, depreciation and amortization

EcoEnergía EcoEnergía Co-Generation Power Plant

Edenor Empresa Distribuidora y Comercializadora Norte S.A.

ENARGAS Ente Nacional Regulador del Gas (National Gas Regulatory Entity)

ENARSA / IEASA Integración Energética Argentina S.A. (former Energía Argentina S.A.)

Energía Plus Energía Plus Program, SE Res. No. 1,281/06

ENRE Ente Nacional Regulador de la Electricidad (National Electricity Regulatory Entity)

ExxonMobil ExxonMobil Exploration Argentina S.R.L.

FO Fuel Oil

FOB Free on Board


FOCEDE Fondo de Obras de Consolidación y Expansión de Distribución Eléctrica (Fund

for Electricity Distribution Expansion and Consolidation Works)

FODER Fondo para el Desarrollo de Energía Renovables (Fund for the Development of Renewable Energies)

FONINVEMEM Fondo para Inversiones Necesarias que permitan incrementar la oferta de energía eléctrica en el Mercado Eléctrico Mayorista (Fund for Investments required to increase the Power Supply in the Electricity Wholesale Market)

FOTAE Fideicomiso de Obras de Transporte para el Abastecimiento Eléctrico (Transportation Works Trust for Electricity Supply)

Foundation Fundación Pampa Energía

FS Financial Statements

FV Face Value

FX Nominal exchange rate(s)

GB Great Britain

GDP Gross Domestic Product

GE General Electric

GHG Greenhouse Gases

GO Gas Oil (Diesel Oil)

Government / National Administration / Federal Government

Federal Government of the Republic of Argentina

GS Gas Station

GT Gas Turbine

GU Large Users

GUDI Large Distribution Company Users

GUMA Major Large Users

GUME Minor Large Users

GWh Gigawatt-hour

GyP Gas y Petróleo de Neuquén S.A.P.E.M.

HI Hydroelectric plants

HIDISA Hidroeléctrica Diamante S.A.

HINISA Hidroeléctrica Los Nihuiles S.A.

HPPL Hidroeléctrica Pichi Picún Leufú

Hydrocarbon Investments Committee

National Plan for Hydrocarbon Investments’ Strategic Planning and Coordination Committee

ICBC Industrial and Commercial Bank of China Dubai Branch

ICSID International Centre for Settlement of Investment Disputes

IDB Inter-American Development Bank

IFRS International Financial Reporting Standards

IGJ Inspección General de Justicia (Public Registry of Organizations)

INDEC Instituto Nacional de Estadística y Censos de Argentina (National Institute of Statistics and Censuses)


IPIM Índice de Precios Internos al por Mayor (Wholesale Domestic Price Index)

Kb/kbbl/kboe Thousand barrels/thousand barrels of oil equivalent

kCal Kilocalories

kton Thousand tons

kW Kilowatt

kWh Kilowatt-hour

LNG Liquefied Natural Gas

LPG Liquefied Petroleum Gas

LU300 Large users with demands in excess of 300 kW

LVFVD Liquidaciones de Ventas sin Fecha de Vencimiento a Definir (Sales Settlements with Maturity Date to be Defined)

M3 Cubic meters

MAT Term Market

MAT ER Term Market from Renewable Energy Sources

MBTU Million BTUs

MDP Ministry of Productive Development (former SGE)

MEGSA Mercado Electrónico de Gas S.A.

Merval Mercado de Valores de Buenos Aires (Buenos Aires Securities Market)

MEyM Former Ministry of Energy and Mining

MinEn Former Ministry of Energy (former MEyM)

MMC Cost Monitoring Mechanism

MW Mega watt

MWh Mega watt-hour

N.a. Not applicable

N/A Not available

NGL Natural Gas Liquids

NYSE New York Stock Exchange

OCP Oleoducto de Crudos Pesados

OED Organismo Encargado del Despacho (Agency in Charge of Dispatch)

OldelVal Oleoductos del Valle S.A.

PACOGEN Pampa Cogeneración S.A.

Pampa / the Company /

the Group / the Issuer Pampa Energía S.A. and its subsidiaries

PEB Pampa Energía Bolivia

PEFM Parques Eólicos del Fin del Mundo

PEMC Parque Eólico Ingeniero Mario Cebreiro

PEN Poder Ejecutivo Nacional (National Executive Branch)

PEPASA / Petrolera Pampa Former Petrolera Pampa S.A.


PEPE Parque Eólico Pampa Energía

Petrobras Argentina Former Petrobras Argentina S.A.

PGSM Puerto General San Martín port

PIST Transportation System Entry Point or natural gas price at wellhead

Plan Gas Natural Gas Surplus Injection Promotion Program (SE Res. No. 1/13) and Natural Gas Injection Promotion Program for Companies with Reduced Injection (SE Res. No. 60/13)

Polisur PBB Polisur S.A.

PPA Power Purchase Agreement

Priority Demand Set of residential users, hospitals, schools, healthcare centers and other

essential services

PUREE Program for the Rational Use of Electric Power

QSELH Quality, Safety, Environment and Labor Health

R&D Refining and Distribution segment

RCD Campo Durán Refinery

RDSA Rivera Desarrollos S.A.

RECPAM Results from net monetary position

Refinor Refinería del Norte S.A.

RENPER Registry of Renewable Electric Power Generation Projects

Res. Resolution(s)

RET Régimen Especial Temporario (Temporary Special Regime)

RTI Integral Tariff Review

RTP Plant’s thermal reduction

S&P Standard & Poor’s Global Ratings

SADI Sistema Argentino de Interconexión (Argentine Electricity Grid)

SE Former Secretariat of Energy

SEC Security and Exchange Commission

Sect. Section(s)

SEDRONAR Secretariat of Planning for the Prevention of Drug Addiction and Action against Drug Trafficking

SEE Subsecretariat of Electric Energy (former Secretariat of Electric Energy)

Senior Management M. Mindlin, D. Mindlin, G. Mariani and R. Torres

SGE Former Government Secretariat of Energy (former MinEn)

SHC Subsecretariat of Hydrocarbons and Fuels

SME Subsecretariat of Electricity Market

Solidarity Law Social Solidarity and Productive Reactivation Law No. 27,541 within the framework of the Public Emergency

SOX Sarbanes-Oxley Act

SRH Subsecretariat of Hydrocarbon Resources (former Secretariat of Hydrocarbon

Resources)

SRRYME Secretariat of Renewable Resources and Electricity Market


ST Steam Turbine

Telcosur Telcosur S.A.

TGS Transportadora de Gas del Sur S.A.

TJSM Termoeléctrica José de San Martín

TMB Termoeléctrica Manuel Belgrano

Ton Metric ton

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.

TWh Terawatt-hour

UN United Nations

Unconventional Plan Gas Encouragement Program for the Investment in Development of Natural Gas Production from Unconventional Reservoirs Program, MEyM Res. No. 46, 419, 447 /17 and 12/18

UNIREN Public Utility Contract Renegotiation and Analysis Unit

US$ U.S. Dollars

UTE Joint Venture

VAD Distribution Added Value

VAT Value-added tax

VRDs Debt Securities

WEM Wholesale Electricity Market

WFP Wind Farm Project

YPF YPF S.A.


1. 2019 Results and Future Outlook

The fiscal year 2019 was once again characterized by the political uncertainty as a result of election

year, the worsening of the economic recession that continued damaging the country, and the general deterioration of all macroeconomic variables. In this difficult context, thanks to the outstanding work performed by the whole Company over the last fiscal years which, among other actions, included a swift divestment of non-strategic assets thus focusing on our core businesses, executing important investments though at the same time, maintaining high levels of liquidity and extending the average life of our financial liabilities, therefore we have recorded once again a positive year in several aspects, an achievement that makes us proud.

For the second consecutive year, we have positioned ourselves as the largest independent power producer in Argentina, representing 12% of the country’s total generation. In May we commissioned our

wind farms PEPE II and III for a total 106 MW of gross power capacity, and in mid-June we reached an important milestone in the most ambitious expansion project in the history of Pampa, the closing to combined cycle at CTGEBA Plus, adding 207 MW by the installation of a new turbine and the power capacity increase of the existing turbine. In June 2020 we expect to commission the combined cycle which, thanks

to the new steam turbine, will contribute an additional 176 MW of efficient energy to the SADI. In this way, Pampa will become the largest operator of combined cycles, with 4 out of the 25 combined cycles installed in the country, thus contributing to generating the least possible impact on the environment.

Moreover, by the end of last June and in partnership with YPF, we acquired the Ensenada Barragán Thermal Power Plant, with an installed capacity of 567 MW. This acquisition involves a closing to combined cycle expansion project for an additional capacity of 280 MW, vital to meet the growing consumption needs of the neighboring industrial area and Greater La Plata. The expansion project will require a US$200 million

investment and will provide direct employment to 650 people over an estimated 24-month period.

In summary, including expansions and acquisitions, in 2019 we added a total of 880 MW, reaching a total operated capacity of 4,751 MW. At Pampa we are proud of being engaged with the country’s energy needs throughout our Company’s entire history. We have actively and aggressively participated in each of

the calls for tenders launched by the Federal Government: since the beginnings with the Energía Plus Program, followed by Res. No. 220 in 2007, Res. No. 21 in 2016, the RenovAr and MAT ER programs in 2016 and 2017, respectively, and Res. No. 287 in 2017, we have invested a total of US$1.5 billion to

organically add a capacity of 1,500 MW to the Argentine Grid. Our goal in the power generation segment has always been growing on a sustainable basis, seeking maximum efficiency through renewable energy and highly productive thermal units.

The E&P area operated in another year marked by a sharp decrease in the domestic price of natural gas, a product which concentrates 80% of our sales in this segment. Even though it is difficult to summarize this situation in a few words, the main causes of this phenomenon are the promotion policies presenting

design and implementation flaws, in addition to the inability to pass through actual prices to consumers and the fiscal restraint that makes it impossible for the Federal Government to settle shortfalls.

Despite this scenario, in 2019 our gas production increased to an average of 7.3 million m3 per day, 9% higher than the previous year, mainly explained by the return of fuel self-procurement for power generators, which allowed synergies between Pampa’s two core businesses. The growth in production was mainly supported by the development of tight gas at El Mangrullo, connecting highly efficient wells that

lifts gas simultaneously from two formations, with a 51% year-on-year increase and reaching 4.2 million

m3 per day.

Moreover, with the purpose of quantifying our production potential in Vaca Muerta formation. In the gas window, two horizontal wells were drilled at El Mangrullo block, each with lateral branches of approximately 2,500 meters, completed with 35 fracking stages, which resulted in a joint initial gas production of 860,000 m3 per day, matching the best results obtained in the area by capitalizing on other operators’ learning curve. Besides, the first vertical pilot well and its horizontal branch with similar characteristics was drilled at Sierra Chata, which is pending completion but with prospective parameters.

At Rincón de Aranda, a block located in the crude oil window, we drilled and completed the first vertical


pilot well with its horizontal branch, with a 2,000-meter extension, which was completed with 27 fracking

stages and resulted in an initial flow of 1,132 barrels per day. As a result of this exploration campaign, 8% of our production in 2019 came from shale gas and oil, a major milestone for our business, which we expect to increase in 2020 by completing wells drilled last year and performing new drillings.

Another extremely significant event in this segment was the achievement, after 34 years with no new crude oil findings in the Noroeste Basin, of a discovery well at Chirete block, located in the Province of Salta. The well showed an initial production of 3,145 barrels per day and, in view of such potential, the facilities for its commercial exploitation were built. As of this date, together with our partner, we are

conducting negotiations with the provincial government for the granting of an exploitation license allowing us to boost investments.

The good results in the activities performed during this fiscal year allowed us to certify shale reserves from Vaca Muerta formation for the first time in our history and, even with a growing year-on-

year production of hydrocarbons, we also recorded once again a 1.3 positive reserve replacement ratio, with proven reserves reaching 135 million boe.

We hope the conditions necessary to significantly increase our pace of activity in this sector, which

is so critical for the country, will be restored soon. For this purpose, we consider it is key to significantly reduce the uncertainty surrounding the industry for more than a year. We are concerned about the lack of predictability faced by this business, which causes the activity to be at historically low levels. This, added to the fact that at present more than half of the domestic gas production comes from unconventional fields, which decline rate is much higher than that of conventional fields, makes us fear that, if the negative trend in reserves development is not reversed, the country may fall again in a growing need for gas imports,

with the resulting negative macroeconomic impact.

As regards our subsidiaries, in 2019 TGS successfully commissioned the 147-km gathering pipeline known as Vaca Muerta Pipeline and a gas conditioning plant, which were built to provide midstream services and assist producers in the evacuation of unconventional gas in the Neuquina Basin to the existing main gas pipelines. This milestone required an approximate US$260 million investment.

Fully aware of the reality of each of our subsidiaries, Edenor, once again and as we have been doing since we took over control in 2005, allocated 100% of its available funds to the investments needed

to continue improving service quality levels. As a result, it achieved a 99.82% grid availability in 2019, the best record in the last 10 years, a milestone which is reflected in the significant improvement in our customers’ satisfaction, which reached 76.3%.

In 2019, companies controlled and co-controlled by Pampa continued pursuing their investment commitment in the country, having disbursed a total of US$1,048 million1, a figure slightly lower than the US$1,138 million recorded in 2018. Out of the total investment, around US$500 million were disbursed for the maintenance of our assets, specifically the rendering of a quality service by our regulated subsidiaries,

and approximately US$550 million were allocated to expansions and non-recurring investments, mainly distributed between the construction of wind farms, the closing to combined cycle at Genelba Plus, TGS’s Vaca Muerta gas gathering pipeline and the exploration campaign mostly targeting Vaca Muerta formation.

1 The amount includes 100% of the investments in affiliates CTEB, PEMC, TGS, Transener, OldelVal and Refinor, which under IFRS are

not consolidated in Pampa’s FS and are denominated in nominal AR$ converted at the year’s average FX.


Amount Invested by Pampa Energía and its Subsidiaries

In million dollars

As regards our sustainability actions, Pampa reported for the second consecutive year its environmental, social and governance performance, and Pampa’s stock is listed in prestigious indexes and panels in this matter: IDB/BYMA’s sustainability index and Bloomberg’s gender-equality index, as well as BYMA’s Corporate Governance Plus Panel. These actions ratify our management’s commitment with

transparency, creating long-term sustainable value and prioritizing the welfare of all stakeholders (employees, communities where our assets are located, shareholders, lending institutions, customers, suppliers, among others).

Finally, as regards our financial activity, with the purpose of improving our maturities profile and preserve a solid cash position, the Company redeemed and pre-cancelled loans for US$366 million, repurchased in market own CBs for a total of US$74 million, refinanced maturities for US$74 million, and issued Series 3 CBs maturing in 2029 for US$300 million.

During most time of 2019 we continued with the Company’s share buyback program started in the

previous year. We have advanced this program based on our conviction on Pampa’s financial strength, which includes a sustainable generation of funds and a comfortable debt maturity profile. We have also analyzed the available alternatives for capital allocation, having concluded that the risk-return equation favors the investment in our own securities. Since the first buyback program started in April 2018, we have acquired a total of 453 million shares, equivalent to 18 million ADRs. Moreover, as of this date we have repurchased 22% of the initial capital stock, which originally amounted to 2,083 million common shares

(83 million ADRs). Currently, the outstanding capital amounts to 1,630 million common shares or 65 million ADRs, net of capital reductions and repurchased shares that are still held in treasury.

Finally, we would like to point out that, even after buybacks carried out during 2019, which include about 10% of the outstanding capital stock at a considerable discount of its intrinsic value and 5% of the notional value of the Company’s CBs, executed an ambitious investment plan and increased power generation and hydrocarbon production levels, the Company and its subsidiaries closed fiscal year 2019

with a strong financial position, a very extended debt profile and ongoing expansions, being CTEB’s closing to combined cycle fully pre-financed. These actions have allowed us to undergo the volatility and uncertainty of the year with the least possible impact, continue receiving support from the capital markets which recognize Pampa’s creditworthiness, even in the very tight market window available in 2019, have the capacity to develop investment plans, and leverage our position to analyze acquisition possibilities.

This would not have been possible without the effort and dedication of the Company’s employees and advisors who accompany us with commitment and involvement, for which Pampa’s Board would like

to seize this opportunity to thank them all for helping us overcome the challenges of our industry on a daily basis and consolidate the Company as a leading representative of the Argentine energy business. We would also like to thank our families, suppliers, financial institutions and investors for the continuous support and trust placed upon us.


2. Corporate Governance

At Pampa we believe that the best way of preserving and protecting our investors is to adopt and

implement the best corporate governance practices, which consolidate us as one of the most trustworthy and transparent companies in the market. For such purpose, we constantly strive to incorporate those practices by considering international market trends, as well as domestic and foreign applicable corporate governance standards and rules.

In this line, in December 2018 Pampa joined the special stock quote panel called +GC Panel, sponsored by ByMA. The +GC Panel has no precedents in Argentina, and includes companies already listed at ByMA with single-vote shares that comply with the best corporate governance and transparency practices

even beyond the regulatory required level, which Pampa entirely fulfills. These practices, which are periodically monitored for compliance, are aligned with the Corporate Governance principles of the

Organization for Economic Co-operation and Development (OECD) and adopted by the G20.

Beyond the information contained in this section, further information on Pampa’s corporate governance practices can be found in Appendix I to this Annual Report, which contains the corporate governance report required under the Code pursuant to the Section 1, Title I, Chapter I, Part IV of the CNV

Rules, in accordance with the text restated in 2013 as amended by CNV General Res. No. 797/19.

2.1 Pampa’s Corporate Structure

Board of Directors

Pursuant to the ABOL, as amended from time to time, the CMA and Pampa’s Bylaws, decision-making within the Company is vested in the Board. The Board consists of ten regular directors and an equal

or smaller number of alternate directors as determined by the Shareholders’ Meeting, a percentage of whom will be independent according to the independence standards set out in the CNV rules. All our directors are elected for a term of three years and may be re-elected indefinitely, except for the restrictions

arising from the independence standards set out in the CNV Rules. The expiration and further renewal of terms of office is made on a partial and staggered basis every year, with the election of three directors for two years, and four directors on the third year. Currently, Pampa’s Board is composed as follows:


Name Position Independence Term Expiration*

Marcos Marcelo Mindlin Chairman Non-Independent 12/31/2020

Gustavo Mariani Vice-chairman Non-Independent 12/31/2019

Ricardo Alejandro Torres Director Non-Independent 12/31/2019

Damián Miguel Mindlin Director Non-Independent 12/31/2020

Miguel Ricardo Bein Director Independent 12/31/2019

María Carolina Sigwald Director Non-Independent 12/31/2020

Gabriel Cohen Director Non-Independent 12/31/2021

Carlos Correa Urquiza Director Independent 12/31/2021

Santiago Alberdi Director Independent 12/31/2021

Darío Epstein Director Independent 12/31/2021

Horacio Jorge Tomás Turri Alternate Director Non-Independent 12/31/2019

Victoria Hitce Alternate Director Non-Independent 12/31/2019

Gerardo Carlos Paz Alternate Director Non-Independent 12/31/2020

Mauricio Penta Alternate Director Non-Independent 12/31/2020

Brian Henderson Alternate Director Non-Independent 12/31/2020

Mariano Batistella Alternate Director Non-Independent 12/31/2021

Pablo Díaz Alternate Director Non-Independent 12/31/2021

Silvana Wasersztrom Alternate Director Independent 12/31/2021

Nicolás Mindlin Alternate Director Non-Independent 12/31/2021

Note: *They will be in office until their reelection or the election of their substitutes.

Senior Management

The following table includes information on our senior management:

Name Position

Marcos Marcelo Mindlin Chairman

Gustavo Mariani Executive vice president and CEO

Ricardo Alejandro Torres Executive vice president

Damián Miguel Mindlin Executive vice president

Gabriel Cohen CFO

Horacio Jorge Tomás Turri Executive director of oil and gas

María Carolina Sigwald Executive director of legal affairs

Mariano Batistella Executive director of strategy, planning, downstream and affiliates


Supervisory Committee

Our Bylaws provide that the oversight of Pampa will be in charge of a Supervisory Committee, consisting of three regular members and three alternate members appointed by our shareholders pursuant to the legal provisions in force. The Supervisory Committee will be composed of duly registered lawyers and/or accountants admitted to practice in Argentina, who will serve for a term of three fiscal years.

The primary function of the Supervisory Committee is to exercise statutory control over the Board, complying with the provisions set forth in the ABOL, the Bylaws, regulations if any, and the Shareholders’

Meeting decisions. In the accomplishment of these duties, the Supervisory Committee does neither monitor our operations nor assess the merits of decisions made by the Board’s members.

Currently, Pampa’s Supervisory Committee is composed as follows:

Name Position Term Expiration**

Germán Wetzler Malbrán Statutory Auditor* 12/31/2020

José Daniel Abelovich Statutory Auditor 12/31/2020

Martín Fernández Dussaut Statutory Auditor 12/31/2020

Tomás Arnaude Alternate Statutory Auditor 12/31/2020

Marcelo Héctor Fuxman Alternate Statutory Auditor 12/31/2021

Damián Burgio Alternate Statutory Auditor 12/31/2021

Note: *Chairman of the Supervisory Committee (Statutory Auditors). **He will be in office until his reelection or the election of his substitute.

Audit Committee

Pursuant to Section 109 of the CMA, Pampa has an Audit Committee integrated by three regular members and one alternate member, who all hold independent status according to the independence standards set out in the CNV Rules. The Audit Committee members have professional expertise in financial, accounting, legal, and/or business matters.

Pursuant to the applicable legislation and its own Internal Regulations, the Audit Committee is responsible for compliance with the following duties, among others:

i. Supervising the operation of internal control systems and the administrative/reporting system, as well as the reliability of the latter and of all financial information or any other significant events that may be disclosed to the CNV and the markets, in compliance with the applicable reporting system;

ii. Expressing its opinion on any proposal by the Board to designate external auditors to be hired by the Company, and ensuring their independence;

iii. Reviewing the plans submitted by external and internal auditors, assessing their performance, and

issuing an opinion on the presentation and disclosure of annual FS, all of which pursuant to the CNV Rules. For the supervision of external auditor’s performance, the Committee may determine a series of objective indicators to assess their commitment, efficiency and independence;

iv. Supervising the implementation of risk management information policies within the Company;

v. Providing the market with full information on transactions where there may be a conflict of interest with members of corporate bodies or controlling shareholders;


vi. Rendering its opinion on remunerations and stock options plans’ proposals for the Company’s

directors and managers submitted by the Company’s Board;

vii. Rendering its opinion on the compliance with legal requirements and the reasonableness of the

conditions for the issuance of shares or convertible securities in capital increases with the exclusion or limitation of preemptive rights;

viii. Issuing a well-founded opinion on related-party transactions in the cases provided by law, and disclosing it in compliance with law whenever there is or may be an alleged conflict of interest

within Pampa;

ix. Supervising the operation of a channel whereby the Company’s executives and staff may report reporting, internal control and audit issues pursuant to the applicable provisions to such effect;

x. Providing any report, opinion or statement required by the current regulations in force, with the

scope and frequency required by such regulations, as amended, etc.;

xi. Fulfilling all obligations provided for in the Bylaws, as well as laws and regulations binding the

Company;

xii. Checking compliance with applicable standards of ethical conduct; and

xiii. Drawing up an annual action plan for which it will be held accountable to the Board and the Audit

Committee. The Audit Committee will submit such action plan within a term of 60 calendar days as from the beginning of the fiscal year.

Currently, Pampa’s Audit Committee is composed as follows:

Name Position

Miguel Ricardo Bein Chair

Darío Epstein Regular Member

Carlos Correa Urquiza Regular Member

Silvana Wasersztrom Alternate Member

2.2 Minority Shareholder Protection

Pampa’s Bylaws include safeguards aimed at the protection of minority shareholders, such as:

Only one class of shares granting equal economic and political rights;

Special majorities of up to 66.6% of the votes to amend certain clauses of the Bylaws; and

Possibility to call a shareholders’ meeting upon request of shareholders representing at least 5% of the capital stock.

2.3 Corporate Governance Policies

Integrity Program – Law No. 27,401

Upon the enactment and entry into force of the Legal Entities’ Criminal Liability Law, Pampa’s Board 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 proceedings, mechanisms and actions for integrity, supervision


and control, geared at preventing, detecting and correcting the irregularities and illegal acts covered by

such law.

The Program set forth by law has mandatory and optional requirements, and Pampa has defined the need to comply with all of them. It is worth highlighting that all mandatory requirements had already been implemented at Pampa before said law’s effective date.

Furthermore, the Integrity Program is periodically monitored by the Board, including the identification of potential improvement opportunities. The Board has defined that Pampa’s Internal Audit Department will be the body internally responsible for the program, including its development, coordination

and supervision.

Code of Business Conduct – Ethics Hotline

Pampa has a Code of Business Conduct in place which lays down the ethical principles that constitute the foundation of the relationships between Pampa, its employees and other stakeholders (customers, suppliers, government, shareholders, community, etc.) by providing guidelines and supplying instruments that guarantee the transparency of affairs and proper Company management.

Moreover, Pampa has a Fraudulent Practices Prevention Policy and a Procedure for handling complaints. This last document describes the process to be followed from the reception of the complaint to the conclusion of the investigation and the application of any pertinent corrective action. One of the available instruments is the Ethics Hotline, an exclusive channel to report, on a strictly confidential basis, any suspected misconduct or breach to the Code of Business Conduct. This line can be accessed through different channels (website, toll-free telephone number or e-mail) and is managed by a third-party provider to ensure higher transparency. The Audit Committee is responsible for supervising the channel’s operation

and the resolution of complaints in issues within its authority.

Policy on Best Security Market Practices

This Policy has been implemented to set certain restrictions and rules regarding the trading of marketable securities in a stock exchange, whether Pampa’s and/or any related companies, thus ensuring higher transparency and guaranteeing that no Pampa employee may be rewarded of any economic

advantage or benefit from the use of material non-public information about Pampa and/or any of its affiliates.

This Policy applies to Pampa and its subsidiaries’ employees deemed ‘covered individuals’, including, but not limited to, directors, members of the Supervisory Committee, and Senior Management lines.

Policy on Related-Party Transactions

Since 2008, the Company has had a Policy on Related-Party Transactions in place whereby,

pursuant to the CMA, all high-value transactions made between Pampa and individuals and/or legal entities which, pursuant to the applicable regulations in force are considered ‘related parties’, will be subject to a

specific prior authorization and control procedure to be carried out under the supervision of Pampa’s Legal Affairs Executive Department and which involves both Pampa’s Board and its Audit Committee (as applicable).

Money Laundering and Terrorist Financing Prevention Policy

Pampa, in its capacity as trustee under the CIESA Trust, qualifies as an ‘Obliged Subject’ pursuant to Subsection 22, Section 20 of Law No. 25,246 on Concealment and Laundering of Proceeds of Crime, as amended. Even though neither acting as a trustee in companies nor any other activity set out in Section


20 of Law No. 25,246 are among the Company’s main activities as of this date, in order to meet the

obligations resulting from its condition as ‘Obliged Subject’, this Policy was approved, which is based on and geared at possible risks for the Company resulting from its role as trustee under a single trust.

Board’s Self-Assessment Questionnaire

Since 2008, Pampa’s Board has implemented a self-assessment questionnaire that allows for annually examining and assessing its own performance and management.

The Company’s Legal Affairs Executive Department oversees examining and filing each individual

questionnaire; afterwards, based on the results, it will submit to Pampa’s Board all measures deemed useful to improve the performance of the Board’s duties.

Policy on Material Information Disclosure

Since 2009, the Company has a Relevant Information Disclosure Policy in place, approved by Pampa’s Board, which aims to regulate the basic principles guiding the operation of the processes to be followed when publishing information relevant to Pampa in accordance with the regulatory requirements

imposed by the securities markets where Pampa’s securities are traded or those in which Pampa is a registered issuer.

Prevention Regarding QSELH

This Policy, approved by Pampa’s Board in 2017, seeks to consolidate the QSELH standards into the operating processes of E&P, power generation, electricity distribution, R&D and petrochemicals with the highest safety possible within the ordinary course of each activity.

Dividend Policy

Approved by Pampa’s Board in 2018, this policy outlines the guidelines to be followed to reach a proper balance between distributed amounts and Pampa’s investment plans with the purpose of establishing a clear, transparent and consistent practice allowing shareholders informed decision-making, all of this consistent with the Company’s Bylaws and the applicable legal and regulatory framework in force.

Compensation Policy

Pampa’s Board approved the Compensation Policy in 2018, which aims to establish general rules to determine the composition, update and handling of directors’ remunerations, as well as the rules to determine the reimbursement of their expenses.

Under the Compensation Policy, the Board created the Compensation Committee, which reports to

Pampa’s Board, and is made up of three regular members and an equal or smaller number of alternate

members, who may not exercise executive functions in the Company.


Currently, Pampa’s Compensation Committee is composed as follows:

Name Position Independence Term Expiration

Miguel Ricardo Bein Chairman Independent 12/31/2019

Carlos Correa Urquiza Regular Member Independent 12/31/2021

Darío Epstein Regular Member Independent 12/31/2021

Silvana Wasersztrom Alternate Member Independent 12/31/2021

Nomination Policy

Pampa’s Board approved the Nomination Policy in 2018, which sets the general guidelines regarding independence, incompatibilities and diversity in the Board, and describes the process to be followed by both the Board and shareholders for the identification and evaluation of Board’s nominees to be presented for consideration by the Shareholders’ Meeting.

Under the Nomination Policy, the Board created the Nomination Committee, which assists Pampa’s Board and Shareholders’ Meeting in the nomination and appointment process of Board’s members. The

Nomination Committee reports to Pampa’s Board and is made up of three regular members and an equal or smaller number of alternate members, the Chairman having to be independent pursuant to the independence criteria stipulated by the CNV rules. Currently, Pampa’s Nomination Committee is composed as follows:

Name Position Independence Term Expiration

Miguel Ricardo Bein Chairman Independent 12/31/2019

Gustavo Mariani Regular Member Non-Independent 12/31/2019

Ricardo Alejandro Torres Regular Member Non-Independent 12/31/2019

Silvana Wasersztrom Alternate Member Independent 12/31/2021

Victoria Hitce Alternate Member Non-Independent 12/31/2019

María Carolina Sigwald Alternate Member Non-Independent 12/31/2020


3. Our Shareholders / Stock Performance

As of December 31, 2019, Pampa held 1,899,870,264 common shares with a par value of AR$1

each and each granting the right to one vote. However, the Extraordinary General Shareholders’ Meeting held on October 1, 2019 approved a capital stock reduction by cancelling 151,997,025 common treasury shares, acquired under the Share Buyback Programs, in process of registration before the IGJ. Therefore, excluding shares in process of cancellation and treasury shares acquired after the October 2019 Shareholders’ Meeting, as of the closing of the fiscal year Pampa Energía’s capital stock amounted to 1,682,147,789 common shares2.

The following table shows information on Pampa’s common shareholdings:

Holders As of December 31, 2019

In million % of Issued Capital Stock

% of Capital

Stock Net of Cancellations and Buybacks

Shares ADRs

Management1 381.3 15.3 20.1% 22.7%

Free Float on NYSE and ByMA 1,295.8 51.8 68.2% 77.0%

Share buyback programs 217.7 8.7 11.5% -

Pending cancellation 152.0 6.1 8.0% -

In treasury2 65.7 2.6 3.5% -

Employee stock-based compensation plan

5.0 0.2 0.3% 0.3%

Issued capital 1,899.9 76.0

100.0% 100.0% Capital stock net of cancellations and buybacks

1,682.1 67.3

Note: All figures are rounded, so the total may not equal the sum of the figures. 1 It includes direct and indirect stakes of Messrs. Marcos

Marcelo Mindlin, Damián Miguel Mindlin, Gustavo Mariani and Ricardo Alejandro Torres. 2 Shares repurchased until December 31, 2019.

As regards the remaining shares repurchased under the Programs, their cancellation will be timely submitted to its shareholders for approval.

Pampa is listed on the ByMA, takes part in the S&P Merval and the sustainability (non-traded)

indexes, and is a member of the special stock quote panel, known as +GC Panel, which selects listed companies having the best corporate governance practices.

Furthermore, Pampa has a Level II ADS program listed on the NYSE, and each ADS represents 25 common shares. Our ADR participates in the MSCI Argentina index and the Bloomberg’s gender-equality stock index GEI (non-traded), in which Pampa is the only Argentine company and one of the 13 selected companies in the energy sector.

2 For further information, see section 7.7: ‘Buyback of Own Financial Securities’ of this Annual Report.


The following chart shows the price evolution per share and Pampa’s traded volume on the ByMA from

January 2006 to December 31, 2019:

Note: * Price adjusted according to preemptive subscription rights and issuances. Source: ByMA/Bloomberg.

The following chart shows the price evolution per ADS and Pampa’s traded volume on the NYSE from October 9, 2009 to December 31, 2019:

Note: *Price adjusted as per issuances. Source: Bloomberg.

-

50

100

150

200

250

300

-

10

20

30

40

50

60

70

Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

AR$ per Share* Volume

(AR$ million)

-

30

60

90

120

150

180

210

240

270

-

10

20

30

40

50

60

70

80

Oct-09 Oct-10 Oct-11 Oct-12 Oct-13 Oct-14 Oct-15 Oct-16 Oct-17 Oct-18 Oct-19

US$ per ADS*Volume

(US$ million)


4. Macroeconomic Context

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 economy, the most affected ones being financial intermediation (-12.4%), wholesale and retail business and repairs (-9.4%) and manufacturing industry (-7.6%). These falls 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 falls were partially offset by a 77.1% year-on-year increase in exports net of imports.

As regards 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 utilities 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 AR$ based on figures published by the Federal Administration of Public Revenue (AFIP), 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.

As regards the financial situation, the BCRA’s US$ currency wholesale exchange rate (Res. A3500)

closed at AR$59.90/US$ 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 BCRA’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 AR$1,895 billion, showing a 34.5% increase at the closing of 2019

compared to the previous year. Furthermore, the BCRA’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 front, 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 recorded a 7.1% contraction.

Fuel and energy exports registered 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%).


5. The Argentine Electricity Market

5.1 Power Generation3

During 2019, the demand for electricity experienced a slight decrease, with a 3% variation compared to 2018, and a total electricity demand volume of 128,880 GWh and 133,010 GWh for 2019 and 2018, respectively.

The following chart shows the breakdown of electricity demand in 2019 by type of customer:

Electricity Demand by Type of Customer

Residential < 10 kW

44%

No Residential < 300 kW

29%

No Residential ≥ 300 kW

10%

Large Users17%

%

Source: ADEERA

Peak Power Capacity Records

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Capacity (MW) 20,843 21,564 21,949 23,794 24,034 23,949 25,380 25,628 26,320 26,113

Date 08-Mar 01-Aug 16-Feb 23-Dec 20-Jan 27-Jan 12-Feb 24-Feb 8-Feb 29-Jan

Temperature (ºC) 1.6 3.5 34.2 35.4 29.6 35.6 35.1 27.7 30.2 34.0

Hour 19:45 20:18 15:10 14:20 15:05 14:13 14:35 14:25 15:35 14:25

Source: CAMMESA.

On February 8, 2018, at 15:35, there was a 26,320 MW record-breaking demand for electricity in the SADI.

3 For further information, see sections 7.1 and 8.1 of this Annual Report.


Evolution of the Electricity Supply

In 2019 there was a 5% decrease in power generation, with 130,838 GWh and 137,199 GWh volumes for the years 2019 and 2018, respectively, mainly due to the economic downturn.

Thermal power generation remained as the main resource to meet the electricity demand, fired with natural gas or liquid fuels (GO and GO) and mineral coal, supplying an electricity volume of 80,138 GWh (61%), followed by hydroelectric power generation, which contributed 34,961 GWh net of pumping (27%), nuclear power generation, with 7,927 GWh (6%), and renewable power generation with

7,812 GWh (6%). Additionally, there were imports for 2,746 GWh (higher than the 344 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 increases were partially offset by a 23% and 133% year-on-year increase in nuclear and renewable generation, respectively, mainly as a result of the commissioning under the RenovAr and MAT ER programs, and the commissioning of Central Nuclear

Embalse’s reconditioning.

The following chart shows the evolution of power generation by source:

Generation by Type of Power Plant In % and in TWh, 2010 – 2019

59% 62% 66% 64% 64% 64% 66% 65% 64% 61%

35% 33% 29% 31% 31% 29% 26% 29% 29%27%

6% 5% 5% 4% 4% 5% 6% 4% 5%6%

1% 2% 2% 2% 2%6%

112.8 118.3 124.7 129.0 129.3 134.6 136.1 136.1 137.2 130.8

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

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

During 2019, power generation facilities recorded an increase in their installed capacity compared

to the previous year, totaling 39,704 MW (+1,166 MW compared to 2018). This increase was mainly due

to the commissioning of renewable units under the RenovAr and MAT ER programs for 1,120 MW, including PEPE II and III (106 MW). In the thermal area, 503 MW were commissioned, mainly under MEyM Res. No. 287/17, including the first phase of Genelba Plus’ expansion project (207 MW).


The following table describes the incorporation of new power units in 2019:

Region Technology Capacity (MW)

Buenos Aires Metro Area - Northwest Litoral

Biogas 14

604.8 Wind 251.2

GT 339.6

Center

Biogas 2.4

105.9

Wind 38

GT 49.5

ST 1.6

Solar 14.4

Midwest - Comahue Wind 152.7 152.7

Cuyo CC 95.3

196.4 Solar 101.1

Northeast Diesel 16.8 16.8

Northwest Biogas and Biomass 5

130 Solar 125

South - Patagonia Wind 416.4 416.4

Total 1,623

Thermal 30.9%

Renewable 69.1%

Source: CAMMESA and Pampa Energía’s own analysis.

Additionally, hydroelectric power units’ capacities were adjusted based on their reservoirs for +22 MW and thermal units for -66 MW, PPAs were terminated for 421 MW, of which 147 MW are mobile generation, 200 MW for ST and the rest for GT, added to the 8 MW expansion in solar generation in the northwestern region. The following chart shows the composition of the Argentine installed power capacity

as of December 31, 2019:

2019 Argentine Installed Power Capacity 100% = 39.7 GW

Thermal61.8%

Renewable6.5%

Nuclear4.4%

Hydroelectric27.2%

%

Source: CAMMESA.


Fuel Supply and Consumption4

Regarding fuel supply for power generation, during 2019 SGE Res. No. 70/18 issued in November 2018 remained in force, which empowered thermal plants to self procure 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 power plants to be traded within the WEM, established by MinEn Res. No. 46/18 and SGE Notes No. 66680075/18 and 07973690/19, were observed.

Moreover, 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 is reduced to 50% of its actual availability. Similarly, it loses its dispatch order, and in case the OED assigns it fuel for generation, only the Generated Energy will be remunerated at 50% of the approved non-fuel variable costs.

However, pursuant to MDP Res. No. 12/19, fuel supply was again centralized in CAMMESA as from December 30, 2019 (except for fuel supply for generators under Energía Plus).

As regards fuel consumption, in 2019 the country continued purchasing LNG and its re-gasification,

as well as natural gas from the Republic of Bolivia. However, the natural gas supply remained insufficient to meet power generation needs and, therefore, liquid fuels (FO and GO) continued to be resorted to in order to meet the demand, although in volumes significantly lower than in 2018.

Natural gas consumption for power generation recorded a 5% decrease in 2019 compared to the previous year (17.2 million dam3). FO consumption was 67% lower than in 2018, totaling 0.2 million ton. Moreover, GO and mineral coal consumption also experienced a 54% and 66% decrease, respectively, compared to 2018.

Price of Electricity

The energy authority has continued with the policy launched in the year 2003 whereby the WEM spot price is determined according to the available power generating units’ CVP with natural gas, even if these units are not generating electricity with such fuel (SE Res. No. 240/03). The additional cost for the consumption of liquid fuels is recognized outside the specified market price as a temporary dispatch

surcharge. Furthermore, pursuant to SGE Res. No. 25/18, the WEM bears the costs of imported gas as from October 1, 2018.

As regards 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 is in effect.

Evolution of WEM Prices

Until October 2019, the approved average monthly spot price for energy was AR$480/MWh, which is the maximum price stipulated pursuant to SEE Provision No. 97/18. As from November 2019, this price increased to AR$720/MWh pursuant to SEE Provision No. 38/19.

On the other hand, the following chart shows the average monthly price that all electricity system users should pay so that the power grid would not run into a deficit. This cost includes not only the energy price, but also the power capacity fee, the generation cost, fuels such as natural gas, FO or GO, and other minor items.

4 For further information, see sections 6.1 and 7.4: ‘Natural Gas for Electric Power Generation’ of this Annual Report.


Average Monthly Monomic Price In US$ / MWh

61

67

66

68

64

74

78

74

72

65

6261

2018

Average76

2019

Average68

Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19

Source: CAMMESA.

Remuneration Scheme for Generation Not Covered by Contracts

SEE Res. No. 19/17: February 2017 - February 2019

SEE Res. 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.

Res. No. 19/17 provided for remunerative items based on technology and scale, establishing US$-denominated prices payable in AR$ by applying BCRA’s FX effective on the last business day of the month of the transaction’s maturity date, according to CAMMESA’s Procedures.

Thermal Power Generators

Res. No. 19/17 defined a remuneration for power capacity based on technology and scale collectable by agents with DIGO declaration for the power capacity and energy from their units not covered by PPAs with a differentiated remuneration regime. The DIGO should be declared for each unit and for a term of three years, together with information for the Summer Seasonal Programming, with the possibility

to later amend availability values, on a semiannual basis. Generators may enter into a DIGO agreement with CAMMESA, which may assign it to the demand. The capacity remuneration for thermal generators with DIGO will be proportional to their compliance. The base remuneration amounted to US$7,000/MW-month,

applicable to generators with DIGO. The additional remuneration for additional available power capacity amounted to US$2,000/MW-month, seeking to encourage DIGO for the periods with a higher demand. Bimonthly, CAMMESA should define a Monthly Thermal Generation Goal for the set of qualified generators and call for additional power capacity availability offers with prices not exceeding the additional price.

For those not offering DIGO, the power capacity remuneration was set at the minimum value.


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, Internal Combustion Engines 5,700

Large GT Capacity > 50 MW 3,550

Regardless of the thermal unit, the remuneration for generated energy was US$5/MWh if fired with natural gas, and US$8/MWh if fired with liquid fuels, except for internal combustion engines, which prices

amounted to US$7/MWh and US$10/MWh for gas or liquid fuels consumptions, respectively. The remuneration for operated energy was applied to the integration of hourly power capacities for the period

(over rotating units) at a price of US$2/MWh for any type of fuel.

Moreover, for low-use thermal generators or generators having frequent startups, an additional remuneration was established based on the monthly generated energy at a price of US$2.6/MWh multiplied by the usage/startup factor. The usage factor was set based on the rated power’s Utilization Factor recorded during the last rolling year, with a 0.5 value for thermal units with a factor lower than 30% and a 1.0 value

for units with a factor lower than 15%. In all other cases, the factor equals 0. The startup factor, which was set based on startups recorded during the last rolling year for issues associated with the economic dispatch made by CAMMESA, was as follows: i) 0 for units with 74 or fewer startups; ii) 0.1 for units recording between 75 and 149 startups; and iii) 0.2 for units recording more than 150 startups.

Hydro Power Generators

In the case of CHs, a base remuneration for capacity (determined by the actual power capacity plus that under programmed and/or agreed maintenance) and an additional remuneration for capacity (applicable to power plants of any scale for their actual availability, based on the applicable period) were

established. 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 taken into consideration 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. In the case of CHs maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters.

Classification Base Price

(US$ / MW-month)

Medium HI Capacity > 120 ≤ 300 MW 3,000

Small HI Capacity > 50 ≤ 120 MW 4,500

Medium Pumped HI Capacity > 120 ≤ 300 MW 2,000

Renewable HI Capacity ≤ 50 MW 8,000

Type of Power Plant Additional Price

(US$ / MW-month)

Conventional 1,000

Pumped 500


The allocation and collection of 50% of the additional remuneration was conditional upon the

generator taking out insurance on critical equipment, as well as updating of the plant’s control systems pursuant to an investment plan to be submitted based on criteria to be defined by the SGE.

For hydroelectric generation, independently of the scale, the prices for generated energy amounted to US$3.5/MWh, added to the price for operated energy, which amounted to US$1.4/MWh.

Other Considerations

The remuneration for wind power was composed by a base price of US$7.5/MWh and an additional

price of US$17.5/MWh, which were 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.

Furthermore, SEE Res. No. 19/17 abrogated the Overhauls Remuneration set by SE Res. No. 95/13 and provided that, as regards the repayment of loans, already accrued and/or committed credits should be applied first, being the balance repaid discounting US$1/MWh from the generated energy until the total cancellation of the financing.

SRRYME Res. No. 1/19: March 2019 - February 2020

On March 1, 2019, SRRYME Res. No. 1/19 was published, which modified certain aspects of the remuneration scheme previously defined by SEE Res. No. 19/17.


For generators without a DIGO declaration, the following table of base prices for power capacity was applied:

Technology / Scale Capacity’s Base 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 Engines 5,200

Large GT Capacity > 50 MW 3,550

Small GT Capacity ≤ 50 MW 4,600

Furthermore, a DIGO offer scheme was established for quarterly periods: a) summer (December through February); b) winter (June through August), and c) ‘other’, which comprises two quarters (March through May, and September through November). For agents with a DIGO declaration, the guaranteed

capacity price was applied, which equaled US$7,000/MW-month in the summer and winter quarters, but US$5,500/MW-month in the ‘other’ quarters.

Additionally, the capacity remuneration ―whether or not the agent had a DIGO declaration― was weighted by a load factor equivalent to the average dispatch factor for the generating unit during the rolling year prior to the calculation month, and applied a coefficient to the power capacity remuneration if the load factor was: i) higher than 70%, 100% of the power capacity remuneration was paid; ii) lower than 30%, 70% of the power capacity remuneration was paid; and iii) between 30% and 70%, the power capacity remuneration was linearly associated with between 70% and 100% of the power capacity remuneration.


Generated energy remuneration values were reduced by US$1/MWh for all technologies except for

internal combustion engines, where the reduction was of US$3/MWh. The remuneration value for operated energy was reduced from US$2/MWh to US$1.4/MWh.

Finally, the additional remuneration schemes were abrogated: capacity remuneration to encourage DIGO during peak demand period, variable remuneration for efficiency, and power capacity remuneration for low-use thermal generators.


