Company Quick10K Filing
Quick10K
Petrobras
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$13.40 7,442 $99,726
20-F 2018-12-31 Annual: 2018-12-31
20-F 2017-12-31 Annual: 2017-12-31
20-F 2016-12-31 Annual: 2016-12-31
20-F 2015-12-31 Annual: 2015-12-31
CEO CNOOC 6,407,803
PXD Pioneer Natural Resources 20,253
TPL Texas Pacific Land Trust 4,935
ESV Ensco 1,634
MGY Magnolia Oil & Gas 1,619
UNT Unit 150
SDLP Seadrill Partners 130
AXAS Abraxas Petroleum 84
ICD Independence Contract Drilling 82
CHAP Chaparral Energy 70
PBR 2018-12-31
Item 17 ☐ Item 18 ☐
Part I
Item 1. Identity of Directors, Senior Management and Advisers
Item 2. Offer Statistics and Expected Timetable
Item 3. Key Information
Item 4. Information on The Company
Item 4A. Unresolved Staff Comments
Item 5. Operating and Financial Review and Prospects
Item 6. Directors, Senior Management and Employees
Item 7. Major Shareholders and Related Party Transactions
Item 8. Financial Information
Item 9. The Offer and Listing
Item 10. Additional Information
Item 11. Qualitative and Quantitative Disclosures About Market Risk
Item 12. Description of Securities Other Than Equity Securities
Part II
Item 13. Defaults, Dividend Arrearages and Delinquencies
Item 14. Material Modifications To The Rights of Security Holders and Use of Proceeds
Item 15. Controls and Procedures
Item 16A. Audit Committee Financial Expert
Item 16B. Code of Ethics
Item 16C. Principal Accountant Fees and Services
Item 16D. Exemptions From The Listing Standards for Audit Committees
Item 16E. Purchases of Equity Securities By The Issuer and Affiliated Purchasers
Item 16F. Change in Registrant's Certifying Accountant
Item 16G. Corporate Governance
Item 16H. Mine Safety Disclosure
Part III
Item 17. Financial Statements
Item 18. Financial Statements
Item 19. Exhibits
Note 31 Provides Information About Class Actions and Other Material Legal Proceedings.
Note 31 Provides Further Detailed Information About Contingencies and Legal Proceedings.
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Petrobras Earnings 2018-12-31

PBR 20F Annual Report

Balance SheetIncome StatementCash Flow

20-F 1 d692671d20f.htm 20-F 20-F
Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 20-F

 

 

ANNUAL REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

for the fiscal year ended December 31, 2018

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)

Rafael Salvador Grisolia

Chief Financial Officer and Chief Investor Relations Officer

(55 21) 3224-4477—dfinri@petrobras.com.br

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

6.900% Global Notes due 2049, issued by PGF

6.850% Global Notes due 2115, issued by PGF

  

New York Stock Exchange

New York Stock Exchange

New York Stock Exchange

 

*

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

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

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

The number of outstanding shares of each class of stock as of December 31, 2018 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

TABLE OF CONTENTS

 

     Page  
Forward-Looking Statements      1  
Glossary of Certain Terms Used in this Annual Report      3  
Conversion Table      10  
Abbreviations      11  
Presentation of Financial and Other Information      13  
Presentation of Information Concerning Reserves      15  
  PART I   
Item 1.  

Identity of Directors, Senior Management and Advisers

     16  
Item 2.  

Offer Statistics and Expected Timetable

     16  
Item 3.  

Key Information

     16  
 

Selected Financial Data

     16  
 

Risk Factors

     19  
Item 4.  

Information on the Company

     37  
 

History and Development

     37  
 

Overview of the Group

     38  
 

2040 Strategic Plan and 2019-2023 Business Plan

     43  
 

Exploration and Production

     45  
 

Refining, Transportation and Marketing

     56  
 

Distribution

     63  
 

Gas and Power

     65  
 

Biofuels

     74  
 

Corporate

     75  
 

Property, Plant and Equipment

     76  
 

Regulation of the Oil and Gas Industry in Brazil

     77  
 

Health, Safety and Environmental Initiatives

     83  
 

Insurance

     85  
 

Additional Reserves and Production Information

     86  
Item 4A.  

Unresolved Staff Comments

     94  
Item 5.  

Operating and Financial Review and Prospects

     95  
 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     95  
 

Overview

     95  
 

Sales Volumes and Prices

     96  
 

Diesel and Gasoline

     96  
 

LPG

     97  
 

Tax Strategy and Effect of Taxes on Our Income

     98  
 

Inflation and Exchange Rate Variation

     98  
 

Results of Operations

     101  
 

Additional Business Segment Information

     110  
 

Liquidity and Capital Resources

     110  
 

Contractual Obligations

     117  
 

Critical Accounting Policies and Estimates

     117  
 

New Accounting Standards

     121  
 

Research and Development

     122  
 

Trends

     123  

 

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Table of Contents
Item 6.  

Directors, Senior Management and Employees

     124  
 

Directors and Senior Management

     124  
 

Compensation

     132  
 

Share Ownership

     133  
 

Fiscal Council

     133  
 

Audit Committee

     134  
 

Other Committees

     135  
 

Ombudsman

     137  
 

Employees and Labor Relations

     138  
Item 7.  

Major Shareholders and Related Party Transactions

     145  
 

Major Shareholders

     145  
 

Related Party Transactions

     146  
Item 8.  

Financial Information

     147  
 

Consolidated Statements and Other Financial Information

     147  
 

Legal Proceedings

     147  
 

Internal Investigations

     155  
 

Dividend Distribution

     155  
Item 9.  

The Offer and Listing

     156  
Item 10.  

Additional Information

     158  
 

Memorandum and Articles of Incorporation

     158  
 

Restrictions on Non Brazilian Holders

     168  
 

Transfer of Control

     168  
 

Disclosure of Shareholder Ownership

     168  
 

Material Contracts

     168  
 

Exchange Controls

     177  
 

Taxation Relating to Our ADSs and Common and Preferred Shares

     178  
 

Taxation Relating to PGF’s Notes

     186  
 

Documents on Display

     193  
Item 11.  

Qualitative and Quantitative Disclosures about Market Risk

     194  
Item 12.  

Description of Securities other than Equity Securities

     197  
 

American Depositary Shares

     197  
 

Fees Payable by holders of our ADSs

     197  
 

Fees Payable by the Depositary to Petrobras

     197  
PART II

 

Item 13.  

Defaults, Dividend Arrearages and Delinquencies

     198  
Item 14.  

Material Modifications to the Rights of Security Holders and Use of Proceeds

     198  
Item 15.  

Controls and Procedures

     198  
 

Disclosure Controls and Procedures

     198  
 

Management Report on Internal Control over Financial Reporting

     198  
 

Changes in Internal Control over Financial Reporting

     199  
Item 16A.  

Audit Committee Financial Expert

     199  
Item 16B.  

Code of Ethics

     199  
Item 16C.  

Accountant Fees and Services

     200  
 

Audit and Non Audit Fees

     200  
 

Audit Committee Approval Policies and Procedures

     201  

 

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Table of Contents
Item 16D.  

Exemptions from the Listing Standards for Audit Committees

     201  
Item 16E.  

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

     201  
Item 16F.  

Change in Registrant’s Certifying Accountant

     201  

Item 16G.

 

Corporate Governance

     201  
Item 16H.  

Mine Safety Disclosure

     203  
  PART III   
Item 17.  

Financial Statements

     204  
Item 18.  

Financial Statements

     204  
Item 19.  

Exhibits

     205  
Signatures      210  

 

 

iii


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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.

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 According to Our Plan Cost Assumptions, commitments and revenues;

 

   

our liquidity and sources of funding;

 

   

our pricing strategy and development of additional revenue sources; and

 

   

the impact, including cost, of acquisitions and divestments.

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

 

   

our ability to obtain financing;

 

   

general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates;

 

   

global economic conditions;

 

   

our ability to find, acquire or gain access to additional reserves and to develop our current reserves successfully;

 

   

uncertainties inherent in making estimates of our oil and gas reserves, including recently discovered oil and gas reserves;

 

   

competition;

 

   

technical difficulties in the operation of our equipment and the provision of our services;

 

   

changes in, or failure to comply with, laws or regulations, including with respect to fraudulent activity, corruption and bribery;

 

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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 Item 3. “Key Information—Risk Factors” 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, and our actual production, revenues and expenditures with respect to our reserves may materially differ from these estimates.

 

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Table of Contents

GLOSSARY OF CERTAIN TERMS USED IN THIS ANNUAL REPORT

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

 

ADR

  

American Depositary Receipt.

 

ADS

  

American Depositary Share.

 

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 regulate the oil, natural gas and renewable fuels industry in Brazil.

 

API

  

Standard measure of oil density developed by the American Petroleum Institute.

 

Assignment Agreement

  

An agreement under which the Brazilian federal government assigned to us the right to explore and produce up to 5 billion barrels of oil equivalent “bnboe”) in specified pre-salt areas in Brazil. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”

 

B3

  

The São Paulo Stock Exchange.

 

Bahiagás

  

Companhia de Gás da Bahia, the natural gas distribution company for the State of Bahia.

 

Banco do Brasil

  

Banco do Brasil S.A.

 

Bank of New York Mellon

  

The Bank of New York Mellon, which serves as depositary for both our common and preferred ADSs.

 

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.

 

Braskem

  

Braskem S.A.

 

Brent Crude Oil

  

A major trading classification of light crude oil that serves as a major benchmark price for commercialization of crude oil worldwide.

 

BNDES

  

The Banco Nacional de Desenvolvimento Econômico e Social (the Brazilian Development Bank).

 

 

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Câmara de Arbitragem do Mercado

  

An arbitration chamber governed and maintained by B3.

 

Capital Expenditures According to Our Plan Cost Assumptions

  

Capital expenditures based on the cost assumptions and financial methodology adopted in our business 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.

 

CDB

  

China Development Bank.

 

CEG Rio

  

Gas Natural Fenosa, the natural gas distribution company for the State of Rio de Janeiro.

 

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).

 

COSO

  

Committee of Sponsoring Organizations of the Treadway Commission.

 

COSO-ERM

  

Committee of Sponsoring Organizations of the Treadway Commission – Enterprise Risk Management Integrated Framework.

 

 

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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.

 

Distillation

  

A 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, for the primary purpose of supplying our domestic refineries.

 

Eletrobras

  

Centrais Elétricas Brasileiras S.A. – Eletrobras.

 

EWT

  

Extended well test.

 

Exploration area

  

A region under a regulatory contract without a known hydrocarbon accumulation or with a hydrocarbon accumulation that has not yet been declared commercial.

 

Fitch

  

Fitch Ratings Inc., a credit rating agency.

 

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

  

Gas Transboliviano S.A.

 

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).

 

IBGC

  

The Instituto Brasileiro de Governança Corporativa (Brazilian Institute of Corporate Governance).

 

 

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IOF

  

Imposto sobre Operações Financeiras (Brazilian taxes over financial transactions).

 

IPCA

  

The Índice Nacional de Preços ao Consumidor Amplo (National Consumer Price Index).

 

ISO

  

The International Organization for Standardization.

 

Lava Jato investigation

  

See Item 3. “Key Information—Risk Factors—Compliance, Legal and Regulatory Risks” and Item 8. “Financial Information—Legal Proceedings—Lava Jato Investigation.”

 

LFTs

  

Letras Financeiras do Tesouro (Brazilian federal government bonds).

 

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).

 

NGL

  

The liquid resulting from the processing of natural gas and containing the heavier gaseous hydrocarbons.

 

NYSE

  

The New York Stock Exchange.

 

NTS

  

Nova Transportadora do Sudeste S.A.

 

Oil

  

Crude oil, including NGLs and condensates.

 

Oil Products

  

Produced through processing at refineries such as diesel, gasoline, liquid fuel, LPG and other products.

 

ONS

  

The Operador Nacional do Sistema Elétrico (National Electric System Operator) of Brazil.

 

OPEC

  

Organization of the Petroleum Exporting Countries.

 

OSRL

  

The Oil Spill Response Limited.

 

PESA

  

Petrobras Argentina S.A.

 

 

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Petrochemicals

  

Chemicals obtained in petrochemical industries such as ethene, propene, benzene, xylenes, polypropylene, polyethylene and others.

 

Petros

  

Petrobras’ employee pension fund.

 

Petros 2

  

Petrobras’ sponsored pension plan.

 

PGF

  

Petrobras Global Finance B.V.

 

PifCo

  

Petrobras International Finance Company S.A.

 

PLSV

  

Pipe laying support vessel.

 

PO&G

  

Petrobras Oil & Gas B.V.

 

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 12 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.

 

 

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Proved developed reserves

  

Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

 

Proved undeveloped reserves

  

Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

 

PTAX

  

The reference exchange rate for the purchase and sale of U.S. dollars in Brazil, as published by the Brazilian Central Bank.

 

PwC

  

PricewaterhouseCoopers Auditores Independentes.

 

RNEST

  

The Refinaria Abreu e Lima (Abreu e Lima Refinery).

 

RTM

  

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.

 

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 Brazilian Central Bank base interest rate.

 

Sete Brasil

  

Sete Brasil Participações, S.A.

 

Suape Petrochemical Complex

  

The Complexo Industrial Petroquímica Suape, an industrial complex with facilities owned by Companhia Petroquímica de Pernambuco – PetroquímicaSuape and Companhia Integrada Têxtil de Pernambuco – Citepe.

 

Shell

  

Shell Brasil Petróleo Ltda.

 

 

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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.

 

TAG

  

Transportadora Associada de Gás S.A.

 

TCU

  

The Tribunal de Contas da União (Federal Auditor’s Office), or TCU, is an advisory body linked to the Brazilian Congress, responsible for assisting it in matters related to the supervision of the Brazilian government with respect to accounting, finance, budget, operational and public property (patrimônio público) matters.

