Company Quick10K Filing
Price12.73 EPS-1
Shares7,442 P/E-18
MCap94,754 P/FCF1
Net Debt65,526 EBIT29,802
TEV160,280 TEV/EBIT5
TTM 2018-12-31, in MM, except price, ratios
20-F 2019-12-31 Filed 2020-03-23
20-F 2018-12-31 Filed 2019-04-01
20-F 2017-12-31 Filed 2018-04-18
20-F 2016-12-31 Filed 2017-04-27
20-F 2015-12-31 Filed 2016-04-28
20-F 2014-12-31 Filed 2015-05-15
20-F 2013-12-31 Filed 2014-04-30
20-F 2012-12-31 Filed 2013-04-29
20-F 2011-12-31 Filed 2012-04-02
20-F 2010-12-31 Filed 2011-05-26
20-F 2009-12-31 Filed 2010-05-20

PBR 20F Annual Report

Item 17 ☐ Item 18 ☐
Note 23 Provides More Detailed Information on Depreciation, Amortization and Depletion.
Note 19 Provides Further Detailed Information About Contingencies and Legal Proceedings.
Note 20 Provides Further Detailed Information About The Decommissioning Provisions.
EX-1.1 d883642dex11.htm
EX-2.4 d883642dex24.htm
EX-2.10 d883642dex210.htm
EX-2.11 d883642dex211.htm
EX-8.1 d883642dex81.htm
EX-12.1 d883642dex121.htm
EX-13.1 d883642dex131.htm
EX-15.1 d883642dex151.htm
EX-15.2 d883642dex152.htm
EX-15.3 d883642dex153.htm
EX-15.4 d883642dex154.htm
EX-99.1 d883642dex991.htm

Petrobras Earnings 2019-12-31

Balance SheetIncome StatementCash Flow
Assets, Equity
Rev, G Profit, Net Income
Ops, Inv, Fin

20-F 1 d883642d20f.htm 20-F 20-F
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for the fiscal year ended December 31, 2019

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—

Avenida República do Chile, 65—23rd Floor 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:


Name of each exchange on which registered:

Petrobras Common Shares, without par value*   New York Stock Exchange*

Petrobras American Depositary Shares, or ADSs

(evidenced by American Depositary Receipts, or ADRs), each representing two Common Shares

  New York Stock Exchange
Petrobras Preferred Shares, without par value*   New York Stock Exchange*

Petrobras American Depositary Shares

(as evidenced by American Depositary Receipts), each representing two Preferred Shares

  New York Stock Exchange
Floating Rate Global Notes due 2020, issued by PGF   New York Stock Exchange
5.375% Global Notes due 2021, issued by PGF
(successor to PifCo)
  New York Stock Exchange
8.375% Global Notes due 2021, issued by PGF   New York Stock Exchange
6.125% Global Notes due 2022, issued by PGF   New York Stock Exchange
4.375% Global Notes due 2023, issued by PGF   New York Stock Exchange
6.250% Global Notes due 2024, issued by PGF   New York Stock Exchange
5.299% Global Notes due 2025, issued by PGF   New York Stock Exchange
8.750% Global Notes due 2026, issued by PGF   New York Stock Exchange
7.375% Global Notes due 2027, issued by PGF   New York Stock Exchange
5.999% Global Notes due 2028, issued by PGF   New York Stock Exchange
5.750% Global Notes due 2029, issued by PGF   New York Stock Exchange
6.875% Global Notes due 2040, issued by PGF
(successor to PifCo)
  New York Stock Exchange
6.750% Global Notes due 2041, issued by PGF
(successor to PifCo)
  New York Stock Exchange
5.625% Global Notes due 2043, issued by PGF   New York Stock Exchange
7.250% Global Notes due 2044, issued by PGF   New York Stock Exchange
6.900% Global Notes due 2049, issued by PGF   New York Stock Exchange
6.850% Global Notes due 2115, issued by PGF   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.

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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, 2019 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 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









Selected Financial Data






Risk Factors


Corporate Risk Management


Disclosures about Market Risk






Exploration and Production


Refining, Transportation and Marketing


Gas and Power


Portfolio Management


External Business Environment




2020 – 2024 Strategic Plan


Digital Transformation






Social Responsibility






Group Financial Performance


Segments Financial Performance


Liquidity and Capital Resources


Other Information












Controls and Procedures


Ombudsman and Internal Investigations






Shares and Shareholders




Additional Information for Foreign Shareholders






Material Contracts


Legal Proceedings






List of Exhibits






Conversion Table


Cross reference to Form 20-F






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In prior years, we presented our annual report on Form 20-F following the structure and order of disclosure displayed in the SEC Form 20-F. In this annual report on Form 20-F for the year ended December 31, 2019 (referred to herein as our “annual report”) we made changes in the structure of our annual report in order to present information to investors in a manner more consistent with how we view our business. To guide the reader, a cross reference guide to SEC Form 20-F is presented under “Cross-Reference to Form 20-F” in this annual report.

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”), including the effect of the implementation of IFRS 16 Leases, which became effective as of January 1, 2019.

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 anddivestments.

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;



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;



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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;



natural disasters, accidents, military operations, acts of sabotage, wars or embargoes;



the cost and availability of adequate insurance coverage;



our ability to successfully implement asset sales under our portfolio management program;



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; 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.

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 and at our website at 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 interim financial statements and other financial information of our company.

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



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Glossary of certain terms used in this Annual Report

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


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), or ANP, 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    The São Paulo 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.
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.
Brazilian Treasury    The 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
Câmara de Arbitragem do Mercado    An arbitration chamber governed and maintained by B3.



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Capital Expenditures or “CAPEX”    Capital expenditures, or CAPEX, 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.
CDS    Credit Default Swap.
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), or CGU, 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.
CMN    The Conselho Monetário Nacional (National Monetary Council), or CMN, 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 – COMPERJ (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), or CNPE, 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), or CVM.
D&M    DeGolyer and MacNaughton.
Deepwater    Between 300 and 1,500 meters (984 and 4,921 feet) deep.
Depositary    JPMorgan.
Development Ratio    Measures the relation between proved developed reserves and total proved reserves.
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. – Eletrobras.
EMBI+    Emerging Markets Bond Index Plus.
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.



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FPSO    Floating production, storage and offloading unit.
Gaspetro    Petrobras Gás S.A.
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 fuels 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 has been divided ten times by a factor of ten since Jan 1, 1985.
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 (LIBOR) 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).
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.
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.



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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 in 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.
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.



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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.
PwC    PricewaterhouseCoopers Auditores Independentes.
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.
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.
SDNY    The United States District Court for the Southern District of New York.
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.
TAG    Transportadora Associada de Gás S.A.
TCU    The Tribunal de Contas da União (Federal Auditor’s Office), or TCU, 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. (TBG).
TJLP    The long-term interest rate target (Taxa de Juros de Longo Prazo or TJLP) 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.



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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.
Ultra-deepwater    Over 1,500 meters (4,921 feet) deep.
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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We are a Brazilian company with over 57,000 employees committed to generate more value for our shareholders and the society. We are the largest company in market capitalization in Latin America, with a market capitalization of US$101.1 billion as of December 31, 2019. 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 acquired expertise on 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.