SRRYME Res. No. 1/19 maintained the base prices for power capacity established by SEE Res. No. 19/17, as well as remuneration values for generated and operated energy. However, as regards the power capacity payment, the hours during which a hydroelectric generator was not available due to programmed

and agreed maintenance were no longer computed for the calculation of the power capacity remuneration. However, in order to mitigate this impact, in May 2019 SME Note No. 46631495 provided for the application of a 1.05 factor on the capacity payment.

Implementation Criteria

Power Plant Generating

Unit Technology Size Capacity

CPB BBLATV29 ST Large >100 MW

BBLATV30 ST Large >100 MW

CTG

GUEMTV11 ST Small ≤100 MW

GUEMTV12 ST Small ≤100 MW

GUEMTV13 ST Large >100 MW

CTGEBA

GEBATG01 CC Large >150MW

GEBATG02 CC Large >150MW

GEBATG041 GT Large >50 MW

GEBATV01 CC Large >150MW

CTLL

LDLATG01 GT Large >50 MW





Power Plant Generating

Unit Technology Size Capacity

HIDISA

ADTOHI HI Medium between 120 MW and 300 MW

LREYHB Pumped HI Medium between 120 MW and 300 MW

ETIGHI Renewable HI - ≤ 50 MW

HINISA

NIH1HI HI Small between 50 MW and 120 MW

NIH2HI HI Small between 50 MW and 120 MW

NIH3HI3 HI Small between 50 MW and 120 MW

HPPL

PPLEHI01 HI Medium between 120 MW and 300 MW



Note: 1 Applicable until the commercial commissioning of Genelba Plus’ CC. 2 Only 26 MW of the unit apply. 3 A 1.20 coefficient applies

on remuneration.

In the case of CTG’s GUEMTG01 and CTGEBA’s GEBATG03 units, pursuant to Section 6 of SE Res. No. 482/15 and with the agreement of ‘Energía Plus’ power generators, both the energy delivered to the spot market and the available power capacity not committed under the Energía Plus contracts in force during each period are remunerated based on the items set out for legacy capacity, the cost of the fuel provided by CAMMESA being excluded from the transaction.


For generation from unconventional sources, a single remuneration value for generated energy was established at US$28/MWh, or 50% of this value if it is generated prior to commercial commissioning.

As regards the refund of the amount disbursed to generators under the loan agreements for the execution of overhauls in their units, the application of all receivables accrued in favor of generators for settlement was established, as well as a discount scheme in the generator’s revenues equivalent to the maximum between US$1/generated MWh or US$700/MW-month for the unit’s real availability.

SE Res. No. 31/20: Current Spot Remuneration Scheme

On February 27, 2020, SE Res. No. 31/20 was published in the BO, which modified certain aspects of the remuneration scheme set forth by SRRYME Res. No. 1/19, effective as from February 1, 2020. The new Res. converts the entire remuneration scheme to the local currency at a FX of AR$60/US$ and establishes an update factor as from the second month of its application, which follows a formula consisting of 60% CPI and 40% PPI.


SE Res. No. 31/20 reduces the power capacity remuneration, whether base or guaranteed, depending on the technology used. However, for CTs 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

Base Price

(AR$/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: * It assumes a FX of AR$60/US$.

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

Period

Capacity Base

Price

(AR$/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 -


As SRRYME Res. No. 1/19, SE Res. No. 31/20 provides for the application of a coefficient arisen 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%, 60% of the power capacity payment is collected.

Regarding the additional remuneration in the hours of high thermal dispatch (HMRT), which consist of the 50 recorded hours with the highest thermal generation dispatch each month, grouped in two blocks of 25 hours each, the following will be applied to the average generated capacity during such hours:

Period, in AR$/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 -

As regards the remuneration for generated and operated energy, they remained unchanged in

US$ at a FX of AR$60/US$, but set at AR$240/MWh with natural gas, AR$420/MWh with fuel oil, AR$600 with biofuels (except for internal combustion engines, AR$720/MWh) and AR$720/MWh with mineral coal. The remuneration for operated energy was set at AR$84/MWh.



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

Scale

Capacity

Base Price

(AR$/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%


As regards the HMRT additional remuneration, the following will be applied to the average operated power capacity during such hours:

Scale Capacity HMRT Price

AR$/MW-HMRT

Large HI Capacity > 300 MW 27,500

Medium HI Capacity > 120 ≤ 300 MW 32,500

Small HI Capacity >50 ≤ 120 MW 32,500

Renewable HI Capacity ≤ 50 MW 32,500

Large Pumped HI Capacity > 300 MW 27,500

Medium Pumped HI Capacity > 120 ≤ 300 32,500

Weighted by the following coefficients:

HMRT December - February,

June - August Other

First 25 HMRT hours 1.2 0.2

Second 25 HMRT hours 0.6 -

The prices for generated and operated energy remained unchanged in US$ at a FX of AR$60/US$,

though set at AR$210/MWh and AR$84/MWh, respectively. The remuneration for operated energy should correspond with the grid’s optimal dispatch. The provision does not indicate, as it does for thermal generators, which would be the consequence otherwise.



For energy generated from any unconventional source, SE Res. No. 31/20 provides for a single remuneration value of AR$1,680/MWh, which equals the previous remuneration converted at a FX of AR$60/US$, 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 the settlement against the repayment of loans for the execution of overhauls, and sets a discount scheme in the generator’s revenues equivalent to the maximum between AR$60/MWh, or

AR$42,000/MW-month for the unit’s actual availability. It is worth highlighting that all overhauls financing owed by Pampa were settled under the Agreement for the Regularization and Settlement of Receivables with the WEM.

Non-Spot Remuneration for Conventional Energy

Energía Plus

In September 2006, the SE approved Res. No. 1281/06, which establishes certain restrictions on the sale of electricity and implements the Energía Plus service aiming to encourage the development of new power generation supply. These measures imply that:

i. Qualify the power generators, co-generators and self-generators which, as of the date of the publication of SE Res. No. 1281/06, are neither WEM agents nor have facilities or interconnection with the WEM;

ii. Applicable power plants should procure fuel and transportation;

iii. The energy used by LU300 in excess of the Base Demand (the electrical consumption for the year 2005) qualifies to contract Energía Plus within the MAT at a price negotiated between the parties; and

iv. For new LU300 entering the grid, their Base Demand equals zero.

Within this framework, CTG, EcoEnergía and CTGEBA provide the Energía Plus service to different WEM clients, which represents 292 MW gross capacity. It is worth highlighting that, effective as from May 2019, CTG transferred its contracts to CTGEBA, selling its electricity in the spot market.

If a power plant cannot meet its Energía Plus demand, it should purchase that power in the spot market at the operated marginal cost. On the other hand, SE Note No. 567/07, as amended, provided that LU300 not purchasing their Surplus Demand within the MAT should pay the Surplus Demand Incremental Average Charge (CMIEE or Cargo Medio Incremental de la Demanda Excedente), and the difference between the real cost and the CMIEE would be accumulated in an individual account on a monthly basis for each LU300 within CAMMESA’s scope. As from June 2018, pursuant to SE Note No. 28663845/18, the

CMIEE became the greater of AR$1,200/MWh or the temporary dispatch surcharge. Additionally, it was provided that, until further instruction, movements in the individual account of each LU300 would temporarily not be recorded.

Energía Plus contract values are mostly denominated in US$; therefore, when expressed in AR$,

they are exposed to FX. Due to the decrease in surplus demand resulting from the economic recession, some LU300 decide not to enter into Energía Plus contracts, and generators must sell their energy at the spot market with lower profitability margins. Additionally, because of the surplus energy from LU300,

Energía Plus contracts were affected by the growth in MAT ER renewable energy contracts.


PPAs under SE Res. No. 220/07

By modifying the market conditions, aiming to 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 PPAs denominated in US$, and the price payable by CAMMESA should compensate the investment made by the plant at a rate of return to be accepted by the SE. CTLL, CTP and CTEB have entered into PPAs with CAMMESA under this Res., which account for a gross power capacity of

856 MW5. Moreover, CTEB has an ongoing expansion project to add 280 MW.

Agreement to Increase Thermal Generation Availability

In 2014, the Federal Government submitted a proposal to generators for the execution of a new

agreement for the increase in 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 scheduled for commissioning in 2020.

In 2015, CTLL, CTG, CPB, HINISA and HIDISA entered into a new agreement with the Federal Government whereby CTLL would incorporate a new high-efficiency GT (105 MW), as well as investments in renewable energies. However, this agreement was canceled with the implementation of SEE Res. No. 19/17. Later, Pampa’s involved generators and CAMMESA executed an Agreement for the Regularization and Settlement of Receivables with the WEM, and the LVFVD's balance was collected in August 2019, with

the waiver of all LVFVD-related claims.

PPAs under SEE Res. No. 21/16

As a result of the state of emergency in the national electricity sector declared pursuant to 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. Successful bidders entered a PPA

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.

Pampa was awarded the installation of GT05 at 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, Pampa acquired and developed CTPP for a 100 MW capacity, which was commissioned for service in August 2017.

PPAs under SEE Res. No. 287/17

On May 10, 2017 the SEE issued Res. 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 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

5 It includes CTLL’s GT04 power capacity, which is partially committed under this contract.


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 the closing to CC in the Plus unit at CTGEBA for 383 MW. 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.

Based on the moderate demand growth, the entrance of renewable generation and widespread work delays, through SRRYME Res. No. 25/19 it was required the ratification of the commercial commissioning dates for the awarded projects. Moreover, it provided the option to extend this date for up to 180 days and established a penalty scheme for the corresponding delays. Pampa ratified Genelba Plus

CC's commercial commissioning date.

Non-Spot Remuneration for Renewable Energy

In October 2015, Law No. 27,191 (regulated by Executive Order No. 531/16) was passed, which amends Law No. 26,190 on the promotion of renewable sources of energy. Among other measures, it provided that by December 31, 2025, 20% of the total demand for energy in Argentina should be covered with renewable sources of energy6. 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 this objective is met. The agreements entered with GU and GUDI may not have an average price exceeding US$113/MWh.

Additionally, several incentives are established to encourage renewable energy projects, including tax benefits (advance VAT return, accelerated depreciation on the income tax return, import duty exemptions, etc.) and the creation of the FODER, which is destined, among other objectives, to the granting of loans, capital contributions, etc. for the financing of these projects.

RenovAr Program

In 2016, the RenovAr Rounds 1 and 1.5 Programs were launched pursuant to MEyM Res. No. 71/16 and 252/16, respectively. In Round 1, 29 projects were awarded 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 in June 2018. In Round 1.5, 30 projects were awarded for a total 1,281.5 MW (100% of which were wind and solar energy projects). In 2017, the RenovAr Round 2 Program was launched pursuant to MEyM Res. No. 275/17, under which 88 projects were awarded for a total 2,043 MW (89% of which were wind and solar energy projects). Finally, in 2018, the RenovAr MiniRen Round 3 Program was

launched for smaller-scale renewable projects (between 0.5 and 10 MW), and projects were awarded for a total 246 MW.

It is worth highlighting that for all projects under the RenovAr rounds, it was established that all greenhouse gas reductions resulting from the power capacity installed throughout the national territory —including those resulting from any other project accounted for to meet the WEM’s renewable capacity goals

set by Law No. 27,191— should be accounted for by the Federal Government for the meeting of its contribution goal under the United Nations Framework Convention on Climate Change and the Paris

Agreement.

6 As from December 2016, CHs with a power capacity lower than 50 MW are classified as renewable sources of energy.


MAT ER

MEyM Res. No. 281/17 issued on August 18, 2017 regulated the MAT ER regime, which sets the conditions for WEM’s 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, it regulates the conditions applicable to renewable power generation projects. Specifically, it created the RENPER, where such projects should be registered.

Projects destined to supply the MAT ER should not be committed under other remuneration

mechanisms (e.g., the RenovAr Program). Surplus power generation exceeding commitments with MAT ER are remunerated up to 10% of the power generation at the minimum price for the applicable technology under the RenovAr Program, and the balance is sold in the spot market.

Furthermore, agreements executed under the MAT ER regime should be administered and managed

in accordance with the WEM Procedures. The contractual terms —life, allocation priorities, prices and others, except for the maximum price set forth by Law No. 27,191— may be freely agreed between the parties, although the committed volumes should be limited by the renewable energy produced by the generator or

supplied by other generators or suppliers with which it has MAT ER agreements in place.

Pampa registered the PEPE II and III projects with the RENPER. It also requested the corresponding dispatch priority under MEyM Res. No. 281/17, which was granted for the total capacity of both projects. On May 10, 2019, CAMMESA granted the commissioning of PEPE II and III’. The generated energy is sold under PPAs with private parties for an average term of approximately 5 years.

Renewable Energy Distributed Generation

On December 27, 2017, Law No. 27,424 was published, which declares the distributed generation of electric power from renewable sources destined to self-consumption and the possible injection of surpluses into the distribution network to be of national interest. The Law also establishes the distribution utility providers’ obligation to facilitate such injection by guaranteeing free access to the distribution

network, notwithstanding the provinces’ own powers.

PEN Executive Order No. 986/18 issued in November 2018 and SGE Res. No. 314/18 in 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.

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


5.2 Transmission7

Evolution of the High-Voltage Transmission System

The following chart shows the evolution of the transformation capacity’s cumulative growth and the number of kilometers of high-voltage transmission system lines, compared to the percentage cumulative growth of peak demand since 1992.

Evolution of the Transmission System Cumulative Growth (in %)

15%

25%

34%

90%

110%

126%132% 141%

151%

16%

34%34%

91%101%

0%

24%

52%

79%

121%134%

142% 144%148%

147%

1992 … 1996 … 2000 … 2005 … 2011 … 2015 2016 2017 2018 2019

Transformers capacity Km of lines Maximum generated capacity

Source: Transener and CAMMESA.

As illustrated in the graphic above, the High-Voltage Transmission System has grown significantly since 2005, mainly due to the implementation of the 500 kV Transmission Federal Plan. The implementation of this Federal Plan has provided the SADI with more stability and better conditions to meet the rising

demand.

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 supplying electricity services. This situation has significantly

affected Transener and Transba’s economic and financial situation.

In May 2005, Transener and Transba signed with the UNIREN the Memorandums of Understanding stipulating the terms and conditions for updating the Concession Agreements. The guidelines of these Memorandums 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 demand 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 to 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, which were executed through loan agreements.

Upon collecting these receivables and still without the RTI, in May 2013 Transener and Transba,

respectively, executed with the SE and the ENRE a Renewal Agreement, effective until December 31, 2015, which, among other provisions, acknowledged a credit claim for cost variations recorded during the December 2010 – December 2012 period. In view of the repeated delays in the implementation of the RTI provided for in the Memorandum of Understanding, the SE and the ENRE successively extended the

recognition of higher costs up to and including November 2015. In May 2016, upon the expiration of the Renewal Agreement and without any pending recognized receivables, Transener and Transba continued collecting the loans granted by CAMMESA, which were disclosed as liabilities. Finally, on December 26, 2016, Transener executed the last agreement with the SE and the ENRE, which recognized credits for cost variations in favor of Transener and Transba for the December 2015 - January 2017 period. On June 19, 2017, CAMMESA made the last disbursement, thus offsetting all credits for cost variations.

RTI

ENRE Res. No. 66/17 and No. 73/17 in February 2017, as amended, established the tariffs effective 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 AR$8,629 million and AR$3,575 million recognized capital base and AR$3,534 million and AR$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 IPIM, ‘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 IPIM 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, but deferred until December 15, 2017, when ENRE issued Res. No. 627/17 and No. 628/17 updating Transener and Transba’s

remunerations 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 of February 19, 2018, 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, retroactively to August 1, 2019.

The Solidarity 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 did not received instructions from the ENRE on the semiannual remuneration update which, according to the RTI, should have been 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 and 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.

5.3 Distribution8

Memorandum of Understanding with the Federal Government

In February 2006, Edenor entered into a Contract Renegotiation Memorandum of Understanding with the UNIREN, which established, effective as from November 2005, a 23% increase in the average VAD, as well as a 5% additional VAD increase to be allocated to certain specific investments in capital goods.

Furthermore, it provides 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 resulting 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. It was stipulated in the 2007 Contractual Renegotiation Agreement, which was not duly passed on to tariffs. This measure was implemented by SE Res. No. 250/13 and its subsequent extensions, which allowed for the offsetting of this



recognition with Edenor’s liabilities 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, except for 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.

Loan Agreements – Extraordinary Investments Plan

Due to the delay in obtaining the RTI, the Federal Government granted to Edenor loans for the

conduction of the investments plan it may deem appropriate. Pursuant to MEyM Res. No. 7/16, CAMMESA suspended, as from February 2016 and until receiving further instructions, all effects from the executed loan agreements and the transfer of resources to distribution companies on behalf of the FOCEDE trust and, therefore, the new works plan would be financed exclusively with tariff proceeds. The amounts owed by Edenor under loan agreements and works were offset by the Federal Government in the Liabilities Regularization Agreement executed on May 10, 2019.

SE Res. No. 32/15

SE Res. No. 32/15, passed in March 2015, implemented a transitory increase in Edenor’s income

as from February 2015 to be charged against the RTI. Moreover, pursuant to this provision, the amounts collected under the PUREE program were deemed as part of Edenor’s income. This Res. did not generate tariff increases for customers but was directly transferred by the Federal Government.

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 of 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 for Edenor effective as from February 2016. In September 2016, Edenor filed its tariff proposal for the RTI, clarifying 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, the remaining increase being completed 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, which tariff schemes were fixed pursuant to ENRE Res. No. 603/17 for the December 2017 - January 2018 two-month period, also contemplating the 18% VAD


increase and the 11.6% CPD update, adjusted retroactively as of the dates they should have been

implemented.

Furthermore, ENRE Res. No. 33/18 published a new tariff scheme, effective as from February 2018, applying the last 17.8% VAD increase, the 22.5% CPD update, and considered the total deferred amount of AR$6,343 million recoverable in 48 installments, subject to an annual review each February for the years 2019 through 2021. These Res. included electricity prices and discount schemes for users benefiting from the social tariff and evidencing consumption savings, as provided for in SEE Res. No. 1091/17 for the December 2017 – January 2018 and February – April 2018 periods, which were later extended until October

2018 pursuant to SEE Provision No. 44/18.

It is worth highlighting that the 22.5% CPD update contemplated a -2.51% E-factor adjustment stimulating efficiency resulting from the RTI as an element geared at passing on to the distributor’s users the expected efficiency gains as from i) factor X, which captures gains resulting from management

optimization and the existence of economies of scale, which reduces the CPD; and ii) investments factor Q, which captures the impact of the cost of capital and the evolution of exploitation costs resulting from investments made by the company, which increases the CPD.

As regards the CPD update scheduled for August 2018, Edenor agreed with the MinEn on a 50% deferral. Moreover, the MinEn agreed to implement the actions necessary to regularize the Memorandum of Understanding entered into in 2007 and the Framework Agreement. ENRE Res. No. 208/18 provided for a 15.85% update in the CPD, 7.925% of which was applicable as from August 2018, and the balance in six monthly consecutive installments effective as from February 2019.

Furthermore, SEE Provisions No. 75/18 and 97/18 established for the August 2018 – January 2019

period the power capacity reference price at AR$10,000/MW-month, the stabilized price for transmission in the extra high voltage system at AR$64/MWh, and a price for main distribution based on the distribution company which, in the case of Edenor, amounted to AR$0/MWh. Energy reference prices were set at AR$2,283/MWh for GUDI and at AR$1,470/MWh for the remaining users. As regards the social tariff, the criteria set by SEE Res. No. 1091/17 for subsidies to users and discounts for savings remained in effect.

Effective as from February 2019, SGE Res. No. 366/18 abrogated SEE Res. No. 1091/17 and, consequently, the Federal Government’s social tariff and the savings discount scheme, and also set a power

capacity reference price of AR$80,000/MW-month, with 25% and 20% increases in the months of 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 AR$2,762/MWh for GUDI for the February – October 2019 period, and at AR$1,852/MWh for the remaining users as from February 2019, with 5% increases in the months of May and August, effective until October 2019.

ENRE Res. No. 25/19 approved the tariff scheme effective as from February 2019, which reflected

the new seasonal prices described in SGE Res. No. 366/18, and ENRE Res. No. 27/19 of March 2019 established the 24%9 CPD update corresponding to the July 2018 – January 2019 semester, retroactive to February 2019, and a 7.925% increase which was timely deferred in August 2018, retroactive to that date. Compensatory amounts for the retroactivity were collected in five installments.

In April 2019, SGE Res. No. 366/18 was partially amended by SRRYME Res. No. 14/19: increases planned for May and August 2019 for the power capacity reference price and increases contemplated for

residential users were suspended, 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. Moreover, 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 hereof these increases in seasonal prices for non-residential users have not been passed on to new tariff schemes.

9 Including the -1.59% E Factor stimulating efficiency.


On September 19, 2019 Edenor agreed with the Federal Government to postpone the 19.05% CPD

update for August 1, 2019 until January 1, 2020. Moreover, the continuity of retroactive amounts applied in the March - July 2019 period for the timely deferred CPD was allowed, the balance being recoverable in 7 monthly consecutive installments as from January 2020. Besides, the payment of penalties by Edenor was postponed until March 1, 2020 in 6 monthly installments. However, with the entry into effect of the Solidarity Law, on December 27 the ENRE instructed Edenor to maintain the current tariff schemes until June 2020, suspending all planned 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 Edenor’s concession jurisdiction. The Province

of Buenos Aires and the City of Buenos Aires immediately bore the social tariff outlays, a bipartite regulatory body would be created, and the Federal Government undertook to terminate pending issues such as the breach of the 2006 Memorandum of Understanding, among others. Until the effective date of such transfer,

the national regulatory framework would apply.

Moreover, on May 10, 2019, Edenor and the Federal Government agreed to end to the reciprocal claims regarding the 2006 – 2016 Tariff Transition Period. Edenor waived all rights and proceedings against the Federal Government, including the lawsuit brought by Edenor in 2013 upon the breach of the 2006 Memorandum of Understanding, undertook to execute investments additional to the RTI in the following 5 years, and to pay certain penalties to users and generated income tax, entailing a disbursement for a total approximate amount of AR$7,600 million over a term of 5 years. For its part, the Federal Government

offset the obligations arising during such period, such as Edenor’s commercial debts for energy purchases, investment loans granted by CAMMESA and penalties owed to the National Treasury, without this implying any fund inflow for Edenor.

However, with the entry into effect of the Solidarity Law, as from December 23, 2019, the ENRE was appointed as Edenor’s regulatory body until December 31, 2020. Moreover, Edenor is currently

unaware of the guidelines to follow regarding consumptions of shantytowns with community meters for

non-recognized and future periods.


Edenor’s Residential Tariff Positioning Consumption: 275 kWh per month; monthly bill in US$ including taxes

918

34

54 54 5665

75

Chile Brazil France Peru UK Spain

Edenor Other Countries

Social

tariff

19% of

clients

March 2019

Normal

tariff

Note: For the social tariff, it is considered without savings and without cap. Reference FX: AR$59.89/US$. Source:

Edenor

Edenor’s Industrial Tariff Positioning Consumption: 1,095 MWh per month; cents of US$ per kWh including taxes except for VAT

6.7 6.9

11.5 12.1 12.8 12.9 13.4

17.0

Mar 19 May 19 France Peru Brazil Spail Chile UK

Edenor Other Countries

Note: Clients with a peak demand of 2.5 MW in medium-voltage networks. Reference FX: AR$59.89/US$. Source: Edenor


6. The Argentine Oil and Gas Market

6.1 Hydrocarbon Exploration and Exploitation

The Argentine Energy Matrix

Natural gas and oil constitute the main energy sources in the national primary energy matrix. The following chart illustrates their shares as of December 31, 2018, as there is no available information for the year 2019:

2018 Argentine Energy Matrix 100% = 75.5 million TOE

Hydro4.6%

Coal1.6%

Oil31.0%

Natural Gas53.2%

Renewable0.3%

Nuclear2.5%

%

Note: The chart does not include other primary sources for 6.7%.

Source: SGE.

Natural Gas

In 2019, the total gross natural gas production amounted to 135 million m3 per day, which

represents a 5% increase compared to the volumes produced in 2018. This variation is mainly due to the continuous growth of production in the Neuquina Basin (+6 million m3 per day) and, to a lesser extent, in the Austral Basin (+1 million m3 per day), associated with the development of unconventional gas reserves, which was partially offset by the declines in the Golfo San Jorge and Noroeste basins.

However, the domestic supply was not able to meet the demand, a dominant trend since 2003, and, therefore, the Federal Government resorted to natural gas imports, the supply from Bolivia reaching

an average of 14 million m3 per day in 2019, a figure 15% lower than the volume recorded in 2018. In this

same sense, imports of seaborne LNG later injected in 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. Moreover, 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 Plan Gas incentive to certain blocks.

Based on the last annual information published by the SGE, as of December 31, 2018 total natural gas reserves and resources within the country reached 1,130,799 million m3, of which 33% were proven reserves. Furthermore, 57% of the total reserves and resources were unconventional. In a year-on-year


comparison, total reserves and resources have recorded a 7% increase, especially resources, which have

increased by 11%, totaling 399,584 million m3.

Evolution of Natural Gas Production, and Reserves and Resources* In billion m3, 2006-2019

1,073971 987 951

878823 808 820 848

921855

1,0521,131

52.3 51.1 50.648.4

47.145.5

44.141.7 41.5

42.945.0

44.7

47.049.4

0

10

20

30

40

50

60

0

200

400

600

800

1,000

1,200

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserves and Resources Production

Note: * There is no available information on reserves for the year 2019. Production is gross. Source: SGE.

Oil

In 2019, total oil production amounted to 81 thousand m3 per day, a volume 4% higher than volumes produced in 2018 (78 thousand m3 per day), thus reversing, since 2018, the downward trend in oil production recorded in Argentina over the last sixteen years.

Based on the last annual information published by the SGE, in 2019 no oil imports were recorded,

whereas in 2018 imports reached 1.2 thousand m3 per day. On the other hand, in 2019 oil exports amounted to 10.4 thousand m3 per day, a volume 6% higher than in 2018. This volume represented 13% of the total domestic production during 2019. The increase in domestic production and the positive oil trade balance are mainly due to the higher unconventional production, encouraged by an increase in international prices.

As of December 31, 2018, total oil reserves and resources within the country totaled 799,402 thousand m3, of which 48% were proven reserves. Furthermore, 27% of the total reserves and resources

were unconventional. In a year-on-year comparison, total reserves and resources have recorded a 16% increase. Furthermore, resources totaled 169,501 thousand m3, similar to the levels recorded as of December 31, 2017.


Evolution of Oil Production, and Reserves and Resources* In million m3, 2006-2019

808755

829742 739 701 674

741 753 749 707 687799

38.3 37.3 36.6 36.1 35.433.2 33.2

31.3 30.9 30.929.7

27.8 28.429.5

0

5

10

15

20

25

30

35

40

0

100

200

300

400

500

600

700

800

900

1,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Reserves and Resources Production

Note: * There is no available information on reserves for the year 2019. Source: SGE.

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 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 a legal status to the concept of ‘Hydrocarbon Unconventional Exploitation

Concession’ created by Executive Order No. 929/13. The term hydrocarbon unconventional exploitation is defined as the extraction of liquid and/or gaseous hydrocarbons by unconventional stimulation techniques applied in reservoirs situated in geological formations of schist rock or slate (shale gas or shale oil), tight sandstone (tight sands, tight gas, tight oil), coal bed methane and/or deposits characterized, in general, by the presence of low permeability rocks.

Holders of exploration permits and/or hydrocarbon exploitation concessions will be entitled to

request a hydrocarbon unconventional 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 hydrocarbon unconventional exploitation blocks and the granting of a hydrocarbon unconventional 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 a hydrocarbon unconventional exploitation concession also being holders of a preexisting and adjacent exploitation concession may request the unification of both blocks as a single hydrocarbon unconventional exploitation concession, provided they duly demonstrate the


geological continuity of these blocks. Such request should be based on the development of a pilot

plan.

Terms for Exploitation Concessions and Permits

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

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

permits is reduced from fourteen to eleven years;

ii. Unconventional exploration: the basic term is divided into two periods of four years each, plus an

optional extension of up to five years, that is, up to a maximum of 13 years; and

iii. 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.

Upon the expiration of the basic term’s first period, the exploration permit holder will decide whether to continue exploring the block or to transfer it back in whole to the Government. The whole

originally granted block may be kept provided the obligations arising from the permit have been properly met. Upon the expiration of the basic term, the holder of the exploration permit will revert the whole block, unless it exercises its right to extension the period, in which case the reversion will be limited to 50% of the remaining block.

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

i. Conventional exploitation concession: 25 years;

ii. Unconventional exploitation concession: 35 years; and

iii. Continental shelf and offshore 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 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 exploration 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 finish it based on the conditions established for each of them. All subsequent extensions

will be governed by the Argentine Hydrocarbons Law.

Awarding of Blocks

Law No. 27,007 proposes the drafting of a standard bid form that will be jointly made by the SE and the provincial authorities, to which all calls for tenders launched by law enforcement authorities should adjust, and introduces a specific criterion for the awarding of permits and concessions by incorporating the specific parameter of ‘greater investment or exploration activity’ as tie-breaker, at the PEN or the Provincial

Executive Branch’s duly supported discretion, as applicable.


Levy 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 exploration permit will pay the levy on an annual basis, in advance, for each square kilometer or its fraction based on the following scale:

First period: AR$250 per km2 or fraction;

Second period: AR$1,000 per km2 or fraction; and

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

In this case, offsetting mechanisms remain in place: the amount that the exploration permit holder

should pay for the second period of the basic term and for the extension period may be readjusted by offsetting it with exploration 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 AR$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 the exploitation concessionaire should pay on a monthly basis to the grantor as royalty remains at 12% of the proceeds derived from liquid hydrocarbons production extracted at wellhead. The production of natural gas will bear a like percentage of the value of extracted and actually used volumes

and will be payable on a monthly basis.

Cash payment of the royalty will be made based on the value of crude oil at 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.

For the conduction of hydrocarbon conventional exploitation complementary activities, as from the expiration of the granted concession and within the hydrocarbons unconventional exploitation concession, the enforcement authority may fix additional royalties of up to 3% above the current royalties, up to a maximum 18%, as applicable.

The PEN or the Provincial Executive Branch, as applicable, acting in its capacity as granting authority, may reduce by up to 25% the amount corresponding to royalties applicable to the production of


hydrocarbons during a term of 10 years after the conclusion of the pilot project in favor of companies

requesting a hydrocarbon unconventional exploitation concession within a 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 2 years before the granting of the extension.

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 so far been granted for 35 years) will be granted for the

same term than that granted for the originating exploitation concession, with the possibility of receiving

subsequent extensions for 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 plus 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: It 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: It provides that the Federal Government and the provinces will seek to adopt a uniform

fiscal treatment encouraging the development of hydrocarbon activities in their corresponding territories in adherence with the following guidelines:

− The gross receipts tax rate applicable to the extraction of hydrocarbons will not exceed 3%;

− The freezing of the current stamp tax rate and the commitment not to charge with it any financial contracts executed in order to structure investment projects, guarantee and/or warrant investments; and


− The commitment by the provinces and its municipalities not to impose new taxes —or increase

the existing ones— on permit and concession holders, except for service compensation rates, improvement contributions and general tax increases.

Restrictions on the Reservation of Blocks to National or Provincial Government-Controlled

Companies

The amendment to the Argentine Hydrocarbons Law restricts the Federal Government and the

provinces from reserving new blocks in the future in favor of public or mixed companies or entities, irrespective of their legal form. Thus, contracts entered 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. In this way, the ‘carry’ system during the blocks’ development or exploitation stage has been

done away with. 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 the Investment Promotion Regime for the Exploitation of Hydrocarbons —both conventional and unconventional— with the purpose of encouraging investments destined to the exploitation of hydrocarbons, and the concept of hydrocarbons unconventional exploitation concession.

Law No. 27,007 extends the benefits of the Promotion Regime to hydrocarbon projects involving a minimum of US$250 million direct investment denominated in foreign currency, assessed at the time the hydrocarbon exploitation investment project is presented, to be invested during its first 3 years. Before the

amendment, the Promotion Regime benefits reached investment projects denominated in foreign currency for a minimum US$1,000 million amount during a term of 5 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 exportation of these

hydrocarbons, provided the applicable projects have involved a minimum of US$250 million entry of foreign currency into the Argentine financial market.

During periods in which the national production of hydrocarbons is insufficient to meet domestic supply needs pursuant to Section 6 of the Argentine Hydrocarbons Law, the subjects 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 not 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 Market10

Encouragement Programs for the Increase in Domestic Natural Gas Production

Plan Gas

In February 2013, Res. No. 1/13 was published establishing the Plan Gas for a term of five years with the purpose of offsetting 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 collected from the

sale of the Surplus Injection; plus

ii. The difference between the Base Price and the price collected from the sale of the Adjusted Base Injection.

PEPASA, later merged into Pampa, joined Plan Gas in August 2013, with retroactive effects as of March 2013 and until December 2017. As regards the compensation accrued in fiscal year 2017, the Natural Gas Program Bond was received in April 2019.

In November 2013, the Hydrocarbon Investments Committee included by Res. No. 60/13 more

beneficiary companies under Plan Gas. Petrobras Argentina, later merged into Pampa, joined the plan on January 30, 2015, effective until June 30, 2018. As regards the compensations accrued in fiscal year 2017,

the Natural Gas Program Bond was received in July 2019, whereas compensations corresponding to the first semester of 2018 were collected in cash in April 2019.

Unconventional Plan Gas

On March 6, 2017, MEyM Res. No. 46/17 was published creating the Encouragement Program to

further investments to produce 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, which was calculated based on 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 calendar 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.

Pilot projects could obtain the minimum price for their whole unconventional production provided they reached an annual average production equal to or higher than 500,000 m3 per day during a twelve-month period by December 31, 2019. Developing projects could only benefit for the incremental portion

on top of the defined initial production. The reference price for calculating the incentive was the domestic market’s weighted average reported by the MEyM’s SRH. Furthermore, permanence in the program was



conditional upon compliance with the investment plan informed to the provincial authority; otherwise,

collected amounts, adjusted by the BNA’s interest rate, should be returned.

On November 17, 2017 MEyM Res. No. 447/17 was published in the BO, which extends the application of the Unconventional Plan Gas to the Austral Basin. Additionally, on January 20, 2018, MEyM Res. No. 12/18 was issued, which introduced the applicable amendments to the Unconventional Plan Gas 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 for the inclusion under this program for Río Neuquén,

El Mangrullo and Sierra Chata blocks, previously approved by the provincial enforcement authority. However, on January 30, 2019, the SGE informed gas producers affected by the Unconventional Plan Gas, including the Company, that no new projects would be approved under the Unconventional Plan Gas.

Natural Gas for the Residential and CNG Segment

Priority Demand and CEE

Pursuant to Res. No. 599 of 2007, the agreement between the Federal Government and natural gas producers, known as Producers’ Agreement, was ratified, the main goals of which were to secure supply of the domestic demand for gas and the gradual recovery in prices through all market segments. The last residential supply commitment expired in December 2011.

In October 2010, ENARGAS Res. I-1410 established certain modifications to the natural gas dispatch mechanism, placing a priority on the supply to the Priority Demand, with volumes exceeding those stipulated under SE Res. No. 599/07. Moreover, in December 2011, the terms of the Producers’ Agreement

were temporarily and unilaterally extended, allowing ENARGAS to continue using gas producers’ shares stipulated in the previous agreement (SE Res. No. 172/11).

In June 2016, MEyM Res. No. 89/16 was published in the BO, which established the criteria for the normalization of natural gas purchase agreements 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 operation.

Finally, 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, 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 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 differentiated 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 devaluation of the AR$ and the impossibility by distributors to pass this new FX 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, as regards the FX’s difference between the price of gas purchased by distributors

and that recognized in final tariffs, on November 15, 2018, PEN Executive Order No. 1053/18 was passed, which established, on an exceptional basis, that the Federal Government would bear such difference for the April 2018 – March 2019 period, in 30 monthly consecutive installments payable as from October 2019.

In mid-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$4.62/MBTU. Pampa submitted and was awarded. Producers would bill to distribution companies in AR$ pursuant to ENARGAS Res. No. 72/19, considering BNA’s average currency FX for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the FX stipulated

in the agreements. However, the FX 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 Solidarity Law, the FX freeze was subjected to a maximum term of up to 180 days.

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 a raw material for the following 6 months ranging between US$2.14/MBTU and US$4.69/MBTU, including the differential tariff11. 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 Solidarity Law, effective as from December 23, 2019, it was provided 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.

Natural Gas for Electric 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.

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, on October 4, 2018 SGE Res. No. 25/18

was issued, which provided 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, a tender was launched for the supply of gas to power plants effective for the year 2019, in which Pampa took part. At CAMMESA’s tender, indicative prices were received for a total 222 million m3 per day on an interruptible basis, at seasonal PIST prices with a maximum of US$5.2/MBTU and a minimum of US$3.2/MBTU for the June – August 2019 period, and with a maximum of US$3.7/MBTU

11 Tariff schemes contemplate a FX of AR$41.003/US$.


and a minimum of US$2.2/MBTU for the rest of the year. This tender 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 tender for the year 2019. Therefore, gas reference prices within the PIST decreased significantly, 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 consumption, as of this date CAMMESA launched successive tenders for monthly coverages. On December 27, 2019, CAMMESA’s tender for the January 2020 period took place, and offers for a total 260 million m3 per day were received, with an average PIST price of US$1.73/MBTU in the Neuquina Basin. However, on January 29, 2020, a tender 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 replicated this methodology for the March 2020 tender, receiving offers

for a total 78 million m3 per day at an average PIST price of US$2.42/MBTU for the Neuquina Basin.

Moreover, as from December 30, 2019, the supply of fuel for power plants was again centralized in CAMMESA (except for generators under Energía Plus)12.

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 Plan Gas, the exported volume does not qualify for such incentive. In this sense, 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.

Moreover, SHC Provision No. 168/19 of 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 northwest area. In that sense, 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 should 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 by 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 AR$4 per each exported US$ is in effect as from September 2018, with a maximum 12% rate; this rate was later amended by the Solidarity 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).

12 For further information, see section 5.1: ‘Fuel Supply and Consumption’ of this Annual Report.


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 10 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 were determined based on the domestic supply and demand.

However, following the FX volatility experienced in August 2019, DNU No. 566/19 was issued on August 16, 2019, which fixed 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 a FX of AR$45.19/US$, being updated until reaching AR$51.77/US$.

Liquid Hydrocarbons Export Duty

As from September 2018, PEN Executive Orders No. 793 and 865/18 provide for an oil export duty of AR$4 per exported US$, with a maximum 12% rate. However, the Solidarity Law established that this rate (pending implementation) should be lower than or equal to 8% of the taxable value.

6.2 Midstream13

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 turning into pesos of utility service

tariffs; consequently, the transportation tariff remained unchanged in AR$ 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 situation. From 2002 to 2015, TGS only had two tariff increases: 20% as from April 2014, as a result of the implementation of the transitory agreement entered in 2008; and, in May 2015, a 44.3% increase in the natural gas transportation tariff and a 73.2% increase in the CAU.

With the purpose of normalizing the segment, on February 24, 2016 TGS entered into a transitory

agreement with the Federal Government and, consequently, on March 29, 2016, the MEyM issued Res. No. 31/16 which, among other measures, instructed ENARGAS to conduct the RTI process and grant a transitory tariff increase to be charged against the RTI. Within this framework, on March 31, 2016 ENARGAS passed Res. No. 3724/16 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 perform a public hearing for setting tariffs and prices without market

intervention, and declared the nullity of MEyM 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 took place 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 took place. 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 IPIM 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.

The RTI considered the income necessary to execute a Five-Year Investments Plan between April 2017 and March 2022 for AR$6,787 million, expressed as of December 2016 values, which are essential to

face the operation 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 costs variations took place 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 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 the month of April 2016, and, as a result, on June 26, 2018, TGS voluntarily dismissed the Arbitration Proceeding it had brought before the ICSID. Moreover, 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 IPIM 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 IPIM variation; however,

on September 27, 2018 ENARGAS issued Res. No. 265/2018 setting a 19.7% increase based on the simple

average of the IPIM, 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 devaluation which took place 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 IPIM to determine tariff increase.

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 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 Res. No. 336/1914.

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 Solidarity Law on December 23, 2019.

Moreover, 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,

14 For further information, see section 6.1: ‘Natural Gas Price within the PIST’ and section 7.4: ‘Natural Gas for Distribution Companies’

of this Annual Report.


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 be in effect. Moreover, the license agreement provides for an irrevocable transportation offer of 10 million m3 per 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.

Regulations Specifically Applicable to the LPG Business

Household Gas Bottles’ Program and Propane for Grids Agreement

Currently, it is in force 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), providing 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 traded under the Household Gas Bottles’ Program is determined by the SRH, which set a price of AR$5,416/ton for butane and AR$5,502/ton for propane as from April 2018 (Provision No. 5/18). Later, prices were updated to AR$9,154/ton for butane and AR$9,042/ton for propane effective as from February 1, 2019 (SGE Res. No. 15/19), to AR$9,327/ton of butane and AR$9,213/ton for propane as from May 10, 2019 (SHC Provisions No. 34/19), and to AR$9,895/ton for butane and

AR$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.

As regards the Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution

Grids, a set of resolutions regulating the price of propane. On May 30, 2018, TGS executed the 16th extension to the agreement, which set a new methodology for the determination of the price and volumes

to be sold 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 extended. 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 works to extend the term 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

As regards 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.

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 AR$4 per each exported US$, with a maximum 12% tax rate. However, as from December 23, 2019, with the implementation of the Solidarity 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 US$-denominated tariff scheme was published providing for an average 34% increase, effective for a term of 5 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.


7. Relevant Events

7.1 Power Generation Segment15

Commercial Commissioning of Two New WFPs

On May 10, 2019, CAMMESA granted the commercial commissioning of PEPEs II and III, which was achieved within the scheduled timeframe. PEPE II and III, each with a 53 MW installed capacity, are located near the City of Bahía Blanca and consist of 14 wind turbines each, by which each turbine is made up of

four tower sections, a nacelle and three blades driving the turbine with a total diameter of 136 meters. The wind farms sell their energy in the MAT ER, meeting the demand of the GU segment through PPAs between private parties, and required a final estimated investment of US$130 million.

Progress in the Closing to CC Project at CTGEBA

CAMMESA granted the commercial commissioning to CTGEBA’s GT 04 as from June 12, 2019 for an installed capacity of 188 MW. Moreover, CAMMESA granted the commissioning to the capacity increase

of the already existing GT 03, also known as Genelba Plus, for a capacity of 19 MW, as from June 1, 2019.

The units, which contribute an additional 207 MW capacity to the SADI, are part of the Genelba Plus’ closing to CC project, which will include the entry into service of a ST, estimated for the second quarter of 2020. Upon the commissioning of the closing to CC, 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 CCs for a total 1.2 GW capacity.

Joint Acquisition of CTEB

On May 29, 2019, Pampa and YPF were jointly awarded the tender for the sale and transfer by IEASA of CTEB’s goodwill. On June 26, 2019, the sale and transfer to CTBSA, a company co-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 GTs with a total installed capacity of 567 MW. Additionally, it has a closing to CC project in place to be completed within a 30-month period, which will add 280 MW. Both open and closed cycles are under PPAs executed with CAMMESA pursuant to SE Res.

No. 220/07, the first one effective as from March 26, 2009 through April 27, 2022, and the second one executed on March 26, 2013 and expiring 10 years as from the commercial commissioning of the CC.

The price of the transaction amounted to a total US$282 million, which included the cash amount tendered and the purchase price of a certain amount of VRDs issued under the CTEB Trust. For the payment of the transaction, CTBSA received a total US$200 million contribution from its co-controlling companies and executed a loan for the amount of US$170 million with a syndicate of banks, non-recourse to Pampa

and YPF, provided the closing to CC project is executed within the stipulated term.

Moreover, CTEB’s acquisition involves the assignment to CTBSA of the trustee’s contractual status

under the CTEB Trust, which VRDs debt (excluding the VRDs repurchased by CTBSA) amounted to approximately US$229 million as of the transaction date and is estimated to be repaid with CTEB’s cash flow proceeds. On August 22, 2019, an amendment to the CTEB Trust was executed, which included, among others, the following:

i. Regarding the VRDs, the granting of a 24-month grace period, the modification of the interest rate

to Libor plus 6.5%, and the setting of principal amortization installments over a 60-month period;



ii. The obligation to complete the CC within a term of 30 months, the breach of this obligation resulting

in the acceleration of the VRDs;

iii. The incorporation of additional collection rights regarding both for open and closed cycle’s PPAs;

iv. Payments to the CTEB Trust transferable simultaneously, with the same payment priority and in the same kind as the amounts owed by CAMMESA to CTBSA; and

v. Upon the occurrence of a CAMMESA Event (pursuant to the definition of this term in the CTEB Trust): (a) CTBSA may request funds to meet the power plant’s operating expenses, and (b) VRDs payments will be rescheduled in case funds received as collection rights are insufficient.

YPF and Pampa jointly guarantee, at 50% each, the timely and proper performance of all payment obligations under the Financial Trust Agreement and the Syndicated Loan Agreement in case the closing to CC’s commissioning is not achieved within 30 months as from the effective date of the seventh amendment

to the agreement, and by December 26, 2021, respectively.

On the other hand, regarding progresses on the expansion project, on September 27, 2019, CTBSA and the Joint Venture made up of SACDE Sociedad Argentina de Construcción y Desarrollo Estratégico S.A. and Techint Compañía Técnica Internacional S.A.C.E.I. executed an engineering, procurement, construction,

commissioning and turnkey agreement.

It is estimated that the investment for the closing to CC will reach approximately US$200 million. Pampa will operate CTEB until 2023 and YPF will supervise the CC expansion works. Services will be provided by YPF and Pampa, taking turns every 4-year period.

Updates to the Remuneration Scheme for Legacy Capacity

On March 1, 2019, SRRYME Res. No. 1/19 entered effect, which abrogated the remuneration

scheme established by SEE Res. No. 19/17. The regime, which maintains the US$-denominated price scheme, mainly affects CTs by reducing the power capacity remuneration, and applies an average utilization

factor over the last twelve months which may reduce such remuneration by up to 30%. Moreover, the operation and maintenance remuneration is reduced by US$1.4/MWh.

Furthermore, on February 27, 2020, SE Res. No. 31/20 was published in the BO, which modified certain aspects of the remuneration scheme set forth by SRRYME Res. No. 1/19, effective as from February

1, 2020. The new Res. converts the whole remuneration scheme to the local currency at an FX of AR$60/US$ and establishes an update factor as from the second month of its application, which follows a formula consisting of 60% CPI and 40% IPIM. Moreover, this Res. modifies power capacity payments and incorporates an additional monthly remuneration in the hours of high thermal dispatch (HMRT).

