20-F 1 pbraform20f_2020.htm PBRAFORM20F_2020

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 20-F

 

ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

for the fiscal year ended December 31, 2020
Commission File Number 001-15106

 

Petróleo Brasileiro S.A. — Petrobras

(Exact name of registrant as specified in its charter)

 

Brazilian Petroleum Corporation — Petrobras
(Translation of registrant’s name into English)

The Federative Republic of Brazil
(Jurisdiction of incorporation or organization)

Avenida República do Chile, 65 - 20031-912 - Rio de Janeiro – RJ - Brazil
(Address of principal executive offices)

Andrea Marques de Almeida
Chief Financial Officer and Chief Investor Relations Officer
(55 21) 3224-4477—dfinri@petrobras.com.br
Avenida República do Chile, 65 - 20031-912 - Rio de Janeiro – RJ - Brazil
(Name, telephone, e-mail and/or facsimile number and address of company contact person)

 


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

Title of each class:

Trading Symbol(s):

Name of each exchange on which registered:

Petrobras Common Shares, without par value* PBR/PBRA New York Stock Exchange*
Petrobras American Depositary Shares, or ADSs
(evidenced by American Depositary Receipts, or ADRs), each representing two Common Shares
PBR/PBRA New York Stock Exchange
Petrobras Preferred Shares, without par value* PBR/PBRA New York Stock Exchange*
Petrobras American Depositary Shares
(as evidenced by American Depositary Receipts), each representing two Preferred Shares
  New York Stock Exchange
4.375% Global Notes due 2023, issued by PGF PBR New York Stock Exchange
6.250% Global Notes due 2024, issued by PGF PBR New York Stock Exchange
5.299% Global Notes due 2025, issued by PGF PBR New York Stock Exchange
8.750% Global Notes due 2026, issued by PGF PBR New York Stock Exchange
7.375% Global Notes due 2027, issued by PGF PBR New York Stock Exchange
5.999% Global Notes due 2028, issued by PGF PBR New York Stock Exchange
5.750% Global Notes due 2029, issued by PGF PBR New York Stock Exchange
5.093% Global Notes due 2030, issued by PGF PBR New York Stock Exchange
5.600% Global Notes due 2031, isuued by PGF PBR New York Stock Exchange
6.875% Global Notes due 2040, issued by PGF (successor to PifCo) PBR New York Stock Exchange
6.750% Global Notes due 2041, issued by PGF (successor to Pifco) PBR New York Stock Exchange
5.625% Global Notes due 2043, issued by PGF PBR New York Stock Exchange
7.250% Global Notes due 2044, issued by PGF PBR New York Stock Exchange
6.900% Global Notes due 2049, issued by PGF PBR New York Stock Exchange
6.750% Global Notes due 2050, issued by PGF PBR New York Stock Exchange
6.850% Global Notes due 2115, issued by PGF PBR New York Stock Exchange

_________________ 

*Not for trading, but only in connection with the registration of American Depositary Shares pursuant to the requirements of the New York Stock Exchange.

 

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

The number of outstanding shares of each class of stock as of December 31, 2020 was:
7,442,231,382 Petrobras Common Shares, without par value

5,601,969,879 Petrobras Preferred Shares, without par value

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

Yes       No

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

Yes       No

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

Yes       No

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

Yes       No

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Emerging growth company

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

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

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

U.S. GAAP

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

Other

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

Item 17       Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes       No

 

 

 

 

TABLE OF CONTENTS

DISCLAIMER 1
GLOSSARY 4
   
About us 13
Datasheet 13
Overview 14
2020 HIGHLIGHTS 18
Recent Developments 19
   
Risks 22
Risk Factors 22
Corporate Risk Management 39
Disclosures about Market Risk 40
Insurance 40
Emerging Risks 41
   
Our Business 44
Exploration and Production 45
Refining, Transportation and Marketing 72
Gas and Power 95
Portfolio Management 116
External Business Environment 121
Our Responses to the Covid-19 Pandemic 128
   
Strategic Plan 132
2021-2025 Strategic Plan 132
Digital Transformation 143
   
Environment, social and governance 151
Environment 152
Social Responsibility 160
CORPORATE Governance 164
   
Operating and financial review and prospects 170
CONSOLIDATED Financial Performance 171
Financial Performance BY BUSINESS SEGMENT 181
Liquidity and Capital Resources 184
Other Information 195
   
Management and employees 197
Management 198
Employees 219
   
Compliance and internal controls 229
Compliance 230
Related Party Transactions 235
Controls and Procedures 237
Ombudsman and Internal Investigations 238
   
Shareholder information 240
Listing 240
Shares and Shareholders 242
Shareholders’ Rights 247
Dividends 252
Additional information for NON-BRAZILIAN shareholders 256
   
Legal and tax 259
Regulation 260
Material Contracts 267
Legal Proceedings 271
Tax 277
   
Additional information 294
List of Exhibits 295
Signatures 301
Abbreviations 302
Conversion table 303
Cross Reference to Form 20-F 304
   
Financial Statements f-1
 
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DISCLAIMER

In order to present information to investors in a manner more consistent with how we view our business, last year we altered the structure and order of the disclosure in our annual report on Form 20-F. In this annual report on Form 20-F for the year ended December 31, 2020 (referred to herein as our “annual report”), we have included a cross reference guide to SEC Form 20-F under “Cross-Reference to Form 20-F”, in order to facilitate your review.

Unless the context otherwise indicates, please consider this report the annual report of Petróleo Brasileiro S.A. – Petrobras. Unless the context otherwise requires, the terms “Petrobras,” “we,” “us” and “our” refer to Petróleo Brasileiro S.A. – Petrobras and its consolidated subsidiaries, joint operations and structured entities.

Our audited consolidated financial statements, presented in U.S. dollars, included in this annual report and the financial information contained in this annual report that is derived therefrom are prepared in accordance with the International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).

Our functional currency and the functional currency of all of our Brazilian subsidiaries is the Brazilian real and the functional currency of most of our entities that operate outside Brazil, such as Petrobras Global Finance B.V. or PGF, is the U.S. dollar. In this annual report, references to “real,” “reais” or “R$” are to Brazilian reais and references to “U.S. dollars” or “US$” are to United States dollars.

Forward-Looking Statements

This annual report includes forward-looking statements that are not based on historical facts and are not assurances of future results. The forward-looking statements contained in this annual report, which address our expected business and financial performance, among other matters, contain words such as “believe,” “expect,” “estimate,” “anticipate,” “intend,” “plan,” “aim,” “will,” “may,” “should,” “could,” “would,” “likely,” “potential” and similar expressions (which are not the exclusive means of identifying such forward-looking statements).

Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date on which they are made. There is no assurance that the expected events, trends or results will actually occur.

We have made forward-looking statements that address, among other things:

our marketing and expansion strategy;
our exploration and production activities, including drilling;
our activities related to refining, import, export, transportation of oil, natural gas and oil products, petrochemicals, power generation, biofuels and other sources of renewable energy;
our projected and targeted Capital Expenditures, commitments and revenues;
our liquidity and sources of funding;
our pricing strategy and development of additional revenue sources; and
the impact, including cost, of acquisitions and divestments.

Our forward-looking statements are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Our actual results could differ materially from those expressed or forecast in any forward-looking statements as a result of a variety of assumptions and factors. These factors include, but are not limited to, the following:

our ability to obtain financing;
general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates;
 
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global economic conditions;
our ability to find, acquire or gain access to additional reserves and to develop our current reserves successfully;
uncertainties inherent in making estimates of our oil and gas reserves, including recently discovered oil and gas reserves;
competition;
technical difficulties in the operation of our equipment and the provision of our services;
changes in, or failure to comply with, laws or regulations, including with respect to fraudulent activity, corruption and bribery;
receipt of governmental approvals and licenses;
international and Brazilian political, economic and social developments, including the role of the Brazilian government, as our controlling shareholder, in our business;
natural disasters, accidents, military operations, acts of sabotage, wars or embargoes;
global health crises, such as the Covid-19 pandemic;
the cost and availability of adequate insurance coverage;
our ability to successfully implement asset sales under our portfolio management program;
our ability to succesfully implement our Strategic Plan, whether that Strategic Plan remains in place, and the direction of any subsequent strategic plans;
the outcome of ongoing corruption investigations and any new facts or information that may arise in relation to the Lava Jato investigation;
the effectiveness of our risk management policies and procedures, including operational risk;
potential changes to the composition of our Board of Directors and our management team; and
litigation, such as class actions or enforcement or other proceedings brought by governmental and regulatory agencies.

For additional information on factors that could cause our actual results to differ from expectations reflected in forward-looking statements, see “Risks” in this annual report.

All forward-looking statements attributed to us or a person acting on our behalf are qualified in their entirety by this cautionary statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or future events or for any other reason.

 
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The crude oil and natural gas reserve data presented or described in this annual report are only estimates, which involve some degree of uncertainty, and our actual production, revenues and expenditures with respect to our reserves may materially differ from these estimates.

Documents on Display

We are subject to the information requirements of the Exchange Act, and accordingly our reports and other information filed and furnished by us with the SEC may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You can obtain further information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also inspect our reports and other information at the offices of the New York Stock Exchange, or NYSE, at 11 Wall Street, New York, New York 10005, on which our ADSs are listed. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov and at our website at www.petrobras.com.br/ir. The information available on these websites, which might be accessible through a hyperlink resulting from the URLs, is not and shall not be deemed to be incorporated into this annual report. For further information about obtaining copies of our public filings at the NYSE, call (212) 656-5060.

We also furnish reports on Form 6-K to the SEC containing our unaudited consolidated interim financial statements and other financial information of our company.

We also file audited consolidated financial statements, unaudited consolidated interim financial information and other periodic reports with the CVM.

 
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GLOSSARY

Glossary of certain terms used in this Annual Report

Unless the context indicates otherwise, the following terms are defined as follows:

ACL Free Marketing Environment (Ambiente de Comercialização Livre). Market segment in which the purchase and sale of electric energy are the subject of freely negotiated bilateral agreements, according to specific marketing rules and procedures.
ACR Regulated Marketing Environment (Ambiente de Comercialização Regulado). Market segment in which the purchase and sale of electric power between selling agents and distribution agents, preceded by a bidding process, except for cases provided by law, according to specific marketing rules and procedures.
ADR American Depositary Receipt.
ADS American Depositary Share.
Amex Oil The NYSE Arca Oil Index is a price-weighted index of the leading companies involved in the exploration, production, and development of petroleum. It measures the performance of the oil industry through changes in the sum of the prices of component stocks. The index was developed with a base level of 125 as of August 27, 1984.
AMS Our health care plan (Assistência Multidisciplinar de Saúde).
ANP The Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (National Petroleum, Natural Gas and Biofuels Agency) is the federal agency that regulates the oil, natural gas and renewable fuels industry in Brazil.
API Standard measure of oil density developed by the American Petroleum Institute.
B3 Brasil, Bolsa, Balcão, the Brazilian Stock Exchange.
BioQav Fuel produced from several biomass sources in different production processes, also known as “biojet” or “biokerosine” or “SAF” (synthetic aviation fuel) and named by the ANP as “Alternative Jet Fuel”, which must be added to jet fuel up to a maximum limit that varies from 10% to 50% by volume depending on the production process, as defined in ASTM (American Society for Testing and Materials) Annex D-7566 and ANP Resolution 778/2019.
 
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Biofuel Any fuel that is derived from biomass (plant, algae material or animal waste). It is produced through biological processes, such as agriculture and anaerobic digestion and it is considered renewable energy. Biodiesel and ethanol can be used as a fuel for vehicles, pure or added to diesel or gasoline to reduce the levels of carbon. Biodiesel is produced from oils or fats using a transesterification process, and ethanol is made by fermentation mostly from carbohydrates produced in sugar or starch crops such as corn, sugarcane or sweet sorghum.
Barrels Standard measure of crude oil volume.
BNDES Brazilian Development Bank (Banco Nacional de Desenvolvimento Econômico e Social).
Braskem Braskem S.A. is currently the largest producer of thermoplastic resins in the Americas and the largest producer of polypropylene in the United States. Its production focuses on polyethylene (PE), polypropylene (PP) and polyvinylchloride (PVC) resins, in addition to basic chemical inputs such as ethylene, propylene, butadiene, benzene, toluene, chlorine, soda, and solvents, among others. Together, they make up one of the most comprehensive portfolios in the industry by also including the green polyethylene produced from the sugarcane, from 100% renewable sources. 
Brazilian Treasury The Brazilian National Treasury is a Federal Government Secretariat, responsible for managing the financial resources that enter in the public safes. The mission of the National Treasury is managing the public accounts in an efficient and transparent way, ensuring a balanced fiscal policy and the quality of public expenditure, in order to contribute to the sustainable economic development.
Brent Crude Oil A major trading classification of light crude oil that serves as a major benchmark price for commercialization of crude oil worldwide.
CADE

Administrative Council for Economic Defense (Conselho Administrativo de Defesa

Econômica)

Câmara de Arbitragem do Mercado An arbitration chamber governed and maintained by B3.
Capital Expenditures or “CAPEX” Capital expenditures based on the cost assumptions and financial methodology adopted in our strategic plans, which includes acquisition of intangible assets and property, plant and equipment, investment in investees and other items that do not necessarily qualify as cash flows used in investing activities, comprising geological and geophysical expenses, research and development expenses, pre-operating charges, purchase of property, plant and equipment on credit and borrowing costs directly attributable to works in progress.
CEO Chief Executive Officer.
CFO Chief Financial Officer.
Central Bank of Brazil The Banco Central do Brasil.
Central Depositária The Central Depositária de Ativos e de Registro de Operações do Mercado, which serves as the custodian of our common and preferred shares (including those represented by ADSs) on behalf of our shareholders.
CGU The Controladoria Geral da União (General Federal Inspector’s Office) is an advisory body of the Brazilian Presidency responsible for assisting in matters related to the protection of federal public property (patrimônio público) and the improvement of transparency in the Brazilian executive branch, through internal control activities, public audits, and the prevention and combat of corruption, among others.
 
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CMN The Conselho Monetário Nacional (National Monetary Council) is the highest authority of the Brazilian financial system, responsible for the formulation of the Brazilian currency, exchange and credit policy, and for the supervision of financial institutions.
CNODC CNODC Brasil Petróleo e Gás Ltda.
CNOOC CNOOC Petroleum Brasil Ltda.
Condensate Hydrocarbons that are in the gaseous phase at reservoir conditions but condense into liquid as they travel up the wellbore and reach separator conditions.
COMPERJ The Complexo Petroquímico do Rio de Janeiro (Petrochemical Complex of Rio de Janeiro).
CONAMA The Conselho Nacional do Meio Ambiente (National Council for the Environment in Brazil).
CNPE The Conselho Nacional de Política Energética (National Energy Policy Council) is an advisory body of the President of the Republic assisting in the formulation of energy policies and guidelines.
CVM The Comissão de Valores Mobiliários (Brazilian Securities and Exchange Commission).
D&M DeGolyer and MacNaughton, an independent petroleum engineer consulting firm that conducts reserves evaluation of part of our net proved crude oil, condensate and natural gas reserves.
Deepwater Between 300 and 1,500 meters (984 and 4,921 feet) deep.  
Depositary JPMorgan.
Distillation The process by which liquids are separated or refined by vaporization followed by condensation.
DoJ The U.S. Department of Justice.
E&P Exploration & Production is our business segment that covers the activities of exploration, development and production of crude oil, NGL and natural gas in Brazil and abroad.
Eletrobras Centrais Elétricas Brasileiras S.A.
Exchange Act Securities Exchange Act of 1934, as amended.
EWT Extended well test.
Fitch Fitch Ratings Inc., a credit rating agency.
Focus Survey The Central Bank of Brazil carries out the Focus Survey compiling forecasts of about 140 banks, asset managers and others institutions.
FPSO Floating production, storage and offloading unit.
G&P Gas & Power is our business segment that covers the activities of logistics and trading of natural gas and electricity, transportation and trading of LNG, generation of electricity by means of thermoelectric power plants, as well as holding interests in transportation and distribution companies of natural gas in Brazil and abroad. It also includes natural gas processing and fertilizer operations.
 
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Gaspetro Petrobras Gás S.A. is our subsidiary and a holding company that carries out the commercialization, import, export, storage and distribution of natural gas in Brazil. It consolidates our equity interests in 19 of the 27 state natural gas distributors, with Mitsui holding the remaining 49% interest.
GHG Greenhouse gas.
GSA Long-term Gas Supply Agreement entered into with the Bolivian state-owned company Yacimientos Petroliferos Fiscales Bolivianos.
GTB Gás Transboliviano S.A.
HCC or Hydrocracking Conversion of heavier intermediate streams into the middle distillates boiling range (kerosene and diesel) in the presence of specific catalyst, hydrogen and severe conditions of temperature and pressure to produce high quality fuels. Depending on feedstock quality and operational conditions it is possible to direct production towards high quality lubes as well.
HDT or Hydrotreating Process widely used in oil refining industry to remove heteroatoms such as sulfur and nitrogen from gasoline, kerosene and/or diesel in the presence of specific catalysts, hydrogen and adequate conditions of temperature and pressure. The aim is to adjust composition to comply with fuel specifications.
HSE Health, Safety and Environmental.
IASB International Accounting Standards Board.
IBAMA The Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis (Brazilian Institute of the Environment and Renewable Natural Resources).
Ibovespa or IBOV The gross total return index weighted by free float market cap and comprised of the most liquid stocks traded on the B3. It was created in 1968.
Inovar-Auto This was a government program that proposed automotive industry to invest in research and development of more efficient and safe vehicles in exchange for tax benefits.
IMO International Maritime Organization.
IOF Imposto sobre Operações Financeiras (Brazilian taxes over financial transactions).
IPCA The Índice Nacional de Preços ao Consumidor Amplo (National Consumer Price Index).
JPMorgan JPMorgan Chase Bank, N.A.
Lava Jato Operação Lava Jato, as detailed in “Risks Factors” and “Legal and Tax – Legal Proceedings – Lava Jato Investigation” in this annual report.
LIBOR The London Interbank Offered Rate is a benchmark interest rate at which major global banks lend to one another in the international interbank market for short-term loans.
LNG Liquefied natural gas.
LPG Liquefied petroleum gas, which is a mixture of saturated and unsaturated hydrocarbons, with up to five carbon atoms, used as domestic fuel.
MME The Ministério de Minas e Energia (Ministry of Mines and Energy) of Brazil.
Moody’s Moody’s Investors Service, Inc., a credit rating agency.
ME The Ministério da Economia of Brazil (Ministry of Economy, former MPDM – Ministério do Planejamento, Desenvolvimento e Gestão).
 
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Natural Gasoline (C5+) Natural Gasoline C5+ is a NGL produced at natural gas processing plants with a vapor pressure intermediate between condensate and LPG, that may compose a gasoline blend.  
Nelson complexity index (NCI) It is a pure cost index that provides a relative measure of the construction costs of a particular refinery based on its crude and upgrading capacity. The NCI compares the costs of various upgrading units to the cost of a pure crude distillation unit, where more complex refineries are able to produce lighter, more heavily refined and valuable products from a barrel of oil. While the complexity factor is independent of the refinery capacity, multiple units of the same process, like multiple hydro treaters or coking units, for example, do increase complexity.
NGL The liquid resulting from the processing of natural gas and containing the heavier gaseous hydrocarbons.
NYSE The New York Stock Exchange.
OCF Operating Cash Flow (net cash provided by operating activities).
Oil Crude oil, including NGLs and condensates.
Oil Products Produced through processing at refineries such as diesel, gasoline, liquid fuel, LPG and other products.
ONS The Operador Nacional do Sistema Elétrico (National Electric System Operator) of Brazil.  
OPEC Organization of the Petroleum Exporting Countries.
Operating income (loss) The line equivalent to Net income (loss) before finance income (expense), results in equity-accounted investments and income taxes derived from our audited consolidated financial statements.
Organic Reserves Replacement Ratio or Organic RRR Measures the amount of proved reserves added to a company’s reserve base during the year, excluding disposals and acquisitons of proved reserves, relative to the amount of oil and gas produced.
OSRL The Oil Spill Response Limited.
OTC Offshore Technology Conference.
Petrochemicals Chemicals obtained in petrochemical industries such as ethane, propene, benzene, xylenes, polypropylene, polyethylene and others.
Petros Fundação Petros de Seguridade Social, Petrobras’ employee pension fund.
Petros 2 Petrobras’ sponsored pension plan.
PFLOPS One PFLOPS equals the processing capacity of a quadrillion mathematical operations per second.
PGF Petrobras Global Finance B.V.
PifCo Petrobras International Finance Company S.A.
PLSV Pipe laying support vessel.
Post-salt reservoir A geological formation containing oil or natural gas deposits located above a salt layer.
PP&E Property, plant and equipment.
PPSA Pré-Sal Petróleo S.A.
 
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Pre-salt Polygon Underground region formed by a vertical prism of undetermined depth, with a polygonal surface defined by the geographic coordinates of its vertices established by Law No. 12,351/2010, as well as other regions that may be delimited by the Brazilian Federal Government, according to the evolution of geological knowledge.
Pre-salt reservoir A geological formation containing oil or natural gas deposits located beneath a salt layer.
Proved reserves Consistent with the definitions in Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the unweighted arithmetic average of the first-day-of-the-month price during the twelve- month period prior to December 31, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that we will commence the project within a reasonable time. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir or an analogous reservoir, provides support for the engineering analysis on which the project or program was based.
Proved developed reserves Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.
Proved undeveloped reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
PTAX The reference exchange rate for the purchase and sale of U.S. dollars in Brazil, as published by the Central Bank of Brazil.
R&D Research and development.
RNEST The Refinaria Abreu e Lima (Abreu e Lima Refinery).
Refining Refining, Transportation and Marketing is our business segment that covers the activities of refining, logistics, transport and trading of crude oil and oil products in Brazil and abroad, exports of ethanol, petrochemical operations, such as extraction and processing of shale, as well as holding interests in petrochemical companies in Brazil.
 
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Reserves Replacement Ratio or RRR Measures the amount of proved reserves added to a company’s reserve base during the year relative to the amount of oil and gas produced.
Reserves to production ratio or R/P Calculated as the amount of proved reserves of the year relative to the amount of oil and gas produced during the year, indicates a number of years reserves would last if production remains constant.
S&P Standard & Poor’s Financial Services LLC, a credit rating agency.
SEC The United States Securities and Exchange Commission.
SELIC The Central Bank of Brazil base interest rate.
Sete Brasil Sete Brasil Participações, S.A.
Shell Shell Brasil Petróleo Ltda.
Synthetic oil and synthetic gas A mixture of hydrocarbons derived by upgrading (i.e., chemically altering) natural bitumen from oil sands, kerogen from oil shales, or processing of other substances such as natural gas or coal. Synthetic oil may contain sulfur or other non-hydrocarbon compounds and has many similarities to crude oil.
SPE Society of Petroleum Engineers.
SS Semi-submersible platform.
Strategic Plan 2021-2025 Strategic Plan
TAG Transportadora Associada de Gás S.A. is a company operating in the natural gas transportation industry, currently holding long-term permits to operate and manage a 4,500 km gas pipeline system, located mainly in the North and Northeast regions of Brazil, with installed capacity of 75 million m³/d.
TCU The Tribunal de Contas da União (Federal Auditor’s Office) is a constitutionally established body linked to the Brazilian Congress, responsible for assisting it in matters related to the supervision of the Brazilian Federal Government and its resources with respect to accounting, finance, budget, operational and public property (patrimônio público) matters.
TBG Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. is a company operating in the natural gas transportation industry, currently holding long-term permits to operate and manage a 2,593 km gas pipeline system, located mainly in the South and Southeast regions of Brazil, with installed capacity of 30 million m³/d. Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. is connected to GTB, which permits access to Bolivian natural gas.
TJLP The Brazil long-term interest rate (Taxa de Juros de Longo Prazo) is set quarterly by the National Monetary Council. The rate is used as the benchmark rate for loans from the BNDES to companies.
Total Total E&P do Brasil Ltda.
Transfer of Rights Agreement An agreement under which the Brazilian Federal Government assigned to us the right to explore and produce up to five billion barrels of oil equivalent “bnboe”) in specified pre-salt areas in Brazil. See “Material Contracts” in this annual report.
Transpetro Petrobras Transporte S.A.
TRI Total recordable injury per million man-hour frequency rate.
Ultra-deepwater Over 1,500 meters (4,921 feet) deep.
 
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UPGN Natural-gas processing Units (Unidade de Processamento de Gás Natural, in Portuguese). A natural gas processing plant is a facility designed to process raw natural gas from the offshore production fields by separating impurities and various non-methane hydrocarbons and fluids through different technologies to produce specified natural gas for final consumption. Through the process a gas processing plant can also recover natural gas liquids (condensate, natural gasoline and liquefied petroleum gas) with higher added value.
YPFB Yacimientos Petroliferos Fiscales Bolivianos.
 