 

TBG

  

Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (TBG).

 

Total

  

Total E&P do Brasil Ltda.

 

Total depth

  

Total depth of a well, including vertical distance through water and below the mudline.

 

Transfer of Rights Agreement

  

An agreement under which a concessionaire sells, assigns or transfers by any means, in whole or in part, indivisible rights and obligations provided for in the concession agreement to a new third-party concessionaire, provided that the new concessionaire meets technical, economic and legal requirements established by the ANP.

 

Transpetro

  

Petrobras Transporte S.A.

 

Ultra-deepwater

  

Over 1,500 meters (4,921 feet) deep.

 

YPFB

  

Yacimientos Petroliferos Fiscales Bolivianos.

 

 

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CONVERSION TABLE

 

1 acre

   =   

43,560 square feet

 

   =   

0.004047 km2

1 barrel

   =   

42 U.S. gallons

 

   =   

Approximately 0.13 t of oil

1 boe

   =   

1 barrel of crude oil equivalent

 

   =   

6,000 cf of natural gas

1 m3 of natural gas

   =   

35.315 cf

 

   =   

0.0059 boe

1 km

   =   

0.6214 miles

 

     

1 meter

   =   

3.2808 feet

 

     

1 t of crude oil

   =    1,000 kilograms of crude oil    =   

Approximately 7.5 barrels of crude oil (assuming an atmospheric pressure index gravity of 37°API)

 

 

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ABBREVIATIONS

 

bbl

  

Barrels

 

bcf

  

Billion cubic feet

 

bn

  

Billion (thousand million)

 

bnbbl

  

Billion barrels

 

bncf

  

Billion cubic feet

 

bnm3

  

Billion cubic meters

 

boe

  

Barrels of oil equivalent

 

bnboe

  

Billion barrels of oil equivalent

 

bbl/d

  

Barrels per day

 

cf

  

Cubic feet

 

GWh

  

One gigawatt of power supplied or demanded for one hour

 

km

  

Kilometer

 

km2

  

Square kilometers

 

m3

  

Cubic meter

 

mbbl

  

Thousand barrels

 

mbbl/d

  

Thousand barrels per day

 

mboe

  

Thousand barrels of oil equivalent

 

mboe/d

  

Thousand barrels of oil equivalent per day

 

mcf

  

Thousand cubic feet

 

mcf/d

  

Thousand cubic feet per day

 

mm3

  

Thousand cubic meters

 

mm3/d

  

Thousand cubic meters per day

 

mm3/y

  

Thousand cubic meter per year

 

mmbbl

  

Million barrels

 

 

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mmbbl/d

  

Million barrels per day

 

mmboe

  

Million barrels of oil equivalent

 

mmboe/d

  

Million barrels of oil equivalent per day

 

mmcf

  

Million cubic feet

 

mmcf/d

  

Million cubic feet per day

 

mmm3

  

Million cubic meters

 

mmm3/d

  

Million cubic meters per day

 

mmt

  

Million metric tons

 

mmt/y

  

Million metric tons per year

 

MW

  

Megawatts

 

MWavg

  

Amount of energy (in MWh) divided by the time (in hours) in which such energy is produced or consumed

 

MWh

  

One megawatt of power supplied or demanded for one hour

 

ppm

  

Parts per million

 

R$

  

Brazilian reais

 

t

  

Metric ton

 

Tcf

  

Trillion cubic feet

 

US$

  

United States dollars

 

/d

  

Per day

 

/y

  

Per year

 

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

This is the annual report of Petróleo Brasileiro S.A.—Petrobras, or 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.

We currently issue notes in the international capital markets through our wholly-owned finance subsidiary Petrobras Global Finance B.V., or PGF, a private company with limited liability incorporated under the law of The Netherlands. We fully and unconditionally guarantee the notes issued by PGF. In the past, we used our former wholly-owned subsidiary, Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes that we fully and unconditionally guaranteed. On December 29, 2014, PifCo merged into PGF, and PGF assumed PifCo’s obligations under all outstanding notes originally issued by PifCo (together with the notes issued by PGF, the “PGF notes”), which continue to benefit from our full and unconditional guarantee. PGF is not required to file periodic reports with the U.S. Securities and Exchange Commission, or SEC. See Note 37 to our audited consolidated financial statements.

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. Certain figures included in this annual report have been subject to rounding adjustments; accordingly, figures shown as totals in certain tables may not be an exact arithmetic aggregation of the figures that precede them.

Our audited consolidated financial statements as of and for each of the three years ended December 31, 2018, 2017 and 2016 and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with International Financial Reporting Standards, or IFRS, issued by the International Accounting Standards Board, or IASB. See Item 5. “Operating and Financial Review and Prospects” and Note 2 to our audited consolidated financial statements. We apply IFRS in our statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the CVM.

Our IFRS financial statements filed with the CVM are presented in reais, while the presentation currency of the audited consolidated financial statements included herein is the U.S. dollar. Our functional currency and that of all our Brazilian subsidiaries is the real. The functional currency of most of our other entities that operate internationally, such as PGF, is the U.S. dollar. As described more fully in Note 2.2 to our audited consolidated financial statements, the U.S. dollar amounts for the periods presented have been translated from the real amounts in accordance with the criteria set forth in IAS 21 – “The effects of changes in foreign exchange rates.” Based on IAS 21, we have translated all assets and liabilities into U.S. dollars at the exchange rate as of the date of the balance sheet, all accounts in the statement of income, other comprehensive income and statement of cash flows at the average rates prevailing during the corresponding year. Equity items are translated at the exchange rates prevailing at the dates of the transactions. All exchange differences arising from the translation are recognized as cumulative translation adjustments (CTA) within consolidated shareholders’ equity.

 

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Unless the context otherwise indicates:

 

   

data contained in this annual report regarding capital expenditures, investments and other expenditures during the corresponding year that were not derived from the audited consolidated financial statements have been translated from reais at the average rates prevailing during such corresponding year;

 

   

historical data contained in this annual report regarding balances of investments, commitments or other related expenditures that were not derived from the audited consolidated financial statements have been translated from reais at the period-end exchange rate;

 

   

forward-looking amounts, including estimated future capital expenditures and investments, have all been based on our 2019-2023 Business and Management Plan, as approved in December 2018 (“2019-2023 Business Plan”), and have been projected on a constant basis. Future calculations involving an assumed price of crude oil have been calculated using an average Brent crude oil price of US$66 per barrel for 2019, US$67 per barrel for 2020, US$72 per barrel for 2021, US$75 per barrel for 2022 and US$75 per barrel for 2023. In addition, in accordance with our 2019-2023 Business Plan, we have used an estimated average nominal exchange rate of R$3.6 to US$1.00 for 2019, R$3.6 to US$1.00 for 2020, R$3.7 for US$1.00 for 2021, R$3.7 to US$1.00 for 2022 and R$3.8 to US$1.00 for 2023. For further information on our 2019-2023 Business Plan, see Item 4. “Information on the Company—2040 Strategic Plan and 2019-2023 Business Plan,”; and

 

   

all reserve and production volumes described in this annual report include 100% of the reserves and production of our consolidated subsidiaries, our proportional participation in reserve volumes in joint operations (e.g. Brazilian consortia) and our percentage interest in the proved reserves and production of equity method investees (associates and joint ventures). For refining activities, the information presented in this document refers to total production, as we currently hold 100% of refining capacity.

 

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PRESENTATION OF INFORMATION CONCERNING RESERVES

We apply the SEC rules for estimating and disclosing oil and natural gas reserve quantities included in this annual report. In accordance with those rules, we estimate reserve volumes considering the 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 reserves in certain fields for which volumes have been 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.

DeGolyer and MacNaughton (D&M) used our reserve estimates to conduct a reserves evaluation of 96% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2018 in Brazil. The amount of reserves reviewed by D&M corresponds to 95% of our total proved reserves company-wide on a net equivalent basis. See Item 4. “Information on the Company—Additional Reserves and Production Information.” The reserve estimates were prepared in accordance with the reserves definitions in Rule 4-10(a) of Regulation S-X. All reserve estimates involve some degree of uncertainty. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations” for a description of the risks relating to our reserves and our reserve estimates.

On January 31, 2019, we filed proved reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 10.1 bnbbl of crude oil, condensate and synthetic oil and 10.4 tcf of natural gas and synthetic gas. The reserve estimates filed with the ANP were approximately 24.8% higher than those provided herein, which have been prepared in accordance with the definitions of Rule 4-10(a) of Regulation S-X, in terms of oil equivalent. This difference is due to: (i) the fact that the ANP permits the estimation of proved reserves through the technical-economical abandonment of production wells, as opposed to limiting reserve estimates to the life of the concession contracts as required by Rule 4-10 of Regulation S-X; and (ii) different technical criteria for booking proved reserves, including the use of our projected future oil prices as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.

 

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PART I

 

Item 1.

Identity of Directors, Senior Management and Advisers

Not applicable.

 

Item 2.

Offer Statistics and Expected Timetable

Not applicable.

 

Item 3.

Key Information

Selected Financial Data

This section contains selected consolidated financial data presented in U.S. dollars and prepared in accordance with IFRS as of and for each of the five years ended December 31, 2018, 2017, 2016, 2015, and 2014, derived from our audited consolidated financial statements. The selected consolidated financial data as of and for the years ended December 31, 2018 and 2017 was derived from our year-end financial statements audited by KPMG Auditores Independentes and the selected consolidated financial data as of and for the years ended December 31, 2016, 2015 and 2014 was derived from the respective year-end financial statements audited by PricewaterhouseCoopers Auditores Independentes (“PwC”).

The information below should be read in conjunction with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and Item 5. “Operating and Financial Review and Prospects.”

 

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STATEMENT OF FINANCIAL POSITION

Summary Financial Data

 

     As of December 31,  
     2018     2017     2016     2015     2014  
     (US$ million)  

Assets:

          

Cash and cash equivalents

     13,899       22,519       21,205       25,058       16,655  

Marketable securities

     1,083       1,885       784       780       9,323  

Trade and other receivables, net

     5,746       4,972       4,769       5,554       7,969  

Inventories

     8,987       8,489       8,475       7,441       11,466  

Assets classified as held for sale

     1,946       5,318       5,728       152       5  

Other current assets

     5,401       3,948       3,808       4,194       5,414  

Long-term receivables

     22,059       21,450       20,420       19,426       18,863  

Investments

     2,759       3,795       3,052       3,527       5,753  

Property, plant and equipment

     157,383       176,650       175,470       161,297       218,730  

Intangible assets

     2,805       2,340       3,272       3,092       4,509  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

     222,068       251,366       246,983       230,521       298,687  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities and equity:

          

Total current liabilities

     25,051       24,948       24,903       28,573       31,118  

Non-current liabilities(1)

     43,334       42,871       36,159       24,411       30,373  

Non-current finance debt(2)

     80,508       102,045       108,371       111,482       120,218  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

     148,893       169,864       169,433       164,466       181,709  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity

          

Share capital (net of share issuance costs)

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

Reserves and other comprehensive income (deficit)(3)

     (35,557     (27,299     (30,322     (41,865     9,171  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity attributable to the shareholders of Petrobras

     71,544       79,802       76,779       65,236       116,272  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Non-controlling interests

     1,631       1,700       771       819       706  

Total equity

     73,175       81,502       77,550       66,055       116,978  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and equity

     222,068       251,366       246,983       230,521       298,687  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Excludes non-current finance debt.

(2)

Excludes current portion of long-term finance debt.

(3)

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

 

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STATEMENT OF INCOME AND OTHER INFORMATION

Summary Financial Data

 

     For the Year Ended December 31,  
     2018(1)      2017(2)     2016(3)     2015(4)     2014(5)  
     (US$ million, except for share and per share data)  

Sales revenues

     95,584        88,827       81,405       97,314       143,657  

Net income (loss) before finance income (expense), results in equity-accounted investments and income taxes

     17,432        11,219       4,308       (1,130     (7,407

Net income (loss) attributable to the shareholders of Petrobras

     7,173        (91     (4,838     (8,450     (7,367

Weighted average number of shares outstanding:

           

Common

     7,442,454,142        7,442,454,142       7,442,454,142       7,442,454,142       7,442,454,142  

Preferred

     5,602,042,788        5,602,042,788       5,602,042,788       5,602,042,788       5,602,042,788  

Net income (loss) before finance income (expense), results in equity-accounted investments and income taxes per:

           

Common and Preferred shares

     1.34        0.86       0.33       (0.09     (0.57

Common and Preferred ADS

     2.68        1.72       0.66       (0.18     (1.14

Basic and diluted earnings (losses) per:

           

Common and Preferred shares

     0.55        (0.01     (0.37     (0.65     (0.56

Common and Preferred ADS

     1.10        (0.02     (0.74     (1.30     (1.12

Cash dividends per(6):

           

Common shares

     0.07        —         —         —         —    

Preferred shares

     0.24        —         —         —         —    

Common ADS

     0.14        —         —         —         —    

Preferred ADS

     0.48        —         —         —         —    

 

(1)

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.

(2)

In 2017, we recognized US$3,449 as other income and expenses, due to the provision for legal proceedings relating to the agreement to settle the Consolidated Securities Class Action as defined in Item 8. “Financial Information–Legal Proceedings–Class Action” before the United States District Court for the Southern District of New York. We also recognized impairment losses of US$1,191 million.

(3)

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

(4)

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

(5)

In 2014, we recognized impairment losses of US$16,823 million.

(6)

Pre-tax interest on capital and/or dividends proposed for the year. Amounts were based on the exchange rate prevailing at the date of the approval, except for the complement of minimum mandatory dividends, based on the closing exchange rate at the date of release of our audited consolidated financial statements.

 

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RISK FACTORS

Risks Relating to Our Strategy

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, operated by us or our partners, 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), 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 and administrative lawsuits. As a consequence, we may incur expenses to repair or remediate damages caused. Further, we may face difficulties in obtaining or maintaining operating licenses and may suffer damages to our reputation.