Fuel Self-Procurement by Thermal Power Plants

SGE Res. No. 70 of November 2018 authorized thermal power plants to acquire their own fuel for

power generation. However, MDP Res. No. 12/19 effective as from December 30, 2019, abrogated SGE Res. No. 70/18 and restored the validity of Section 8 of SE Res. No. 95/13 and Section 4 of SE Res. No. 529/14, being the commercial management and fuel supply centralized again in CAMMESA (except for

generators with Energía Plus contracts).

Agreement for the Regularization and Settlement of Receivables with the WEM

On August 5, 2019, Pampa and certain subsidiaries executed an agreement with CAMMESA

whereby CAMMESA committed to disburse the LVFVD in arrears, after offsetting debts undertaken with the WEM under the financing agreements, loan agreements and receivables assignment agreements executed by generators, and applying a 18% reduction on the balance. Pampa and certain subsidiaries agreed on a


net amount for all items associated with the outstanding LVFVD, including interest as of July 31, 2019, as

well as the above-mentioned debt reduction, which amounted to AR$2,123 million, before tax withholdings for AR$393 million.

On August 7, 2019, the balance of AR$1,730 million was collected and, in furtherance of the undertaken commitments, Pampa and certain subsidiaries waived all submitted claims and irrevocably dismissed their rights to file any claim against the Federal Government, the SGE and/or CAMMESA regarding the outstanding LVFVDs. As a result of this agreement, the Company recognized revenues from sales of AR$260 million and net financial gains for AR$3,119 million.

Situation at TMB and TJSM

On January 6 and February 2, 2020 matured the PPAs between CAMMESA and the BICE, in its

capacity as trustee and acting on behalf of the Trusts16, for the trade of energy produced by TMB and TJSM, respectively. Consequently, as from these dates, the remunerations collectable by such power plants are those stipulated for capacity without PPAs.

In parallel, the respective Trust agreements terminated, a milestone that 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 TMB and TJSM’s operating and maintenance contracts also terminated on the above-mentioned dates, on January 3, 2020, the applicable addenda 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.

7.2 Transener17

Semiannual Remuneration Update

On March 22, 2019, the ENRE issued Res. No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 25.15% and 26.53%, respectively, effective as from February 1, 2019,

corresponding to the recognition of higher costs for the June – December 2018 period. Moreover, on September 25, 2019, the ENRE issued Res. No. 269/19 and 267/19 adjusting Transener and Transba’s remunerations by 18.83% and 18.81%, respectively, for the December 2018 – June 2019 period, with retroactive effects as of August 1, 2019.

The Solidarity Law, which entered effect on December 23, 2019, provided that electricity tariffs under federal jurisdiction would remain unchanged and contemplates the possibility to perform an

extraordinary RTI review for a term of up to 180 days. As of this date, Transener has not received any instructions by the ENRE.

Power Service Outage

On June 16, 2019 at 7:07 a.m., the SADI experienced a total outage as a result of the concurrence of multiple shortcomings, including a specific technical problem in the transmission system under the

16 The ‘Timbúes Thermal Power Plant’ and ‘Manuel Belgrano Thermal Power Plant’ Trust agreements executed on June 4, 2006 among

CAMMESA, in its capacity as the WEM’s Funds and Accounts Administrator, acting as Trustor; the BICE, acting as Trustee, and the SE, as

the WEM’s funds regulatory authority. 17 For further information, see sections 5.2 and 8.5 of this Annual Report.


responsibility of Transener but unrelated to the lack of investment and maintenance, as well as other faults

external to Transener.

As regards the transmission system under the responsibility of Transener, the fault was due to an improper adjustment of the DAG mechanism following the change in the Littoral Corridor configuration due to the bypass between the 500 kV Colonia Elía – Campana and Colonia Elía –Manuel Belgrano lines, made on account of the relocation of Tower 412 to support the highest possible power transmission capacity in this corridor, consequently, the DAG did not recognize signals sent out by the protection system.

Due to the large volume of electricity dispatched through this corridor and the DAG’s fault, there

was an imbalance between supply and demand, which could not be redressed by the system’s other restraint barriers unrelated to the electric power transmission service, resulting in a total outage. However, the 500 kV transmission system was available immediately after the collapse, being 100% of the transmission lines available to come into operation and allow for the system restore. Within just 8.5 hours,

75% of the country’s demand had been restored.

On November 6, 2019, the ENRE filed charges against Transener on account of the unavailability recorded in June 2019, including the previously described event, for a total AR$92 million, and Transener

submitted its discharge on December 9, 2019. As of the date hereof, Transener has not been notified by the ENRE of the applicable penalty.

Distribution of Cash Dividends

On April 25, 2019, Transener held a Shareholders’ Meeting, which approved, among other measures, the payment of cash dividends for AR$3,300 million, which payment was made on May 16, 2019.

Equity Interest Increase in Transba

On June 28, 2019, Transener acquired all Series C shares under the Employee Stock Program benefiting certain Transba employees. The price of the transaction amounted to AR$238 million, and Transener became the holder of 99.99% of Transba’s capital stock, the balance still being held by Citelec.

7.3 Edenor18

WEM Seasonal Programming

On December 27, 2018, SGE Res. No. 366/18 was issued, which abrogated SEE Res. No. 1091/17 and, consequently, the Federal Government’s social tariff and the discount scheme based on savings. The power capacity reference price was fixed at AR$80,000/MW-month as from February 2019, with 25% and 20% increases in May and August 2019, respectively, effective until October 2019. The transportation

stabilized price for extra high voltage system and the price for regional distribution based on the distribution company established by SEE Provision No. 75/18 remained unchanged. Energy reference prices were set at AR$2,762/MWh for GUDI for the February – October 2019 period, and at AR$1,852/MWh for other users as from February 2019, with 5% increases in May and August 2019, effective until October 2019.

However, on April 29, 2019, SRRYME Res. No. 14/19 was issued, which suspended the increases scheduled for May and August 2019 in the power capacity price and, as regards energy reference prices, provided for a 5% increase in May and August 2019 for GUDI and a 7% increase in May and August 2019

for the rest of non-residential users, and suspended increases scheduled for residential users.



Moreover, SRRYME Res. No. 26/19 and No. 38/19 issued on September 3 and October 22, 2019

approved the seasonal programming for the August – October 2019 and November 2019 – April 2020 periods, respectively, keeping prices effective as of August 2019 unchanged until April 2020.

With the entry into effect of the Solidarity Law, increases were suspended pursuant to the instruction issued by the ENRE at the end of 2019.


On February 1, 2019, ENRE Res. No. 27/19 was published, which approved the 25% CPD update

corresponding to the August 2018 – January 2019 semester (including a -1.59% efficiency stimulus E factor) effective as from February 1, 2019 but with retroactive effects as of February 1, 2019, added to the 6% CPD update, timely deferred in August 2018, with retroactive effects as of that date. Compensatory

amounts resulting from the deferral were collected in five installments.

On September 19, 2019, Edenor executed with the Federal Government an agreement to maintain the tariff schemes in force as of August 1, 2019, thus, deferring the CPD update for the January – June 2019 period, equivalent to 19.05% that should have been applied to tariff schemes as from August 2019.

However, the maintenance of tariff schemes allowed for the continuity of the amounts applied during the March – July 2019 period as the recovery of CPD deferral under ENRE Res. No. 27/19. Therefore, the CPD deferred amounts, excluding collections from the deferral, would be recoverable in 7 monthly and consecutive installments as from January 1, 2020, and would be adjusted based on the procedures standardized by CAMMESA. Moreover, Edenor undertook to meet the service quality parameters stipulated in the Concession Agreement, and any penalty payable by Edenor was postponed until March 1, 2020 at the original value plus the applicable updates, in 6 monthly installments. In turn, Edenor waived all

administrative, judicial, extrajudicial and/or arbitration claims resulting from this agreement.

The Solidarity Law, effective as from December 23, 2019, provided that electricity tariffs under federal jurisdiction would remain unchanged, and that an extraordinary RTI review process would be

launched for up to 180 days. On December 27, 2019, the ENRE instructed Edenor to maintain the tariff schemes effective as of May 1, 2019.

Agreement for the Transfer of Concession Jurisdiction

On February 28, 2019 the Federal Government, the Province of Buenos Aires and the City of Buenos Aires executed an agreement to transfer the electricity distribution utility service ―timely granted by the Federal Government to our subsidiary Edenor― to the jurisdictions of the Province of Buenos Aires and the City of Buenos Aires.

Mainly, this agreement provides for the creation of a bipartite regulatory body, the expenses related to Social Tariff under the responsibility of the Province of Buenos Aires and the City of Buenos Aires as

from 2019, and the commitment by the Federal Government to terminate pending issues, such as the claims related with the compliance of 2006 Memorandum of Understanding, as well as receivables from Social Tariff bills’ caps prior to 2019 and consumptions by shantytowns with community meters.

On May 9, 2019 the Federal Government, the Province of Buenos Aires and the City of Buenos Aires executed the Agreement for the Transfer of Jurisdiction, which provided that the applicable framework should be the federal regulation until the effective transfer date. This agreement was ratified in July 2019 pursuant to Provincial Executive Order No. 992/19 and Law No. 6,180 of the City of Buenos Aires. However,

with the entry into effect of the Solidarity Law, as from December 23, 2019 the ENRE was appointed as Edenor’s regulatory body until December 31, 2020.


Regularization of Liabilities

On May 10, 2019, Edenor entered into a Liabilities Regularization Agreement with the Federal Government, ending the reciprocal claims regarding the 2006-2016 Tariff Transition Period. Edenor waived all rights and proceedings against the Federal Government, including the lawsuit brought by Edenor in 2013 on account of the breach of the 2006 Memorandum of Understanding. Additionally, it undertook to settle debts for the works and loans of such period and committed to pay users certain penalties corresponding to such period and execute investments additional to those committed under the RTI. On the other hand,

the Federal Government partially recognized Edenor’s court claim by offsetting outstanding liabilities with the WEM for electricity purchases made during such period, partial settlement of investment loans granted by CAMMESA during such period, and the cancellation of penalties collectable by the National Treasury.

Additionally, the parties agreed that Edenor’s receivable from consumptions by shantytowns with community meters generated from July 2017 to December 31, 2018 in the amount of AR$471 million,

corresponding to the percentage committed by the Federal Government under the Framework Agreement, and the receivable resulting from the application of caps in the bills for users benefiting from the Social

Tariff for AR$923 million, to be offset with Edenor’s debts under the loans granted by CAMMESA and funded by the Federal Government, and the investments made under the FOTAE for the Interconnection works of Costanera – Puerto Nuevo – Malaver at 220 kV, and the execution of Tecnópolis Substation works.

Edenor’s Shareholders’ Meeting held on June 10, 2019 ratified Edenor’s Board of Directors’ acts associated with the negotiations of the Agreement for the Implementation of the Transfer of Jurisdiction and the Liabilities Regularization Agreement. The implementation of this agreement generated a one-time profit of US$308 million before income tax, which is disclosed in the line of ‘Agreement on the regularization

of obligations’ of the FS as of June 30, 2019, and does not imply any fund inflow; quite on the contrary, within the next 5 years Edenor shall meet the investment plan additional to the RTI, pay penalties to users, settle liabilities on account of loans and works, and pay the generated income tax, which involves a fund disbursement for an approximate total of AR$7,600 million, at June 2019 values, over a term of 5 years.

Extension of the New Framework Agreement

On September 20, 2019, Edenor executed with the Federal Government an Agreement for the Extension of the New Framework Agreement, effective from January 1, 2019 to May 31, 2019, ratifying the commitment by the Federal Government to settle the amounts corresponding to the supply of electricity to shantytowns, after discounting the electricity associated with the Social Tariff. Pursuant to the Liabilities Regularization Agreement and the Agreement for the Extension of the New Framework Agreement, as of December 31, 2019 Edenor recognized revenues from the sale of energy under the Framework Agreement, expressed at constant currency, for AR$591 million and AR$220 million, corresponding to the Federal

Government’s stake, until May 31, 2019.

Additionally, the Extension Agreement stipulated that Edenor should assign the recognized receivables to Edesur, the Federal Government undertaking to instruct CAMMESA to offset such receivables with loans payables Edesur holds with the Federal Government. In this context, Edenor and Edesur entered into the applicable receivables’ assignment agreement, which stipulated that Edesur will pay to Edenor, in consideration of the assigned receivables, a total, single and final amount of AR$168 million.

Following the entry into effect of the Solidarity Law, Edenor is currently unaware of the guidelines

to follow regarding consumptions by shantytowns with community meters for non-recognized and future periods stipulated in the Framework Agreement.

Claim Against RDSA

In November 2015, Edenor acquired from RDSA a real estate asset to be built, but the agreement was breached by RDSA in August 2018. Furthermore, in February 2019 RDSA filed a bankruptcy petition simultaneously with the bringing of legal actions by Edenor against RDSA and the insurance claim. On


September 30, 2019, Edenor agreed with Aseguradores de Cauciones S.A., the insurance company of RDSA,

that it will receive as single, total and final compensation the amount of US$15 million and the assignment in its favor of the insurance company’s right to subrogate to the right to subrogate to the rights of the insured party for the amount paid against the insurance holder, RDSA. As of the date hereof, Edenor has received the amount of US$13.5 million, an additional US$0.5 million to be collected pending approval by the National Superintendence of Insurance, and the balance of US$1 million to be paid in 6 monthly consecutive installments, the first one being payable on April 1, 2020.

On the other hand, the arbitration complaint timely brought by Edenor against RDSA before the

BCBA’s Arbitration Court seeking the refund of the price paid for the undelivered real estate was suspended, in order to verify RDSA’s credit status throughout the bankruptcy process, which was verified in the amount of AR$2,126 million by the court hearing the case.

7.4 Oil and Gas19

Natural Gas for Electric Power Generation20

On December 27, 2018, through the MEGSA platform, CAMMESA tendered natural gas to be supplied to thermal power plants for the year 2019, and offers for a total gas volume of 222 million m3 per day on an interruptible basis were received, at seasonal PIST prices consistent with the reference prices set out in the auction.

Furthermore, in November 2018, thermal power plants were authorized to procure their own fuel for power generation. Reference prices were observed as from January 2019, being for the Neuquina Basin

US$3.70/MBTU until May 31, 2019. However, the SGE later instructed CAMMESA to recognize in the CVPs declared as from February 18, 2019 the gas prices which would have resulted if CAMMESA had acquired them, thus reducing reference PIST prices in the Neuquina Basin 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.

However, the Company opted to exercise such option, allocating a significant part of its gas production to the dispatch of its thermal units since November 2018 to December 30, 2019, when the supply of gas to thermal generators was again centralized in CAMMESA.

For 2020 consumptions, as of this date CAMMESA has launched successive monthly tenders. On December 27, 2019, CAMMESA tendered gas for January 2020 at an average PIST price of US$1.73/MBTU in the Neuquina Basin. However, on January 29, 2020, a tender for gas was launched for the month of February 2020, but on a partially biding basis, with a 30% DoP, the resulting average PIST price for the Neuquina Basin reaching US$2.59/MBTU. CAMMESA replicated this methodology for the March 2020 tender, obtaining an average PIST price of US$2.42/MBTU for the Neuquina Basin. Pampa took part in said tenders.

Gas Export

SGE Res. 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 quantity21, whichever

occurs first. SGE Res. 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.

19 For further information, see sections 6.1 and 8.3 of this Annual Report. 20 For further information, see section 5.1: ‘Fuel Supply and Consumption’ of this Annual Report. 21 Authorized daily export volume by the number of days the authorization is valid as from its granting.


Moreover, on July 26, 2019, SGE Res. No. 417/19 was published, which provided that exports may

be agreed under firm, interruptible, operational exchanges or support agreements, being the supply to the Argentine domestic market secured in all cases. In the case of projects covered by the Unconventional Plan Gas, the exported gas may not be computed under such program. Later, in October 2019, this Res. was supplemented by SHC Provision No. 284/19.

On August 21, 2019, SHC Provision No. 168/19 was published, which approved the terms and conditions for the export of gas to Chile on a firm basis, for the September 15, 2019 – May 15, 2020 period, for a maximum aggregate volume of 10 million m3/day, being 65% from the Argentine Central-Western

area, 25% from the South, and 10% from the Northwest area, as long as the Argentine domestic market is fully supplied.

In this sense, in September 2019 Pampa obtained a permit to export gas on a firm basis to Refinerías ENAP in Chile for a maximum volume of 0.6 million m3/day or a total 137 million m3 at a price

of US$3.1/MBTU, net of export duties and transportation costs, effective until May 15, 2020. In December 2019, the maximum volume was increased to 0.9 million m3/day or a total 189 million m3.

If higher costs are incurred by the WEM as a result of the use of alternative fuels for electric power

generation (imported LNG, coal, FO or GO), 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 Solidarity Law, setting a rate lower than or equal to 8% of the taxable value or the FOB price.

Natural Gas for Distribution Companies

Public Tender for Gas Supply on a Firm Basis for Distribution Companies

On February 14, 2019, gas distribution companies tendered through the MEGSA for the supply of gas on a firm basis with a ToP and DoP 70% commitment of the volume, for all the basins except for the

Noroeste Basin, for the winter (April – September 2019) and summer (October 2019 – April 2020) periods. The amounts of 36.1 and 14.4 million m3/day were assigned for the winter and the summer, respectively,

at an average price of US$4.62/MBTU. Pampa tendered and was awarded. On February 15, 2019, the auction for the Noroeste Basin was held, and 9.4 and 3.8 million m3/day were assigned for the winter and the summer, respectively, at an average price of US$4.35/MBTU.

Invoices from producers to distribution companies would be in AR$ pursuant to ENARGAS Res. No. 72/19, considering BNA’s average currency FX for the first 15 days of the month immediately preceding the beginning of each seasonal period or, if lower, the FX stipulated in the agreements. The seller may request the purchaser to constitute a surety bond and, in case ENARGAS does not guarantee the pass-

through of the agreed sales price to the tariff, either party may terminate the rights and obligations under the agreement.

The FX update which should have been applied since October 1, 2019 was deferred pursuant to several regulations and was finally subject to a maximum term of up to 180 days as from the entry into force of the Solidarity Law.

FX Difference between Gas Producers and Distribution Companies

As regards receivables accrued on account of FX differences between the price of the gas purchased by gas distributors and that recognized in their final tariffs between April and October 2018, on November 15, 2018 PEN Executive Order No. 1053/18 was issued, which established, on an exceptional basis, that the Federal Government would bear such difference for the April 2018 – March 2019 period. The amount resulting from the updates would be transferred to gas distribution companies, which would immediately transfer it to the involved gas suppliers in 30 monthly and consecutive installments as from October 1,


2019. On August 20, 2019, ENARGAS Res. No. 466/19 was published, which approved the methodology

for its calculation.

ENARGAS Res. No. 735/19 issued on November 12, 2019 approved the payment to producers and IEASA through gas distribution companies for a total AR$24,525 million22, of which AR$1,219 million correspond to Pampa. As of December 31, 2019, the first installment of AR$41 million has been collected, whereas 29 installments and the applicable updates are still pending of collection.

Tariff Scheme for Natural Gas Users in Distribution

ENARGAS Res. No. 193-199, 201-202 and 205-207 /19 established gas tariff schemes effective as from April 1, 2019, considering a 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 tariff23. These gas prices differ based

on the distribution company and the geographical location. Furthermore, pursuant to SGE Res. No. 148/19 issued on March 29, 2019, 27% and 12% discounts in the price of natural gas within the PIST were set for the months of April and May 2019, respectively, which would be borne by the Federal Government in the form of a subsidy.

Aiming to provide smoothening in residential users’ seasonal expenses due to higher winter consumptions, on June 21, 2019, SGE Res. No. 336/19 was issued, which established, on an exceptional basis, a 22% payment deferral on bills issued during the July – October 2019 period, to be recovered in five monthly, equal and consecutive installments payable as from the bills issued in December 2019. The financing cost of such deferral would be borne by the Federal Government, and residential users may opt out of this benefit.

On August 22, 2019, SGE Res. No. 488/19 was issued, which established the methodology

applicable to the deferral, the calculation of interest and the compensation procedure. As of December 31, 2019, the receivables, collectable mainly by TGS (for the gas transportation regulated utility) amounted to approximately AR$1,206 million. However, as of this date, no regulations have been passed in this respect.

SGE Res. No. 521/19, 751/19 and 791/19 deferred until February 1, 2020 the semiannual update which should have been applied since October 1, 2019 on account of both costs variations in TGS’s regulated business and the price variation of natural gas as a raw material in AR$. However, the Solidarity

Law, which entered effect on December 23, 2019, provided that gas tariffs under federal jurisdiction would remain unchanged for a term of up to 180 days.

Plan Gas

As regards the Unconventional Plan Gas, on January 30, 2019, the SGE communicated the affected companies that no new projects would be approved. As of the date hereof, no regulations have been issued in this respect, and Pampa has not been formally notified of the rejection to the inclusion of the Río Neuquén,

El Mangrullo and Sierra Chata blocks under this program.

In January 2019, Pampa collected AR$649 million in cash on account of the Plan Gas accrued in 2018. As regards the Plan Gas accrued in 2017, in February 2019 SGE Res. No. 54/19 was published, which

provided that obligations arising under MEyM Res. No. 97/18 should be settled with national debt securities, as well as Joint Res. No. 21/19 of the Secretariat of Finance and the Secretariat of Treasury, which provided for the issuance, on February 27, 2019, of US$-denominated Natural Gas Program Bonds for a term of 2 years and 4 months, without interest, and consisting of 29 monthly and consecutive installments, the first

one for a FV of 6.66%, the following 18 installments for 3.33%, and the remaining 10 installments for 3.34%. On April 17, 2019 Pampa received US$89 million FV for PEPASA (a company absorbed by Pampa), and on July 17, 2019 it collected the outstanding receivables of US$54 million FV, both maturing on June

22 Original value of AR$19,531.6 million updated as of September 30, 2019 pursuant to ENARGAS Res. No. 735/19. 23 It contemplates a FX of AR$41.003/US$, corresponding to the average quote price between March 1 and 15, 2019.


28, 2021. In 2019, 11 installments for a total amount of US$57 million were collected, and, as of the date

hereof, two additional installments have been collected for a total amount of US$9.5 million.

Measures for Crude Oil and Fuel Commercialization in the Domestic Market

On August 16, 2019, DNU No. 566/19 was published, which provided that crude oil deliveries made in the domestic market in the following 90 calendar days might be invoiced and paid at the price agreed between oil producers and refiners as of August 9, 2019, applying a FX of AR$45.19/US$ and a reference Brent price of US$59/bbl. The prices of gasoline and diesel oil sold in the domestic market might not exceed

the price effective on August 9, 2019. Both oil producers and refiners should meet the domestic demand during this period, effective until November 13, 2019.

The reference FX were successively updated to AR$46.69/US$ (DNU No. 601/19),

AR$49.30/US$ (SGE Res. No. 557/19) and AR$51.77/US$ (SGE Res. No. 688/19). These resolutions also allowed for a gradual increase in pesos of refined products’ prices.

SGE Res. No. 552/19 of September 13, 2019 provided for a compensation of AR$116/bbl of oil supplied to the domestic market during September 2019, of which 88% would be payable to oil producers

and 12% to the granting provinces, in exchange of granting the Federal Government indemnity from any kind of claim associated with such measure. Pampa did not adhere and is evaluating the courses of action to take.

Increase of Equity Interest in OCP

On December 5, 2018 Pampa, through its subsidiary PEB, entered into an agreement with AGIP for the acquisition of 4.49% of OCP’s capital stock and the receivable AGIP held regarding the subordinated

debt issued by OCP, which was approved by the Ecuadorian Government on March 8, 2019 and executed on June 20, 2019, thus increasing our equity interest in OCP to 15.91%. In case the above-mentioned

receivable is collected by PEB before 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 involved the recognition of profit for US$25 million in Pampa’s FS. Besides, as of December 31, 2019, PEB reported losses for the impairment of its prior interest in OCP

(11.42%) for an amount of US$6.7 million.

Exploration Licenses

The extension of the exploration license for Parva Negra Este, a block located in the Province of Neuquén granted under concession to GyP and operated by Pampa since April 2014 in which the Company has a 42.5% stake, expired in April 2019. On March 29, 2019, GyP requested that the whole Parva Negra Este block should be classified as an evaluation lot for a 3-year period.

On February 22, 2019, Salta’s Provincial Executive Order No. 249/19 was issued, which granted a 12-month term extension for the third exploratory period of Chirete, a block located in the Province of Salta

and operated by High Luck Group Limited, effective as from November 18, 2018. Since the discovered field turned out to be commercially exploitable, on April 26, 2019 an application was filed for the granting of an exploitation concession for the 95-km2 lot known as ‘Los Blancos’. Additionally, on April 30, 2019 a three-year extension of the third exploratory period for the remaining area was requested considering that the exploratory potential will require additional surveys after the discovery of oil in late 2018. Pampa has a 50%

interest.

In the case of Río Atuel, a block located in the Province of Mendoza and operated by Petrolera el Trébol, the new expiration date for the second exploratory period was established at December 7, 2019,


and as from December 18, 2019 the third exploratory period, for a term of one year, started, with the

relinquishment of 50% of the total surface of 998 km2. Pampa holds a 33.33% interest.

Moreover, the Company had timely informed to the partners of the Enarsa 1 and Enarsa 3 blocks of its decision not to take part in their reconversion into exploration permits pursuant to Law No. 27,007. On April 15, 2019, SGE Res. No. 195/19 and 196/19 were published informing of the relinquishment and transfer back to the Federal Government of the Enarsa 3 block, as well as the partial reconversion of the Enarsa 1 block into an exploration permit granted to YPF and the relinquishment and transfer back to the Federal Government of Enarsa 1 block’s remaining surface. Therefore, Pampa no longer holds any interests

in these areas.

7.5 TGS24


On March 29, 2019 ENARGAS issued Res. No. 192/19, which established a 26.0% increase in tariff

schemes applicable to the natural gas transportation utility service by TGS, effective as from April 1, 2019, which represents an approximate 3% increase for end-users. This increase was determined by ENARGAS using the non-automatic adjustment mechanism based on the PPI’s semiannual variation between August 2018 and February 2019.

SGE Res. No. 521/19, 751/19 and 791/19 deferred until February 1, 2020 the semiannual update which should have been applied since October 1, 2019 on account of costs variations in TGS’s regulated business, as well as the price variation of natural gas as a raw material in AR$. Pursuant to these Res.,

TGS submitted its proposal for the readjustment of committed mandatory investments before the ENARGAS so that the applicable adjustments should be implemented, observing the exact impact of the amounts not collectable in the tariff and the committed investment amounts, without this affecting the continuity of the utility service. As of the date hereof, ENARGAS has not issued any regulation in this respect.

However, the Solidarity Law, which entered effect on December 23, 2019, provided that natural gas tariffs under federal jurisdiction would remain unchanged, and that an extraordinary RTI review would be initiated for a maximum term of up to 180 days. As of this date, TGS has not received any instructions

by ENARGAS.

New Vaca Muerta – Province of Buenos Aires Main Gas Pipeline

In order to replace imported NGL and the use of liquid fuels, pursuant to SGE Res. No. 82/19 published on March 8, 2019, the private sector was called upon to submit bids for the construction and/or expansion of a gas pipeline connecting the Neuquina Basin with the Province of Buenos Aires. On April 8,

2019 TGS submitted its project for the construction of a gas pipeline with a length of more than 1,000 km.

On July 30, 2019, SGE Res. No. 437/19 —issued in furtherance of DNU No. 465/19 of July 5, 2019— launched a national and international public tender for the award of a license for the rendering of the natural gas transportation service connecting the town of Tratayén, Province of Neuquén, with the town of Salliqueló, Province of Buenos Aires (Phase 1), and Salliqueló with the City of San Nicolás de los Arroyos,

Province of Buenos Aires (Phase 2). The new license introduced as a requirement to build a gas pipeline and associated facilities for the subsequent provision of the transportation service, to which effect a RET is

established for the first 17 years as from the execution of the license in order to allow for the repayment of incurred investments, which would be governed by the following guidelines:

i. The bid terms will provide for the partial assignment of the initial transportation capacity on a direct basis, and the remaining capacity will be assigned under open proceedings; furthermore, the



remuneration to the transportation company and the applicable adjustments will be freely

negotiated with carriers and shall not incur any discriminatory conduct in the access;

ii. Values resulting from the negotiation may not be passed through to the Priority Demand;

iii. The license agreement provides for an irrevocable transportation offer of 10 million m3/day to CAMMESA for a 15-year period.

The license will be granted for a term of 35 years, with the possibility to extend for an additional 10-year period; therefore, once the RET term has expired, the regime set forth by Gas Law No. 24,076 will govern during the remaining term of the license. Moreover, Phase 1, with an approximate length of 570

km and a minimum initial transportation capacity of 15 million m3/day (expandable to 40 million m3/day), should be ready for service within a term of 18 months as from the granting of the license, whereas Phase 2, with an approximate length of 470 km and a transportation capacity of 20 million m3/day, within a term of 60 months.

The opening of the proposals had been set at September 12, 2019, and the final award at October 12, 2019, whereas the deadline for the granting of the new license was scheduled for 60 days after the opening of the proposals. However, the SGE provided for a term extension until March 31, 2020 for the

opening of tenders. Currently, although the new Government has not expressed itself on this matter, TGS is analyzing the bid terms and its participation in the bidding process.

Vaca Muerta Midstream Project

The project for the construction and operation of a 147-km gathering gas pipeline in Vaca Muerta formation, with a total transportation capacity of 60 million m3/day, and a conditioning plant in the town of Tratayén, with an initial capacity of 5 million m3/day and modularly expandable to 56 million m3/day,

was started in April 2018, and during 2019 the facilities’ assembly and pressurization works were successfully completed, involving a total approximate investment of US$260 million.

On April 30, 2019 the Southern tranche and part of the Northern tranche of the gas pipeline for a

total 66 km were commissioned, and a partial commissioning of the conditioning plant was granted. On November 3, 2019, 56 km of the Northern tranche was commissioned, connecting Rincón la Ceniza field with the Southern tranche of this gas pipeline. Finally, on December 12, 2019 the remaining section of the

Northern tranche was commissioned, which connects Los Toldos I Sur field to Rincón la Ceniza and the conditioning plant.

Moreover, in February 2020 TGS approved the expansion of the conditioning plant, with a term of execution of one year, which works are expected to start between April and May 2020 and will require a US$15 million investment. The project, which will consist of a 2.6 million m3/day increase in the treatment capacity, the installation of a butane extraction unit and the construction of facilities for the storage and dispatch of liquids, will allow to continue improving the return on the investment made by TGS.

General Shareholders’ Meeting and Distribution of Dividends

On April 11, 2019 TGS held General Ordinary Shareholders' Meeting, which approved, among other

measures, the payment of cash dividends in the amount of AR$6,942 million. Furthermore, TGS’s Board of Directors resolved to pay an additional cash dividend in the amount of AR$240.5 million from the partial release of the Reserve for Future Investments and Other Specific Purposes, totalizing AR$7,182.5 million, which were placed at the shareholders’ disposal as from April 23, 2019.

On October 17, 2019, TGS’s General Shareholders’ Meeting was held, which approved the distribution of a dividend consisting of 29.4 million common shares (equivalent to 0.03849 common shares per outstanding share), which is the repurchased amount held in treasury as of the date of such meeting. On October 31, 2019 TGS’s Board of Directors resolved to place such treasury shares at the disposal of shareholders as from November 13, 2019, and to provide for the payment of a cash dividend to the sole


effect of withholding the income tax, if applicable, for AR$238 million, equivalent to 7.5269% of the market

value of the 29.4 million common shares to be distributed, according to TGS’s closing stock price on November 8, 2019 at ByMA. Therefore, as of the date hereof Pampa’s stake in TGS amounts to 27.2% of its issued capital stock25.

In addition, this meeting approved certain amendments to the Technical, Financial and Operational Service Agreement, including a term extension and a gradual reduction in the amount of payable compensation over the next years, effective as from December 28, 2019. These modifications would entail a progressive reduction in the remuneration collectable by Pampa over the years in its capacity as technical

operator, but would not entail a modification in the scope of the tasks performed.

Legal Proceeding Challenging the Charge on Natural Gas Processing Companies

On March 26, 2019, TGS was served notice of the first-instance ruling rendered by the National First-Instance Administrative Litigation Court No. 1 upholding the claim for unconstitutionality and nullity of PEN Executive Order No. 2,067/08, Res. No. 1451/08 of the former Ministry of Federal Planning, Public Investment and Services, and ENARGAS Res. No. I-1,982/11 and I-1,991/11, as well as of any other act

or provision issued or to be issued based on the above-mentioned provisions. The Federal Government appealed this ruling on March 29, 2019; the appeal was granted on April 3, 2019 and has not been resolved as of the date hereof. On 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.

It is important to remember that the charge from PEN Executive Order No. 2,067/08 was created to finance natural gas imports carried out by the Federal Government, and it made up the variable costs for

the processing of natural gas by TGS at its own expense.

7.6 Solidarity Law

On December 23, 2019 the Solidarity Law entered effect, which declares a public emergency in economic, financial, fiscal, administrative, pension, tariff, energy, health and social matters, vesting in the PEN the powers conferred by such Law until December 31, 2020. The main measures affecting the Company

are described below:

The maintenance of tariff schemes for electricity and natural gas under federal jurisdiction and the consideration of an extraordinary RTI review for a maximum term of up to 180 days;

The maintenance of the ENRE’s competency over Edenor’s electricity distribution utility service until December 31, 202026;

The suspension of the income tax rate decrease to 25%, setting it at 30%; an increase in the tax

on dividends rate to 13%, setting it at 7% for fiscal years starting on or after 2021;

The inflation adjustment resulting from the application of the comprehensive adjustment provided for by the Income Tax Law, corresponding to the first and second fiscal year as from 2019, should be charged as follows: 1/6 during such fiscal year, and the remaining 5/6s, in equal parts, in the immediately following five periods27; and

The hydrocarbon export duty rate may not exceed 8% of the taxable value or the official FOB price, and this tax may not decrease the Wellhead value for the calculation and payment of royalties to

the producing provinces.

25 It includes TGS shares acquired by Pampa in the market. 26 For further information, see section 7.3: ‘Agreement for the Transfer of Concession Jurisdiction’ of this Annual Report. 27 For further information, see section 7.9: ‘Tax Inflation Adjustment’ of this Annual Report.


7.7 Buyback of Own Financial Securities

Given the current markets’ volatility and the difference between the value of assets and the quoted price in stock exchange market, which the latter does not reflect either the value or the economic reality that currently hold nor its upside potential in the future, resulting in detriment to shareholders’ interests, and taking into account the strong cash position and availability of funds, Pampa, Edenor and TGS’s Boards of Directors approved programs for the repurchase of own shares.

Furthermore, while the repurchase programs are in effect, directors, statutory auditors and senior managers may not sell shares in such companies held directly or indirectly managed by them during the applicable term.

Pampa Energía

In 2019, Pampa’s Board of Directors approved three Share Buyback Programs under the following terms and conditions:

Repurchase Program III Repurchase Program IV Repurchase Program V

Maximum amount for repurchase US$100 million US$65 million US$50 million

Maximum price US$1.04/ordinary share or US$26/ADR US$1/ordinary share or US$25/ADR US$0.58/ordinary share or US$14.5/ADR

Period in force 120 days since Mar 28, 2019 120 days since Aug 13, 2019 120 days since Nov 11, 2019

Repurchases @ end of feb-20 2,387,873 ADRs @ US$22.87/ADR 4,307,692 ADRs @ US$15.06/ADR 3,191,232 ADRs @ US$13,09/ADR

Progress 55% - Complete 100% - Complete 84% - In process

Pampa

Note: Repurchases are deemed to be effected transactions.

The third share buyback program was suspended by the Board on June 12, 2019, as the quote of

shares exceeded the repurchase caps. However, on August 12, 2019 the fourth program was approved, which maximum amount was extended on August 30, 2019 from US$50 million to US$65 million.

Furthermore, Pampa’s Shareholders’ Meeting held on October 1, 2019 approved the capital stock reduction through the cancellation of 152.0 million common treasury shares (equivalent to 6.1 million ADRs) acquired under the share buyback programs, currently in the process of registration before the IGJ.

At the end of February 2020, Pampa’s outstanding capital stock amounted to 1,632.6 million

common shares (equivalent to 65.3 million ADRs), without including shares pending cancellation and 115.3 common shares (equivalent to 4.6 million ADRs) held in treasury, repurchased after the October 1, 2019 Shareholders’ Meeting.

Regarding debt securities, in 2019 Pampa acquired and held in treasury:

i. US$13.5 million FV of its CBs maturing in 2023, acquired at an average clean price of US$74.5 per US$100 FV;

ii. US$54.2 million FV of its CBs maturing in 2027, acquired at an average clean price of US$73.5 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; and

iii. US$7.3 million FV of its CBs maturing in 2029, acquired at an average clean price of US$78.6 per US$100 FV.

At the end of February 2020, outstanding 2023, 2027 and 2029 CBs, excluding treasury holdings, amounted to US$486.5 million, US$687.0 million and US$292.7 million, respectively.


Edenor

After terminating the second share buyback program on April 5, 2019, on April 9, 2019, Edenor’s Board of Directors approved a third program pursuant to the following terms and conditions:

Repurchase Program II Repurchase Program III

Maximum amount for repurchase AR$800 million AR$800 million

Maximum price US$1.5/ordinary share or US$30/ADR US$1.15/ordinary share or US$23/ADR

Period in force 120 days since Dec 6, 2018 120 days since April 10, 2019

Repurchases @ end of feb-20 449,676 ADRs @ US$26.48/ADR 97,463 ADRs @ US$17.33/ADR

Progress 57% - Complete 9% - Complete

Edenor


On June 12, 2019 Edenor’s Board of Directors resolved to early terminate the third share buyback program. As of the closing of February 2020, Edenor’s outstanding capital stock amounted to 875.1 million

common shares (equivalent to 43.8 million ADRs), not including 31.4 million repurchased common shares held in treasury (equivalent to 1.6 million ADRs).

As regards debt securities, in 2019 Edenor repurchased a total of US$29.1 million28 FV of its 2022 CBs at an average clean price of US$73.7 per US$100 FV which, in addition to those already held in treasury, amount to a total US$39.3 million FV. Therefore, at the end of February 2020, outstanding CBs amounted to US$137.0 million.

Moreover, in 2019 Pampa acquired a total of 1.2 million Edenor’s ADRs at an average cost of

US$5.0/ADR. Thus, at the end of February 2020 the Company’s equity interest amounts to 54.4% of Edenor’s issued capital stock.

TGS

After terminating the second share buyback program on March 5, 2019 (the last transaction being conducted on December 26, 2018), during 2019 TGS’s Board of Directors approved two Share Buyback Programs pursuant to the following terms and conditions:

Repurchase Program III Repurchase Program IV Repurchase Program V

Maximum amount for repurchase AR$1.5 billion AR$3.2 billion AR$4.0 billion

Maximum price AR$135/ordinary share or US$15/ADR AR$116/ordinary share or US$10.5/ADR AR$130/ordinary share or US$10.5/ADR

Period in force 180 days since Mar 28, 2019 90 days since Aug 27, 2019 120 days since Nov 20, 2019

Repurchases @ end of feb-20 2,424,018 ADRs @ US$10.00/ADR 1,388,905 ADRs @ US$7.10/ADR 3,485,450 ADRs @ US$6.22/ADR

Progress 79% - Complete 18% - Complete 33% - In process

TGS


On August 26, 2019, TGS’s Board of Directors terminated the third share buyback program and

approved the fourth program. On November 19, 2019, it was decided to terminate the fourth program, the last transaction being conducted on November 20, 2019, and the fifth program was approved.

Moreover, on November 13, 2019, 29.4 million common shares (equivalent to 5.9 million ADRs) which TGS held in treasury under the share buyback programs were distributed as dividends29.

28 Including the related-party transaction on November 21, 2019 for the sale of US$19.1 million FV of Edenor’s 2022 CBs held in treasury

by Pampa. 29 For further information, see section 7.5: ‘General Shareholders’ Meeting and Distribution of Dividends’ of this Annual Report.


As of the closing of February 2020, TGS’s outstanding capital stock amounts to 773.8 million

common shares (equivalent to 154.8 million ADRs), not including 20.6 million common shares repurchased after the Shareholders’ Meeting held on October 17, 2019 (equivalent to 4.1 million ADRs).

Besides, in 2019 Pampa acquired a total of 1 million TGS’s ADRs at an average acquisition cost of US$6.8/ADR. As of the closing of February 2020, the Company's direct and indirect shareholdings amount to 27.2% of TGS’s issued capital stock, including 7.9 million common shares (equivalent to 1.6 million ADRs) received as dividend in kind.

Transener

In 2019, Transener repurchased a total of US$7 million FV of its 2021 CBs at an average clean price of US$96.1 FV. Thus, at the end of February 2020, outstanding CBs amount to US$91.5 million.

7.8 Debt Transactions

As of December 31, 2019, at consolidated level, the average interest rate bearing US$ loans was

7.7%, currency in which 93% of its gross debt is denominated and mostly at fixed rate. The average life of Pampa’s consolidated financial debt amounted to approximately 5.4 years. The following chart shows Pampa Group’s debt profile30 (in million US$):

In 2019, Pampa stand-alone had short-term debt maturities for approximately US$282 million.

Throughout 2019 and with the purpose of improving its maturities profile and preserve a solid cash position, the Company canceled and pre-canceled short-term loans, repurchased its own CBs in the market and issued Series 3 CBs for US$300 million. As of December 31, 2019, Pampa stand-alone’s short-term principal maturities amounted to approximately US$101 million. After the closing of fiscal year 2019, Pampa redeemed at maturity for a total US$25 million.

Moreover, in 2019 Edenor redeemed at maturity two of the four amortizations of the loan granted by ICBC for a total amount of US$25 million.

Furthermore, in November 2019 TGS executed pre-export credit facility for US$17 million maturing in March 2020. However, it was pre-cancelled in February 2020.

30 It does not include interests; it considers Pampa stand-alone and Edenor at 100%, and the affiliates TGS, Transener, Greenwind,

CTBSA and Refinor at our equity participation.

Transener

US$92m

@ 9¾

Edenor

US$137m

@ 9¾

Pampa US$487m

@ 7⅜ Pampa

US$687m

@ 7½

TGS US$500m

@ 6¾

Pampa

US$293m

@ 9⅛


As of the date hereof, Pampa holds in treasury US$13.5 million FV of its 2023 CBs, US$63.0 million

FV of its 2027 CBs and US$7.3 million FV of its 2029 CBs, whereas Edenor holds in treasury US$39.3 million FV of its 2022 CBs, and Transener, US$7.0 million FV of its 2021 CBs31.

Issuance of Pampa’s Series 3 CBs

On July 2, 2019, the Company placed Series 3 CBs, denominated in US$ at fixed rate, for a face value of US$300 million, after having received offers of purchase for more than US$1.3 billion, more than 4 times compared to the face value to be issued. The issuance price was 98.449% of the face value, at a

fixed nominal annual interest rate of 9⅛ percent, yielding 9⅜ percent and maturing in April 2029. Proceeds would allow the Company to boost its liquidity position and foster the growth of our power generation business, aiming investments on technological enhancements and renewable energies, as well as moving forward in the development of Vaca Muerta’s potential.

Redemption of CTLL’s Series 4 CBs

On July 12, 2019, Pampa fully redeemed outstanding Series 4 CBs originally issued by CTLL, a

company merged with Pampa, and originally maturing in October 2020, for a total amount of US$33.9 million including interest.

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 ‘B1’ to ‘Caa1’. 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 Transener’s 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. Credit ratings for Pampa Group’s CBs are detailed below:

31 For further information, see section 7.7: ‘Buyback of Own Financial Securities’ of this Annual Report.


Global Local

S&P B- na

Moody's Caa1 na

FitchRatings CCC+ AA-

S&P CCC+ raBB-

Moody's Caa1 Baa3.ar

S&P B- na

Moody's Caa1 Baa3.ar

Transener S&P B- raBBB+

TGS

Company AgencyRating

Pampa

Edenor

7.9 Other Relevant Events

Closing of the Sale of Dock Sud

Under the sale of the Dock Sud storage facility agreed on March 6, 2019, on March 30, 2019 the facility was transferred to Raízen Argentina, a licensee of the Shell brand, at a price of US$19.5 million and US$2.0 million on account of products. As of December 31, 2019, the transaction resulted in a profit before income tax of AR$45 million.

Pampa’s Compensation Plan

In March 2019 and January 2020, a total of 290,363 and 163,466 common shares, respectively, were granted to employees benefitted by the stock compensation plan for the Company’s key staff approved by the Board on February 10, 2017. The Company currently holds 4.9 million common shares in treasury, representing 0.3% of the issued capital stock32, available to fund such plan.

Corporate Reorganization

On August 30, 2019, the Boards of Directors of Pampa and PEFM approved the merger between Pampa, as absorbing company, and PEFM, a company fully directly and indirectly owned by Pampa, effective as from July 1, 2019. This merger was approved by Pampa’s Extraordinary General Shareholders’ Meeting held on October 15, 2019. On February 19, 2020, the CNV granted the administrative consent to the merger, which is currently in the process of registration before the IGJ.

Moreover, on October 8, 2019, the Board of the Company instructed to move forward with the

procedures aiming to assess the benefits of a merger through absorption between Pampa, as absorbing company, and CPB, a company fully controlled by Pampa, effective as from January 1, 2020.

IFRS: Financial information

As from January 1, 2019, Pampa changed its functional currency from AR$ to US$ and, therefore, it records its transactions in US$, mainly considering the following factors which have affected the entity’s business and its sales prices:

The divestment of the refining and distribution segment in 2018, with prices mainly denominated in AR$;

32 It does not include 151,997,025 common shares/6,079,881 ADRs held in treasury, in cancellation process.


The growing trend of US$-nominated contracts, in line with the strategy of focusing investments

and resources on the expansion of installed capacity in power generation segment; and

The maintenance of remuneration scheme for generation during 2019 with US$-nominated prices.

After the closing of 2019, SE Res. No. 31/20 modified the remuneration scheme for legacy capacity set forth by SRRYME Res. No. 1/19 as from the commercial transaction corresponding to February 1, 2020. It is worth highlighting that, even though this change affects the profitability of the power generation business, it does not constitute a modification of the underlying conditions for Pampa’s main economic environment due to: (i) the higher incidence in 2019 of revenues from US$-nominated PPAs compared to

legacy capacity’s sales revenues as a result of the commissioning of PEPE II and III in May 2019, which will increase in 2020 with the entry into force of the PPA remunerating CTGEBA’s closing to CC for 383 MW; and (ii) the fact that the US$ remains the basis for setting sales prices and costs in the segments of oil and gas, and petrochemicals.