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ABOUT US

We are a Brazilian company with over 49,000 employees committed to generate more value for our shareholders and the society, with a focus on oil and gas, with safety and respect for people and the environment. We are one of the largest companies in market capitalization in Latin America, with a market capitalization of US$72.5 billion as of December 31, 2020. We are one of the largest producers of oil and gas in the world, primarily engaged in exploration and production, refining, energy generation and trading. We have a large proven reserve base and have acquired expertise in deep and ultra-deepwater exploration and production as a result of almost 50 years spent developing the Brazilian offshore basins, becoming world leaders in this segment.

Datasheet

Name of the company: Petróleo Brasileiro S.A. – Petrobras

Date of Incorporation: 1953

Country of Incorporation: Brazil

Registration number at the CVM: 951-2

Central Index Key (or “CIK”) at the SEC: 0001119639

Address of principal executive office: Avenida República do Chile 65, 20031-912, Rio de Janeiro, RJ, Brazil

Telephone number: (55 21) 3224 4477

Corporate and investor relations websites: www.petrobras.com.br and www.petrobras.com.br/ir.

The information on these websites, which might be accessible through a hyperlink resulting from both URL, is not and shall not be deemed to be incorporated into this annual report.

Corporate purpose established in our Bylaws: research, extraction, refining, processing, trading and the transport of oil, its by-products, natural gas and other fluid hydrocarbon from wells, shale and other rocks, in addition to energy-related activities, and the research, development, production, transport, distribution, sale and trading of all forms of energy, and other related activities or similar purposes.

 
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Overview

We have a large base of proved reserves and operate and produce the majority of Brazil’s oil and gas. The majority of our proved reserves are located in the adjacent offshore Campos and Santos Basins in southeast Brazil. Their proximity allows us to optimize our infrastructure and limit our costs of exploration, development and production. Additionally, we have developed technical knowledge in deepwater exploration and production from almost 50 years of developing Brazil’s offshore basins, including the Campos and Santos Basins. The Campos and Santos Basins are expected to remain the main source of our future growth in proved reserves and oil and gas production.

Our business, however, goes beyond the oil and gas exploration and production. It entails a long process through which we get the oil and gas to our refineries and gas treatment units which themselves must be equipped and in constant evolution to supply the best products.

We operate the majority of the refining capacity in Brazil. Our refining capacity is substantially concentrated in southeast Brazil, within the country’s most populated and industrialized markets and adjacent to the sources of most of our crude oil in the Campos and Santos Basins. We meet our demand for oil products through a planned combination of domestic refining of crude oil and oil products imports, seeking value creation. We are also involved in the production of petrochemicals through stakes in some companies. We distribute oil products through wholesalers and retailers.

We also participate in the Brazilian natural gas market, including the logistics, distribution and processing of natural gas.

To meet domestic demand, we process natural gas derived from our onshore and offshore production (mainly from fields in the Campos, Espírito Santo and Santos Basins), import natural gas from Bolivia and import liquefied natural gas (“LNG”) through our regasification terminals. We also participate in the domestic power market primarily through our investments in gas-fired, fuel oil and diesel oil thermoelectric power plants and in renewable energy.

We currently divide our business into three main segments:

Exploration and Production (“E&P”): this segment covers the activities of exploration, development and production of crude oil, Natutal Gas Liquids (“NGL”) and natural gas in Brazil and abroad, for the primary purpose of supplying our domestic refineries. The E&P segment also operates through partnerships with other companies, including holding interests in non-Brazilian companies in this segment.
 
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Refining, Transportation and Marketing (“Refining”): this segment covers the activities of refining, logistics, transport, marketing and trading of crude oil and oil products in Brazil and abroad, exports of ethanol, petrochemical operations, such as extraction and processing of shale, as well as holding interests in petrochemical companies in Brazil.
Gas and Power (“G&P”): this segment covers the activities of logistics and trading of natural gas and electricity, transportation and trading of LNG, generation of electricity by means of thermoelectric power plants, as well as holding interests in transportation and distribution companies of natural gas in Brazil and abroad. It also includes natural gas processing and fertilizer operations.

Activities that are not attributed to the business segments are classified as “Corporate and Other Businesses” including, notably those related to corporate financial management, corporate overhead and other expenses, provision for the class action settlement, and actuarial expenses related to the pension and medical benefits for retired employees and their dependents. It also comprises biofuels and distribution businesses. The biofuels business covers the activities of production of biodiesel and its co-products and ethanol. The distribution business covers the equity interest in the associate BR Distribuidora and the business for the distribution of oil products abroad (South America).

For further information regarding our business segments, see Notes 13 and 33 to our audited consolidated financial statements, as well as “Operating and Financial Review and Prospects” in this annual report.

In 2020 we had activities in eight countries besides Brazil (i.e., Argentina, Bolivia, Colombia, Uruguay, the U.S., Netherlands, United Kingdom and Singapore). In Latin America, our operations include exploration and production, marketing, and retail services, including natural gas. In North America, we produce oil and gas through a joint venture. We have controlled companies in London, Rotterdam, Houston, and Singapore that support our trade and financial activities. They constitute a complete and active trading desk for markets worldwide, responsible for market intelligence and marketing of oil, oil products, natural gas, commodity derivatives and shipping. Beginning in 2021, we will end our European trading activities in the United Kingdom and concentrate them only in the Netherlands. In February 2021 we ended our operational activities in Uruguay with the sale of our shares in the distribution company.

We operate through 20 direct subsidiaries (18 incorporated under the laws of Brazil and two incorporated abroad) and two direct joint operations as listed below. We also have indirect subsidiaries, including Petrobras Global Finance B.V. (“PGF”).

Companies  Location   Our shareholding   Other
shareholders
 
Petrobras Transporte S.A. – Transpetro   Brazil    100%   —   
Petrobras Logística de Exploração e Produção S.A. – PB-LOG   Brazil    100%     
Petrobras Gás S.A. – Gaspetro   Brazil    51%   Mitsui Gás e Energia do Brasil Ltda (49%) 
Petrobras Biocombustível S.A.   Brazil    100%   —   
Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. – TBG   Brazil    51%   

BBPP Holdings Ltda. (29%)
YPFB Transporte S.A. (12%)
GTB-TBG Holdings S.À.R.L. (8%)

 
Procurement Negócios Eletrônicos S.A.   Brazil    72%   

SAP Brasil Ltda. (17%)
Accenture do Brasil S.A. (11%)

 
Araucária Nitrogenados S.A.   Brazil    100%   —   
Termomacaé S.A.   Brazil    100%   —   
 
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Breitener Energética S.A.   Brazil    94%   

Alcântara, Mendes & Cia Ltda (1%)
Arcadis Logos Energia S.A. (1%)
Orteng Equipamentos e Sistemas Ltda (1%)
GGR Participações S.A. (3%)

 
Termobahia S.A.   Brazil    99%   Petros (1%) 
Baixada Santista Energia S.A.   Brazil    100%   —   
Petrobras Comercializadora de Energia S.A. – PBEN   Brazil    100%   —   
Fundo de Investimento Imobiliário RB Logística – FII   Brazil    99%   Pentágono SA DTVM (1%) 
5283 Participações S.A.   Brazil    100%   —   
Fábrica Carioca de Catalisadores S.A. – FCC(1)   Brazil    50%   Albemarle Brazil Holding Ltda. (50%) 
Ibiritermo S.A.(1)   Brazil    50%   Edison S.p.A (50%) 
Petrobras International Braspetro – PIB BV   Abroad    100%   —   
Braspetro Oil Services Company – Brasoil   Abroad    100%   —   
Refinaria Mucuripe S.A.(2)   Brazil    100%   —   
Refinaria de Manaus S.A.(2)   Brazil    100%   —   
Paraná Xisto S.A.(2)   Brazil    100%   —   
Refinaria Mataripe(2)   Brazil    100%   —   

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(1)Joint operations.
(2)Companies legally established, with capital contribution of US$ 58.000 for each company, for the subsequent divestment of these refineries.

For a complete list of our subsidiaries and joint operations, including each of their full names, jurisdictions of incorporation and our percentage of equity interest, see Exhibit 8.1 to this annual report and Note 30 to our Financial Statements. Additionally, we participate in consortia that engage in the exploration of blocks and the production of oil fields in Brazil – see “Our Business, E&P, Overview” for more details.

 
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RECENT DEVELOPMENTS

Pending Changes in our Senior Management and Board of Directors

The Brazilian federal government controls a majority of our voting shares and has the right to elect a majority of the members of our Board of Directors. Our Board of Directors, in turn, selects our management.

On February 19, 2021, the Brazilian federal government, through the Ministry of Mines and Energy (MME), issued a formal notice (oficio) to the Chairman of our Board of Directors requesting that the Chairman call a general shareholders meeting for the election of Directors. The notice designated Joaquim Silva e Luna to replace Roberto da Cunha Castello Branco as a Director, based on the Brazilian federal government’s power to remove members of the Board of Directors. It also requested the Board of Directors to subsequently consider and elect Mr. Silva e Luna to replace Mr. Castello Branco as our CEO. Media reports have suggested that the decision to replace Mr. Castello Branco was related to our February 2021 announcement of increases in prices for diesel and gasoline products.

Under Brazilian law, the removal of a Director elected by cumulative voting automatically results in the removal of all other Directors elected through the same mechanism. Mr. Castello Branco and seven other Directors were elected by cumulative voting in the July 2020 Ordinary Shareholders Meeting. The MME notice proposed that, at the meeting to replace Mr. Castello Branco, the other Directors be re-elected for the balance of their terms. However, five of the seven have since announced that they would not accept their nomination for the election (João Cox Neto, Nivio Ziviani, Paulo Cesar de Souza e Silva, Omar Carneiro da Cunha Sobrinho and Leonardo Pietro Antonelli).

On March 5, 2021, the Brazilian federal government, through MME and the Ministry of Economy, designated six individuals for election to the Board of Directors: Eduardo Bacellar Leal Ferreira (for Chairman of the Board), Joaquim Silva e Luna, Ruy Flaks Schneider, Márcio Andrade Weber, Murilo Marroquim de Souza and Sonia Julia Sulzbeck Villalobos.

On March 8, 2021, minority shareholders designated Leonardo Pietro Antonelli for a Board position in the event that the election is conducted using cumulative voting. Under Brazilian law, the election of our Board members must be by cumulative voting if requested by holders of at least 5% of the outstanding shares. If cumulative voting is adopted, the Brazilian federal government may not be able to elect all of its designees in the general shareholders meeting.

On March 10, 2021, the Brazilian federal government, through MME, designated two more individuals for election to the Board of Directors: Cynthia Santana Silveira and Ana Silvia Corso Matte. These additional designations completed the list of eight nominees by the Brazilian federal government.

On March 11, 2021, our Board of Directors called an Extraordinary General Meeting, to be held on April 12, 2021, for the election of eight Directors.

Continuing Uncertainty Concerning our Senior Management and Board of Directors

The election of our Board of Directors will take place at the Extraordinary General Meeting to be held on April 12, 2021. This meeting may provide more definition about the future of Petrobras, the composition of our Board of Directors and our management team. However, the situation is changing rapidly and there can be no certainty as to the outcome of that meeting, the composition of our Board of Directors or our management team.

For a current list of our Executive Officers and Board of Director members as of the date of this annual report, see “Management and Employees – Management” and “Management and Employees – Executive Officers” in this annual report.

It is possible that members of our Board of Directors may resign prior to the Extraordinary General Meeting. Our CEO is expected to depart once his removal is approved by a majority of votes at the Extraordinary General Meeting. It is also possible that our CFO and other members of our senior management may depart, whether by termination or resignation, after the Extraordinary General Meeting. On March 24, 2021, four of our executive officers, Andrea Almeida, Chief Financial and Investor Relations Officer, Carlos Alberto Pereira de Oliveira, Chief Exploration and Production Officer, André Chiarini, Chief Trading and Logistics Officer, and Rudimar Andreis Lorenzatto, Chief Production Development Officer, informed our Board that they do not intend to renew their respective terms in such positions. Although their terms expired on March 20, 2021, they will continue to serve until their successors are appointed, in accordance with Brazilian law. On March 24, 2021, our Board approved the appointment of Salvador Dahan as our new Chief Governance and Compliance Officer, to be effective following completion of all internal processes. If there are vacancies at the Board of Directors or in senior management, it is possible that such positions will not be filled promptly.

 
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The potential changes to the composition of our Board of Directors and our management team may result in significant additional uncertainty. It is difficult to predict the future strategic, business or policy decisions or views that any newly-elected members of our Board of Directors or our management team may take or have, and we cannot predict how this will affect our business, our results of operations and our financial condition, which could in turn adversely affect the value of our securities.

Potential Changes to our Strategic Plan and our Pricing Policies

Our Strategic Plan consists of our continuous evaluation of the business environment and the implementation of our strategies, allowing for adjustments to be made in a more efficient way. See “Strategic Plan—2021-2025 Strategic Plan” in this annual report. The recent developments described above, including any changes to our Board of Directors and our management team, may affect not only our ability to implement our Strategic Plan, but whether that Strategic Plan remains in place, as well as the direction of any subsequent strategic plans, including decisions related to the management of our operations and investments.

Our current pricing policy in Brazil takes into account domestic market conditions and seeks to align the price of oil products with international prices. Specifically, diesel oil, gasoline, LPG, jet fuel, fuel oil and other minor product prices are defined taking into account the international import parity price, margins to remunerate the risks inherent in our operations and the level of market share.

In 2021, we raised fuel prices according to international price parity as global oil prices surged. Although we announced increases in fuel prices in early March, on March 24, 2021, we announced that we would decrease wholesale diesel prices by 4.2% and wholesale gasoline prices by 4.4%, effective on March 25, 2021. For more information, see “Risks—Financial Risks—Our cash flow and profitability are exposed to the volatility of prices of oil, gas and oil products” and “Our Business—Refining, Transportation and Marketing—Marketing—Oil products prices.” The Brazilian federal government has recently made statements regarding the need to modify and adjust our pricing policy for domestic conditions.

In February 2021, the Brazilian federal government announced, for a two-month period, changes in state fuel taxes, and in March 2021, announced that it would eliminate federal taxes on diesel fuel (for two months) and residential LPG.

In view of the statements made by the Brazilian President and the recent developments described above, the new CEO, the new management team or the new Board of Directors may propose changes to our pricing policies, including a decision that such policies will not seek for alignment with international price parity. Changes to our fuel pricing policy could have a material adverse effect on our business and prospects, our results of operations and our financial condition, which could in turn adversely affect the value of our securities.

Lava Jato Investigation

In 2021, the Brazilian Supreme Court started to decide cases brought by criminal defendants in Lava Jato proceedings aimed at nullifying criminal convictions relating to the investigation. These cases are still in progress and their outcomes may affect our interests. For more information, see “Risks—Risk Factors—We may face additional proceedings related to the Lava Jato investigation” and “Legal and Tax—Legal Proceedings—Lava Jato Investigation” in this annual report.

Risk Factors

The recent developments described above may materially and adversely impact our business, prospects, results of operations and financial condition, and the value of our securities. The role of the Brazilian federal government as our controlling shareholder presents specific risks for investors. For more information, see “Risks—Government Ownership and Country Risks” in this annual report.

 
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RISKS

The nature of our operations exposes us to a number of risks that could, individually or together, have an effect on our financial performance. We classify the risks to which we are exposed in the following groups: (i) operational risks, (ii) financial risks, and (iii) compliance, legal and regulatory risks. We also describe herein the risks arising from the government ownership and country risks, as well as debt and equity securities risks.

Risk Factors

Operational Risks

We are exposed to health, environment and safety risks in our operations, which may lead to accidents, significant losses, administrative proceedings and legal liabilities.

Some of our main activities present risks capable of leading to accidents, such as oil spills, product leaks, fires and explosions. In particular, deepwater, ultra-deepwater and refining activities present various risks, such as oil spills and explosions in our refineries and exploration and production units, including platforms, ships, pipelines, terminals and dams, among other assets owned or operated by us. These events may occur due to technical failures, human errors or natural events, among other factors. The occurrence of one of these events, or other related incidents, may result in various damages such as death, and serious environmental damage, and may impact our workforce or communities. They may cause property damage, loss of production, financial losses and, in certain circumstances, liability in civil, labor, criminal, environmental and administrative lawsuits. As a consequence, we may incur expenses for cleaning, repairing or remedying the damages caused.

We are also exposed to corporate security risks from acts of intentional interference by third parties in our downstream areas and pipelines, including illegal taps (thefts) of oil, gas and oil products, especially in the states of São Paulo and Rio de Janeiro. If this interference continues, we may experience short-term or long-term accidents, leaks or damage in our facilities as a result, which can impact the continuation of our operations. In addition, we may be compelled to indemnify for any damages caused to the environment or to third parties because of these incidents. In addition, public health epidemics and pandemics such as the Covid-19 outbreak could cause health restrictions to our workforce and, therefore, impact the operation of some of our facilities, including our platforms, refineries, terminals, among others. This condition could have a negative impact on our results and financial condition. Finally, due to risks such as those mentioned above, we may face difficulties in obtaining or maintaining operating licenses and may suffer damages to our image and reputation.

 
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Changes in the competitive environment of the Brazilian oil and gas market may intensify the requirements for our performance levels to remain in line with the best companies in the sector. The need to adapt to an increasingly competitive and more complex environment may compromise our ability to implement our current Strategic Plan or any subsequent plans adopted.

We may face greater competitive forces in the downstream segment in Brazil, with the emergence of new companies competing against us in this sector. If we are unable to maximize return on capital employed, reduce costs, sell our products competitively, and implement new technologies in our business, we may encounter adverse effects on our results and operations.

Additionally, in the upstream segment, we may not be successful in acquiring exploration blocks in future bidding rounds if our competitors are able to bid based on better cost and capital structures than us. In that case, we may therefore have difficulty in repositioning our portfolio towards upstream assets that offer higher profitability and competitive advantage, especially in the pre-salt layer, which could negatively affect our results.

In addition, changes in the regulatory framework and inquiries regarding compliance with antitrust and competition laws may subject us to penalties, business restrictions and difficulties in renewing concessions, adversely affecting our operations, results and reputation.

In order to create a favorable environment for new investors to enter the natural gas and refining industries in Brazil, we signed commitment agreements with the Administrative Council for Economic Defense (CADE) and the National Petroleum, Natural Gas and Biofuels Agency (ANP). Under the agreements, we committed to include some of our shareholding participation in companies and assets of the gas transportation and distribution segments in our divestment program and to renounce some of the contracted transportation network capacity (of injection and withdrawal volumes), which would create more competitive conditions to encourage new economic agents to enter the downstream market. Failure to comply with these commitment agreements may result in negative impacts such as administrative proceedings and fines.

Failures in our information technology systems, information security (cybersecurity) systems and telecommunications systems and services can adversely impact our operations and reputation.

Our operations are highly dependent on information technology and communications systems and services. Interruption or malfunction affecting these systems and/ or their infrastructure, as a result of obsolescence, technical failures and/or deliberate acts, may harm or halt our business and adversely impact our operations and reputation.

Moreover, information security failures, including automation systems, either due to external acts, deliberate or unintentional, such as malware, hacking and cyberterrorism, or internal ones, such as negligence and misuse from employees or contractors, may also cause impacts on our business, our reputation, our relationship with stakeholders and external agents (government, regulatory bodies, partners, suppliers and others), our strategic positioning towards our competitors and our results. According to Law No. 13,709/2018 – Lei Geral de Proteção de Dados Pessoais (“LGPD”), we will be subject to penalties in cases of disclosure or misuse of personal information.

The selection and development of our investment projects have risks that may affect our expected results.

We have numerous project opportunities in our portfolio of investments. Since most projects are characterized by a long development period, we may face changes in market conditions, such as changes in prices, consumer preferences and demand profile, exchange and interest rates and financing conditions of projects that may jeopardize our expected rate of return on these projects.

We also face specific risks for oil and gas projects. Despite our experience in the exploration and production of oil in deepwater and ultra-deepwater and the continuous development of studies during the planning stages, the quantity and quality of oil produced in a certain field will only be fully known in the phases of deployment and operation, which may require adjustments throughout the project lifecycle and its expected rate of return.

 
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Furthermore, decommissioning projects have grown and become more relevant to our portfolio as concession contracts and production systems expire. With the recent publication of Resolution ANP 817/2020, we might face some difficulties in defining the scope of these decommissioning projects and meeting the regulation requirements, particularly in light of our and the industry’s learning curve in this area.

Moreover, despite our experience in exploration and production, we may face new technical challenges as we move closer to the technology frontier.

In addition, public health epidemics and pandemics such as the Covid-19 outbreak could cause restrictions on of our workforce, partners and suppliers, that could have an impact in the productivity of various activities.

External factors could impact the successful implementation of our partnerships and our portfolio management.

Pursuant to our Strategic Plan, our divestment portfolio includes several assets in different stages of the sales process, which we expect to conclude in the coming years.

External factors, such as the decline of oil prices, exchange rate fluctuations, the deterioration of the Brazilian economy and global economic conditions, the Brazilian political scenario, judicial and administrative decisions, the passing of new laws, among other unpredictable factors, may reduce, delay or hinder sale opportunities for these assets or affect the price at which we can sell them.

Our Strategic Plan is adapted from time to time by our management; we cannot assure you that our Strategic Plan will not be changed in the future. In the event our Strategic Plan changes based on the decisions of the Brazilian federal government as our controlling shareholder, our divestment plan might be revised. See “—Risks Relating to Our Relationship with the Brazilian Federal Government—The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us” and “Recent Developments” in this annual report. In addition, any changes to our Board of Directors and our management team may affect not only our ability to implement our Strategic Plan, but whether that Strategic Plan remains in place, as well as the direction of any subsequent strategic plans, including decisions related to the management of our operations and investments. See “Recent Developments” in this annual report.

If we are unable to successfully implement our planned partnerships and divestments, or if our divestment plan is modified, this may negatively impact our business, results and financial condition, including by potentially exposing us to short and medium-term liquidity constraints.

Climate change could impact our results and strategy.

Climate change poses new challenges and opportunities for our business. More stringent environmental regulations can result in the imposition of costs associated with greenhouse gas emissions, either through environmental agency requirements relating to mitigation initiatives or through other regulatory measures such as carbon pricing taxation limitations on greenhouse gas emissions, which have the potential to increase our operating costs and reduce production.

In addition, environmental laws that may be implemented in the future could increase litigation risks and have a material adverse effect on us.

The risks associated with climate change could also include difficulties to access capital due to public image issues with investors; changes in the consumer profile, with reduced consumption of fossil fuels; and energy transitions in the world economy, towards a lower carbon matrix, with the insertion of substitute products for fossil fuels and the increasing use of electricity for urban mobility. These factors may have a negative impact on the demand for our products and services and may jeopardize or even impair the implementation and operation of our businesses, adversely impacting our results and financial condition and limiting some of our growth opportunities.

 
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Maintaining our long-term objectives for oil production depends on our ability to successfully obtain and develop oil reserves.

Our ability to maintain our long-term objectives for oil production is highly dependent upon our ability to obtain additional reserves and to successfully develop our existing reserves.

Our ability to obtain additional reserves depends upon exploration activities, which demand significant capital investments, expose us to the inherent risks, and may not lead to the discovery of commercially producible crude oil or natural gas reserves. We may also obtain additional reserves by proposing and implementing new development projects. Deepwater reservoirs exploitation demands significant investments and involves numerous factors beyond our control, such as significant changes in economic conditions, delays in availability of offshore equipment and critical resources, and unexpected operational conditions, including equipment failures or incidents, that may cause operations to be curtailed, delayed or cancelled.

In addition, increased competition in the oil and gas sector in Brazil and our own capital constraints may make it more difficult or costly to obtain additional acreage in bidding rounds for new contracts and to explore existing contracted areas.

We are not insured against business interruption for our Brazilian operations, and most of our assets are not insured against war or sabotage.

We generally do not maintain insurance coverage for business interruptions of any nature for our Brazilian operations, including business interruptions caused by labor disputes. If, for instance, our workers or those of our key third-party suppliers, vendors and service providers were to strike, the resulting work stoppages could have an adverse effect on us. In addition, we do not insure most of our assets against war or sabotage. Therefore, an attack or an incident causing an interruption of our operations could have a material adverse effect on our results and financial condition.

Additionally, our insurance policies do not cover all types of risks and liabilities related to safety, environment, health, government fees, fines or punitive damages, which may impact our results. There can be no guarantee that incidents will not occur in the future, that there will be insurance to cover the damages or that we will not be held responsible for these events, all of which may negatively impact our results.