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: and

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, prospecting, extraction, processing, trading and transportation of crude oil from wells, shale and other rocks, its products, natural gas and other fluid hydrocarbons, in addition to other energy-related activities, and the research, development, production, transportation, distribution, sale and trading concerning all forms of energy, as well as other related activities or similar purposes.



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Selected Financial Data

The information below should be read jointly with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and “Operating and Financial Review and Prospects” in this annual report.

Statement of financial position


     As of December 31,                          
     2019     2018     2017     2016     2015  
                 (in US$ million)              



Cash and cash equivalents

     7,372       13,899       22,519       21,205       25,058  

Marketable securities

     888       1,083       1,885       784       780  

Trade and other receivables, net

     3,762       5,746       4,972       4,769       5,554  


     8,189       8,987       8,489       8,475       7,441  

Assets classified as held for sale

     2,564       1,946       5,318       5,728       152  

Other current assets

     5,037       5,401       3,948       3,808       4,194  

Long-term receivables

     17,691       22,059       21,450       20,420       19,426  


     5,499       2,759       3,795       3,052       3,527  

Property, plant and equipment

     159,265       157,383       176,650       175,470       161,297  

Intangible assets

     19,473       2,805       2,340       3,272       3,092  

Total assets

     229,740       222,068       251,366       246,983       230,521  
Liabilities and equity                               

Total current liabilities

     28,816       25,051       24,948       24,903       28,573  

Non-current liabilities(1)

     67,918       43,334       42,871       36,159       24,411  

Non-current finance debt(2)

     58,791       80,508       102,045       108,371       111,482  

Total liabilities

     155,525       148,893       169,864       169,433       164,466  

Share capital (net of share issuance costs)

     107,101       107,101       107,101       107,101       107,101  

Reserves and other comprehensive income (deficit)(3)

     (33,778     (35,557     (27,299     (30,322     (41,865

Equity attributable to our shareholders

     73,323       71,544       79,802       76,779       65,236  

Non-controlling interests

     892       1,631       1,700       771       819  

Total equity

     74,215       73,175       81,502       77,550       66,055  

Total liabilities and equity

     229,740       222,068       251,366       246,983       230,521  


















Excludes non-current finance debt.


Excludes current portion of long-term finance debt.


Capital transactions, profit reserves and accumulated other comprehensive income (deficit).



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Statement of income and other information


     For the Year Ended December 31,                    
     2019(1)     2018(2)     2017(3)     2016(4)     2015(5)(10)  
                 (in US$ million)              

Sales revenues

     76,589       84,638       77,884       72,426       97,314  

Operating income (loss)

     20,614       16,788       10,553       4,303       (1,130

Net income (loss) attributable to our shareholders

     10,151       7,173       (91     (4,838     (8,450

From continuing operations

     7,660       6,572       (347     (4,780      

From discontinued operations

     2,491       601       256       (58      

Weighted average number of shares outstanding(6):




     7,442,231,382 (7)      7,442,231,382 (7)      7,442,231,382 (8)      7,442,231,382 (8)      7,442,231,382 (8) 


     5,601,969,879 (7)      5,601,969,879 (7)      5,601,980,132 (8)      5,601,980,132 (8)      5,601,980,132 (8) 

Operating income (loss) per:


Common and preferred shares

     1.58       1.29       0.81       0.33       (0.09

Common and preferred ADS(6)

     3.16       2.58       1.62       0.66       (0.18

Basic and diluted earnings (losses) per:


Common and preferred shares

     0.78       0.55       (0.01     (0.37     (0.65

From continuing operations

     0.59       0.50       (0.03     (0.36      

From discontinued operations

     0.19       0.05       0.02       (0.01      

Common and preferred ADS(6)

     1.56       1.10       (0.02     (0.74     (1.30

From continuing operations

     1.18       1.00       (0.06     (0.72      

From discontinued operations

     0.38       0.10       0.04       (0.02      

Cash dividends per(9)


Common shares

     0.19       0.07                    

Preferred shares

     0.23       0.24                    

Common ADS(6)

     0.38       0.14                    

Preferred ADS(6)

     0.46       0.48                    



In July 2019, we closed the transaction under which we sold a further portion of our interest in BR Distribuidora. After the closing of this transaction, we are no longer the controlling shareholder of BR Distribuidora and, since August 2019, we have been reflecting BR Distribuidora’s results as an equity-accounted investment. Thus, from January to July 2019, we presented our post-tax profit of BR Distribuidora as Net income from discontinued operations in our consolidated statement of income, in accordance with IFRS 5, since it represented a separate major line of business. The statements of income for 2018, 2017 and 2016 were revised accordingly to reflect this classification. In 2019, we recognized impairment losses of US$2,848 million.


In 2018, we recognized the effects of the settlement of open matters with the DoJ and the SEC investigation, in the amount of US$853 million. We also recognized impairment losses of US$2,005 million.


In 2017, we recognized US$3,449 million as other income and expenses, due to the provision for legal proceedings relating to the agreement to settle our consolidated class action lawsuit before the United States District Court for the Southern District of New York. We also recognized impairment losses of US$1,191 million.


In 2016, we recognized impairment losses of US$6,193 million.


In 2015, we recognized impairment losses of US$12,299 million.


The ratio of ADR to our common and preferred shares is two shares to one ADR.


The total number of shares does not include 295,669 shares in treasury, of which 222,760 are common shares and 72,909 are preferred shares.


The total number of shares does not include 285,416 shares in treasury, of which 222,760 are common shares and 62,656 are preferred shares.


Pre-tax interest on capital and/or dividends proposed for the periods. Amounts were based on the exchange rate prevailing at the date of the approval by our Board of Directors, except for minimum mandatory dividends, which is based on the closing exchange rate on the date that our audited consolidated financial statements were released.


Our audited consolidated financial statements for the year ended December 31, 2015 were not retrospectively revised to reflect our sale of BR Distribuidora as a discontinued operation.



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We have a large base of proved reserves and operate and produce most of Brazil’s oil and gas. Most of our proved reserves are world-class assets 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 which themselves must be equipped and in constant evolution to supply the best products.

We operate most 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.




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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.

As a result of the divestments we concluded in 2019 and our portfolio review done as part of our 2020-2024 Strategic Plan, we reassessed the presentation of our business into certain segments. Our distribution and biofuels activities are no longer considered separate segments. We currently classify these activities as “Corporate and Other Businesses.” Accordingly, 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;



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; and



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.

Furthermore, our “Corporate and Other Businesses” classification includes the activities that are not attributed to the business segments, 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 (in Argentina, Bolivia, Colombia and Uruguay).

For further information regarding our business segments, see Notes 12 and 31 to our audited consolidated financial statements, as well as “Operating and Financial Review and Prospects” in this annual report.

In accordance with our 2020-2024 Strategic Plan, we have reduced our activities to eight countries outside 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. Until April 2019, we had refining operations in the United States. 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, and are in charge of market intelligence and marketing of oil, oil products, natural gas, commodity derivatives and shipping.

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“).



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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%)

Liquigás Distribuidora S.A.

   Brazil      100  

Araucária Nitrogenados S.A.

   Brazil      100  

Termomacaé S.A.

   Brazil      100  

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%)

Petrobras Negócios Eletrônicos S.A. – E-Petro

   Brazil      100  

Termomacaé Comercializadora de Energia S.A.