Tax Reform

Optional Tax Revaluation

Based on an assessment of the domestic context and the evolution of financial variables (including the inflation rate), on March 27, 2019, Pampa and CPB exercised their option to adhere to the tax revaluation regime on property, plant and equipment existing as of December 31, 2017 pursuant to Law No. 27,430, increasing the tax cost of such goods to AR$15,311 million. Consequently, Pampa and CPB paid the special tax for a principal amount of AR$1,495 million, plus interest for AR$45 million, under a 5 monthly installments’ plan.

Additionally, Pampa and CPB had to waive all claims filed before the adoption of such measure, as well as their rights to initiate any claim seeking the application of such mechanism to fiscal years ended before December 31, 2017.

Tax Inflation Adjustment

Law No. 27,430 provides for a cost adjustment for goods acquired or investments made during fiscal years beginning in 2018, taking into consideration the CPI variations. Furthermore, this Law provides

for the application of the tax inflation adjustment set forth by the Income Tax Law for the first, second and third fiscal year as from 2018 in case the CPI cumulative variation, calculated from the beginning to the end of each fiscal year, exceeds 55%, 30% and 15% for fiscal years 2018, 2019 and 2020, respectively.

Besides, the Solidarity Law, effective as from December 23, 2019, provides that, as regards the positive or negative inflation adjustment to be determined as a result of the application of the comprehensive adjustment provided for by Part VI of the Income Tax Law corresponding to the first and

second fiscal year starting as from January 1, 2019, 1/6 should be charged in that fiscal period and the remaining 5/6s, in equal parts, in the five immediately subsequent fiscal periods.

As of the closing of fiscal year 2018, the CPI cumulative variation did not exceed 55%; however, the cost of goods acquired in 2018 were updated. As of the closing of fiscal year 2019, the CPI cumulative

variation exceeded 30% and, therefore, certain companies of the Group have applied the tax inflation adjustment in the calculation of the current and deferred income tax provision, except for Pampa and its subsidiary PEFM, which, taking into consideration the merger process, have not exceeded the established

legal parameter for the interim six-month period ended on June 30, 2019.


Appointment of Board and Audit Committee Members at Pampa

On April 29, 2019, Pampa’s Ordinary and Extraordinary Shareholders’ Meeting approved the renewal of the terms of office of Gabriel Cohen as non-independent director, Pablo Díaz, Mariano Batistella and Nicolás Mindlin as non-independent alternate directors, and Santiago Alberdi as independent director. Moreover, it approved the appointment of Carolina Sigwald, which previously served as Pampa’s alternate director, as non-independent director, Carlos Correa Urquiza and Darío Epstein as independent directors to replace Diana Mondino and Carlos Tovagliari, Horacio Turri and Gerardo Paz as non-independent alternate

directors, and Silvana Wasersztrom and Catalina Lappas as independent alternate directors.

Moreover, the Audit Committee was made up of Miguel Bein as chairman, Carlos Correa Urquiza and Darío Epstein as members, and Silvana Wasersztrom as alternate member.

Besides, in December 2019 the Company was informed of Ms. Catalina Lappas’ resignation to her

position as independent alternate director, which became effective as from its acceptance by the Board.


8. Description of Our Assets

As of December 31, 2019, Pampa and its subsidiaries participate in the electricity and gas value

chains:

Note: segments correspond to business classifications in the FS. Transener, TGS and Refinor are co-controlled companies, which under

IFRS are not consolidated in Pampa’s FS. 1 It includes 383 MW at CTGEBA, 280 MW at CTEB (co-controlled) and 15 MW at CTLL. 2 It

includes PEMC (co-controlled). 3 2019 average production of blocks in Argentina.

Our power generation segment operates an installed capacity of 4,751 MW, which represents 12% of Argentina’s installed capacity. By adding next 471 MW expansions, our total installed capacity would amount to 5,222 MW.

Edenor is in our electricity distribution segment, the largest electricity distributor in the country, with a concession serving 3.1 million customers, covering North and Northwest Buenos Aires metro area.

Our oil and gas segment comprises both operated and non-operated blocks at Pampa Energía’s stake. In 2019, the total average production in Argentina amounted to 48.2 kboe/day, with operations in

12 productive blocks and 885 productive wells.

In the petrochemicals segment, Pampa owns three high-complexity plants producing styrene, SBR and polystyrene, with a domestic market share ranging between 89% and 100%.

Finally, our holding and others segment is mainly made up by our 27.2% interest in TGS, the country’s largest gas transportation company, owning a 9,231 km-long gas pipelines and a NGL plant, General Cerri, with production capacity of 1 million tons/year. Moreover, Transener, in which we have a 26.3% indirect interest, operates and maintains 85% of the Argentine high voltage transmission grid

covering 21 thousand km of lines. Besides, our assets include Refinor, a company in which we have a 28.5% direct interest, which has a refinery with an installed capacity of 25.8 kb of oil per day and 90 GSs.


Corporate Structure as of December 31, 2019


8.1 Power Generation33

The following tables summarizes the 15 power generation assets operated by Pampa:

HINISA HIDISA HPPL PEMC 1 PEPE22 PEPE32

Installed Capacity (MW) 265 388 285 100 53 53 1,144

New Capacity (MW) - - - 100 53 53 206

Market Share 0.7% 1.0% 0.7% 0.3% 0.1% 0.1% 2.9%

Fiscal Year

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 - - 2,102

Variation 2019 vs. 2018 -14% -15% -7% +55% na na +10%

Sales 2018 (GWh) 577 393 886 247 - - 2,102

Avg. Price 2019 (US$/MWh) 38 58 23 69 62 65 44

Avg. Price 2018 (US$/MWh) 31 46 22 80 na na 36

Avg. Gross Margin 2019 (US$/MWh) 23 42 15 59 53 55 33

Avg. Gross Margin 2019 (US$/MWh) 20 32 15 71 na na 26

Summary of

Electricity Generation Assets

Hydroelectric Subtotal

Hydro

+Wind

Wind

CTLL CTG CTP CPB CTPP CTIW CTGEBA1 Eco-

EnergíaCTEB2 Subtotal

Installed Capacity (MW) 765 361 30 620 100 100 1,050 14 567 3,607 4,751

New Capacity (MW) 364 100 30 - 100 100 178 14 567 1,453 1,659

Market Share 1.9% 0.9% 0.1% 1.6% 0.3% 0.3% 2.6% 0.04% 1.4% 9.1% 12.0%

Fiscal Year

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% 11.9%

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

Variation 2019 vs. 2018 +7% -55% -61% +47% -13% +14% +14% -3% na +4% +5%

Sales 2018 (GWh) 4,748 2,227 134 753 192 274 5,457 110 - 13,897 15,999

Avg. Price 2019 (US$/MWh) 55 45 113 62 na 107 46 47 na 61 58

Avg. Price 2018 (US$/MWh) 43 35 59 88 na 107 36 57 na 45 44

Avg. Gross Margin 2019 (US$/MWh) 31 29 na 23 na 80 17 7 na 33 33

Avg. Gross Margin 2019 (US$/MWh) 37 20 na 46 na 85 18 15 na 30 29

Summary of

Electricity Generation AssetsTotal

Thermal

Note: Gross Margin before depreciation and amortization, values expressed in nominal terms. AR$/US$ FX: 2019 – 48.23; 2018 – 28.13.



The following chart shows Pampa’s market share in the power generation segment:

2019 Net Power Generation 100% = 131,247 GWh

CEPU

11.3%

ENEL

9.9%

AES

8.1%

YPF

5%

Others

25%

Bi-National

Hydros16%

FONINVEMEM

6%

Nuclear

6.0%

IEASA

0.4% Pampa Energía

11.9%

%

Note: Hydroelectric power generation net of pumping. Source: CAMMESA.

Hydroelectric Generation

Located on the Atuel river, in the Province of Mendoza, since June 1994 HINISA has a 30-year

concession for the generation, sale and marketing of electricity from the Los Nihuiles hydroelectric system. HINISA has an installed capacity of 265 MW, which represents 0.7% of Argentina’s installed capacity, and consists of three dams and three hydroelectric power generation plants (Nihuil I, Nihuil II and Nihuil III), as well as a compensator dam. Los Nihuiles System extends for a total distance of approximately 40 km with a height differential between 440 m and 480 m. From 1990 to 2019, its annual average generation was 818 GWh, with a record high of 1,250 GWh in 2006 and a record low of 498 GWh in 2019. Pampa has

a 52% direct and indirect stake in HINISA’s capital stock.

Also, in the Province of Mendoza, but on the Diamante river, HIDISA holds a 30-year concession, effective since October 1994, for the generation, sale and marketing of electricity from the Diamante hydroelectric system. With an installed capacity of 388 MW, which represents 1% of Argentina’s installed capacity, it consists of three dams and three hydroelectric power generation plants (Agua del Toro, Los Reyunos, and El Tigre). The Diamante System extends for a total distance of approximately 55 km, with a height differential between 873 m and 1,338 m. From 1990 to 2019, its annual average generation was

553 GWh, with a generation record high of 943 GWh in 2006 and a record low of 322 GWh in 2014. Pampa holds a 61% direct and indirect stake on HIDISA’s capital stock.

The HPPL plant started operating in the year 1999 under a 30-year concession. Located on the Limay River, in the Province of Neuquén, it has an installed capacity of 285 MW distributed in 3 Kaplan type turbines, which represents 0.7% of Argentina’s installed capacity. The dam is made up of loose materials with a waterproof concrete side. It has a total length of 1,045 meters, a total height of 54 m at the deepest point of the foundation, and a crest at 480.2 meters above sea level. From 2000 to 2019,

HPPL’s historical 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. HPPL’s concession is 100% owned by Pampa.


Wind Power Generation

PEMC is located on provincial route No. 51, 18 km from the City of Bahía Blanca, Province of Buenos Aires. The wind farm is made up of 29 V-126 Vestas wind turbines, each with a 3.45 MW power capacity and an 87-meter hub height. PEMC’s total installed capacity amounts to 100 MW, which represents 0.3% of Argentina’s installed capacity. It was commissioned for service on June 8, 2018, selling its energy to

CAMMESA under the RenovAr program. In 2019, PEMC generated 383 GWh, which represents an approximate 45% dispatch factor. Even though Pampa is the operator, the Company has a 50% direct interest in the capital stock of Greenwind, a company which only asset is PEMC.

PEPE II is located next to PEMC, it is made up of 14 V-136 Vestas wind turbines, each with a 3.8 MW power capacity and a 120-meter hub height. PEPE II’s total installed capacity amounts to 53 MW, which represents 0.1% of Argentina’s installed capacity. It was commissioned on May 10, 2019, selling its energy in the MAT ER. From its commissioning and during 2019, PEPE II generated 122 GWh, which represents an

approximate 40% dispatch factor.

Finally, PEPE II’s twin wind farm, PEPE III is in Coronel Rosales, on national route No. 3, 45 km from the City of Bahía Blanca, Province of Buenos Aires. It was also commissioned on May 10, 2019, selling its energy in the MAT ER. Since its commissioning and during 2019, PEPE III generated 148 GWh, which represents an approximate 50% dispatch factor. Both PEPE II and PEPE III are assets fully owned by Pampa.

Thermal Generation

CTG is in Northwestern Argentina, in the City of Gral. Güemes, Province of Salta. Privatized in 1992, it has a 261 MW open cycle thermal power generation plant, and with the addition in September 2008 of a GE natural gas-fired turbo generator unit of 100 MW, totaling 361 MW, 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.

Also, in the north of the Province of Salta is located CTP, in the small village of Piquirenda,

Municipality of Aguaray, Department of General San Martín. Its construction started in early 2008 and finished in 2010; it has 30 MW consisting of ten GE Jenbacher JGS 620 gas-fired engines, which represent 0.1% of Argentina’s installed capacity. From 2011 to 2019, the average annual generation was 121 GWh, with a record high of 156 GWh registered in 2017 and a record low of 53 GWh in 2019.

In the south of the Province of Neuquén, CTLL is located at Loma de la Lata. The plant was built in 1994 and consists of three GTs with an installed capacity of 375 MW, a 180 MW Siemens ST installed in 2011 for its closing to CC and repowered in January 2018, a 105 MW GE aeroderivative GT installed in May

2016, and the incorporation in August 2017 of a 105 MW GE GT, its total capacity thus amounting to 765 MW, which represents 1.9% of Argentina’s installed capacity. 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, the average annual generation was 1,993 GWh, with a record high of 5,096 GWh registered in 2019 and a record low of 272 GWh registered in 2002.

Pampa operates six CTs in the Province of Buenos Aires. Three of them are placed in the vicinity of

the City of Bahía Blanca: CPB, in the port of Ingeniero White, consists of 2 STs with a 310 MW capacity each, totaling 620 MW, which represents 1.6% of Argentina’s installed capacity. The boilers can be

indistinctly fed with FO or natural gas, which is supplied through a proprietary 22 km gas pipeline operated and maintained by CPB and connecting with TGS’s main gas pipeline system. Furthermore, CPB has two tanks for the storage of FO with a combined capacity of 60,000 m3. From 1997 to 2019, its average annual generation was 2,048 GWh, with a generation record high of 3,434 GWh in 2011, and a record low of 189 GWh in 2002.

Located in a lot adjacent to CPB, CTIW consists of 6 dual-fuel (natural gas or FO) Wärtsilä engines, with a total 100 MW installed power capacity, which represents 0.3% of Argentine installed capacity. The engines are high-efficiency, with a 46% performance rate. The plant is interconnected to the 132 kV grid through a substation of Transba. Liquid fuel is supplied using CPB’s unloading and storage facilities, and


natural gas is also provided from CPB’s internal facilities. The power plant was commissioned on December 22, 2017, and from 2018 to 2019 its average annual generation amounted to 293 GWh.

Moreover, EcoEnergía, located in the outskirts of the City of Bahía Blanca, is a co-generation power plant located inside TGS’s General Cerri Complex. The plant, consisting of a 14 MW ST, was commissioned in 2011. The plant sells electricity in the Energía Plus market. From 2011 to 2019, EcoEnergía’s historical 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.

Other two CTs in the Province of Buenos Aires are located in Greater Buenos Aires: CTGEBA, in the district of Marcos Paz, in Western Greater Buenos Aires, has a strategic location since it is just one kilometer from the Ezeiza transforming station, a WEM reference node for the supply of electricity to the country’s highest demand zone. The plant began operating in 1999 and has a CC with a 674 MW installed capacity, which consists of two GTs of 219 MW each and a 236 MW ST. On the same lot, there is a GT with

a 169 MW power capacity known as Genelba Plus, which was repowered by 19 MW in June 2019, as well as a 188 MW GT incorporated in June 2019 under the expansion to CC process. CTGEBA’s CC is sold in the spot market, whereas Genelba Plus’ GT energy is sold under Energía Plus, and the new GT incorporated in 2019 is sold in the spot market until the commissioning of the CC, when it will start to be sold under a PPA. Currently, the total installed capacity of the CTGEBA complex amounts to 1,050 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.

Furthermore, CTPP is in Northern Greater Buenos Aires, in the Pilar Industrial Complex, district of Pilar. Construction began in October 2016 pursuant to SEE Res. No. 21/16, and the plant was commissioned on August 29, 2017. The plant is made up of 6 Wärtsilä engines with an approximate 43% efficiency, has a total 100 MW capacity, and may indistinctly consume FO stored in own tanks or natural gas supplied through a dedicated gas pipeline which is connected with TGN’s main gas pipeline, whereas the energy is evacuated through a 132 kV line connected to the Pilar substation owned by Edenor. Its historical average annual generation from 2018 to 2019 was 180 GWh.

Finally, CTEB is the sixth CT in the Province of Buenos Aires, located in Ensenada city, Greater La

Plata. Currently is composed by two Siemens GTs commissioned in 2012, with a total power capacity of 567 MW, representing 1.4% of Argentina’s capacity. This CT may consume natural gas or GO, and, therefore, has two storage tanks with a combined capacity of 45,000 m3, and also has a port for the unloading of GO under construction at Isla Santiago, on the river of the same name, with a 20,000 m3 storage capacity in two tanks. Moreover, the closing to CC is expected with the incorporation of a 280 MW Siemens ST. From 2012 to 2019, CTEB’s historical average annual generation amounted to 1,461 GWh,

with a generation record high of 2,093 GWh in 2016, and a record low of 564 GWh in 2019. Pampa operates CTEB until July 2023 and has a 50% indirect equity interest of CTBSA, a company which only asset is CTEB.

Current Expansions

Project MW Equipment Supplier

Marketing

Awarded Price Invest-ment in

US$ million1

Date of Commi-ssioning

Power Capacity US$/MW-

month

Variable US$/MWh

Total US$/MWh

Thermal

CTLL 15 MAN SE Res.

No. 31/20 4,500-6,0002 5.4 13 20 Q2 2020

CTGEBA3 176 Siemens 15-Year contract

in US$ 20,500 6 34 350 CC: Q2 2020

CTEB4 280 Siemens 10-Year contract

in US$ 23,962 10.5 43 200 CC: Q4 2022

Total 471 390

Note: 1 Amounts do not include VAT. 2 Initial FX of AR$60/US$, weighted by the load factor coefficient. It does not consider the HMRT additional remuneration 3 Total expansion of 383 MW, of which 207 MW were commissioned in June 2019. 4 Pampa holds a 50% interest.


ENECOR

Pampa holds a 70% interest in Enecor, an independent power transportation company under a 95-year concession which is due to expire in 2088. Enecor subcontracts Transener, which operates and maintains 21 km of 132 kV double-triad electricity lines from the Paso de la Patria transforming station, in the Province of Corrientes.

8.2 Electricity Distribution34

Edenor is the largest electricity distribution company in the country in terms of number of customers and electricity sold (in GWh as well as in monetary terms). It holds a concession until 2087 to distribute electricity on an exclusivity basis in Northwestern Greater Buenos Aires and the Northern City of Buenos Aires, which covers an area of 4,637 km2 and a population of approximately 8.5 million inhabitants.

The following table summarizes Edenor’s electricity sales and customers:

In GWh Part. % Clients In GWh Part. % Clients % GWh % Clients

Fiscal Year

Residential1 8,372 42% 2,758,162 8,948 42% 2,677,554 -6% +3%

Commercial 3,241 16% 353,113 3,478 16% 354,799 -7% -0%

Industrial 3,503 18% 6,830 3,646 17% 6,857 -4% -0%

Wheeling System 3,569 18% 684 3,823 18% 699 -7% -2%

Others

Public Lighting 713 4% 21 724 3% 21 -1% -

Shantytowns and Others 575 3% 469 553 3% 456 +4% +3%

Total 19,974 100% 3,119,279 21,172 100% 3,040,386 -6% +3%

VariationEdenor's Sales

by Type of Customer

2019 2018

Note: 1 Including 561,915 and 586,222 customers covered by the Social Tariff as of December 31, 2019 and 2018, respectively.

The following chart shows Edenor’s market share:

2019 Total Electricity Distribution 100% = 105,321 GWh

Edenor

19%

Others

81% %

Source: CAMMESA and ADEERA.



The following table summarizes Edenor’s main technical and financial indicators:

2018 2019

Technical Information

Transmission and distribution lines (Km) 39,699 40,488

Number of clients (million) 3.0 3.1

Electricity sales (GWh) 21,172 19,974

Financial Information*

Revenue from services 86,040 89,944

Fiscal year’s results, attributable to company’s shareholders 6,608 12,134

Assets 118,388 119,473

Liabilities 70,767 60,322

Shareholders’ equity 47,621 59,151

Note: *Annual FS figures under IFRS, in million AR$, adjusted by inflation as of December 31, 2019.

Energy Demand

Edenor’s energy demand in 2019 reached 24,960 GWh, which represents a 3.7% decrease compared to 2018, in line with the drop in the total WEM demand, which also decreased by 3% to 128,880 GWh. However, in 2019 Edenor’s maximum power capacity reached 5,124 MW, similar to the 5,151 MW recorded in 2018, whereas the WEM’s maximum capacity amounted to 26,113 MW in 2019, compared to 26,320 MW in 2018.

The volume of electricity distributed in 2019 across Edenor’s area, including the sale of energy and

the wheeling system, totaled 19,974 GWh. Energy purchased to meet such demand amounted to 24,960 GWh, which represents a 3.7% decrease compared to 2018. Edenor purchased all the energy in the market at an average annual monomic price of AR$2,117/MWh, equivalent to US$43.9/MWh at the average FX, which represents a 6% increase in US$ on account of the update, as from August 2018 and pursuant to several provisions and Res., of the prices payable by the demand that distribution companies pay to CAMMESA.


Evolution of Peak Power Capacity 2000 – 2019, in MW

5,124

0

5,000

10,000

15,000

20,000

25,000

30,000

0

1,000

2,000

3,000

4,000

5,000

6,000

'00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Argentine Grid Edenor

Edenor Argentine Grid26,320

Source: Edenor.

Commercial Management

The sale of electricity evidenced a year-on-year 5.7% decrease in 2019 mainly as a result of higher average temperatures compared to the previous year, the impact of the economic recession and the price elasticity of demand due to the tariff increase. The residential demand, which plays a key role in the total volume of the demand behavior (42%), experienced a 6.4% decrease compared to 2018. The commercial

segment demand, which represents 16% of the total demand, decreased by 6.8%, whereas the large demands, T3 and Wheeling System, which represent a 35% share, recorded a 5.3% decrease compared

to 2018.

Energy Losses

The rolling annual rate for total (technical and non-technical) energy losses reached 19.9% in 2019, experiencing an increase compared to 2018 (18.2%). Technical losses are those which are a necessary consequence of electric power transmission and distribution, whereas non-technical losses are attributable to errors in customers’ consumption metering, whether on account of theft, defective installation or

metering flaws.

During the winter season, in poor homes with no natural gas network access, energy consuming home-made devices continue to be used for room and water heating purposes. The massive and simultaneous use of such devices during the winter season has generated a substantial grid power demand. Electricity theft in poor neighborhoods was the most influential factor in non-technical losses, added to the

deterioration of the economic context.

In 2019, the plan launched in previous years with the purpose of putting back to normal clandestine,

inactive and chronically delinquent customers continued to be implemented, with a substantial increase in the installation of MIDE (Energy Integrated Meter) self-managed meters. In 2019, 75,160 MIDEs were installed, 57,000 of which are already activated and, as of the closing of the fiscal year, the cumulative number amounts to 199,728 MIDEs.


Additionally, the installation of the new type of MULCON (Multiple Concentric) grid continued; developed in 2018, it leverages the MIDE meters functionality, enhancing invulnerability to electricity theft and, based on the good results obtained, it is being implemented in neighborhoods with high fraud level.

Moreover, the company continued working on the development of analytical and artificial intelligence tools to enhance effectiveness in the routing of inspections aiming to reduce electricity theft. In this same line, approximately 485,000 tariff 1 meter inspections were carried out, with a 52% efficiency.

Regarding the recovery of energy, besides the customers put back to normal with MIDE, clandestine customers were recovered by installing conventional meters. The evolution of the annual rates for energy losses since the beginning of Edenor’s concession is shown below:

Energy Losses: Annual Rolling Rate (%) 1992 – 2019

19.90

0

5

10

15

20

25

30

'92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

%

Source: Edenor.

It is worth highlighting that the rolling annual energy losses rate grew due to an absolute factor, losses in GWh, and to a relative factor, caused by the sharp decrease in Large Customers’ bills, where fraud is minimal.

Service Quality Management

In March 2019 the fifth semester of the RTI 2017 – 2021 five-year period started, which is governed by the new sub-annex IV to the Concession Agreement established by the RTI. Besides setting district and commune-based service quality controls, a quality improvement path with increasing requirements is implemented, both regarding frequency limits and admissible times, and the cost of non-delivered energy. Additionally, an automatic penalty scheme was established so that bonuses on account of deviations from

the established limits should be credited to customers within a term of 60 days as from the end of the

controlled semester. The values of final penalties require the ENRE to render judgment regarding the information submitted for each semester.

Pursuant to Res. No. 198/18, the ENRE provided for 300 or 600 kWh supplementary penalties per user based on the Feeder’s Semiannual Path Factor (FSSA) and the User’s Semiannual Path Factor (FSSU) as from the fourth semester of the 2017 - 2021 RTI five-year period starting in September 2018. Applicable penalties should be calculated and informed to the ENRE within a term of 120 calendar days as from the

end of the control semester and deposited in a third-party escrow account.


The average frequency and the total interruption times during the last five years are detailed below:

Checked by Client* 2015 2016 2017 2018 2019

SAIFI (frequency) 8.93 8.67 9.02 6.94 6.15

SAIDI (hours) 26.63 25.84 27.55 22.65 15.94

Note: *Rolling annual rate as of December of each year.

Even though the investments in distribution grids’ effect is evidenced by the decrease in the SAIFI frequency indicator, the maturity of these investments and the grid’s operation and maintenance have accompanied them with a clear improvement in the SAIDI total time indicator.

Investments

Investments made in 2019 amounted to AR$8,624 million in nominal currency and AR$9,919

million in constant currency as of December 31, 2019, prioritizing their execution on top of other expenses as a way to preserve the safety of the utility under concession. In order to meet the demand, improve the service quality and reduce non-technical losses, most investments were allocated to increasing the power capacity, installing equipment with remote control in the medium-voltage grid, connect new supplies and install new energy meters compatible with prepaid sales. Furthermore, Edenor continued making investments to preserve the environment and safety on the streets.

In comparative terms, there was a significant increase in investments in the last few years, with

an annual AR$1,013 million nominal increase in 2019. The following chart illustrates its annual distribution:

Edenor’s Annual Investments 1992 – 2019

8,624

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

'92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

AR$ Million

Note: Figures in nominal terms. Source: Edenor.


8.3 Oil and Gas35

Pampa is one of the leading hydrocarbon E&P companies in Argentina, with presence in the country’s major oil basins, from which it obtains natural gas and oil. In 2019, investments in this segment amounted to US$191 million, which represents a 17% decrease compared to 201836. The following table

summarizes the E&P’s main technical indicators:

2018 2019

Technical Information*

Number of productive wells in Argentina 892 885

Average gas production in Argentina (thousand m3/day) 6,753 7,344

Average oil production in Argentina (thousand bbl/day) 5.1 5.0

Average total production in Argentina (thousand bbl/day) 44.8 48.2

Note: *2018 considers continuing operations.

The following table summarizes Pampa’s blocks:

Oil kbbl Gas dam3 Total kboe

1 El Mangrullo 0.1 4,161 24.6 100% Neuquina 100.00% Pampa 2053

2 Sierra Chata 0.1 562 3.4 98% Neuquina 45.55% Pampa 2053

3 Río Neuquén 0.6 1,186 7.6 92% Neuquina31.42%

1

33.07%2

YPF2027

2051

4 Rincón del Mangrullo3 0.1 1,163 7.0 98% Neuquina 50.00% YPF 2052

5 Anticlinal Campamento - 9 0.1 100% Neuquina 15%4 Oilstone Energía 2026

6 Estación Fernández Oro 0.0 12 0.1 95% Neuquina 15%5 YPF 2026

7 Rio Limay Este (Ex Senillosa) - - - na Neuquina 85.00% Pampa 2040

8 Veta Escondida - Rincón de Aranda 0.0 - 0.0 0% Neuquina 55.00% Pampa 2027

9 Gobernador Ayala 0.8 - 0.8 0% Neuquina 22.51% Pluspetrol 2036

10 Aguaragüe6 0.2 196 1.4 85% Noroeste 15.00% Tecpetrol 2023/2027

11 La Tapera - Puesto Quiroga - 42 0.2 100% Golfo San Jorge 35.67% Tecpetrol 2027

12 El Tordillo 2.9 - 2.9 0% Golfo San Jorge 35.67% Tecpetrol 2027

4.8 7,330 48.0 90%

1 Parva Negra Este7 - 14 0.1 100% Neuquina 42.50% Pampa 2019

2 Las Tacanas Norte n.a. n.a. n.a. n.a. Neuquina 90.00% Pampa 2023

3 Río Atuel n.a. n.a. n.a. n.a. Neuquina 33.33% Petrolera El Trebol 2020

4 Chirete8 0.2 - 0.2 0% Noroeste 50.00% High Luck Group 2019

5 Borde del Limay9 n.a. n.a. n.a. n.a. Neuquina 85.00% Pampa 2015

6 Los Vértices9 n.a. n.a. n.a. n.a. Neuquina 85.00% Pampa 2015

0.2 14 0.2 32%

5.0 7,344 48.2 90%

Basin Stake

Total Exploratory Blocks

Total Production in Argentina

Operator

License

expiration

year

Total Productive Blocks

Block2019 average daily production

% Gas

Note: Production at our ownership. 1 Province of Río Negro. 2 Province of Neuquén. 3 It does not include Vaca Muerta formation. 4 Over

9 wells. 5 Over 13 wells. 6 It includes San Antonio Sur, expiring in 2023, and Aguaragüe, expiring in 2027. 7 Under process of approval

for a 3-year extension. 8 Under process of approval for a 3-year extension, except for Los Blancos lot, for which an exploitation concession

has been applied. 9 Under transfer process to GyP (exploration permit holder).

35 For further information, see sections 6.1 and 7.4 of this Annual Report. 36 It considers 2018 investments in AR$ and in nominal terms, expressed in US$ at an average FX of AR$28.13/US$.


Production

In 2019, the E&P segment’s production levels reached 48.2 kboe per day, 90% corresponding to gas production and 10% to oil production. The monthly evolution of the E&P segment’s production is detailed below:

E&P Segment’s Production* In kboe/day

40.0 42.1 42.3 41.645.0 44.5 44.7 44.9 45.4 43.6 42.5 42.0

4.86.1 5.3 5.0

4.9 4.6 4.8 4.7 5.04.7 4.8 5.4

44.848.2 47.6 46.6

49.9 49.1 49.4 49.6 50.448.3 47.3 47.4

Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19

Gas Crude oil

Source: Pampa.

With a greater focus on the Neuquina Basin, during 2019 Pampa’s investment plan involved the

drilling of 57 production and injection wells: 16 gas wells and 41 oil wells. Pampa focused its natural gas drilling activities specifically in El Mangrullo and Sierra Chata blocks; and its oil drilling activities in

Gobernador Ayala and El Tordillo blocks.

Gas production at our ownership was 8% higher than in 2018, mainly due to the 51% year-on-year increase in El Mangrullo block, which reached an average gas production of 4.2 million m3/day, with monthly increases from the 2.8 million m3/day recorded in 2018, and reaching its peak of 4.4 million m3/day in September 2019, mainly due to the increased drilling activity, the performance of the drilled tight gas wells, and the greater evacuation infrastructure. In total, 10 wells were drilled and 4 were completed. Out of the 10 drilled wells, 8 were for tight gas targeting Agrio and Mulichinco formations, and

2 were for shale gas targeting Vaca Muerta formation.

In Sierra Chata block, gas production reached 0.6 million m3/day in 2019 corresponding to our working interest, thus maintaining production levels of 2018. Four wells were drilled and 2 were completed. Out of the 4 drilled wells, 2 were for shale gas targeting Vaca Muerta formation.

Moreover, in Río Neuquén, the production at our working interest reached 1.2 million m3/day,

recording peaks of 1.4 million m3/day in February. Compared to 2018, Río Neuquén kept its average production level, even without new drillings, but with the completion of 3 wells.

The increase in gas production was partially offset by Rincón del Mangrullo, on account of natural decline and lower drilling rate, where production decreased by 36% in 2019, reaching 1.2 million m3/day. In 2019, an exploratory well was drilled targeting Lajas formation, and a development well was connected.

As regards oil blocks, in Gobernador Ayala 26 wells were drilled and completed, and oil production grew by 7% compared to 2018, with an annual average of 0.8 kb/day. In El Tordillo block, 12 wells were


drilled and completed, offsetting the field’s natural decline and reaching an average production of 3 kbbl/day in 2019, similar to the production level recorded in 2018.

Exploration activities

Pampa considers that exploration is the main vehicle for reserves replacement. In 2019, we continued exploring Vaca Muerta formation with the drilling of two horizontal wells in El Mangrullo block

targeting shale gas, both wells with a horizontal branch of approximately 2,500 meters. Furthermore, each well was completed with 35 fracking stages. During the trial stage, production levels in each of the wells reached approximately 400 dam3/day.

Furthermore, in the last quarter of 2019, the first vertical pilot well in Sierra Chata block was drilled with a 2,500-meter horizontal branch, also targeting shale gas in Vaca Muerta formation. The well is

expected to be completed in 2020.

In the Chirete block, considering the discovery of oil, after concluding the discovery well’s initial

trial period in the first quarter of 2019 and the building of the applicable facilities, the well was put into production, with an average flow of 333 barrels/day corresponding to Pampa’s working interest between November and December 2019. The well has reached its testing phase, with production levels of up to 944 barrels/day corresponding to our working interest.

Moreover, in 2019 the first vertical pilot well with its 2,000-meter horizontal branch was drilled in Rincón de Aranda block targeting shale gas in Vaca Muerta formation. The well was completed with 27

hydraulic fractures, and an initial production flow of 1,100 barrels/day. The well is currently in the trial period. In January 2020, the drilling of another horizontal well started, which is expected to be completed in 2020.

Additionally, exploratory activities were carried out in Rincón del Mangrullo and Río Atuel blocks, applications were submitted for the extension of exploration permits in Parva Negra Este, Chirete and Río Atuel blocks, and Enarsa 1 and 3 were relinquished.

Reserves

Pampa estimates its reserves at least once a year. Proven reserves are estimated by the Company’s geologists and reservoir engineers. Reserve engineering is a subjective process consisting of estimating underground accumulations of hydrocarbons that cannot be precisely measured; this process depends on the quality of the available information and on engineering and geological interpretation and judgment. Accordingly, reserves estimate, as well as future production profiles, are often different from the quantities of hydrocarbons that are ultimately recovered. The validity of estimates largely depends on the underlying

assumptions. Such reserves estimates were prepared according to the rules for the Modernization of Oil and Gas Reporting Presentation issued by the SEC.

Gaffney Cline & Associates, international technical consultants, carried out an independent assessment of our reserves, auditing 94% of Pampa’s estimated proven reserves, and concluded that oil and natural gas reserve volumes subject to their independent technical assessment are reasonable.

As of December 31, 2019, Pampa’s proven reserves amounted to 135 million boe, 4% higher

compared to the volumes recorded as of December 31, 2018. Taking into consideration production levels and the 2019 incorporations, the reserve-replacement ratio was 1.3 and the average life was approximately 8 years. Out of proven reserves as of the closing of fiscal year 2019, 90% corresponded to natural gas.


Proven Reserves (P1)

in Argentina

Oil,

in kb

Natural Gas,

in million cubic feet

Total,

in million boe% Gas

Proven Developed (P1-D) 8,805 372,000 71 88%

Proven Undeveloped (P1-U) 4,746 359,083 65 93%

Total as of December 31, 2019 13,551 731,082 135 90%

Total as of December, 2018 14,997 691,958 130 88%

Estimated reserves in Argentina are shown before deduction of royalty payments, since royalties have characteristics like taxes on production and, therefore, are treated as operating costs.

The composition and evolution of Pampa’s proven reserves as of December 31, 2019, both developed and undeveloped, is detailed below:

Pampa’s Total Proven Reserves As of December 31, 2019 100% = 135 million boe

Evolution of Pampa’s Certified

Proven Reserves In million boe

Hydrocarbon Transportation37

OldelVal

As of December 31, 2019, Pampa holds 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.

In 2019, oil transportation from Allen to Puerto Rosales reached 24,809 m3/day on average, and transportation to the refineries located in the Province of Neuquén totaled an average 2,355 m3/day. The total transported volume was 28,045 m3/day, equivalent to 64.4 million bbl transported in 2019,

representing a 16.2% increase compared to 2018.

37 For further information, see section 6.2 of this Annual Report.

Developed

52%

Undeveloped

48%

Liquids

10%

Natural Gas

90%Argentina

100%

%130

(17) +23

135

Stock @

Dec 31, 2018

(-) Production (+) Additions Stock @

Dec 31, 2019


In 2019, OldelVal managed to maintain uninterrupted transportation services, ensuring operational continuity and a reliable pumping system. Furthermore, planned objectives were achieved in terms of safety and investments.

8.4 Petrochemicals

The petrochemicals segment takes part in Pampa’s vertical integration with gas operations. The Company’s goal is to maintain its position in the styrene’s market by capitalizing on current conditions and maximizing the use of its own petrochemical raw materials. Our assets’ production covers a wide range of products, such as octane bases for gasoline, benzene, aromatic solvents, hexane and other hydrogenated paraffinic solvents, propellants for the cosmetic industry, monomer styrene, rubber, and polystyrene for the domestic and foreign markets.

The petrochemicals market where Pampa competes is influenced by the global supply and demand,

which has a strong impact on our results. Pampa is the only producer of monomer styrene, polystyrene and elastomers in Argentina, as well as the only integrated producer of goods ranging from oil and natural gas to plastics. As part of its efforts to integrate operations, it uses an important volume of its own benzene production to obtain styrene and, in turn, a substantial volume of styrene to manufacture polystyrene and SBR.

The petrochemicals division consists of the PGSM integrated petrochemical complex, in the Province

of Santa Fe, with an annual production capacity of 50 kton of gases (LPG, which is used as raw material, and propellant), 155 kton of aromatics, 290 kton of gasoline and refined products, 160 kton of styrene, 55 kton of SBR, 180 kton of ethyl benzene and 31 kton of ethylene. This segment also includes a polystyrene plant in Zárate, Province of Buenos Aires, with a production capacity of 65 kton. As a result of the falling demand and with the purpose of optimizing business results, the Company discontinued operations of the BOPS plant, with a production capacity of 14 kton, in April 2018, and of the San Lorenzo ethylene plant with 19 kton/year, in January 2019.

The following table shows the petrochemicals division’s main indicators for fiscal years ended December

31, 2018 and 2019:

2018

2019


Revenues (in kton):

Styrene (incl. propylene and ethylene) 64 55

SBR 26 27

Polystyrene (includes BOPS) 50 44

Others 213 217

Sales Destination*

Argentina 70% 70%

Abroad 30% 30%

Note: *Percentage calculated from sales in nominal terms.


Styrene’s Division

In 2019, the monomer styrene sales volume totaled 45 kton, a figure 9% lower than in 2018, with a 4% decrease in domestic sales and a 20% decrease in exports, associated with lower sales to Brazil. Propylene sales volumes reached 10 kton, 18% lower than in 2018, mainly associated with the lower styrene plant’s load. The polystyrene sales volume was 44 kton, experiencing a 13% decrease due to lower

domestic sales as a result of the economic recession, which was partially offset by a 46% increase in exports, mainly to Chile. Moreover, in 2019 Pampa sold a total of 27 kton of rubber, a figure 4% higher than in 2018, associated with an increase in domestic sales.

Gasoline Reforming Division

Sales of the Reforming division increased by 2% compared to 2018. In 2019, octane bases and

gasolines sales totaled 158 thousand ton, a volume 5% higher than in 2018, with a 14% increase in

domestic sales. Additionally, in 2019 15 kton of bases and gasolines were dispatched as toll processing, and therefore not recorded as sales volume. Hexane, paraffin solvents and aromatics sales volumes totaled 49 kton in 2019, which represent a 6% decrease compared to 2018, associated with lower exports. In 2019, propellant sales totaled 9 kton, experiencing a 21% increase associated with a higher presence in the domestic market. As of December 31, 2019, Pampa’s estimated share in the Argentine styrene, polystyrene and rubber markets amounted to 100%, 91% and 89%, respectively.

8.5 Other Businesses

Transener38

Transener is the leading company in the utility service of high voltage electric energy transmission in Argentina. It holds a concession over 14,489 kilometers of transmission lines and 57 transforming stations, and directly operates 85% of high-voltage lines in the country. In turn, its subsidiary Transba

holds a concession over 6,492 km of transmission lines and 104 transforming stations, which make up the Main Distribution Transmission System of the Province of Buenos Aires. The following table summarizes Transener’s most relevant technical and financial indicators:

2018 2019


Transener Transmission Lines (Km) 14,489 14,489

Transba Transmission Lines (Km) 6,455 6,492


Revenues 15,131 14,479


Assets 30,558 30,296


Shareholders’ Equity 17,773 17,019




Operation and Maintenance

The extra high voltage power transmission’s grid SADI, operated and maintained by Transener, is subject to significant load conditions year after year. However, the record-breaking demand for power capacity of 26,320 MW, registered on February 8, 2018, was not surpassed in 2019.

Despite the great number of power grid requests, in 2019 service quality has been wholly

acceptable for the values required from a company like Transener, which ended the year with a rate equal to 0.35 failures per each 100 kilometer-line, consistent with international parameters accepted for companies which operate and maintain extra high voltage transmission systems.

The following chart shows the failure rate for the service provided:

Failure Rate (Rate per each 100 km of lines)

2019

0.35

-

0.50

1.00

1.50

2.00

2.50

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Failute Limit: 2.50

Failure Transener

Source: Transener.

Investments

In 2019, Transener made investments in the amount of AR$2,755 million in nominal currency and AR$3,352 million in constant currency.


The following chart illustrates its annual distribution:

Transener’s Annual Investments In million AR$, 1999 - 2019

11 14 21 15 13 30 24 51 88 108 76 47 54 76217

393257

350

706

2,272

2,755

'99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Note: Figures in nominal terms. Source: Transener.

Business Development

Engineering Services –Works

Regarding power grid expansion works, Transener has focused its activity on the works in which it

has competitive advantages, prioritizing the works to be executed on the 500 kV and 132 kV systems.

The development of an important works program for the generation of renewable energies has entailed the demand for other services, such as the preparation of bidding documents, electricity studies, the implementation of power generation and demand monitoring systems (DAG and DAD systems), and the testing and commissioning of transforming stations. Transener’s technical team 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.

Power Transmission-Related Services

Operation, maintenance and other services, such as specific testing hired by private customers owning transmission facilities for both private and public use (independent transporters and international

transporters) have been provided since the creation of Transener.

Among the works performed by Transener, we can mention the replacement of bushings, the performance of oil analyses, diagnostic trials, OPGW repairs, FO connections in repeater junction boxes, the cleaning of isolators, measurements of electric and magnetic fields, automation implementation, maintenance of lines and equipment in transforming stations, among others.

All service agreements include provisions to maintain actual values for Transener’s remuneration; and most agreements have been uninterruptedly renewed since their commencement, which confirms the

quality of the service provided by Transener and the level of satisfaction of its customers.


Communications

In 2019, Transener continued providing infrastructure services to several communications companies, including the assignment of dark fiber optics to its own system (Line IV), and the rent of space in microwave stations and in their antenna-supporting structures. The growing demand from mobile communication companies has led to a significant increase in revenues both in terms of volume and better

prices involved, also offering internet services to wind farms. Moreover, Transener continued providing support services for operational communications and data transmission to WEM agents.

TGS39

TGS is the most important gas transportation company within the country, and it operates the largest pipeline system in Latin America. It is also a leading company in the production and

commercialization of NGL for both the domestic and the export markets, conducting this business from the

General Cerri Complex located in Bahía Blanca, Province of Buenos Aires. TGS also provides comprehensive solutions in the natural gas area and, since 1998, it has also landed in the telecommunications area through its controlled company Telcosur. As of December 31, 2019, Pampa holds a 27.2% interest in TGS.

The following table summarizes TGS’s main technical and financial indicators:

2018 2019


Gas transportation

Average firm capacity contracted (in million m3 per day) 81.7 82.6

Average delivery (in million m3 per day) 69.6 66.3

Production and commercialization of liquids

Total liquids production (in kton) 1,063.1 1,022.9

Gas processing capacity (in million m3 per day) 47.0 47.0

Storage capacity (in kton) 54.0 54.0


Revenues 52,399 48,561


Assets 95,288 95,601


Shareholders’ Equity 47,604 48,083


Description of Business Segments

Regulated Segment: Gas Transportation

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. Besides,



TGS provides an interruptible service, where the transportation of natural gas is subject to the gas pipeline’s available capacity. Moreover, TGS provides operation and maintenance services for assets allocated to the natural gas transportation service for the expansions fostered by the Federal Government and held under trusts created 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 constant terms as of December 31, 2019, annual revenues from this business segment amounted to AR$22,620 million in 2019, evidencing a 5% decrease compared to the AR$23,786 million recorded in 2018. This decrease is mainly due to the deferral of the semiannual update which should have been 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. These effects were partially offset by the full application of the tariff increase resulting from the RTI granted by

ENARGAS Res. 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.

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. Besides, 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.

In the commercial area, in 2019 TGS launched an open tender which allowed for the renewal of the total firm capacity of agreements maturing in 2020 and 2021 (12.7 million m3/day), achieving an average additional term of 12 years. Besides, in July 2019 a call for bids was launched for the construction and provision of a transportation service connecting Vaca Muerta formation with the Province of Buenos Aires. Out of the 35 years of the concession, a RET is contemplated for the first 17 years aiming to make the repayment of the construction feasible. TGS is currently analyzing its participation.

Non-Regulated Segment: Production and Commercialization of NGL

Unlike the gas transportation business, the production and commercialization of NGL 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 AR$23,138 million (in real terms, 10% lower than in 2018). The decrease in revenues from sales is mainly attributable to the fall in international reference prices, the decrease in dispatched ethane volumes as a result of the accident in Polisur facilities, 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 volume.

NGL production and commercialization activities are conducted at the Cerri Complex, located close to the City of Bahía Blanca, which is supplied by all TGS’s main gas pipelines. Ethane, propane, butane and natural gasoline are recovered at this complex. TGS sells NGL to both domestic and foreign markets. In the domestic market, propane and butane are sold to reseller companies. In the foreign market, the sale

of these products and natural gasoline is made at current international market prices. On the other hand, ethane is sold to Polisur at a price agreed by the parties. In 2019 the production of NGL amounted to 1,022,914 ton (4% lower than in 2018). It is worth highlighting 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 volume reached 1,040,393 ton, 38% of which were destined to exports. Out of the total sales to the domestic market, 75% were made at US$-denominated prices.


Sales of NGL by Destination Market In kton, 2015-2019

598 595 602710 642

339 316 359348 399

937 912961

1,058 1,040

2015 2016 2017 2018 2019Domestic Market Foreign Market

Source: TGS.

As regards 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 fall in international reference prices in the first semester of 2019, recovering as from August 2019.