In addition, we cannot guarantee that the amounts of insurance coverage contracted to cover risks related to our activities will be sufficient to guarantee, in the event of a claim, the payment of all damages caused, which may adversely affect our business and results.

Strikes, work stoppages or labor unrest by our employees or by the employees of our suppliers or contractors could adversely affect our results and our business.

Disagreements on how we manage our business, in particular divestments and their implications for our personnel, changes in our strategy, human resources policies regarding remuneration, benefits and headcount, employee contributions to cover the deficit of our pension plan, implementation of regulations recently created relating to health and pension plans and changes in labor law may lead to judicial inquiries, labor unrest, strikes and stoppages.

Strikes, work stoppages or other forms of labor unrest at any of our facilities or in major suppliers, contractors or their facilities or in sectors of society that affect our business could impair our ability to complete major projects and impact our ability to continue our operations and achieve our long-term objectives.

Our success also depends on our ability to continue to train and qualify our personnel so they can assume qualified senior positions in the future. We cannot assure you that we will be effective in training and qualifying our workforce sufficiently, nor that we will be able to achieve this goal without incurring additional costs. Any such failure could adversely affect our results and our business.

 
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We rely on suppliers of goods and services for the operation and execution of our projects and, as a result, we may be adversely affected by failures or delays of such suppliers.

We are susceptible to the risks of performance and product quality within our supply chain. If our suppliers and service providers delay or fail to deliver goods and services owed to us, we may not meet our operational goals within the expected timeframe. In this case, we may ultimately need to postpone one or more of our projects, which may have an adverse effect on our results and financial condition.

Additionally, there may be risks of delays in the customs clearance process caused by external factors, which may impact the supply of goods to us and affect our operations and projects.

Furthermore, disruptions due to health events such as Covid-19 could have a negative impact on our results and on our supply chain as well.

Our projects and operations may affect, and be affected by, the expectations and dynamics of the communities where we operate, impacting our business, image and reputation.

It is part of our policy to respect human rights and maintain responsible relationships with the local communities located where we operate. However, the various locations where we operate are exposed to a wide range of issues related to political, social and economic instability, as well as intentional acts, such as illegal diversion, crime, theft, sabotage, terrorism, roadblocks and protests. We cannot control the changes in local dynamics and the expectations of the communities where we operate and establish our businesses.

Social impacts that result from our decisions and direct and indirect activities – especially those related to divestments – and disagreements with these communities and local governments may affect the schedule or budget of our projects, hinder our operations due to potential lawsuits, have a negative financial impact and harm our image and reputation.

Water scarcity in some regions where we operate may impact the availability of water in the quantity and/or quality required for our operations, as well as difficulties in obtaining grants of the right to use water resources, impacting the business continuity of our industrial units.

We have industrial facilities that demand the use of water, ranging from large users such as refineries to small users like distribution bases and terminals that, although not very hydro-intensive, are logistically important within our chain. In recent years, several regions of the world, including some regions in Brazil, have experienced events of shortage of freshwater, including for public consumption. In case of water scarcity, the grants pursuant to which we have the right to use water resources may be suspended or temporarily modified and, as a result, we may be required to reduce or suspend our production activities, because the availability of water for public consumption and watering of animals has priority over industrial use. This may jeopardize our business continuity, as well as generate financial impacts on us and our image.

Developments in the economic environment and in the oil and gas industry and other factors have resulted, and may result, in substantial write-downs of the carrying amount of certain of our assets, which could adversely affect our results and financial condition.

We evaluate on an annual basis, or more frequently when the circumstances require, the carrying amount of our assets for possible impairment. Our impairment tests are performed by a comparison of the carrying amount of an individual asset or a cash generating unit with its recoverable amount. Whenever the recoverable amount of an individual asset value or cash generating unit is less than its carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount.

Changes in the economic, regulatory, business or political environment in Brazil or other markets where we operate, such as the recent significant decline in international crude oil and gas prices, the depreciation of the real, as well as changes in financing conditions, such as deterioration of risk perception and interest rates, for such projects, among other factors, may affect the original profitability estimates of our projects, which could adversely affect our results.

 
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The ability to develop, adapt, access new technologies and take advantage of opportunities related to innovations in digital technology is fundamental to our competitiveness.

The availability of technologies that ensure the maintenance of our reserve rates and the viability of production in an efficient manner, as well as the development of new products and processes that respond to environmental regulations and new market trends, play a key role in increasing our long-term competitiveness. In the event some disruptive technology is introduced into the energy industry, changing performance standards, it would be important for us to have access to this technology, which may impact our competitiveness in relation to other companies.

Recent advances in data acquisition and analysis, connectivity, artificial intelligence, robotics and other technologies are changing the sources that create competitive advantage. Eventual failure to capture these opportunities may have an impact on our competitiveness in the energy market and our long-term objectives.

Our crude oil and natural gas reserve estimates involve some degree of uncertainty, which could adversely affect our ability to generate income.

Our proved crude oil and natural gas reserves set forth in this annual report are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic and operating conditions (i.e. using prices and costs as of the date the estimate is made) according to applicable regulations. Reserve estimates presented are based on assumptions and interpretations, which are subject to risks and uncertainties. If the geological and engineering data that we use to estimate our reserves are not accurate, our reserves may be lower than the ones currently indicated in the volume estimates of our portfolio and reported by companies that conduct an evaluation on our reserves estimates. In addition, reserve estimates may be affected by significant changes in economic conditions. Downward revisions in our reserve estimates indicate lower future production, which could have an adverse effect on our results and financial condition.

We do not own any of the subsoil accumulations of crude oil and natural gas in Brazil.

Under Brazilian law, the Brazilian federal government owns all subsoil accumulations of crude oil and natural gas in Brazil and, according to the Brazilian regulation, the concessionaire or contracted party owns the oil and gas it produces from those subsoil accumulations pursuant to applicable agreements executed with the Brazilian federal government. We possess, as a concessionaire or contracted party of certain oil and natural gas fields in Brazil, the exclusive right to develop the volumes of crude oil and natural gas included in our reserves pursuant to concession and other agreements. Access to crude oil and natural gas reserves is essential to an oil and gas company’s sustained production and generation of income, and our ability to generate income would be adversely affected if the Brazilian federal government were to restrict or prevent us from exploiting these crude oil and natural gas reserves.

As a result of divestments and partnerships, we are exposed to risks that could lead to unforeseen financial losses.

Upon completion of each divestment or partnership (post-closing stage), we must perform integrated management and monitoring of the actions required and provided for in the contracts related to each project, paying attention to the fulfillment of the obligations established for the buyer and the seller. In the event of non-compliance with these obligations, the financial adjustments between the parties may show results different from the ones expected at the time of divestment or partnership. In addition, as determined by the ANP in the event of total or partial sale of our participation in E&P contracts, we remain jointly liable for abandonment costs after the new concessionaire’s production closes, should it default on this task. Such joint liability covers obligations arising prior to or after the transfer, provided that it arises from activities carried out on a date prior to the transfer. The same is true for any environmental liabilities.

Additionally, our sale of assets may negatively impact existing synergies or logistical issues within our company which may adversely affect our results.

 
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In addition, our partners may not be able to meet their obligations, including financial obligations, which may jeopardize the viability of some projects in which we participate. When we act as operators, our partners may have the right to veto certain decisions, which may also affect the viability of some projects. Regardless of the partner responsible for the operations of each E&P project, we may be exposed to the risks associated with those operations, including litigation (where joint liability could apply) and the risk of government sanctions arising from such partnerships, which could have a material adverse effect on our operations, reputation, cash flow and financial condition.

We have assets and investments in other countries in South America, where the political, economic and social situation may negatively impact our business.

Although we have significantly reduced our participation abroad, we still operate and have businesses in several countries, particularly in South America in areas where there may be political, economic and social instabilities. In such regions, external factors may adversely affect the results and the financial condition of our subsidiaries in these countries, including: (i) the imposition of price controls; (ii) the imposition of restrictions on hydrocarbon exports; (iii) the fluctuation of local currencies against the real; (iv) nationalization of our oil and gas reserves and our assets; (v) increases in export tax and income tax rates for oil and oil products; and (vi) unilateral (governmental) and contractual institutional changes, including controls on investments and limitations on new projects.

If one or more of the risks described above occurs, we may lose part or all of our reserves in the affected country and may also fail to achieve our strategic objectives in these countries, or in our international operations as a whole, which may negatively impact our results and financial resources.

The performance of companies licensed to use our brands may impact our image and reputation.

Our divestment plan includes the partial or total sale of our companies in the fuel distribution segment and some of these businesses involve licensing agreements for our brands. Once a licensee holds the right to display our brands in products, services and communications, it can be perceived by stakeholders as our legitimate representative or spokesperson. Licensees’ actions or events related to their business, such as, failures, accidents, errors in business performance, environmental crises, corruption scandals and improper use of our brand, among other factors, may negatively impact our image and reputation.

Financial Risks

Our cash flow and profitability are exposed to the volatility of prices of oil, gas and oil products.

Most of our revenue derives primarily from sales of crude oil, oil products and, to a lesser extent, natural gas. International prices for oil and oil products are volatile and strongly influenced by conditions and expectations of world supply and demand. In addition, public health epidemics and pandemics (such as the Covid-19 pandemic during 2020) could affect oil prices and demand, which, consequently, may affect our financial results. Volatility and uncertainty in international oil prices are structural and likely to continue. Changes in oil prices usually result in changes in the prices of oil products and natural gas.

Currently, diesel and gasoline prices are defined taking into account the international import parity price, margins to remunerate the risks inherent in our operations and the level of market share. Price adjustments can be made at any time. Since one of our pricing objectives is to maintain fuel prices in parity with global market trends, substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results and financial condition, and may also affect the value of our proved reserves.Additionally, the periodicity of the fuel readjustments, determined by us, may be revised due to exogenous factors that affect our customers, such as the transportation sector, among others and consequently, our business.

 
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In the past, our management has adjusted our pricing of oil, gas and oil products from time to time. In the future, there may be periods during which our product prices will not be at parity with international product prices. Actions of the Brazilian government, as our controlling shareholder, could affect these pricing decisions. See “—Risks Relating to Our Relationship with the Brazilian Federal Government—The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us.” We cannot guarantee that our way of setting prices will not change in the future. As a result, when we are a net importer by volume of oil and oil products to meet Brazilian demand, increases in the price of crude oil and oil products in the international markets may have a negative impact on our costs of sales and margins, since the cost to acquire such oil and oil products may exceed the price at which we are able to sell these products in Brazil. A similar effect occurs when the real depreciates in relation to the U.S. dollar, as we sell oil and oil products in Brazil in reais and international prices for crude oil and oil products are set in U.S. dollars. A depreciation of the real increases our cost of imported oil and oil products, without a corresponding increase in our revenues unless we are able to increase the price at which we sell products in Brazil.

The Brazilian President has, at times, made statements regarding the need to modify and adjust our pricing policy for domestic conditions. In view of the statements made by the Brazilian President and the recent developments described in “Recent Developments” above, a new CEO, a new management team or Board of Directors may propose changes to our pricing policies, including a decision that such policies will not seek for alignment with international price parity. Changes to our fuel pricing policy could have a material adverse impact on our businesses, results, financial condition, and the value of our securities. See “Recent Developments” in this annual report.

We have substantial liabilities and may be exposed to significant liquidity constraints in the near and medium term, which could materially and adversely affect our financial condition and results.

We have incurred in a substantial amount of debt related to investments decisions taken in the past and in order to finance the capital expenditures needed to meet our long-term objectives.

Since there may be liquidity restrictions on the debt market to finance our planned investments and repay principal and interest obligations under the terms of our debt, any difficulty in raising significant amounts of debt capital in the future may impact our results and the ability to fulfill our Strategic Plan or any subsequent plan adopted.

The loss of our investment grade credit rating and any further lowering of our credit ratings could have adverse consequences on our ability to obtain financing in the market through debt or equity securities, or may impact our cost of financing, also making it more difficult or costly to refinance maturing obligations. The impact on our ability to obtain financing and the cost of financing may adversely affect our results and financial condition.

In addition, our credit rating is sensitive to any change in the credit rating of the Brazilian federal government. Any further lowering of the Brazilian sovereign’s credit ratings may have additional adverse consequences on our ability to obtain financing or the cost of our financing, and consequently, on our results and financial condition.

We are vulnerable to increased debt service resulting from depreciation of the real in relation to the U.S. dollar and increases in prevailing market interest rates.

As of December 31, 2020, 84.9% of our financial debt was denominated in currencies other than the real. A substantial portion of our indebtedness is, and is expected to continue to be, denominated in or indexed to the U.S. dollar and other foreign currencies. A further depreciation of the real against any of these other currencies will increase our debt service in reais, as the amount of reais necessary to pay principal and interest on foreign currency debt will increase with this depreciation.

Foreign exchange variations may have an immediate impact on our reported income. According to our cash flow hedge accounting policy, hedging relationships are designated for the existing natural hedge between our U.S. dollar denominated future exports that are considered to be highly probable (hedged item) and U.S. dollar denominated financial debt (hedging instruments).

 
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Following a depreciation of the real, some of our operating expenses, capital expenditures, investments and import costs will increase. As most of our revenues are denominated in reais but linked to Brent prices in U.S. dollars, unless we increase the prices of our products in the local market to reflect the depreciation of the real, our cash generation relative to our capacity to service debt may decline.

To the extent we refinance our maturing obligations with newly contracted debt, we may incur additional interest expense.

As of December 31, 2020, 41.9% of our finance debt consisted of floating rate debt. We generally do not enter into derivative contracts or similar financial instruments or make other arrangements with third parties to hedge against the risk of an increase in interest rates.

To the extent that such floating rates rise, we may incur in additional expenses. Moreover, as we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated or to which it is indexed.

Changes that affect the composition of our debt and cause rises in short or long-term interest rates may increase our debt service payments, which could have an adverse effect on our results and financial condition.

The obligations relating to our pension plan (“Petros”) and health care benefits (“AMS”) are estimates, which are reviewed annually, and may diverge from actual future contributions due to changes in market and economic conditions, as well as changes in actuarial assumptions.

The criteria used for determining commitments relating to pension and health care plan benefits are based on actuarial and financial estimates and assumptions with respect to (i) the calculation of projected short-term and long-term cash flows and (ii) the application of internal and external regulatory rules. Therefore, there are uncertainties inherent in the use of estimates that may result in differences between the forecasted value and the actual realized value. In addition, the financial assets held by Petros to cover pension obligations are subject to risks inherent to investment management and such assets may not generate the necessary returns to cover the relevant liabilities, in which case extraordinary contributions from us, as sponsor, and the participants, may be required.

With respect to health care benefits (AMS), the projected cash flows can also be impacted by (i) higher medical costs than expected; (ii) additional claims arising from the extension of benefits; and (iii) difficulties in adjusting the contributions of participants to reflect increases in health care costs.

In addition, we and Petros face risks relating to pension funds in lawsuits that may occasionally require additional disbursements from us.

These risks may result in an increase in our liabilities and may adversely affect our results and our financial conditions.

We are exposed to the credit risks of certain of our customers and associated risks of default. Any material nonpayment or nonperformance by some of our customers could adversely affect our cash flow, results and financial condition.

Some of our customers may experience financial constraints or liquidity issues that could have a significant negative effect on their creditworthiness. Severe financial issues encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.

In addition, many of our customers finance their activities through their cash flows from operations, the incurrence of short and long-term debt.

Declining economic conditions in Brazil, and resulting decreased cash flows, combined with a lack of debt or equity financing for our customers may affect us, since many of our customers are Brazilian and may have significantly reduced liquidity and limited ability to make payments or perform their obligations.

 
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This could result in a decrease in our cash flow and may also reduce or curtail our customers’ future demand for our products and services, which may have an adverse effect on our results and financial condition.

Compliance, Legal and Regulatory Risks

We may incur losses and spend time and financial resources defending pending litigations and arbitrations.

We are currently party to numerous legal and administrative proceedings relating to civil, administrative, tax, labor, environmental and corporate claims filed against us. These claims involve substantial amounts of money and other remedies, and the aggregate cost of unfavorable decisions could have a material adverse effect on our results and financial condition.

We may be frequently affected by changes in rules and regulation.

In addition, changes in rules and regulations applicable to us may have a material adverse effect on our financial condition and results.

These legal and administrative proceedings can have a negative impact on our results due to their outcome, such as contracts` termination and/or the revision of governmental authorizations.

Depending on the outcome, litigation can result in restrictions on our operations and have a material adverse effect on some of our businesses.

Failures to prevent, detect in a timely manner, or correct behaviors inconsistent with our ethical principles and rules of conduct may have a material adverse effect on our results and financial condition.

We are subject to the risk that our management, employees, contractors, or any person doing business with us may engage in fraudulent activity, corruption or bribery, circumvent or override our internal controls and procedures or misappropriate or manipulate our assets for their personal benefit or of third parties, against our interest.

This risk is heightened by the fact that we have many complex, high value contracts with local and foreign suppliers, as well as the geographic distribution of our operations and the wide variety of counterparties involved in our business.

We cannot guarantee that all our employees and contractors will comply with our principles and rules of ethical behavior and professional conduct aimed at guiding our management, employees and service providers. Any failure, whether actual or perceived, to abide by our ethical principles or to comply with applicable governance or regulatory obligations could harm our reputation, limit our ability to obtain financing and have a material adverse effect on our results and financial condition, if not detected in a timely manner.

We are subject to the risk that our internal controls may become inadequate in the future because of changes in conditions, or that our degree of compliance with our policies and procedures may deteriorate.

Because of its inherent limitations, our internal control over financial reporting may not prevent or detect misstatements. It is also difficult to project the effectiveness of internal control over financial reporting for future periods, as our controls may become inadequate because of changes in conditions, or because our degree of compliance with our policies or procedures may deteriorate and we cannot be certain that in the future additional material weaknesses will not occur or otherwise be identified in a timely manner.

Any failure to maintain our internal control over financial reporting could adversely impact our ability to report our financial results in future periods accurately and in a timely manner, and to file required forms and documents with government authorities, including the SEC. We may also be unable to detect accounting errors in our financial reports or may even have to restate our financial results. Any of these occurrences may adversely affect our business and operation, and may generate negative market reactions, potentially affecting our financial conditions leading to a decline of our shareholder value.

 
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Any violation of the agreements that resolved the investigations conducted by the SEC and the DoJ and potential future investigations regarding the possibility of noncompliance with the U.S. Foreign Corrupt Practices Act could adversely affect us. Violations of this or other laws may require us to pay fines and expose us and our employees to criminal sanctions and civil suits.

In 2018, in light of facts uncovered in connection with the Lava Jato investigation, we entered into a nonprosecution agreement (“NPA”) with the DoJ, pursuant to which we admitted that certain of our former executives and officers had engaged in conduct during the period from 2004 to 2012 that gave rise to violations of books and records and internal controls provisions under U.S. law. As part of the SEC resolution, we settled charges of violation of the United States Securities Act of 1933 and the books and records and internal control provisions of the Securities Exchange Act of 1934, without admitting the SEC allegations.

If, during the term of the NPA (three years, unless extended), the DoJ determines that we have committed a felony under U.S. federal law, provided deliberately false or misleading information, or otherwise breached the NPA, we could be subject to prosecution and additional fines or penalties, including charges under the U.S. Foreign Corrupt Practices Act (“FCPA”).

The Lava Jato investigation is still in progress by Brazilian authorities and additional relevant information affecting our interests may come to light. Adverse developments in relation to any of the above matters could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations. In connection with any further investigations or proceedings carried out by any authorities in Brazil or in any other jurisdiction, or any violation of the NPA, we may be required to pay fines or other financial relief, or consent to injunctions or orders on future conduct or suffer other penalties, any of which could have a material adverse effect on us.

We may face additional proceedings related to the Lava Jato investigation.

In 2018 and 2019, we paid a total of US$2,950 million in the United States to settle a consolidated securities class action filed in connection with the Lava Jato proceedings.

We are currently party to a collective action commenced in the Netherlands, an arbitration proceeding in Argentina, and arbitration and judicial proceedings commenced in Brazil. In each case, the proceedings were brought by investors (or entities that allegedly represent investors’ interests) who purchased our shares traded on the B3 Stock Exchange or other securities issued by us outside of the United States, alleging damages caused by facts uncovered in the Lava Jato investigations.

In Argentina, we are the defendant in two criminal lawsuits. The first lawsuit alleges non-compliance by us with the obligation to disclose to the Argentinian market a pending class action filed by Consumidores Financieros Asociación Civil para su Defensa before the Judicial Commercial Courts, pursuant to provisions of Argentine capital markets law. The second criminal action alleges a fraudulent offer of securities aggravated by allegedly false information included in our financial statements issued prior to 2015.

In addition, EIG Management Company, LLC (“EIG Management”) and eight of EIG Management’s managed funds (“EIG Funds”) (together with EIG Management, “EIG”) filed a complaint against us on February 23, 2016 before the United States District Court for the District of Columbia. The dispute arises out of the EIG Funds’ indirect purchase of equity interests in Sete Brasil Participações S.A., and EIG currently has claims against us for fraud and aiding and abetting fraud related to the Lava Jato investigation. EIG seeks damages of at least US$221 million.

It is possible that additional complaints or claims might be filed in the United States, Brazil, or elsewhere against us relating to the Lava Jato investigation in the future. It is also possible that further information damaging to us and our interests will come to light in the course of the ongoing investigations of corruption by Brazilian authorities. Our management may be required to direct its time and attention to defending these claims, which could prevent them from focusing on our core business.

 
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In addition, as a result of the continuing Lava Jato investigation, substantive additional information may come to light in the future that would make the estimate that we made in 2014 for overpayments incorrectly capitalized appear, retrospectively, to have been materially low or high. In prior years, we were required to write off capitalized costs representing amounts that we overpaid for the acquisition of property, plant and equipment. We may be required to restate our financial statements to further adjust the write offs representing the overstatement of our assets recognized in our audited consolidated financial statements for prior years.

Differing interpretations and numerous environmental, health and safety regulations and industry standards that are becoming more stringent may result in increased capital and operating expenditures and decreased production.

Our activities are subject to evolving industry standards and best practices, and a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health, safety and the environment, both in Brazil and in other jurisdictions where we operate. These laws, regulations and requirements may result in significant costs, which may have a negative impact on the profitability of the projects we intend to implement or may make such projects economically unfeasible.

Any substantial increase in expenditures for compliance with environmental, health or safety regulations may have a material adverse effect on our results and financial condition. These increasingly stringent laws, regulations and requirements may result in significant decreases in our production, including unplanned shutdowns, which may also have a material adverse effect on our results and financial condition.

Moreover, we have operational units in several metropolitan regions of the country and, in some of these locations, the concentration of pollutants generated by a variable set of polluters (industries, passenger cars, trucks, etc.) may exceed the air quality standards defined by legislation. Recently, more restrictive air quality standards were defined, which may increase the demands on industrial units installed in regions that already have air quality problems. This could include obstacles to obtaining or renewing operating licenses and the need to adopt new environmental control practices such as new types of practices, increasing the frequency of monitoring emissions and installing new environmental protection equipment, generating higher costs for us. There is also a risk that the use of fuels will be subject to restrictions related to the level of pollutant emissions, which may increase the need for investments in refineries or loss of market.

In addition, changes in interpretation or differing interpretations regarding environmental, health and safety regulations, as well as our decision to settle any claims related to such regulations, could have a material adverse effect on our financial condition and results.

Differing interpretations of tax regulations or changes in tax policies could have an adverse effect on our financial condition and results.

We are subject to tax rules and regulation that may be interpreted differently over time, or that may be interpreted differently by us and Brazilian tax authorities (including the federal, state and municipal authorities), both of which could have a financial impact on our business. In some cases, when we have exhausted all administrative appeals relating to a tax contingency, further appeals must be made in the judicial courts, which may require that, in order to appeal, we provide collateral to judicial courts, such as the deposit of amounts equal to the potential tax liability in addition to accrued interest and penalties. In certain of these cases, settlement of the matter may be a more favorable option for us.

We may face similar situations in which our interpretation of a tax regulation may differ from that of tax authorities, or tax authorities may dispute our interpretation and we may eventually take unanticipated provisions and charges. In addition, the eventual settlement of one tax dispute may have a broader impact on other tax disputes. Any of these occurrences could have a material adverse effect on our financial condition and results.

 
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Differences in interpretations and new regulatory requirements by the agencies in our industry may result in our need for increased investments, expenses and operating costs, or may cause delays in production.

Our activities are subject to regulation and supervision by regulatory agencies, such as the ANP. Issues such as local content requirements, procedures for the unification of areas, definition of reference prices for the calculation of royalties and governmental participation, among others, are subject to a regulatory regime overseen by the ANP.

Any regulatory change, as well as change or differences of interpretation between us and regulatory agencies may materially impact our results, since such newly enacted or revised pronouncements or interpretations may directly affect the economic and technical assumptions that guide our investment decisions.