   Brazil      100  

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  



Joint operations.

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.



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The nature of our operations exposes us to a number of business 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) strategic risks, (ii) operational risks, (iii) financial risks, (iv) compliance, legal and regulatory risks, and (v) business 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

Strategic 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, serious environmental damage and related expenses (including, for example, cleaning and repairing expenses). These events may have an impact on the health of our workforce or on communities, and may cause environmental or 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 to repair or remediate the damages caused.

Since 2016, we suffered a significant increase in acts of intentional interference by third parties in our 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.




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In addition, public health epidemics such as the outbreak of the coronavirus (“COVID-19”) 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, we may face difficulties in obtaining or maintaining operating licenses and may suffer damages to our reputation.

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. These claims include the following: (i) indemnity actions (claiming material damages and loss of profits) brought by ethanol plants in several locations against the Brazilian federal government and us, as a result of diesel and gasoline prices in effect until 2016, and (ii) claims that seek to nullify divestments of assets and subsidiaries.

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.

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

The selection and development of our investment projects involve risks that may affect our originally 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.

In addition, we 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 life cycle and expected rate of return on these projects.

Our partnerships and divestments depend on external factors that could impact their successful implementation.

Pursuant to our 2020-2024 Strategic Plan, we expect to divest a significant number of assets in the coming years. External factors, such as the sustained decline in oil prices, injunctions and claims by third parties or public authorities in judicial, arbitral or administrative proceedings, exchange rate fluctuations, the deterioration of Brazilian and global economic conditions, the Brazilian political scenario and judicial decisions, among other factors, may reduce, delay or hinder sale opportunities for our assets or affect the price at which we can sell our assets.

If we are unable to successfully implement our planned partnerships and divestments, this may negatively impact our business, results and financial condition, including by potentially exposing us to short and medium-term liquidity constraints. In addition, the sale of assets may result in a decrease in our cash flows, which could negatively impact our long-term operating growth prospects and consequently our results in the medium and long-term.

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 2020-2024 Strategic Plan.

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 business restrictions and penalties, adversely affecting our operations, results and reputation.



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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, cybersecurity and 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, when the law comes into effect in August 2020.

Operational Risks

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.

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 Petros, 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.

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.

We are subject to minimum local content requirements in some of our concession agreements, in the Transfer of Rights Agreement and in the Production Sharing Agreements. In this case, we may not meet the minimum percentages of local content required in those agreements with appropriate financial conditions and, as a result, we may be pacteded by penalties in our contracts and we may need to search for international providers in the foreign market, which may subject us to consequences as defined in our agreements or delays in our investment projects.




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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 in China and elsewhere 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, reputation and image.

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 reputation and image.

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 a number of industrial facilities that demand the use of water, ranging from large users such as refineries to small users like distribution bases and terminals, which are logistically important within our chain. In recent years, several regions of the world, including some regions in Brazil, have experienced a 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 modified and, as a result, we may be required to reduce or suspend our production activities, since water for public consumption and watering of animals has priority over industrial use. This may jeopardize our business continuity, as well as generate financial and environmental impacts on us and our image.

Financial Risks

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 2020-2024 Strategic Plan.

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.



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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, 2019, a significant portion 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).

Following a devaluation 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 dolar, 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, 2019, a significant portion of our total indebtedness 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 business.



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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.

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

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.

In the past, some of our senior managers, directors and contractors have engaged in fraudulent activities incompatible with our ethics and compliance standards. 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 a large number of complex, valuable 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 of 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.

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 solved 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.

The agreements, subject to the terms thereof, fully resolve the investigations carried out by the DoJ and the SEC. Under the terms of the agreements, we paid US$85.3 million to the DoJ and US$85.3 million to the SEC. In addition, the agreements credited our remittance of US$682.6 million to the Brazilian authorities, which we deposited on January 30, 2019. The SEC also credited the payments we already made under our previously announced settlement of a securities class action lawsuit in the United States. The amount of US$853.2 million was recorded in other operating expenses in the third quarter of 2018.

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.

We were subject to a number of U.S. civil proceedings relating to the Lava Jato investigation, including the consolidated securities class action before the United States District Court for the Southern District of New York (“SDNY”), 33 lawsuits filed by individual investors before the same judge in the SDNY and one lawsuit filed in the United States District Court for the Eastern District of Pennsylvania (collectively, the “Individual Actions.”)

We entered into an agreement to settle the consolidated securities class action, which was approved by the SDNY, as well as agreements to settle the Individual Actions. In connection with the settlement of the consolidated securities class action, we paid US$2,950 million in three different installments in 2018 and 2019, into an escrow account designated by the lead plaintiff. After resolving certain objections and appeals of the settlement, it is now final and no longer subject to appeal.

We are also currently party to a collective action commenced in the Netherlands, an arbitration proceeding in Argentina, and arbitration and judicial proceedings commenced in Brazil, all of which are currently in their initial stages. 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 related to an alleged fraudulent offer of securities. 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.




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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.

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 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.

In the future, 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.

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 unitization 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.

Changes in the regulations applicable to us, as well as differences of interpretation between us and the agencies that regulate our industry, may have a material adverse effect on our financial condition and results. Any future differences in interpretation between us and these regulatory agencies may materially impact our results, since such interpretations directly affect the economic and technical assumptions that guide our investment decisions.

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.



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We are subject to 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, will not be affected by demands of new regulatory bodies or that the relevant licenses and permits will be 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.

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

Generally, transactions with related parties are part of the business of large companies. Such transactions 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 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.

Business 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 (such as the COVID-19 epidemic in early 2020), which is likely to decelerate the expected growth of worldwide oil demand in 2020, has already significantly affected oil prices and, consequently, could 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.

In the past, our management has adjusted our pricing from time to time. We cannot guarantee that our way of setting prices will not change in the future. In previous years, we have not always adjusted our prices to reflect parity with the global market trends or reflect exchange rate volatility. In the event that our way of setting prices changes based on the decisions of the Brazilian federal government, as our controlling shareholder, we may have periods in the future during which our prices for diesel and gasoline will not be at parity with international prices. Any such changes in our pricing may have a material adverse effect on our businesses, results and financial condition.



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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 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 devaluation 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.

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 greenhouse gas emissions taxation and market creation of limitations on greenhouse gas emissions that have the potential to increase our operating costs.

The risks associated with climate change could also make it difficult for us 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.

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 oil 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 oil and gas market and our long-term objectives.

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 demands significant capital investments, exposes us to the inherent risks of drilling, and may not lead to the discovery of commercially productive crude oil or natural gas reserves. We may also obtain additional reserves by proposing and implementing new development projects. Deepwater reservoirs exploitation demands significant resources to be successful and involves numerous factors beyond our control, such as delays in availability of offshore equipment, shortages in access to 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.




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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 recoverable 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 significantly 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. Downward revisions in our reserve estimates could lead to 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 concession regime, the concessionaire 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 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, we must perform integrated management and monitoring of the actions required and provided for in the contracts related to such 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 be different from the base scenario adopted at the time of divestment or partnership. In addition, as determined by the ANP, even in the event of total or partial disposal of our participation in E&P contracts, we remain jointly and severally liable for abandonment costs after the new concessionaire’s production closes, should it default on this task. Such joint and several liability covers obligations arising on a date prior to the transfer, regardless of when such obligations arise. 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 long-term operating growth prospects and, as a result, our medium and long-term results.