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. 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, our pricing policy for diesel and gasoline allows for price readjustments at any time, also on a daily basis for gasoline, and by periods of not less than 15 days for diesel. Since one of the goals of our new pricing policy is to maintain fuel prices in parity with international market trends, substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition, and may also affect the value of our proved reserves.

In the past, our pricing policy has been adjusted from time to time by our management. We cannot guarantee that our pricing policy will not change in the future. In previous periods, we have not always adjusted our prices to reflect parity with the international market trends or reflect exchange rate volatility. In the event that our pricing policy 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 product prices. Any of such changes in our policy may have a material adverse effect on our businesses, results of operations and financial condition.

Illegal taps (thefts) of oil and oil products may, temporarily or permanently, generate accidents, leaks or damage in our facilities, impacting the continuation of our operations.

In recent months, we suffered a significant increase in acts of intentional interference by third parties in our pipelines, including illegal taps of oil, gas and oil products, especially in the states of São Paulo and Rio de Janeiro. In addition to financial losses, these occurrences present a risk to people, facilities and the environment near these pipelines and us. In 2018, we reported 228 occurrences of illegal taps to Brazilian authorities. In case of new occurrences, we may become involved in accidents, such as explosions or oil and oil products spills, resulting in fatalities, damages to the environment or interruptions of our operations. In addition, we may face fines and sanctions imposed by environmental and regulatory agencies for the damages resulting from acts of intentional interference by third parties. As a consequence of illegal taps, we may also be compelled to indemnify for any damages caused to the environment or to third parties.

 

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

We are currently party to numerous legal 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 of operations and financial condition.

We may also be subject to litigation and administrative proceedings in connection with our concessions and other government authorizations, which could result in the revocation of such concessions and government authorizations. In addition, 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. Depending on the outcome, litigation could result in restrictions on our operations and have a material adverse effect on some of our businesses.

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 of operations and financial condition.

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. We may ultimately need to postpone one or more of our projects, which may have an adverse effect on our results of operations and financial condition. In addition, we are subject to minimum local content requirements in some of our concession agreements, in the Assignment Agreement and in the Production Sharing Agreements. Even taking into account the flexibility in certain of our projects, we may not meet the minimum percentages of local content required in those agreements and, as a result, 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.

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.

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

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 rates, and financing conditions of projects that may jeopardize our expected rate of return on these projects.

 

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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.

In addition, we are not immune to potential risks arising from problems in contracting goods and services and in relationships with suppliers, partners, governments and local representatives. All of these factors could result in delays, which may negatively impact our business and results of operation.

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

Pursuant to our 2019-2023 Business Plan, we expect to develop partnerships and divest of assets totaling up to US$26.9 billion by 2023. 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 of operations and financial condition, including by potentially exposing us to short and medium-term liquidity constraints. In addition, the sale of strategic assets may result in a decrease in our cash flows from operations, which could negatively impact our long-term operating growth prospects and consequently our results of operations in the medium and long-term.

Climate change could impact our operating 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 operating and financial results and limiting some of our growth opportunities.

Water scarcity in some regions where we operate may generate unavailability (temporary or permanent) 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 455 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.

 

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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.

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 have our activities guided by the Brazilian federal government to contribute to the public interest, and, as a result, we may make investments, incur costs and engage in transactions with parties or on terms that may have an adverse effect on our results of operations and financial condition.

In December 2017, we included the definition of public interest in our bylaws, as required by Brazilian law. We also stated in our bylaws that the Brazilian federal government may direct our activities to pursue the public interest under certain circumstances, which distinguishes us from any other private company, including oil and gas companies. More specifically, the Brazilian federal government may direct us to assume obligations or responsibilities that contribute to the public interest, including the execution of investment projects and the incurrence of certain operating costs, if certain conditions are met. First, the obligations or responsibilities must be clearly defined by law or regulation and established in a contract or agreement with the competent public authority. Second, the investment projects must have their costs and revenues disclosed in a transparent manner.

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 of operations may be adversely affected by the following factors and the response of the Brazilian federal government to these factors:

 

   

exchange rate movements and volatility;

 

   

inflation;

 

   

financing of government fiscal deficits;

 

   

price instability;

 

   

interest rates;

 

   

liquidity of domestic capital and lending markets;

 

   

tax policy;

 

   

regulatory policy for the oil and gas industry, including pricing policy and local content requirements;

 

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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.

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 of operations and financial condition.

Risks Relating to Our Operations

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 operational incident causing an interruption of our business could have a material adverse effect on our results of operations 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 of operations. 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. See Item 4. “Information on the Company—Health, Safety and Environmental Initiatives” and “—Insurance.”

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

Disagreements about how we manage our business, in particular divestments and their implications for our personnel, changes in our business 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 (CGPAR resolutions No. 22 and 23) 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 successfully 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 of operations and our business.

 

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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.

As part of our policy, we respect human rights and we 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.

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 heavily dependent on information technology and telecommunication systems and services. Interruptions in these systems, caused by obsolescence, technical failures or intentional acts, can disrupt or even paralyze our business and adversely impact our operations and reputation. In addition, security failures related to sensitive information due to intentional or unintentional actions, such as cyberterrorism, or internal actions, including negligence or misconduct of our employees, may have a negative impact on our reputation, our relationship with external entities (government, regulators, partners and suppliers, among others), our strategic positioning with relation to our competitors, and our results, due to the leakage of information or unauthorized use of such information.

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 of operations.

We have incurred a substantial amount of debt in order to finance the capital expenditures needed to meet our long term objectives, of which 43%, or US$58 billion (including interest), will mature in the next five years. Since there may be liquidity restrictions on the debt market to finance our planned investments and the 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 of operations and the ability to fulfill our 2019-2023 Plan.

 

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Between 2015 and mid-2016, we lost our investment grade ratings. Our Moody’s, S&P and Fitch ratings have fluctuated substantially over the past three years. The loss of our investment grade credit rating and any further lowering of our credit ratings has had, and may continue to have, adverse consequences on our ability to obtain financing in the market for our debt and 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 of operations and financial condition. For further information on our rating, see Item 5 “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Rating.”

In addition, despite the fact that the Brazilian federal government (as our controlling shareholder) is not responsible or liable for any of our liabilities, any further lowering of the Brazilian federal government’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 of operations and financial condition.

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

As of December 31, 2018, 81% of our financial debt was denominated in currencies other than the real (74% was denominated in U.S. dollars). 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, unless we increase the prices of our products to reflect the depreciation of the real, our cash generation relative to our capacity to service debt may decline.

Additionally, we have a substantial amount of debt maturing during the next five years, a portion of which may be refinanced by issuing new debt. To the extent we refinance our maturing obligations with newly contracted debt, we may incur additional interest expense.

As of December 31, 2018, approximately 50% 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 additional expenses. Additionally, 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 of operations and financial condition.

 

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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 predicted value and the actual realized value. In addition, the financial assets held by Fundação 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.

These risks may result in an increase in our liabilities and adversely affect our results of operations and our business.

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 of operations 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 financial results and 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 flows from operations and may also reduce or curtail our customers’ future demand for our products and services, which may have an adverse effect on our results of operations 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 of operations and financial condition.

In the past, some of our senior managers and contractors have engaged in fraudulent activities incompatible with our ethics and compliance standards. Although we have adopted measures to identify, monitor, mitigate and remediate such actions, 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.

 

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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 of operations and financial condition.

Although our management has concluded that our internal control over financial reporting was effective as of December 31, 2018, we are subject to the risk that our 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.

Our management has concluded that our internal control over financial reporting was effective as of December 31, 2018. However, because of its inherent limitations, 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 and cannot be sure that in the future significant deficiencies will not exist or will be identified in a timely manner. Any of these occurrences may adversely affect our business and operation, and may generate negative market reactions, potentially leading to a decline in the price of our shares, ADSs and debt securities.

Any violation of the agreements that resolved the investigations conducted by the SEC and the DoJ and potential future investigations regarding the possibility of non-compliance 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 November 2014, we received a subpoena from the SEC requesting certain documents and information about us relating to, among other things, the Lava Jato investigation and any allegations regarding a violation of the U.S. Foreign Corrupt Practices Act (“FCPA”). The DoJ conducted a similar inquiry.

On September 27, 2018, we announced the settlement of the SEC and DoJ investigations related to our internal controls, accounting records and financial statements for the period of 2003 to 2012. Pursuant to the non-prosecution agreement (“NPA”) with the DoJ, we admitted that certain of our former executives and officers took action 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 violations 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 SEC. Under the terms of the agreements, Petrobras paid in the United States US$85.3 million to the DoJ and paid US$85.3 million to the SEC. In addition, the agreements credited Petrobras’s remittance of US$682.6 million to the Brazilian authorities, which were deposited by Petrobras on January 30, 2019 and will be used under the terms of an agreement signed with the Federal Prosecution Office of Brazil (MPF). The SEC also credited the payments Petrobras 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.

 

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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 FCPA.

The Lava Jato investigation is still in progress by Brazilian authorities and additional relevant information affecting Petrobras’ interests may come to light.

Such adverse developments 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.

Our methodology to estimate the overpayments incorrectly capitalized, uncovered in the context of the Lava Jato investigation, involves some degree of uncertainty. If substantive additional information comes to light in the future that would make our estimate for the overstatements of our assets appear, in retrospect, to have been materially underestimated or overestimated, this could require a restatement of our financial statements and may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.

As a result of the findings of the Lava Jato investigation, in the third quarter of 2014, we wrote off US$2,527 million of capitalized costs representing amounts that we overpaid for the acquisition of property, plant and equipment in prior years.

We concluded that a portion of our costs incurred to build property, plant and equipment that resulted from contractors and suppliers in the cartel overcharging us to make improper payments should not have been capitalized in our historical costs of property, plant and equipment. As it is impracticable to identify the specific periods and amounts for the overpayments made by us, we considered all the available information to determine the impact of the overpayments charged to us. As a result, to account for these overpayments, we developed a methodology to estimate the aggregate amount that we overpaid under the payment scheme, in order to determine the amount of the write off representing the overstatement of our assets resulting from overpayments used to fund improper payments.

The Lava Jato investigation is still ongoing and it could be a significant amount of time before the Brazilian federal prosecutors conclude their investigation. As a result of this investigation, substantive additional information might come to light in the future that would make our estimate for overpayments appear, in retrospect, to have been materially low or high, which may require us 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 the year ended December 31, 2014.

We believe that we have used the most appropriate methodology and assumptions to determine the amounts of overpayments incorrectly capitalized based on the information available to us, but our estimation methodology involves some degree of uncertainty. There can be no assurance that the write offs representing the overstatement of our assets, determined using our estimation methodology, and recognized in our audited consolidated financial statements for the year ended December 31, 2014, are not underestimated or overestimated. In the event that we are required to write off additional historical costs from our property, plant and equipment or to reverse write offs previously recognized in our financial statements, this might impact the total value of our assets and we may be subject to negative publicity, credit rating downgrades, or other negative material events, which may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.

 

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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”). See Item 8. “Financial Information—Legal Proceedings” and Note 31.4 to our audited consolidated financial statements for a description of the U.S. securities class action litigation and other civil proceedings. As detailed in Item 8. “Financial Information—Legal Proceedings” and Note 31.4 to our audited consolidated financial statements, 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 2017, we provisioned US$3,449 million to reflect the settlement reached in the Consolidated Securities Class Action (including expected withholding taxes). We also provisioned US$456 million to reflect settled Individual Actions and pending Individual Actions in advanced stages of negotiations, of which US$8 million was provisioned in 2018, US$76 million in 2017 and US$372 million in 2016 .

The settlement of the Consolidated Securities Class Action eliminates the risk of an unfavorable judgment, which, as previously reported by us, could have a material adverse effect on us and our financial situation, as well as eliminate uncertainties, burdens and costs associated with the continuation of this dispute.

On March 1, 2018, Petrobras and PGF disbursed the first US$983 million installment of the Class Action Settlement into an escrow account designated by the lead plaintiff and accounted for it as other current assets. The second installment of US$983 million was deposited on July 2, 2018, 10 days after the final approval of the Class Action Settlement, and Petrobras accounted for it as other current assets. The third installment of US$984 million was deposited by January 15, 2019. Foreign exchange losses on the provision amounted to US$452 million and were accounted for as other expenses.

Certain objectors have appealed the SDNY’s final decision to approve the Class Action Settlement, and one such appeal remains pending. In the event that a higher court annuls the agreement, or if the agreement does not become final for other reasons, we will return to our position prior to the settlement of the Consolidated Securities Class Action and, depending on the outcome of the subsequent litigation, we might be required to pay substantial amounts, which could have a material adverse effect on our financial condition, its consolidated results of operations or its consolidated cash flows for an individual reporting period.

Individuals are seeking measures against us in Brazil to annul and/or suspend the settlement of the Consolidated Securities Class Action. No adverse decision has been rendered to date against the settlement.

We are also currently party to a class action commenced in the Netherlands, to an arbitration proceeding in Argentina, and to 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) that purchased our shares traded in B3 or other securities issued by us outside of the United States, alleging damages caused by facts uncovered in the Lava Jato investigations.

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 (“DC Court”). 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.

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

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 of operations.

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 of operations. Any future differences in interpretation between us and these regulatory agencies may materially impact our results of operations, since such interpretations directly affect the economic and technical assumptions that guide our investment decisions.

The Assignment Agreement we entered into with the Brazilian federal government is a related party transaction subject to future price revision.

We entered into an Assignment Agreement in 2010 with the Brazilian federal government, our controlling shareholder, to obtain oil and gas exploration and production rights for specific pre-salt areas, subject to a maximum production of five billion boe. At the time the Assignment Agreement was negotiated, the initial contract price paid by us was based on an assumed Brent oil crude price of approximately US$80 per barrel. However, the Assignment Agreement includes provisions for a subsequent revision of certain of its terms, including the price we paid for the rights we acquired, maximum volume, maturity and local content percentages.