We are subject to sanctions or the granting of environmental licenses and permits, that may result in delays to deliver some of our projects and difficulties to reach our crude oil and natural gas production objectives.

Our activities are subject to and depend on the granting of environmental licenses and permits by a wide variety of federal, state and local laws, relating to the protection of human health, safety and the environment, both in Brazil and in other jurisdictions in which we operate. As environmental, health and safety regulations become increasingly complex, it is possible that our efforts to comply with such laws and regulations will increase substantially in the future.

We cannot ensure that the planned schedules and budgets of our projects, including the decommissioning of mature fields and divestments, will not be affected by demands of new regulatory bodies or that the relevant licenses and permits will be transferred or issued in a timely manner. Potential delays in obtaining licenses may impact our crude oil and natural gas production objectives, negatively influencing our results and financial condition.

We are also subject to sanctions that may result in delays in the execution of some of our projects and difficulties in achieving our oil and natural gas production objectives, such as embargoes or partial or total interdictions.

Operations with related parties may not be properly identified and handled.

Transactions with related parties must follow market standards and generate mutual benefit. Decision processes surrounding such transactions must be objective and documented. Further, we must comply with the rules of competition and adequate disclosure of information, in accordance with the applicable legislation and as determined by the CVM and the SEC. The possible failure of our process to identify and deal with these situations may adversely affect our economic and financial condition, as well as lead to regulatory assessments by agencies.

We may be required by courts to guarantee the supply of products or services to defaulted counterparties.

As a company controlled by the federal government and operating throughout Brazil, we may be required by the Brazilian courts to provide products and services to clients, whether public or private institutions, with the purpose of guaranteeing supplies to the domestic oil and gas market, even in situations where these clients and institutions are in default with contractual or legal obligations. Such supply in exceptional situations may adversely affect our financial position.

 
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Government Ownership and Country Risks

The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us.

Our Board of Directors consists of a minimum of seven and a maximum of eleven members, who are elected at our shareholders’ meeting for a term of up to two years, with a maximum of three consecutive reelections allowed. Brazilian law requires that the Brazilian federal government owns a majority of our voting stock, and so long as it does, the Brazilian federal government will have the power to elect a majority of the members of our Board of Directors and, through them, the executive officers who are responsible for our day-to-day management. As a result, we may engage in activities that give preference to the objectives of the Brazilian federal government rather than to our own economic and business objectives, which may have an adverse effect on our results and financial condition. The interests of our controlling shareholder may differ from the interests of our other shareholders, and the decisions taken by our controlling shareholder may involve different considerations, strategies and policies than they have in the past.

Presidential elections in Brazil occur every four years, and changes in elected representatives may lead to a change of the members of our Board of Directors appointed by the controlling shareholder, which may further impact the management of our business strategy, including our Strategic Plan, and guidelines, as mentioned above.

As our controlling shareholder, the Brazilian federal government has guided and may continue to guide certain macroeconomic and social policies through us, pursuant to Brazilian law. Accordingly, we may make investments, incur costs and engage in transactions with parties or on terms that may have an adverse effect on our results and financial condition.

Fragility in the performance of the Brazilian economy, regulatory changes and investor perception of these conditions may adversely affect the results of our operations and our financial performance and may have a material adverse effect on us.

Our activities are strongly concentrated in Brazil. Economic policies adopted by the Brazilian federal government may have important effects on Brazilian companies, including us, and on market conditions and prices of Brazilian securities. Our financial condition and results may be adversely affected by the following factors and the response of the Brazilian federal government to these factors:

exchange rate movements and volatility;
inflation;
financing of government fiscal deficits;
price instability;
interest rates;
liquidity of domestic capital and lending markets;
tax policy;
regulatory policy for the oil and gas industry, including pricing policy and local content requirements;
allegations of corruption against political parties, elected officials or other public officials, including allegations made in relation to the Lava Jato investigation; and
other diplomatic, social and economic developments in or affecting Brazil.

Uncertainty over whether the Brazilian federal government will implement changes in policy or regulations that may affect any of the factors mentioned above or other factors in the future may lead to economic uncertainty in Brazil and increase the volatility of the Brazilian securities market and securities issued abroad by Brazilian companies, which may have a material adverse effect on our results and financial condition.

 
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Instability in the Brazilian Political Environment.

The Brazilian economy has been and continues to be affected by political events in Brazil, which have also affected the confidence of investors and the public in general, adversely affecting the performance of the Brazilian economy and resulting in heightened volatility in the Brazilian securities markets. You should make your own assessment about Brazil and prevailing conditions in the country before deciding to invest in us.

The Brazilian political environment has been considered polarized in the past few years. Brazil had not fully recovered from the impact of the 2015-2016 economic crisis when the country began feeling the effects of the Covid-19 pandemic, which severely affected the economy and increased political tensions.

The Brazilian government’s policies to address economic and fiscal reforms in response to the Covid-19 pandemic remain divisive issues for Brazilian society. Any developments to the current political situation or any new relevant facts in connection with the Brazilian political situation could adversely affect Brazil’s economic growth and, in turn, affect our financial condition and results of operations.

In addition, any difficulties of the Brazilian government in obtaining a majority vote in the national congress to implement reforms may result in congressional gridlock and political unrest, which could adversely affect us. Uncertainties relating to the implementation by the Brazilian government of changes to monetary, fiscal and social security policies and related legislation may contribute to economic instability and heighten market volatility and may materially and adversely affect us.

Allegations of political corruption against members of the Brazilian government could create economic and political instability.

In the past, members of the Brazilian federal government and the Brazilian legislative branch have faced allegations of political corruption. As a result, a number of politicians, including senior federal officials and congressmen, resigned or have been arrested.

Currently, elected officials and other public officials in Brazil are being investigated for allegations of unethical and illegal conduct identified during the Lava Jato investigation being conducted by the Office of the Brazilian Federal Prosecutor. The potential outcome of these investigations is unknown, but they have already had an adverse impact on the image and reputation of the implicated companies (including us), in addition to the adverse impact on general market perception of the Brazilian economy. These proceedings, their conclusions or further allegations of illicit conduct could have additional adverse effects on the Brazilian economy. Such allegations may lead to further instability, or new allegations against Brazilian government officials and others may arise in the future, which could have a material adverse effect on us. We cannot predict the outcome of any such allegations nor their effect on the Brazilian economy.

Equity and Debt Securities Risks

The size, volatility, liquidity or regulation of the Brazilian securities markets may curb the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs.

Our shares are among the most liquid traded on the B3, but overall, the Brazilian securities markets are smaller, more volatile and less liquid than the major securities markets in the United States and other jurisdictions, and may be regulated differently from the way in which U.S. investors are accustomed. Factors that may specifically affect the Brazilian equity markets may limit the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs at the price and time they desire.

 
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Holders of our ADSs may be unable to exercise preemptive rights with respect to the common or preferred shares underlying the ADSs.

Holders of ADSs who are residents of the United States may not be able to exercise the preemptive rights relating to the common or preferred shares underlying our ADSs unless a registration statement under the Securities Act is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. We are not obligated to file a registration statement with respect to the common or preferred shares relating to these preemptive rights, and therefore we may not file any such registration statement. If a registration statement is not filed and an exemption from registration does not exist, JPMorgan, as depositary, will attempt to sell the preemptive rights, and holders of ADSs will be entitled to receive the proceeds of the sale. However, the preemptive rights will expire if the depositary cannot sell them. For a more complete description of preemptive rights with respect to the common or preferred shares, see “Shareholder Information – Shares and Shareholders – Shareholders’ Rights – Other Shareholders’ Rights” in this annual report.

If holders of our ADSs exchange their ADSs for common or preferred shares, they risk losing the ability to timely remit foreign currency abroad and other related advantages.

The Brazilian custodian for our common or preferred shares underlying our ADSs must obtain a certificate of registration from the Central Bank of Brazil to be entitled to remit U.S. dollars abroad for payments of dividends and other distributions relating to our preferred and common shares or upon the disposition of the common or preferred shares.

The conversion of ADSs directly into ownership of the underlying common or preferred shares is governed by CMN Resolution No. 4,373 and foreign investors who intend to do so are required to appoint a representative in Brazil for the purposes of CMN Resolution No. 4,373, who will be in charge for keeping and updating the investors’ certificates of registrations with the Central Bank of Brazil, which entitles registered foreign investors to buy and sell directly on the B3. Such arrangements may require additional expenses from the foreign investor. Moreover, if such representatives fail to obtain or update the relevant certificates of registration, investors may incur in additional expenses or be subject to operational delays which could affect their ability to receive dividends or distributions relating to the common or preferred shares or the return of their capital in a timely manner.

The custodian’s certificate of registration or any foreign capital registration directly obtained by such holders may be affected by future legislative or regulatory changes, and we cannot assure such holders that additional restrictions applicable to them, the disposition of the underlying common or preferred shares, or the repatriation of the proceeds from the process will not be imposed in the future.

Holders of our ADSs may face difficulties in protecting their interests.

Our corporate affairs are governed by our Bylaws and Law No. 6,404/76 (“Brazilian Corporate Law”), which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or elsewhere outside Brazil. In addition, the rights of an ADS holder, which are derivative of the rights of holders of our common or preferred shares, as the case may be, to protect their interests are different under Brazilian Corporate Law than under the laws of other jurisdictions. Rules against insider trading and self-dealing and the preservation of shareholder interests may also be different in Brazil than in the United States. In addition, the structure of a class action in Brazil is different from that in the U.S. Under Brazilian law, shareholders in Brazilian companies do not have standing to bring a class action, and under our Bylaws must, generally with respect to disputes concerning rules regarding the operation of the capital markets, arbitrate any such disputes. See “Shareholder Information – Shares and Shareholders – Dispute Resolution” in this annual report.

 
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We are a state-controlled company organized under the laws of Brazil, and all of our directors and officers reside in Brazil. Substantially all of our assets and those of our directors and officers are located in Brazil. As a result, it may not be possible for holders of ADSs to effect service of process upon us or our directors and officers within the United States or other jurisdictions outside Brazil or to enforce against us or our directors and officers’ judgments obtained in the United States or other jurisdictions outside Brazil. Because judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain requirements are met, holders of ADSs may face greater difficulties in protecting their interest in actions against us or our directors and officers than would shareholders of a corporation incorporated in a state or other jurisdiction of the United States.

Holders of our ADSs do not have the same voting rights as our shareholders. In addition, holders of ADSs representing preferred shares do not have voting rights.

Holders of our ADSs do not have the same voting rights as holders of our shares. Holders of our ADSs are entitled to the contractual rights set forth for their benefit under the deposit agreements. ADS holders exercise voting rights by providing instructions to the depositary, as opposed to attending shareholders’ meetings or voting by other means available to shareholders. In practice, the ability of a holder of ADSs to instruct the depositary as to voting will depend on the timing and procedures for providing instructions to the depositary, either directly or through the holder’s custodian and clearing system.

In addition, a portion of our ADSs represents our preferred shares. Under Brazilian Corporate Law and our Bylaws, except for specific situations, holders of preferred shares do not have the right to vote in shareholders’ meetings. Holders of ADSs representing preferred shares are not entitled to vote most of decisions as well. See “Shareholders – Shares and Shareholders – Shareholders Rights – Shareholders’ Meetings and Voting Rights” in this annual report.

The market for PGF’s debt securities may not be liquid.

Some of PGF’s notes are not listed on any securities exchange and are not quoted through an automated quotation system. Most of PGF’s notes are currently listed both on the NYSE and the Luxembourg Stock Exchange and trade on the NYSE Euronext and Euro Multilateral Trading Facility (“MTF”) market, respectively, although most trading in PGF’s notes occurs over-the-counter. PGF can issue new notes that can be listed in markets other than the NYSE and the Luxembourg Stock Exchange and traded in markets other than the NYSE Euronext and the Euro MTF market. We can make no assurance as to the liquidity of or trading markets for PGF’s notes. We cannot guarantee that the holders of PGF’s notes will be able to sell their notes in the future. If a market for PGF’s notes does not develop, holders of PGF’s notes may not be able to resell the notes for an extended period of time, if at all.

We would be required to pay judgments of Brazilian courts enforcing our obligations under the guaranty relating to PGF’s notes only in reais.

If proceedings were brought in Brazil seeking to enforce our obligations in respect of the guaranty relating to PGF’s notes, we would be required to discharge our obligations only in reais. Under Brazilian exchange controls, an obligation to pay amounts denominated in a currency other than reais, which is payable in Brazil pursuant to a decision of a Brazilian court, will be satisfied in reais at the rate of exchange in effect on the date of payment, as determined by the Central Bank of Brazil.

 
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A finding that we are subject to U.S. bankruptcy laws and that the guaranty executed by us was a fraudulent conveyance could result in PGF noteholders losing their legal claim against us.

PGF’s obligation to make payments on the PGF notes is supported by our obligation under the corresponding guaranty. We have been advised by our external U.S. counsel that the guaranty is valid and enforceable in accordance with the laws of the State of New York and the United States. In addition, we have been advised by our general counsel that the laws of Brazil do not prevent the guaranty from being valid, binding and enforceable against us in accordance with its terms. In the event that U.S. federal fraudulent conveyance or similar laws are applied to the guaranty, and we, at the time we entered into the relevant guaranty:

were or are insolvent or rendered insolvent by reason of our entry into such guaranty;
were or are engaged in business or transactions for which the assets remaining with us constituted unreasonably small capital; or
intended to incur or incurred, or believed or believe that we would incur, debts beyond our ability to pay such debts as they mature; and
in each case, intended to receive or received less than reasonably equivalent value or fair consideration therefor, then our obligations under the guaranty could be avoided, or claims with respect to that agreement could be subordinated to the claims of other creditors. Among other things, a legal challenge to the guaranty on fraudulent conveyance grounds may focus on the benefits, if any, realized by us as a result of the issuance of the PGF notes. To the extent that the guaranty is held to be a fraudulent conveyance or unenforceable for any other reason, the holders of the PGF notes would not have a claim against us under the relevant guaranty and would solely have a claim against PGF. We cannot ensure that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of the PGF noteholders relating to any avoided portion of the guaranty.

 

Corporate Risk Management

We believe that integrated and proactive risk management is essential for the delivery of results in a safe and sustainable way. Our risk-management process is centralized, allowing the standardization and uniformity of risk analysis and the management of risk responsibilities. We have an executive risk committee to advise our Board of Executive Officers in the analysis of matters relating to risk management. Each of our organizational units must identify, prioritize, monitor and, together with our business risks teams, periodically communicate to the executive risk committee the main risks involved in the activities performed by such unit, as well as planned mitigating actions.

In order to assist in this process, our corporate risk management policy establishes guidelines and responsibilities and is based on the following fundamental principles:

respect for life and life diversity;
full alignment and consistency with our Strategic Plan;
ethical behavior and compliance with legal and regulatory requirements;
integrated risk management; and
the risk response actions consider the possible long-term cumulative consequences, the possible impacts on our stakeholders and should be oriented towards preserving or adding value and for business continuity.

The risk management organizational structure, that is under the supervision of our CFO, is responsible for:

establishing a corporate methodology for risk management guided by an integrated and systemic view, which allows for an environment of continuous monitoring of risks in several hierarchical levels;
disseminating knowledge and supporting the use of risk management practices in organizational units; and
identifying, monitoring and reporting periodically to our Board of Executive Officers and Board of Directors regarding our major risks.
 
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In order to support the risk management process, our corporate risk management policy specifies authorities to be consulted, responsibilities to be undertaken, and five principles and ten guidelines that drive our risk management initiatives.

This policy has a comprehensive approach to corporate risk management, which combines the traditional economic and financial risk management approach with other relevant areas of interest, such as protection of life, health and environment, assets and business information protection (property and security) and combating fraud and corruption (legal and compliance), among other corporate risks. With a focus on integrating risk management actions, our policy allows any employee to have access to the terms and concepts related to risk management, as well as to the measures taken and parties responsible for the management of each of the risks we are exposed to.

For further information regarding our revised business risk management policy, please visit our website at www.petrobras.com.br/ir. The information on this website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be incorporated into this annual report.

 

Disclosures about Market Risk

Commodity Price Risk

We operate in an integrated manner throughout the various stages of the oil industry. A significant portion of our results relate directly to oil exploration and production, refining and the sale of natural gas, biofuels, and electricity in Brazil. As our purchases and sales of crude oil and oil products are linked to international commodity prices, we are exposed to their price fluctuations, which may influence our profitability, our cash flow from operations and our financial situation.

We prefer to maintain exposure to the price cycle than use financial derivatives to systematically protect purchases and sale transactions that focus on fulfilling our operation needs. However, based on crude oil market conditions and prospects of realization of our Strategic Plan, we may decide to implement protection strategies using financial instruments to manage our cash flow expenses.

In addition, we are party to derivative contracts in order to protect our margins for short-term commercial transactions carried out abroad. Our derivatives contracts provide economic hedges for oil product purchases and sales in the global markets, generally expected to occur within a 30 to 360-day period.

For more information about our commodity derivatives transactions, including a sensitivity analysis demonstrating the net change in fair value of a 25% (or 50%) adverse change in the price of the underlying commodity for options and futures, see Note 38 to our audited consolidated financial statements.

Exposure to interest rate and exchange rate risk

For information about interest rate and exchange rate risk, see “Operating and Financial Review and Prospects” in this annual report.

 

Insurance

Regarding operational risks, our policy is to maintain insurance coverage when the obligation to maintain such coverage derives from a legal or contractual instrument or our Bylaws; or the event covered may cause significant damage to our financial results, and coverage is economically feasible.

 
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We maintain several insurance policies, including policies against fire, operational risk, engineering risk, property damage coverage for onshore and offshore assets such as fixed platforms, floating production systems and offshore drilling units, hull insurance for tankers and auxiliary vessels, third party liability insurance and transportation insurance. The coverages of these policies are contracted according to the objectives we define and the limitations imposed by the global insurance and reinsurance markets. Although some policies are issued in Brazil, most of our policies are reinsured abroad with reinsurers rated A- or higher by Standard & Poor’s or A3 by Moody’s and/or B ++ or higher by A.M. Best.

Our policies are subject to deductibles, limits, exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all possible consequences and damages associated with our activities. Thus, it is not possible to assure that insurance coverage will exist for all damages resulting from possible incidents or accidents, which may negatively affect our results.

Specifically, we do not maintain insurance coverage to safeguard our assets in case of war or sabotage. We also do not maintain coverage for business interruption, except for some specific assets in Brazil. Generally, we do not maintain coverage for our wells in operation in Brazil, except when required by a joint operating agreement. In addition, our third-party liability policies do not cover government fines or punitive damages.

Our national property damage policies have a maximum deductible of US$180 million and their indemnity limits can reach US$2.2 billion for refineries and US$1.9 billion for platforms, depending on the replacement value of our assets.

Our general third-party liability policy with respect to our onshore and offshore activities in Brazil, including losses due to sudden pollution, such as oil spills, has a maximum indemnity limit of US$250 million with an associated deductible of US$10 million. We also maintain marine insurance with additional protection and indemnity against third parties related to our domestic offshore operations with an indemnity limit of US$50 million up to US$500 million, depending on the type of vessel. For activities in Brazil, in the event of an explosion or similar event on one of our non-fixed offshore platforms, these policies may provide third-party combined liability coverage of up to US$750 million. In addition, although we do not insure most of our pipelines against property damage, we have insurance against damages or losses to third parties arising from specific incidents, such as unexpected infiltration and oil pollution.

Outside Brazil, we maintain different levels of third-party liability insurance, as a result of a variety of factors, including country risk assessments, whether we have onshore and offshore operations, or legal requirements imposed by a particular country in which we operate. We maintain separate well-control insurance policies in our international operations to cover liabilities arising from the uncontrolled eruption of oil, gas, water or drilling fluid. In addition, such policies cover claims of environmental damage caused by wellbore explosion and similar events as well as related clean-up costs with coverage limits of up to US$198 million depending on the country.

 

Emerging Risks

Emerging risks are the long-term risks that we have identified as the most severe and could significantly impact the execution of our current and subsequent strategic plans. We detail below the main emerging risks, which are also briefly described in “Risks – Risk Factors” in this annual report, either as a separate risk factor or as part of one or more risk factors.

Technology systems, security (cybersecurity) systems, telecommunications systems and services.

Recently, concerns about information security failures have been growing in the world. These failures may have an external source, such as malware, hacking, cyber terrorism, among others. These failures can also have an internal origin, through intentional and fraudulent acts by employees and contractors with the purpose of obtaining personal advantages.

The perception of the severity of this risk by our management has increased significantly over time. In addition to cybersecurity issues, the concern and actions by our management aimed to improve protection and privacy of personal data held by us.

 
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According to Law No. 13,709/2018 – Lei Geral de Proteção de Dados Pessoais (“LGPD”), we will be subject to penalties in cases of disclosure or misuse of personal information.

We are using layers of protection over e-mails, analysis of vulnerabilities in networks and applications, audit trails in information systems, privileged access control, updating security packages, authentication of devices and users for access to the internet, corporate network, internet content filters, encryption and segregation of key functions.

Additionally, in order to guarantee our security in a world where data is considered valuable we have maintained an area dedicated to information security, linked to the Digital Transformation and Innovation Executive Officer, for the purpose of centralizing management related to all security information disciplines.

The strategic initiative for digital transformation of our Strategic Plan aims to prepare for a competitive environment that is being increasingly influenced by digital technologies and a new way of working, based on collaboration. The possibilities for transforming operational and business models bring opportunities to increase the efficiency and safety of operations, reduce costs and bring more robustness and agility to decisions. Efforts go beyond the implementation of technological solutions, also seeking to implement a culture of innovation that promotes experimentation, multifunctional collaboration and information sharing.

For more details, see “Risks – Risk Factors – Digital Transformation” in this annual report.

Carbon Risk

The Paris Agreement requires a profound reduction in GHG emissions and a transformation of the energy supply. Our scenarios point to an unequivocal energy transition and alterations are already being observed in the energy markets, through regulatory changes and some physical impacts of climate change on the infrastructure of companies and countries. The industry leaders have been expanding their commitments to lower carbon emissions, and the market’s increasing demand for transparency of the results related to the emissions of greenhouse gases and the impacts of the transition to low carbon emissions for the companies. The transition generates a series of additional expenses, both for controlling emissions and eventual adaptations to avoid or mitigate physical risks of the units, as well as for adapting to the business to regulatory and market changes.

The scenario predicts possible reduction in the demand for fossil fuels, carbon pricing generating higher costs, and segmentation of oils and fuels according to their carbon intensity. Greater requirements regarding the transparency of actions related to low carbon transition can also be expected, with the potential to generate image issues, loss of investors and greater difficulty in capital access.

While we work to safeguard a solid financial position in the medium and long term, we also work on our competitiveness to capture potential renewable opportunities from a long-term perspective. In this context, the Strategic Plan presents the strategies to “Undertake research aimed at operating, in the long term, in petrochemical and renewable energy businesses with a focus on wind and solar power in Brazil” and “Add value to the refining park, with more efficient processes and new BioRefining products, such as Biokerosene and Renewable Diesel Fuel, moving towards a low carbon market.”

In the short and medium term, our Strategic Plan also contains ten sustainability commitments, six of which are related to carbon with clear and well-defined metrics.

Since 2019, metrics related to carbon intensity in our refining and upstream operations have been integrated into executive remuneration. In 2020, these metrics were incorporated as a main indicator, influencing variable remuneration not only for executives, but for all company employees.

We have a greenhouse gas emission mitigation corporate program that aims to ensure compliance with disclosed commitments and is part of our US$1 billion investment forecast for environmental commitments between 2021 and 2025. The program involves all our operational areas and includes actions related to reduce natural gas flaring, CO2 reinjection, energy efficiency gains and control of operational losses.

 
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The commitments and actions of the GHG emissions mitigation program are monitored at different levels of governance, including senior management. In 2020, we created a climate change executive management position, reinforcing our existing carbon governance, also composed of advisory committees of the Executive Board and the Board of Directors, in addition to several management level positions that evaluate carbon aspects in its activities.

In addition, we assess the physical risk associated with climate change in our operations, through research and development of climate regionalization, with renowned institutions in Brazil and abroad (Federal University of São Paulo - USP, National Institute for Space Research - INPE and National Oceanic and Atmospheric Administration - NOAA), of parameters considered potentially more susceptible to these changes, such as water availability for our refineries and thermoelectric plants and wave, wind and current patterns for our offshore platforms, generating qualified information for the process of our operations adaptation.