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 project, we may be exposed to the risks associated with those operations, including litigation (where joint liability could apply, in relation to the ANP, in the case of concession agreements, and in relation to the ANP and production sharing regime) and the risk of government sanctions arising from such partnerships, which could have a material adverse effect on their operations, reputation, cash flow and financial condition.

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

We operate and have businesses in several countries, particularly in the Gulf of Mexico, in the U.S., in South America, in Europe, in Asia and in Africa, 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.




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

Our divestments and partnerships plan includes the sale of some of our companies in the fuel distribution segment. Some of these transactions include licensing our brands to future buyers and partners. 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.

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.

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 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, instability in the political environment, 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;






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 political, diplomatic, social and economic developments in or affecting Brazil.



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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.

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.

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 – 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.



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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 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.

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



orientation of risk response actions aimed at aggregating or preserving shareholder value and business continuity.

The risks we categorize as “strategic risks” are monitored through specific actions, which are key for the implementation of our Strategic Plan. The scope and probability of these risks, as well as the resources required to address these risks, are particularly important to assess for our business.

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



identifying, monitoring and reporting periodically to our Board of Executive Officers and Board of Directors on the effects of major risks on our integrated results;



promoting integration and synergy of risk management actions taken in the organizational units, as well as in other business processes, support and management;



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 the culture of risk management; and



encouraging managers to develop and implement the necessary measures to align our exposure to acceptable risk levels.




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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 guide 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 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 great part 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 March 2019, we deployed a hedging strategy for part of our expected oil production in 2019, in a volume equivalent to 186 million barrels. Put options were purchased with exercise price referenced to the average price of Brent oil from April through the end of 2019, with an average exercise price of around US$60 per barrel. The options matured at the end of 2019. However, throughout the third quarter of 2019, due to the significant reduction in cash flow uncertainties for the 2019-2023 period, we sold our put options at an exercise price referenced to the average Brent oil prices from April to the end of 2019 at US$60/barrel, with total premium received of US$101 million.

In addition, transactions with derivatives were also implemented 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 36 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.




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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.

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 accordin’s, 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$2.28 billion for refineries and US$2.5 billion for platforms, depending on the replacement value of our assets. We self-insure less valuable assets, including but not limited to small auxiliary vessels, certain storage facilities and some administrative facilities.

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$345 million depending on the country.

Emerging Risks

Emerging risks are the long-term strategic risks that we have identified as the most severe and could significantly impact the execution of our Strategic Plan. We detail below these risks already briefly described in “Risks – Risk Factors” in this annual report.

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. Therefore such risk has been classified as a strategic risk in our Strategic Plan. In addition to cybersecurity issues, the concern and actions by our management aimed to improve protection and privacy of personal data held by us.

In Brazil, the LGPD will be completely effective as of August 2020. The LGPD has a series of sanctions, including fines, to be applied to organizations that do not comply with LGPD’s rules.




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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 are considered valuable and strategic assets, in December 2019, we created an area dedicated to information security, linked to the Digital Transformation and Innovation Executive Officer, form purposes 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 – Strategic Risks” and “Strategic Plan – Digital Transformation” in this annual report.

Changes in the competitive environment.

In June 2019, we signed two commitment agreements with CADE, which consolidate the understanding between the parties on the execution of divestment of refining assets and the promotion of competition in the natural gas industry in Brazil, including the sale of our shareholding in companies operating in the natural gas sector and their related assets. These agreements suspend the administrative investigation started by CADE court to investigate alleged abuse of our dominant position in the refining segment and creates a favorable environment for new investors to enter the natural gas industry.

The implementation of these agreements, associated with possible upstream regulatory changes, could increase the level of competition in the sector.

We are focusing on assets in which we are the natural owner and we expect better prospective return on capital (deepwater and ultra-deepwater activities), constantly pursue a competitive and efficient cost and investment structure, using active portfolio management as a key driver to our partnerships and divestments.

In addition, we have improving our operating efficiencies, reducing significantly our financial debt and we approved a plan of resilience related to our projects and assets, for guarantee profitability even in low oil prices scenarios. Since 2015, we launched some voluntary dismissal programs (see “Management and Employees – Employees – Workforce” in this annual report) and we maintain the efforts to cut others costs, with a rationalization of our physical space as part of risk treatment and strategy.

For more information, see “Risks – Risk Factors – Strategic Risks”, “Strategic Plan – 2020-2024 Strategic Plan” and “Portfolio Management” in this annual report.



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Exploration and Production


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 87% of our total production in 2019. 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 92% of our worldwide blocks and fields, 98% of our global oil production and 99% of our oil and natural gas reserves.



We have 430 assets in exploration and production including 132 joint ventures with other oil and gas companies. From the 430 blocks and fields, 406 are under the concession regime, 14 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 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 Lula (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 which are under the concession regime 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.


Outside Brazil, we have activies in South America, North America and West Africa. 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.



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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 2019, our production of oil and gas in Argentina, including NGL, was 7.7 mboed.

In Bolivia, our gas and condensate production comes, among others, mostly from the San Alberto and San Antonio fields with 35% working interest on each of those service operation contracts, which are operated mainly to supply gas to Brazil and Bolivia. In 2019, our production of oil and gas in Bolivia, including NGL, was 27.5 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.

North America

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 2019, our 20% participation represents a production of 13.5 mboed, including NGL.

In Mexico, we were party to the non-risk service contracts through our joint venture with PTD Servicios Multiplos SRL for the Cuervito and Fronterizo blocks in the Burgos Basin. This was terminated in March 2019.

West Africa

We used to explore oil and gas opportunities in West Africa exclusively through our 50% equity interest in Petrobras Oil & Gas B.V. (“PO&G”), a joint venture with BTG Pactual. The assets of this joint venture included the Agbami, Akpo, and Egina fields, and the Preowei and Egina South discoveries appraisal projects in Nigeria. In 2019, our 50% participation represents a production of 33.6 mboed, including NGL.

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


     2019      2018      2017  

Exploration and Production


Production wells (oil and natural gas)(1)

     6,587        7,256        7,888  

Floating rigs

     16        16        30  

Operated platforms in production(2)

     107        113        114  



Includes information from outside Brazil, corresponding to our shares in affiliated companies.


Includes only definitive production systems, EWT and EPS units.




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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 federal government 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 Transfer of Rights Agreements and Production Sharing Regimes in the Pre-salt Polygon. Currently, our main production fields follow the concession regime. However, our production fields under the Transfer of Rights Agreement and Production Sharing Regime will represent an important part of our production in the medium and long term.

Projected production by regulatory regime

(2020-2024 Strategic Plan)



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

The Transfer of Rights Agreement Amendment

The Transfer of Rights Agreement signed in 2010 between us and the Brazilian federal government is governed by Law No. 12,276/2010. This agreement regulates the transfer of oil and natural gas exploration and production rights in specific pre-salt areas and establishes provisions such as:



Volume that can be extracted in these areas, up to five billion barrels of oil equivalent;



Price paid for the Transfer of Rights Agreement;



Term of the Transfer of Rights Agreement and percentage of local content; and



Provisions that define a later revision on the following items: value, maximum volume, term and percentage of local content.