Moreover, pursuant to PEN Executive Orders No. 793 and 865/18, as from September 2018 a duty was imposed on the export of NGL, among other products, with a maximum 12% rate, which was limited to up to 8% as from the entry into effect of the Solidarity 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 allow for an improvement in prices compared to the expired agreements, but will also bring short-term certainty for their sale. Furthermore, TGS makes inland transport exports via trucks to Chile, Paraguay and Brazil which, even at volumes lower than those exported by sea, allow TGS to capitalize on a higher operating margin.

As regards the domestic market, in 2019 TGS continued participating in the Household Gas Bottles’ Program and the Propane for Grids Agreement, which prices are regulated by a set of Res., 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. Moreover, as a result of the participation in these programs, the Federal Government must reimburse to TGS an economic compensation denominated in AR$, which is currently being collected with delays. Outside these programs, TGS sold 184,941 ton of propane and 14,736 ton of butane, mainly to the reseller market, and, to a lower extent, to the industrial, propellant and automotive market.

Moreover, in 2019 TGS continued selling ethane under the long-term agreement entered with Polisur in September 2018. This agreement stipulates commercial guidelines with improvements in the ToP clause, which guarantees TGS a gradual increase in sales volumes over the first 5 years of the contract. However, in fiscal year 2019 there was a significant decrease in the volume of ethane sold to Polisur, which reached 283,635 ton 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, sales returning to normal in October 2019.


NGL Foreign Market Sales Per product, in kton, 2015-2019

NGL Domestic Market Sales Per product, in kton, 2015-2019

142 137 144 147 165

90 81 94 81 115

10799

121 120

118

339 316

359 348

399

2015 2016 2017 2018 2019

Propane Butane Natural gasoline

278 277 283 397

284

173 176 177

157

212

147 141 142

156146

598 595 602

710 642

2015 2016 2017 2018 2019

Ethane Propane Butane Source: TGS.

Furthermore, in 2019, thanks to the works carried out at the Cerri Complex and at the Puerto

Galván facilities, TGS continued rendering logistic services at the Puerto Galván facilities, selling LPG by inland transport, dispatching approximately 13,781 trucks (311,885 tons) of own products, compared to the 12,353 trucks (279,040 tons) recorded in fiscal year 2018.

As regards US$-denominated prices for natural gas acquired as RTP for processing in the Cerri Complex, a 24% decrease was recorded compared to 2018, mainly due to the negative trend in market prices, in line with the reductions imposed by CAMMESA, its main purchaser, in gas reference prices for power plants as from August 2018.

Non-Regulated 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. These services may also include gas extraction and transportation in the fields, construction services, inspection and maintenance of compression plants and gas pipelines, as well as steam generation services to produce electricity. This

segment also includes revenues from telecommunication services provided through its subsidiary Telcosur.

This segment represented 6% of TGS’s total revenues in 2019, experiencing an 8% decrease in real terms compared to 2018, which is mainly accounted for by the mismatch between the inflation reflected in the restated financial information and the devaluation during the period over US$-denominated sales, 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 Vaca Muerta formation started 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 was key to its development. Additionally, in February 2020 TGS approved the expansion of the conditioning plant with an additional investment of US$15 million.

Moreover, 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, we 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. In 2019, we moved forward with this project to reach the final investment decision. We have also made progress on the pre-feasibility study for the construction of a new liquids processing plant in the town of Tratayén, which will allow for the enhancement and growth of the liquids business.


Refinor

Pampa has a 28.5% interest in Refinor, a company that owns the only refinery in the North of Argentina, located at Campo Durán, Province of Salta. The nominal processing capacity of the topping unit is 25.8 kbbl per day, whereas the two turboexpander plants’ nominal processing capacity reaches 20.3 million m3 of gas per day. Besides, Refinor operates a 1,108 km multiproduct pipeline extending from RCD (Salta) to Montecristo (Córdoba).

RCD receives condensed and crude oil from the Noroeste Basin in Argentina, and natural gas from

the Noroeste Basin in Argentina 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 bbl. In turn, gas processing reached a daily average of 6.9 million m3.

In 2012, an agreement was executed with ENARSA, currently IEASA, whereby Refinor would provide compression services for the gas IEASA imports from Bolivia. This agreement was later amended

to increase the gas compression capacity (up to a volume of 26 million m3/day), and keeping its term until April 2019. This agreement was renewed in 2019 and will be in effect until April 2021, with a compression capacity of 21 million m3 of gas per day.

As of December 31, 2019, Refinor had a commercial network of 90 GSs in the Provinces of Tucumán, Salta, Santiago del Estero, La Rioja, Jujuy, Catamarca, and Chaco. The network offers a high-performance fuel line: Premium Max (97 octanes), Super Max (95 octanes), Eco Diesel Max and Eco Diesel Premium Max.

In 2019, sales of gasoline, GO, raw gasoline and other liquid fuels amounted to 478 dam3, which represents a 10% year-on-year decrease. LPG sales amounted to approximately 74 kton in 2019, experiencing a 62% decrease compared to the previous year.


9. Human Resources

At Pampa, we work with passion and enthusiasm. Guided by our values, we strive for excellence and continuous improvement to meet the market demands and continue growing on a daily basis. The Company supports several practices aimed at human resources training, development, attraction, loyalty and management, thus creating a favorable context for the achievement of organizational results.

In 2019, the strategy of the Human Resources Department was oriented towards talent development and knowledge management. We launched the second edition of our young professionals’ program, Pampa’s

Young Talent, and we are working on improving our value proposal based on development and benefits with a strong focus on the employee experience.

We also launched the self-management and learning modules at SuccessFactors to boost the agility of our culture. As regards communication, we have defined a new paradigm and strategy based on proximity and the knowledge of the businesses and people making up the Company. We continue working daily to maintain labor relationships based on respect for people, rule of law and a positive work

environment.

9.1 Recruitment and Selection

To cover vacant positions in the different assets and corporate sectors, we recruit dynamic profiles representing our team working culture, the search for excellence, and system-thinking.

We conducted the second edition of the ‘Young Talent’ Program, whereby Pampa incorporated 13

new young professionals with high potential in core business teams and corporate areas. The purpose of the program is to incorporate new generations so that they may develop a long term career in an industry that requires highly specialized professionals, thus contributing to the sustainability of the business and the country's future growth.

9.2 Professional Practice / Internships

In 2019, the Company continued conducting professional practices in its different plants jointly with technical schools so students could get acquainted with professional and work environment. This practice has allowed students to take part in selection processes for positions similar to actual professional functions, and some of them have been finally hired by the Company.

We also have interns who, while pursuing their university studies, began to develop an experience of learning, practical training and application of knowledge acquired in their career in an organization. In 2019, we conducted internships in different sectors such as: Accounting, Risks and Insurance, Production

and Engineering, Finance, Human Resources, Planning and Management Control, etc.

9.3 Planning of Human Resources

Our human capital management processes, policies and practices are geared towards the development of talent and organizational skills, leadership strengthening and the development of a high-performing culture to attain business goals.


9.4 Compensation and Benefits

Pampa’s policy on compensation is based on ensuring external competitiveness and maintaining in-house equality. Thus, at Pampa we work with different surveys which allow us to adjust our benefit packages and wage structure in line to those offered in the market. In 2019, the Company granted

increases aligned with those offered by the labor market to personnel not subject to collective bargaining agreements, and salaries were adjusted according to collective bargaining agreements for unionized employees.

As regards benefits, we have developed a program with an identity representing all initiatives considered as such. This identity consists of 5 main axes which allow for segmenting proposals focused on experiences, family, time, health and finance. The challenge for 2020 is that employees may get to know the proposals we have for them, matching these proposals with their needs or preferences.

9.5 Relations with Unions

Throughout our history, we have kept constant relationship with unions and professional organizations in each of the businesses where we operate. This exchange, based on mutual respect, dialog and constructive negotiation, has allowed us to develop bargainings focused on the search for common interests, and facilitates the development of activities in changing social and economic contexts.

The maturity in these relationships has allowed us to face challenges posed by constantly changing scenarios.

In 2019, we actively participated in business chambers conducting labor and conventional negotiations, both at national and regional levels, taking part in the committees representing them and responsible for negotiations. The negotiation processes conducted by our subsidiaries have been monitored throughout their course.

9.6 Management of Personnel

In 2019, we concluded the implementation of SuccessFactors Employee Central module, a self-management platform which, together with the payroll consolidation operated in SAP in 2019, has contributed to the achievement of a more functional and efficient management of payroll and accounting records.

Moreover, within the framework of incorporating more technological tools into our processes, in

December 2019 we launched the digital payslip pilot test in two areas of the Pampa Building; besides, we continued with the control management of working hours in our power plants through the LENEL system, in coordination with the Assets Security area.

In addition, a bidding process for employees’ life insurance was performed in the last quarter of 2019, which entailed, besides the unification of insurance, a significant improvement in terms of capital, premiums and covered risks. Furthermore, as regards medical insurance, we continued with the voluntary unification process started in the previous year at CTLL, CTG, HIDISA and HINISA’s personnel that is not under the Collective Bargaining Agreement and also have incorporated CPB and the Pampa Building in this process.

During 2020, we will continue pursuing our digitalization efforts, implementing the digital payslip for the rest of the Company’s employees, and we will complete the installation of time control equipment

in locations which did not have this system to continue strengthening the goal of achieving more agile and efficient procedures. We will also undertake the digitalization of physical files and area processes.


9.7 Training and Development

In 2019 we invested more than 76,000 man-hours in training, aiming at accompanying the development of our employees, mainly focused on technical, business, skills and leadership training, including the following:

Pampa Skills Development Program, targeted at positions with no employees reporting to them and wishing to develop some of the skills of the model defined by the Company. In 2019, more than 330 employees participated, with an investment of more than 6,200 man-hours. The program included visits to plants, business simulators, face-to-face workshops and virtual materials;

Leadership Development Program, which consisted of the training of all Pampa leaders, distributed in three programs: Managers, Heads and Supervisors. In total, about 380 leaders

participated, with the investment of more than 10,800 man-hours, the contribution of 2 counselors, and more than 45 coaching processes were performed;

First edition of the Introduction to Leadership Program, geared at senior professionals with the purpose of strengthening their individuals and team management skills;

We accompanied the academic training of employees who participated in Master’s Degree and Specialization Programs; we organized Effective Oral Presentations and technical training courses,

and participated in congresses both locally and abroad;

We launched an e-learning platform, through which we can manage all trainings in a more agile, flexible and effective way;

At Pampa, we encourage internal development. Therefore, whenever there is a vacancy, we first make an internal search looking for the proper profiles to cover it. In 2019 we had 43 internal transfers of employees not covered by collective agreements, in corporate areas as well as the E&P and Power Generation businesses.

We have developed a methodology to map our employees based on their development, commitment and personal aspirations to undertake more responsibilities or new challenges. As a result of this mapping, leaders could choose different possible development initiatives to assign to each employee.

9.8 Internal Communications, Working Environment and Culture

Pampa’s culture is based on an integrated, professional and flexible model which articulates diversity and integrates our values, practices and objectives. In 2019 we focused on streamlining our communications to make them more agile and effective, generating greater knowledge of our business by our employees and reinforcing a culture of recognition based on our values. The main initiatives conducted were the following:

The implementation of Kaizala, Microsoft’s messaging application which allows us to reach our

employees through their mobile phones with instant, friendly, and participative communications.

At the same time, working teams use it to stay in contact and optimize management. As of this date, we have reached an approximate 70% adoption rate;

The development of the ‘Knowing Our Businesses’ program encouraging employees to get a more thorough knowledge of the operation and specific characteristics from each of our businesses. We have organized visits to operating facilities, breakfast gatherings with our CEO, a business simulator and open lectures with leaders of each business;


The launching of the recognition program ‘A round of Applause!’, through which Company leaders recognize individuals in their teams who are examples of the five values of Pampa’s culture: teamwork, excellence, entrepreneurial spirit, integrity and accountability. More than 100 employees were recognized and received a voucher with experiences as a gift;

The 1st edition of ‘#PampaInspira’ (Pampa Inspires), an initiative conceived at the closing event of the Leadership Development Program 2019 edition, but later spread throughout the Company.

Different Pampa leaders shared, through inspiring talks, their development, transformation and entrepreneurship stories; and

The continuation of the ‘Family Day at Pampa’, an annual event where employees receive close relatives at offices and plants to share a different day.


10. Community and Pampa Energía Foundation

Programs and social investment actions performed by Pampa are part of a strategic model for establishing relationships with our stakeholders led jointly with the Pampa Energía Foundation. With a strong commitment to society, 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.

To support the development of the community on an orderly way and set clear, measurable and assessable goals and intervention modalities, in 2019 we redefined our social investment strategy based

on three axes:

Education: a key element for individuals’ growth and autonomy, and a necessary condition to access professional and work training;

Employment: a driver for the effective development of individuals in the short term, and of communities in the medium and long term; and

Social inclusion: a trend consisting of bringing opportunities and resources to individuals so that

they may actively participate in the social, environmental, cultural and economic activities of their communities.

As a company committed to managing the economic, social and environmental impacts of our business, through our social investment 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: 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 rely on the background and the

importance of the efforts by social organizations and public bodies, therefore we have partnered with them for the development of social investment initiatives. SDG 17 (partnerships for the goals) is cross-cutting to all our initiatives.

10.1 Education and Labor Placement Training

We believe that education is the key to development and social and labor market inclusion.

Therefore, we seek to provide equal opportunities to children and young people in vulnerable situation.

Accompaniment in Educational Paths

Through the granting of scholarships and the development of soft skills, we seek to support the completion of technical secondary education studies and the entry into university and college of teenagers living in the Provinces of Neuquén, Salta, Mendoza, Buenos Aires and Santa Fe.

Young people participating in the program receive monthly financial assistance and personalized

support through mentoring, trainings and educational trips. In turn, they are offered the possibility to get acquainted with formal work environments and perform activities so they may envision concrete employment possibilities in the future.

In 2019, we accompanied 1,082 students in the last three years of technical secondary education and 349 university and college students, of which 421 secondary students and 25 university students graduated from courses of study associated with our businesses, mainly engineering.

We believe that the students’ educational paths may not be conceived in isolation from their environment, therefore we work bringing proposals to institutions contributing to students’ learning improvement: providing tools for teacher training and educational management, and allocating a budget to the improvement of the institutions’ facilities and equipment.


In 2019, we offered 8 workshops to 59 teachers of primary schools in the City of Bahía Blanca, and in the Provinces of Mendoza and Neuquén under the Energy Researchers project (Investigadores de la Energía) which deals with topics associated with energy, its sources, efficiency and benefits. The tools incorporated by teachers were implemented with 990 students.

Moreover, we continued supporting the Learning Schools Network program fostered by the Ministry of Education of the Government of the Province of Buenos Aires geared at providing training to 1,914

principals and 7,214 teachers; and we granted 15 scholarships for the Educational Management at Escuela Superior de Economía y Administración de Empresas. 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.

As part of our commitment with the improvement of educational and community institutions, we

performed refurbishments and donated equipment to schools, universities, and training and community centers of the communities where we operate. In 2019, we invested more than AR$4.4 million in schools, universities and educational institutions.

Labor Placement Training

We conducted professional practices and first job workshops so that secondary, college and university students may consolidate, integrate and develop knowledge and capabilities matching the

professional profile they are developing and increase their employability opportunities.

In 2019 we continued fostering professional practices for more than 191 students attending the last years at 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 also participated in our secondary school scholarships program. In turn, at the university and college level, 30 grantees performed professional practices and internships and, since the beginning of the Educational Paths Escort program, 19 grantees have been hired in different assets of the Pampa Group.

In the Provinces of Buenos Aires and Salta, we conducted 8 first-job workshops with the attendance of 1,270 near graduates from secondary school.

10.2 Local Assessment and Development of Community Impact Projects

Strategic Alliances for Community Development

We believe in the creation of shared value, therefore 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 difficulties in each community and define strategic lines of action with reference 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,

incorporating a strategic view and defining the direction, scope, priorities and issues to address regarding

each stakeholder. We organized 5 workshops, provided training to 56 employees and developed 6 analysis matrices aiming to move forward with the action plan in 2020, including the following:

Sustainable Energy

As a power company, we develop social projects facilitating access to energy through renewable sources and the improvement of energy efficiency. We worked in partnership with 500RPM to improve access to energy in rural communities through the installation of low power wind turbines. Since 2018, we


implemented two projects in kindergartens and primary schools in Coronel Rosales, Province of Buenos Aires, attended by 32 children. This is a participatory project which involved more than 100 technical schools’ students and their teachers in training and construction, as well as 27 volunteers of the Company. The wind turbines have a power capacity of 350 watts and generate about 1,570 kWh annually.

In the Province of Salta, we have been working since 2017 with Fundación Solar Inti accompanying 20 women and their families of the guaraní community in Piriquenda through the self-construction of eco-

stoves and kitchens, and cooking and entrepreneurship workshops. In 2019, we measured the positive impact in the life of 148 people and their environment: preventing the logging of 462 native trees and the burning of 39 tons of firewood per year, a 50% reduction of the smoke in homes and an average of 1 ton of GHG per year and per family, as well as a decrease in the consumption of gas bottles, which helped to improve household economy. Furthermore, in association with companies taking part in the Industrial Union of Salta, we supplied eco-stoves to 25 Rural Early Childhood Centers attended by 750 people.

In the Province of Neuquén, in partnership with the Ministry of Education and the National Institute of Industrial Technology, we started an assessment aiming to improve energy efficiency in two schools. These actions are added to the efforts made in Technical School No. 10 of Plaza Huincul where, thanks to the purchase of measuring equipment and a capacitor bank, monthly savings for about AR$400 thousand were achieved.

As regards environmental education, together with companies making up the AcercaRSE group and Interindustrial Committee for Environmental Conservation of Campana-Zárate (Comité Interindustrial de

Conservación del Ambiente Campana-Zárate), we have been implementing the ‘La Basura Sirve’ (Waste Is Useful) program since 2009. In 2019, the program was developed in 13 schools of the towns of Campana, Zárate and Lima, reaching 4,500 students, with the training of teachers, the organization of workshops and the presentation of circus performances to raise awareness on the improvement of the environment and education, and the strengthening of waste separation, collection and recycling. Moreover, we developed a renewable energies and environmental protection workshop for 30 students of the primary school Virgen de Fátima de Piquirenda, in the Province of Salta.

Skills Training and Support to Productive Entrepreneurships

We foster the development of productive activities and the creation of decent work through the development of courses on skills for job profiles associated with our business or in demand in the community, and we provide support to productive entrepreneurships towards social and/or environmental benefit.

In 2019 we offered 6 skills training courses to more than 130 people. In the Province of Buenos

Aires, together with the Formar and Tzedaká Foundations, we offered basic electricity workshops to 86 adults. In the Province of Neuquén, we organized Operation and Maintenance of Electric Facilities and Equipment courses, as well as the Gas Plant Operator Course together with the National Technological University for 18 people of the Cutral Có community. Lastly, jointly with the Haciendo Lío organization and the Municipality of Morón, we offered manicure and social network management courses for 28 youngsters and adults of the Carlos Gardel neighborhood.

Besides, we supported social productive entrepreneurships in the communities where we operate. We donated inputs for the production and sale of materials of the Accervil Sheltered Workshop, which

employs 45 people with disabilities. Moreover, we encourage inclusive and responsible consumption with Pampa employees through campaigns such as Solidarity Easter and Entrepreneurs’ Fair in alliance with 5 organizations focusing on labor placement: Hogar San José Providente de José C. Paz, Instituto de Adoratrices de la Eucaristía de Roldán, Centro de Formación Profesional y Hogar de Cristo Don Bosco de Zárate, the Formar Foundation, and the 100% Nuestro Program in the City of Buenos Aires. In our Neuquina

Basin asset, we support Los Chihuidos Rural Development Association through donations for the development of forage programs benefiting more than 70 farmers.


Enhancement of Local Organizations

We assist in the improvement of the institutional management of the organizations with which we coordinate projects by supporting projects developed by them. With the purpose of strengthening leaders and volunteers, in 2019 we granted 9 post-graduate scholarships in social organizations jointly with the San Andrés University and the Argentine Catholic University.

In partnership with Food Bank Foundation (Banco de Alimentos), we accompanied the Carlos Menem Jr. Soup Kitchen in General Güemes, Province of Salta, which provides daily assistance to 120 children.

Pampa’s Volunteering Program

At Pampa we are convinced that our employees are our main asset, and that we are responsible for creating shared value in and with the communities where we operate our assets. With ‘Pampa

Volunteering’, we seek to generate a space where, through the Volunteering Committees, employees may draw up proposals contributing to solving social difficulties identified at the local level and allowing in turn to reinforce each asset’s links with the community, contribute to its socio-economic and community development, and strengthen the organizational culture and the employees’ sense of belonging.

After holding periodical meetings to reflect on the proposed intervention strategies, each assets’ committee members define action plans for volunteering activities and their coordination with strategic

partners at a local level. In 2019 we fostered 49 actions, thanks to the participation of more than 1,300 volunteers, dedicating more than 19,000 hours to humanitarian activities. We currently have 9 active Volunteering Committees, and 3 others are in the process of being established.

Professional Volunteering

We encourage employees’ involvement and participation in activities in which they can put their specific skills and expertise into action to support causes, projects and organizations needing them through

counseling, technical talks and technical-professional expertise.

With the purpose of contributing to the training of students of all educational levels by getting to know our productive processes, facilities and working methodology, as well as the people making up Pampa, we organized visits to our plants as part of the Open Doors program.

In 2019 we received more than 2,400 students in our assets and offered workshops at schools for more than 350 primary and secondary students. At Pampa Building we organized, jointly with the Pescar Foundation, for the first time a Pescar Educational Center with the purpose of providing personal and job

training to 20 young people aged 18-24 in vulnerable situation to favor their social and labor integration in the administrative area. Pampa volunteers offered trainings and mentoring, dedicating more than 200 hours to this activity. After the implementation of the center, more than 50% of them have joined formal jobs.

Annual Campaigns

More than 150 volunteers participated in the Blood Donation Drive in the Provinces of Buenos Aires,

Salta, Mendoza and Neuquén, in partnership with local organizations encouraging voluntary blood donation.

With the ‘2019: A Sound Beginning’ campaign, employees of our assets collected and donated school supplies to more than 600 students attending 8 institutions in the communities where we operate.

In the winter, and in partnership with 8 civil organizations, we developed again the ‘Together Against Cold Weather’ campaign with the purpose of assisting people in vulnerable situation. The activities


included a winter clothing collection and the sorting of kits based on size and gender, night walks to assist people in need, and the making of blankets and scarfs. More than 1,000 people received our donations in the Cities of Buenos Aires and Bahía Blanca, Province of Buenos Aires, and in the City of San Rafael, Province of Mendoza.

Every December 5, International Volunteer Day established by the UN, Pampa’s assets join the ‘A Christmas Eve for Everyone’ campaign. Volunteers get organized so that families in vulnerable situation

may receive gift boxes with food and gifts to share during the holiday season’s celebrations. 4,250 people received complete boxes thanks to the largest humanitarian action of the year, which involves more than 500 employees.

Refurbishments and Enhancements in Organizations of Our Community

We organized events for educational and social institutions, where volunteers may add value and/or improve spaces in kindergartens and several educational and social institutions. In 2019, we implemented

3 actions benefiting 165 people of all ages, thanks to the participation of 78 volunteers and a AR$380 thousand investment. The beneficiary organizations were: Anide Home, in the town of San Lorenzo, Province of Santa Fe; Don Bosco Club, in San Rafael, Province of Mendoza; and the Senior Adults’ Day Club in the neighbourhood of Flores, City of Buenos Aires.


11. Information Technology

In 2019, we redefined the strategy of the Information Technology Department through the implementation of a strategic map containing goals, indicators and initiatives associated with four different perspectives: financial, customer, processes and human capital. Numerous projects and initiatives were implemented aiming to optimize and digitalize processes in the Company’s businesses and corporate areas.

In the power generation business, support was provided in the construction of failure predictive models for the resolution of different scenarios, and a solution was implemented for the operation analysis

and tracking of power production in wind farms.

At CTLL and CTGEBA, a document manager was implemented, optimizing the organization and

management of files, images, plans and other documents, creating a single, secure and always-available repository. Moreover, at CTG, CPB, CTP and in the dispatch center a log solution was implemented for recording and tracking of operational developments. Besides, within the framework of the acquisition of CTEB, the reliability and availability of IT services at the plant were improved through the integration of

systems and processes.

In the E&P business, development plans integrating all information on production and budgets were implemented, thus achieving higher flexibility for the generation of scenarios and facilitating decision-making. Moreover, the gas pre-billing process was automated, integrating dispatch and billing processes in order to have a single source of commercial information, and an operating efficiency tracking solution was implemented, optimizing controls of productive processes.

In corporate areas, for the Human Resources area, the SuccessFactors system was expanded

through the training module, and the digital payslip project was launched. For the Procurement area, SAP Ariba functionalities were expanded to streamline purchase transactions. In this line, new inflation-adjustment and US$ as functional currency functionalities were implemented.

Accompanying digital transformation, the automatic processing for the Accounts Payable area was implemented, and the processes for budget creation and tracking of expenses and investments, insurance management, QSELH and assets security were digitalized. Moreover, the migration of information to the cloud continued, and blade servers were replaced by a hyperconverged system, thus increasing processing

speeds.

Finally, as regards information security, an assessment of the current scope of information security governance was performed, and an action plan was designed to bring current resources and technology to the levels recommended by the industry’s standards and best practices (ISO 27001, NIST and CIS controls).

With the purpose of minimizing operational risks and facilitating compliance with the required legal frameworks and standards, new modules of the GRC (Governance, Risk and Compliance) system were

implemented, and we continue working on raising our employees’ awareness on risks associated with information security, promoting the responsible use of technological resources and strengthening our assets’ operative areas on cybersecurity aspects. In this respect, an annual information security awareness program was developed, closing with the Information Security Week event, which included workshops and talks on the topics covered throughout the year.


12. Quality, Safety, Environment and Labor Health

Pampa considers that economic progress should be sustainable and be attained through the implementation and improvement of a management system committed to all stakeholders: shareholders, customers, employees, community, suppliers and control bodies, with a focus on quality, personal health and safety, environmental care and energy efficiency.

Pampa applies its QSELH policy in all its businesses 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 assets, and its results were used as a reference for 2019 and 2020 planning.

Moreover, in 2019 Pampa continued advancing management programs in all its operations, allocating important resources to staff training; besides, it furthered the development and strengthening of Pampa’s culture in QSELH aspects through an integrated and aligned management.

12.1 Management Quality

Pampa furthers its management quality using international ISO standards and the National Quality Prize model as references. The main applicable QSELH methodologies are the following: policies and guidelines, risk management, certified management systems, and daily management quality, which comprises standards and anomalies, audits and actions, 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 assets.

All Pampa assets maintain their management systems third-party certifications from the Argentine

Accreditation Organization, under ISO 14001 (environmental management) and OHSAS 18001 (occupational health and safety management) standards. The power generation and petrochemicals’ assets are certified under the ISO 9001 standard, and, specifically, CTGEBA has also been certified under the ISO 50001 (energy management) standard. The certification under the ISO 14001 standard was also achieved

at PEMC, and PEPE II and III. External audits are conducted on an annual basis to guarantee adherence to the requirements of the above-mentioned standards, and internal audits by qualified Pampa staff and contractors have also been conducted.

Moreover, in 2019 Pampa started the certification process for the new ISO 45001:2018 standard, which replaces OHSAS 18001, reinforcing safe and healthy 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 Subsecretariat of Renewable Energies and Energy Efficiency, in the Energy Management category.

As regards quality in daily management, in early 2019 the anomalies management process was reviewed, and the action management was launched at E&P, strengthening 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 solution which is more agile, modern

and customized to Pampa’s needs.

With the purpose of improving operations and results through teamwork, since 2013 selected Pampa’s Improvement Teams have been participating in the National Annual Meeting for Continuous Improvement organized by Argentine Society for Continuous Improvement (Sociedad Argentina Pro Mejoramiento Continuo), where knowledge and experiences are shared. In 2019 Pampa presented two experiences: Design and Printing of Blocking Elements at HPPL, and Redesign of the Auxiliary Cooling System at CTLL’s Combined Cycle.


12.2 Health and Safety

Pampa has advanced with the definition and periodic monitoring of its safety goals through the QSELH indicator board, as well as with the development of initiatives to improve safety management and performance in each asset. 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 a part of the daily activities.

In this sense, a Work Permits System Manual was drawn up focusing on a comprehensive risk analysis during the tasks’ planning stage. In 2019, 4 workshops were organized for specialists of each of our businesses to meet their specific needs.

In terms of human behavior, one of the pillars of QSELH management, a comprehensive review of the Behavioral Preventive Observations tool was made focusing on the approach to people, the search for

commitment and increased awareness on prevention, and compliance with the golden rules during such observations.

As regards industrial hygiene, we continued working on quality improvements in hygiene risk maps, covering chemical, physical and ergonomic risks. Assessments were conducted, and measurements of both work, environments and individual dosimetries, were optimized, resulting in several plant improvements geared at minimizing risks.

12.3 Environment

Pampa’s operations are conducted within a context of sustainable development. Pampa is committed to the protection of the environment and endeavors to make a rational use of natural resources in each of its projects by applying proper and economically viable technologies.

Pampa continues managing environmental risks to prevent the occurrence of undesirable events

and/or to minimize their impact by developing actions and programs such as that 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 which has 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 Pampa started operations of PEPE II and III, with a total installed power capacity of 106 MW, and important progresses were made at CTGEBA’s closing to combined cycle, which will become operative by mid-2020, adding 383 MW. In June 2019, Pampa acquired CTEB in partnership with YPF, and will operate the power plant over the next 4 years, with a 567 MW capacity, participating in its closing to combined cycle, which will add an additional 280 MW power capacity.

12.4 Response to Emergency

Pampa endeavors to prevent undesirable events; even so, it is fully prepared to provide a prompt and effective response to emergencies in order to minimize possible consequences. In 2019, the Company continued making periodic emergency response simulations in terrestrial and aquatic scenarios, promoting the observance of established practices and specific improvements which are incorporated into the integrated management system.

In order to develop the necessary skills and competencies to execute emergency plans and

coordinate the necessary activities if an undesirable event occurs, practices and training are performed based on the roles established in the Emergency Response Plans. In 2019, critical emergency scenarios in


the power generation business were surveyed and updated, and this process will be extended to the rest of the businesses in 2020.

Moreover, in 2019 we started a survey on the condition of fire detection and suppression systems with the purpose of evaluating 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 worked on with each business during 2020.

12.5 Labor Health

In 2019, Pampa continued implementing the policy on the use of alcohol, drugs and psychoactive substances. Moreover, the Preventive Labor Environments certification granted by SEDRONAR and COPOLAD was obtained in all assets operated by Pampa, aiming to recognize the implementation of

preventive programs in work environments, which involves the development of the prevention and effective

actions policy based on the employees’ welfare.

Aiming to promote the biopsychosocial health of all its members, in 2019 Pampa continued advancing the Labor Health Management. Occupational and risk medical exams were performed to 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.

As regards prevention, Pampa continued implementing the physical activity program, as well as flu and tetanus immunization campaigns. Moreover, the cardio-protection program continued, aiming to train staff so that they may 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 Pampa assets with the use of AED and First Aid training, and we achieved the certification as a cardiac-safe company.

On the other hand, together with Pampa Foundation, a blood donation campaign was conducted through the implementation of voluntary blood donation drives, collecting 158 blood bags. This practice

continues being organized on a systematic basis in all our assets to strengthen the bonds among Pampa, its staff and the community.


13. Results for the Fiscal Year

Pampa, the largest independent energy integrated company in Argentina, focuses its business on the electricity value chain by participating in the generation, transmission and distribution of electricity, as well as in the gas value chain by taking part in E&P and midstream. The following table summarizes the consolidated ratios obtained during fiscal year ended December 31, 2019, compared to the last fiscal years:

12.31.2019 12.31.2018 12.31.2017 12.31.2016

Liquidity 1.60 1.29 1.25 0.77

Solvency 0.74 0.46 0.53 0.47

Immobilized Capital 0.76 0.73 0.65 0.77

Yield 0.272 0.160 0.211 0.068

Through its subsidiaries and share participations in joint businesses, and based on the business nature, customer portfolio and risks involved, we were able to identify the following business segments for continuing operations:

Power Generation, consisting of the Company’s direct and indirect interests in CPB, CTBSA, HINISA, HIDISA, PACOSA, Greenwind, TMB, TJSM; as well as power generation activities through

CTG, CTP, CTLL, CTGEBA, CTPP, CTIW, EcoEnergía power plants, PEPE II and III wind farms and the HPPL dam, and its equity interest in Enecor;

Electricity Distribution, consisting of Pampa’s direct interest in Edenor;

Oil and Gas, consisting of the Company’s own interests in oil and gas blocks, as well as interests

in its associates OldelVal and OCP;

Petrochemicals, comprising styrene and the catalytic reformer unit’s own operations developed

in plants in Argentina; and

Holding and Others, consisting of financial investment transactions, holding activities, interests in joint businesses CITELEC and CIESA and their respective subsidiaries holding the concession over the high voltage electricity transmission nationwide and over gas transportation in the south

of the country, respectively, as well as the Company's interest in its associate Refinor.

It should be pointed out that the analysis of results for fiscal year 2018 has been made for continuing operations.


13.1 Consolidated Income Statement by Segment, Fiscal Year 2019 (US$ Million)

Consolidated profit and loss information

(as of December 31, 2019)

Revenue 819 1,502 174 321 20 - 2,836

Intersegment sales - - 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, plan and equipment (52) - (10) - - - (62)

Results for participation in joint businesses and associates 13 - 21 - 67 - 101

Agreement from regularization of liabilities - 285 - - - - 285

Operating income 273 342 71 5 60 - 751

RECPAM - 187 - - - - 187

Financial income 51 20 18 1 7 (1) 96

Financial expenses (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 of the year 248 197 63 11 281 - 800

Attributable to:

Owners of the Company 239 98 63 11 281 - 692

Non-controlling interests 9 99 - - - - 108

Consolidated statement of financial position


Assets 1,472 1,480 1,261 136 1,527 (192) 5,684

Liabilities 1,226 1,792 465 122 (160) (170) 3,275

ConsolidatedGenerationElectricity

distribution

Holding and

othersEliminationsOil and gas

Petro-

chemicals

ConsolidatedGenerationElectricity

distribution

Holding and

othersEliminationsOil and gas

Petro-

chemicals


13.2 Consolidated Income Statement by Segment, Fiscal Year 2018 (US$ Million)

Consolidated profit and loss information


Revenue 604 1,484 458 338 36 - 2,920

Intersegment sales 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, plan and equipment - - - (32) - - (32)

Results for participation in joint businesses and associates (11) - 37 - 92 - 118

Results from sale of equity share in companies - - 28 - - - 28

Operating profit (loss) 274 103 250 (62) 106 (1) 670

RECPAM 233 226 107 49 12 2 629

Financial income 52 18 15 1 14 (1) 99

Financial expenses (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)

Profits (loss) for the year from continuing operations 106 116 (162) (54) 200 1 207

Discontinued operations - - 49 - 31 - 80

Profit (loss) of the year 106 116 (113) (54) 231 1 287

Attributable to:

Owners of the Company 100 61 (115) (54) 231 1 224

Non-controlling interests 6 55 2 - - - 63

Consolidated statement of financial position


Assets 1,414 2,133 1,237 153 872 (137) 5,672

Liabilities 1,054 1,241 1,273 198 247 (136) 3,877

Oil and gasHolding and

others

Petro-

chemicalsConsolidated

GenerationElectricity

distributionOil and gas

Holding and

othersEliminations Consolidated

Petro-

chemicals

EliminationsGenerationElectricity

distribution


13.3 Income Statement Analysis for Fiscal Year ended December 31, 2019,

compared to Fiscal Year ended December 31, 2018

Consolidated net sales revenues of US$2,836 million for fiscal year ended December 31, 2019, 3% lower than the US$2,920 million for fiscal year 2018. The following decreases were registered: 15% (US$77 million) in oil and gas, 5% (US$17 million) in petrochemicals, US$16 million in our holding and others segment, and higher intersegment eliminations for US$205 million, partially offset by increases of 35%

(US$213 million) in power generation and 1% (US$18 million) in electricity distribution.

Consolidated cost of sales of US$2,032 million for fiscal year ended December 31, 2019, a 3% rise compared to US$1,967 million for fiscal year 2018. The following increases were registered: 71% (US$193 million) in power generation, 8% (US$89 million) in electricity distribution, and 9% (US$26 million) in oil and gas, without variations in our holding and others segment, partially offset by an 11% (US$36 million) decrease in petrochemicals and higher intersegment eliminations (US$207 million).

Consolidated gross income of US$804 million for fiscal year ended December 31, 2019, a 16%

decrease compared to US$953 million for fiscal year 2018. The following decreases were registered: US$71 million in electricity distribution, US$103 million in oil and gas, and US$16 million in our holding and others segment, partially offset by the following increases: US$20 million in power generation, US$19 million in petrochemicals and US$2 million in intersegment eliminations.

Consolidated operating profit of US$751 million for fiscal year ended December 31, 2019, a 12% increase compared to US$670 million for fiscal year 2018. The following increases were recorded: US$239 million in electricity distribution, US$67 million in petrochemicals and US$1 million in intersegment

eliminations, partially offset by decreases of US$1 million in power generation, US$179 million in oil and gas, and US$46 million in holding and others.

Net financial results represented a profit of US$97 million for fiscal year ended December 31, 2019, compared to a loss of US$446 million for fiscal year 2018, mainly due to higher net profits of US$220 million in power generation, US$477 million in oil and gas, and US$15 million in petrochemicals, partially offset by lower profits of US$29 million in electricity distribution and US$2 million in intersegment

eliminations, as well as higher net losses of US$138 million in holding and others.

Consolidated profit of US$800 million for fiscal year ended December 31, 2019, of which US$692 million are attributable to the owners of the Company, compared to US$224 million40 attributable to the owners of the Company for fiscal year 2018, explained by the profits reported in the power generation (US$239 million), electricity distribution (US$98 million), oil and gas (US$63 million), petrochemicals (US$11 million) and holding and others (US$281 million) segments.

40 It includes profits reported for discontinued operations (US$78 million).


Power Generation Segment

Net sales in our power generation segment increased by 35% to US$819 million for fiscal year

ended December 31, 2019, compared to US$606 million for fiscal year 2018. The following table shows net electricity sales (in GWh) for power generation plants:

In GWhNet

GenerationPurchases Total Sales

Net

GenerationPurchases Total Sales

Hydroelectric

HINISA 498 - 498 577 - 577

HIDISA 334 - 334 393 - 393

HPPL 823 - 823 886 - 886

Wind

PEMC1 383 - 383 247 - 247

PEPE II2 122 7 129 - - -

PEPE III2 148 5 154 - - -

Thermal

CTLL 5,096 - 5,096 4,748 - 4,748

CTG 755 137 891 1,674 553 2,227

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

CTEB3 128 - 128 - - -

Total 15,582 490 16,072 14,845 1,154 15,999

For the fiscal year ended December 31,

2019 2018

Note: 1 Operated by Pampa (50% of equity stake). 2 Commissioned on May 10, 2019. 3 Operated by Pampa (50% of equity stake) as

from June 26, 2019.

Cost of sales increased by 71%, to US$466 million, for fiscal year ended December 31, 2019, against US$273 million for fiscal year 2018, mainly due to higher purchases of inventories, energy and gas for US$176 million, higher depreciation of property, plant and equipment for US$5 million, and higher rentals and insurance for US$5 million. The following table shows the main components of our power generation segment cost of sales for the specified periods:


Purchases of inventories, energy and gas 306 65.7% 130 47.6%

Depreciation of property, plant and equipment 62 13.3% 57 20.9%

Labor costs 29 6.2% 29 10.6%

Maintenance 16 3.4% 14 5.1%

Material comsumption 14 3.0% 13 4.8%

Rentals and insurance 12 2.6% 7 2.6%

Amortization for intangible assets 6 1.3% 6 2.2%

Transportation of electricity 4 0.9% 4 1.5%

Taxes, rates and contributions 3 0.6% 3 1.1%

Royalties 3 0.6% 3 1.1%

Fees for third-party services 3 0.6% 2 0.7%

Accrual of defined benefit plans 2 0.4% 1 0.4%

Others 6 1.3% 4 1.5%

Total 466 100.0% 273 100.0%

Cost of Sales, in US$ million except %Fiscal Years Ended December 31,

2019 2018

Therefore, our power generation segment gross profit increased by 6% to US$353 million for fiscal

year ended December 31, 2019, compared to US$333 million for fiscal year 2018. Moreover, during fiscal year 2019, the sales gross margin had a 43% decrease, compared to 55% recorded in fiscal year 2018.

Selling expenses from our power generation segment increased to US$3 million for fiscal year ended December 31, 2019, against US$1 million for fiscal year 2018, mainly due to higher taxes, rates and contributions for US$1 million and higher doubtful accounts for US$1 million. The following table shows the

main components of our power generation segment selling expenses for the specified periods:


Labor costs 1 33.3% 1 100.0%

Doubtful accounts 0 0.0% -1 -100.0%

Total 3 100.0% 1 100.0%

Selling Expenses, in US$ million except %2018

Fiscal Years Ended December 31,

2019

In turn, administrative expenses decreased to US$36 million for the fiscal year ended December 31, 2019, from US$41 million for fiscal year 2018, mainly due to a US$5 million decrease in labor costs. The following table shows the main components of our power generation segment administrative expenses

for the specified periods:


Labor costs 19 52.8% 24 58.5%




Others 7 19.4% 5 12.2%

Total 36 100.0% 41 100.0%

Administrative Expenses, in US$ million except %2019 2018


Losses from other net operating income and expenses decreased by US$4 million, to a US$2 million loss, for fiscal year 2019, compared to a loss of US$6 million for fiscal year 2018, mainly attributable to a

US$12 million loss recorded in fiscal year 2018 for the provision for contingencies, partially offset by higher taxes on bank transactions for US$4 million and a lower recovery of insurance for US$2 million. The following table shows the main components of our power generation segment for the specified periods:

Recovery of insurance 5 -250.0% 7 -116.7%

Provision for contingencies 0 0.0% -12 200.0%

Provision of tax credits -1 50.0% 0 0.0%

Tax on bank transactions -8 400.0% -4 66.7%

Others 2 -100.0% 3 -50.0%

Total (2) 100.0% (6) 100.0%

Other Net Operating Income and Expenses,

in US$ million except %


2019 2018

Losses from other operating items increased by US$28 million to a US$39 million loss for fiscal year ended December 31, 2019, compared to a loss of US$11 million for fiscal year 2018, due to the impairment

of property, plant and equipment for US$52 million recorded in fiscal year 2019, offset by higher net profits for US$24 million in results for participation in joint businesses. The following table shows the main components of our power generation segment for the specified periods:

Results for participation in joint businesses 13 -33.3% -11 100.0%

Impairment of property, plant and equipment -52 133.3% 0 0.0%

Total (39) 100.0% (11) 100.0%

20182019

Fiscal Years Ended December 31,Other Operating Items,


Power generation operating income remained similar, at US$273 million, for fiscal year ended December 31, 2019, against US$274 million for fiscal year 2018. In 2019, the sales operating margin

decreased to 33%, against 45% in fiscal year 2018.

Power generation net financial results accounted for a profit of US$55 million for the fiscal year ended December 31, 2019, compared to a loss of US$165 million for fiscal year 2018, mainly due to lower net foreign exchange differences (US$340 million) as a result of the change to US$ as functional currency as from fiscal year 2019, higher proceeds from current value measurement (US$90 million) and changes in the fair value of financial instruments (US$16 million), and lower net financial interest expenses (US$2 million), partially offset by the positive RECPAM (US$233 million) recorded in fiscal year 2018. The

following table shows the main components of our power generation segment financial and holding results for the specified periods:


Financial income

Commercial interest 49 96.1% 50 96.2%

Financial interest 2 3.9% 2 3.8%

Subtotal 51 100.0% 52 100.0%

Financial cost

Financial interest -78 95.1% -82 96.5%

Tax interest -3 3.7% -2 2.4%

Others -1 1.2% -1 1.2%

Subtotal (82) 100.0% (85) 100.0%

RECPAM 0 0.0% 233 100.0%

Subtotal - 0.0% 233 100.0%

Other financial results

Changes in the fair value of financial instruments 32 37.2% 16 -4.4%

Foreign exchange differences, net -1 -1.2% -341 93.4%

Proceeds from current value measurement 49 57.0% -41 11.2%

Other 6 7.0% 1 -0.3%

Subtotal 86 100.0% (365) 100.0%

Total 55 100.0% (165) 100.0%

2019 2018

Fiscal Years Ended December 31,Financial Results, in US$ million

except %

Our power generation activities recorded an income tax charge of US$80 million for fiscal year ended December 31, 2019, compared to a charge of US$3 million for fiscal year 2018.

Finally, our power generation activities recorded a net profit of US$248 million for 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 fiscal year 2018.

Electricity Distribution Segment

Net sales from our electricity distribution activities increased by 1% to US$1,502 million for fiscal year ended December 31, 2019, compared to US$1,484 million for fiscal year 2018.

The cost of sales increased by 8% to US$1,225 million for the fiscal year ended December 31, 2019, compared to US$1,136 million for fiscal year 2018, mainly due to increases in energy purchases (US$106 million), depreciation of property, plant and equipment (US$8 million), fees for third-party services (US$6 million), and material consumption (US$6 million), partially offset by lower penalties (US$31 million) and

lower labor costs (US$7 million). The following table shows the main components of our electricity

distribution segment cost of sales for the specified periods:


Energy Purchases 952 77.7% 846 74.5%

Labor costs 108 8.8% 115 10.1%




Penalties 24 2.0% 55 4.8%

Others 10 0.8% 9 0.8%

Total 1,225 100.0% 1,136 100.0%


2019 2018

Therefore, gross profit from our electricity distribution activities amounted to US$277 million during fiscal year ended December 31, 2019, compared to a profit of US$348 million for fiscal year 2018. Moreover, during fiscal year ended December 31, 2019, the sales gross margin decreased to 18% compared to 23% recorded in fiscal year 2018.