The Covid-19 Pandemic

Public health epidemics and pandemics, such as the Covid-19 pandemic, can impact our workforce, our partners and our suppliers, which can affect our supply chain and the productivity of many our activities, including impact on some of our facilities, such as our platforms, refineries, terminals, among others. This may have a negative impact on our results and financial condition. A pandemic has the potential to influence our activities in many ways, which can result in operational discontinuity, increased costs, reduced revenues, compromised supply, delays in processes and projects, interruption and / or interdiction of activities. In addition, public health epidemics and pandemics may affect oil prices and demand and, consequently, our financial results. The risk of mass contagion of our own employees and contractors is being monitored by us. During the Covid-19 pandemic, we have observed:

A reduction in demand for oil products due to the restriction in the mobility of society by lockdown measures imposed by state and municipal governments.
A decrease in economic activity, recession, unemployment growth due to the closing of small and medium-sized companies, which may affect our supply chain.
The postponement of return to work due to the pandemic, increase of employees' absence from work due to the growth of mental illnesses related to social isolation and social distance.
The increase in freight prices, given the depressed oil prices, led to a shortage of ships in the market, as they were being used to store oil and byproducts.

In order to manage a situation that involves the mass contagion of our employees due to epidemics or public health pandemics, we must use mitigating actions that minimize the impact on our operations. Some of these actions are already being carried out at the time of the Covid-19 pandemic, such as the constitution of the ORS (Organizational Response Structure) for organizing actions and making decisions, adopting different work regimes for reducing exposure, defining ways operating conditions optimized for the prioritized assets and units and providing the necessary resources for operational continuity.

 
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Exploration and Production

Overview

Our oil and natural gas exploration and production activities are the major components of our investment portfolio and include offshore and onshore exploration, appraisal, development, production and incorporation of oil and natural gas reserves, producing oil and natural gas in a safe and profitable way.

Our activities are focused on deepwater and ultra-deepwater oil reservoirs in Brazil, which accounted for 94% of our total production in 2020. We also have activities in mature fields in shallow waters and onshore, as well as outside Brazil as detailed below in this annual report. Brazilian exploration and production assets represent 93% of our worldwide blocks and fields, 99% of our global oil production and 99.7% of our oil and natural gas reserves.

We have 360 assets in exploration and production including 109 consortia with other oil and gas companies. From the 360 blocks and fields, 335 are under Concession Agreements, 15 are Production Sharing Agreements and 10 are regulated by Transfer of Rights Agreements.

 
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Exploration and Production assets
(Number of assets)

Like most major oil and gas companies, we operate in partnerships using E&P consortia in the exploration of blocks and the production of oil fields in Brazil, mainly in ultra-deepwaters.

We lead and operate E&P consortia that are responsible for some major projects under development, such as Mero (Petrobras 40%, Shell 20%, Total 20%, CNODC 10% and CNOOC 10%), Berbigão, Sururu and Oeste de Atapu (all with Petrobras 42.5%, Shell 25%, Total 22.5% and Petrogal 10%).

These E&P consortia also comprise some of the biggest production fields in Brazil, such as Tupi (Petrobras 65%, Shell 25%, Petrogal 10%), Sapinhoá (Petrobras 45%, Shell 30%, Repsol Sinopec 25%), Roncador (Petrobras 75%, Equinor 25%) and Tartaruga Verde (Petrobras 50%, Petronas 50%). We also operate these fields in the Pre-salt Polygon area.

 
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Other Basins

We produce oil and gas and hold exploration acreage in 17 other basins in Brazil. The most significant potential for exploratory success within our other basins are the Equatorial Margin and East Margin.

International

Outside Brazil, we have activies in South America and North America. In West Africa we had activities until January 14, 2020. We have focused on opportunities to leverage the deepwater expertise we have developed in Brazil. However, since 2012 we have been substantially reducing our international activities through the sale of assets in accordance with our portfolio management.

South America

We conduct exploration and production activities in Argentina, Bolivia and Colombia.

In Argentina, through our subsidiary Petrobras Operaciones S.A., we have a 33.6% working interest in the Rio Neuquén production asset. Our unconventional gas and condensate production is concentrated in the Neuquén Basin. In 2020, our production of oil and gas in Argentina, including NGL, was 5.9 mboed.

In Bolivia, our gas and condensate production derives primarily from the San Alberto and San Antonio fields with 35% working interest in each of those service operation contracts, which are operated mainly to supply gas to Brazil and Bolivia. In 2020, our production of oil and gas in Bolivia, including NGL, was 28.6 mboed. The return of those contracts is a proportion of the production.

In Colombia, we operate and hold a 44.44% working interest in the Tayrona offshore exploration block, which includes the Orca gas discovery. We also operate and hold a 50% working interest in the Villarica Norte onshore exploration block.

 
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North America and West Africa

In the United States, we focus on deepwater fields in the Gulf of Mexico, where we have non-consolidated production from the 20% participation of Petrobras America Inc. (“PAI”) in the joint venture with Murphy Exploration & Production Company (“Murphy”), the MPGOM LLC. The main contributors to the production are the Chinook, Saint Malo and Dalmatian fields. In 2020, our 20% participation represents a production of 12.1 mboed, including NGL.

In West Africa, we used to explore oil and gas opportunities exclusively through our 50% equity interest in Petrobras Oil & Gas B.V. (“PO&G”). On October 31, 2018, our subsidiary Petrobras International Braspetro BV (”PIBBV”) signed a sale and purchase agreement for the sale of its 50% equity interest in PO&G with Petrovida Holding B.V. (“Petrovida”). Petrovida is owned by Africa Oil Corp. The transaction closed on January 14, 2020.

For more information on our divestments, see “Portfolio Management” in this annual report.

Main Assets

   2020   2019   2018 
Exploration and Production               
Production wells (oil and natural gas)(1)   5,646    7,021(4)   7,256 
Floating rigs   20    16    16 
Operated platforms in production(2)   67(3)   107    113 

_________________ 

(1)Includes the total amount of wells of our equity method investees (100, 164 and 163 wells in 2020, 2019 and 2018, respectively).
(2)Includes only definitive production systems, EWT and EPS units.
(3)Does not Include 37 producing platforms mothballed in 2020. Excludes 26 non-producing platforms mothballed in 2020 and platforms operated by our partners.
(4)Adjusted to include wells from affiliated companies.
 
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Exploration

The oil and gas industry value chain begins in the exploratory phase, with the acquisition of exploratory blocks either through bid rounds conducted by governments or by purchases from other companies.

In Brazil, the Brazilian State owns the oil deposits, but companies and consortia are allowed to extract and explore such oil upon payment in several forms, such as royalties. Forms of payment vary depending on the applied regulatory model. Biddings rounds are the main process for the acquisition of rights over the exploratory blocks.

There are currently three regulatory models in Brazil: Concession Agreements, Transfer of Rights Agreements and Production Sharing Agreements. The concession model fully governed the oil and natural gas exploration and production until 2010, when the Brazilian federal government enacted laws establishing the Transfer of Rights Regime and the Production Sharing Regime in the Pre-salt Polygon. Currently, our main production fields follow the Concession Agreements model. However, our production fields under the Transfer of Rights Agreement and Production Sharing Agreements will represent an important part of our production in the medium and long term.

For information on the regulatory models applicable to our exploration and production activities, see “Legal and Tax” in this annual report.

 
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Bidding rounds

Over the past few years, we have participated selectively in the bidding rounds carried out by the ANP, aiming to reorganize our exploratory portfolio and maintain the relationship between our reserves and our production in order to ensure the sustainability of our future oil and gas production. Our joint operation with large oil companies in consortia is also aligned with our strategic goal to strengthen partnerships, with the intent to share risks, combine technical and technological skills and capture synergies to leverage results.

In 2018, we acquired 11 new offshore exploratory blocks, with a total area of 8,800 km2. In the Pre-salt Polygon, we acquired four areas under the production sharing regime, in partnerships with Chevron, Shell, Equinor, ExxonMobil, BP and Galp. In the Campos Basin, we acquired four blocks outside of the Pre-salt Polygon, under the concession regime, in partnerships with ExxonMobil, Qatar Petroleum and Equinor. We also acquired three blocks in the Potiguar Basin, two of them in partnership with Shell.

In 2019, we acquired two new offshore exploratory blocks, with a total area of 5,800 km2. In the Pre-salt Polygon, we acquired one area under the production sharing regime, in partnership with CNODC. In the Campos Basin, we acquired one block outside of the Pre-salt Polygon, under the concession regime, in partnership with BP. Additionally, we acquired 90% of the exploration and production rights of the surplus volume of the Búzios field during the Transfer of Rights Surplus Production Sharing Bidding Round, in a partnership with CNODC Brasil Petróleo e Gás Ltda. (5%) and CNOOC Petroleum Brasil Ltda. (5%). During the same bidding round, we also acquired 100% of the exploration and production rights of the surplus volume of the Itapu field.

In 2020, due to limitations resulting from the Covid-19 pandemic, the 17th Bidding Round was postponed. The 2nd Cycle of Open Acreage was the only bidding round of the year and took place on December 4, 2020. We did not present any offers during this bidding round.

 
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Exploration Activities

As of December 31, 2020, we had 86 exploratory blocks (27 with 100% working interest) that had three discoveries under evaluation. We also had three discoveries being assessed in production areas. We serve as the operator in 59 of these exploration partnership blocks.

The table below breaks down our participation in exploration activities in 2020:

Our participation in exploration activities in 2020

  

Net exploratory area

(km2)

  

Exploratory blocks

(number)

  

Evaluation plans

(number)

  

Wells drilled

(number)

 
   2020   2019   2018   2020   2019   2018   2020   2019   2018   2020   2019   2018 
Brazil   42,996    40,625    51,600    82    113    133    32    24    26    9    8    8 
Other S. America   5,751    6,081    6,081    4    4    4    2    1    1    0    1    0 
North America   0    0    0    0    0    0    0    0    0    0    0    0 
Africa   0    0    0    0    0    0    0    2    2    0    0    0 
TOTAL   48,747    46,706    57,681    86    117    137    34    27    29    9    9    8 

These investments mainly cover the costs of drilling, seismic surveys and acquisition of blocks, which contributed to the following endeavors.

In 2020, we concentrated our exploratory efforts on delimiting pre-salt reservoirs, the main oil-producing areas in Brazil. In addition to confirming the presence of oil of excellent quality in the southeastern area of the Búzios field, in the Santos Basin, a well test proved greater potential in the pre-salt area of the Albacora field, in the Campos Basin. While the former is considered a promising area for a new Floating Production Storage and Offloading (“FPSO”), the latter still has remaining untapped potential and can continue to contribute to our production.

Another well in the pre-salt area of the Uirapuru block, in the Santos Basin, also resulted in discoveries of oil and gas. There is at least one extension well planned for this prospect in the next five years. Moreover, a prospect situated in block C-M-657, in the Campos Basin, but outside of the main pre-salt cluster, was drilled this year and the results identified the presence of hydrocarbons. Additional studies are being conducted to provide better measurements and to guarantee each project’s economic viability and future resources incorporation.

We also obtained encouraging results outside the pre-salt reservoirs. In the southwestern portion of the ring fence of Tartaruga Verde, also located in the Campos Basin, an exploratory well discovered oil in carbonate reservoirs from the Albian age. We are currently evaluating the commerciality of the discovery and the possible incorporation of resources into existing infrastructure.

Finally, the turbiditic reservoirs in the Sergipe Alagoas Basin also showed promising results. After the incorporation of the results of two wells in our geological models, there was an increase in the expected volume of both Poço Verde and Moita Bonita´s appraisal blocks. These results contributed to an increase in the future resources incorporation. We also conducted a long-term test in the Farfan reservoir, which resulted not only in reduced uncertainties regarding reservoir properties, but also in an increase of the expected volumes. Thus, this test confirmed the good productivity projections for this region of the deepwater complex.

 
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In order to achieve greater return on invested capital, while always prioritizing safety, the speed at which our new projects are implemented is key. Thus, we have a strategic program (PROD1000) with the objective of reducing the implementation time of our projects, with the ambition to reach 1,000 days between field discovery and the beginning of production, compared to our current average of 3,540 days, considering large projects that use FPSO systems. Our efforts in such program are related to the integration of exploration and production development and technical data teams, the optimization of reservoir processes, the standardization of FPSO, subsea and well design, the early supplier engagement, the reduction of the construction time, and the optimization of processes using digital technologies and agile methods. As an example of our standardization efforts in the FPSO design, we applied for a patent for a Polyvalent Riser Balcony, which can be applied to different project scenarios and reduce engineering time and late changes during the FPSO construction phase.

In addition, we implemented a strategic program (EXP100) that has the ambition to increase the chance of discovering oil to 100% in exploratory wells, reducing project risks and costs by expediting production development. This program aims to better evaluate the prediction of geological properties through the use of an integrated upstream data platform and high-performance computing capacity, that enables the application of more complex algorithms in the processing of large volumes of data. Several initiatives are already underway, with notable advances in the integration of the exploratory database and in the automated interpretation of seismic and well data.

Production

Production Development

After a field is declared commercially viable, the process of production development begins. The investments made in this phase are mainly focused on designing and contracting production systems, which includes platforms, subsea systems, drilling, and the completion of wells.

Over the last ten years, we pursued substantial cost optimizations related to project development. Time to drill and complete wells in the Santos Basin pre-salt area decreased by 64% in 2020 when compared to 2010. In 2020, we spent an average of 117 days in the drilling and completion of a pre-salt well on the Santos Basin. This helped to significantly reduce our capital expenditures per well. Through the Well Efficiency Program (PEP70), launched in 2019, we strive to further reduce well construction costs by 30% by shortening construction time, optimizing well configurations, streamlining operations and adopting new technologies. In the post-salt, we highlight the adoption of the True One Trip - Three Phases (TOT-3P) technology, which allowed us to build a well in half the estimated time and cost and resulted in savings of US$30 million.

We have also pursued substantial cost optimizations in wells interconnections in the Santos Basin pre-salt area, with an average cost reduction of around 6-7% per year during the past four years. Regarding the integrity of subsea systems, we have made progress in the development and application of new tools for inspection, leading to greater reliability and availability of equipment, pipelines and other components, especially those subsea components exposed to SCC-CO2 events.

In 2020, we also completed the Reference Basic Design for the new generation of FPSOs for pre-salts. The design, which focuses on maximizing the economic value of production development projects, features solutions aimed at reducing implementation times, increasing system standardization, enhancing operational efficiencies and integrating new technologies and innovations to meet our low carbon commitments. This project incorporates improvements based on more than a decade of experience with the design, construction, start-up and operation of production platforms in the pre-salt layer.

In the last three years, we have installed several major systems, mainly in the pre-salt area of the Santos Basin, which helped to mitigate the Santos Basin’s natural decline. In 2019, we started four new production systems: (i) the P-76 and P-77 platforms, located in the Búzios field; (ii) the P-67 platform, located in the Tupi field; and (iii) the P-68, located in the Berbigão and Sururu fields. In 2020, we started the P-70 platform, located in the Atapu field. Those five new systems connected 32 new wells (19 production wells and 13 injection wells) into our production systems. We expect to install 13 new FPSOs in the next five years.

 
53 

In January 2020, the P-77 platform in the Búzios field reached its full capacity in only 10.4 months. In the Búzios field, we also achieved monthly production records of 615 kbpd of oil and 765 kboed in July, and the highest monthly production achieved by a well in Brazil, with a record of 69.6 kboed from the BUZ-10 well, registered in September. The performance of the Búzios platforms was aided by the temporary expansion of the oil and gas processing capacity of the units, using spare capacity in power generation and gas compression available until the beginning of gas exports, and by the high production potential of the wells and the reservoir.

In 2020, our producing platforms had a daily production of 2.06 million barrels of oil and 2,393 million cubic feet of natural gas (discounting the liquefied volume). As part of our response to the 2020 oil crisis, we indefinitely mothballed, and have no current plan to reenable, our 63 shallow water platforms (37 active and 26 inactive immediately prior to the mothballing). Additionally, during 2020, and due to divestment or demobilization efforts, we also discontinued eight active platforms that contributed to our annual production. These mothballed and discontinued platforms produced approximately 29 mbbl/d in 2020. As of December 31, 2020, we own 43 and lease 16 offshore producing platforms. Besides these offshore platforms, there are three platforms on fields operated by our partners, totalling 62 active platforms.

Pre-salt and the fields under the Transfer of Rights Agreements will be particularly important to support our production growth.

In 2021, the FPSO Carioca will be installed in the Sépia field. This platform has the capacity to process 180 kbpd and 211.9 mmcf/d of natural gas per day and arrived in Rio de Janeiro in February 2021 to finalize the integration and commissioning activities. In 2021, we also expect to install the FPSO Guanabara, the first definitive system in the Mero field. This FPSO has the capacity to process 180 kbpd and 423.8 mmcf/d of natural gas per day and is under construction in China.

After negotiations with our partners in the BM-S-11 Consortium, Shell Brasil Petróleo Ltda (owning a 25% stake in the partnership) and Petrogal Brasil S.A. (owning a 10% stake in the partnership), we signed a commitment to purchase platform P-71. The unit, which is in the final phase of construction, has a production capacity of 150 kbpd and will be allocated to the Itapu field, which will allow us to begin oil production one year earlier.

With the commitment to sell P-71, subject to the above-mentioned conditions, the partners of the BM-S-11 Consortium in Brazil agreed to prepare a new development plan for the Tupi field, to be delivered to the ANP in 2021. The acquisition of P-71 and the actions to elaborate a new DP for the Tupi field are in line with our strategy of concentrating our activities on world-class assets in deep and ultra-deepwaters.

 
54 

Systems Installed since 2010

                   
Start up (year) Basin Field/Area Production unit Crude oil nominal capacity (bbl/d) Gas nominal capacity (mmcf/d) Water depth (meters) Fiscal regime Main production source Type
2020 Santos Atapu Petrobras 70 150,000 211.9 2,300 Transfer of Rights/Concession Pre-Salt FPSO
2019 Santos Berbigão Petrobras 68 150,000 211.9 2,280 Transfer of Rights/Concession Pre-Salt FPSO
Santos Búzios 4 Petrobras 77 150,000 211.9 1,980 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Santos

Búzios 3

Petrobras 76

150,000

211.9

2,030

Transfer of Rights/Production Sharing/Concession
Pre-Salt

FPSO
Santos Tupi Norte Petrobras 67 150,000 211.9 2,130 Concession Pre-Salt FPSO
2018 Campos Tartaruga Verde Cid. de Campos dos Goytacazes 150,000 117 765 Concession Post-Salt FPSO
Santos Tupi Ext. Sul Petrobras 69 150,000 211.9 2,170 Transfer of Rights/Concession Pre-Salt FPSO
Santos Búzios 1 Petrobras 74 150,000 211.9 2,005 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Santos Búzios 2 Petrobras 75 150,000 211.9 2,010 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
2017 Santos
Santos
Tupi Sul
Mero
Petrobras 66
Pioneiro de Libra
150,000
50,000
211.9
141.3
2,100
2,040
Concession
Production Sharing
Pre-Salt
Pre-Salt
FPSO
FPSO
2016 Santos
Santos
Tupi Central
Tupi Alto
Cidade de Saquarema
Cidade de Maricá
150,000
150,000
211.9
211.9
2,100
2,100
Concession
Concession
Pre-Salt
Pre-Salt
FPSO
FPSO
2015 Santos Tupi Cidade de Itaguaí 150,000 282.5 2,200 Concession Pre-Salt FPSO
2014 Santos
Santos
Campos
Campos
Sapinhoá
Tupi
Roncador
Jubarte
Cidade de Ilhabela
Cidade de Mangaratiba
Petrobras 62
Petrobras 58
150,000
150,000
180,000
180,000
211.9
282.5
211.9
211.9
2,140
2,220
1,600
1,400
Concession
Concession
Concession
Concession
Pre-Salt
Pre-Salt
Post-Salt
Pre-Salt
FPSO
FPSO
FPSO
FPSO
2013 Campos
Campos
Santos
Santos
Roncador
Papa-Terra
Tupi
Sapinhoá
Petrobras 55
Petrobras 63
Cidade de Paraty
Cidade de São Paulo
180,000
145,000
120,000

150,000
141.3
35.3
176.6

176.6
1,795
1,200
2,140

2,140
Concession
Concession
Concession

Concession
Post-Salt
Post-Salt
Pre-Salt

Pre-Salt
SS
FPSO
FPSO

FPSO
2012 Campos Jubarte Cidade de Anchieta 100,000 123.6 1,220 Concession Pre-Salt FPSO
2011 Campos
Santos
Marlim Sul
Mexilhão
Petrobras 56
Mexilhão
140,000
20,000
211.9
529.7
1,700
170
Concession
Concession
Post-Salt
Post-Salt
SS
Fixed
2010 Campos
Santos
Santos
Campos
Jubarte
Tupi
Uruguá /Tambaú
Jubarte
Petrobras 57
Cidade de Angra dos Reis
Cidade de Santos
Capixaba
180,000
100,000
25,000
110,000
70.6
176.6
353.1
113.0
1,260
2,150
1,300
1,300
Concession
Concession
Concession
Concession
Post-Salt
Pre-Salt
Post-Salt
Post-Salt
FPSO
FPSO
FPSO
FPSO
 
55 

Main Systems to be Installed through 2025

Start up (year) Basin Field/Area Production unit Crude oil  nominal  capacity  (bbl/d) Gas nominal capacity (mmcf/d) Water  depth  (meters) Fiscal regime Main  production  source Type
Expected 2021 Santos Sépia Carioca 180,000 211.9 2,200 Transfer of Rights Pre-Salt FPSO
Santos Mero 1 Guanabara 180,000 423.8 1,930 Production Sharing Pre-Salt FPSO
Expected 2022 Santos Búzios 5 Alm. Barroso 150,000 211.9 2,100 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Expected 2023 Campos Marlim 1 Anita Garibaldi 80,000 247.3     670 Concession Post-Salt FPSO
Campos Marlim 2 Anna Nery 70,000 141.3    927 Concession Post-Salt FPSO
Santos Mero 2 Sepetiba 180,000 423.8 2,000 Production Sharing Pre-Salt FPSO
Santos Itapu Petrobras 71 150,000 211.9 2,010 Transfer of Rights/ Production Sharing Pre-Salt FPSO
Expected 2024 Campos Parque das Baleias N/D 100,000 176.6 1,385 Concession Pre-Salt FPSO
Santos Búzios 6(1) Almirante Tamandaré 225,000 423.8 1,900 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Santos Mero 3 Marechal Duque de Caxias 180,000 423.8 2,070 Production Sharing Pre-Salt FPSO
Expected 2025 Santos Búzios 7(2) Petrobras 78 180,000 254.3 2,030 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Santos Búzios 8 Petrobras 79 180,000 254.3 1,700 Transfer of Rights/Production Sharing/Concession Pre-Salt FPSO
Santos Mero 4 N/D 180,000 423.8 1,890 Production Sharing Pre-Salt FPSO

_________________ 

(1) Regarding the production system to be installed in the Module 7 area of the Búzios field.
(2) Regarding the production system to be installed in the Module 6 area of the Búzios field.
 
56 

Decommissioning

When the output extension opportunities of an oil and gas production system are exhausted, it is necessary to carry out its decommissioning. Before that, however, we prioritize solutions for the continuity and maximization of production, including processes for assigning our rights (through divestments) of fields that no longer fit into our strategic portfolio or that have reached their economic limit.

In 2020, we made advancements in the approval of decommissioning plans and in the execution of activities relating to decommissioning.

We obtained the approvals of Brazilian regulatory bodies overseeing decommissioning plans as to: the P-07 platform, in the Bicudo field; the P-12 platform, in the Linguado field; the P-15 platform, in the Piraúna field; and the P-32 platform, in the Marlim field, all in the Campos Basin. During 2020, we sold three of those platforms (P-07, P-15 and P-12) through a public auction, one (P-12) of which was already removed from the location.

Additionally, some decommissioning processes approved before 2020 have also advanced. We started the decommissioning of the FPSO Piranema Spirit, and contracted Engineering, Preparation, Removal and Final Disposal (EPRD) services to assist with the decommissioning of the PCA-1, PCA-2 and PCA-3 platforms.

Critical Resources in Exploration and Production

We seek to procure, develop and retain all of the critical resources that are necessary to meet our production targets. Drilling rigs and special vessels are important resources for our exploration and production operations and are centrally coordinated to assure both technical specifications and proper lead time.

Since 2008, we have grown from three rigs capable of drilling in waters with depth greater than 2,000 meters (6,560 feet) to 19 rigs with this capacity as of December 31, 2020.

We have sufficient rigs to meet our production targets, and we will continue to evaluate our drilling and special vessels demands and will adjust our fleet size as needed.