As a counterpart to the right of exploration and production, we paid the Brazilian federal government R$74.8 billion (US$42.5 billion as of September 1, 2010).



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The Transfer of Rights Agreement defined that the revision of its clauses of value, maximum volume to be produced by area, the term of validity and minimum percentages of local content could occur after the first declaration of an area’s commercial feasibility. We have already declared commercial feasibility in fields of all six blocks provided for in the agreement: Franco (Búzios), Florim (Itapu), Nordeste de Tupi (Sépia), Entorno de Iara (Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu, Atapu), Sul de Guará (Sul de Sapinhoá) and Sul de Tupi (Sul de Lula).

We acquired a significant volume of information through the drilling of more than 50 wells and long-term production tests and also have extensive knowledge of the Santos Basin pre-salt layer. This allowed us to characterize the existence of volumes exceeding five billion equivalent oil barrels originally contracted (“surplus volume”).

We formed an internal committee, composed of the two directors elected by the minority shareholders, and by an independent external member with notable knowledge in the area of technical and financial analysis of investment projects. The committee was responsible for negotiating the review of the Transfer of Rights Agreement with representatives of the Brazilian federal government.

In November 2019, we signed an amendment to the Transfer of Rights Agreement with the Brazilian federal government. Under this amendment, we maintain the total contracted volume of five billion barrels of oil equivalent, guarantee the reimbursement of US$8.3 billion, and adopt revised local content requirements. In December 2019, we received the amount owed to us by the Brazilian federal government.

For more information on the Transfer of Rights Agreement, see “Legal and Tax” in this annual report.

Bid rounds

We acted 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 important 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 and reflect the importance of these areas in Brazil for world-class oil companies.

In September and October 2017, we acquired 10 new exploratory blocks (nine offshore and one onshore), with a total area of 11.4 thousand km2. In the offshore blocks outside the Pre-salt Polygon, contracted under the concession regime, we hold 50% of the working interest in partnerships with ExxonMobil. Under the Production Sharing Agreements, we acquired three blocks inside the pre-salt area, in partnership with Shell, Repsol Sinopec, CNODC and BP.

In 2018, we acquired 11 new offshore exploratory blocks, with a total area of 8.8 thousand 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.



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In 2019, the ANP held three bidding rounds for exploratory blocks in Brazil.

The table below summarizes the areas acquired by us in each bidding round.














Profit Oil


Area Acquired

               (R$ million)    (USD Million)(2)    %    km2

16th Round Concession


Petrobras(1) 70%

BP 30%

   1,432    348    n/a    1,363

Transfer of Rights Surplus Production Sharing Bidding Round


Petrobras(1) 90%



   61,375    14,912    23.24    n/a
   ITAPU    Petrobras 100%    1,766    429    18.15    n/a

6th Round Production Sharing


Petrobras(1) 80%


   4,040    982    29.96    4,476





Using an exchange rate of R$ 4.1158 per USD for 4Q19

Búzios and Itapu fields

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 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. New units will be installed in the field to produce the surplus volume of the Transfer of Rights Agreement. The number and capacity of the new units will be established with the formalization of the co-participation agreement between the consortium participants. The co-participation agreement must be signed until September2021, but we have the agreement with CNODC and CNOOC to conclude it until December 2020. The Chinese partners in the consortium have the right to acquire more 5% of participation, or, if the agreement has not been signed by Pré-Sal Petróleo S.A. (“PPSA”) until September 2021, they have the right to leave the consortium.



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Additionally, we acquired 100% of the exploration and production rights of Itapu field’s surplus volume. In July 2019 we started the procurement process of the production unit, which will now be responsible for production under the Transfer of Rights Agreement and production of the surplus volumes. The full acquisition of the area is extremely attractive economically, given the low additional investments and the bid conditions.

The bidding round results help us ensure the maintenance of the operation in these fields, which enhance our global leadership in ultra-deepwaters. This is consistent with our strategy of focusing on the exploration and production of world-class offshore assets.

As of December 31, 2019, we had 117 exploratory blocks (39 with 100% working interest) which had 22 discoveries under evaluation. We also had five discoveries being assessed in production areas. We serve as the operator in 52 of these exploration partnership blocks.

The table below breaks down our participation in exploration activities in 2019:

Our participation in exploration activities in 2019


     Net exploratory area     

Exploratory blocks


Evaluation plans


Wells drilled

     (km²)      (number)    (number)    (number)
     2019      2018      2017     



















     40,625        51,600        41,820      113    133    123    24    26    28    8    8    8

Other S. America

     6,081        6,081        5,425      4    4    2    1    1    1    1    0    1

North America

     0        0        198      0    0    10    0    0    0    0    0    0


     0        0        0      0    0    0    2    2    2    0    0    0




























     46,706        57,681        47,443      117    137    135    27    29    31    9    8    9



























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

In 2019, two exploratory wells were drilled in the Moita Bonita Appraisal plan area, Sergipe Basin. These wells confirmed Campanian oil and gas-bearing reservoirs extensions. A Drilling Stem Test (“DST”) in the gas-bearing accumulation has shown encouraging results regarding reservoir continuity and productivity.

An exploratory well was drilled in 2019 in Marlim Leste, Campos Basin. This well confirmed the Aptian pre-salt oil reservoirs extensions discovered. Future extended well testing at the discovery site is intended to provide better measurements to guarantee the project’s economic viability and future resources incorporation.

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 current average for pre-salts of 3,000 days. Our efforts in such program are related to the integration of exploration and production development teams, the optimization of reservoir processes, the standardization of FPSO design, the early supplier engagement, the reduction of the construction time, and the optimization of processes through the use of digital technologies and agile methods. In addition, we are also implementing 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.



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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.

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 Lula field; and (iii) the P-68, located in the Berbigão and Sururu fields. Those new systems connected 19 new wells (13 production and six injection wells) in our production systems. We expect several major systems to be installed in the next five years.

Over the last nine years, we pursued substantial cost optimizations regarding project development. Time to drill and complete wells in the Santos Basin pre-salt area decreased by 63% in 2019 when compared to 2010. In 2019, we spent an average of 116 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. Due to the wells’ high productivity, we have been able to complete the ramp-up of the platforms with fewer wells.

In the Búzios field, we hit a production record with 63 mbbl/d from a single well connected to the P-75 platform. The Búzios field’s greater productivity made the P-75 and P-76 complete their ramp-up with just three wells each. This productivity plus the reduction on FPSO commissioning time allowed us to beat our ramp-up time record twice in 2019. In July, the P-75 reached its production capacity in 8.6 months; in October, the P-76 reached its full capacity in only 7.7 months.

We have installed eight new systems since 2018, including the systems that were implemented in 2019. In total, we have installed 10 new systems throughout the last three years, and expect to install other systems in the next five years.

Currently, we own 89 and lease 18 offshore platforms. Besides those, there are three platforms on fields operated by our partners. In 2019, these 110 platforms had a daily production of 2.09 million barrels of oil and 380.4 million cubic feet of natural gas (discounting the liquefied volume).

Pre-salt and the fields under the transfer of rights fiscal regime will be particularly important to support our production growth.