Negotiations with the Brazilian federal government to revise the Assignment Agreement began in December 2013, and are still ongoing. Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if the revised contract price is higher than the initial contract price, we will either make an additional payment to the Brazilian federal government or reduce the amount of barrels of oil equivalent subject to the Assignment Agreement.

 

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We do not know when this negotiation will be completed, nor can we assure that the terms of this new agreement would be favorable to us, which could negatively impact our operating and financial results.

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.

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 require us to incur 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 or reduction in strategic investments and significant decreases in our production from unplanned shutdowns may have a material adverse effect on our results of operations and financial condition.

We may be required by law 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, and public and 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

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 of operations 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 and lower projected economic growth in Brazil, 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.

 

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Future developments in the economic environment, in the oil and gas industry and other factors could result in further substantial impairment charges, adversely affecting our operating results and financial condition.

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. 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 concessions and to explore existing concessions.

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 uncertainties and contingencies that are beyond our control. 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 the certification companies. Downward revisions in our reserve estimates could lead to lower future production, which could have an adverse effect on our results of operations 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.

 

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Many of our projects and operations are conducted in joint arrangements which may not perform as expected, negatively impacting our results.

Our partners or members of joint arrangements to which we are a party may not be able to meet their financial or other obligations, which may threaten the viability of certain projects in which we are engaged. Where we are the operator of joint arrangements, the other partner(s) may be able to veto or block certain decisions, which may also affect the viability of certain projects. Even when we are not operating the project, we may be exposed to the risks associated with these operations, including reputational, litigation (where joint and several liability could apply, in relation to the ANP, in the case of a concession agreement, and in relation to ANP and third parties, in the case of a production sharing regime) and government sanction risks, which could have a material adverse effect on our operations, 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 operating 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 operating results and financial resources.

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 maintaining 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. Digital technologies are already a relevant part of our processes and operations. Recent advances in data acquisition and analysis, connectivity, artificial intelligence, robotics and other technologies are changing the sources that create competitive advantage. Failure to capture these opportunities may have an impact on our competitiveness in the oil and gas market and our long term objectives.

Market fluctuations, related to political instability, acts of terrorism, armed conflict and war in various regions of the world, may have a material adverse effect on our business.

Geopolitical risk factors have recently become more prominent in the world. Events such as the increasing tension between the U.S. and other countries, the escalation of the conflict in Syria, the terrorist attacks and political movements in Europe indicate the growing possibility that new events may occur that affect, directly or indirectly, markets related to the oil industry, which could negatively impact our business and result in substantial losses.

 

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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.

Risks Relating to Brazil and Our Relationship with the Brazilian Federal Government

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.

Our planned investment budget is subject to approval by the Brazilian federal government, and failure to obtain approval of our planned investments may adversely affect our operations and financial condition.

As a federal state-owned company, we are subject to certain rules that limit our investments, and we must submit our proposed annual budget to the ME (former MPDM) and MME. Following review by these governmental authorities, the Brazilian Congress must approve our annual budget. Our approved budget may reduce or alter our proposed investments. As a result, we may not be able to make all the investments we envision, including those intended to expand and develop our crude oil and natural gas fields, which may adversely affect our results of operations and financial condition.

Risks Relating to Our Equity and Debt Securities

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

 

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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 New York Stock Exchange and the Luxembourg Stock Exchange and trade on the NYSE Euronext and Euro MTF (Multilateral Trading Facility) 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.

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, The Bank of New York Mellon, 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 Item 10. “Additional Information—Memorandum and Articles of Incorporation—Preemptive Rights.”

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 Annex I of CMN Resolution No. 4,373, who will be in charge for keeping and updating the investors’ certificates of registrations with the Central Bank of Brazil, which entitles registered foreign investors to buy and sell directly on the B3. Such arrangements may require additional expenses from the foreign investor. Moreover, if such representatives fail to obtain or update the relevant certificates of registration, investors may incur in additional expenses or be subject to operational delays which could affect their ability to receive dividends or distributions relating to the common or preferred shares or the return of their capital in a timely manner.

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

 

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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 US, and under Brazilian law, shareholders in Brazilian companies do not have standing to bring a class action, and under our by-laws must, generally with respect to disputes concerning rules regarding the operation of the capital markets, arbitrate any such disputes. See Item 10. “Additional Information—Memorandum and Articles of Incorporation—Dispute Resolution.”

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 law and our bylaws, holders of preferred shares do not have the right to vote in shareholders’ meetings. This means, among other things, that holders of ADSs representing preferred shares are not entitled to vote on important corporate transactions or decisions. See Item 10. “Additional Information—Memorandum and Articles of Incorporation—Voting Rights.”

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.

 

Item 4.

Information on the Company

History and Development

Petróleo Brasileiro S.A.—Petrobras was incorporated in 1953 as the exclusive agent to conduct the Brazilian federal government’s hydrocarbon activities. We began operations in 1954 and since then we have been carrying out crude oil and natural gas production and refining activities in Brazil on behalf of the government. As of December 31, 2018, the Brazilian federal government owned 28.67% of our outstanding capital stock and 50.26% of our voting shares. See Item 7. “Major Shareholders and Related Party Transactions—Major Shareholders.” Our common and preferred shares have been traded on the B3 since 1968 and on the NYSE in the form of ADSs since 2000.

We lost our exclusive right to carry out oil and gas activities in Brazil when the Brazilian Congress amended the Brazilian Constitution, and subsequently passed Law No. 9,478/1997 in 1997. Enacted as part of a comprehensive reform of the oil and gas regulatory system, this law authorized the Brazilian federal government to contract with any state or privately-owned company to carry out all activities related to oil, natural gas and their respective products. This new law established a concession-based regulatory framework, ended our exclusive right to carry out oil and gas activities, and allowed open competition in all aspects of the oil and gas industry in Brazil. The law also created an independent regulatory agency, the ANP, to regulate the oil, natural gas and renewable fuel industry in Brazil and to create a competitive environment in the oil and gas sector. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”

 

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Following the discovery of large pre-salt reservoirs in offshore Brazil, Congress passed additional laws in 2010 intended to regulate exploration and production activities in the pre-salt area, as well as other potentially strategic areas not already under concession. Under these new laws, we acquired from the Brazilian federal government through an Assignment Agreement the right to explore and produce up to five bnboe of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas. Additionally, on December 2, 2013, based on these laws enacted in 2010, we executed our first agreement with the Brazilian federal government under a production sharing regime for the Libra field. On November 29, 2016, Law No. 13,365/2016 was enacted, which no longer requires us to be the operator in this area, but provides us with a right of first refusal to do so. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil,” Item 10. “Additional Information—Material Contracts—Assignment Agreement” and Item 10. “Additional Information—Material Contracts—Production Sharing Agreements.”

We operate through subsidiaries, joint ventures, joint operations, consolidated structured entities and associates established in Brazil and many other countries. Our principal executive office is located at Avenida República do Chile 65, 20031-912 Rio de Janeiro, RJ, Brazil and our website is www.petrobras.com.br. The information on our 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.

Overview of the Group

Business Segments

We are a publicly-held company operating on an integrated basis and specializing in the oil, natural gas and energy industry. We are one of the world’s largest integrated oil and gas companies, operating principally in Brazil where we are the dominant participant. Our business segments operate year-round.

We are world-renowned for our ultra-deepwater oil exploration technology. Our business however goes beyond reaching the field and lifting out the oil and gas. 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.

As a result of our legacy as Brazil’s former sole producer and supplier of crude oil and oil products and our strong and continuous commitment to find and develop oil fields in Brazil, we have a large base of proved reserves and operate and produce most of Brazil’s oil and gas production. In 2018, our average domestic daily oil production was 2,035 mmbbl/d, which represents 79% of Brazil’s total oil production. Most of our domestic proved reserves are located in the adjacent offshore Campos and Santos Basins in southeast Brazil. Their proximity allows us to optimize our infrastructure and limit our costs of development and production for our new discoveries. Additionally, we have developed special expertise in deepwater exploration and production from 48 years of developing Brazil’s offshore basins. We are applying the technical expertise we gained through developing the Campos Basin to the Santos Basin, which is expected to be the principal source of our future growth in proved reserves and oil production.

As of December 31, 2018, we had proved developed oil and gas reserves of 5,146.4 mmboe and proved undeveloped reserves of 4,326.4 mmboe in Brazil. The development of this large reserve base and the exploration of pre-salt areas have demanded, and will continue to demand, significant investments and the growth of our operations.

 

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We operate most of the refining capacity in Brazil. Our refining capacity is substantially concentrated in southeastern 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. Our current domestic crude distillation capacity is 2,176 mbbl/d and our domestic refining throughput in 2018 was 1,715mbbl/d. We meet our demand for oil products through a planned combination of domestic refining of crude oil and oil products imports, seeking margin maximization. We are also involved in the production of petrochemicals through stakes in various companies. We distribute oil products through our own retail network and through wholesalers.

We participate in most aspects of the Brazilian natural gas market, including the logistics and processing of natural gas. To meet our domestic demand, we process natural gas derived from our onshore and offshore (mainly from fields in the Campos, Espírito Santo and Santos Basins) production, import natural gas from Bolivia, and to the extent necessary, import 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.

Outside Brazil, we maintain activities in 10 countries. In Latin America, our operations extend from exploration and production to marketing, retail services and natural gas. In North America, we produce oil and gas through a joint venture and until January 2019, had have refining operations in the United States. In Africa, through a joint venture, we produce oil in Nigeria. We have controlled companies in London, Rotterdam, Houston and Singapore that support our trade and financial activities. They comprise a complete and active Petrobras trading desk for markets worldwide, and are in charge of market intelligence and marketing of oil, oil products, natural gas, derivatives, shipping and vessel operation.

In 2018, our total production of oil and gas, including NGL, was 2.63 mmboe/d. Our total proved reserves totaled 9,606.2 million boe in the end of 2018.

Comprehensive information and tables on reserves and production is presented at the end of Item 4. See “Information on the Company—Additional Reserves and Production Information.”

Our activities are currently organized into five business segments:

 

   

Exploration and Production (“E&P”): this segment covers the activities of exploration, development and production of crude oil, NGL (natural gas liquid) 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 foreign entities operating in this segment;

 

   

Refining, Transportation and Marketing (“RTM”): this segment 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;

 

   

Gas and Power: this segment covers the activities of logistics and trading of natural gas and electricity, transportation and trading of LNG (liquefied natural gas), generation of electricity by means of thermoelectric power plants, as well as holding interests in transporters and distributors of natural gas in Brazil and abroad. It also includes fertilizer operations;

 

   

Distribution: this segment covers the activities of Petrobras Distribuidora S.A., which sells oil products, including gasoline and diesel, ethanol and vehicle natural gas in Brazil. This segment also includes distribution of oil products operations abroad (South America);

 

   

Biofuel: this segment covers the activities of production of biodiesel and its co-products, as well as ethanol-related activities through interest in entities producing and trading ethanol, sugar and surplus electric power generated from sugarcane bagasse.

 

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Additionally, we have a corporate segment that has activities that are not attributed to the other segments, notably those related to corporate financial management, corporate overhead and other expenses, provision for the class action settlement, actuarial expenses related to the pension and medical benefits for retired employees and their dependents. For further information regarding our business segments, see Notes 4.2 and 30 to our audited consolidated financial statements.

The following table sets forth key information for each business segment in 2018:

 

     Key Information by Business Segment, 2018  
     Exploration
and
Production
     Refining,
Transportation
and Marketing
     Gas
and
Power
     Biofuel      Distribution      Corporate      Eliminations     Group
Total
 
     (US$ million)  

Sales revenues

     52,382        73,448        12,269        255        27,960        —          (70,730     95,584  

Income (loss) before income taxes

     18,421        3,362        874        3        722        10,514        (770     12,098  

Total assets at December 31

     132,313        44,083        15,609        216        5,140        28,168        (3,461     222,068  

Capital Expenditures According to Our Plan Cost Assumptions

     11,592        1,107        433        16        136        155        —         13,439  

Portfolio Management

Our active portfolio management, part of our 2019-2023 Business Plan, is the key driver to our partnerships and divestments, which aim to improve our operating efficiencies and returns on capital, and generate additional cash to service our debt and our investment opportunities. Currently, our partnerships and divestments comprise the sale of minority, majority or entire positions in certain of our subsidiaries, associates, and assets to strategic or financial investors or through public offerings.

In 2018 and in the beginning of 2019, we completed, among others, the following partnerships and divestments.

 

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Signing Date

  

Closing Date

  

Transaction

  

Transaction
Nominal
Value*
(US$billion)

02/28/2017

   01/12/2018    Strategic Partnership between Petrobras and Total, including the assignment of 22.5% Petrobras’ interests in the Iara area, and the assignment of 35% Petrobras interests of Lapa Field in Block BM-S-9, to Total. There are other aspects of the Strategic Partnership which are subject to compliance with contractual and legal conditions precedent.    2.2**

02/16/2018

   02/21/2018    Sale of the total amount of our shares in São Martinho S.A (6.593%).    0.14

11/22/2017

   04/30/2018    Assignment of Azulão Gasfield    0.06
        

 

28/12/2016

   04/30/2018    Sale of Companhia Petroquímica de Pernambuco (“PetroquímicaSuape”) and Companhia Integrada Têxtil de Pernambuco (“Citepe”)    0.44

12/18/2017

   06/14/2018    Strategic Partnership with Equinor (formerly Statoil) which includes: (i) assignment of 25% of Petrobras’ interest in the Roncador field to Equinor; (ii) strategic technical alliance agreement for technical cooperation aiming at maximizing recovery factor; (iii) subject to regulatory requirements, an option for Equinor to hire a certain processing capacity of natural gas at the Cabiúnas Terminal (TECAB).    2.9
        

 

10/10/2016

   11/30/2018    Partnership with Murphy Exploration & Production Company (“Murphy”) in order to establish a joint venture company (“JV”), of which Murphy has 80% stake and Petrobras America Inc. (“PAI”) 20% stake, with the contribution from both companies of all of their producing oil and natural gas assets located in the Gulf of Mexico.    1.1***
        

 

06/27/2018

   03/08/2019    Full sale of our stake in Petrobras Paraguay Distribución Limited (PPDL UK), Petrobras Paraguay Operaciones y Logistics SRL (PPOL) and Petrobras Paraguay Gas SRL (PPG).    0.38
        

 

Total

   7,2
  

 

 

*

Considering amounts received and future payments related to the transaction.