 
57 

Drilling units in use by exploration and production as of December 31(1)

   2020   2019   2018 
   Leased   Owned   Leased   Owned   Leased   Owned 
Brazil   20    0    18    0    17    4 
Onshore   0    0    2    0    1    3 
Offshore, by water depth (WD)   20    0    16    0    16    1 
Jack-up rigs   0    0    0    0    0    0 
Floating rigs   20    0    16    0    16    1 
500 to 999 meters WD   0    0    0    0    1    0 
1000 to 1999 meters WD   1    0    1    0    2    0 
2000 to 3200 meters WD   19    0    15    0    13    1 
Outside Brazil   0    0    1    0    1    0 
Onshore   0    0    1    0    1    0 
Offshore   0    0    0    0    0    0 
Worldwide   20    0    19    0    18    4 

(1) In operated fields.

To achieve our production goals, we have also secured a number of specialized vessels (such as Pipe Laying Support Vessels or “PLSVs”) to connect wells to production systems. As of December 31, 2020, we had 13 PLSVs and our specialized vessels were sufficient to meet our needs.

In the subsea area, we have also been developing the HISEPTM Technology, which is a subsea separation and boosting system that will remove a significant portion of the produced gas rich in CO2 from the seabed, debottlenecking the topside gas processing plants. The new technology will enable the extension of the oil production plateau, accelerating the production and boosting the economics of development projects in areas with high GOR and high CO2 content. Once qualified, HISEPTM will have the potential to unlock the development of new FPSO generations suitable for areas with high GOR and high CO2 content, since they will benefit from the synergy between topside and subsea processing systems capacities. This represents an opportunity to maximize oil production with controlled handled gas inventory in the surface facility, reducing CAPEX, OPEX, lead time as well as emissions, improving safety. The HISEPTM will be qualified in 2025 in the Mero Field via construction, installation and tests execution in a subsea real scale prototype that will be supported by Libra Consortium’s R,D&I levy.

 
58 

Búzios field

The Búzios field started production in April 2018 and has already produced around 100 million boe. The Búzios field is the largest discovered deepwater field in the world. It has light oil and high productivity wells.

The Búzios field is an asset with significant reserves and low lifting costs. It is economically resilient to a low oil price scenario.

In 2019, we acquired 90% of the exploration and production rights of the surplus volume of the Búzios field from the Transfer of Rights Agreement, in a partnership with CNODC Brasil Petróleo e Gás Ltda. (5%) and CNOOC Petroleum Brasil Ltda. (5%). This acquisition is consistent with the strategy of focusing our investments on world-class assets.

In March 2020, we signed the Production Sharing Contract for the Suplus of the Transfer of Rights of the Búzios Area (ToR), with CNOOC and CNODC as private partners and Pré-Sal Petróleo S.A (PPSA) as its manager. The parties have been discussing the global development strategy and other matters related to the co-participation agreement, that will regulate the coexistence of the Transfer of Rights Contract and Production Sharing Contract for the Surplus of the ToR. Pursuant to Ordinance MME 265/2019, the co-participation agreement should be signed by September 2021. Each of the private partners will have the right to increase their participating interest by 5%, if certain conditions have been met.

There are currently four units in operation in Búzios. A fifth platform, the FPSO Almirante Barroso, is under construction and expected to start production in 2022. FPSO Almirante Barroso will be the first chartered unit in the Búzios Field, capable of processing 150,000 barrels of crude oil per day.

In July 2020, we received approval for three additional operational units in Búzios. FPSO Almirante Tamandaré, a chartered unit that will become the field’s sixth production system, is expected to start production in 2024. In addition, P-78 and P-79, two platforms owned by us, are expected to start production in 2025.

In 2020, with less than two years of operation, the Búzios field surpassed the 600 kbpd production mark, due to good operating results and a technical study that allowed its units to operate above the nominal capacity. In addition, three important field records were also achieved in 2020: daily field production of 674 kbbl, monthly field production of 615 kbpd in July and daily production of a single well of 65 kbbl (9-BUZ-4-RJS). Moreover, another important milestone achieved this year was the start of gas exports from the P-74 platform.

We expect better operating results for 2021 due to internal actions that have been taken to improve the production efficiency and the maintenance of the production level above the nominal capacity until the end of 2021. Finally, in 2021 we also expect to start exporting gas from other three FPSOs that are in operation.

In 2020, investments in the Búzios field totaled US$1.7 billion. According to the Strategic Plan, US$20.2 billion will be invested over the next five years. The average daily production from 2021 to 2025 is expected to be 639 kbbl, with Operational Expenditures around US$5.6 billion, including leasing of vessels.

Production

Despite the unprecedented crisis in the oil and gas sector, our operating performance has improved significantly, reaching daily, quarterly and annual oil and gas production records. In 2020, our total production of oil and gas, including NGL, was 2,836 mboed, of which 2,788 mboed were produced in Brazil and 48 mboed were produced abroad, a 2.4% increase compared to 2019. This production growth was due to higher production in the Búzios and Tupi fields.

Our 2020 operating performance was leveraged by the ramp-up of new production systems in the Búzios and Tupi fields, offsetting the negative effects derivedduring the Covid-19 pandemic. The oil production represented 81% of the average of 2,788 mboed oil and gas produced in Brazil.

 
59 

Our production in the pre-salt layer reached 1,546 mbbl/d in 2020, representing an increase of 21.1% in relation to our production in 2019. In 2020, the oil production in the pre-salt layer represented 68% of all oil production in Brazil, compared to 59% in 2019.

Oil and gas production

   2020   2019   2018   2020 vs 2019 
Crude oil and natural gas — Brazil   2,788    2,688    2,527    3.7%
Crude oil (mbbl/d)(1)   2,266    2,172    2,035    4.3%
Onshore   105    124    135    -15.3%
Shallow Water   32    66    90    -51.5%
Post-salt deep and ultra-deepwaters   582    704    816    -17.3%
Pre-salt   1,546    1,277    994    21.1%
Natural gas (mboed)   522    516    492    1.2%
Crude oil and natural gas – Abroad (2)   48    82    101    -41.5%
TOTAL   2,836    2,770    2,628    2.4%

(1) Including NGL.

(2) Includes the proportional production of our equity method investees, based on our percentage interest in these entities.

Pre-salt oil production increased 21.1%, reflecting higher production in the Búzios and Tupi fields. The pre-salt area is comprised of large accumulations of light oil, of excellent quality and with high commercial value. The post-salt oil production, in deep and ultra-deepwaters, decreased by 17.3%. This was due to natural decline in reservoirs, especially from the Campos Basin.

Shallow waters oil production decreased by 51.5%, to 32 mbbl/d, due to hibernation of all shallow water platforms. Onshore oil production decreased by 15.3%, to 105 mbbl/d, due to the natural decline in reservoirs.

We produced 88.40 million m3/d of gas in 2020. From that volume, we used 48.50 million m3/d in our production processes (reinjected, flared, consumed, liquefied) and destined 39.90 million m3/d for sale.

In 2020, our lifting cost, without government participation or leases, was US$5.2 per boe, which represents a 33% decrease from the 2019 cost of US$7.8 per boe. Including leases, our lifting cost in 2020 was US$6.8 per boe, which represents a 29% decrease from the 2019 cost of US$9.6 per boe.

 
60 

Main production fields

         Production units                  
Basin  Field  Main source  Owned  Capacity
 (mbbl/d)
   Leased  Capacity
 (mbbl/d)
   Consortium  API gravity  Sulphur
 content
 (% wt)
   2020 oil
production
 (mbbl/d)
 
Santos  Tupi  Pre-salt  4   4 units with 150   6   1 unit with 100
1 unit with 120
4 units with 150
   Petrobras (65%),
Shell (25%),
Petrogal (10%)
  28 – 32   0.29 –0.38    619.8 
Santos  Búzios  Pre-salt  4   4 units with 150      —     Petrobras (100%)(1)  28- 29   0.31- 0.32    516.8 
Santos  Sapinhoá  Pre-salt     —     2   2 units with 150   Petrobras (45%),
 Shell (30%),
 Repsol Sinopec (25%)
  29.8   0.4    92.6 
Campos  Jubarte  Pre-salt  2   2 units with 180   2   1 unit with 100
1 unit with 110
   Petrobras (100%)  17 – 30   0.29 –0.56    185.5 
Campos  Roncador  Post-salt  4   3 units with 180
1 unit with 190
      —     Petrobras (75%),
 Equinor (25%)
  17 – 28   0.53 – 0.74    112.0 
Campos  Marlim Sul  Post-salt  3   1 unit with 140
1 unit with 180
1 unit with 200
           Petrobras (100%)  17 – 25   0.59 – 0.73    109.9 
Campos  Tartaruga Verde  Post-salt     —     1   1 unit with 150  

Petrobras (50%)

Petronas (50%)1

  27.5   0.76    45.5 
Campos  Marlim  Post-salt  7   1 unit with 50
1 unit with 75
4 units with 100
1 unit with 180
      —     Petrobras (100%)  19 – 23   0.68 – 0.77    61.3 
Campos  Marlim Leste  Post-salt  1   1 unit with 180   1   1 unit with 100   Petrobras (100%)  23 – 29   0.50 – 0.51    41.4 
Other pre and post-salt fields                                    344.2 
Onshore                                    104.9 
Shallow waters                                    31.9 
TOTAL                                    2.265.8 

_________________ 

(1)Including operations in 2020.
 
61 

Tupi Field

In July 2020, we reached the accumulated production of two billion barrels of oil equivalent (boe) in the Tupi field, located in the pre-salt of the Santos Basin, approximately 230 km from the coast of the state of Rio de Janeiro. This milestone took place in the same month in which we celebrated the 20th anniversary of the signing of the concession agreement for block BM-S-11, where the field is located currently producing approximately one million barrels per day (bpd).

This accumulated production occured just 10 years after the start of the first permanent production system, the FPSO Cidade Angra dos Reis, and 14 years after it was discovered, in 2006. From 2010 to 2019, the consortium, formed by us, with a 65% stake in the partnership with Shell Brasil Petróleo Ltda (25% stake in the partnership) and Petrogal Brasil S.A. (10% stake in the partnership), put into operation nine production systems, an average of one system per year.

In the process of implementing these production systems, we had to overcome a series of unprecedented challenges in the industry, such as the distance from the coast and the existence of very few similar reservoirs in the world, ultra-deep reservoirs under a thick layer of salt. In partnership with research institutions, partner companies and suppliers, we developed a series of technologies and innovations that allowed safe and profitable productions in pre-salt fields, which continues to be a reference in terms of its environmental performance. As a result of the unprecedented technologies we developed, in 2015 we received the Distinguished Achievement Award for Companies, Organizations and Institutions, which is the main award in the industry and is promoted by the Offshore Technology Conference (OTC).

The Future of Tupi

Together with our partners in the BM-S-11 block, we have developed several initiatives aimed at revitalizing the field even before the start of its decline, seeking to increase the oil and gas recovery factor that can be extracted from the field and, thus, maximize the value of the asset. Working towards this goal, we are developing projects to maintain the reservoir's pressure, such as interconnecting new wells into already implemented production systems and alternating water and gas injection technology (Water Alternating Gas - WAG). In addition to these projects, together with our partners we are also analyzing actions that will be taken according to the terms of the concession and seeking to develop other low-cost and highly reliable technologies that may increase the recovery factor.

 
62 

We also carry out limited oil shale mining operations in São Mateus do Sul, in the Paraná Basin of Brazil, and convert the kerogen (solid organic matter) from these deposits into synthetic oil and gas. This operation is conducted in an integrated facility and its final products are fuel gas, liquefied petroleum gas (“LPG”), shale naphtha and shale fuel oil. Our business units in Brazil do not utilize the fracking method or the hydraulic fracturing method for oil production, since they are not appropriate in the context of our operations. Also, we do not inject any water or chemicals in the soil in connection with our open pit oil shale mining operations. Our process consists of crushing, screening and subsequently heating all the shale at high temperatures (pyrolysis) and we have in place a proper segregation process for the by-products derived from such process.

For more information on our production of crude oil, natural gas, synthetic oil and synthetic gas by geographic area in 2020, 2019 and 2018, see Exhibit 15.3 to this annual report.

Customers and Competitors

Crude oil is primarily sold through long-term contracts and also in the spot market. Our overseas portfolio includes approximately 60 clients, such as refiners that process or have processed Brazilian oils regularly, distributed throughout China, Americas, Europe, and other countries in Asia.

Oil clients (% vol)

Fuel oil is one of the most representative types of oil products in terms of volume in exports. In 2020, we exported high sulfur oil and, to a greater degree, low sulfur fuel oil to several destinations. Our fuel oil is available in the major hubs in the market such as Singapore, the Mediterranean, the US Gulf Coast, the west coast of Africa, Panama and the Caribbean. Our counterparties list consists of major companies, trading companies and barging companies. We have sold fuel oil to more than 40 different companies this year.

In the exploration and production industry, we deal with several competitors when we participate in bidding rounds conducted by the ANP.

 
63 

Reserves

Preparation of reserves estimates

We apply SEC rules (Rule 4-10(a) of Regulation S-X) for estimating and disclosing oil and natural gas reserve quantities included in this annual report. In accordance with those rules, we estimate reserves by considering average prices calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, except for the reserves of the Amazon fields for which volumes are estimated using gas prices as set forth in our contractual arrangements for gas sales. In 2020, we did not book proved reserves relating to non-traditional reserves such as synthetic oil and gas.

We estimate reserves based on forecasts of field production, which depends on an array of technical information, such as seismic surveys, well logs and tests, rock and fluid samples, and geoscience, engineering and economic data. All reserve estimates involve some degree of uncertainty. The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of that data. Our estimates are thus made using the most reliable data and technology at the time of the estimate, in accordance with the best practices in the oil and gas industry and SEC rules and regulations.

Thus, the reserve estimation process begins with an initial evaluation of our assets by geophysicists, geologists and engineers. Reserves coordinators in each business unit in Brazil and the corporate reserves team provide guidance for reserves estimates in compliance with SEC requirements to the asset teams. General managers in our business units in Brazil and executive officers of companies outside Brazil where we have interests are responsible for regional reserves estimates in compliance with SEC requirements. The corporate reserves team is responsible for consolidating our reserves estimates, standardized measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves. Our reserves estimates are approved by our Board of Executive Officers, which then informs our Board of Directors about the approval. The technical person primarily responsible for overseeing the preparation of our reserves is the manager of the corporate reserves team, who has a degree in engineering and 18 years of experience in the oil and gas industry.

DeGolyer and MacNaughton (“D&M”) conducted a reserves evaluation of 97% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2020 in Brazil. The amount of reserves reviewed by D&M corresponds to 97% of our total proved reserves company-wide on a net equivalent barrel basis. For disclosure describing the qualification of D&M’s technical person primarily responsible for overseeing our reserves evaluation, see Exhibit 99.1 to this annual report.

For a description of the risks relating to our reserves and our reserve estimates, see “Risks” in this annual report.

We discover new areas through exploratory activity. Such areas constitute our fields after the declaration of commerciality. We then prepare a development plan for each field. As projects achieve adequate maturity, proved reserves may be reported.

Our fields’ proved reserves can be later increased with additional drilling, operational optimizations and improved recovery methods, such as water injection, among other activities.

Our net proved oil, condensate and natural gas reserves as of December 31, 2020 were estimated at 8,816 million boe. This estimate includes our interest in our equity method investees, which represents 0.2% of our net reserves.

 
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Proved reserves(1) (million boe)

_________________ 

(1)Apparent differences in the sum of the numbers are due to rounding off.

Oil and gas reserves volumes change yearly. Quantities included in our previous year’s reserves that are produced during the year are no longer reserves at year-end. Other factors, such as reservoir performance, revisions in oil prices, discoveries, extensions, purchases and sales of assets that occurred during the year, also influence year-end reserves quantities.

 
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Proved reserves(1) (million boe)

_________________ 

(1)Apparent differences in the sum of the numbers are due to rounding off.
(2)The 922.5 million boe production volume is the net volume withdrawn from our proved reserves. It therefore excludes NGL, as we estimate our oil and gas reserves at a reference point located prior to the gas processing plants, except for the United States of America and Argentina. The production does not consider injected gas volumes, production of EWTs in exploratory blocks and production in Bolivia, since Bolivian reserves are not included in our reserves due to restrictions determined by Bolivian Constitution.

In 2020, we incorporated 223.7 million boe of proved reserves by revising previous estimates, including:

addition of 637.1 million boe arising from technical revisions, mainly due to good performance and increased production experience in reservoirs in the pre-salt layer of Santos Basin;
addition of 253.9 million boe due to approvals of new projects, mainly in the Santos and Campos Basins; and
reduction of 667.2 million boe related to economic revisions, mainly due to the decrease in oil prices.

In addition, we added 40.8 million boe to our proved reserves due to extensions and discoveries in the pre-salt of Santos Basin, and reduced 116.8 million boe due to sales of proved reserves.

 
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Proved Undeveloped Reserves

As of December 31, 2020, our proved undeveloped reserves were estimated at 2,983.1 million boe, a net decrease of 16% when compared to 2019 year-end. This decrease is a result of the following changes:

we converted a total of 423.9 million boe of proved undeveloped reserves to proved developed reserves, mainly as a result of the P-70 platform start-up in the Santos Basin and offshore and onshore drilling and tieback operations;
our proved undeveloped reserves decreased by 149.2 million boe as a result of revisions to previous estimates, including a 456.3 million boe reduction due to economic revisions, partially offset by additions from new project approvals, mainly in the Santos and Campos Basins (247.2 million boe), and technical revisions, mainly due to good performance and increased production experience in the pre-salt layer of the Santos Basin (60.0 million boe);
we added 12.8 million boe to our proved undeveloped reserves due to extensions and discoveries in the pre-salt of the Santos Basin; and
we reduced 9.6 million boe from our proved undeveloped reserves as a result of sales of proved reserves.
 
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Changes in proved undeveloped reserves(1) (million boe)

_________________ 

(1)Apparent differences in the sum of the numbers are due to rounding off.

As of December 31, 2020, 55% (1,647 million boe) of our proved undeveloped reserves have remained undeveloped for five years or more, mainly due to the inherent complexity of ultra-deepwater development projects in giant fields, particularly in the Santos and Campos Basins, in which we are investing in the required infrastructure.

In 2020, we invested a total of US$5.7 billion in development projects, of which 99% was invested in Brazil.

Most of our investments relate to long-term development projects, which are developed in phases due to the large volumes and extensions involved, the deep and ultra-deepwater infrastructure and the production resources complexity. In these cases, the full development of the reserves related to these investments may exceed five years.

For further information on our reserves, see the unaudited section “Supplementary Information on Oil and Gas Exploration and Production” in our audited consolidated financial statements.

Oil and Gas Additional Information

The following tables show (i) the number of gross and net productive oil and natural gas wells and (ii) total gross and net developed and undeveloped oil and natural gas acreage in which we had working interests as of December 31, 2020. A gross well or acre is a well or acre where we own a working interest, while the number of net wells or acres is the sum of fractional working interests in gross wells or acres. We do not have any material acreage expiring before 2025.

 
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Gross and net productive wells

   As of December 31, 2020 
   Oil   Natural Gas   Synthetic Oil   Synthetic gas 
   Gross   Net   Gross   Net   Gross   Net   Gross   Net 
Consolidated subsidiaries                                        
Brazil   5,187    5,155    316    310    0    0    0    0 
International                                        
South America (outside of Brazil)   46    20    191    94    0    0    0    0 
Total international   46    20    191    94    0    0    0    0 
Total consolidated   5,233    5,176    507    404    0    0    0    0 
Equity method investees                                        
South America (outside of Brazil)   0    0    0    0    0    0    0    0 
North America   38    3    1    0.1    0    0    0    0 
Africa   0    0    0    0    0    0    0    0 
TOTAL GROSS AND NET PRODUCTIVE WELLS   5,271    5,179    508    404    0    0    0    0 

 

Gross and net developed and undeveloped acreage (in acres)

   As of December 31, 2020 
   Developed acreage   Undeveloped acreage 
   Gross   Net   Gross   Net 
Consolidated                    
Brazil   4,374,882.4    3,847,297.5    468,233.6    415,649.9 
South America (outside of Brazil)   2,304.0    774.1    2,310.0    776.2 
Total consolidated   4,377,186.4    3,848,071.6    470,543.6    416,426.1 
Equity method investees                    
Africa   0    0    0    0 
North America   22,897.0    1,985.2    146,177.0    10,832.1 
Total equity method investees   22,897.0    1,985.2    146,177.0    10,832.1 
TOTAL GROSS AND NET ACREAGE   4,400,083.4    3,850,056.8    616,720.6    427,258.2 

For “net” figures, we used our working interest held on December 31, 2020. The division in oil and gas in the acreage table was not included because, usually, oil and gas are produced from the same acreage. Gross and net developed and undeveloped acreage presented in this table does not include exploratory areas.

The following table sets forth the number of net productive and dry exploratory and development wells drilled in the last three years.

 
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Net productive and dry exploratory and development wells

   2020   2019(1)   2018 
Net productive exploratory wells drilled            
Consolidated subsidiaries               
Brazil   4.6    5.5    4.0 
South America (outside of Brazil)   —      1.0    —   
Total consolidated subsidiaries   4.6    6.5    4.0 
Equity method investees               
North America(2)   —      —      —   
Africa   —      —      —   
Total productive exploratory wells drilled   4.6    6.5    4.0 
Net dry exploratory wells drilled               
Consolidated subsidiaries               
Brazil   1.5    1.0    4.0 
South America (outside of Brazil)   —      —      —   
Total consolidated subsidiaries   1.5    1.0    4.0 
Equity method investees               
North America(2)   —      —      —   
Africa   —      —      —   
Total dry exploratory wells drilled   1.5    1.0    4.0 
Total number of net exploratory wells drilled   6.1    7.5    8.0 
Net productive development wells drilled               
Consolidated subsidiaries               
Brazil   79.0    102.0    103.7 
South America (outside of Brazil)   0.336    —      3.7 
Total consolidated subsidiaries   79.3    102.0    107.4 
Equity method investees               
North America(2)   0.306    0.14    0.1 
Africa   0    0.6    0.4 
Total productive development wells drilled   79.6    102.7    107.9 
Net dry development wells drilled               
Consolidated subsidiaries   —      —      —   
Brazil   —      —      —   
South America (outside of Brazil)   —      —      —   
Total consolidated subsidiaries   —      —      —   
Equity method investees   —      —      —   
North America(2)   —      —      —   
Africa   —      —      —   
Total dry development wells drilled   —      —      —   
TOTAL NUMBER OF NET DEVELOPMENT WELLS DRILLED   79.64    102.7    107.9 

_________________ 

(1)Data from 2019 has been adjusted to reflect the inclusion of both injection and producing wells.
(2)Due to the joint venture formed by PAI and Murphy, information regarding proved reserves, acreage and wells in the United States are reported in the “equity method investees” section. For “net” figures, we used the working interest held as of December 31, 2020.
 
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The following table summarizes the number of wells in the process of being drilled as of December 31, 2020.

Number of wells being drilled as of December 31, 2020

   Gross   Net 
Consolidated Subsidiaries          
Brazil   8.0    6.65 
International          
South America (outside of Brazil)   1.0    0.34 
North America   4.0    0.18 
TOTAL WELLS DRILLING   13.0    7.17 

The following table sets forth our average sales prices and average production costs by geographic area and by product type for the last three years.

Average sales prices and average production costs (US$)

   Brazil   South America   North America   Total   Equity method investees(2) 
2020                         
Average sales prices                         
Oil and NGL, per barrel   39.96    36.89    —      39.95    37.69 
Natural gas, per thousand cubic feet(1)   5.63    3.65    —      5.47    2.00 
Synthetic oil, per barrel   33.2    —      —      33.2    —   
Synthetic gas, per thousand cubic feet   2.52    —      —      2.52    —   
Average production costs, per barrel – total   4.11    4.35    —      4.11    36.23 
2019                         
Average sales prices                         
Oil and NGL, per barrel   61.25    36.89    —      61.25    64.71 
Natural gas, per thousand cubic feet(1)   7.72    3.65    —      7.55    2.60 
Synthetic oil, per barrel   50.55    —      —      50.55    —   
Synthetic gas, per thousand cubic feet   3.53    —      —      3.53    —   
Average production costs, per barrel – total   7.05    4.69    —      7.02    31.20 
2018                         
Average sales prices   66.66    42.44    67.21    66.65    72.76 
Oil and NGL, per barrel   7.15    4.09    3.56    7.00    0.76 
Natural gas, per thousand cubic feet(1)                         
Synthetic oil, per barrel   60.04    —      —      60.04    —   
Synthetic gas, per thousand cubic feet   4.47    —      —      4.47    —   
Average production costs, per barrel – total   10.21    4.57    9.75    10.11    31.85 

_________________ 

  (1)The volumes of natural gas used in the calculation of this table are the production volumes of natural gas available for sale and are also shown in the production table above. Natural gas amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet.
  (2)Operations in Venezuela until 2016, in Africa until October 2018, and in the United States from December 2018, following the creation of a joint venture with Murphy, in which our wholly-owned subsidiary PAI has a 20% stake.