In 2020, the P-70 platform will be installed in the Atapu field. The P-70 platform has the capacity to process 150 mbbl/d and 6 million m3 of natural gas per day and arrived in Brazil, Rio de Janeiro on January 2020. A dry tow was used to transport the unit from China to Rio de Janeiro. It was loaded on a semi-submersible vessel used to transport heavy cargo instead of being driven by ocean tugs. Due to this transportation method, we were able to reduce the average transportation time from 100 days to around 45 days. Time is an extremely important variable for the return of a project, which highlights the contribution of the decrease in transportation time obtained through the use of dry tow.

As for the production sharing contracts areas, we expect to install the first definitive system in the Mero field in 2021.



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Installed Systems since 2010


Start up (year)

   Basin    Field/Area    Production unit    Crude oil
     Fiscal regime    Main


   Santos    Berbigão    Petrobras 68      150,000        211.9        2,280      Concession    Pre-Salt    FPSO
   Santos    Búzios 4    Petrobras 77      150,000        247        2,000      Transfer of Rights    Pre-Salt    FPSO
   Santos    Búzios 3    Petrobras 76      150,000        247        2,030      Transfer of Rights    Pre-Salt    FPSO
   Santos    Lula Norte    Petrobras 67      150,000        211.9        2,130      Concession    Pre-Salt    FPSO


   Campos    Tartaruga Verde    Cid. de Campos dos Goytacazes      150,000        117        765      Concession    Post-Salt    FPSO
   Santos    Lula Extremo Sul    Petrobras 69      150,000        211.9        2,200      Concession    Pre-Salt    FPSO
   Santos    Búzios 1    Petrobras 74      150,000        247        2,005      Transfer of Rights    Pre-Salt    FPSO
   Santos    Búzios 2    Petrobras 75      150,000        247        2,010      Transfer of Rights    Pre-Salt    FPSO


   Santos    Lula Sul    Petrobras 66      150,000        211.9        2,100      Concession    Pre-Salt    FPSO
   Santos    Mero    Pioneiro de Libra      50,000        141.3        2,040      Production Sharing    Pre-Salt    FPSO


   Santos    Lula Central    Cidade de Saquarema      150,000        211.9        2,100      Concession    Pre-Salt    FPSO
   Santos    Lula Alto    Cidade de Maricá      150,000        211.9        2,100      Concession    Pre-Salt    FPSO


   Santos    Lula    Cidade de Itaguaí      150,000        282.5        2,200      Concession    Pre-salt    FPSO


   Santos    Sapinhoá    Cidade de Ilhabela      150,000        211.9        2,140      Concession    Pre-salt    FPSO
   Santos    Lula    Cidade de Mangaratiba      150,000        282.5        2,220      Concession    Pre-salt    FPSO
   Campos    Roncador    Petrobras 62      180,000        211.9        1,600      Concession    Post-salt    FPSO
   Campos    Jubarte    Petrobras 58      180,000        211.9        1,400      Concession    Pre-salt    FPSO


   Campos    Roncador    Petrobras 55      180,000        141.3        1,795      Concession    Post-salt    SS
   Campos    Papa-Terra    Petrobras 63      145,000        35.3        1,200      Concession    Post-salt    FPSO
   Santos    Lula    Cidade de Paraty      120,000        176.6        2,140      Concession    Pre-salt    FPSO
   Santos    Baúna    Cidade de Itajai      80,000        70.6        275      Concession    Post-salt    FPSO
   Santos    Sapinhoá    Cidade de São Paulo      150,000        176.6        2,140      Concession    Pre-salt    FPSO


   Campos    Jubarte    Cidade de Anchieta      100,000        123.6        1,220      Concession    Pre-salt    FPSO


   Campos    Marlim Sul    Petrobras 56      140,000        211.9        1,700      Concession    Post-salt    SS
   Santos    Mexilhão    Mexilhão      20,000        529.7        170      Concession    Post-salt    Fixed


   Campos    Jubarte    Petrobras 57      180,000        70.6        1,260      Concession    Post-salt    FPSO
   Santos    Lula    Cidade de Angra dos Reis      100,000        176.6        2,150      Concession    Pre-salt    FPSO
   Santos    Uruguá /Tambaú    Cidade de Santos      25,000        353.1        1,300      Concession    Post-salt    FPSO
   Campos    Jubarte    Capixaba      110,000        113.0        1,300      Concession    Post-salt    FPSO

Main Systems to be installed until 2024


Start up (year)






Production unit


Crude oil






Fiscal regime





Expected 2020

   Santos    Atapu 1    Petrobras 70    150,000    211.9    2,300    Transfer of Rights    Pre-Salt    FPSO

Expected 2021

   Santos    Sépia    Carioca    180,000    211.9    2,150    Transfer of Rights    Pre-Salt    FPSO
   Santos    Mero 1    Guanabara    180,000    423.8    2,100    Production Sharing    Pre-Salt    FPSO

Expected 2022

   Campos    Marlim 1    Anita Garibaldi    80,000    51.2    670    Concession    Post-Salt    FPSO
   Santos    Búzios 5    Alm. Barroso    150,000    211.9    2,100    Transfer of Rights    Pre-Salt    FPSO
   Santos    Lula (Lula Recovery Factor Project)    N/D    150,000    211.9    2,000    Concession    Pre-Salt    FPSO

Expected 2023

   Campos    Parque das Baleias    N/D    100,000    176.6    1,400    Concession    Pre-Salt    FPSO
   Santos    Mero 2    Sepetiba    180,000    423.8    2,000    Production Sharing    Pre-Salt    FPSO
   Campos    Marlim 2    Anna Nery    70,000    33.2    927    Concession    Post-Salt    FPSO

Expected 2024

   Santos    Búzios 6(1)    N/D    150,000    254.3    2,025    Transfer of Rights/Production Sharing    Pre-Salt    FPSO
   Santos    Mero 3    N/D    180,000    423.8    2,070    Production Sharing    Pre-Salt    FPSO
   Sergipe Alagoas    SEAP    N/D    120,000    353.1    2,250    Concession    Deepwater    FPSO
   Santos    Itapu    N/D    120,000    106    2,010    Transfer of Rights/ Production Sharing    Pre-Salt    FPSO



Regarding the production system to be installed in the Module 7 area of the Búzios field.



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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 15 rigs with this capacity as of December 31, 2019.

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.



Drilling units in use by exploration and production as of December 31,


     2019      2018      2017  
     Leased      Owned      Leased      Owned      Leased      Owned  


     18        0        17        4        29        7  


     2        0        1        3        1        4  

Offshore, by water depth (WD)

     16        0        16        1        28        3  

Jack-up rigs

     0        0        0        0        0        2  

Floating rigs:

     16        0        16        1        28        1  

500 to 999 meters WD

     0        0        1        0        1        0  

1000 to 1999 meters WD

     1        0        2        0        3        1  

2000 to 3200 meters WD

     15        0        13        1        24        0  

Outside Brazil

     1        0        1        0        4        0  


     1        0        1        0        3        0  


     0        0        0        0        1        0  


     19        0        18        4        33        7  

In order 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, 2019, we had 13 PLSVs and our specialized vessels were sufficient to meet our needs.