**

This amount includes the payment related to the sale of Lapa and Iara in the amount of US$1.95 billion, as well as a credit line, which may be activated by us in the amount of US$400 million, and contingent payment of US$150 million, associated with the volume of production in the Lapa field.

***

This amount is comprised of US$900 million to be paid at the closing day (reflecting the price adjustments, the amount received was US$795 million), in addition to contingent payments of up to US$150 million and an investment charge of up to US$50 million of costs for the development of the field of St. Malo, to be performed by Murphy.

In 2018 and early 2019, we received proceeds from the sale of assets amounting to US$6.5 billion, which includes US$250 million relating to the distribution of dividends from PO&G BV to Petrobras. The proceeds resulted mainly from the (i) strategic alliance with Equinor (formerly Statoil) including assignments of rights in the Roncador field, (ii) strategic alliance with Total including assignment of rights in the Iara and Lapa Oilfields and (iii) formation of a joint venture between Petrobras America Inc (“PAI”) and Murphy Exploration & Production Company (“Murphy”).

 

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In addition, in 2018 and in the beginning of 2019, we have signed agreements in transactions that are currently pending closing. Completion of such transactions is subject to compliance with certain contractual and legal conditions precedent.

 

Signing Date   

Transaction

   Transaction
Nominal
Value*
(US$
billion)
 
10/31/2018   

Sale of our entire 50% interest in PO&G.

     1.53  
11/28/2018   

Sale of our stake in the fields of Pargo, Carapeba and Vermelho, the so-called “Polo Nordeste,” located in shallow waters off the coast of Rio de Janeiro state.

     0.37  
12/21/2018   

Assignment of 10% rights from the Lapa field to Total, in Block BM-S-9. Exercise of the option to sell the remainder of our interest, as provided for in the agreement signed in January 2018, when Total acquired a 35% stake in Petrobras, within the scope of the strategic partnership.

     0.05  
1/30/2019   

Sale of all of the shares held by Petrobras America Inc (PAI) in the companies that encompass Pasadena’s entire refining operations system in the United States.

     0,56  
03/08/2019   

Sale of our full stake in the Maromba field

     0.09  

Total

     2.6  
  

 

 

 

 

*

Considering amounts to be received at the closing of the transaction and subsequent payments.

Regarding the sale of Liquigás Distribuidora S.A. (Liquigás), the court of the Administrative Council for Economic Defense (“CADE”) did not approve the purchase of Liquigás by Companhia Ultragaz S.A. CADE’s decision triggered the termination of Liquigás sale contract, which required Companhia Ultragaz S.A. to pay us a fine in the total amount of US$ 88 million. The payment was made on March 13, 2018. We are currently analyzing alternatives for the divestment of Liquigás.

Our partnership and divestment processes are subject to continuous Brazilian judicial scrutiny. In 2018 and early 2019, various ongoing bidding processes for the sale of our assets were subject to preliminary injunctions, which were later suspended due to reviews by the Brazilian courts. For more information on judicial proceedings related to our divestments, see Item 8. “Financial Information—Legal Proceedings—Legal Proceedings and Preliminary Procedure on TCU—Divestments.”

Restructuring and Contracting Initiatives

In 2017, our board of directors approved changes in the organizational structure of our operational units, following the organizational changes implemented in the non-operational units started in 2016. We expect the approved changes to result in a reduction of 11% of all management positions in operational areas until 2021. In addition, we expect these changes in the organizational structure to lead to cost savings around US$9.21 million per year after 2021, when the final structure shall be entirely implemented.

The initiative to implement such changes had the purpose of aligning our organizational structure with our current business environment and with the current oil and gas sector. As part of the initiative, we also focused on maximizing efficiency, maintaining operational continuity and integrity of our facilities, and capturing gains through the implementation of lean and agile structures.

Some examples of the changes implemented are the redistribution of production’s fields among E&P’s operational units, the strengthening of our organizational structure for the management of reservoirs and a significant reduction of the various management positions of our refiner.

 

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Law No. 13,303 of June 30, 2016 (“Law No. 13,303/16”) introduced new bidding and contracting procedures. In compliance with Article 40 of Law No. 13,303/16, the new bid and contract regulation (RLCP) was published on January 15, 2018, at Brazilian Federal Register (Diário Oficial da União—DOU). The RLCP entered into force on the date of its publication, having progressive effects per organizational unit, under the terms of the implementation schedule, and was fully implemented to us by May 15, 2018, before the deadline provided for by Law No. 13,303/16 (i.e., June 30, 2018).

Social Responsibility

In 2018, we improved the management of our community relationships by locating and identifying around 650 priority communities. We also prepared 23 relationship plans for the communities nearby our operational units.

We strengthen our work with communities, civil society organizations, public sector and universities through our social-environmental program (namely, Petrobras Socioambiental). This initiative contributes to environmental conservation and the improvement of living conditions where we operate. The program is aligned with our social responsibility policy, which aims at providing energy, respecting human rights and the environment, managing responsibly our relationship with nearby communities and overcoming sustainability challenges.

In 2018, our voluntary social investment totaled US$24 million (R$87 million), which amount supports 123 social-environmental projects. In order to improve our social risk management process, since 2017, we have been incorporating new requirements into our capital investment projects guidelines for our decision-making process, such as a social risk analysis by a multidisciplinary group composed of our employees. Following this new guideline, 19 investment projects were assessed in 2018.

2040 Strategic Plan and 2019-2023 Business Plan

In December 2018, our board of directors approved our 2040 Strategic Plan and our 2019-2023 Business Plan. The strategic monitoring process generated adjustments in the set of strategies established in our strategic plan approved in 2017 resulting in 10 strategies, with longer outlook and linked with the recent conditions of our business and internal resources.

Our process consists of the continuous evaluation of the business environment and the implementation of the plan, allowing adjustments to be made in a more efficient way. Our 2040 Strategic Plan and our 2019-2023 Business Plan are focused on oil and natural gas exploration and production, notably in the Brazilian pre-salt area, which is one of our greatest strengths and sources of value creation. In the medium term, we expect that the use of natural gas as a source of energy generation will gain more relevance in our operations, in accordance with energy transition trends. In the long term, we plan to study opportunities in renewable energies that have synergies with our activities and competitive advantages. In this way, we will work towards a more environmentally sustainable portfolio. Digital technology should permeate our activities along this timeframe with the goal of cost reduction and increase in productivity.

Our purpose is to provide energy that moves society to fulfill its potential and our valuesare (i) respect for life, (ii) respect for people and the environment, (iii) ethics and transparency, (iv) market orientation, (v) resilience and confidence and (vi) and results.

 

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Our strategies are adjusted, defining the focus of our actions by business segment:

 

   

Exploration and Production (E&P): (i) Maximize our value through active management of the E&P portfolio; and (ii) ensure the sustainability of oil and gas production, prioritizing activities in deepwaters.

 

   

Gas and Power: Optimize our position in the natural gas and energy segment in Brazil and develop positions in the global market through partnerships:

 

   

Refining, Transportation and Marketing: (i) Maximize our value through active management of our portfolio for refining, logistics, trading and petrochemicals integrated into the activities of national oil and gas production; and (ii) exit the fertilizer business, LPG distribution, biodiesel and ethanol holdings and production.

 

   

Renewables: Operate in profitable renewable energy businesses, with a focus on wind and solar energy in Brazil.

 

   

Corporate Strategies:(i) Develop critical skills and a culture of high performance to meet the new challenges of the company; (ii) prepare us for a more competitive environment based on cost and scale efficiency and digital transformation; (iii) assess current and future partnerships seeking integrity and value generation; and (iv) strengthen our credibility, pride and reputation among our stakeholders.

Our 2019-2023 Business Plan details the operational variables, with a focus on safety, as well as the financial performance and the profitability in our businesses for the next five years (2019-2023).

Additionally, our 2019-2023 Business Plan incorporates a new metric, seeking to ensure profitability, in addition to maintaining the safety and debt reduction metrics that guide our strategies: (i) total recordable injuries per million man-hour frequency rate (TRI) below 1.0 in 2019; (ii) Net debt/adjusted EBITDA in US dollars below 1.5 in 2020; and (iii) return on capital employed (ROCE) above 11% in 2020. Our 2019-2023 Business Plan investment portfolio adds up to US$84.1 billion distributed among our business segments as follows:

 

  (1)

Exploration and Production – 82%

 

  (2)

Refining, Transportation and Marketing – 10%

 

  (3)

Gas and Power – 6%

 

  (4)

Renewables – 0.5%

 

  (5)

Corporate – 2%

Our 2019-2023 Business Plan also brings a commitment to the decarbonization of processes and products, establishing zero growth of absolute operational emissions until 2025, considering 2015 as reference and excluding a national water crisis, even with increase in production. Targets are set to reduce emissions intensity by 32% in E&P and 16% in refining between 2015 and 2025, when we aim to reach 15 kg CO2e/boe in E&P and 36 kg CO2e/t CWT in refining.

Due to the volatility in oil price, and the exposure of Petrobras’ cash flow results to this variable, in March 2019, our Executive Board approved a Resilience Plan which includes additional actions to 2019-2023 Business Plan and was structured in three value generation levers, as described below.

Expansion of the portfolio management program, with the inclusion of more mature fields of oil and gas in land and in shallow waters, midstream and downstream assets. This adjustment does not include the revision of the refineries’ divestment package, still under study.

 

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The second lever comprises a decrease in manageable operating costs estimated at US$ 8.1 billion (6.6%) compared to the total amount of US$ 122.6 billion budgeted in the 2019-2023 Business Plan. Staff expense cuts as well as reduction in discretionary expenses, in addition to savings from optimization of use of office buildings are the main sources of cost reduction. We will focus on digital transformation to pursue the target reduction in operating costs.

Finally, we are working to release the excess capital parked in cash, which allows its allocation to more productive uses.

The Resilience Plan doesn´t change the investment program approved in the 2019-2023 Business Plan.

Exploration and Production

 

     Exploration and Production Key
Statistics
 
     2018      2017      2016  
     (US$ million)  

Exploration and Production:

        

Sales revenues

     52,382        42,184        33,675  

Income (loss) before income taxes

     18,421        10,633        2,055  

Property, plant and equipment

     116,153        126,487        123,056  

Capital Expenditures According to Our Plan Cost Assumptions

     11,592        12,397        13,509  

Our oil and gas exploration and production activities are the largest components of our investment portfolio. Our activities are concentrated in deepwater oil reservoirs in Brazil. Our domestic activities represented 96% of our worldwide production in 2018 and accounted for 99% of our reserves on December 31, 2018. Over the last five years, approximately 89% of our total Brazilian production has been oil.

Brazil’s largest oil fields are located offshore, most of them in deepwaters. We have been conducting offshore exploration and production activities in the Campos Basin since 1971, when we started exploration, and our major discoveries were made in deepwater and ultra-deepwater. Our technology and expertise have created a competitive advantage for us and we have become globally recognized as innovators in the technology required to explore and produce hydrocarbons in deep and ultra-deepwaters. In 2018, offshore production accounted for 93% of our production in Brazil and deepwater production accounted for 85% of our production in Brazil.

Historically, we focused our offshore exploration and production activities on sandstone turbidite reservoirs, located primarily in the Campos Basin. In 2006, we were successful in drilling through a massive salt layer off the Brazilian coast that stretches from the Campos to the Santos Basin. This pre-salt area has many large carbonate reservoirs with well-preserved oil, leading to a number of important discoveries. The pre-salt polygon occupies an area of approximately 149,000 km² (36.8 million acres), of which we have rights to produce from 18% of the total area (around 26,500 km² or 6.6 million acres), through acreage assigned to us under Concession Agreements, the Assignment Agreement and Production Sharing Agreements.

The pre-salt reservoirs we have discovered are located in deepwater and ultra-deepwaters at total depths of up to 7,000 meters (22,965 feet). The southern part of the pre-salt province consists of the Santos Basin, where the salt layer is approximately two kilometers thick. In the northern part of the pre-salt province, the salt is thinner and most of the oil has migrated through the salt to the post-salt sandstone reservoirs of the Campos Basin. While some of the oil that formed has migrated, we still have made important discoveries in pre-salt reservoirs in the Campos Basin, as we drilled through the salt layers. Most of our current and future capital will be committed to developing the oil found in the pre-salt province, with an emphasis on the Santos Basin, given the size of its reservoirs and its potential.

 

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The map below shows the location of our pre-salt reservoirs.

 

LOGO

Our activities by region

Brazil

Domestic exploration and production assets are the main components of our portfolio, representing 97% of our worldwide exploratory blocks, 97% of our global oil production and 99% of our oil and natural gas reserves.

 

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The following map shows our exploration and production areas in Brazil as of December 2018.

 

LOGO

Campos Basin

The Campos Basin is one of Brazil’s main and most prolific oil and gas offshore basins, with over 60 hydrocarbon fields discovered, eight large oil fields and a total area of approximately 115 thousand km2 (28.4 million acres). Our activities in the basin began in 1971 and we are now focused on maintaining our production in relatively mature fields. We have been able to mitigate the natural decline in mature fields of this basin by installing new production systems, tapping pre-salt reservoirs with both new and existing production units and improving operational efficiency.