For more information about our capitalized exploration costs, see Note 28 to our audited consolidated financial statements and the unaudited supplementary information on oil and gas exploration and production contained therein.

 
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REFINING, TRANSPORTATION AND MARKETING

We processed 73% of all our oil production, which includes oil and LNG and excludes natural gasoline (“C5+”), in our refineries. The remainder was exported. In 2020, we produced 1.828 million bbl/d of oil products, from the processing of Brazilian oil (94% of feedstock) and imported oil (6% of feedstock). We traded these oil products both in Brazil and abroad.

Furthermore, we operate in the petrochemical sector with interests in companies, as well as in the production of biofuels through our wholly-owned subsidiary, Petrobras Biocombustível S.A. (“PBIO”).

Overview

We own and operate 13 refineries in Brazil, with a total net crude distillation capacity of 2,176 mbbl/d. This represents 99% of all refining capacity in Brazil, according to the 2020 statistical yearbook published by the ANP.

Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, easing access to crude oil supplies and end-users.

We also operate a large and complex infrastructure of pipelines and terminals, and a shipping fleet to transport oil products and crude oil to Brazilian and global markets. We operate 44 of our own terminals through our wholly-owned subsidiary Petrobras Transporte S.A. (“Transpetro”), and we have contracts for the use of some of the storage capacity of 17 third-party terminals.

 
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Our Refining, Transportation and Marketing also include activities such as (i) petrochemicals (ii) extraction and processing of shale and (iii) production of biofuels.

We are repositioning ourselves in the refining business through divestment, a strategy which allows us to share risks and to establish a dynamic, competitive and efficient industry, while generating liquidity for us.

In line with our repositioning process, in June 2019, we signed a commitment with CADE which consolidates our understanding on the execution of divestment of refining assets in Brazil. The purpose of the agreement is to provide competitive conditions, encouraging new economic agents to enter the downstream market, as well as suspending CADE’s court administrative investigation related to the alleged abuse of our dominant position in the refining segment. The agreement considers the divestment of approximately 50% of our refining capacity, which comprises seven refining units (Reman, Lubnor, Rnest, Rlam, Regap, Repar and Refap) and a shale industrialization unit (SIX).

For more information on our agreement with CADE regarding our divestments in refining assets, see “Risks – Risk Factors – Operational Risks” and “Portfolio Management” in this annual report.

The initial stages of these divestments processes were announced in 2019. We have since announced additional stages in 2020.

For more information on our partnerships and divestments, see “Portfolio Management” in this annual report.

Main Assets

   2020   2019   2018 
Transport and storage               
Pipelines (km)   7,719    7,719    7,719 
Vessel fleet (owned and chartered)   131    128    123 
Own   30    45    43 
Chartered    101    83    80 
Terminals   61    63    56 
Own   44    44    44 
Third party’s(1)    17    19    9 
Refining                
Refineries   13    13    14 
Brazil   13    13    13 
Abroad   —      —      1 
Nominal installed capacity (mbbl/d)   2,176    2,176    2,276 
Brazil   2,176    2,176    2,176 
Abroad   —      —      100 

_________________ 

(1)Third party terminals that have existing contracts for the use of the storage service, except Transpetro contracts.

Refining

We serve our oil products clients in Brazil through a coordinated combination of oil processing, importing and exporting that seeks to optimize our margins, considering different opportunity costs of domestic and imported oil, oil products in the several markets, as well as the costs for transport, storage and processing involved.

In 2020, we processed 1,754 mbbl/d of oil in our 13 refineries. The following graphs show the processed feedstock and the performance of our refineries.

 
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Processed feedstock (mbbl/d)

In October, our refineries broke an internal production record of S-10 Diesel low-sulfur diesel, producing 2.01 million m³ of the product, a higher volume than in July, when production reached 1.81 million m³, and 25% higher than the June mark of 1.6 million m³.

The S-10 Diesel records follow the evolution of heavy-duty and utility vehicle engines powered by diesel, which are responsible for most of the goods circulated in Brazil. There are two types of road diesel in Brazil, the S-500 and the S-10, with the former being used by vehicles manufactured prior to 2012.

In 2020, there was an increase in the production of oil products and utilization factor of the refining system as compared to 2019. Despite the reduction in gasoline and jet fuel production between 2019 and 2020, the production of oil products rose in 2020 mainly due to increases in the production of low sulfur fuel oil for export, which resulted from higher bunker oil prices in the global market due to the new IMO 2020 quality specifications. Diesel production increased in 2020, despite the drop in sales in the domestic market, with the surplus being directed to exports.

Naphtha production increased in 2020, accompanying the increase in sales in the domestic market, due to the reduction in direct imports made by Braskem.

LPG production increased in 2020 due to an increase in sales resulting from lower average temperatures and social isolation because of the Covid-19 pandemic, both of which boosted the consumption of residential LPG.

In 2020, there was a decrease in the production of jet fuel following the reduction in sales due to the impact of Covid-19 on commercial jet fuel demand.

In addition to constructing new refineries, over the past 10 years we have made substantial investments in our existing refineries to increase our capacity to economically process heavier Brazilian crude oil, improve the quality of our oil products to meet stricter regulatory standards, modernize our refineries, and reduce the environmental impact of our refining operations. These investments in our existing refineries have been largely completed.

The following table sets out the performance of our refineries.

 
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Performance of refineries

   Crude distillation capacity (mbbl/d)   Nelson Complexity Index   Average throughput(1)
(mbbl/d)
   Operational
availability
(%)
  

Utilization rate

(%)

 
Refinery  2020   2020   2020   2019   2018   2020   2019   2018   2020   2019   2018 
LUBNOR   8    3.5    8    7    8    97.3    95.3    97.5    102.0    82.7    94.5 
RECAP   57    6.8    39    50    50    96.8    96.2    97.6    68.4    87.8    93.1 
REDUC   239    15    178    190    190    96.8    96.9    95.3    74.5    79.5    79.7 
REFAP   201    6    129    138    135    97.6    93.7    95.8    64.1    68.8    66.8 
REGAP   157    7.9    123    134    141    97.4    96.3    97.7    78.0    85.3    89.7 
REMAN   46    1.8    27    32    30    97.9    97.9    97.1    59.3    69.1    64.3 
REPAR   208    7.8    179    168    173    97.8    94.2    96.6    86.3    80.9    83.1 
REPLAN   434    6.9    306    326    286    96.8    96.2    87.2    70.4    75.2    68.8 
REVAP   252    8.6    216    185    213    97.1    94.5    96.5    85.9    73.5    84.8 
RLAM   279    7.7    239    206    201    94.1    92.9    95.2    85.6    73.9    63.8 
RPBC   170    10.2    143    133    140    96.2    95.3    97.5    84.0    78.3    82.4 
RPCC   38    1    29    32    32    —      —      —      —      —      —   
RNEST   88    10.7    93    74    67    96.8    97.8    94.6    105.7    84.4    90.2 
Average crude oil throughput   —      —      1,709    1,675    1,664    —      —      —      —      —      —   
Average NGL throughput   —      —      45    45    51    —      —      —      —      —      —   
Average throughput   —      —      1,754    1,720    1,715    —      —      —      —      —      —   
Crude Distillation capacity   2,176    —      —      —      —      —      —      —      —      —      —   
                                                        

_________________ 

(1)Considers oil and NGL processing (fresh feedstock).
 
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Main products, markets and storage capacity of our refinaries

          Storage capacity
(mbbl)
 
Refinery   Main products  Main markets in Brazil  Crude oil   Oil products 
 LUBNOR   Asphalt (45%); Fuel Oil (35%); Lubricants (13%); Diesel (7%)  Lubricant Oil – sold to distributors and marketed nationwide 0.3 0.6 Asphalts – states in Northern and Northeastern Brazil and Minas Gerais   0.3    0.6 
 RECAP   Diesel (42%); Gasoline (33%); LPG (9%)  Part of the São Paulo metro region and petrochemical plants   0.5    1.8 
 REDUC   Diesel (25%); Gasoline (14%); Fuel Oil (19%); LPG (12%); Jet Fuel (4%); Naphtha (12%)  Rio de Janeiro, São Paulo, Espírito Santo, Minas Gerais, Bahia, Ceará, Paraná, Rio Grande do Sul   5.7    12.5 
 REFAP   Diesel (47%); Gasoline (20%); Naphtha (14%); LPG (7%)  Rio Grande do Sul, part of Santa Catarina and Paraná, in addition to other states by means of coastal shipping   3.2    1.4 
 REGAP   Diesel (48%); Gasoline (24%); Jet Fuel (4%); LPG (7%)  Currently supplies the state of Minas Gerais and, occasionally, the state of Espírito Santo. It can also expand its reach to the Rio de Janeiro market   1.7    6.0 
 REMAN   Gasoline (31%); Diesel (26%); Naphtha (9%); Jet Fuel (7%); Fuel Oil (15%)  Amazonas, Acre, Roraima, Rondônia, Amapá and Pará   0.7    1.5 
 REPAR   Diesel (47%); Gasoline (27%); LPG (8%)  Paraná, Santa Catarina, Southern São Paulo and Mato Grosso do Sul   2.9    1.9 
 REPLAN   Diesel (46%); Gasoline (21%); LPG (7%); Jet Fuel (3%)  Countryside of the state of São Paulo, Mato Grosso, Mato Grosso do Sul, Rondônia and Acre, Southern Minas Gerais and the so-called “Triângulo Mineiro”, Goiás, Brasília, and Tocantins   6.7    12.9 
 REVAP   Diesel (32%); Gasoline (19%); Naphtha (10%); Jet Fuel (10%); Fuel Oil (14%)  Paraíba Valley, the northern coast of the state of São Paulo, southern Minas Gerais, the São Paulo metro region, Midwestern Brazil and Southern Rio de Janeiro. It supplies 80% of the demand for jet fuel in the São Paulo state market and 100% of the Guarulhos International Airport   3.3    12.0 
 RLAM   Diesel (30%); Gasoline (17%); LPG (5%); Fuel Oil (39%);  Primarily the northeastern region of Brazil, followed by the north region and the state of Minas Gerais   —  (1)   4.3 
 RPBC   Diesel (45%); Gasoline (25%); Fuel Oil (13%); LPG (6%)  Most products are intended for São Paulo’s capital. A portion is also shipped to Santos and to the Northern, Northeastern, and Southern Brazilian regions   2.5    6.8 
 RPCC   Fuel Oil (76%); Diesel (9%); Jet Fuel (5%); Gasoline (6%)  Rio Grande do Norte and southern Ceará   0.12    0.12 
 RNEST   Diesel (50%); Naphtha (13%); Coke (8%); Fuel Oil (27%)  North and Northeast of Brazil   —  (2)   0.7 

_________________ 

(1)Crude oil is supplied directly to RLAM tank farms of 4.1 mbbl, with no external crude oil storage.
(2)Crude oil is supplied directly to RNEST’s tank farms of 5.1 mbbl, with no external crude oil storage.
 
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With respect to oil products, we produced 1,828 mbbl/d of oil products in 2020, as shown in the following graphic:

 

Oil products production (mbbl/d)

Ongoing undertakings

Located in southeastern Brazil (Itaboraí, in the state of Rio de Janeiro), the GASLUB Itaboraí project is comprised of the GASLUB Itaboraí Refinery, UPGNs and other underlying utilities. With respect to the UPGN, all critical bidding for the UPGN utilities was successfully completed during 2019. In 2020, some utilities systems were successfully completed and the unit start up is scheduled for 2022. We are studying new project alternatives for the GASLUB Itaboraí area that include integration with the refinery operating in Duque de Caxias (REDUC) for the production of basic lubricants G-II and high quality fuels and the construction of a Natural Gas Thermoelectric Power Plant.

International Maritime Organization

In 2016, the International Maritime Organization (“IMO”) decided to reduce the allowable upper limit for sulfur content in marine fuels (bunker oil) from 3.5% to 0.5% from January 1, 2020 onwards.

From 2017 to the first quarter of 2019, we carried out studies and analyses in order to prepare our refineries and logistics to produce and deliver a compliant fuel. Furthermore, our increasing production of oil from pre-salt has low sulfur, allowing us to obtain fuel oil that already practically meets the bunker fuel specifications without requiring the addition of high amounts of diluents which give us a competitive edge in the global market.

We have a competitive advantage in the production of the IMO 2020 compliant marine fuel, allowing us to anticipate the market trend and satisfying the needs of our clients.

In the last quarter of 2019, the demand for LSFO increased in all ports where we offered the product while international prices have risen significantly.

In 2020, due to the rising value of the low sulfur fuel oil (LSFO), we have set new records of exports from Brazil three times, the last one being in September when 1.14 mmt of fuel oil (mainly LSFO grades) left Brazilian ports. Even with increasing export quantities during 2020, the average of LSFO grades from Brazil were commercialized at a positive crackspread against Brent.

 
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Logistics

 

Oil and oil products logistics connect the oil production systems to refineries and markets seeking to maximize the value of oil refining operations and the commercialization of oil and oil products in Brazil and abroad through an integrated system of logistics planning, sales, and operations and assets, as depicted below.

We directly manage some assets of this system, while we contract others with our wholly owned subsidiary Transpetro.

Transpetro is a logistics company which performs operations for the storage and handling of oil and its derivates, ethanol, gas and biofuels for the supply of Brazilian machinery, thermoelectric and refineries, including import and export activities.

The terminals and pipelines operation is an important link in our supply chain. The oil is transported from the production fields to Transpetro terminals either by pipeline or by ship. From there, it is transported to refineries or for export. After refining, the oil products are again drained through pipelines to the terminals to be delivered to fuel distribution companies, which supply the Brazilian and global markets.

This operation covers a 7,719 km pipeline network and 44 terminals, 24 of which are marine and 20 onshore. The terminals have a total nominal storage capacity of 10.24 million m³. In 2020, Transpetro handled 568.4 million m³ of oil and oil products, totaling 8,227 operations with tankers and oil barges.

 
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Volume moved at terminals and pipelines (million m3)

In 2020, we continued, in partnership with Transpetro, our implementation of the Integrated Pipeline Protection Program (“Pró-Dutos”). Pró-Dutos aims to expand and integrate all actions targeted at mitigating the risks caused by fuel thefts (illegal taps) in onshore pipelines. The scope of the program is multidisciplinary and focuses on six areas: intelligence, legislation, social responsibility, communication, technology and contingency.

In addition to our attention to operational safety, we seek to work in cooperation with public intelligence and security agencies to protect life and the environment around the areas in which we operate. In 2020, new pipeline routes for the transportation of LPG, naphtha and oil were put into operation. As a result, these highly flammable products are now transported far away from the urban centers of the metropolitan region of São Paulo, significantly mitigating the risk to human life caused by the fuel theft from pipelines. In 2020, 4,973 m³ of oil and oil products were stolen, a decrease of 30% compared to 2019. The number of thefts in 2020 reached 201, slightly below the 203 occurrences in 2019.

We also launched a new and wide-ranging advertising campaign to raise public awareness of fuel theft risks and to encourage the public to report criminal actions through our communication channel. In addition, we continued to exercise our crises procedures and responses to emergencies resulting from fuel theft from pipelines. For example, in 2020, we completed the first integrated crisis simulation exercise between Transpetro and us.

 
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Terminals

Location  Terminal  Type  Nominal capacity (m³) 
Alagoas  Maceió  Marine   58,266 
Amazonas  Manaus (REMAN)
Coari
  Marine
Marine
   –81,705 
Bahia  Candeias
Itabuna
Jequié
Madre de Deus
  Onshore
Onshore
Onshore
Marine
   36,472
28,845
28,111
663,582
 
Ceará  Mucuripe  Marine   —   
Espírito Santo  Barra do Riacho
Norte Capixaba
Vitória
  Marine
Marine
Marine
   107,883
85,205
10,706
 
Distrito Federal  Brasília  Onshore   72,309 
Goiás  Senador Canedo  Onshore   127,449 
Maranhão  São Luís  Marine   78,895 
Minas Gerais  Uberaba
Uberlândia
  Onshore
Onshore
   54,615
47,226
 
Pará  Belém  Marine   48,100 
Paraíba  Cabedelo  Marine   10,745 
Pernambuco  Suape  Marine   108,713 
Paraná  Paranaguá  Marine   204,499 
Rio de Janeiro  Ilha d’ Água
Angra dos Reis
Campos Elíseos
Ilha Redonda
Japeri
Volta Redonda
  Marine
Marine
Onshore
Marine
Onshore
Onshore
   179,150
1,004,861
547,243
81,833
37,729
29,649
 
Rio Grande do Norte  Guamaré
Osório
  Marine
Marine
   258,521
842,100
 
Rio Grande do Sul  Niterói
Rio Grande
  Marine
Marine
   26,978
101,408
 
Santa Catarina  Biguaçu
Itajaí
Guaramirim
São Francisco do Sul
  Onshore
Onshore
Onshore
Marine
   37,916
56,806
18,926
472,408
 
Sergipe  Aracaju  Marine   156,940 
São Paulo  Santos
São Sebastião
Barueri
Cubatão
Guararema
Guarulhos
Paulínia
Ribeirão Preto
São Caetano do Sul
  Marine
Marine
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
   382,561
2,041,906
206,262
160,836
1,030,673
164,194
274,349
50,826
227,496
 
TOTAL  44     10,244,896 
 
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In 2020, aiming to optimize the operational fleet and following the best practices of the shipping market, Transpetro performed an analysis of its ship portfolio and decided to dispose of assets over 25 years old. In this way, Transpetro created a divestment plan that will end in the first half of 2021. This action plan resulted in a reduction in the average age of the fleet from 13.57 years to 9.34 years in 2020, in addition to improving the operational availability indicator.

For more information on the vessels chartered or owned by us and Transpetro, see Exhibit 15.4 to this annual report.

Marketing

 
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Besides oil and oil products, we also trade natural gas, nitrogen fertilizers, renewables and other products.

Brazilian sales volumes and exports (mbbl/d)

   2020   2019   2018 
Total oil products   1,663    1,738    1,787 
Ethanol, nitrogen fertilizers, renewables and other products   8    7    17 
Natural gas   292    350    345 
Total Brazilian market   1,963    2,095    2,149 
Exports(1)   957    735    594 
TOTAL BRAZILIAN MARKET AND EXPORTS   2,920    2,830    2,743 

_________________ 

(1)It mainly includes crude oil and oil products.
 
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Oil products prices

Crude oil is a commodity, the value of which depends on its quality. Traditionally, a lighter crude oil has a better value than a heavier one, given that it can generate higher value products. Recently, however, heavy crudes have shown a strong market value due to the possibility of high margin production when these crudes are processed in high complexity hardware refineries. Moreover, low-sulfur crude oil could have a better expectancy value than oil with higher sulfur content if they both have similar yields and physical properties. Different refineries assign different values to the same crude oil, depending on their conversion capacity and the products they intend to produce to supply their specific market. Refineries can process a wide variety of different crude oils, which make different crude oils competitors among themselves.

Crude oils are globally traded and their prices used to be referenced on international quotations, as WTI, Brent or Dubai. Depending on the quality, offer, demand, size lot, commercial conditions and logistics costs to make a crude oil cargo available at a certain delivery point, a premium or a discount negotiated between buyer and seller will be added to the reference quotation.

Refined oil products are commodities and their prices in the global market are driven by the supply and demand balance, crude oil price and crack spread. Crack spread refers to the overall pricing difference between a barrel of crude oil and oil products refined from it. It is an industry-specific type of gross processing margin. The “crack” being referred to is an industry term for breaking apart crude oil into the component products, including gases like propane, heating fuel, gasoline, light distillates like jet fuel, intermediate distillates like diesel fuel and heavy distillates like grease. Typically, a crack is defined in terms of one specific product versus one specific crude. For example, the diesel crack on Brent indicates how much the price of the individual product is contributing to refining profitability.

The price of a barrel of crude oil and the various prices of the products refined from it are not always in perfect synchronization. Depending on seasonality and global inventories among other factors, the supply and demand for particular distillates results in pricing changes that can impact the profit margins on a barrel of crude oil for the refiner.

As oil products are traded globally and can be transported between markets, prices around the world tend to fluctuate together, subject to local conditions.

Diesel and Gasoline

Diesel and gasoline prices in the Brazilian market are defined taking into account the import parity price and margins to remunerate the risks inherent in the operation.

Prices readjustments of diesel and gasoline are carried out without defined frequency, according to market conditions and external environment analysis, enabling us to compete more efficiently and flexibly.

In 2020, we announced adjustments to selling prices at refineries, resulting in price decreases of 4.1% for gasoline and 13.2% for diesel, when comparing prices in place on December 31, 2020 with those effective as of December 31, 2019.

LPG

In August 2019, prices for “residential LPG” began to adopt the import parity price as reference, similar to the “industrial/commercial LPG” policy. This allowed a greater alignment of prices for both segments. In November 2019, we equalized prices for residential and industrial/commercial use. In March 2020, the Brazilian National Council of Energy Policy (CNPE) revoked the legal basis that allowed differentiation of prices by segment.

 
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Price adjustments are made without defined periodicity, according to market conditions and analysis of internal and external environments.

In 2020, we announced adjustments to selling prices at refineries, resulting in price increases of 21.9% for LPG, when comparing prices in place on December 31, 2020 with those effective as of December 31, 2019.

Imports, Exports, and International Sales

Our import and export of crude and oil products are driven by economic factors involving our domestic refining, the Brazilian demand levels and international prices. Most of the crude oil we produce in Brazil is classified as medium API gravity. We import some light crude oil to balance the slate for our refineries, and export mainly medium crude oil from our production in Brazil. In addition, we continue to import oil products to balance any shortfall between production from our Brazilian refineries and the market demand for each product.

In 2020, net exports increased by 362,000 bbl/d, reaching 743,000 bbl/d. This increase resulted from the record in oil exports, 33% higher than in 2019 and from an increase in fuel oil exports for bunker formulation due to the appreciation caused by the entry of IMO 2020. In addition, there was a drop in diesel and gasoline imports due to the negative impact on consumption caused by the Covid-19 pandemic.

Exports and imports of crude oil and oil products (mbbl/d)

   2020   2019   2018 
Exports               
Crude oil   713    536    428 
Fuel oil   194    133    121 
Other oil products   50    66    43 
Total exports   957    735    592 
Imports               
Crude oil   97    168    154 
Diesel   18    70    59 
Gasoline   10    28    19 
Other oil products   89    88    117 
Total imports   214    354    349 

Our crude oil, oil products and LNG trading activities aim to meet our internal demands or potential businesses opportunities identified by our commercial teams, seeking to optimize the buying and selling operations in the Brazilian and global markets, as well as offshore operations.

The international trading teams are based in the major global commercial hubs of oil and oil products, such as London, Houston and Singapore and Rotterdam and are comprised of crude oil and product traders, shipping and support operators.

One of our most representative trades in terms of volume and profitability is crude oil. We sell oil through long-term and spot-market contracts. In 2020, the crude oil volume committed through long-term contracts with fixed quantity subject to final agreement on commercial terms was approximately 100,000 bbl/d.

 
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Distribution

We sell our oil products to several distribution companies in Brazil. Until July 2019, we had a 71.25% stake in BR Distribuidora (“BRDT”), one of the largest distribution companies in the country. As a result of the follow-on offering closed in July 2019, we have a 37.5% participation in BRDT as of December 31, 2020.

In August 2020, our Board of Directors approved the proposal to sell our remaining 37.5% stake in the capital stock of BRDT, by means of a secondary public offering (follow-on). The launch date of the offer will be defined at a later time and is subject, among other conditions, to market conditions, the approval of our internal boards (particularly regarding price), and to the analysis of the CVM and other regulatory and self-regulatory bodies, under the terms of the applicable legislation.

Even after completing the sale of part of our shareholding in BRDT, we remain the owner of the main brands used by it, including those that identify service stations, fuel, loyalty program, aviation segments and certification program, among others.

A 10-year trademark license agreement is in place and grants BRDT a non-exclusive, paid, temporary license on certain trademarks we own, including but not limited to “Petrobras,” “Petrobras Podium,” “Petrobras Premmia,” “De Olho no Combustível,” “BR Aviation” and “Petrobras Grid.” The trademark license agreement was renegotiated before the follow on to incorporate changes necessary for both companies. It was signed in 2019 and is renewable for an additional 10-year period. Under the terms of this agreement, the license is granted exclusively to the service station and aviation segments, for which BRDT shall exclusively use the brands licensed by us. BRDT must also exclusively use our licensed brands in the oil and gas and biofuels segments. Meanwhile, during the term of the trademark license agreement, we undertake to refrain from operating in the service stations across the Brazilian territory. The definition of a “service station” under this agreement is any facility where oil and gas products and services and/or services related to any other energy sources (renewable or otherwise) intended to power automotive vehicles and watercrafts are offered to the Business-to-Consumer (or B2C) public, including convenience stores.