After several years of stagnation, our operating performance has improved significantly, reaching daily, quarterly and annual oil and gas production records. In 2019, our total production of oil and gas, including NGL, was 2.77 mmboed, of which 2.69 mmboed were produced in Brazil and 82.3 mboed were produced abroad, a 5.4% increase compared to 2018. This production growth was due to the ramp-up of the eight new systems in Búzios (P-74, P-75, P-76 and P-77), Lula (P-67 and P-69), Berbigão/Sururu (P-68) and Tartaruga Verde (FPSO Campos dos Goytacazes) fields.

Our 2019 operating performance reflected better results in the second half, leveraged by the ramp-up of new production systems, compensating for the challenges faced during the first half. The oil production in Brazil was 2.17 million bbl/d, 6.7% above production achieved in 2018, exceeding the revised target in July (2.1 million bbl/d). The oil production represented 81% of the average of 2.69 mmboed oil and gas produced in Brazil.

Our production in the pre-salt layer reached 1.28 million bbl/d in 2019, representing an increase of 28.4% in relation to our production in 2018. In 2019, the oil production in the pre-salt layer represented more than half of our total oil production in Brazil,59% compared to 49% in 2018.



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Oil and gas production (mboed)


     2019      2018      2017      2019 vs 2018  

Crude oil and natural gas—Brazil

     2,688        2,527        2,654        6.4

Crude oil (mbbl/d)(1)

     2,172        2,035        2,154        6.7


     124        135        150        -8.1

Shallow waters

     66        90        118        -26.7

Post-salt deep and ultra-deepwaters

     704        816        977        -13.7


     1,277        994        908        28.5

Natural gas (mboed)

     516        492        500        4.9

Crude oil and natural gas -Abroad

     82        101        112        -18.8














     2,770        2,628        2,767        5.4















Including NGL

Pre-salt oil production increased 28.5%, reflecting higher production in the Búzios and Lula 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 13.7% . This was due to (i) the closure of the production cycle of platforms P-33 and P-37 (which will be replaced by new units for the Marlim field revitalization project) and (ii) the postponement of new wells on platforms that need adjustments in discharged water processing plants.

Main production fields



Production units




















(% wt)

  2019 oil


  Lula   Pre-salt   3   3 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     615  


  Búzios   Pre-salt   4   4 units with 150       Petrobras (100%)(1)   28.4   0.31     252  


  Sapinhoá   Pre-salt       2   2 units with 150  

Petrobras (45%),

Shell (30%),

Repsol Sinopec (25%)

  29.8   0.4     106  


  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     205  


  Roncador   Post-salt   4  

3 units with 180

1 unit with 190


Petrobras (75%),

Equinor (25%)

  17 – 28   0.53 – 0.74     121  


  Marlim Sul   Post-salt   3  

1 unit with 140

1 unit with 180

1 unit with 200

      Petrobras (100%)   17 – 23   0.59 – 0.73     135  


  Tartaruga Verde   Post-salt       1   1 unit with 150   Petrobras (100%)(1)   26.9   0.61     94  


  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     75  


  Marlim Leste   Post-salt   1   1 unit with 180   1   1 unit with 100   Petrobras (100%)   23 – 29   0.50 – 0.51     55  

Other pre and post-salt fields




Shallow waters












Including operations in 2019.

Shallow waters oil production decreased by 24 mbbl/d due to the divestment of Polo Pargo, the maintenance stop of the PNA-2 platform and the end of the PNA-1 production. Onshore oil production decreased 11 mbbl/d due to the natural decline in reservoir.



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We have produced 91.8 million m3/d of gas in 2019. From that volume, we have used 49 million m3/d in our production processes (reinjected, flared, consumed), and destinated 42.8 million m3/d to our processing plants.

In 2019, our average lifting cost excluding government fees was US$9.5 per boe, 11% less than the average cost of US$10.7 per boe in 2018.




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 2019, 2018 and 2017, 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 the Americas, Europe, China, and Asia.

Oil clients (% vol)



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



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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 reserve volumes 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 the sale of gas. Reserve volumes of non-traditional reserves such as synthetic oil and gas are also included in this annual report in accordance with SEC rules.

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 17 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, 2019 in Brazil. The amount of reserves reviewed by D&M corresponds to 96% 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.



Table of Contents

Our net proved oil, condensate and natural gas reserves as of December 31, 2019 were estimated at 9,590 million boe.

Proved reserves (million boe)*





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.

Proved reserves (million boe)(1)





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


The 913 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.



Table of Contents

In 2019, we incorporated 944 million boe of proved reserves by revising previous estimates, including:



addition of 529 million boe resulting from technical revisions, mainly due to good performance and increased production experience in reservoirs in the pre-salt layer of Santos Basin;



addition of 267 million boe related to contractual revisions, including the rearrangement of volumes due to the revision of Transfer of Rights Agreement and renewals of concession contracts in Brazil;



addition of 243 million boe due to approvals of new projects in the Santos, Campos and Espírito Santo Basins; and



reduction of 95 million boe related to economic revisions, mainly due to the decrease in oil prices.

In addition, we added 26 million boe to our proved reserves due to extensions and discoveries, mainly in the pre-salt of Santos Basin, and reduced 72 million boe due to sales of proved reserves.




Proved Undeveloped Reserves

As of December 31, 2019, our proved undeveloped reserves were estimated at 3,553 million boe, a net decrease of 19% when compared to 2018 year-end. This decrease is a result of the following changes:



we converted a total of 1,701 million boe of proved undeveloped reserves to proved developed reserves, mainly as a result of pre-salt fields platforms start-ups in the Santos Basin and offshore and onshore drilling and tieback operations;



we incorporated 867 million boe into our proved undeveloped reserves as a result of revisions to previous estimates, including: technical revisions (580 million boe), mainly due to the good performance and increased production experience in the pre-salt layer of the Santos Basin; new project approvals (241 million boe) in the Santos, Campos and Espírito Santo Basins; contractual revisions (59 million boe); and a reduction of 12 million boe due to economic revisions.



we added 20 million boe to our proved undeveloped reserves due to extensions and discoveries, mainly in the pre-salt of the Santos Basin; and



we reduced 22 million boe from our proved undeveloped reserves as a result of sales of proved reserves.



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Variation in proved undeveloped reserves (million boe)(1)





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

As of December 31, 2019, 42% (1,489 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 2019, we invested a total of US$7.0 billion in development projects, of which 98% (US$6.8 billion) 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 can 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, 2019. 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, 2019  
     Oil      Natural gas      Synthetic oil      Synthetic
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Consolidated subsidiaries



     5,870        5,841        346        339        —          —          —          —    



South America (outside of Brazil)

     55        24        197        96        —          —          —          —    

Total international

     55        24        197        96        —          —          —          —    

























Total consolidated

     5,925        5,864        543        435        —          —          —          —    

























Equity method investees:


South America (outside of Brazil)

     —          —          —          —          —          —          —          —    

North America

     42        5,0        1        0,1        —          —          —          —    


     67        4        —          —          —          —          —          —    

























Total gross and net productive wells

     6,034        5,874        544        435        —          —          —          —    

























Gross and net developed and undeveloped acreage


     As of December 31, 2019  
     Developed acreage      Undeveloped acreage  

Acreage (in acres)

   Gross      Net      Gross      Net  




     4,664,280.7        4,168,906.0        559,717.3        461,612.3  

South America (outside of Brazil)

     2,304.0        774.1        2,310.0        776.2  

Total consolidated

     4,666,584.7        4,169,680.1        562,027.3        462,388.5  

Equity method investees



     35,978.3        2,575.3        —          —    

North America

     23,024.0        2,354.6        153,336.0        15,067.7  

Total equity method investees

     59,002.3        4,929.9        153,336.0        15,067.7  













Total gross and net acreage

     4,725,587.0        4,174,610.0        715,363.3        477,456.2  













For “net” figures, we used our working interest held on December 31, 2019. 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.