Most of our production in the Campos Basin is from post-salt reservoirs, but pre-salt reservoirs in the basin are a growing source of production. We first began pre-salt oil production in 2008 in the Jubarte field located in the Parque das Baleias region. In 2018, the Campos Basin pre-salt area average production of oil was 213.4mbbl/d, which represents a decrease of 8.1% compared to 2017. We have a 100% working interest in oil produced from the Campos Basin pre-salt reservoirs.

 

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Santos Basin

The Santos Basin is one of the most promising offshore exploration and production areas in the world, containing the southern and most prolific part of the pre-salt province. Our activities in the Santos Basin began with the acquisition of eight blocks through public auction under concession agreements in 2000 and 2001. In 2010, we entered into an Assignment Agreement with the Brazilian federal government, under which we were assigned exclusive rights to explore and produce five billion barrels of oil equivalents in the Santos Basin. In 2018, we started producing in the Búzios field, through the FPSOs P-74 and P-75.

In 2013, a consortium led by us was awarded with the rights and obligations to explore and develop the Libra block in the ultra-deepwaters of the Santos Basin, in the first production sharing regime auction ever held in Brazil. In 2017, we presented to the ANP the declaration of commerciality of the northwestern portion of the Libra area, proposing the name Mero for the new oil field, which holds a field’s total recoverable estimated volume of 3.3 billion barrels of oil. In 2017 and 2018, we were awarded the rights and obligations of seven other areas under production sharing regime in Brazil. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil” and Item 10. “Additional Information—Material Contracts.”

We currently have 16 pre-salt production units in the Santos Basin, of which one is dedicated to Extended Well Test (EWT). With these units, we have been increasing the pre-salt oil production in the Santos Basin since its first oil production, in 2009. Petrobras’s and our non-operated partners’ production in the Santos Basin pre-salt area reached an average of 1,393 mmbbl/d in 2018, which represents an increase of 8.2% when compared to 2017. Despite these important results, we continue to concentrate our efforts on gathering information about the pre-salt reserves through EWTs. In 2018, two EWTs were performed in the Sururu and Mero fields and there is another onstream in the Mero field.

Other Basins

We produce hydrocarbons and hold exploration acreage in 17 other basins in Brazil. While our onshore production is primarily in mature fields, we plan to sustain and slightly increase production in these fields by enhancing recovery methods. The most significant potential for exploratory success within our other basins are the Equatorial Margin and East Margin.

International

Outside Brazil, we have long been active in South America, in North America and West Africa. We focus on opportunities to leverage the deepwater expertise we have developed in Brazil. Since 2012, we have been substantially reducing our international activities through the sale of assets to meet our announced divestment targets.

South America

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

 

   

In Argentina, through our subsidiary Petrobras Operaciones S.A., or POSA, 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 Bolivia, our gas and condensate production comes, among others, principally from the San Alberto and San Antonio production contracts, which are operated mainly to supply gas to Brazil and Bolivia.

 

   

In Colombia, we are operators of, and hold a 40% working interest in, the Tayrona offshore exploration block, which includes the Orca gas discovery, and the Villarica Norte onshore exploration block (50% WI).

 

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North America

 

   

In the United States, we focus on deepwater fields in the Gulf of Mexico. Our production in 2018 originated mainly from the Cascade, Chinook, Saint Malo and Lucius fields. On November 30, 2018, we concluded the operation that has resulted in the formation of a joint venture (”JV”) with Murphy Exploration & Production Company (“Murphy”). The JV was established through the contribution by both companies of their production assets in the Gulf of Mexico. Murphy oversees the operations with an 80% working interest and Petrobras America Inc. (“PAI”) holds a 20% stake. PAI and Murphy also signed a Limited Liability Company Agreement, a shareholders agreement that governs the JV, a Master Service Agreement (“MSA”), through which Murphy will operate the assets included in the JV, and a Transition Services Agreement (“TSA”), through which PAI will operate its previously owned assets until the takeover by Murphy.

 

   

In Mexico, we have held non-risk service contracts through our joint venture with PTD Servicios Multiplos SRL for the Cuervito and Fronterizo blocks in the Burgos Basin since 2003. Under these service contracts, we receive fees for our services.

Africa

We explore oil and gas opportunities in Africa exclusively through our 50% working interest in Petrobras Oil & Gas B.V. (“PO&G”), a joint venture with BTG Pactual. The assets of this joint venture include the Agbami, Akpo, and Egina fields, and the Preowei and Egina South discoveries appraisal projects, all of them in Nigeria. Our subsidiary Petrobras International Braspetro BV (”PIBBV”) signed on October 31, 2018 a sale and purchase agreement for the sale of its 50% working interest in PO&G with Petrovida Holding B.V. (“Petrovida”), the latter owned by members of Vitol Investment Partnership II Ltd (“Vitol”), Africa Oil Corp (“Africa Oil”) and Delonex Energy Ltd (”Delonex”). The closing of this transaction is subject to certain conditions precedent, such as obtaining approvals by relevant Nigerian government bodies. See “Item 4. Information on the Company—Overview of the Group—Portfolio Management.”

Oil and Gas Production Activities

In 2018, our total production of oil and gas, including NGL was 2.63 million barrels of oil equivalent per day (boed), of which 2.53 million boed were produced in Brazil and 101,000 boed were produced abroad. Our own production of oil in Brazil was 2.03 million barrels per day (bpd).

The annual average of our total operated production of oil and gas, including NGL (share of both Petrobras and associates), in 2018 was 3.29 million boed, of which 3.16 million boed were produced in Brazil.

The main highlights of our production in 2018 were the following: (i) starting four new production systems: (a) the P-74 and P-75 platforms, located in the Búzios Field, in the pre-salt area of the Santos Basin; (b) the P-69 platform, located in the Lula Field, also in the pre-salt area of the Santos Basin; and (c) the FPSO Cidade de Campos dos Goytacazes, located in the Tartaruga Verde Field, in the post-salt of the Campos Basin; (ii) the continuous development of our pre-salt production, which has been in development for 10 years and achieved an annual production of oil and natural gas of 1.75 million boed and the monthly record of 1.85 million boed December; (iii) achieving a new annual record in the use of associated gas produced in our production facilities in Brazil at 96.6%, as a result of the efforts undertaken over the past years through a program focused on the optimization for the use of gas; and (iv) divestments in the Lapa, Sururu, Berbigão, Oeste de Atapu and Roncador fields, as well as the joint venture formed by Petrobras America Inc. and Murphy Exploration & Production Co.

 

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Our production per region in the last three years is summarized in the following table:

 

     Oil (mmbbl) (1)(4)      Gas (mmcf) (2)(4)      Total (mboe)(4)      Stationary
production units(4)
 
     2018      2017      2016      2018      2017      2016      2018      2017      2016      2018      2017      2016  

Brazil(3)

     742.7        786.1        784.8        541.8        556.0        534.0        833.0        878.8        873.8        113        114        115  

South America (excluding Brazil)

     1.6        1.9        8.0        75.4        85.4        144.7        14.2        16.1        32.1        —          —          —    

North America (5)

     14.3        13.2        12.1        4.2        21.5        32.1        15.0        16.7        17.4        —          2        2  

Equity and non-consolidated affiliates

     7.5        8.2        9.2        0.2        0.0        0.1        7.6        8.2        9.2        —          —          —    

South America (excluding Brazil)

            —          0.5               —          0.1               —          0.5        —          —          —    

North America

     0.4                      0.2        —          —          0.5        —          —          —          —          —    

Africa

     7.1        8.2        8.7        —          —          —          7.1        8.2        8.7        —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     766.2        809.4        814.1        621.6        662.8        710.9        869.8        919.8        932.6        113        116        117  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Oil production includes production from extended well tests (EWT) and NGL.

(2)

Natural gas production figures are the production volumes of natural gas available for sale, excluding flared and reinjected gas and gas consumed in operations.

(3)

Includes NGL, synthetic oil and synthetic gas production from oil shales deposits in São Mateus do Sul, in the Paraná Basin of Brazil.

(4)

This table contains only definitive production systems and units performing EWT (Extended Well Tests) or EPS (Early Production Systems). We had 115 units (being 2 drilling units) in 2018, 120 units (6 drilling units) in 2017 and, 121 units (6 drilling units) in 2016, all of these including drilling units that may have also contributed to production.

(5)

Due to the joint venture formed by Petrobras America Inc. and Murphy Exploration & Production Co, our production in the United States was reported on a consolidated basis from January through November 2018, and as an equity method investee from December 2018 onward.

For 2019, we expect to produce 2.3 mmbbl/d of oil in Brazil (10% more than our average in 2018). For more information on new production systems, see Item 4. “Information on the Company—Exploration and Production—Production Development.”

We recognized impairment losses for the fiscal year ended December 31, 2018 of US$1,391 million with respect to the E&P segment, primarily reflecting higher estimates of decommissioning costs in producing properties in Brazil (driven by costs related to subsea facilities and equipment) and depreciation of the Brazilian real against the US dollar (US$1,054 million), as well as the impacts of the agreement to establish a joint venture through the E&P field in the Gulf of Mexico (US$715 million). These effects were partially offset by reversals of impairment previously recognized due to upward revision in the estimated production curves following a review of certain investment projects, as set out in the 2019-2023 Business Plan (US$530 million).

 

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We recognized impairment reversals for the fiscal year ended December 31, 2017 of US$870 million with respect to our domestic exploration and production producing properties due to (i) reversals of US$1,733 million, substantially reflecting the lower post-tax real discount rate, the approval of investments enhancing the recovery of mature fields and the lower tax burden set forth in the new tax rules applicable to the oil and gas industry; and (ii) impairment losses of US$863 million, substantially driven by an expected acceleration of production cessation reflecting an optimization of investment portfolio, as well as by a lower risk-adjusted discount rate for decommissioning costs, which also increased the costs of assets related to the abandonment and dismantling of certain areas. We have also recognized impairment losses of US$363 million with respect to oil and gas production and drilling equipment, which were not directly related to producing properties in Brazil, mainly resulting from: (i) lower fair value of certain equipment related to the FPSO P-72 and P-73 that could not be allocated to other projects, when compared to their carrying amount (US$127 million); (ii) decommissioning of a crane and launch ferry (US$114 million) and (iii) hibernation of equipment of Inhaúma Shipyard excluded from the initial scope of Inhaúma logistic center (US$125 million). In addition, we recognized impairment losses of US$405 million with respect to the sale of 25% of Roncador field in Campos basin to Statoil, as its sales price was lower than the carrying amount.

For the fiscal year ended December 31, 2016, we previously recognized impairment losses of US$2.3 billion with respect to our domestic exploration and production producing properties due to (i) the appreciation of the real against the U.S. dollar, (ii) the review of our price assumptions, (iii) our annual reviews of oil and gas reserves, (iv) decommissioning cost estimates and (v) a higher discount rate following the increase in Brazil’s risk premium. This amount also includes an impairment reversal relating to the Centro Sul group, amounting to US$415 million, was recognized due to the higher estimates of reserves and production and the lower estimates of operating expenses. The decommissioning of a unit, which had high operational costs, and the replacement of another unit by an investment in a new processing plant, which was committed during the third quarter of 2016, also contributed to such impairment reversal. We have also recognized impairment losses of US$854 million with respect to oil and gas production and drilling equipment, which were not directly related to producing properties in Brazil, mainly due to uncertainties over the ongoing hulls construction of the FPSOs P-71, P-72 and P-73.

For further information on impairment losses in 2018, 2017 and 2016, see Note 14 to our audited consolidated financial statements.

Lifting Cost

In 2018, our average lifting cost excluding government fees was US$10.7 per boe, which is a decrease of 2.7% compared to the average cost of US$11.0 per boe mined in 2017.

Capital Expenditures According to Our Plan Cost Assumptions – E&P

In our 2019-2023 Business Plan, we maintain our focus on the development of our reservoirs in Brazil, especially in the pre-salt layer.

Out of US$68.8 billion Capital Expenditures According to Our Plan Cost Assumptions in exploration and production for the next five years, 70% will be allocated to production development, 16% to exploration and 14% to infrastructure and R&D.

 

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The Capital Expenditures According to Our Plan Cost Assumptions in exploration and production activities in 2018 (in Brazil and abroad) amounted to US$11.6 billion, a 7% decrease compared to Capital Expenditures According to Our Plan Cost Assumptions for the fiscal year ended December 31, 2017 (US$ 12.4 billion), mainly attributable to the postponement of some construction activities for FPSOs, gains in efficiency of capital expenditure and depreciation of local currency against dollar (higher USD/BRL). This amount includes US$0.8 billion related to signature bonuses paid by us as a result of exploratory blocks contracted in ANP bidding rounds held in 2018. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Uses of Funds” for further information on our investments.

Exploration

As of December 31, 2018, we had 137 exploratory blocks in which 24 discoveries were under evaluation. We also had 5 discoveries being assessed in production areas. As of December 31, 2018, we had a 100% working interest in 43 exploratory blocks. We also had exploration partnerships with 23 foreign and domestic companies, for a total of 94 exploratory blocks. We serve as the operator in 64 of these exploration partnership blocks. We hold working interest ranging from 30% to 100% in the exploration areas under concession or assigned to us.

The table below breaks down our investments in exploration activities in 2018, which totaled US$1.35 billion.