Selling expenses decreased by 9% to US$122 million for fiscal year ended December 31, 2019, compared to US$134 million for fiscal year 2018, mainly due to a decrease in penalties (US$6 million), labor costs (US$4 million) and doubtful accounts (US$3 million). The following table shows the main components of our electricity distribution segment selling expenses for the specified periods:


Doubtful accounts 23 18.9% 26 19.4%

Penalties 22 18.0% 28 20.9%

Labor costs 17 13.9% 21 15.7%


Communication expenses 6 4.9% 7 5.2%

Others 12 9.8% 8 6.0%

Total 122 100.0% 134 100.0%

Selling Expenses, in US$ million except %2019 2018


Administrative expenses decreased by 14% to US$65 million for the fiscal year ended December 31, 2019, compared to US$76 million for fiscal year 2018, mainly due to a decrease in fees for third-party services (US$4 million), labor costs (US$1 million), rentals and insurance (US$1 million), and security surveillance expenses (US$1 million). The following table shows the main components of our electricity

distribution segment administrative expenses for the specified periods:



Labor costs 23 35.4% 24 31.6%


Security surveillance expenses 2 3.1% 3 3.9%

Others 13 20.0% 17 22.4%

Total 65 100.0% 76 100.0%

Administrative Expenses, in US$ million except %Fiscal Years Ended December 31,

2019 2018

Other net operating income and expenses for the fiscal year ended December 31, 2019 amounted to a net loss of US$33 million, compared to a net loss of US$35 million for fiscal year 2018, mainly explained

by lower decreases in property, plant and equipment (US$3 million) and tax on bank transactions (US$3 million), partially offset by higher provision for contingencies (US$4 million). The following table shows the main components of our electricity distribution segment for the specified periods:

Income from services to third-party 3 -9.1% 2 -5.7%

Decrease in property, plant and equipment -1 3.0% -4 11.4%

Voluntary retirements - bonus -3 9.1% -2 5.7%

Tax on bank transactions -13 39.4% -16 45.7%

Provision for contingencies -23 69.7% -19 54.3%

Others 4 -12.1% 4 -11.4%

Total (33) 100.0% (35) 100.0%




2019 2018

Operating income from our electricity distribution activities increased by US$239 million and recorded a US$342 million profit for fiscal year ended December 31, 2019, compared to a US$103 million profit for fiscal year 2018. In fiscal year 2019, the sales operating margin amounted to 23%, compared to 7% in fiscal year 2018. Moreover, in fiscal year 2019 a US$285 million profit was recorded under other operating items on account of the Liabilities Regularization Agreement41.

Net financial results related to our electricity distribution activities represented a profit of US$33 million for the fiscal year ended December 31, 2019, 47% lower than the US$62 million profit for fiscal

year 2018, mainly due to lower RECPAM profits (US$39 million) and changes in the fair value of financial instruments (US$17 million), partially offset by lower net financial expenses (US$22 million). The following table illustrates the main components of financial and holding results from our electricity distribution segment for the periods shown:

41 For further information, see section 7.3: ‘Regularization of Liabilities’ of this Annual Report.


Financial income



Subtotal 20 100.0% 18 100.0%

Financial cost

Commercial interest -50 44.6% -78 59.1%


Tax interest 0 0.0% -1 0.8%

Subtotal (112) 100.0% (132) 100.0%

RECPAM 187 100.0% 226 100.0%

Subtotal 187 100.0% 226 100.0%


Foreign exchange differences, net -68 109.7% -83 166.0%

Changes in the fair value of financial instruments 3 -4.8% 20 -40.0%

Proceeds from financial debt buyback 2 -3.2% 0 0.0%

Others 1 -1.6% 13 -26.0%

Subtotal (62) 100.0% (50) 100.0%

Total 33 100.0% 62 100.0%

Financial Results, in US$ million

except % 2019 2018


In turn, our electricity distribution operations recorded an income tax charge of US$178 million in fiscal year ended December 31, 2019, compared to a US$49 million charge for fiscal year 2018.

Finally, our electricity distribution activities disclosed a net profit of US$197 million for fiscal year ended December 31, 2019, of which US$98 million are attributable to the owners of the Company, compared to a net profit of US$61 million attributable to the owners of the Company for fiscal year 2018.

Oil and Gas Segment

Net sales from our oil and gas segment amounted to US$444 million for fiscal year ended December 31, 2019, a figure 15% lower than the US$521 million disclosed for fiscal year 2018. The following table shows the production of our oil and gas segment for the periods shown:


2019 2018

Oil (k bbl/day)

Continued operations 5.0 5.1

Discontinued operations - 12.7

Total 5.0 17.7

Gas (k m3/day)

Continued operations 7,344 6,753

Discontinued operations - 1,112

Total 7,344 7,865

LPG (k ton/day)

Discontinued operations - 0.1

Total - 0.1

For the fiscal year ended December 31,

Note: Production in Argentina. Discontinued operations recorded in 2018 consider the production for the first quarter.

Cost of sales increased by 9% to US$313 million for the fiscal year ended December 31, 2019, against US$287 million for fiscal year 2018, mainly due to increases in depreciation of property, plant and equipment (US$20 million) and purchases of inventory and gas (US$11 million), partially offset by lower royalties (US$15 million). The following table shows the main components of our oil and gas segment cost of sales for the specified periods:


Fees for third-party and contract of work and service 57 18.2% 56 19.5%

Royalties 56 17.9% 71 24.7%

Purchases of inventory and gas 55 17.6% 44 15.3%




Labor costs 3 1.0% 3 1.0%

Others 17 5.4% 10 3.5%

Total 313 100.0% 287 100.0%


2019 2018

Therefore, our oil and gas segment’s gross profit decreased by 44% to US$131 million for fiscal year ended December 31, 2019, compared to US$234 million for fiscal year 2018. In fiscal year 2019, the gross margin decreased to 30% of total sales, against 45% for fiscal year 2018.

Our oil and gas segment selling expenses decreased to US$12 million for fiscal year ended December 31, 2019, against US$19 million for fiscal year 2018, mainly due to lower taxes, rates and contributions (US$5 million) and compensation agreements (US$3 million). The following table shows the main components of our oil and gas segment selling expenses for the specified periods:



Labor costs 1 8.3% 2 10.5%

Compensation Agreements -1 -8.3% 2 10.5%

Doubtful accounts -1 -8.3% 0 0.0%

Others 8 66.7% 5 26.3%

Total 12 100.0% 19 100.0%



In turn, administrative expenses decreased to US$47 million for fiscal year ended December 31, 2019, against US$56 million for fiscal year 2018, mainly due to decreases in labor costs (US$7 million),

compensation agreements (US$3 million) and taxes, rates and contributions (US$1 million), partially offset by higher fees for third-party services (US$2 million). The following table illustrates the main components of administrative expenses from our oil and gas segment for the periods shown:

Labor costs 26 55.3% 33 58.9%



Compensation Agreements -1 -2.1% 2 3.6%

Others 9 19.1% 9 16.1%

Total 47 100.0% 56 100.0%


2019 2018

During fiscal year 2019, exploration expenses amounted to US$9 million, compared to US$1 million in fiscal year 2018, mainly due to geological and geophysical expenses (US$4 million), and higher wells retirement and decommissioning (US$4 million). The following table shows the main components of our oil and gas segment exploration expenses for the specified periods:

Wells retirement and decommissioning 5 55.6% 1 100.0%

Geological and geophysical costs 4 44.4% 0 0.0%

Total 9 100.0% 1 100.0%

Exploration Expenses, in US$m except %Fiscal Years Ended December 31,

2019 2018

Other net operating income and expenses decreased by US$30 million, recording a net loss of US$3

million for fiscal year 2019, compared to a net profit of US$27 million for fiscal year 2018, mainly due to the US$30 million profit recorded in fiscal year 2018 as a result of the transactional agreement in Ecuador and US$23 million on account of Plan Gas, partially offset by losses recorded in fiscal year 2018 for ship or

pay (US$9 million) and agreements with provincial treasuries (US$3 million). The following table shows the main components of our oil and gas segment for the specified periods:


Income from services to third-party 4 -133.3% 2 7.4%

Plan Gas 0 0.0% 23 85.2%

Ship or pay 0 0.0% -9 -33.3%

Provision for contingencies 0 0.0% -1 -3.7%

Agreement with provincial treasuries 0 0.0% -3 -11.1%

Transactional argeement in Ecuador 0 0.0% 30 111.1%

Result from sale of property, plant and equipment -1 33.3% 3 11.1%

Tax on bank transactions -6 200.0% -8 -29.6%

Others 0 0.0% -10 -37.0%

Total (3) 100.0% 27 100.0%




2019 2018

Profits from other operating items decreased by US$54 million, to US$11 million for fiscal year ended December 31, 2019, against US$65 million for fiscal year 2018, mainly on account of lower profits in the results from sale of equity share in companies (US$28 million) and results for participation in associates (US$16 million), as well as a loss on account of the impairment of property, plant and equipment recorded in fiscal year 2019 (US$10 million). The following table shows the main components of our oil and gas segment for the specified periods:

Results for participation in associates 21 190.9% 37 56.9%

Results from sale of equity share in companies 0 0.0% 28 43.1%

Impairment of property, plant and equipment -10 -90.9% 0 0.0%

Total 11 100.0% 65 100.0%


2019 2018

Other Operating Items,


Oil and gas segment operating profit decreased by 72% to US$71 million for fiscal year ended December 31, 2019, against US$250 million for fiscal year 2018. In fiscal year 2019, our operating margin

decreased to 16% of total sales, compared to 48% for fiscal year 2018.

Net financial results from our oil and gas activities represented a profit of US$8 million for fiscal year ended December 31, 2019, compared to a US$469 million loss in fiscal year 2018, mainly due to higher net profits from net foreign exchange difference (US$567 million) as a result of the change to US$ as functional currency as from fiscal year 2019, and higher profits in proceeds from current value measurement (US$18 million) and results from the financial debt buyback (US$17 million), partially offset

by the positive RECPAM (US$107 million) recorded in fiscal year 2018, higher net financial expenses (US$12 million) and lower profits from changes in the fair value of financial instruments (US$7 million). The following table illustrates the main components of financial and holding results from our oil and gas segment for the periods shown:


Financial income


Others 12 66.7% 6 40.0%

Subtotal 18 100.0% 15 100.0%

Financial cost


Tax interest -1 1.1% 0 0.0%

Others -6 6.4% -4 5.1%

Subtotal (94) 100.0% (79) 100.0%

RECPAM 0 0.0% 107 100.0%

Subtotal - 0.0% 107 100.0%


Foreign exchange differences, net 11 13.1% -556 108.6%

Changes in the fair value of financial instruments 53 63.1% 60 -11.7%

Proceeds from current value measurement 1 1.2% -17 3.3%

Proceeds from financial debt buyback 18 21.4% 1 -0.2%

Others 1 1.2% 0 0.0%

Subtotal 84 100.0% (512) 100.0%

Total 8 100.0% (469) 100.0%


except % 2019 2018


Our oil and gas segment recorded an income tax charge of US$16 million for fiscal year ended December 31, 2019, compared to a benefit of US$57 million for fiscal year 2018.

Moreover, in fiscal year 2018, a US$49 million profit from discontinued operations was recorded in our oil and gas segment.

Finally, our oil and gas segment recorded a net profit of US$63 million for fiscal year ended December 31, 2019, the whole of which is attributable to the Company’s owners, compared to a US$115

million42 loss recorded for fiscal year 2018 attributable to the Company’s owners.

Petrochemicals Segment

Net sales from our petrochemicals segment amounted to US$321 million during fiscal year ended December 31, 2019, a figure 5% lower than US$338 million disclosed for fiscal year 2018. The following

table shows sales volumes in the petrochemicals segment during the specified periods:

42 It includes profits reported for discontinued operations in the oil and gas segment (US$47 million).


2019 2018

Styrene & Polystyrene 99 113

SBR 27 26

Others 217 215

Total 343 355

For the fiscal year ended December 31,Selling Volume in k ton

Cost of sales decreased by 11%, to US$298 million for fiscal year ended December 31, 2019, against US$334 million for fiscal year 2018, mainly due to decreases in material consumption (US$22 million), labor costs (US$5 million), depreciation of property, plant and equipment (US$5 million) and inventory purchases (US$2 million). The following table shows the main components of our petrochemicals

segment cost of sales for the specified periods:

Inventory purchases 236 79.2% 238 71.3%

Labor costs 34 11.4% 39 11.7%





Others 17 5.7% 19 5.7%

Total 298 100.0% 334 100.0%

2019Cost of Sales, in US$ million except %

2018


Therefore, our petrochemicals segment gross profit increased by US$19 million, to US$23 million, for fiscal year ended December 31, 2019, compared to US$4 million in fiscal year 2018. In fiscal year 2019, the gross margin increased to 7% of total sales, against 1% for fiscal year 2018.

Selling expenses from our petrochemicals segment decreased to US$9 million in fiscal year ended December 31, 2019, against US$13 million for fiscal year 2018, mainly due to a decrease in doubtful accounts (US$2 million) and taxes, rates and contributions (US$1 million). The following table shows the main components of our petrochemicals segment selling expenses for the specified periods:


Transportation and loading 2 22.2% 2 15.4%


Labor costs 1 11.1% 1 7.7%

Doubtful accounts 0 0.0% 2 15.4%

Others 0 0.0% 1 7.7%

Total 9 100.0% 13 100.0%

Selling Expenses, in US$ million except %Fiscal Years Ended December 31,

2019 2018

In turn, administrative expenses decreased to US$4 million during fiscal year ended December 31, 2019, against US$6 million in fiscal year 2018. The following table shows the main components of our petrochemicals segment administrative expenses for the specified periods:


Labor costs 3 75.0% 3 50.0%


Others 0 0.0% 2 33.3%

Total 4 100.0% 6 100.0%

Administrative Expenses, in US$ million except %2019 2018


Other net operating income and expenses, recorded a loss of US$5 million during fiscal year 2019, against a US$15 million loss in fiscal year 2018, mainly on account of lower idle capacity losses (US$12 million). The following table shows the main components of our petrochemicals segment for the specified periods:

Provision for contingencies -1 20.0% -1 6.7%

Idle capacity -5 100.0% -17 113.3%

Others 1 -20.0% 3 -20.0%

Total (5) 100.0% (15) 100.0%


in US$ million except % 2019 2018


During fiscal year ended December 31, 2019, there were no other operating items, whereas in fiscal year 2018 a US$32 million loss was recorded for impairment of property, plant and equipment.

Operating income from our petrochemicals segment recorded a profit of US$5 million for fiscal year

ended December 31, 2019, whereas in fiscal year 2018 a US$62 million loss was reported. The operating margin amounted to 2% of total sales in fiscal year 2019, compared to the 18% operating loss over total

sales ratio disclosed in fiscal year 2018.

Net financial results from our petrochemicals activities represented a US$11 million profit during fiscal year ended December 31, 2019, against US$4 million losses in fiscal year 2018, mainly due to the change in functional currency as from fiscal year 2019. The positive variation was mainly due to higher net profits on account of net foreign exchange differences (US$46 million) and lower financial expenses (US$7

million), partially offset by the positive RECPAM (US$49 million) recorded in fiscal year 2018. The following table illustrates the main components of financial and holding results from our petrochemicals segment for the specified periods:


Financial income


Subtotal 1 100.0% 1 100.0%

Financial cost

Others -8 100.0% -15 100.0%

Subtotal (8) 100.0% (15) 100.0%

RECPAM 0 0.0% 49 100.0%

Subtotal - 0.0% 49 100.0%


Foreign exchange differences, net 7 38.9% -39 100.0%

Others 11 61.1% 0 0.0%

Subtotal 18 100.0% (39) 100.0%

Total 11 100.0% (4) 100.0%


except % 2019


2019

Our petrochemicals segment recorded an income tax charge of US$5 million for fiscal year ended December 31, 2019, compared to a benefit of US$12 million for the fiscal year 2018.

Finally, our petrochemicals activities recorded a net profit of US$11 million for fiscal year ended December 31, 2019, the whole of which is attributable to the owners of the Company, against a net loss of US$54 million attributable to the owners of the Company for fiscal year 2018.

Holding and Others Segment

Net sales from our holding and others segment amounted to US$20 million for fiscal year ended December 31, 2019, a figure 44% lower than US$36 million disclosed for fiscal year 2018.

No cost of sales was recorded in our holding and others segment in both fiscal years ended December 31, 2019 and 2018.

Therefore, our holding and others segment gross profit amounted to US$20 million for fiscal year

ended December 31, 2019, a figure 44% lower than US$36 million reported in fiscal year 2018.

Our holding and others segment selling expenses decreased to US$2 million for fiscal year ended December 31, 2019, compared to US$4 million in fiscal year 2018. The following table shows the main components of our holding and others segment selling expenses for the specified periods:


Others 1 50.0% 3 75.0%

Total 2 100.0% 4 100.0%




Administrative expenses decreased by 19% to US$22 million during fiscal year ended December 31, 2019 against US$27 million for fiscal year 2018, mainly due to lower expenses in fees for third-party services (US$8 million), partially offset by higher directors’ and syndics’ fees (US$3 million), and labor

costs (US$3 million). The following table illustrates the main components of administrative expenses from our holding and others segment for the periods shown:


Directors' and syndics' fees 6 27.3% 3 11.1%

Labor costs 5 22.7% 2 7.4%

Others 0 0.0% 3 11.1%

Total 22 100.0% 27 100.0%


2019 2018

Other net operating income and expenses registered a loss of US$3 million during fiscal year 2019, against a profit of US$9 million disclosed in fiscal year 2018, mainly on account of lower profits from billing of works to third-parties (US$6 million) and reversal of contingencies and fiscal charges (US$3 million), as well as higher charges from provision of tax credits (US$3 million). The following table shows the main items recorded in our holding and others segments for the specified periods:

Billing of works to third-parties 3 -100.0% 9 100.0%

Result from sale of property, plant and equipment 1 -33.3% 0 0.0%

Reversal of contingencies and fiscal charges 1 -33.3% 4 44.4%

Donations and contributions -2 66.7% -2 -22.2%

Provision of tax credits -3 100.0% 0 0.0%

Provision for contingencies -4 133.3% -2 -22.2%

Others 1 -33.3% 0 0.0%

Total (3) 100.0% 9 100.0%




2019 2018

Other operating items decreased by 27% to US$67 million for fiscal year ended December 31, 2019,

against US$92 million in fiscal year 2018, due to a US$25 million decrease in the results for participation in associates and joint businesses.

Operating results from our holding and others segment amounted to US$60 million for fiscal year ended December 31, 2019, against US$106 million for fiscal year 2018.

Net financial results from our holding and others activities represented a loss of US$10 million

during fiscal year ended December 31, 2019, against a US$128 million profit for fiscal year 2018, mainly

due to higher net losses from net foreign exchange differences (US$177 million) over the financial position in AR$ as a result of the change to US$ as functional currency as from fiscal year 2019, the positive RECPAM (US$12 million) recorded in fiscal year 2018, and lower net financial profits (US$5 million). These effects were partially offset by increases in the result from changes in the fair value of financial instruments (US$35 million) and the proceeds from current value measurement (US$22 million). The following table illustrates the main components of financial and holding results from our holding and others segment for the periods shown:


Financial income


Others 2 28.6% 0 0.0%

Subtotal 7 100.0% 14 100.0%

Financial cost


Tax interest -3 75.0% -5 83.3%

Subtotal (4) 100.0% (6) 100.0%

RECPAM 0 0.0% 12 100.0%

Subtotal - 0.0% 12 100.0%


Proceeds from current value measurement 5 -38.5% -17 -15.7%

Changes in the fair value of financial instruments 3 -23.1% -32 -29.6%

Foreign exchange differences, net -21 161.5% 156 144.4%

Others 0 0.0% 1 0.9%

Subtotal (13) 100.0% 108 100.0%

Total (10) 100.0% 128 100.0%


except %


2019 2018

In turn, our holding and others segment recorded an income tax benefit of US$231 million for fiscal year ended December 31, 2019, compared to a US$34 million charge for fiscal year 2018. Moreover, in

fiscal year 2018 profits from discontinued operations in the amount of US$31 million were recorded in our holding and others segment.

Finally, our holding and others segment registered a net profit of US$281 million for fiscal year ended December 31, 2019, the whole of which is attributable to the Company’s owners, compared to a net profit of US$231 million43 attributable to the Company’s owners in fiscal year 2018.

43 It includes profits reported for discontinued operations in the holding and others segment (US$31 million).


14. Dividend Policy

With the purpose of establishing a clear, transparent and consistent practice allowing shareholders to make informed decisions, all of this in consonance with the Company Bylaws and the applicable legal and regulatory framework in force, as from 2018 the Company has a Dividend Policy in place outlining the

guidelines to be followed to reach a proper balance between distributed amounts and Pampa’s investment plans.

In observance of this policy’s guidelines, every year the Board assesses the possibility of paying dividends to Pampa’s shareholders on a prudential basis within each fiscal year, and examines thoroughly the economic circumstances prevailing at the time.

In 2019, we are not planning to pay cash dividends on our common shares nor ADSs, thus retaining

all available funds and profits in order to apply them to the operation and expansion of our business.


15. Board of Directors’ Proposal

The Company is not planning to pay dividends, thus retain all funds and profits in order to apply them to and/or to have them available for:

i. The operation and expansion of our business, taking into consideration planned ordinary and

extraordinary investments, including the commissioning of the second closing to CC at CTGEBA, a project in its final stage and committed for the second quarter of 2020; the beginning of expansion works for the closing to CC at CTEB, as well as the continuation of our exploratory campaign in our gas and oil blocks targeting Vaca Muerta formation, and the development of our tight gas reserves;

ii. Making the most of any investment possibilities which may arise and offer significant opportunities

for the growth, expansion and synergy of our businesses;

iii. In view of the current financial situation, maintaining a proper liquidity level allowing us to meet, if necessary, our present and future obligations; and

iv. Taking the necessary measures to safeguard the interests and value of the Company shareholders’ investment in view of the current market volatility scenario.

All of this is in line with the Company’s Dividend Policy.

Results for the fiscal year recorded a AR$33,012 million profit and, as of December 31, 2019, retained earnings amount to AR$51,844 million. Consequently, the Board unanimously resolves to propose

to the Shareholders’ Meeting:

i. That AR$1,790 million of the voluntary Reserve should be allocated to absorb the negative balance of retained earnings;

ii. That AR$764 million of the currency translation difference charged to retained earnings should be allocated to the legal reserve and AR$9,369 million, to the voluntary reserve;

iii. That 5% of the profits for the fiscal year and the corresponding translation difference, in the amount of AR$2,097 million, should be allocated to the legal reserve; and

iv. That the balance of AR$41,404 million should be destined to the constitution of a voluntary reserve.

Finally, we would like to express our gratitude to all the people who shape Pampa Energía into the largest independent energy integrated company in Argentina. To all of them, to our shareholders who rely on us, to our advisors, to our customers and suppliers, a warm vote of thanks.

City of Buenos Aires, March 9, 2020.

THE BOARD OF DIRECTORS


Appendix I: Corporate Governance Report The Board has drawn up the following report corresponding to the degree of application of the

principles set out in the Code of Corporate Governance for the fiscal year ended December 31, 2019 pursuant to the CNV Rules (Sect. 1, Title I, Chapter I of Part IV), in accordance with the text restated in

2013, as amended by CNV General Res. No. 797/19.

A. The Board of Directors’ Functions: Principles i through v - Practices 1 through 5

Principles

i. The Company must be led by a professional and qualified Board of Directors, which will be in charge

of laying the necessary foundations to guarantee the Company’s sustainable success. The Board is the guardian of the Company and the interests of all its shareholders.

ii. The Board will be responsible for establishing and promoting the corporate culture and values. In its actions, the Board should ensure compliance with the highest standards of ethics and integrity based on the Company’s best interests.

iii. The Board will be responsible for pursuing a strategy inspired in the Company’s vision and mission and aligned with its values and culture. The Board will constructively engage with the management

to ensure the proper development, execution, monitoring and modification of the Company’s strategy.

iv. The Board will exercise a permanent control and supervision over the Company’s management, ensuring that it takes measures towards the implementation of the strategy and the business plan approved by the Board.

v. The Board will have the necessary mechanisms and policies in place to exercise its and each of its members’ duties in an efficient and effective way.

1. The Board of Directors generates an ethical working culture and sets out the

Company’s vision, mission and values.

In 2017, the Company’s Board approved its Code of Business Conduct, which sets out Pampa’s vision, mission and values44 and expresses the conduct expected of the Company members, both in their

daily activities and in decisions having long-term effects. The Company permanently monitors all its policies and procedures, including the Code of Business Conduct, to keep them updated in accordance with the development of the Company and its businesses, always in observance of the highest standards of corporate governance. Based on what has been described above, the Company applies the recommended practice.

2. The Board of Directors sets the Company’s general strategy and approves the

strategic plan, which is developed by the management. In doing so, the Board

takes into consideration environmental, social and corporate governance

factors. The Board of Directors oversees its implementation using key

performance indicators and taking into consideration the best interests of the

Company and all its shareholders.

As regards the Board of Directors, the Company applies the practice taking into consideration several indexes, factors, risks and projections analyzed by the management, as well as the different environmental, social, health and safety factors disclosed in the Company’s Annual Sustainability Report,

44 For further information, see Practices 22 and 23 in Appendix I to this Annual Report.

https://ri.pampaenergia.com/en/corporate-governance/code-of-business-conduct/

https://ri.pampaenergia.com/en/corporate-governance/board-of-directors/


and in line with Pampa’s strategy, approves an annual budget which will guide each sector’s actions in the following fiscal year. To such effect, the Planning and Strategy Department oversees devising and enforcing the strategy and its budget.

3. The Board oversees the management and ensures that it develops, implements

and maintains a proper internal control system with clear reporting lines.

The Company applies the recommended practice given that, at least on a quarterly basis, a management report is submitted to the Board detailing relevant events for Pampa’s performance.

Moreover, the Board is on daily contact with the Company’s management and during the Board’s

meetings with members of the different departments, who are invited so that they may raise queries regarding the specific topics to be addressed, aiming to guarantee the Board’s monitoring and follow-up of

the goals set for the fiscal year.

Pampa understands that the interaction between the Board of Directors and the management (including the Board’s members exercising executive functions) enriches control over the Company’s administration and the level of understanding on its performance. The preparation and professional credentials of all Board of Directors’ members allow for an open and sincere discussion on the Company’s

management45.

Moreover, one of the duties of the Audit Committee (consisting exclusively of independent directors) is supervising the proper functioning of internal control systems.

Finally, the Board of Directors approved the Company’s organizational chart, setting out the different reporting levels to the Chief Executive Officer (CEO), establishing clearer reporting lines.

4. The Board of Directors designs the corporate governance structure and

practices, appoints the responsible person for their implementation, monitors

their efficiency, and suggests changes if necessary.

In line with the best practices, the Board not only approves the different corporate governance policies applicable throughout the Company, but also monitors them to adjust them to the Company’s

reality, as described in Practice 1 in Appendix I to this Annual Report. In this sense, the Board has approved the following policies: Best Security Trading Practices, Related-Party Transactions, Material Information Disclosure, Compensation, Nomination, Dividend Distribution and Prevention Regarding QSELH. On the other hand, it periodically monitors the Company’s Integrity Program.

Moreover, the Board analyzes in each case whether specific committees are needed for the application of different policies. If it considers that a specific committee is not necessary, the Board delegates its application, monitoring and review to the area it considers competent to such effect. In the

way described, the Company applies the recommended practice.

5. The Board of Directors’ members have enough time to exercise their duties in a

professional and efficient manner. The Board and its Committees have clear and

formalized rules for their operation and organization, which are disclosed in the

Company’s website.

The Board’s members devote the time and efforts necessary to monitor issues submitted for their approval, tracking and monitoring. The Board and its Committees receive prior information on the topics submitted for their consideration to allow for an efficient decision-making process. Moreover, certain

45 For further information, see ‘C. Composition, Nomination and Succession of the Board of Directors’ of Appendix I to this Annual Report.

https://ri.pampaenergia.com/en/corporate-governance/audit-committee/


Directors serve executive functions in the Company, which allows them to have daily contact in their administration. As regards the professionalism of the Board’s members, as established in our Nomination Policy, the Company evaluates the nominees to be proposed before the Shareholders’ Meeting taking into

consideration, among other aspects, their independence, diversity, age, skills, experience, knowledge of the Company’s business and industry and possible incompatibilities, to guarantee the Board of Directors’ diversity.

Moreover, the Board of Directors and its Committees (the Audit, Compensation and Nomination Committees) have their respective internal rules governing their functioning, which are available on our website. These rules primarily regulate matters concerning the directors’ powers and responsibilities and the holding of meetings. In the way described, the Company applies the recommended practice.

B. Board of Directors’ Chair and Corporate Secretary’s Office: Principles vi through

viii - Practices 6 through 10

Principles

vi. The Board’s Chair oversees ensuring actual compliance with the Board’s duties and leading its

members. It should generate positive working dynamic and promote constructive engagement by its members, as well as ensure that the members have the elements and information necessary for decision-making. This also applies to the Chairs of each of the Committees regarding their functions.

vii. The Board’s Chair will lead processes and establish structures seeking the Board’s members commitment, objectivity and competence, as well as the best possible performance of the body as

a whole and its evolution according to the Company’s needs.

viii. The Board’s Chair will ensure that the entire Board of Directors is engaged and responsible for the General Manager’s succession.

6. The Board of Directors’ Chair is responsible for the proper organization of Board

meetings, prepares the agenda ensuring collaboration by the other members,

and guarantees that they receive the necessary materials with enough time to

participate in meetings in an efficient and well-informed manner. Each

Committee’s Chair has the same responsibilities for their meetings.

The Company applies the recommended practice as it has a Board of Directors’ corporate secretary

which, pusuant the Board of Directors’ Rules and Regulations published in our website, schedules and

coordinates meetings of the Board and of its different Committees within its scope. These meetings are convened pursuant to the provisions of each of the applicable regulations, attaching the necessary documentation so that directors may analyze in advance the topics to be addressed, and always under the

applicable supervision of the Board’s Chair and the respective Committees46.

7. The Board of Directors’ Chair ensures the proper internal functioning of the

Board through the implementation of formal annual assessment processes.

As from 2008, Pampa’s Board of Directors has implemented a self-assessment questionnaire to annually examine and assess its own performance and management. As from that date, every director

completes this self-assessment on an annual basis which is submitted to the Legal Affairs Executive Department, responsible for analyzing results and, if necessary, suggesting actions aiming to improve the

46 For further information, see Practice 9 in Appendix I to this Annual Report.


https://ri.pampaenergia.com/en/corporate-governance/corporate-governance-policies/compensation-committee/

https://ri.pampaenergia.com/en/corporate-governance/nomination-committee/

https://ri.pampaenergia.com/en/corporate-governance/overview/



functioning of this body. This allows for the evaluation of the Board proper internal functioning, thus applying the recommended practice.

8. The Chair generates a positive and constructive work environment for all the

Board of Directors’ members and ensures they receive ongoing training to stay

permanently updated and enabled to properly exercise their duties.

The Company applies this practice as described. The Chair leads the Board of Directors’ meetings, ensuring its orderly progress and facilitating its proper development, and coordinates the correct

functioning of the body through the Board’s corporate secretary. In the Chair’s absence, meetings are presided by the vice-chair, or by any other Board of Directors’ member in case both are absent. To guarantee that the Board’s members have access to the information as well as enough time to analyze it, meetings are convened within the terms established in the regulations of such body.

Moreover, directors serving executive functions in the Company are in permanent contact with its different areas and their daily management, which allows them to get a comprehensive vision of the business and stay updated on issues affecting it. As regards independent directors who are members of

the Audit Committee, this update is received within the scope of this body.

9. The Corporate Secretary’s Office supports the Board’s Chair in its administration

and assists in communications among shareholders, the Board and the

management.

Pampa applies the recommended practice as it has a Board of Directors’ corporate secretary within the scope of the Legal Affairs Executive Department, which main duties are as follows: (i) coordinating the preparation of the schedules for the Board’s meetings jointly with the Board’s Chair and other members, as well as with the management, so the latter may address the necessary issues for proper corporate development; (ii) coordinating the advance preparation and submittal of the necessary information for the

Board’s meetings; (iii) coordinating the drawing up, circulation and approval of the minutes of meetings; (iv) ensuring communication among the Board’s members, the management and their counselors; (v) filing

the documentation of the Board’s meetings; (vi) conducting the above-mentioned functions for the rest of the Company Committees created within the scope of the Board; (vii) coordinating Shareholders’ Meetings, the shareholders’ registry and the participation of directors in the meeting; and (viii) performing all administrative procedures associated with the Board of Directors, the Committees and the Shareholders’ Meeting. Thus, the Board’s Chair may supervise these functions without losing focus on its primary role.

10. The Board’s Chair ensures participation by all its members in the development

and approval of a succession plan for the Company’s General Manager.

Even though there is no specific plan regulating its succession line, the Company applies this practice and the corresponding principles since the Board of Directors has considered the Company’s organizational structure and appointed both its Chief Executive Officer (CEO) and Chief Financial Officer (CFO). To such effect, it takes into consideration the candidates’ personal and professional qualifications.

Moreover, the role of the Board’s Chair is different from that of the Chief Executive Officer (CEO). In this

sense, the Board’s Chair, jointly with the Human Resources Department, defines, based on the Company’s mission, vision and values, the characteristics required by the successor to the Chief Executive Officer (CEO), without currently considering it necessary to establish a succession plan.


C. Composition, Nomination and Succession of the Board of Directors: Principles ix

through x - Practices 11 through 14

Principles

ix. The Board of Directors should have adequate independence and diversity levels allowing it to make decisions in the Company’s best interests, avoiding group thinking and the decision-making by dominant individuals or groups within the Board.

x. The Board of Directors should guarantee that the Company has formal procedures in place for the

proposal and nomination of candidates to hold positions within the Board under a succession plan.

11. The Board of Directors has at least two members with an independent status

according to the current criteria established by the CNV.

The Company applies the recommended practice since, as of the issuance hereof, the Board of

Directors has 4 independent directors and 1 independent alternate director. Moreover, and as mentioned in Practice 3 in Appendix I to this Annual Report, the Audit Committee consists exclusively of independent members, exceeding the local regulations’ requirements, which only provide for a majority of members.

12. The Company has a Nomination Committee consisting of at least three members

and presided over by an independent director. If chairing the Nomination

Committee, the Board’s Chair will refrain from participating in the discussions

for the appointment of his or her own successor.

In 2018, Pampa’s Board of Directors approved its Nomination Policy, under which a Nomination Committee was created to assist Pampa’s Board and Shareholders’ Meeting in nomination and appointment process of the Board of Directors’ members.

The Nomination Committee reports to Pampa’s Board and is made up of three regular members and an equal or smaller number of alternate members. The Chair is independent pursuant to the independence criteria stipulated by the CNV rules. Therefore, the Company applies the recommended practice.

13. The Board of Directors, through the Nomination Committee, develops a

succession plan for its members guiding the candidates pre-screening process

for the filling of vacancies, and takes into consideration the non-binding

recommendations made by its members, the General Manager and shareholders.

The Board approved the Nomination Policy mentioned in the previous practice, which sets the general guidelines regarding independence, incompatibilities and diversity within the Board’s members.

Under this policy a Committee was created, which is responsible for describing the process for the identification and evaluation of nominees, as well as assisting the Board and shareholders so that the latter

may have all the necessary elements to select nominees in the Shareholders’ Meeting, all of this in compliance with the applicable legal provisions and, especially, Section 12 of Pampa’s Bylaws, which sets out the method for the selection of directors, who are elected upon candidate lists, thus guaranteeing enhanced transparency in the selection process.

As of this date, the Company’s Board is composed of members having quite diverse professions: major in economics and business administrators, financial advisors, engineers, lawyers, among others. Moreover, there are 4 female directors in the Board. Finally, all directors receive the same compensation for the duties they perform in the Board. In this sense, diversity and a culture of inclusion are guaranteed,




https://ri.pampaenergia.com/en/corporate-governance/nomination-committee/


which strengthen analysis, discussion and decision-making processes, as well as pay equality for its members. In the way decribed, the Company applies the recommended practice.

14. The Board of Directors implements an onboarding program for its newly elected

members.

The Company applies the recommended practice since the Board of Directors, through its corporate secretary office, provides the Board’s new members with the Code of Business Conduct, the main policies they should know, as well as the documentation and information necessary to perform their duties. Moreover, they are included in the Board’s distribution list together with the other members of the Board

so that they have access to the necessary documentation before their first participation in a Board meeting. Finally, upon the members’ request, meetings are coordinated with the leaders of the different departments so that they may dispel all their doubts and get acquainted with the Company’s business. On the other

hand, Pampa’s managers are available to provide answers on and supplement all the information the directors may require, all of this within the framework of permanent interaction set out in Practice 8 in Appendix I to this Annual Report.

D. Compensation: Principle xi - Practices 15 through 16

Principle

xi. The Board should generate incentives through compensation schemes to align the management —led by the General Manager— and the Board itself with the Company’s long-term interests so that all directors may comply with their obligations towards shareholders on an equitable basis.

15. The Company has a Compensation Committee consisting of at least three

members, all of whom are independent or non-executive.

Within the framework of its Compensation Policy, in 2018 the Company’s Board of Directors created a Compensation Committee assisting it and/or the Shareholders’ Meeting regarding remunerations of the

Board of Directors and the preparation and monitoring of policies and/or compensation plans and/or benefits for the Board of Directors’ members. Moreover, this policy establishes that the remuneration of the Board’s members will be in line with those received by directors of domestic peers.

The Compensation Committee reports to Pampa’s Board of Directors, and is made up of three regular members and an equal or smaller number of alternate members, who may not serve executive functions at Pampa. Currently, all its members are independent. In the way described, the Company applies the recommended practice.

16. The Board of Directors, through the Compensation Committee, establishes a

compensation policy for the General Manager and the Board of Directors’

members.

Pampa applies the practice since it has a Compensation Policy in place, approved in 2018, whereby

the Compensation Committee renders its prior opinion so that directors’ compensation is in line with those received by directors of domestic peers and pursuant to the limitations set forth by the applicable laws and the CNV rules. Within the framework of the approved policy, both the Board of Directors and the Shareholders’ Meeting should be informed on the opinion rendered by such committee.

Pampa’s policy on compensation and benefits seeks to ensure external competitiveness and maintain in-house equality. In this line, different surveys are used to adjust our benefit packages and wage structure to those offered in the market.

https://ri.pampaenergia.com/en/corporate-governance/corporate-governance-policies/compensation-committee/


In this sense, as regards the Company’s main officers —including the Chief Executive Officer (CEO) and the Company’s key staff—, seeking that their performance should align with the Company’s strategic plans and that a clear and direct link should be established between the creation of value for shareholders

and the covered employees’ compensation, in 2017 the Board of Directors approved the corresponding variable compensation plans.

E. Control Environment: Principles xii through xvi - Practices 17 through 21

Principles

xii. The Board of Directors should ensure the existence of a control environment consisting of internal

controls developed by the management, the internal audit, risk management, regulatory compliance areas and external audit establishing the necessary defense lines to guarantee integrity

in the Company’s operations and financial reports.

xiii. The Board should ensure the existence of a comprehensive risk management system allowing the management and the Board to efficiently direct the Company towards its strategic goals.

xiv. The Board should ensure the existence of a person or department (according to the size and

complexity of the business, the nature of its operations and the risks it faces) responsible for the Company’s internal audit. This audit, conducted for the evaluation and auditing of the Company’s internal controls, corporate governance processes and risk management, should be independent and objective, and have clearly defined reporting lines.

xv. The Board’s Audit Committee will be made up by qualified and highly-experienced members and should exercise its functions in a transparent and independent manner.

xvi. The Board should establish appropriate procedures to ensure the external auditors’ independent

and effective performance.

17. The Board of Directors determines the Company’s appetite for risk and

supervises and guarantees the existence of a comprehensive risk management

system identifying, assessing and making decisions on the course of action, and

monitoring the risks faced by the Company, including, but not limited to,

environmental and social risks, as well as those inherent in the business in the

short and long term.

Regarding risk management, Pampa implemented a risk management methodology as a useful working tool for the identification of the main risks affecting Pampa. To such effects, Pampa’s Board of Directors approved the ‘Risk Management Handbook’, which was later updated and restated as the ‘Business Risk Management Policy’.

The most relevant aspect of this policy is the establishment of responsibilities, functions and methodologies for the detection and assessment of risks arising from activities conducted by the Company which may affect its business or operations.

Based on these policies’ guidelines, the internal control management updates Pampa’s risk map in accordance with the administered businesses.

This policy sets out responsibilities and methodologies for the determination of business risks, with the assistance of the Audit Committee, which is responsible for supervising its application. The key business risk factors taken into consideration by Pampa include, among others:

Strategic economic and political risks;

Risks associated with competitors and joint ventures;


Risks associated with natural disasters;

Risks related to social issues;

Corporate governance risks;

Compliance risks;

Process risks, including, but not limited to, those associated with human resources, fraud, IT and operations; and

Financial and reporting risks.

The Policy also provides for the role of a ‘Risk Manager’, who is responsible for: (i) including in its annual programs all the necessary tests for detecting business risk indicators and signals; (ii) monitoring the effectiveness of the process as a whole, and safeguarding compliance with and oversight of this policy;

(iii) informing the General Management and the Audit Committee of the risk management process; and (iv) following up on the implementation of action plans to ensure that corrective measures are taken once a risk is detected. Moreover, the management in charge of internal control helps the Board to keep the risk matrix updated, identifying and assessing risks, as well as following up with the derived action plan, if required, and keeping the General Management and Audit Committee informed of this process.

The Company discloses its financial risk management in its Financial Statements, making a

distinction by type of risks and describing, for each of them, the plans or actions implemented to mitigate them. Moreover, in preparation of the 20-F Form to be submitted before the SEC, a description is made of the risk factors the Company is exposed to. In the way described, Pampa applies the practice.

18. The Board monitors and reviews the effectiveness of the independent internal

audit and guarantees the resources for the implementation of an annual risk-

based audit plan and a direct reporting line to the Audit Committee.

Pampa applies the recommended practice since the Internal Audit Department reports functionally

to the Audit Committee and administratively to the CEO.

At the beginning of each fiscal year, the Internal Audit area submits its proposed annual audit plan to the Audit Committee for its evaluation and approval, having the resources for its implementation. On a quarterly basis and to monitor its advancement, the Internal Audit Department submits a progress report

to the Committee, which contains a summary of the completed tasks and main findings.

On an annual basis, the Audit Committee evaluates the independence level and performance of the Internal Audit in issues within its authority, and discloses its assessment in its annual report.

As a member of the Institute of Internal Auditors, the Company uses the standards it considers reasonable and/or applicable without expressly adhering to them.

19. The internal auditor or the members of the Internal Audit department are

independent and highly-qualified.

The Company applies the recommended practice since, as mentioned in Practice 18 in Appendix I to this Annual Report, the Internal Audit Department reports directly to the Audit Committee, which evaluates its independence on an annual basis.

The Internal Audit Department is made up of highly-skilled staff in this subject-matter, not only for their education and training, but also for their experience in the area.

Pampa’s Internal Audit Department has rules, approved by the Audit Committee, regulating its

activities and aligned with the most relevant standards issued by The Institute of Internal Auditors.



20. The Board of Directors has an Audit Committee in place which acts based on its

rules. The Committee is mostly composed of and is chaired by independent

directors and does not include the General Manager. Most of its members have

professional experience in financial and accounting areas.

Pampa applies the recommended practice since it has an Audit Committee in place that acts based on its regulations, which establishes its functions and main operating rules. As mentioned in Practice 3 in

Appendix I to this Annual Report, the Audit Committee consists exclusively of independent members, thus exceeding the local regulations’ requirements, providing that only most members should have such status. Its duties include, among others: (i) expressing its opinion on any proposal by the Board to dessignate external auditors and ensuring their independence, reviewing the plans submitted by external and internal auditors, assessing their performance, and issuing an opinion on the presentation and disclosure of the annual FS; (ii) supervising the operation of the internal control and risk management system; (iii) rendering its opinion on related-party transactions for a relevant amount pursuant to the legal regulations in force,

disclosing such opinion to the market; (iv) expressing its opinion on the compensation proposals submitted by the Board; (v) rendering its opinion on the conditions for the issuance of shares or convertible securities in the case of a capital increase; and (vi) checking compliance with the applicable standards of conduct.

The Board of Directors seeks to ensure that most members of the Audit Committee have professional expertise in financial and/or accounting areas. This is one of the issues to assess when nominating new members to the Board of Directors and which should be taken into consideration by the Nomination Committee on issuing its prior opinion. Moreover, the Audit Committee should appoint one of

its members as financial expert as required by Title 407 of the Sarbanes-Oxley Law.

21. The Board of Directors, with the Audit Committee’s opinion, approves a policy

for the selection and monitoring of external auditors establishing the indicators

to consider when submitting to the Shareholders’ Meeting a recommendation

on the re-election or substitution of the external auditor.

Upon the presentation and publication of Pampa’s annual FS, the Audit Committee conducts an annual assessment of the external auditors’ independency, planning and performance taking into consideration different objective indicators, and issues an informed opinion pursuant to Sect. 18, Title V, Chapter III of CNV Rules (restated in 2013) and the Audit Committee’s rules. Besides, throughout the fiscal year, it holds meetings with the external auditors, at least quarterly, for the review of the Company’s

interim FS and when deemed necessary.

Moreover, Pampa has an external auditor services’ pre-approval policy, which standardizes an internal process allowing the Audit Committee to fulfill its obligation of granting its prior approval for the hiring of an external auditor to render any kind of authorized service to the Company or any of its subsidiaries. In the way described, the Company applies this practice.

F. Ethics, Integrity and Compliance: Principles xvii through xviii - Practices 22

through 24

Principles

xvii. The Board should design and establish appropriate structures and practices to promote a culture of ethics, integrity and regulation compliance which prevents, spots and address serious personal

or corporate misconduct.

xviii. The Board will ensure the establishment of formal mechanisms to prevent or, failing that, deal with conflicts of interest which may arise in the Company’s administration and management. It should have formal procedures in place seeking to ensure that related-party transactions are conducted in pursuance of the best interests of the Company, as well as fair treatment to all its shareholders.


22. The Board of Directors approves a Code of Ethics and Conduct reflecting ethical

and integrity values and principles, as well as the Company’s culture. The Code

of Ethics and Conduct is informed to and binding on all the Company’s directors,

managers and employees.

Pampa has a Code of Business Conduct in place, which lays down the ethical principles that constitute the foundation of the relationships between Pampa, its employees, and other stakeholders

(customers, suppliers, government, shareholders, community, etc.) by providing guidelines and supplying instruments guaranteeing the transparency of affairs and proper Company management.

The Code of Business Conduct is publicly available at the Company’s website and should be expressly accepted by all the Company employees, as well as by the members of the Board and Supervisory Committee. Therefore, the Company applies this recommended practice.