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

Net productive and dry exploratory and development wells


     2019      2018      2017  

Net productive exploratory wells drilled:


Consolidated subsidiaries:



     5.5        4.0        7.0  

South America (outside of Brazil)


Total consolidated subsidiaries

     6.5        4.0        7.0  

Equity method investees:


North America(1)

     —          —          —    


     —          —          —    

Total productive exploratory wells drilled

     6.5        4.0        7.0  

Net dry exploratory wells drilled:


Consolidated subsidiaries:



     1.0        4.0        0.4  

South America (outside of Brazil)

     —          —          0.4  

Total consolidated subsidiaries

     1.0        4.0        0.8  

Equity method investees:


North America(1)

     —          —          —    


     —          —          —    

Total dry exploratory wells drilled

     1.0      4.0        0.8  










Total number of net exploratory wells drilled

     7.5        8.0        7.8  










Net productive development wells drilled:


Consolidated subsidiaries:



     98.3        103.7        174.8  

South America (outside of Brazil)

          3.7        2.7  

Total consolidated subsidiaries

     98.3        107.4        177.5  

Equity method investees:


North America(1)

     0.14        0.1        0.6  


     0.6        0.4        1.0  

Total productive development wells drilled

     99.04        107.9        179.1  

Net dry development wells drilled:


Consolidated subsidiaries:



     —          —          —    

South America (outside of Brazil)

     —          —          —    

Total consolidated subsidiaries

     —          —          —    

Equity method investees:

     —          —          —    

North America(1)

     —          —          —    


     —          —          —    

Total dry development wells drilled

     —          —          —    










Total number of net development wells drilled

     99.04        107.9        179.1  











(1)   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, 2019.




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The following table summarizes the number of wells in the process of being drilled as of December 31, 2019.

Number of wells being drilled as of December 31, 2019


     Gross      Net  

Wells Drilling


Consolidated Subsidiaries:



     7.0        5.45  



South America (outside of Brazil)

     1.0        1.0  

North America

     1.0        0.2  







Total wells drilling

     9.0        6.65  







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
     Total      Equity



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  



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  



Average sales prices


Oil and NGL, per barrel

     50.48        34.18        47.92        50.42        53.87  

Natural gas, per thousand cubic feet(1)

     6.30        3.53        3.31        6.10        —    

Synthetic oil, per barrel

     42.42        —          —          42.42        —    

Synthetic gas, per thousand cubic feet

     3.97        —          —          3.97        —    

Average production costs, per barrel – total

     11.15        3.65        9.17        10.99        27.00  



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.


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.



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For more information about our capitalized exploration costs, see Note 26 to our audited consolidated financial statements and the unaudited supplementary information on oil and gas exploration and production contained in our audited consolidated financial statements.

Refining, Transportation and Marketing

We processed 71% of all our oil production, which includes oil and LNG and excludes natural gasoline (“C5+”), in our refineries. The remainder was exported. In 2019, our production of oil products of 1.779 million bbl/d from the processing of 90% of Brazilian oil, complemented with imported oil. 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”).


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 2019 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 19 third-party terminals.



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Operated by Transpetro, a 100% Petrobras subsidiary



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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 the establishment of 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 the Administrative Council for Economic Defense (“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 the 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. We intend to divest from seven refining units (Reman, Lubnor, Rnest, Rlam, Regap, Repar and Refap) and a shale industrialization unit (SIX).

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

Main Assets


     2019      2018      2017  

Transport and storage


Pipelines (km)

     7,719        7,719        7,719  

Vessel fleet (owned and chartered)

     128        123        128  


     45        43        39  


     83        80        89  


     63        56        55  


     44        44        44  

Third party’s(1)

     19        9        8  




     13        14        14  


     13        13        13  


     —          1        1  

Nominal installed capacity (mbbl/d)

     2,176        2,276        2,276  


     2,176        2,176        2,176  


     —          100        100  



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



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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 2019, we processed 1,720 mbbl/d of oil in our 13 refineries, based on the processing of 91% of domestic oil. The following graphs show the processed feedstock and the performance of our refineries.

Processed feedstock (mbbl/d)



In 2019, there was an increase in the production of oil products and utilization factor of the refining system as compared to 2018. The higher production volume was directed to the export of bunker oil and high octane gasoline, which is valued in the U.S. market.

Diesel output fell due to the use of some of its streams to produce 0.5% bunker according to IMO 2020 specifications and the lower availability of the refining system. Diesel sales in 2019 dropped compared to 2018, with an increased portion of imported diesel.

The volume of gasoline production remained stable between 2019 and 2018. There was a drop in sales due to the higher market share of importers and hydrated ethanol. This drop was offset by an increase in exports of 34 mbbl/d.

Fuel oil production increased in 2019 due to the bunker oil price rose in the global market, which brought fuel oil export opportunities in particular to Singapore. There was a drop in sales volume in the Brazilian market between 2019 and 2018 due to lower deliveries for thermal power generation.

Naphtha production increased in 2019, enabling the reduction of imports compared to 2018.

LPG production and sales remained stable in 2019 and 2018.

In 2019, there was a decrease in the production of jet fuel following the reduction in sales due to a retraction in 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.



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The following table sets out the performance of our refineries.

Performance of refineries


     Average throughput(1)

     Utilization rate %  


   2019      2019      2019      2018      2017      2019      2018      2017      2019      2018      2017  


     8        3.5        7        8        7        95.3        97.5      98.0        82.7        94.5        89.9  


     57        6.8        50        50        50        96.2        97.6      97.5      87.8        93.1        94.0  


     239        14.9        190        190        178        96.9        95.3        93.9        79.5        79.7      74.5  


     201        5.7        138        135        138        93.7        95.8        97.3      68.8        66.8        68.4  


     157        7.8        134        141        143        96.3        97.7        97.2        85.3        89.7      91.0  


     46        1.8        32        30        32        97.9        97.1        97.6        69.1        64.3        69.8  


     208        7.7        168        173        162        94.2        96.6        96.0        80.9        83.1      78  


     434        6.9        326        286        324        96.2        87.2        95.7        75.2        68.8      77.9  


     252        8.5        185        213        208        94.5        96.5        94.8        73.5        84.8      82.8  


     279        7.7        206        201        198        92.9        95.2        93.9        73.9        63.8        62.7  


     170        9.6        133        140        144        95.3        97.5        96.9      78.3        82.4        85.0  


     38        1.0        32        32        33        —          —          98.7      —          —          87.8  


     88        8.5        74        67        68        97.8        94.6      94.6      84.4        90.2        92.4  

Average crude oil throughput

     —          —          1,675        1,664        1,686        —          —        —          —        —        —  

Average NGL throughput

     —          —          45        51        50        —          —          —          —        —          —    

Average throughput

     —          —          1,72        1,715        1,736        —          —          —          —        —