In 2020, we operated in the bottling, distribution and sale of LPG through our subsidiary Liquigás Distribuidora S.A. (“Liquigás”). In line with our goals of optimizing our portfolio, improving our capital allocation and creating value for our shareholders, we completed the sale of our entire stake in Liquigás on December 2020.

For more information on the sale of our equity stake in Liquigás see “Portfolio Management” in this annual report.

For more information on oil products clients, see “Our Business – Production -Customers and Competitors” in this annual report.

We also participate in the retail sector in other South American countries, as follows:

Colombia: Our operations through Petrobras Colombia Combustibles S.A. (PECOCO) include 123 service stations and a lubricant plant with a production capacity of 54,000 m3/year. In March 2020, we announced the beginning of PECOCO’s divestment process;
Uruguay: We had 88 service stations. In February 2021, we sold our stake in PUDSA and ended the operation in this country.
Chile: Following the sale of our distribution operations in Chile, which was concluded in January 2017, we entered into a brand licensing agreement in that country, for the initial term of eight years. To operate our acquired assets in Chile, Southern Cross created Esmax, a company that operates as our licensee in the fuel distribution segment;
 
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Paraguay: Until March 8, 2019, our operations included 201 service stations, the distribution and sales of fuel at three airports and an LPG refueling plant. Our operations were sold to Paraguay Energy, a subsidiary of Copetrol Group. The sale agreement also included the licensing for the exclusive use of our brands by Nextar (the successor of Petrobras Paraguay Operaciones y Logística SRL) in service stations in Paraguay, for the initial term of five years.

For more information of the divestment process, see “Portfolio Management” in this annual report.

Customers and Competitors

We interact with around 470 clients in Brazil, in regards to liquid oil products, seven of which account for 70% of the total volume sold.

Liquid Oil Products Clients (% vol)

The sale of oil products to distribution companies is done by contracts executed in accordance with ANP regulations.

We offer a virtual commercial platform, called Canal Cliente to Brazilian market companies. The platform works 24 hours a day, seven days a week. Through this online platform, clients can place orders for products, schedule withdrawals and track the entire business process up to the payment phase.

According to information provided by the ANP, we have a dominant participation in the Brazilian market for refining. We own and operate 13 refineries in Brazil and a shale industrialization unit (“SIX”). SIX is presented in the Shale Industrialization section in this annual report.

 
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In June 2019, we signed a commitment with CADE which consolidates the understanding between the parties on the execution of the divestment of refining assets and SIX in Brazil.

For more information on our agreement with CADE regarding our divestments in refining assets, see “Risks – Risk Factors – Operational Risks” and “Portfolio Management” in this annual report.

With respect to the trading of oil products in the Brazilian market, we face competition from importers, formulators, other domestic producers and petrochemical plants. In 2020, our participation in diesel and gasoline markets decreased compared to the previous year, mainly due to the increase in imports by third parties. In the specific case of gasoline, demand also reflected competition with a substitute product, hydrous ethanol, which recorded a sharp increase in consumption during 2020.

 
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Other Activities

Petrochemicals

We engage in the petrochemical sector through the following companies:

Our shareholding in petrochemical companies in Brazil and their main products

Company/Main products Location Nominal capacity (mmt/y) Our shareholding Other shareholding
Braskem        
Ethylene Bahia 5.00 36.15%

Novonor (38.32%); Others (25.53%)

Polyethylene 4.11
Polypropylene 4.50
DETEN Quĺmica S.A.        
LAB(1) Bahia 0.22 27.88% Petresa (69.78%); Others (2.34%)
LABSA(1) 0.12
METANOR S.A./COPENOR S.A.(2)        
Formaldehyde

Bahia

0.09

34.34%

GPC –Grupo Peixoto de Castro (45,22%); Tesouraria (0.59%); Others (20.44%)
Hexamine 0.01
FCC Fábrica Carioca de Catalisadores S.A.        
Catalysts Rio de Janeiro 0.04 50.00% Albemarle (50.00%)
Additives   0.01    
PETROCOQUE S.A.        
Calcined petroleum coke São Paulo 0.55 50.00% Universal Empreendimentos e Participações Ltda (50.00%)
         

_________________ 

(1) Feedstock for the production of biodegradable detergents.
(2) Copernor S.A. is a subsidiary of Metanor S.A.
 
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Shale Industrialization

We operate shale processing through our shale industrialization unit (“SIX”), an operating unit with installed capacity of 5,880 t/d, located in São Mateus do Sul, Brazil. We have developed a technology that covers all stages of the manufacturing process. The products obtained from shale processing are fuel oil, naphtha, fuel gas, liquefied gas, sulfur and paving inputs that are used by various industries, such as ceramics, oil refineries, cement plants, sugar mills and agricultural undertakings. The process also produces shale water, which is an input used to formulate foliar fertilizers.

Fuel oils obtained from shale are suitable for industrial consumption in urban centers because they are highly fluid, very easy to handle and eliminate the need for pre-heating. This allows for reductions in burning operating costs and, as such, is ideal for cold climates.

In conducting our operation, we work to repair mined areas through an environmental program that consists of reforestation with native species and the return of fauna to rehabilitated land.

In line with our repositioning process, in 2019, we signed a commitment with the CADE which consolidated our understanding on the execution of divestment of refining assets in Brazil and started the divestment processes of seven refining units (Reman, Lubnor, Rnest, Rlam, Regap, Repar and Refap) and SIX.

For more information on our agreement with CADE regarding our divestments in refining assets, see “Risks – Risk Factors – Operational Risks” and “Portfolio Management” in this annual report.

Biofuels

BioRefino 2030

In 2020, we launched the BioRefino 2030 Program, which aims to transform the refining park in sync with a low-carbon based economy and anticipates projects for the generation of new, modern and sustainable fuels, such as renewable diesel and biojet.

Renewable diesel is an advanced biofuel, produced from vegetable oils using our proprietary HBIO technology. The resulting fuel presents the same structure as conventional diesel fuel. According to reports from the Biodiesel Producers Association (APROBIO), this new fuel reduces the emission of greenhouse gases by 70% compared to mineral diesel oil and by 15% compared to ester biodiesel. Renewable diesel is also free of contaminants and does not cause any damage to engines, effectively increasing vehicle life and reducing transportation costs. The authorization for the commercial sale of this biofuel in Brazil will depend on a new regulation to be issued by the National Petroleum Agency (ANP).

BioQAv, or biojet fuel, will be used worldwide to reduce the emission of greenhouse gases in the aviation sector. This was determined by the International Civil Aviation Organization (ICAO) and will be mandatory in Brazil in 2027. The production process for BioQAv, through hydrogenation, uses the same raw materials required for the production of renewable diesel and produces renewable diesel (HVO) as a co-product.

We also operate in the production of biodiesel through our wholly owned subsidiary PBIO, which manages our activities for the production, logistics and marketing of these products.

Brazil is a global leader in the use and production of biofuels. The anhydrous ethanol content requirement for gasoline sold in Brazil is 27%.

Historically, Brazil is a major producer of ethanol and sugar and some companies that operate in this market sell the excess electricity generated from the burning of sugarcane bagasse.

 
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There is mandatory blend of 13% biodiesel in all diesel sold in Brazil on or after March 2021, with gradual scheduled increases of 1% per year, until it reaches a mandated 15% in 2023. PBIO had a 50% interest in BSBios Indústria e Comércio de Biodiesel Sul Brasil S.A. (“BSBios”), which owns two biodiesel plants. In February 2021, we announced the sale of PBIO’s entire stake in BSBios to RP Participações em Biocombustíveis S.A. (“RPBio”), which owned the remaining 50% stake in BSBios. PBIO has three biodiesel plants for its own operations. However, the Quixada biodiesel plant, one of our directly owned units, is in hibernation state since November 2016. Our biodiesel production capacity in the other two in operation is 8.63 mbbl/d. In 2020 we supplied 4.81% of Brazil’s biodiesel demand, according to the ANP.

Main Assets

   2020   2019   2018 
Biofuels               
Biodiesel production units - PBIO   3    3    3 
Biodiesel production capacity (mbbl/d) - PBIO   10.5(1)   10.0(1)   8.2(1)
Biodiesel production units - BSBios   2    2    2 
Biodiesel production capacity (mbbl/d) - BSBios   14.3(2)   12.1(2)   9.9(2)

_________________ 

(1)Includes the capacity of Quixadá biodiesel plant, which has been in hibernation state since November 2016.
(2)Includes total production capacity in two plants in which we have 50% interest through BSBIOS Sul Brasil.

With respect to divestments, in July 2020, we announced the sale of PBIO’s entire stake in Bambuí Bioenergia S.A. (Bambuí). This stake represented 8.40% of Bambuí shares and was sold to Turdus Participações S.A. (Turdus), which held the remaining 91.60% stake in the company. However, Turdus and Bambuí initiated an arbitration process against PBIO. In February 2021, we also announced the sale of PBIO’s entire stake in BSBios to RPBio. In addition, we are in the process of divesting our stake in PBIO. In September 2020, we announced the beginning of the binding phase of the sale of all of our shares in this wholly owned subsidiary.

For more information on our divestments, see “Portfolio Management” in this annual report.

In accordance with our Strategic Plan, we decided to exit the biodiesel and ethanol production market. Nevertheless, we are working to produce renewable diesel and BioQav, in response to the sustainability policies of the Brazilian energy matrix. We entered into several strategic transactions to this end.

 
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Biofuels production(1) (thousand m3)

_________________ 

(1)Includes 100% of the volume of our equity method investee (net production of PBIO in biodiesel, considering PBIO share in the investee, was 68.4% in 2018, 67.4% in 2019 and 64.5% in 2020 ).
(2)Ethanol production figures from 2020 are up to July 10, 2020, the date when we sold our share in Bambuí, our investee in this segment (net production of PBIO in ethanol was 8.4% of total).
 
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GAS AND POWER

Overview

We process gas produced in our oil fields in our natural gas processing units (“UPGNs”) that have the capacity to treat 106.15 million m3/d of natural gas in Brazil. We market this natural gas, along with gas imported from Bolivia and LNG acquired in the global market, to several consumers and to the thermoelectric plants.

We also operate in the generation and sale of electric energy through thermal power plants fired by natural gas, diesel oil and fuel oil.

Main Assets

   2020   2019   2018 
Natural gas               
Gas pipelines in Brazil (km)   4,686(1)   9,190    9,190 
Processing Units   22    22    23 
Brazil   19    19    20 
Bolivia   3    3    3 
Processing capacity (million m3/day)   149    149    149 
Brazil   105    105    105 
Bolivia   44    44    44 
Regasification terminals   3    3    3 
Regasification capacity (million m3/day)    47    47    47 
Power               
Number of thermal power plants   20    20    20 
Installed capacity (thousand MW)   6.1    6.1    6.1 

_________________ 

(1)In July 2020, we entered into a share purchase and sale agreement for our remaining 10% interest in TAG, which has 4,504 km of pipelines.
 
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Natural Gas

Our Gas and Power segment comprises gas processing, transportation and distribution, LNG regasification (Ceará, Bahia and Rio de Janeiro), gas-fired, oil-fuelled and flex fuel power generation.

The Gas and Power segment strategy is:

Act competitively in the trading of its own gas.
Optimize the thermoelectric portfolio focusing on self-consumption and trading of its own gas.
Withdraw completely from gas distribution and transport.

Processing of Natural Gas

Natural gas from our exploration and production activities needs to be processed in processing units, to be transformed into marketable products. These products serve as fuel and raw material for different uses, such as vehicular, industrial and residential uses, as well as uses in the fertilizer industry and thermoelectric power generation.

Our UPGNs are located in the states of Amazonas, Ceará, Rio Grande do Norte, Alagoas, Sergipe, Bahia, Espírito Santo, Rio de Janeiro and São Paulo in Brazil as well as in Bolivia, where we have the capacity to process natural gas in its gaseous and condensed forms.

The current processing capacity and production of our UPGNs in Brazil is:

 
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Processing capacity and production of our UPGNs in Brazil

              2020   2019   2018 
   Location  Number of units   2020 Processing capacity   Unprocessed natural gas   Processed natural gas   LPG   Unprocessed natural gas   Processed natural gas   LPG   Unprocessed natural gas   Processed natural gas   LPG 
            (million m³/d)    (million m³/d)    (million m³/d)    (thousand t/d)    (million m³/d)    (million m³/d)    (thousand t/d)    (million m³/d)    (million m³/d)    (thousand t/d) 
UTGCAB  Rio de Janeiro   1    24.60    22.58    17.54    0.98    23.37    17.35    0.71    22.15    17.85    0.61 
UTGCA  São Paulo   1    20.00    12.43    11.84    0.62    14.68    14.03    0.70    11.47    10.95    0.47 
UTGC  Espírito Santo   1    18.10(1)    3.98    3.50    0.59    4.89    4.36    0.82    6.41    5.83    0.92 
UTGSUL  Espírito Santo   1    2.50    0.48    0.46    —      0.58    0.57    —      1.01    0.96    —   
REDUC  Rio de Janeiro   1    5.00    1.05    0.93    0.05    1.46    1.02    0.06    1.02    0.71    —   
RPBC  São Paulo   1    2.00    0.08    —      —      0.46    0.43    —      0.52    0.37    —   
LUBNOR  Ceará   1    0.35    —      —      —      —      —      —      —      —      —   
URUCU  Amazonas   4    12.20    11.61    10.81    1.08    12.10    11.56    1.21    12.32    11.45    1.26 
GUAMARÉ  Rio Grande do Norte   3    5.7    0.69    0.63    0.1    1.36    1.25    0.15    1.45    1.34    0.16 
PILAR  Alagoas   1    1.8    1.24    1.20    0.07    1.24    1.19    0.07    1.40    1.34    0.10 
ATALAIA  Sergipe   1    3.00    0.21    0.20    0.02    0.78    0.73    0.06    0.83    0.76    0.08 
CATU  Bahia   1    2.00    1.22    1.06    —      1.57    1.45    —      1.71    1.58    —   
CANDEIAS  Bahia   1    2.90    —      —      —      —      —      —      —      —      —   
EVF MANATI  Bahia   1    6.00    2.32    2.20    —      3.54    —      —      4.80    —      —   
TOTAL      19    106.15    57.89    50.37    3.51    66.33    53.95    3.78    65.09    53.16    3.60 

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(1)The UTGC unit's project was estimated to have a gas richness of approximately 14%. However, it actually presented an approximate richness of 8.5%. Thus, there was an opportunity to increase the nominal capacity of the plant without impacting the process, as the real richness was less than the projected richness.
 
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Logistics

We use a pipeline system to transport natural gas from processing plants, regasification terminals and the border with Bolivia, to the local distributors, as well as for the internal consumption of our units. Brazil has an integrated pipeline system centered around two main interlinked pipeline networks, a gas pipeline connection with Bolivia and an isolated pipeline in the northern region of Brazil (all together spanning over 9,190 km).

 
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Our share in gas transportation companies in Brazil

Company  Gas pipeline extension (km)   Our shareholding   Other shareholders
Transportadora Brasileira Gasoduto Bolívia Brasil S.A (“TBG”)   2,593    51%  BBPP Holdings Ltda. (29%); YPFB Transporte S.A. (12%); GTB –TBG Holdings S.A.R.L. (8%)
Nova Transportadora do Sudeste S.A. (“NTS”)   2,043    10%  Nova Infraestrutura Fundo de Investimento em Participações (FIP) (82.35%); Investimentos Itaú S.A. (Itaúsa) (7.65%)
Transportadora Sulbrasileira de Gás S.A. (“TSB”)   50    25%  Ipiranga Produtos de Petróleo S.A. (25%), Repsol Exploração Brasil (25%) e Total Gas and Power Brazil (25%)
TOTAL   4,686    —      

In July 2020, we sold our remaining 10% interest in Transportadora Associada de Gás S.A. (TAG), with the group comprised of ENGIE and CDPQ.

In March 2020, we announced the start of the divestment process of our remaining 10% interest in Nova Transportadora do Sudeste S.A. (NTS).

For more information on our divestments, see “Portfolio Management” in this annual report.

In addition, outside Brazil we hold an 11% stake in Gás Transboliviano S.A. (“GTB”), which is responsible for the Bolivian side of the Bolivia-Brazil gas pipeline, measuring 557 km.

 
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Gas from Pre-Salt

 

In order to derive natural gas from our production of the Santos Basin pre-salt pole, in addition to using part of the existing infrastructure, we invested in the construction of subsea pipelines (routes) integrated with the processing units, which seek to optimize the use of natural gas.

We have invested in the following flow routes:

ROUTE 1 AND GASMEX: The 359 km pipeline consists of two stretches: Route 1, which is the stretch connecting the Tupi Platform to the Mexilhão Platform, with capacity to flow up to 10 million m³/d, and GASMEX, which is the stretch connecting the Mexilhão platform to the Monteiro Lobato Gas Treatment Unit (“UTGCA”), in the city of Caraguatatuba in the state of São Paulo, with capacity to flow up to 20 million m³/d of gas produced in the Santos Basin pre-salt. We own 65% of Route 1, Shell owns 25% and Petrogal owns the remaining 10%.

ROUTE 2: The 401 km pipeline links the Santos Basin pre-salt to the UTGCAB processing asset, in the city of Macaé in the state of Rio de Janeiro. It had an initial capacity to flow up to 13 million m³/d, which then increased to 16 million m³/d. In July 2019, the ANP authorized the pipeline to operate with 20 million m³/d. We own 65% of Route 2 Tupi-Cernambi, Shell owns 25% and Petrogal owns the remaining 10%. We own 55% of Route 2 Cernambi-TECAB, Shell owns 25%, Petrogal owns 10%, and Repson owns the remaining 10%.

ROUTE 3: This 355 km gas pipeline will connect the pre-salt to the natural gas processing plant located in Itaboraí in the state of Rio de Janeiro, for the sale of up to 18 million m³/d. Three hundred seven km of the pipeline will be offshore, and 48 km onshore. The natural gas processing plant will have two units with a total capacity of processing 21 million m³/d of natural gas, which will increase the supply of natural gas, LPG and natural gasoline (C5+) to the market. The construction of Route 3 is scheduled to start in 2022. We own 100% of Route 3.

Recently installed and upcoming units in the Santos Basin pre-salt will be progressively connected to Route 2 (P-66, P-69, P-68, P-76) and to Route 3 once they become operational (P-67, P-75, P-77, P-70, FPSO Carioca and FPSO Almirante Barroso). All projects will be able to flow through any of the three flow routes once the system is fully implemented.

Marketing and Sales

The total volume of natural gas sold by us in 2020 was 68.3 mmm³/d. The volume of our natural gas consumption by industrial, gas-fired electric power generation, commercial and retail customers in 2020 was 54.7 mmm³/d, representing a small decrease of approximately 11% compared to 2019. This decrease is mainly attributable to the Covid-19 pandemic.

In 2020, the consumption of natural gas by our refineries and fertilizer plants was 13.5 mmm³/d, the same level as in 2019.

Below we present our sources and consumption in 2020:

 
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Opening the gas market

In July 2019, we signed an agreement with CADE, which consolidates the understandings between the parties on the promotion of competition in the natural gas industry in Brazil. This agreement includes the sale of shareholdings in gas transportation and distribution companies and, among other matters, increases the flexibility for third parties to have access to our processing plants and release capacity in certain gas transportation contracts to which we are part. The purpose of the agreement is to preserve and protect the competitive conditions, aiming to open the Brazilian natural gas market, encouraging new agents to enter this market, as well as suspending administrative procedures established by CADE court to investigate our natural gas business. The agreement signed in July 2019 also contains our commitment to sell the following ownership interest: (i) our 10% stake in Nova Transportadora do Sudeste S.A. (NTS); (ii) our 10% stake in Transportadora Associada de Gás S.A. (TAG); (iii) our 51% stake in Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (TBG); and (iv) our indirect stake in gas distribution companies, either by selling our 51% interest in Gaspetro, or by selling our indirect stakes in the distribution companies. In 2020, additional initiatives were implemented and for 2021 other initiatives are planned, which are included in the infographic below.

Additionally, we initiated the GAS + Program, which aims to increase our competitiveness in the natural gas segment within Brazil’s current conditions of market opening. With this program, we will launch new commercial products, new forms of relationships with customers, new tools (such as digital contracts and sales through automated platforms), and new business models (such as negotiated access to the outflow infrastructure and gas processing in our Gas Treatment Units), as well as direct the portfolio to high performance assets.

The Gas + Program also includes initiatives aimed at enhancing the efficiency and profitability of our Gas and Energy segment, thereby contributing to our high performance in a competitive market.

The program also provides for the incorporation of digital transformation initiatives, utilizing technological advances as an important resource for improving performance in all processes, whether at the industrial or business level.

 
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For more information on our agreement with CADE, see “Risks – Risk Factors – Operational Risks” and “Portfolio Management” in this annual report.

Natural gas sales contracts and long-term gas purchase and transportation commitments

We sell our gas primarily to local gas distribution companies and to gas-powered plants, generally based on standard take-or-pay, medium term supply contracts. This represents 66% of total demand volumes. The price formulas under these contracts are mostly aligned with Brent oil prices and the U.S. dollar. They were negotiated under the new gas bill.

In 2020, we renegotiated some existing mid-term natural gas sales contracts with local natural gas distribution companies in order to promote adjustments to commercial conditions tailored to specific market demands. We ultimately negotiated with 12 local distribution companies that represent 46% of the non-thermoelectric natural gas market and they were negotiated by the new gas policy.

When we began construction of the Bolivia-Brazil pipeline (“GASBOL”) in 1996, we entered into a long-term Gas Supply Agreement (“GSA”), with the Bolivian state-owned company Yacimientos Petroliferos Fiscales Bolivianos (“YPFB”), to purchase certain minimum volumes of natural gas at prices linked to the global fuel oil price through 2019. In 2020, the agreement may be extended until all contracted volume has been delivered by YPFB. We estimate that the agreement will be extended at least through May 2024 under the existing terms.

In December 2019, we signed a transition agreement with YPFB under the GSA which sets a transition period (from January 1, 2020 to March 10, 2020), during which we continued the ongoing negotiation process. Our purpose is to change certain commercial conditions according to the Brazilian natural gas market opening process and the new context of the Bolivian market.

Following the transition agreement, in March 2020, we and YPFB signed a new amendment to the GSA, (Amendment Eight), which refers to the volume of gas initially contracted that has not yet been delivered by YPFB until December 31, 2019. This amendment provides for the reductions of (i) the YPFB supply obligation to us from the current volume of 30.08 million m³/d to 20 million m³/d and (ii) our take-or-pay obligation from the current volume of 24.06 million m³/d (annual basis with make-up possibility) to 14 million m³/d (daily basis without make-up possibility), without any changes on the gas price formula, thus allowing the surplus volume of natural gas to be traded directly by YPFB with other market agents in Brazil.

Therefore, the execution of this amendment reaffirms our commitment to the opening of the Brazilian natural gas market, stimulating its competition by encouraging new agents to enter the market.

Furthermore, on March 21, 2020, we invoked force majeure under the GSA due to the impacts in the natural gas demand caused by the Covid-19 pandemic and, the consequent declaration of force majeure by each of the local distribution companies of natural gas in Brazil with respect to their own contracts with us. As a result, any payments of take-or-pay obligations were suspended up until the end of this event which occurred on August 31, 2020, which the GSA came back into full force.

According to the GSA provisions, the suspension of payments of take-or-pay obligations will be in place up until the date when we have taken the remaining gas volume originally agreed with YPFB. We estimate that this will occur in 2024 or 2025, depending on the gas demand that we perceive until then.

On the Bolivian side of GASBOL, while YPFB has shipper’s obligations, we agreed to pay, on behalf of YPFB, the amounts related to 24 million m³/d directly to GTB through 2019 and pre-paid six million m³/d through 2039.

 
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On the Brazilian side of GASBOL, after 2020, we expect 12 million m³/d of remaining volume related to Bolivian gas imports and 5.2 million m³/d related to extra capacity between Paulínia, in the state of São Paulo, and Araucária, in the state of Paraná. Any additional capacity must be contracted through a public process conducted by the ANP, in accordance with Brazilian law. In December 2019, the ANP approved the resumption of the ANP Public Call 01/2019 process, authorizing Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (“TBG”) to disclose the result of the guaranteed proposal stage and the signing of transport service contracts. As a result, we hired 18.08 million m³/d of entry capacity and 13.84 million m³/d of exit capacity for 2020 and 8.00 million m³/d of entry capacity and 1.82 million m³/d of exit capacity for 2021.

In December 2020, the ANP authorized TBG to implement a public auction, as an alternative to the postponed ANP Public Call 02/2020. After the conclusion of the auction, we hired additional entry capacity of 3.00 million m³/d and e