23. The Board establishes and periodically reviews an Ethics and Integrity Program

based on the risks, dimension and financial capacity. The plan is visibly and

unequivocally supported by the management with the appointment of an in-

house officer responsible for the development, coordination, supervision and

periodical assessment of the program’s effectiveness. The program provides for:

(i) periodic training for directors, managers and employees on ethics, integrity

and compliance issues; (ii) internal channels for reporting anomalies, which are

open to third parties and properly communicated; (iii) a policy against

retaliation protecting individuals who report a complaint; and an internal

investigation system which respects the rights of the individuals under

investigation and imposes effective sanctions for violations to the Code of Ethics

and Conduct; (iv) policies on integrity in bidding processes; (v) mechanisms for

the Program’s periodic risk analysis, monitoring and assessment; and (vi)

procedures ensuring the integrity and background of third parties and business

associates (including the due diligence for the verification of anomalies, illegal

acts or the existence of vulnerabilities in corporate transformation and

acquisition processes), including suppliers, distributors, service providers,

agents and brokers.

Pampa applies the practice as it has an Integrity Program bringing together and unifying a set of internal proceedings, mechanisms and actions for integrity, supervision and control aimed at preventing,

detecting and correcting anomalies and illegal acts. The Program’s design comprises both the mandatory and optional requirements set out in sections 22 and 23 of Law No. 27,401 and other applicable regulations. As regards the mandatory requirements, it is worth highlighting that they had already been implemented at Pampa before the law’s effective date. The Board has defined that Pampa’s Internal Audit Department will be the body internally responsible for the program, including its development, coordination and supervision. Pampa also offers the Ethics Hotline, an exclusive channel to report, on a strictly confidential basis, any suspected misconduct or breach to the Code of Business Conduct. This tool is available through

different channels (toll-free telephone number, e-mail or website) and is managed by a third-party provider to ensure higher transparency and information integrity. Additionally, the Company has policies and procedures in place prescribing the way in which received complaints should be analyzed and dealt with.

The responsibility over this channel rests with the Audit Committee, which delegates its administration to the Internal Audit Department. At least quarterly, the Internal Audit Department reports the received cases and the adopted decisions to the Audit Committee. The Committee supervises the channel’s operations and

the resolution of complaints in issues within its authority.

https://ri.pampaenergia.com/en/corporate-governance/code-of-business-conduct/


24. The Board ensures the existence of formal mechanisms to prevent and address

conflict of interest. In related-party transactions, the Board approves a policy

that establishes the role of each corporate body and defines how to identify,

manage and disclose transactions which are detrimental to the company or only

to certain investors.

The Code of Business Conduct’s guidelines provide that individuals within the scope of this one should avoid any situation resulting in a conflict between their own personal interests and the Company’s, thus preventing their personal or family interests from exerting any influence on their decisions and/or professional performance.

Pampa has a policy on Related-Party Transactions Approval in place whereby all transactions (i) deemed high-value transactions, that is, with a value equal to or higher than 1% of Pampa’s Shareholders Equity; (ii) made with individuals and/or legal entities which, pursuant to Sect. 72 of the CMA, are

considered related parties, should be subject to a specific prior authorization and control procedure carried out under the coordination of Pampa’s Legal Affairs Executive Department, with the participation of both the Board and its Audit Committee (as applicable). This Policy strictly follows the guidelines set out in the laws and regulations in force in this matter (Sect. 72 of the CMA).

Additionally, Pampa presents itemized information on any contract entered into with related parties in its annual and interim FS; moreover, in compliance with the regulations in force, all high-value transactions executed by Pampa with related parties are submitted to the consideration of the Audit

Committee and promptly reported under the caption ‘relevant event’ to both the CNV and the markets where the Company quotes its shares.

Finally, the Audit Committee is responsible, among other duties, for providing the market with full information on transactions where there may be a conflict of interest with members of corporate bodies or controlling shareholders, and issuing well-founded opinion on related-party transactions in the cases provided by law; it is also responsible for disclosing them in compliance with law whenever there is or may

be an alleged conflict of interest within Pampa. Moreover, every time the Board has to address an issue where a director may have a personal interest, that director is prevented from voting. In the way described,

the Company applies this practice.

G. Shareholder and Stakeholder Participation: Principles xix through xxii -

Practices 25 through 29

Principles

xix. The Company should give equal treatment to all its shareholders. It should guarantee equal access to non-confidential information that is relevant for decision-making at the Company’s Shareholders’ Meetings.

xx. The Company should promote the active involvement by all shareholders based on appropriate information, especially regarding the composition of the Board.

xxi. The Company should have a transparent Dividend Distribution Policy aligned with the strategy.

xxii. The Company should take into consideration the interests of its stakeholders.

25. The Company’s website discloses financial and non-financial information,

providing timely and equal access to all investors. The website has a specialized

area to address investors’ inqueries.

Pampa applies the recommended practice as it has a website with a special ‘Investors’ section, including all types of relevant information (FS, filings before regulatory authorities —including the SEC and

https://ri.pampaenergia.com/en/


the NYSE—, relevant events, corporate governance policies, etc.) for its shareholders and the general investment community, which is permanently updated by the Investor Relations office.

In turn, this special section in the website operates as a channel for inqueries, which are received

and managed by the specialized area in charge of shareholder and investor relations.

Additionally, the Company has presence in social media (Facebook, Instagram, Twitter and LinkedIn) through which it not only publishes relevant information but also interacts with its followers.

26. The Board should ensure a process in place for the identification and

classification of its stakeholders, as well as a communication channel for them.

Engagement and dialog with our internal or external stakeholders are an essential aspect of the

process for the definition of the Company’s material topics. Before this fiscal year and following the guidelines offered by AA1000SES - Accountability, we have started developing a multidimensional assessment system to identify our main stakeholders (based on accountability, influence, proximity, dependence and representation). Moreover, the Company lists its main stakeholders in the Sustainability Report issued on an annual basis and published in our website. Through this process, the Company applies the recommended practice.

The different dialog and communication channels with Pampa’s stakeholders are detailed below:

Employees: information-sharing meetings with the founding shareholders, internal website - intranet, Nexo - Human Resources channel, ethics hotline, Sustainability Report, Kaizala internal messaging network and social media.

Government: accountability under the regulations in force, Annual Report and Financial Statements, meetings with government officers, ethics hotline, Sustainability Report and social

media.

Community: Social Responsibility Committee, ethics hotline, Sustainability Report, meetings on

social investment programs and social media.

Investors: Annual Report and Financial Statements, 20-F Form, reports requested by the CNV and the SEC, quarterly earnings releases, earnings conference calls, ethics hotline, Sustainability

Report, investor website - ri.pampaenergia.com, and social media.

Suppliers: meetings with suppliers, ethics hotline, Sustainability Report, SAP ARIBA platform and social media.

Customers: institutional website - www.pampaenergia.com/en, customer service channel, ethics hotline, Sustainability Report and social media.

Corporate Associations: ethics hotline, industry meetings and social media.

Media: institutional website - www.pampaenergia.com/en, Annual Report and Financial Statements, ethics hotline and social media.

Unions: meetings with union representatives, ethics hotline, Sustainability Report and social media.

https://www.facebook.com/PampaEnergia/

https://www.instagram.com/pampaenergia/

https://twitter.com/pampaenergia

https://www.linkedin.com/company/pampa-energia/

https://ri.pampaenergia.com/en/sustainability/

https://ri.pampaenergia.com/en/sustainability/


http://www.pampaenergia.com/en

http://www.pampaenergia.com/en


27. Prior to a Shareholders’ Meeting, the Board submits —through a formal

communication channel— a ‘provisional information package’ allowing

shareholders to make non-binding comments and to share dissenting opinions

on the recommendations issued by the Board, and the latter will expressly issue

its opinion on the received comments as it deems necessary.

When calling for a meeting, the Board formulates proposals regarding each item in the agenda, except in cases there may be possible conflict of interest, where it will refrain from submitting a proposal. Any information supporting the topics to be addressed in the Shareholders’ Meetings are placed at the disposal of all shareholders well in advance so that they may perform their analysis and vote accordingly.

Both the shareholders and the general investment community may make the inqueries they deem necessary through the formal channel mentioned in Practice 25 in Appendix I to this Annual Report. This allows shareholders to attend the Meeting with information on the topics to be discussed which is precise

and has been received well in advance.

It is worth highlighting that Pampa provides the necessary means to keep a permanent and fluid dialog with its shareholders, and not only at the time of calling for a Shareholders’ Meeting. In this sense, shareholders have at their disposal: (i) the communication channel described in Practice 25 in Appendix I to this Annual Report; (ii) the investor relations office, which receives and manages shareholders’ concerns; (iii) throughout the fiscal year, conference calls are organized at the end of each quarter to discuss the quarterly results and allow for interaction with the management; and (iv) the attendance of management

and Board members to the Shareholders’ Meeting, with the possibility to raise questions not only on each item of the agenda, but also on the Company’s management once the treatment of all formal items has concluded. In the way described, the Company applies the practice.

28. The Company’s Bylaws contemplate that shareholders may receive the

information packages for Shareholders’ Meetings through electronic means and

participate in Shareholders’ Meetings virtually, allowing for the simultaneous

transmission of sound, images and words, ensuring compliance with the

principle of equal treatment to participants.

Although they are not contained in the Company’s Bylaws, Pampa’s application of the principles

since the proposals mentioned in the previous item are placed at the disposal of Shareholders and the general investment community not only through the communication maners established by the regulatory bodies (ByMA, CNV, SEC), but also on the Company’s website, ri.pampaenergia.com. Moreover, as it has been previously mentioned, shareholders have the means to keep a permanent and fluid dialog with the Company throughout the year.

Pampa’s Bylaws currently do not contemplate the holding of Shareholders’ Meetings by electronic means of communication allowing for the simultaneous transmission of sound, images and words. The

Company will analyze the appropriateness of its implementation.

29. The Dividend Distribution Policy is aligned with the strategy and clearly

establishes the criteria, frequency and conditions under which dividends will be

distributed.

Since in 2018, the Company applies the recommended practice of Dividend Policy, approved by the Board. Said policy sets out the guidelines to be followed to reach a proper balance between distributed amounts and Pampa’s investment plans, aiming at a clear, transparent and consistent practice, allowing shareholders to make informed decisions, all of this in line with the Company’s Bylaws and the applicable legal and regulatory framework in force. Based on this policy, the Board of Directors assesses the possibility to pay dividends to Pampa’s shareholders on a prudential basis within each fiscal year, thoroughly

evaluating the economic circumstances prevailing at the time.


7 B24note

CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2019 AND 2018, AND

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(In millions of Pesos (“$”))

Report of Independent Registered Public Accounting Firm

1

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 and 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. (antes PEA)

CTEB Central Térmica Ensenada Barragán

2

GLOSSARY OF TERMS: (Continuation)

Terms Definitions

CTG Central Térmica Güemes S.A.

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. (ex 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

3


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. (Ex “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.

PISA Pampa Inversiones S.A.

4


Terms Definitions

PIST Transportation System Entry Point

PP Pampa Participaciones S.A.

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 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.

5


Terms Definitions

TV Vapor Turbine

U$S U.S. dollar

UTE Senillosa Petrolera Pampa S.A. – Rovella Carranza – Gas y Petróleo de 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.

6

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2019, 2018 and 2017

(In millions of Pesos (“$”) – unless otherwise stated)

Note 12.31.2019 12.31.2018 12.31.2017

Revenue 8 154,642 110,080 82,008

Cost of sales 9 (112,433) (74,161) (59,339)

Gross profit 42,209 35,919 22,669

Selling expenses 10.1 (8,645) (6,451) (4,776)

Administrative expenses 10.2 (9,179) (7,751) (7,481)

Exploration expenses 10.3 (463) (45) (71)

Other operating income 10.4 2,088 6,842 5,608

Other operating expenses 10.4 (4,617) (7,526) (3,892)

Impairment of property, plant and equipment and intangible

assets11.1.1 (3,713) (1,195) -

Share of profit from associates and joint ventures 5.3.2 5,855 4,464 1,813

Income from the sale of associates 5.1.2.2 - 1,052 -

Agreement on the regularization of obligations 2.3.4 17,095 - -

Operating income 40,630 25,309 13,870

Gain on monetary position, net 11,186 23,696 11,478

Finance income 10.5 4,483 3,751 2,333

Finance costs 10.5 (15,759) (11,944) (8,750)

Other financial results 10.5 4,891 (32,365) (3,774)

Financial results, net 4,801 (16,862) 1,287

Profit (loss) before income tax 45,431 8,447 15,157

Income tax 10.6 (6,124) (658) 985

Profit of the year from continuing operations 39,307 7,789 16,142

Profit (loss) of the year from discontinued operations 5.2.3 - 3,019 (1,893)

Profit of the year 39,307 10,808 14,249

Other comprehensive income (loss)

Items that will not be reclassified to profit or loss

Results related to defined benefit plans 103 (160) (13)

Income tax (26) 41 4

Share of loss from joint ventures - (19) -

Exchange differences on translation 46,570 - -

Items that may be reclassified to profit or loss

Exchange differences on translation (1,345) 19 111

Other comprehensive income (loss) of the year from continuing

operations45,302 (119) 102

Other comprehensive income of the year from discontinued

operations5.2.3 - 312 (533)

Other comprehensive income (loss) of the year 45,302 193 (431)

Total comprehensive income of the year 84,609 11,001 13,818

7

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2019, 2018 and 2017 (Continuation)


Note 12.31.2019 12.31.2018 12.31.2017

Total income of the year attributable to:

Owners of the company 33,012 8,435 10,799

Non - controlling interest 6,295 2,373 3,450

39,307 10,808 14,249

Total income (loss) of the year attributable to owners of the

company:

Continuing operations 33,012 5,506 12,867

Discontinued operations - 2,929 (2,068)

33,012 8,435 10,799

Total comprehensive income of the year attributable to:

Owners of the company 69,616 8,474 10,588

Non - controlling interest 14,993 2,527 3,230

84,609 11,001 13,818

Total comprehensive income (loss) of the year attributable to

owners of the company:

Continuing operations 69,616 5,297 12,940

Discontinued operations - 3,177 (2,352)

69,616 8,474 10,588

Earnings (losses) per share attributable to the equity holders of

the company during the year

Basic and diluted earnings per share from continuing operations 13.2 18.35 2.81 6.65

Basic and diluted earnings (loss) per share from discontinued

operations13.2 - 1.50 (1.07)

Total basic and diluted earnings per share 13.2 18.35 4.31 5.58

The accompanying notes are an integral part of these Consolidated Financial Statements.

8

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2019 and 2018


Note 12.31.2019 12.31.2018

ASSETS

NON-CURRENT ASSETS

Property, plant and equipment 11.1 210,056 125,005

Intangible assets 11.2 9,068 6,080

Right-of-use assets 18.1.1 930 -

Deferred tax assets 11.3 1,702 80

Investments in joint ventures and

associates5.3.2 30,638 15,333

Financial assets at amortized cost 12.1 1,048 -

Financial assets at fair value through profit

and loss12.2 671 422

Other assets 45 33

Trade and other receivables 12.3 4,711 9,521

Total non-current assets 258,869 156,474

CURRENT ASSETS

Inventories 11.4 9,175 5,169

Financial assets at amortized cost 12.1 3,224 1,330


and loss12.2 21,867 15,273

Derivative financial instruments 214 3

Trade and other receivables 12.3 33,583 26,489

Cash and cash equivalents 12.4 13,496 9,097

Total current assets 81,559 57,361

Total assets 340,428 213,835

9

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2019 and 2018 (Continuation)


Note 12.31.2019 12.31.2018

SHAREHOLDERS´ EQUITY

Share capital 13.1 1,677 1,874

Share capital adjustment 13.1 9,826 9,826

Share premium 13.1 19,570 18,499

Treasury shares 13.1 71 25

Treasury shares adjustment 13.1 27 134

Treasury shares cost 13.1 (2,527) (1,490)

Legal reserve 1,753 904

Voluntary reserve 17,727 7,355

Other reserves (771) (483)

Retained earnings 51,844 15,193

Other comprehensive income 15,668 (314)

Equity attributable to owners of the company 114,865 51,523

Non-controlling interest 29,397 16,160

Total equity 144,262 67,683

LIABILITIES

NON-CURRENT LIABILITIES

Investments in joint ventures and

associates5.3.2 265 153

Provisions 11.5 8,703 5,499

Income tax and minimum notional income tax

provision11.6 590 1,034

Deferred revenue 270 275

Taxes payables 11.7 263 542

Deferred tax liabilities 11.3 22,068 15,354

Defined benefit plans 11.8 1,606 1,175

Salaries and social security payable 11.9 241 163

Borrowings 12.5 105,629 69,189

Trade and other payables 12.6 5,419 8,162

Total non-current liabilities 145,054 101,546

CURRENT LIABILITIES

Provisions 11.5 1,206 871

Deferred revenue 5 5

Income tax and minimum notional income tax

provision11.6 3,154 1,084

Taxes payables 11.7 4,316 2,052

Defined benefit plans 11.8 230 162

Salaries and social security payable 11.9 3,834 2,726

Derivative financial instruments 204 49

Borrowings 12.5 10,974 12,901

Trade and other payables 12.6 27,189 24,756

Total current liabilities 51,112 44,606

Total liabilities 196,166 146,152

Total liabilities and equity 340,428 213,835


10

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the years ended December 31, 2019, 2018 and 2017


Share capitalShare capital

adjustmentShare premium

Treasury

shares

Treasury shares

adjustment

Treasury

shares costLegal reserve

Voluntary

reserve

Other

reserves (1)

Other

comprehensiv

e income /

(loss)

Retained

earnings

(Accumulated

losses)

Subtotal

Non-

controlling

interest

Total equity

Balance as of December 31, 2016 1,938 10,838 15,870 - - - 567 9,422 333 (142) 4,305 43,131 17,515 60,646

Constitution of legal reserve - Shareholders’ meeting 04.07.2017 - - - - - - 166 - - - (166) - - -

Constitution of voluntary reserve - Shareholders’ meeting 04.07.2017 - - - - - - - 3,132 - - (3,132) - - -

Stock compensation plans - - 24 - - - - - 34 - - 58 7 65

Acquisition of own shares (3) (1) - 2 13 (126) - - - - - (115) - (115)

Merger with subsidiaries (Note 5.1.1.1) 145 69 2,602 - - - - - - - - 2,816 (2,816) -

Dividends provided for pay - - - - - - - - - - - - (144) (144)

Profit of the year - - - - - - - - - - 10,799 10,799 3,450 14,249

Other comprehensive income for the year - - - - - - - - - (211) - (211) (220) (431)

Balance as of December 31, 2017 2,080 10,906 18,496 2 13 (126) 733 12,554 367 (353) 11,806 56,478 17,792 74,270

Change in accounting policies (2)

- - - - - - - - - - (55) (55) (25) (80)

Balance as of Juanary 1, 2018 2,080 10,906 18,496 2 13 (126) 733 12,554 367 (353) 11,751 56,423 17,767 74,190

Constitution of legal reserve - Shareholders’ meeting 04.27.2018 - - - - - - 171 - - - (171) - - -

Constitution of voluntary reserve - Shareholders’ meeting 04.27.2018 - - - - - - - 4,822 - - (4,822) - - -

Stock compensation plans - - 3 - (1) 9 - - 14 - - 25 - 25

Acquisition of own shares (Note 13.1.1.2) (206) (1,080) - 206 1,080 (12,535) - - (864) - - (13,399) (534) (13,933)


Capital reduction (Note 13.1.1) - - - (183) (958) 11,162 - (10,021) - - - - - -

Sale of interest in subsidiaries - - - - - - - - - - - - (3,518) (3,518)

Profit for the year - - - - - - - - - - 8,435 8,435 2,373 10,808

Other comprehensive income for the year - - - - - - - - - 39 - 39 154 193

Balance as of December 31, 2018 1,874 9,826 18,499 25 134 (1,490) 904 7,355 (483) (314) 15,193 51,523 16,160 67,683

Equity holders of the company Retained earnings

Attributable to owners

11

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Continuation) For the years ended December 31, 2019, 2018 and 2017


Share capitalShare capital

adjustmentShare premium

Treasury

shares

Treasury shares

adjustment

Treasury

shares costLegal reserve

Voluntary

reserve

Other

reserves (1)

Other

comprehensiv

e income /

(loss)

Retained

earnings

(Accumulated

losses)

Subtotal

Non-

controlling

interest

Total equity

Balance as of December 31, 2018 1,874 9,826 18,499 25 134 (1,490) 904 7,355 (483) (314) 15,193 51,523 16,160 67,683

Constitution of legal and voluntary reserve - Shareholders’ meeting

04.29.2019 - - - - - - 849 16,134 - - (16,983) - - -

Stock compensation plans 1 - 2 - (2) 14 - - 23 - - 38 - 38


Acquisition of own shares (Note 13.1.1.2) (198) - 1,069 198 - (7,070) - - (311) - - (6,312) (1,699) (8,011)

Capital reduction (Note 13.1.1) - - - (152) (105) 6,019 - (5,762) - - - - - -

Profit for the year - - - - - - - - - - 33,012 33,012 6,295 39,307

Other comprehensive income for the year - - - - - - - - - 15,982 20,622 36,604 8,698 45,302

Balance as of December 31, 2019 1,677 9,826 19,570 71 27 (2,527) 1,753 17,727 (771) 15,668 51,844 114,865 29,397 144,262

Attributable to owners

Equity holders of the company Retained earnings

(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


12

CONSOLIDATED STATEMENT OF CASH FLOWS For the years ended December 31, 2019, 2018 and 2017


Note 12.31.2019 12.31.2018 12.31.2017

Cash flows from operating activities:

Profit of the year from continuing operations 39,307 7,789 16,142

Profit (loss) of the year from discontinued operations - 3,019 (1,893)

Adjustments to reconcile net profit (loss) to cash flows generated by

operating activities: 14.1315 23,548 5,771

Changes in operating assets and liabilities 14.2 (1,911) (9,700) (6,676)

Net cash used in operating activities from discontinued operations 5.2.3 - (1,726) 3,291

Net cash generated by operating activities 37,711 22,930 16,635

Cash flows from investing activities:

Payment for property, plant and equipment (28,813) (25,407) (18,290)

Payment for acquisitions of intangible assets - (6) -

Collection (payment) for financial assets 11,322 (1,178) (4,118)

Payments for capital integration in associates and joint ventures (4,794) - -

Proceeds from sale of intangible assets - 87 -

Collections for sales of shares in companies and property, plant and

equipment2,187 17,240 548

Dividends received 3,798 735 40

Colletion (proceeds) from loans 215 (167) 38

Recovery of investment funds, net (1,107) 9,436 (8,259)

Net cash used in investing activities from discontinued operations5.2.3

- - (1,897)

Net cash (used in) generated by investing activities (17,192) 740 (31,938)

Cash flows from financing activities:

Proceeds from borrowings 12.5 25,808 9,250 47,130

Payment of borrowings 12.5 (26,869) (9,057) (27,650)

Payment of borrowings interests 12.5 (6,651) (5,004) (4,072)

Payment for acquisition of own shares (8,011) (13,933) (115)

Payments of dividends from subsidiaries to third parties (57) (82) (74)

Repurchase and redemption of corporate bonds 12.5 (5,107) (448) (47)

Payments of leases (285) - -

Net cash generated by (use in) financing activities from discontinued

operations 5.2.3- 1,565 (1,168)

Net cash (used in) generated by financing activities (21,172) (17,709) 14,004

Increase (decrease) in cash and cash equivalents (653) 5,961 (1,299)

Cash and cash equivalents at the begining of the year 12.4 9,097 1,179 2,613

Cash and cash equivalents at the begining of the year reclasified to

assets classified as held for sale- 238 (238)

Exchange difference generated by cash and cash equivalents 5,067 2,011 509

Loss on net monetary position generated by cash and cash equivalents (15) (292) (406)

Increase (decrease) in cash and cash equivalents (653) 5,961 (1,299)

Cash and cash equivalents at the end of the year 12.4 13,496 9,097 1,179


13

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017

(In millions of $ – 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.




14

NOTE 1: (Continuation)

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);




15


- 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.




16

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.

The Company’s generating units are detailed below:

In operation:

CTG GUEMTG01 TG 100 MW Energy Plus Res. No. 1281/2006 (1)

CTG GUEMTV11 TV ≤100 MW SE Resolutions No. 1/2019

CTG GUEMTV12 TV ≤100 MW SE Resolutions No. 1/2019

CTG GUEMTV13 TV >100 MW SE Resolutions No. 1/2019

Piquirenda PIQIDI 01-10 MG 30 MW SE Resolution No. 220/2007 (1)

CPB BBLATV29 TV >100 MW SE Resolutions No. 1/2019

CPB BBLATV30 TV >100 MW SE Resolutions No. 1/2019

CT Ing. White BBLMD01-06 MG 100 MW SEE Resolution No. 21/2016 (1)

CTLL LDLATG01 TG >50 MW SE Resolutions No. 1/2019



CTLL LDLATG04 TG 105 MW SEE Res. 220/2007 (75%), SEE Res. 1/2019 (25%)

CTLL LDLATG05 TG 105 MW SEE Resolution No. 21/2016 (1)

CTLL LDLATV01 TV 180 MW SE Resolution No. 220/2007 (1)

CTGEBA GEBATG01/TG02/TV01 CC >150 MW SE Resolutions No. 1/2019

CTGEBA GEBATG03 TG 188 MW Energy Plus Res. No. 1281/2006 (1)

CTGEBA GEBATG04 TG >100 MW SE Resolutions No. 1/2019 (3)

Ecoenergía CERITV01 TV Renewable ≤ 50 Energy Plus Res. N° 1281/2006 (1)

CT Parque Pilar PILBD01-06 MG 100 MW SE Resolutions No. 1/2019 (3)

CTB EBARTG01 - TG02 TG HI – Small 50<P≤120 SE Resolution No. 220/2007 (1)

HIDISA AGUA DEL TORO HI HI – Small 50<P≤120 SE Resolutions No. 1/2019

HIDISA EL TIGRE HI HI – Small 50<P≤120 SE Resolutions No. 1/2019

HIDISA LOS REYUNOS HB HB – Media 120<P≤300 SE Resolutions No. 1/2019

HINISA NIHUIL I - II - III HI HI – Chica 50<P≤120 SE Resolutions No. 1/2019

HPPL PPLEHI HI HI – Media 120<P≤300 SE Resolutions No. 1/2019

P.E. M. Cebreiro CORTEO Eólica 100 MW Renovar (1)

PEPE II PAMEEO Eólica 53 MW SEE Resolution No. 281/2017

PEPE III BAHIEO Eólica 53 MW SEE Resolution No. 281/2017

In construction:

CTLL MG 15 MW SE Resolutions No. 1/2019

CTGEBA CC 176 MW SE Resolution No. 287/2017

CTB CC 280 MW SE Resolution No. 220/2007

Generator Generating unit Tecnology Power Applicable regime (2)

(1) Uncommitted power and energy is remunerated according to Resolution No. 1/2019.

(3) Once the combined cycle is commercially enabled, the supply agreements with CAMMESA will come into force under Resolution No. 287/2017.

(2) Resolution No. 1/2019 entered into force as of February 2019. During the month of January 2019, it was remunerated under Resolution No. 19/2017.

Generating unit Tecnology Applicable regimeGenerator




17


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.




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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




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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$S 7.5/MWh and an

additional price of U$S 17.5/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$S 5

and U$S 10/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$S 2.0/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 from U$S1.4 to U$S 3.5/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.




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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$S 2.6/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$S 1/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.




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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.




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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.




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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




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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.




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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 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 $ 260 million and net

financial profits for $ 3,119.3 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.

https://www.boletinoficial.gob.ar/detalleAviso/primera/215920/20190909




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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.




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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 $ 6.6 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.




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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.




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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.




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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 $ 1,159.2 million, 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 $ 3,993.5 million.

Additionally, Edenor has a receivable for $ 251.4 million for the same concept.




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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.




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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 $ 17,095 million, 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 $

1,468 million totaling a liability pending application of $ 4,648 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.




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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:




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- 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 $ 591 million, and for the first five months of 2019 for $ 220,

both related to the Federal Government’s participation




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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.




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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.




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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.




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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”.




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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.




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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 $ 41 million, with the 29

installments and the corresponding update still pending collection, for which it keeps a receivable of $ 877 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.




41


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.




42


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.




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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.




44


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.




45


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.




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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.




47


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.




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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.




49


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 $ 1,495 million plus

interest for $ 45 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.




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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.




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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 $ 558 million.




52

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 24, 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.




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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.

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.




54

NOTE 4: ACCOUNTING POLICIES

The main accounting policies used in the preparation of these Consolidated Financial Statements are explained

below.

4.1 New accounting standards, amendments and interpretations issued by the IASB effective as of December

31, 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.




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Management has reviewed effective lease contracts and has recognized a right-of-use asset in the amount of

$ 471 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 396

Discount using incremental borrowing rate of 58,16% as

of 01.01.2019(90)

Exchange differences on translation 165

Lease liability recognised as of 01.01.2019 471

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.




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- 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 in U.S. dollars, which is the

Company’s functional currency, that is, the currency of the primary economic environment where the entity operates

and, pursuant to the CNV’s requirements, is presented in pesos, the legal currency in Argentina.

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 presentation currency

The Company applies the step-by-step method of consolidation; consequently, the financial statements of entities

with a functional currency different from the U.S. dollar are first translated into the Company’s functional currency

and later into the presentation currency.

The results and financial position of the Company, its subsidiaries, joint ventures and associates with the U.S. dollar

as their functional currency are translated into the presentation currency at the end of each period using the

following method:

- assets and liabilities are translated at the year-end exchange rates;

- income and expenses are translated at the exchange rate in effect on the date of each transaction;

- results from the translation of functional into presentation currency are recognized under “Other comprehensive

income”.




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The results and financial position of subsidiaries, joint ventures and associates whose functional currency is

argentine peso, a currency of a hyperinflationary economy, are translated into the presentation 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 translation

differences generated by results (at opening balance and for the year) of the Company and its subsidiaries, joint

ventures and associates which functional currency is the U.S. dollar.

The Company classifies and directly accumulates within equity, in the retained earnings line, the results generated

by the application of IAS 29 adjustment mechanism on the opening retained earnings measured in functional

currency, 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.

As a result of the application of the described policy, the translation of the functional currency into a different

presentation currency does not change the way in which the underlying items are measured, preserving the amounts,

both retained earnings and equity holders, measured in the functional currency in which they are generated.

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.




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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.




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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.




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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 U.S. dollars 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.




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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.




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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.




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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.




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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.




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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).




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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.




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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.




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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 and the translation differences attributable to equity. 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.




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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.

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.




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ii. 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.




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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.




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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.




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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




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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.




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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.




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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.




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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.




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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.




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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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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.

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.




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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 $ 1,052 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.




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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 $ 1,115 million, as follows:

Petróleo y gas

12.31.2018

Sale price 10,197

Book value of assets sold and costs associated with the

transaction(8,553)

Result for sale 1,644

Interests (1)

133

Income tax (818)

Imputed in results 959


Reclasification exchange differences on translation 223

Income tax (67)

Imputed in Other comprehensive income 156

Total comprehensive income 1,115 (1) Are exposed in "Financial income" in the consolidated statement of comprehensive income related to discontinued operations.

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.




83


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 $ 1,040 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 1,044

Book value of assets sold and costs associated with the

transaction(1,044)

Result for sale -

Income tax -

Total result -

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.




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5.2.3 Relevant information on discontinued operations

As of December 31, 2018:

Oil and gasRefining and

distributionEliminations Total

Revenue 2,481 15,900 (3,388) 14,993

Cost of sales (1,233) (13,606) 3,419 (11,420)

Gross profit 1,248 2,294 31 3,573

Selling expenses (72) (1,243) - (1,315)

Administrative expenses (46) (152) - (198)

Exploration expenses (4) - - (4)

Other operating income 54 211 - 265

Other operating expenses (231) (378) - (609)

Result from the sale of share of profit and property, plant and

equipment1,644 - - 1,644

Operating income 2,593 732 31 3,356

Gain on monetary position, net 255 80 (47) 288

Finance income 148 27 - 175

Finance costs (20) (10) - (30)

Other financial results (135) 824 - 689

Financial results, net 248 921 (47) 1,122

Income (loss) before income tax 2,841 1,653 (16) 4,478-

Income tax (973) (486) - (1,459)

Profit (loss) of the year from discontinued operations 1,868 1,167 (16) 3,019



Income tax (67) - - (67)

Reclasification exchange differences on translation 223 223

Exchange differences on translation 156 - - 156

Other comprehensive loss of the year from discontinued

operations312 - - 312

Total comprehensive income (loss) of the year from

discontinued operations2,180 1,167 (16) 3,331



Total income (loss) of the tear from discontinued operations

attributable to:

Owners of the company 1,778 1,167 (16) 2,929

Non - controlling interest 90 - - 90

1,868 1,167 (16) 3,019


discontinued operations attributable to:

Owners of the company 2,026 1,167 (16) 3,177


2,180 1,167 (16) 3,331




85


As of December 31, 2017:



Revenue 9,755 27,439 (11,177) 26,017

Cost of sales (9,468) (23,313) 11,211 (21,570)

Gross profit 287 4,126 34 4,447

Selling expenses (298) (3,192) - (3,490)

Administrative expenses (208) (703) - (911)

Exploration expenses (31) - - (31)

Other operating income 604 365 - 969

Other operating expenses (294) (484) - (778)

Result from the sale of property, plant and equipment - (1,040) - (1,040)

Operating income 60 (928) 34 (834)

Financial income 36 25 - 61

Financial expenses - (27) - (27)

Other financial results (375) (20) - (395)

Financial results, net (339) (22) - (361)

Income (loss) before income tax (279) (950) 34 (1,195)-

Income tax (1,049) 351 - (698)

Profit (loss) of the year from discontinued operations (1,328) (599) 34 (1,893)



Remeasurements related to defined benefit plans (11) 26 - 15

Income tax 67 (9) - 58

Exchange differences on translation (606) - - (606)

Other comprehensive loss of the year from discontinued

operations(550) 17 - (533)


discontinued operations(1,878) (582) 34 (2,426)



Total income (loss) of the year from discontinued operations

attributable to:

Owners of the company (1,503) (599) 34 (2,068)


(1,328) (599) 34 (1,893)


discontinued operations attributable to:

Owners of the company (1,804) (582) 34 (2,352)

Non - controlling interest (74) - - (74)

(1,878) (582) 34 (2,426)

Oil and gas 00.01.00




86


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 (1,726) 3,291

Net cash used in investing activities - (1,897)

Net cash generated by (used in) financing activities 1,565 (1,168)

(Decrease) increase in cash and cash equivalents from discontinued operations (161) 226

Cash and cash equivalents at the begining of the year 238 142

Loss on net monetary position generated by cash and cash equivalents (77) (130)

(Decrease) increase in cash and cash equivalents (161) 226

Cash and cash equivalents at the end of the year - 238




87


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.




88


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 101,597 63,284

Borrowings 8,197 7,192

Other non current liabilities 27,542 17,853

Total non current liabities 35,739 25,045

Current

Cash and cash equivalents 410 28

Other current assets 17,466 13,680


Borrowings 1,659 1,077

Other current liabilities 22,924 19,901


Total equity 59,151 30,969

Non-controlling interest 26,993 14,938




89


5.3.1.1.2 Edenor´s Summary statement of comprehensive income

12.31.2019 12.31.2018 12.31.2017

Revenue 89,944 55,954 39,603

Depreciation (4,625) (2,561) (2,148)

Interest income 1,209 672 454

Interest expense (6,745) (4,968) (2,567)

(Loss) Profit for the year before tax 22,808 6,175 5,591

Income tax (10,674) (1,877) (510)

(Loss) Profit for the year 12,134 4,298 5,081

Other comprehensive loss (5) (47) (14)

Total comprehensive (loss) profit of the year 12,129 4,251 5,067

Income (loss) of the year attributable to non-controlling

interest5,853 2,073 2,462

Other comprehensive income of the year attributable to non-

controlling interest(2) (22) (7)

Comprehensive income of the year attributable to non-

controlling interest5,851 2,051 2,455

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 10,158 9,621 2,931

Net cash used in investing activities (5,156) (8,327) (2,373)

Net cash used in financing activities (5,071) (2,097) (493)

(Decrease) increase in cash and cash equivalents (69) (803) 65

Cash and cash equivalents at the begining of the year 42 122 129

Loss on net monetary position generated by cash and cash

equivalents437 709 65

Cash and cash equivalents at the end of the year 410 28 259




90


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:

Main activity Date Share capital

Profit (loss)

of the period /

year

Equity

Direct and

indirect

participation

%

Associates

Refinor Refinery 09.30.2019 92 (181) 3,433 28.50%

OCP (1)

Investment 12.31.2019 6,016 951 15,943 15.91%

TGS (2)(5)

Transport of gas 12.31.2019 785 12,805 48,083 27.193%

CIESA (2)

Investment 12.31.2019 639 6,169 24,234 50%

Citelec (3)

Investment 12.31.2019 556 2,258 10,548 50%

Greenwind Generation 12.31.2019 5 (14) (688) 50%

CTB (4)

Generation 12.31.2019 8,558 2,370 13,619 50%

Information about the issuer

Joint ventures

(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.




91


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 1,188 960

OCP 1,974 1,305

TGS 1,293 -

Other 12 10

4,467 2,275

Joint ventures

CIESA 14,088 9,755

Citelec 5,274 3,303

CTB 6,809 -

26,171 13,058

30,638 15,333

Disclosed in non-current liabilities

Greenwind (1)

265 153 (1) The Company provides financial assistance to this company.




92


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 - 116 41

Refinor (135) (138) (113)

OCP 901 1,305 -

TGS 54 - -

Other 1 1 (3)

821 1,284 (75)

Joint ventures

CIESA 2,970 2,793 949

CTB 945 - -

Citelec 1,129 801 1,012

Greenwind (10) (414) (73)

5,034 3,180 1,888

5,855 4,464 1,813

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 15,180 11,875 9,608

Reclassifications (1)

(691) - 457

Dividends 17 (4,371) (706) -

Decreases - (434) (3)

Increases 4,770 - -

Share of profit 5,855 4,464 1,813

Other comprehensive loss - (19) -


At the end of the year 30,373 15,180 11,875

(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.




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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.




94


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.




95


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.




96


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 $

Total consideration transferred (1) (11,530)

Financial assets at fair value 704

Property, plant and equipment: 20,333

Inventories 329

VRDs (9,836)

Fair value of net assets 11,530

(1) Includes $ 9,835 million offered in the Tender, net of $ 580 million of a price adjustment in favor of CTB and $ 2,275 million for the

purchase of the acquired VRDs.

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.




97


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.




98


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.




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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.




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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%.




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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.




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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:

Name Note Location Direct Indirect Operator

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

Participation Duration

Up To

(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.




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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.




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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 727 452 486

Increases 1,527 308 226

Transferred to development (682) (6) (216)

Loss of the year (296) (27) (44)

Traslation differences 685 - -

At the end of the year 1,961 727 452

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.




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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$S 40 million ($ 1,116 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.




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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.




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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.




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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.


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.




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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.




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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.




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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 $ 262 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 $ 630 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.




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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 $ 4,430 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 $ 1,237 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:

Financial assets 12.31.2019 12.31.2018

Shares 115 47

Government securities 678 1,123

Investment funds 1,461 400

Variation of the result of the year 2,254 1,570

Increase of the result for the year

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.




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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 8,589 550

U.S dollar 101,036 70,149

Subtotal loans granted at a fixed

interest rate 109,625 70,699

Floating interest rates:

Argentinian pesos 575 4,074

U.S dollar 3,827 4,950

Subtotal loans granted at a floating

interest rate 4,402 9,024

Non interest accrued

U.S dollar 995 1,165

Argentinian pesos 1,581 1,202

Subtotal no interest accrued 2,576 2,367

Total borrowings 116,603 82,090

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 $ 56 million.




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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 $ 17,862 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 $ 12,209 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 $ 9 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.




115


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 $ 3,601

million and $ 1,514 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%


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


Rest of business segments 0.32% 0.93% 8.11% 19.61% 35.69% 45.63% 59.00% 63.01%




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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 822 256

Adjustment to the opening balance of retained earnings 153 (39)

Loss allowance calculated under IFRS 9 as of 01.01.2018 975 217

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 $ 80 million, with counterpart in retained earnings of $ 55 million and in non-

controlling interest of $ 25 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 $ 90 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.




117

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 81,559 57,361

Current liabilities 51,112 44,606

Index 1.60 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.




118

As of December 31, 2019Trade and other

payables (1)

Borrowings Total

Less than three months 6 4,217 4,223

Three months to one year 27,182 12,007 39,189

One to two years 659 9,130 9,789

Two to five years 4,222 33,634 37,856

More than five years 539 36,844 37,383

Total 32,608 95,832 128,440

As of December 31, 2018Trade and other

payablesBorrowings Total

Less than three months 12,412 4,217 16,629

Three months to one year 20,072 12,007 32,079

One to two years 334 9,130 9,464

Two to five years 100 33,634 33,734

More than five years - 36,844 36,844

Total 32,918 95,832 128,750

(1) Includes Lease Liabilities (see Note 18.1.2)




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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 116,603 82,090

Less: cash and cash equivalents, and

financial assets at fair value through

profit and loss

(35,363) (24,370)

Net debt 81,240 57,720

Total capital attributable to owners 196,105 109,243

Leverage ratio 41.43% 52.84%

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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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 in U.S. dollars.

The information as of December 31, 2018 and 2017 disclosed below for comparative purposes arises from the

Consolidated Financial Statements denominated in pesos expressed in terms of the measuring unit current as of

December 31, 2018 in accordance with IAS 29 - “Financial Reporting in Hyperinflationary Economies”, and was

translated into U.S. dollars using the exchange rate as of that date.




121


in million of

pesos

Consolidated profit and loss information for the year ended

December 31, 2019Generation

Distribution

of energyOil and gas Petrochemicals

Holding and

othersEliminations Consolidated Consolidated

Revenue 819 1,502 174 321 20 - 2,836 154,642

Intersegment revenue - - 270 - - (270) - -

Cost of sales (466) (1,225) (313) (298) - 270 (2,032) (112,433)

Gross profit 353 277 131 23 20 - 804 42,209

Selling expenses (3) (122) (12) (9) (2) - (148) (8,645)

Administrative expenses (36) (65) (47) (4) (22) - (174) (9,179)

Exploration expenses - - (9) - - - (9) (463)

Other operating income 9 10 8 4 9 - 40 2,088

Other operating expenses (11) (43) (11) (9) (12) - (86) (4,617)

Impairment of property, plant and equipment (52) - (10) - - - (62)

Share of profit from associates and joint ventures 13 - 21 - 67 - 101 5,855

Agreement on the regularization of obligations - 285 - - - - 285 17,095

Operating income 273 342 71 5 60 - 751 44,343

Gain on net monetary position, net - 187 - - - - 187 11,186

Finance income 51 20 18 1 7 (1) 96 4,483

Finance costs (82) (112) (94) (8) (4) 1 (299) (15,759)

Other financial results 86 (62) 84 18 (13) - 113 4,891

Financial results, net 55 33 8 11 (10) - 97 4,801

Profit before income tax 328 375 79 16 50 - 848 49,144

Income tax (80) (178) (16) (5) 231 - (48) (6,124)

Profit for the year 248 197 63 11 281 - 800 43,020

Depreciation and amortization 71 79 112 1 - - 263 13,311

in millions of u$s




122


in million of

pesos



Distribution


Holding and


Total profit attributable to:

Owners of the company 239 98 63 11 281 - 692 33,012

Non - controlling interest 9 99 - - - - 108 6,295

Consolidated statement of financial position as of December 31, 2019

Assets 1,472 1,480 1,261 136 1,527 (192) 5,684 340,428

Liabilities 1,226 1,792 465 122 (160) (170) 3,275 196,166

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 30,426

Net book values of property, plant and equipment 1,152 1,691 612 18 34 - 3,507 210,056

in millions of u$s




123


in million of

pesos


December 31, 2018

GenerationDistribution


Holding and


Revenue 604 1,484 458 338 36 - 2,920 110,080

Intersegment revenue 2 - 63 - - (65) - -

Cost of sales (273) (1,136) (287) (334) - 63 (1,967) (74,161)

Gross profit (loss) 333 348 234 4 36 (2) 953 35,919

Selling expenses (1) (134) (19) (13) (4) - (171) (6,451)




Other operating expenses (17) (44) (114) (20) (6) 1 (200) (7,526)

Impairment of property, plant and equipment - - - (32) - - (32)

Share of profit (loss) from joint ventures and associates (11) - 37 - 92 - 118 4,464

Income from the sale of associates - - 28 - - - 28

Operating income (loss) 274 103 250 (62) 106 (1) 670 25,452

Gain on net monetary position 233 226 107 49 12 2 629 23,696

Finance income 52 18 15 1 14 (1) 99 3,751

Finance costs (85) (132) (79) (15) (6) 1 (316) (11,944)

Other financial results (365) (50) (512) (39) 108 - (858) (32,365)

Financial results, net (165) 62 (469) (4) 128 2 (446) (16,862)

Profit (loss) before income tax 109 165 (219) (66) 234 1 224 8,590

Income tax (3) (49) 57 12 (34) - (17) (658)

Profit (loss) for the year from continuing operations 106 116 (162) (54) 200 1 207 7,932

Profit for the year from discontinued operations - - 49 - 31 - 80 3,019

Profit (loss) for the year 106 116 (113) (54) 231 1 287 10,951

Depreciation and amortization 66 69 92 6 1 - 234 8,816

in millions of u$s




124


in million of

pesos



Distribution


Holding and

othersEliminations Consolidated

Consolidated

Total profit (loss) attributable to:

Owners of the company 100 61 (115) (54) 231 1 224 8,435

Non - controlling interest 6 55 2 - - - 63 2,373

Consolidated statement of financial position as of December 31,2018

Assets 1,414 2,133 1,237 153 872 (137) 5,672 213,835

Liabilities 1,054 1,241 1,273 198 247 (136) 3,877 146,152


Increases in property, plant and equipment 235 227 192 4 7 - 665 25,071

Net book values of property, plant and equipment 1,036 1,657 554 15 54 - 3,316 125,005

in millions of u$s




125


in million of

pesos



Distribution


Holding and


Revenue 351 1,050 443 314 17 - 2,175 82,008

Intersegment revenue 2 - 19 - - (21) - -

Cost of sales (195) (799) (310) (290) (1) 21 (1,574) (59,339)

Gross profit 158 251 152 24 16 - 601 22,669

Selling expenses (4) (95) (17) (12) - 1 (127) (4,776)




Other operating expenses (9) (33) (38) (10) (13) - (103) (3,892)

Share of profit (loss) from joint ventures and associates (2) - 1 - 49 - 48 1,813

Operating income (loss) 130 61 152 (11) 35 1 368 13,870

Gain (loss) on net monetary position 17 145 (18) 2 158 - 304 11,478

Finance income 39 12 6 - 7 (2) 62 2,333

Finance costs (69) (69) (78) (10) (8) 2 (232) (8,750)

Other financial results (34) 1 (93) (6) 32 - (100) (3,774)

Financial results, net (47) 89 (183) (14) 189 - 34 1,287

Profit (loss) before income tax 83 150 (31) (25) 224 1 402 15,157

Income tax (4) (12) 24 19 (1) - 26 985

Profit (loss) for the year from continuing operations 79 138 (7) (6) 223 1 428 16,142

(Loss) profit for the year from discontinued operations - - (35) - (16) 1 (50) (1,893)

Profit (loss) for the year 79 138 (42) (6) 207 2 378 14,249

Depreciation and amortization 54 58 87 4 2 - 205 7,739

in millions of u$s




126


in million of

pesos



Distribution


Holding and


Total profit (loss) attributable to:

Owners of the Company 75 73 (62) (6) 207 2 289 10,848

Non - controlling interest 4 65 20 - - - 89 3,401

Consolidated statement of financial position as of December 31,2017

Assets 1,115 1,972 1,154 141 1,475 (200) 5,657 213,255

Liabilities 333 1,166 444 94 1,850 (200) 3,687 138,985


Increases in property, plant and equipment 275 225 140 5 12 - 657 24,787

in millions of u$s

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.