 

     Net Exploratory Area (km²)      Exploratory Blocks      Evaluation Plans      Wells Drilled  
     2018      2017      2016      2018      2017      2016      2018      2017      2016      2018      2017      2016  

Brazil

     51,600        41,820        43,966        133        123        131        26        28        37        8        8        16  

Other S. America

     6,081        5,425        11,444        4        2        7        1        1        1        0        1        5  

North America

     0        198        376        0        10        28        0        0        0        0        0        0  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Africa

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     57,681        47,641        55,786        137        135        166        29        31        38        8        9        21  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

In 2018, we announced an oil discovery in the Campos Basin post-salt section in the Marlim Leste field. This discovery occurred with the drilling of a well (9-MLL-79D-RJS, named as Traca-3 well). In 2018, we also received a declaration of commerciality in the Espirito Santo Terra Basin, Cancã Leste field, and three declarations of commerciality in the Santos Basin, for the Noroeste de Sapinhoá, Sudoeste de Sapinhoá, Nordeste de Sapinhoá fields, and one in the Campos Basin, for the Tartaruga Verde Sudoeste field. In Libra, we started the seismic reprocessing over the Central and Southeastern areas, in order to start the activities until March 1, 2020, when the extension of the exploratory phase approved by the MME expires.

We acted selectively in the bidding rounds carried out by the ANP, reflecting our strategic vision to reorganize our exploratory portfolio, which seeks to maintain the relationship between reserves and production and to ensure the sustainability of our future oil and gas production. Furthermore, the operation in consortium with important companies is aligned with our strategic goal to strengthen partnerships, sharing risks, combining technical and technological skills and capturing synergies to leverage results, while reflecting the importance of these areas in Brazil for world-class oil companies. In 2018, we contracted 11 new offshore exploratory blocks, with a total area of 8.8 thousand km2 and a signing bonus of US$0.8 billion (equivalent to R$3.3 billion) at the acquisition date. In the pre-salt polygon, we contracted four areas under the production sharing regime, in partnerships with Chevron, Shell, Equinor, ExxonMobil, BP, Equinor, and Galp. In the Campos Basin, we contracted four blocks outside of the pre-salt polygon, under the concession regime, in partnerships with ExxonMobil, Qatar Petroleum and Equinor. We also contracted three blocks in Potiguar Basin, two of them as partnerships with Shell.

 

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In January 2019, we exercised the pre-emption right for the 6th bidding round of exploration blocks under the production sharing regime for the blocks of Aram, Norte de Brava and Sudeste de Sagitário, located in the Santos and Campos Basins, as operator and with the percentage of 30%. The amount corresponding to the signature bonus to be paid, considering that the auction results confirm the minimum stake indicated above, is US$ 0.5 billion (equivalent to R$1.8 billion).

Production Development

In 2018, four new systems came on stream and we connected 30 new wells (21 production and 9 injection wells) in our production systems. The FPSO Pioneiro de Libra, in the Mero Field, finished the first Extended Well Test (“EWT”). During the EWT, the producer reached the record production of 58 kboed. With the completion of the tests, the FPSO Pioneiro de Libra will operate the subsequent Early Production Systems (“EPS”) in other Mero wells. The Libra consortium continues to progress with the beginning of the construction of the Mero 1 FPSO in China, and an additional FPSO for Mero 2 is for bidding.

Over the last eight years, we had substantial cost optimizations regarding project development. For instance, we reduced the time required to drill and complete wells in the Santos Basin pre-salt area by 60.6% in 2018, compared to 2010, significantly reducing our capital expenditures per well. In addition, due to the wells’ high productivity, we have been able to top the capacity of the platforms with fewer wells.

Recently Installed Systems

In the last three years, we have installed several major systems, mainly in the pre-salt area of the Santos Basin, which helped mitigating the basin’s natural decline (table below).

 

Start Up
(year)

  

Basin

   Field/Area   

Unit Type

  

Production
Unit

  

Crude Oil
Nominal
Capacity
(bbl/d)

  

Natural
Gas
Nominal
Capacity
(mmcf/d)

  

Water
Depth
(meters)

   E&P Regime

2019

   Santos    Búzios 4    FPSO    P-77    150,000    211,9    2,100    Assignment Agreement

2019

   Santos    Búzios 3    FPSO    P-76    150,000    211,9    2,100    Assignment Agreement

2019

   Santos    Lula Norte    FPSO    P-67    150,000    211.9    2,100    Pre-salt Concession

2018

   Campos    Tartaruga Verde    FPSO    Cid. De Campos dos Goytacazes    150,000    176.6    765    Post-salt Concession

2018

   Santos    Lula Extremo Sul    FPSO    P-69    150,000    211.9    2,100    Pre-salt Concession

2018

   Santos    Búzios 1    FPSO    P-74    150,000    211.9    2,100    Assignment Agreement

2018

   Santos    Búzios 2    FPSO    P-75    150,000    211.9    2,100    Assignment Agreement

2017

   Santos    Lula    FPSO    P-66    150,000    211.9    2,100    Pre-salt Concession

2017

   Santos    Mero    FPSO    Pioneiro de Libra    50,000    141.6    2,400    Pre-salt Production
Sharing Agreement

2016

   Santos    Lapa    FPSO    Cid. de Caraguatatuba    100,000    176.6    2,140    Pre-salt Concession

2016

   Santos    Lula Central    FPSO    Cid. de Saquarema    150,000    211.9    2,100    Pre-salt Concession

2016

   Santos    Lula Alto    FPSO    Cid. de Maricá    150,000    211.9    2,100    Pre-salt Concession

 

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Main Systems to be Installed through 2021

In addition to the P-67 in the Lula field, and the P-76 and P-77 in the Búzios field, operations which started in early 2019, there are still four major systems to be installed in the next three years, all in the Santos Basin, in Brazil. The fields under the Assignment Agreement will be particularly important to support our production growth. Moreover, we will install the first definitive system in the Mero field, the first under the production sharing regime in Brazil. The table below lists our upcoming system start-ups.

 

Projected Start
Up (year)

  

Basin

  

Field/Area

  

Unit Type

  

Crude Oil
Nominal
Capacity
(bbl/d)

  

Natural Gas
Nominal
Capacity
(mmcf/d)

  

Water Depth
(meters)

   E&P Regime
2019    Santos    Berbigão    FPSO    150,000    211.9    2,280    Pre-salt Concession
2020    Santos    Atapu 1    FPSO    150,000    211.9    2,300    Assignment Agreement
2021    Santos    Mero 1    FPSO    180,000    423.8    2,100    Production Sharing
2021    Santos    Sépia    FPSO    180,000    211.9    2,200    Assignment Agreement

Critical Resources in Exploration and Production

We seek to develop and retain the critical resources that are necessary to meet our production targets. Drilling rigs are an important resource for our exploration and production operations and lead time is required when fleet expansion is needed. When we discovered the pre-salt reservoirs, in 2006, our activities as operators were constrained by a lack of rigs, but our subsequent efforts to lease additional rigs have eliminated this constraint. Whereas in 2008 we only had three rigs capable of drilling in waters with depth greater than 2,000 meters (6,560 feet), we had 14 as of December 31, 2018 (see table below). We believe that we now have sufficient rigs to meet our production targets, and we will continue to evaluate our drilling requirements and will adjust our fleet size as needed.

Likewise, in order to achieve our production goals, we must secure a number of specialized vessels (such as PLSV) to connect wells to production systems. In 2018, our specialized vessels were sufficient to meet our needs.

 

Drilling Units in Use by Exploration and Production on December 31 of Each Year

 
     2018      2017      2016  
     Leased      Owned      Leased      Owned      Leased      Owned  

Brazil

     17        4        29        7        31        10  

Onshore

     1        3        1        4        1        4  

Offshore, by water depth (WD)

     16        1        28        3        30        6  

Jack-up rigs

     0        0        0        2        0        2  

Floating rigs:

     16        1        28        1        30        4  

500 to 999 meters WD

     1        0        1        0        1        2  

1000 to 1999 meters WD

     2        0        3        1        3        2  

2000 to 3200 meters WD

     13        1        24        0        26        0  

Outside Brazil

     1        0        4        0        4        0  

Onshore

     1        0        3        0        4        0  

Offshore

     0        0        1        0        0        0  

Worldwide

     18        4        33        7        35        10  

 

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Reserves

According to SEC technical criteria for booking proved reserves, as of December 31, 2018, our worldwide net proved oil, condensate and natural gas reserves, including synthetic oil and gas, reached 9.6 bnboe, a 1.5% decrease compared to our proved reserves of 9.8 bnboe as of December 31, 2017, as shown in the table below.

 

Proved Reserves (1)

   Oil (mmbbl)      Gas (bcf)      Total (mmboe)  
     2018      2017      2016      2018      2017      2016      2018      2017      2016  

Brazil

     8,173.5        8,255.4        8,069.8        7,796.2        7,684.2        8,403.2        9,472.9        9,536.1        9,470.3  

Other S. America (2)

     1.6        1.2        0.8        214.1        160.2        113.9        37.2        27.9        19.8  

North America

     26.6        114.6        96.4        10.8        40.9        87.2        28.4        121.5        111.0  

Africa

     59.8        63.4        69.0        47.3        17.3        12.5        67.7        66.3        71.1  

Total

     8,261.5        8,434.6        8,236.1        8,068.5        7,902.6        8,616.8        9,606.2        9,751.7        9,672.2  

 

(1)

Includes synthetic oil and gas

(2)

In the case of Bolivia, the country’s Constitution prohibits concessionaires from recording reserves

In 2018, we incorporated 473.3 million boe of proved reserves by revisions of previous estimates, including 233.5 million boe due to economic revisions, mainly due to the increase in prices, and 239.9 million boe due to technical revisions, mainly due to the performance of our reservoirs, in the pre-salt of Santos and Campos basins, both in Brazil. In addition, we added 258.8million boe in our proved reserves resulting from positive responses from improved recovery (water injection), and added 343.6 million boe in our proved reserves due to extensions and discoveries, mainly in the pre- salt of Santos basins. Our proved reserves decreased by 367.8 million boe due to sales of reserves and increased 9.1 million boe in our proved reserves due to the purchase of reserves, resulting in a decrease of 358.7 million boe in our proved reserves due to sales and purchases. Considering a production of 862.6 million boe in 2018, our total proved reserves resulted in 9,606.2 million boe in 2018. This 862.6 million boe production volume is the net volume withdrawn from our proved reserves, therefore excludes NGL (except for North America) and does not consider the production of Extended Well Tests (EWTs) in exploratory blocks and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves. For further information on our reserves, see Item 4. “Information on the Company—Additional Reserves and Production Information” and “Supplementary Information on Oil and Gas Exploration and Production” in our audited consolidated financial statements.

The following table summarizes the reserves variations in the last three years, in terms of oil equivalents, including synthetic oil and gas.

 

Proved reserves

(million barrels of oil equivalent)

   2018     2017     2016  

Proved reserves, beginning of year

     9,751.7       9,672.2       10,516.0  

Discoveries and extensions

     343.6       82.5       103.2  

Improved recovery

     258.8       246.7       0.0  

Revisions of previous estimates

     473.3       670.1       131.0  

Sales of proved reserves

     (367.8     0       (168.8

Purchases of proved reserves

     9.1       0       16.3  

Production

     (862.6     (919.8     (925.4

Proved Reserves, end of year

     9,606.2       9,751.7       9,672.2  

 

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We recorded in 2018 a reserve replacement ratio (RRR) of 125%, disregarding the effects of sales and purchases. We also recorded a reserves-to-production ratio (R/P) of 11.1 years and a development ratio (DR), which is the ratio between developed proved reserves and total proved reserves, of 54%.

Refining, Transportation and Marketing

 

Refining, Transportation and Marketing Key Statistics

 
     2018      2017      2016  
     (US$ million)  

Refining, Transportation and Marketing:

        

Sales revenues

     73,448        67,037        62,588  

Income (loss) before income taxes

     3,362        6,099        8,644  

Property, plant and equipment

     27,356        33,400        35,515  

Capital Expenditures According to Our Plan Cost Assumptions

     1,107        1,284        1,168  

According to global energy market data released by PIRA Energy Group, Inc. for the end of 2018, we are one of the world’s largest refiners. We own and operate 13 refineries in Brazil, with a total net crude distillation capacity of 2.176 mbbl/d. As of December 31, 2018, we operated substantially almost all of Brazil’s total refining capacity. We supplied most of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of our wholesale segment. We operate a large and complex infrastructure of pipelines, terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets. Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, facilitating access to crude oil supplies and end-users.

Our Refining, Transportation and Marketing segment also includes (i) petrochemical operations that add value to the hydrocarbons we produce, (ii) extraction and processing of shale and (iii) international refining activities.

Refining Capacity in Brazil

Our crude distillation capacity in Brazil as of December 31, 2018, was 2,176 mbbl/d and our average throughput during 2018 was 1,715mbbl/d.

The following table shows the installed capacity of our Brazilian refineries as of December 31, 2018, and the average daily throughputs of our refineries in Brazil in 2018, 2017 and 2016.

 

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Capacity and Average Throughput of Refineries

 

Name (Alternative Name)

   Location    Crude
Distillation
Capacity at
December 31,
2018
     Average Throughput*  
   2018      2017      2016  
          (mbbl/d)      (mbbl/d)  

LUBNOR

   Fortaleza (CE)      8        8        7        9  

RECAP (Capuava)

   Capuava (SP)      53        50        50        54  

REDUC (Duque de Caxias)

   Duque de Caxias (RJ)      239        190        178        194  

REFAP (Alberto Pasqualini)

   Canoas (RS)      201        135        138        148  

REGAP (Gabriel Passos)

   Betim (MG)      157        141        143        150  

REMAN (Isaac Sabbá)

   Manaus (AM)      46        30        32        34  

REPAR (Presidente Getúlio Vargas)

   Araucária (PR)      208        173        162        167  

REPLAN (Paulínia)

   Paulínia (SP)      415        286        324        331  

REVAP (Henrique Lage)

   São José dos Campos
(SP)
     252        213        208        217  

RLAM (Landulpho Alves)

   Mataripe (BA)      315        201        198        218  

RPBC (Presidente Bernardes)

   Cubatão (SP)      170        140        144        142  

RPCC (Potiguar Clara Camarão)

   Guamaré (RN)      38        32        33        33  

RNEST (Abreu e Lima)

   Ipojuca (PE)      74        67        68        75  
     

 

 

    

 

 

    

 

 

    

 

 

 

Average crude oil throughput

        —          1,664        1,686        1,772  
     

 

 

    

 

 

    

 

 

    

 

 

 

Average NGL throughput

        —          51        50        47  
     

 

 

    

 

 

    

 

 

    

 

 

 

Average throughput

        —          1,715        1,736        1,819  
     

 

 

    

 

 

    

 

 

    

 

 

 

Crude distillation capacity

        2,176        —          —          —    
     

 

 

    

 

 

    

 

 

    

 

 

 

 

*

Considers oil and NGLs processing (fresh feedstock)

Refinery Investments

We initiated in the last few years the construction of two new refineries—RNEST in northeastern Brazil and COMPERJ to process our domestically produced heavy oil for oil products that were most in demand in the Brazilian market and with growing shortage.