127

NOTE 8: REVENUE

12.31.2019 12.31.2018 12.31.2017

Energy sales to the Spot Market 12,161 10,311 8,719

Energy sales by supply contracts 14,022 10,483 4,304

Fuel self-supply 13,366 1,918 150

Other sales 104 51 77

Generation sales subtotal 39,653 22,763 13,250

Energy sales 89,573 55,690 39,328

Right of use of poles 283 190 213

Connection and reconnection charges 87 74 62

Distribution of energy sales subtotal 89,943 55,954 39,603

Oil, gas and liquid sales 8,349 17,123 15,766

Other sales 137 138 929

Oil and gas sales subtotal 8,486 17,261 16,695

Technical assistance services and

administartion sales1,017 1,347 627

Other 20 7 8

Holding and others subtotal 1,037 1,354 635

Petrochemicals sales 15,523 12,748 11,825

Petrochemicals sales subtotal 15,523 12,748 11,825

Total revenue 154,642 110,080 82,008

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 $ 136,311 million, $ 95,844 million and $ 74,492 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

$ 18,331 million, $ 14,236 million and $ 7,516 million as of December 31, 2019, 2018 and 2017,

respectively.




128

NOTE 9: COST OF SALES

12.31.2019 12.31.2018 12.31.2017

Inventories at the beginning of the year 5,169 4,266 6,191

Plus: Charges for the year

Purchases of inventories, energy and gas 74,989 46,175 32,903

Salaries and social security charges 9,082 6,807 7,602

Benefits to employees 444 218 267

Accrual of defined benefit plans 382 150 276

Works contracts, fees and compensation for

services5,575 3,686 3,174

Depreciation of property, plant and equipment 12,016 7,766 7,342

Intangible assets amortization 358 273 53

Right-of-use assets amortization 106 - -

Transport of energy 188 155 128

Transportation and freights 907 543 102

Consumption of materials 2,547 2,406 1,091

Penalties 1,512 2,093 425

Maintenance 1,272 908 688

Canons and royalties 2,898 2,782 2,110

Environmental control 176 193 105

Rental and insurance 847 502 430

Surveillance and security 348 209 230

Taxes, rates and contributions 180 183 109

Other 211 15 384

Subtotal 114,038 75,064 57,419


Less: Inventories at the end of the year (9,175) (5,169) (4,271)

Total cost of sales 112,433 74,161 59,339




129

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 1,250 972 1,007

Benefits to employees 31 - -


Fees and compensation for services 1,724 1,126 963

Compensation agreements (55) 81 221

Depreciation of property, plant and equipment 550 322 127


Taxes, rates and contributions 1,420 1,244 1,137

Communications 371 270 289

Penalties 1,326 1,052 434

Net impairment losses on financial assets 1,307 1,067 418

Transport 471 211 137

Other 185 90 21

Total selling expenses 8,645 6,451 4,776

10.2 Administrative expenses

12.31.2019 12.31.2018 12.31.2017

Salaries and social security charges 3,268 3,044 2,898

Benefits to employees 368 206 205


Fees and compensation for services 2,887 2,548 2,032

Compensation agreements (17) 115 754

Directors' and Syndicates' fees 321 173 155

Depreciation of property, plant and equipment 745 455 217

Consumption of materials 147 149 99

Maintenance 100 88 77

Transport and per diem 117 82 63

Rental and insurance 269 212 220

Surveillance and security 125 171 151

Taxes, rates and contributions 129 317 145

Communications 73 74 74


Institutional advertising and promotion - 49 89

Other 129 38 82

Total administrative expenses 9,179 7,751 7,481




130


10.3 Exploration expenses

12.31.2019 12.31.2018 12.31.2017

Geological and geophysical expenses 167 17 27

Decrease in unproductive wells 296 28 44

Total exploration expenses 463 45 71

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)

- 3,721 -

Recovery of doubtful accounts 5 7 154

Insurrance recovery 320 - -

Natural Gas Surplus Injection Promotion Program 4.24.1.1 - 866 3,820

Commissions on municipal tax collections 129 77 52

Services to third parties 666 503 313

Profit for property, plant and equipment sale 26 118 7

Dividends received 61 29 56

Reversal of contingencies and taxes payables (2) 67 140 915

Other 814 1,381 291

Total other operating income 2,088 6,842 5,608

Other operating expenses

Provision for contingencies (1,622) (1,320) (765)

Decrease in property, plant and equipment (73) (217) (38)

Allowance for tax credits (225) (1) (27)

Tax on bank transactions (1,539) (1,136) (1,035)

Cost for services provided to third parties (97) (57) (62)

Compensation agreements - - (80)

Donations and contributions (92) (82) (62)

Institutional promotion (125) (114) (105)

Extraordinary canon - (117) (511)

Contingent consideration - - (304)

Onerous contract (Ship or Pay) - (265) (142)

Tax contingencies in Ecuador (1)

- (2,605) -

Other (844) (1,612) (761)

Total other operating expenses (4,617) (7,526) (3,892)

(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).




131


10.5. Financial results

Note 12.31.2019 12.31.2018 12.31.2017

Gain on monetary position, net 11,186 23,696 11,478

Finance income

Commercial interest 2,762 2,230 1,605

Financial interest 1,100 1,270 540

Other interest 621 251 188

Total finance income 4,483 3,751 2,333

Finance cost

Commercial interest (3,096) (2,957) (1,679)

Fiscal interest (306) (318) (415)

Financial interest (1) (11,693) (7,922) (6,107)

Other interest (449) (549) (387)

Other financial expenses (215) (198) (162)

Total financial expenses (15,759) (11,944) (8,750)


Foreign currency exchange difference, net (4,467) (32,549) (5,819)

Changes in the fair value of financial instruments 4,778 2,415 2,324

Gains (losses) from present value measurement 2,424 (2,792) (282)

Other financial results of RDSA 121 501 -

Results for the repurchase of corporate bonds 1,590 59 -

Other financial results 445 1 3

Total other financial results 4,891 (32,365) (3,774)

Total financial results, net 4,801 (16,862) 1,287

(1) Net of $ 818 million, $ 282 million and $ 602 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 4,199 1,465 2,061

Deferred tax 426 (713) (2,708)

Other comprehensive income - 19 -

Difference in the estimate of previous fiscal year income tax

and the income tax statement4 (113) (456)

Direct charges for income tax - - 118

Optional tax revaluation 1,495 - -

Total loss (gain) income tax 6,124 658 (985)




132


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 45,431 8,447 15,157

Current tax rate 30% 30% 35%

Result at the tax rate 13,629 2,534 5,305

Share of profit of associates and joint ventures (1,448) (125) (4,403)

Non-taxable results (2,048) 267 (2,235)

Effects of exchange differences and traslation effect of

property, plant and equipment and intangible assets, net4,881 - -

Adjustment of valuation of property, plant and equipment

and intangible assets(9,477) - -

Gain (loss) on monetary position, net 896 (1,441) 2,476

Effect of tax rate change in deferred tax 1,506 (983) (746)

Adjustment effect for tax inflation 7,374 - -

Payment of optional tax revaluation 1,495 - -

Special tax, revaluation of property, plant and equipment (7,070) - -

Difference in the estimate of previous fiscal year income tax

and the income tax statement(3,688) 165 (741)

Deferred tax not previously recognized - 143 (1,183)

Non-deductible cost - 18 322

Non-deductible provisions - - 201

Other 74 80 19

Total loss (gain) income tax 6,124 658 (985)




133


As of December 31, 2019 and 2018 consolidated accumulated tax losses amount to $ 26,618 million and $ 6,651 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 generationFiscal year

prescription12.31.2019 12.31.2018

2015 2020 - 98

2016 2021 213 667

2017 2022 108 161

2018 2023 2,278 1,050

2019 2024 4,060 -

6,659 1,976

Unrecognized deferred assets - (1)

Recognized Tax loss-carryforwards 6,659 1,975




134

NOTE 11: NON-FINANCIAL ASSETS AND LIABILITIES

11.1. Property, plant and equipment

Land 820 - - - (341) 330 809

Buildings 7,814 61 (462) 211 (51) 4,515 12,088

Equipment and machinery 39,606 49 (5,441) 15,353 (260) 25,748 75,055

High, medium and low voltage lines 38,061 158 - 4,308 (257) 20,466 62,736

Substations 13,769 7 - 856 - 7,404 22,036

Transforming chamber and platforms 7,859 224 - 920 (74) 4,226 13,155

Meters 7,890 64 - 1,377 - 4,243 13,574

Wells 21,174 1,229 - 5,097 (446) 13,219 40,273

Mining property 10,069 - (860) - - 5,927 15,136

Vehicles 813 30 - (5) (6) 450 1,282

Furniture and fixtures and software equipment 2,532 244 - 195 (17) 1,507 4,461

Communication equipments 554 1 - 14 - 304 873

Materials and spare parts 1,222 854 - (583) (9) 716 2,200

Distribution storage center 363 - - - (398) 35 -

Petrochemical industrial complex 558 - - (84) - 343 817

Work in progress 29,523 26,298 - (26,454) (132) 18,160 47,395

Advances to suppliers 722 1,207 - (1,284) (7) 446 1,084

Other goods 168 - - 79 - 116 363

Total at 12.31.2019 183,517 30,426 (6,763) - (1,998) 108,155 313,337

Total at 12.31.2018 162,758 25,071 (2,081) - (2,236) 5 183,517

Transfers (1)Type of good

At the

beginning

Original values

At the end IncreasesTraslation

effectDecreasesImpairment

(1) Includes the transfer of materials and spare parts to the item "Inventories" of the current asset.




135


Type of good

Land - - - - - - 809 820

Buildings (2,803) 28 304 (369) (1,694) (4,534) 7,554 5,011

Equipment and machinery (14,460) 241 2,485 (3,490) (9,337) (24,561) 50,494 25,146

High, medium and low voltage lines (12,172) 250 - (2,165) (6,545) (20,632) 42,104 25,889

Substations (3,974) - - (751) (2,137) (6,862) 15,174 9,795

Transforming chamber and platforms (2,160) 22 - (454) (1,161) (3,753) 9,402 5,699

Meters (3,001) (1) - (588) (1,614) (5,204) 8,370 4,889

Wells (12,087) - - (3,221) (7,792) (23,100) 17,173 9,087

Mining property (4,505) - 261 (1,384) (2,991) (8,619) 6,517 5,564

Vehicles (592) 4 - (266) (330) (1,184) 98 221

Furniture and fixtures and software equipment (1,828) 11 - (505) (1,097) (3,419) 1,042 704

Communication equipments (378) - - (26) (207) (611) 262 176

Materials and spare parts (68) 3 - (30) (39) (134) 2,066 1,154

Distribution storage center (93) 118 - (21) (4) - - 270

Petrochemical industrial complex (256) - - (30) (155) (441) 376 302

Work in progress - - - - - - 47,395 29,523

Advances to suppliers - - - - - - 1,084 722

Other goods (135) - - (11) (81) (227) 136 33

Total at 12.31.2019 (58,512) 676 3,050 (13,311) (35,184) (103,281) 210,056

Total at 12.31.2018 (51,187) 325 893 (8,543) - (58,512) 125,005

Net book values

Traslation

effect

Depreciation

At the end At 12.31.2018At the end At the

beginning Decreases Impairment For the year

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (in millions of Argentine Pesos (“$”) – unless otherwise stated)

136


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 $ 1,127 million and $ 1,021 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 $ 818 million and $ 282 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.




137


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 $ 3,114 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 $ 500 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 $ 400 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.




138


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 $ 599 million.




139


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 $ 102 million impairment losses decrease or

increase, respectively, and ii) the gas price: a 2% increase or decrease in the gas price would involve $ 109 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 $ 1,188 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.




140


11.2 Intangible assets

Type of good At the beginning Increase Traslate Effect At the end

Concession agreements 10,267 - - 5,861 16,128

Goodwill 1,309 - - 764 2,073

Intangibles identified in acquisitions of companies 263 - - 155 418

Total at 12.31.2019 11,839 - - 6,780 18,619

Total at 12.31.2018 11,840 6 (7) - 11,839

Type of good At the beginning For the year Traslate Effect At the end

Concession agreements (5,675) (345) (3,380) (9,400)

Intangibles identified in acquisitions of companies (84) (13) (54) (151)

Total at 12.31.2019 (5,759) (358) (3,434) (9,551)

Total at 12.31.2018 (5,486) (273) - (5,759)

Net book values

Type of good At the end At 12.31.2018

Concession agreements 6,728 4,592

Goodwill 2,073 1,309

Intangibles identified in acquisitions of companies 267 179

Total at 12.31.2019 9,068

Total at 12.31.2018 6,080

Depreciation

Devalorization

Original values




141


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

Other

comprehensive

loss

12.31.2019

Tax loss carryforwards 1,975 2,797 - 1,887 6,659

Trade and other receivables 543 (76) 239 46 752


and loss2 (3) - 1 -

Cash and cash equivalents - - - - -

Trade and other payables 1,955 (2,246) 1,051 30 790

Salaries and social security payable 56 56 27 7 146

Defined benefit plans 327 (70) 57 86 400

Provisions 1,201 392 186 584 2,363

Taxes payable 213 (260) 8 57 18

Adjustment for tax inflation - 448 - 4 452

Other 75 (60) - 3 18

Deferred tax asset 6,347 978 1,568 2,705 11,598

Property, plant and equipment (12,598) (7,009) (2,381) (1,084) (23,072)

Adjustment for tax inflation - (5,392) - (516) (5,908)

Investments in companies (701) 468 - (259) (492)

Intangible assets (7,286) 10,520 (3,293) (691) (750)

Inventory - (454) (105) (58) (617)

Trade and other receivables (353) 413 - (305) (245)


and loss(322) (173) (114) (35) (644)

Cash and cash equivalents - - - - -

Borrowings (122) 139 (2) (18) (3)

Taxes payable - (160) - (71) (231)

Other (239) 244 - (7) (2)

Deferred tax liabilities (21,621) (1,404) (5,895) (3,044) (31,964)




142


12.31.2017 Profit (loss)

Other

comprehensive

income (loss)

12.31.2018

Tax los-carryforwards 2,416 (441) - 1,975

Trade and other receivables 175 368 - 543

Derivative financial instruments - - - -


and loss18 (16) - 2

Trade and other payables 1,745 210 - 1,955

Salaries and social security payable - 56 - 56

Defined benefit plans 384 (98) 41 327

Provisions 1,096 105 - 1,201

Taxes payable 249 (36) - 213

Liabilities associated to assets classified as

held for sale542 (542) - -

Other 67 8 - 75

Deferred tax asset 6,692 (386) 41 6,347

Property, plant and equipment (16,687) 4,089 - (12,598)

Investments in companies (1,962) 1,328 (67) (701)

Intangible assets (108) (7,178) - (7,286)

Trade and other receivables (997) 644 - (353)


and loss(89) (233) - (322)

Borrowings (201) 79 - (122)

Assets classified as held

for sale(1,241) 1,241 - -

Other (165) (74) - (239)

Deferred tax liabilities (21,450) (104) (67) (21,621)




143


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 1,702 80

Deferred tax liabilities (22,068) (15,354)

Deferred tax liabilities, net (20,366) (15,274)

11.4 Inventories

12.31.2019 12.31.2018

Materials and spare parts 5,673 3,536

Advances to suppliers 1,277 71

In process and finished products 2,225 1,516

Stock crude oil - 46

Total 9,175 5,169

11.5 Provisions

12.31.2019 12.31.2018

Non-Current

Provisions for contingencies 7,411 4,674

Asset retirement obligation and

dismantling of wind turbines1,195 770

Environmental remediation 34 13

Other provisions 63 42

8,703 5,499

Current

Provisions for contingencies 968 658

Asset retirement obligation and

dismantling of wind turbines132 65

Environmental remediation 105 147

Other provisions 1 1

1,206 871




144


For

contingencies

Asset

retirement

obligation and

dismantling of

wind turbines

For

environmental

remediation

At the beginning of the year 5,332 835 160

Increases 2,332 134 12

Decreases (551) (8) (87)

Exchange differences on translation 2,032 519 58

Gain on monetary position, net (250) - -

Reversal of unused amounts (516) (153) (4)

At the end of the year 8,379 1,327 139

For

contingencies

Asset

retirement

obligation

For

environmental

remediation

At the beginning of the year 5,311 1,579 210

Increases 4,013 1,391 208

Reclasification - (677) -

Gain on monetary position, net (1,965) (677) (74)

Decreases (904) (190) (184)

Reversal of unused amounts (1,123) (591) -

At the end of the year 5,332 835 160

For

contingencies

Asset

retirement

obligation

For

environmental

remediation

At the beginning of the year 7,500 3,430 642

Increases 1,627 1,053 162

Reclasifications (347) (27) 27

Reclasification to liabilities associated to

assets classified as held for sale - (1,292) (272)

Gain on monetary position, net (1,404) (695) (123)

Decreases (1,461) (276) (223)



12.31.2019

12.31.2018

12.31.2017




145


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.


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.




146


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 $ 5,348 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 $ 5,072 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 590 1,034

Total non-current 590 1,034

Current

Income tax, net of witholdings and advances3,154 930

Minimum notional income tax, net of witholdings and

advances- 154

Total current 3,154 1,084




147


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 $ 469 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 $ 592

million including compensatory interest and was disclosed in the line “Income tax liability and minimum notional

income tax non-current”.




148


11.7 Tax liabilities

12.31.2019 12.31.2018

Non-current

Value added tax - 160

Sales tax 78 33

Payment plans 29 60

Extraordinary Canon 156 289

Total non-current 263 542

Current

Value added tax 2,306 786

Municipal, provincial and national contributions 179 130

Personal assets tax provision 179 -

Payment plans 47 53

Municipal taxes 138 108

Tax withholdings to be deposited 338 337

Stamp tax payable - 10

Royalties 252 202

Extraordinary Canon 743 374

Other 134 52


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.




149


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.




150


As of December 31, 2019, 2018 and 2017, the most relevant actuarial information corresponding to the described

benefit plans is the following:

Present value

of the

obligation

Fair value of

plan assets

Net liability at

the end of the

year

Liabilities at the beginning 1,500 (163) 1,337

Items classified in profit or loss

Current services cost 148 - 148

Cost for interest 771 (102) 669

Cost for past service 1 - 1

Contributions paid (16) - (16)

Items classified in other comprehensive

income

Actuarial (gains) losses (104) 1 (103)

Benefit payments (132) - (132)

Gain on monetary position, net (68) - (68)

At the end 2,100 (264) 1,836

Present value

of the

obligation

Present value

of assets

Net liability at

the end of the

year





Past services cost (187) - (187)


income

Actuarial losses (gains) 225 (65) 160

Exchange differences on translation 4 - 4

Benefit payments (130) - (130)

Increase for subsidiries acquisition (586) 50 (536)

At the end 1,500 (163) 1,337

12.31.2019

12.31.2018




151


Present value

of the

obligation

Present value

of assets

Net liability at

the end of the

year





Past services cost 46 - 46


Actuarial (gains) losses (32) 16 (16)

Exchange differences on translation 52 (26) 26

Benefit payments (87) 11 (76)

Contributions paid - (11) (11)

Reclasification to liabilities associated to assets

classified as hed for sale (420) 165 (255)

Gain (loss) on net monetary position (540) 52 (488)

At the end 1,760 (117) 1,643

12.31.2017

As of December 31, 2019, the breakdown of net liabilities per type of plan is as follows: a) $ 1,234 million

correspond to the Pension and Retirement Benefits Plan and b) $ 602 million correspond to the Compensatory Plan.

As of December 31, 2018, net liability by type of plan, is as follows: a) $ 933 million corresponding to Pension and

Retirement Benefits Plan and b) $ 404 million corresponding to Compensatory Plan.

As of December 31, 2017, net liability by type of plan, is as follows: a) $ 1,238 million corresponding to Pension

and Retirement Benefits Plan and b) $ 405 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 230

One to two years 150

Two to three years 147

Three to four years 137

Four to five years 134

Six to ten years 671




152


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 2,289

Variation 189

10%

Discount rate: 6%

Obligation 1,931

Variation (169)

(9%)

Salaries increase: 0%

Obligation 2,000

Variation (100)

(5%)

Salaries increase: 2%

Obligation 2,213

Variation 113

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.




153


11.9 Salaries and social security payable

12.31.2019 12.31.2018

Non-current

Seniority - based bonus 201 148

Early retirements payable 40 15


Current

Salaries and social security contributions 1,292 918

Provision for vacations 991 711

Provision for gratifications and annual bonus for efficiency 1,523 1,087

Early retirements payable 28 10


NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1 Financial assets at amortized cost

12.31.2019 12.31.2018

Non-current

Public securities (1) 1,048 -

Total non-current 1,048 -

Current

Time deposits - 1,330

Public securities (1) 3,224 -


(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.




154


12.2 Financial assets at fair value through profit and loss

12.31.2019 12.31.2018

Non-current

Shares 671 422


Current

Government securities 6,775 11,234

Shares 478 44

Investment funds 14,614 3,995


12.3 Trade and other receivables

Note 12.31.2019 12.31.2018

Non-Current

CAMMESA Receivable (1) - 2,647

Other 459 853

Trade receivables, net 459 3,500

Non-Current

Tax credits 208 503

Related parties 17 3,169 1,860

Prepaid expenses 52 28

Financial credit 22 30

Guarantee deposits 1 1

Receivable for sale of property, plant and equipment - 112

Natural Gas Surplus Injection Promotion Program (2) - 2,671

Credit with RDSA 20 2,126 766

Allowance for doubtful accounts (2,126) -

Allowance for tax credits (5) (11)

Other 805 61

Other receivables, net 4,252 6,021

Total non-current 4,711 9,521




155


Current Note 12.31.2019 12.31.2018

Receivables from energy distribution sales 13,540 8,392

Receivables from MAT 1,023 1,035

CAMMESA 10,052 4,943

CAMMESA Receivable (1) 7 574

Receivables from oil and gas sales (3) 2,856 2,923

Receivables from refinery and distribution sales - 218

Receivables from petrochemistry sales 3,234 2,544

Related parties 17 392 384

Government of the PBA and CABA by Social Rate 251 -

Other 508 139

Allowance for doubtful accounts (2,000) (1,266)

Trade receivables, net 29,863 19,886

Tax credits 624 1,020

Advances to suppliers 10 83

Advances to employees 8 8


Prepaid expenses 123 61

Receivables for non-electrical activities 639 539

Financial credit 296 209

Guarantee deposits 300 475

Natural Gas Surplus Injection Promotion Program (2) - 2,667

Insurance to recover - 212

Expenses to be recovered 727 417

Credits for the sale of property, plant and equipment 35 783

Credit with RDSA 20 60 -

Other 706 213

Allowance for other receivables (305) (285)

Other receivables, net 3,720 6,603


(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 $ 877 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).




156


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:

Note 12.31.2019 12.31.2018 12.31.2017

At the beginning 4.1 1,266 975 790

Allowance for impairment 3,544 1,266 480

Utilizations (771) (389) (76)


Exchange differences on translation 126 - -

Reclasification to assets held

for sale - - (191)

Gain on monetary position, net 51 (555) (179)


The movements in the allowance for the impairment of other receivables are as follows:

Note 12.31.2019 12.31.2018 12.31.2017

At the beginning 4.1 296 217 372

Allowance for impairment 56 248 55

Exchange differences on translation 89 - -

Gain on monetary position, net (1) (115) 15

Decreases - - (25)


At the end of the year 310 296 256

12.4 Cash and cash equivalents

12.31.2019 12.31.2018

Cash 29 17

Banks 3,407 3,133

Investment funds 250 -

Time deposits 9,810 5,947

Total 13,496 9,097




157


12.5 Borrowings

Non-Current Note 12.31.2019 12.31.2018

Financial borrowings 9,623 9,743

Corporate bonds (1) 96,006 54,927

CAMMESA financing - 4,519

105,629 69,189

Current

Financial borrowings 8,227 11,811

Corporate bonds 1,932 934

CAMMESA financing - 127


10,974 12,901

Total 116,603 82,090

(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 $

86,005 million and $ 49,026 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.




158


The movements in the borrowings are as follows:

Note 12.31.2019 12.31.2018 12.31.2017

At the beginning 82,090 63,439 47,855

Proceeds from borrowings 25,808 9,250 47,130

Payment of borrowings (26,869) (9,057) (27,650)

Accrued interest 9,185 6,766 5,396

Payment of borrowings' interests (6,651) (5,004) (4,072)

Net foreign currency exchange difference 4,283 46,895 8,546

Results for the repurchase of corporate bonds12.5.2

(1,590) (59) -

Costs capitalized in property, plant and

equipment11.1

818282 546

Decrease through offsetting with trade

receivables (5,981) - (6)

Gain on monetary position, net (385) (29,974) (14,301)

Repurchase and redemption of corporate bonds (5,107) (448) (47)

Other comprehensive loss 41,002 - -

Other financial results - - 42

At the end of the year 116,603 82,090 63,439

As of the date of issuance of these Consolidated Financial Statements, the Company is in compliance with the

covenants established in its indebtedness


159


12.5.1 Details of borrowings:

Corporate bonds:

2022 CB Edenor U$S 166 Fixed 9.75% 2022 8,341

Class E CB PAMPA ARS 575 Variable Badlar Nov-20 618

Class 1 CB PAMPA U$S 687 Fixed 7.50% Ene-27 41,779

T Series CB PAMPA U$S 487 Fixed 7.38% Jul-23 29,783

Serie 3 CB (1)PAMPA U$S 293 Fixed 9.13% Abr-29 17,417

97,938

Financial loans:

Thrid parties:

PAMPA U$S 84 FixedBetween 4,25%

and 7,65%

Jan-2020 to

May-2020

5,283

PAMPA U$S 39 Fixed and variable 4.21% + Libor May-2024 2,326

PAMPA ARS 7,775 FixedBetween 40%

and 44,14%

Apr-2021 to

Apr-2022

8,726

16,335

Related parties:

PAMPA U$S 13 Fixed 6.0% 2020 815

Financial loans:

Edenor U$S 1,885 Variable Libor + 4,27% Oct-20 1,515

1,515

116,603

Type of instrument Rate ExpirationBook value as

of 12.31.2019Company Currency

Residual

valueInterest

(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.




160


Corporate bonds:

2022 CB Edenor U$S 166 Fixed 9.75% 2022 6,360

Class 4 CB (1)PAMPA U$S 34 Fixed 6.25% Oct 20 1,291

Class E CB PAMPA ARS 607 Fixed Badlar Nov-20 607

T Series CB PAMPA U$S 500 Fixed 7.38% Jul-23 28,404

Class 1 CB PAMPA U$S 747 Fixed 7.50% Jan-27 19,228

55,890

Regulatory:

CAMMESA 2014 Agreement PAMPA ARS 855 Variable CAMMESA(2) 2,158

CAMMESA Mapro PAMPA ARS 174 Variable CAMMESA (2) 254

CAMMESA Mapro CPB ARS 1,085 Variable CAMMESA (2) 2,234

4,646

Financial loans:

PAMPA U$S 17,116 FixedBetween 2,9%

and 7,5%

Feb-2018 to

May-202117,357

PAMPA U$S 1,746 Variable 6% + Libor May-2024 1,732

PAMPA ARS 550 FixedBetween 22%

and 22,25%

Sep-2019 to

Oct-2019561

Edenor U$S 1,885 Fixed Libor + 4,27% Oct-20 1,904

21,554

82,090

Rate ExpirationType of instrumentBook value as

of 12.31.2018Company Currency

Residual

valueInterest

(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).


161


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 $ 1,590 million and $ 59.4 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.




162


12.6. Trade and other payables

Non-Current 12.31.2019 12.31.2018

Customer contributions 156 112

Funding contributions for substations - 33

Customer guarantees 213 141

Trade payables 369 286

ENRE Penalties and discounts 3,932 5,097

Loans (mutuums) with CAMMESA - 2,282

Compensation agreements 399 251

Liability with FOTAE - 207

Payment agreement with ENRE - 37

Lease liability 716 -

Other 3 2

Other payables 5,050 7,876

Total non-current 5,419 8,162

Current Note 12.31.2019 12.31.2018

Suppliers 12,739 9,371

CAMMESA 9,305 11,909

Customer contributions 31 15

Discounts to customers 37 37

Funding contributions substations - 17

Customer advances 362 244


Other 22 19

Trade payables 22,964 21,857

ENRE Penalties and discounts 3,387 1,836


Advances for works to be executed 6 14

Compensation agreements 150 481

Payment agreements with ENRE 48 65

Other creditors - 305

Lease liability 254 -

Other 64 187

Other payables 4,225 2,899





163


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 $ 45 million and

$ 108 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).




164


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/liabilitiesTotal

Assets

Trade receivables and other receivables 37,233 250 37,483 811 38,294


and loss

Government securities - 6,775 6,775 - 6,775

Shares - 1,149 1,149 - 1,149

Investment funds - 14,614 14,614 - 14,614

Derivative financial instruments - 214 214 - 214

Cash and cash equivalents 13,246 250 13,496 - 13,496

Total 50,479 23,252 73,731 811 74,542

Liabilities

Trade and other liabilities 24,484 399 24,883 7,725 32,608

Borrowings 116,603 - 116,603 - 116,603


Total 141,087 603 141,690 7,725 149,415


Financial

assets/liabilities

at amortized

cost

Financial

assets/liabilities

at fair value

through profit

and losss

Subtotal

financial

assets/liabilities

Non financial

assets/liabilitiesTotal

Assets

Trade receivables and other receivables 34,217 122 34,339 1,671 36,010

Financial assets at amortized cost

Government securities 1,330 - 1,330 - 1,330


and loss

Government securities - 11,234 11,234 - 11,234

Shares - 466 466 - 466

Investment funds - 3,995 3,995 - 3,995


Cash and cash equivalents 9,097 - 9,097 - 9,097

Total 44,644 15,820 60,464 1,671 62,135

Liabilities

Trade and other liabilities 22,833 576 23,409 9,509 32,918

Borrowings 82,090 - 82,090 - 82,090

Instrumentos financieros derivados - 49 49 - 49

Total 104,923 625 105,548 9,509 115,057




165


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:


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 4,347 136 4,483 - 4,483

Interest expense (14,832) - (14,832) (712) (15,544)

Foreign exchange, net (5,729) 1,061 (4,668) 201 (4,467)

Results from financial instruments at fair

value- 4,778 4,778 - 4,778

Gains (losses) from present value

measurement2,482 - 2,482 (58) 2,424

Other financial results 1,941 - 1,941 - 1,941

Total (11,791) 5,975 (5,816) (569) (6,385)


Financial

assets/liabilities

at amortized

cost

Financial

assets/liabilities

at fair value

through profit

and losss

Subtotal

financial

assets/liabilities

Non Financial


Interest income 3,555 196 3,751 - 3,751


Foreign exchange, net (32,653) 3,260 (29,393) (3,156) (32,549)


value- 2,415 2,415 - 2,415


measurement(2,713) - (2,713) - (2,713)

Other financial results 363 - 363 (79) 284

Total (42,350) 5,871 (36,479) (4,079) (40,558)


Financial

assets/liabilities

at amortized

cost

Financial

assets/liabilities

at fair value

through profit

and losss

Subtotal

financial

assets/liabilities

Non Financial


Interest income 2,076 257 2,333 - 2,333


Foreign exchange, net (7,138) 1,850 (5,288) (531) (5,819)


value- 2,324 2,324 - 2,324


measurement(213) - (213) - (213)

Other financial results (167) - (167) (61) (228)

Total (13,615) 4,431 (9,184) (1,007) (10,191)




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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).




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The following table shows the Company’s financial assets and liabilities measured at fair value as of December 31,

2019 and 2018:

As of December 31, 2019 Level 1 Level 2 Level 3 Total

Assets

Financial assets at fair value through

profit and losss

Government securities 6,775 - - 6,775

Shares 478 - 671 1,149

Investment funds 14,614 - - 14,614

Cash and cash equivalents

Investment funds 250 - - 250

Derivative financial instruments - 214 - 214

Other receivables 250 - - 250

Total assets 22,367 214 671 23,252

Liabilities


Total liabilities - 205 - 205

As of December 31, 2018 Level 1 Level 2 Level 3 Total

Assets

Financial assets at fair value through

profit and losss

Government securities 11,234 - - 11,234

Shares 44 - 422 466

Investment funds 3,995 - - 3,995


Other receivables 122 - - 122

Total assets 15,395 3 422 15,820

Liabilities


Total liabilities - 49 - 49

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.





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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 to $ 1,899,870,264 (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 by $ 151,997,025 through the cancellation of

151,997,025 treasury shares, the capital stock thus decreasing from $ 1,899,870,264 to $1,747,873,239. 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.




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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.




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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.




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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 33,012 5,506 12,867

Weighted average amount of outstanding shares 1,799 1,959 1,936

Basic and diluted earnings per share from continuing operations18.35 2.81 6.65

Earning (loss) for discontinued operations attributable to the equity

holders of the Company - 2,929 (2,068)


Basic and diluted earnings (loss) per share from

discontinued operations- 1.50 (1.07)

Total earning attributable to the equity holders of the Company 33,012 8,435 10,799


Basic and diluted earnings per share 18.35 4.31 5.58




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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 6,124 658 (985)

Accrued interest 11,148 8,254 6,255

Depreciations and amortizations 9, 10.1 and 10.2 13,923 8,816 7,739

Constitution of allowances, net 10.4 and 10.1 1,527 1,061 418

Constitution (recovery) of provisions, net 10.4 1,555 1,180 (150)

Share of profit from joint ventures and associates 5.3.2 (5,855) (4,464) (1,813)

Income from the sale of companies 5.1 - (1,052) -

Accrual of defined benefit plans 9, 10.1 and 10.2 817 196 518

Net exchange differences 10.5 4,467 32,549 5,819

Result from measurement at present value 10.5 (2,424) 2,792 282

Changes in the fair value of financial instruments 10.5 (4,606) (2,372) (2,324)

Results from property, plant and equipment sale and decreases 10.4 and 10.3 343 127 56

Results for the repurchase of corporate bonds 10.5 (1,590) (59) -

Impairment of property, plant and equipment 11.1.1 3,713 1,195 -

Dividends received 10.4 (61) (29) (56)

Compensation agreements 10.1 and 10.2 (72) 196 1,055

Result from the sale of shareholdings in companies, property, plant and

equipment and intangibles assets 5.2.3- (1,644) -

Agreement on the regularization of obligations (17,095) - -

Resolución contractual activo inmobiliario 10.5 (121) (501) -

Onerous contract (Ship or pay) 10.4 - 265 142

Gain on monetary position, net 10.5 (11,186) (23,696) (11,478)

Other (292) 76 293

Total adjustments to reconcile net profit (loss) to cash flows generated

by operating activities315 23,548 5,771




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14.2 Changes in operating assets and liabilities

12.31.2019 12.31.2018 12.31.2017

Acquisition of property, plant and equipment through an increase in

trade payables(2,819) 639 (3,898)

Borrowing costs capitalized in property, plant and equipment (818) (282) (602)

Decreases of property, plant and equipment through an increase in

other receivables- 439 -

Agreement on the regularization of obligations 17,095 - -

Increase in asset retirement obligation provision through an increase in

property, plant and equipment185 1,272 (59)

Constitution of guarantee of derivative financial instruments, net

through the delivery of financial assets at fair value through profit or

loss

128 (819) 718

Cancellation of other credits for capital contributions in associates 713 - -

Compensation of investments at a cost cost through the transfer of

other credits5,341 - -

5,981 - -

1,156 - -

Significant non-cash transactions from

discontinued operations :


trade payables- - (13)

Credit pending collection for sale of property, plant and equipment - - 551

Loan compensation through the transfer of sales credits

Increase of right-of-use assets through an increase in other debts

14.3 Significant non-cash transactions

12.31.2019 12.31.2018 12.31.2017


trade payables(2,819) 639 (3,898)

Borrowing costs capitalized in property, plant and equipment (818) (282) (602)

Decreases of property, plant and equipment through an increase in

other receivables- 439 -

Agreement on the regularization of obligations 17,095 - -

Increase in asset retirement obligation provision through an increase in

property, plant and equipment185 1,272 (59)

Constitution of guarantee of derivative financial instruments, net

through the delivery of financial assets at fair value through profit or

loss

128 (819) 718

Cancellation of other credits for capital contributions in associates 713 - -

Compensation of investments at a cost cost through the transfer of

other credits5,341 - -

5,981 - -

1,156 - -

Significant non-cash transactions from

discontinued operations :


trade payables- - (13)

Credit pending collection for sale of property, plant and equipment - - 551

Loan compensation through the transfer of sales credits

Increase of right-of-use assets through an increase in other debts




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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.




175


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.




176


- 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.




177


- 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.




178


- 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.




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- 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.




180


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 $ 88 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.




181


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.

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 24).

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.




182


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 $ 8 million, which were offset with receivables CTB held against the Company

on account of loans and commercial debt.

16.1.3 CTGEBA

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.




183


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.




184

NOTE 17: 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) 57 - -

Transener - 20 48

TGS (2) 1,386 1,937 862

Greenwind 33 12 -

Refinor (3) 813 593 205

Oldelval - 6 6

Other related parties

SACDE - 35 -

2,289 2,603 1,121

(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


Transener (10) (3) (11)

TGS (1) (1,097) (783) (319)

SACME (83) (82) (77)

Refinor (2) (870) (1,275) (639)

Oldelval (3) (43) (60) (120)


SACDE (4) (69) (69) -

Orígenes Vida - - (21)

(2,172) (2,272) (1,187)

(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.




185


17.3 Fees for services

12.31.2019 12.31.2018 12.31.2017


Salaverri, Dellatorre, Burgio & Wetzler (59) (49) (27)

(59) (49) (27)

Corresponds to fees for legal advice.

17.4 Other operating income (expenses), net

12.31.2019 12.31.2018 12.31.2017


Greenwind (36) - -

OCP (1) - (265) -


SACDE 34 - -

Foundation (2) (79) (76) (55)

(81) (341) (55)

(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


SACDE 4 - -

TGS (1) 157 122 106

161 122 106

(1) Corresponds to finance leases.

17.6 Finance expenses

12.31.2019 12.31.2018 12.31.2017


Citelec (25) - -

Orígenes Retiro (1) (17) (10)

(26) (17) (10)




186


17.7 Corporate Bonds purchases

Purchase of Corporate Bonds

12.31.2019 12.31.2018 12.31.2017


Orígenes Retiro - - (10)

- - (10)

17.8 Dividends received

12.31.2019 12.31.2018 12.31.2017


CIESA/TGS 2,349 657 -

OCP 733 - -

Oldelval - 50 12

Citelec 669 - -


TSM 24 13 13

TMB 23 15 15

3,798 735 40

17.9 Payment of dividends

Other related parties 12.31.2019 12.31.2018 12.31.2017

EMESA (57) (82) (72)

APCO Oil - - (72)

(57) (82) (144)

17.10 Key management personnel remuneration

The total remuneration to executive directors accrued amounts to $ 249 million ($ 321 million loss for Directors' and

Sindycs' fees and $ 72 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, $ 363 million ($ 173 million in

Directors' and Sindycs' fees and $ 190 million in the accrual of the Company-Value Compensation, EBDA

Compensation and Stock-based Compensation Plans) during the year ended December 31, 2018 and $ 1,177 million

($ 155 million in Directors' and Sindycs' fees and $ 1,022 million in the accrual of the Company-Value

Compensation, EBDA Compensation and Stock-based Compensation Plan) during the year ended December 31,

2017.




187


17.11 Balances with related parties:

Trade

receivables

Current Non Current Current


CTB 27 - -

TGS 221 2,014 274

CIESA - - -

Greenwind 16 260 5

SACME - 4 -

Refinor 109 - -

OCP - 891 14


SACDE 19 - 145

Fidus - - 25

Other - - 34

392 3,169 497

As of December 31, 2019Other receivables

Trade

payables

Other

payablesBorrowings

Current Current Current


Transener 5 - -

TGS 5 - -

Greenwind 274 - -

SACME 144 13 -

Citelec - - 815

OCP - 303 -

Refinor 40 - -

468 316 815


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).




188


Trade

receivables

Current Non Current Current


TGS 288 1,436 158

Greenwind - 419 17

SACME - 5 -

Refinor 91 - -


SACDE 5 - 26

384 1,860 201

As of December 31, 2018Other receivables

Trade

payables

Other

payablesBorrowings

Current Current Current


Transener 4 - -

TGS 105 - -

SACME - 8 -

OCP - 3 -

Refinor 136 - -


Orígenes Retiro - - 29

245 11 29


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.




189


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

Type of good At the beginning Increase At the end(1)

Machinery and equipment - 731 31 762

Buildings - 425 - 425

Total at 12.31.2019 - 1,156 31 1,187

Type of good At the beginning For the year At the end At the end

Machinery and equipment - (90) (3) (93)

Buildings - (164) - (164)

Total at 12.31.2019 - (254) (3) (257)

Net book values

Type of good At the end

Machinery and equipment 669

Buildings 261

Total at 12.31.2019 930

Traslate Effect

Original values

Depreciation

(1) Includes $ 471 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 16 471

Increases 734

Discounted value measurement (1)

158

Payments (285)

Exchange differences on translation (108)

At the end of the year 970

(1) Included in the “Gains (losses) from present value measurement” under Other financial results




190


As of December 31, 2019, this liability is disclosed under Other current payables in the amount of $ 254 million and

Other non-current payables for $ 716 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 89

Three months to one year 229





More than five years 949

Total 1,764

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

$ 491 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 $ 274

million and under Other non-current receivables for $ 2,014 million.




191


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 112

Three months to one year 336





More than five years 716

Total 2,956

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 - 174

2020 325 -

Total future minimum lease collections 325 174

The total income from operating leases for the years ended December 31, 2019 and 2018 amounts to $ 283 million

and $ 190 respectively.




192

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.




193


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.




194


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.

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 $ 2,125.9

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.




195

NOTE 21: ASSETS AND LIABILITIES IN CURRENCIES DIFERENT FROM THE ARGENTINE PESO (1)

ASSETS

NON-CURRENT ASSETS

Financial instruments


Third parties U$S 17.5 59.890 1,048 -

Other receivables

Related parties U$S 33.6 59.890 2,014 1,436

Third parties U$S 28.5 59.890 1,705 4,849


and loss

Third parties U$S - - - 135

Total non-current assets 4,767 6,420

CURRENT ASSETS



and loss

Third parties U$S 167.0 59.890 10,000 11,272


Third parties U$S 53.8 59.890 3,224 -

Instrumentos financieros derivados

Third parties U$S 3.5 59.890 211 -

Trade and other receivables

Related parties U$S 10.7 59.890 640 372

Third parties U$S 168.3 59.890 10,079 6,780

U$ - 1.605 - 4,688

EUR 3.0 67.227 200 17

Cash and cash equivalents U$S 215.6 59.890 12,914 6,135

EUR 2.0 67.227 135 741


Total assets 42,170 36,425

Type

Amount in

currencies

other than

pesos

Exchange

rate (1)

Total

12.31.2019

Total

12.31.2018




196


LIABILITIES

NON-CURRENT LIABILITIES


Trade and other payables

Third parties U$S 6.7 59.890 402 251

Borrowings

Third parties U$S 1,633.9 59.890 97,854 64,750

Non financial instruments

Provisions

Third parties U$S 101.0 59.890 6,048 3,951

Taxes payables

Third parties U$S 2.6 59.890 156 290

Total non-current liabilities 104,460 69,242

CURRENT LIABILITIES


Trade and other payables

Related parties U$S 6.4 59.890 380 105

Third parties U$S 98.6 59.890 5,908 4,995

EUR 3.8 67.227 251 186

CHF 0.2 61.870 15 -

SEK 1.0 - 9 4

Borrowings

Third parties U$S 143.4 59.890 8,590 11,551

Derivative financial instruments

Third parties U$S - 0.000 - 49

Non financial instruments

Salaries and social security payable

Third parties U$S 0.1 59.890 4 11

U$ 1.7 1.605 3 2

Taxes payables

Third parties U$S 11.7 59.890 702 222

Provisions

Third parties U$S 16.4 59.890 985 682


Total liabilities 121,307 87,049

Net Position Liability (79,137) (50,624)

Total

12.31.2019

Total

12.31.2018Type

Amount in

currencies

other than

pesos

Exchange

rate (1)

(1) Information presented for the purpose of complying with the CNV Rules.

(2) The exchange rates correspond to December 31, 2019 released by the National Bank of Argentine for U.S. dollars (U$S), euros (EUR),

Swiss francs (CHF), Uruguayos pesos (U$) and Norwegian kroner (SEK).




197

NOTE 22: 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 23: 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.

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

Proved Reserves

Proved Developed Proved Undeveloped Total Proved

(1) In thousands of barrels. (2) In millions of cubic meters.




198

NOTE 24: SUBSEQUENT EVENTS

24.1 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:

24.1.1 Remuneration for Available Power Capacity

24.1.1.1 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.




199


24.1.1.2 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.

24.1.1.3 Wind power

No remuneration related to power capacity availability is set, establishing a single remuneration value for generated

energy (see next item).

24.1.2 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.




200


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.

24.2 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.

24.3 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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