The first refining unit of RNEST began its operations in December 2014. Designed to process 115 mbbl/d of crude oil into low sulfur diesel (10 ppm) and other products, this unit started operating with a partial capacity of 74 mbbl/d and since February 2016 it has been authorized to process up to 100 mbbl/d of crude oil. Reaching full capacity for the unit will require the completion of a sulfur dioxide emissions reduction unit (SNOX), which is under evaluation due to a notice of contractual suspension issued by the contractor (Qualiman Engenharia e Montagens) in December 2018, and also a revamp of the heavy gasoil section at Coker Unit to be implemented at the turnaround maintenance scheduled for 2020. Construction of the second refining unit of RNEST is included in our 2019-2023 Business Plan.

With respect to COMPERJ, we, in partnership with the Chinese company CNPC, are currently building a business model and feasibility study. The decision to build the refinery will depend on several factors, including the results of this feasibility study. To support gas processing from the pre-salt areas, in 2018, we started the construction phase to complete the gas processing plant and its utilities.

 

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In 2018, impairment losses on refining assets mainly related to RNEST and COMPERJ. As set forth in our 2019-2023 Business Plan, the resumption of the COMPERJ project still depends on new partnerships and expected project profitability. However, the construction of COMPERJ’s first refining unit facilities that will also support the natural gas processing plant (UPGN) are in progress as the facilities are part of the infrastructure for transporting and processing natural gas from the pre-salt layer in the Santos Basin. Nevertheless, due to the interdependence between such infrastructure and COMPERJ first refining unit, we recognized additional impairment charges, totaling US$47 million in 2018. The impairment assessment over the second refining unit in RNEST resulted in the recognition of an impairment loss amounting to US$22 million, as its start-up was postponed by five months.

In 2017, the resumption of the COMPERJ project depended on new partnerships. Accordingly, due to the same aforementioned reasons, in 2017, we recognized impairment charges totaling US$51 million. Regarding RNEST, a loss of US$464 million was recognized mainly due to higher costs of raw materials and lower refining margin, as set forth in our 2018-2022 business plan.

We previously recognized impairment losses in 2016, following a reassessment of COMPERJ project confirming its postponement until December 2020, with continuous efforts to seek new partnerships to resume the project, on the remaining balance of this project (US$403 million). A loss of US$780 million was recognized for the second refining unit in RNEST, mainly attributable to the use of a higher discount rate and a delay in expected future cash inflows to 2023 due to the postponement of the RNEST project.

In addition to constructing new refineries, over the past ten years, we 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.

Through our subsidiary Liquigás Distribuidora, we have operations in 24 Brazilian states and in the federal district. Its activities are segmented into two business areas: (i) segmented LPG to serve individual clients (residences), with approximately five thousand direct resellers and (ii) bulk LPG, in about 21 thousand customers from different sectors, including trade, industry, agribusiness and services.

In January 2017, our shareholders’ extraordinary general meeting approved the sale of our wholly-owned subsidiary Liquigás Distribuidora S.A. (“Liquigás”). In February 2018, the court of the Administrative Council of Economic Defense (CADE) evaluated the sale of Liquigás to Companhia Ultragaz S.A., and decided, by the majority of its members, not to approve the sale.

Petrobras is analyzing the alternatives for the divestment of Liquigás that remains in our portfolio management program in accordance with our strategic plan, which aims to optimize the business portfolio focused on oil and gas, withdrawing entirely from LPG distribution.

Domestic Output of Oil Products and Domestic Sales Volumes

The following tables summarize our domestic output of oil products and sales by product for the last three years.

 

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Table of Contents

Domestic Output of Oil Products: Refining and marketing operations, mbbl/d (1)

 
     2018      2017      2016  

Diesel

     715        692        775  

Gasoline

     393        439        444  

Fuel oil

     178        200        196  

Naphtha

     67        53        54  

LPG

     126        126        125  

Jet fuel

     110        106        100  

Others

     176        184        193  
  

 

 

    

 

 

    

 

 

 

Total domestic output of oil products

     1,765        1,800        1,887  
  

 

 

    

 

 

    

 

 

 

Installed capacity (2)

     2,176        2,176        2,176  

Crude distillation utilization (%) (3)

     76        77        81  

Domestic crude oil as % of total feedstock processed

     91        93        92  

 

(1)

Output volumes are larger than throughput volumes as a result of gains during the refining process.

(2)

Installed capacity as of December 31, 2018, 2017 and 2016.

(3)

Crude distillation utilization considers average installed capacity as of December 31, 2018, 2017 and 2016.

Our total domestic output of oil products decreased to 1,765 mbbl/d in 2018 from 1,800 mbbl/d in 2017, as a result of lower market demand for gasoline in 2018. In 2018, there was a lower participation of domestic crude oil in our total domestic feedstock processed (91% as compared to 93% in 2017).

 

Domestic Sales Volumes and Exports from Brazil, mbbl/d

 
     2018      2017      2016  

Diesel

     784        717        780  

Gasoline

     459        521        545  

Fuel oil

     45        61        67  

Naphtha

     97        134        151  

LPG

     231        235        234  

Jet fuel

     108        101        101  

Others

     163        171        186  
  

 

 

    

 

 

    

 

 

 

Total oil products

     1,887        1,940        2,064  
  

 

 

    

 

 

    

 

 

 

Ethanol, nitrogen fertilizers, renewables and other products

     71        112        112  

Natural gas

     345        361        333  
  

 

 

    

 

 

    

 

 

 

Total domestic market

     2,303        2,413        2,509  
  

 

 

    

 

 

    

 

 

 

Exports (1)

     608        672        554  
  

 

 

    

 

 

    

 

 

 

Total domestic market and exports

     2,911        3,085        3,063  
  

 

 

    

 

 

    

 

 

 

 

(1)

It mainly includes crude oil and oil products.

The Brazilian domestic market grew rapidly from 2010 to 2014, in parallel with Brazil’s economic expansion and the increase of average income, increasing by an average of 5.6%. In 2015 and 2016, as a result of the Brazilian economic slowdown, the domestic growth rate in consumption of oil products, particularly diesel, decreased as compared to the higher rates of growth experienced in prior years. In 2017 we observed slight signs of improvement in fuel consumption, due to the effects of recovery of some sectors of the Brazilian economy. In 2018, fuel consumption reached the same level as in 2017.

 

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Despite unchanged Brazilian fuel consumption, our total domestic sales volumes for oil products were 1,887 mbbl/d in 2018, a reduction of 3% compared to 2017. Our market-share increased in 2018 for diesel, and decreased for gasoline. However, factors such as cheaper hydrated ethanol prices, that led to increased biofuel participation in the Otto cycle market, lower sales of naphtha for Braskem and the decrease of fuel oil usage for electricity generation were predominant and resulted in a decrease in our total sales.

Imports and Exports

Our import and export of crude and oil products is driven by the economics involving our domestic refining, the Brazilian demand levels and international prices. Most of the crude oil we produce in Brazil is intermediate. We import some light crude to balance the slate for our refineries, and export mainly intermediate crude oil from our production in Brazil. We also continue to import oil products to balance any shortfall between production from our Brazilian refineries and the market demand for each product. Despite the domestic market retraction there was an increase in our market share, resulting in higher import levels in 2018 compared to the previous years.

We export oil products from our refineries, mainly fuel oil and bunker, but also gasoline and diesel.

The table below shows our exports and imports of crude oil and oil products in 2018, 2017 and 2016:

 

Exports and Imports of Crude Oil and Oil Products, mbbl/d

 
     2018      2017      2016  

Exports

        

Crude oil

     428        512        387  

Oil products

     178        157        155  

Total exports

     606        669        542  
  

 

 

    

 

 

    

 

 

 

Imports

        

Crude oil

     154        127        136  

Diesel

     59        12        13  

Gasoline

     19        11        32  

Other oil products

     117        158        193  

Total imports

     349        308        374  
  

 

 

    

 

 

    

 

 

 

Delivery Commitments

We sell crude oil through long-term and spot-market contracts. In 2018, the crude oil volume committed through long-term contracts with fixed quantity subject to final agreement on commercial terms is approximately 290 mbbl/d and the volume committed through long-term contracts subject to mutual agreement is expected to be around 10mbbl/d. Taking into consideration the planned processing rates of our refineries for the coming year we believe that our domestic proved reserves will be sufficient to allow us to continue delivering all contracted volumes. In 2018, approximately 67% of our domestic exported crude oil were committed by our contracts with third parties.

Logistics and Infrastructure for Oil and Oil Products

We own and operate, through Transpetro, an extensive network of crude oil and oil product pipelines in Brazil that connect our terminals, refineries and other primary distribution points. As of December 31, 2018, our onshore and offshore, crude oil and oil products pipelines extended over 7,719km (4,796miles). We operate 27 marine storage terminals and 20 other tank farms with nominal aggregated storage capacity of 64.6 mmbbl. In 2018, our marine terminals handled 8,161 tankers and oil barges.

 

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We operate a fleet of owned and chartered vessels. We provide shuttle services between our producing offshore areas in Brazil and our terminals onshore, and transportation of crude oil and products internationally and along the Brazilian coast. We are upgrading our own fleet, replacing old vessels with new ones by building or chartering vessels, which is part of our growing strategy. Our long-term strategy continues to focus on the flexibility afforded by operating a combination of owned and chartered vessels.

Also, three new oil tankers and one new LPG carrier were delivered to us in 2018. We plan to have another two vessels delivered to us in 2019, which are being built in Brazilian shipyards.

The table below shows our operating fleet and vessels under contract as of December 31, 2018.

 

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2018

 
     In Operation      Under Contract/
Construction
 
     Number      Tons
Deadweight
Capacity
     Number      Tons
Deadweight
Capacity
 

Owned fleet:

           

Tankers

     34        2,943,529        2        229,400  

LPG tankers

     9        52,148        —          —    

Total

     43        2,995,676        2        229,400  
  

 

 

    

 

 

    

 

 

    

 

 

 

Chartered vessels:

        —          

Tankers (Petrobras)

     58        2,337,862        4        610,800  

Tankers (Transpetro)

     14        1,576,447        

LPG Tankers (Petrobras)

     8        241,463        —          —    

Total

     80        4,155,772        4        610,800  
  

 

 

    

 

 

    

 

 

    

 

 

 

A decrease in the number of chartered vessels (tankers) in 2018 to 80 (as compared to 89 as of December 31, 2017) is mainly attributable to an increase of operational efficiency and a decrease in the market demand.

The lower freight rates projected in our 2019-2023 Business Plan significantly affected our impairment assessment of the Transpetro’s fleet of vessels, resulting in the recognition of impairment losses in the amount of US$428 million in 2018.

We recognized impairment losses for the fiscal year ended December 31, 2017 of US$112 million on transportation assets, relating to the decision to suspend the construction of three vessels of Panamax project, which triggered an impairment loss for the total carrying amounts of these assets.

In 2016, impairment losses of US$244 million on transportation assets mainly reflected postponements and suspension of construction projects relating to support vessels of Hidrovias project, the use of a higher discount rate and the commencement of the construction on 5 vessels after securing the projects funding, which avoided potential future claims for breach of contracts.

For further information, see Note 14 to our audited consolidated financial statements.

Petrochemicals

Our participation in the petrochemical sector provides an outlet for our growing production volumes of gas and other refined products, which increase their value and provide substitutes for products that are otherwise imported. Our new strategy outlined in the 2040 Strategic Plan is to maximize value through active management of our portfolio for refining, logistics, trading and petrochemicals, integrated into the activities of national oil and gas production.

 

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We engage in the petrochemical sector through the following subsidiaries, joint ventures, joint operations and associated companies:

 

     mmt/y
(nominal
capacity)
     Petrobras
interest
(%)
 

Braskem:

     

Ethylene

     5.00        36.20  

Polyethylene

     4.11  

Polypropylene

     4.05  

DETEN Química S.A.:

     

LAB(1)

     0.22        27.88  

LABSA(1)

     0.12  

METANOR S.A./COPENOR S.A.(2):

     

Methanol(3)

     0.08        34.54  

Formaldehyde

     0.09  

Hexamine

     0.01  

FCC Fábrica Carioca de Catalisadores S.A.:

     

Catalysts

     0.04        50.00  

Additives

     0.01  

PETROCOQUE S.A.:

     

Calcined petroleum coke

     0.50        50.00  

 

(1)

Feedstock for the production of biodegradable detergents.

(2)

Copernor S.A. is a Metanor S.A. subsidiary.

(3)

The company decided to stop the production of methanol in 2016.

The sale of Companhia Petroquímica de Pernambuco (PetroquímicaSuape) and Companhia Integrada Têxtil de Pernambuco (Citepe) to Grupo Petrotemex S.A. de C.V. and Dak Americas Exterior, S.L, both subsidiaries of Alpek was completed in April 2018.

We recognized impairment losses for the fiscal year ended December 31, 2016 of US$619 million with respect to the Suape Petrochemical Complex, mainly attributable to lower market projections and the appreciation of the real against the U.S. dollar. Following the disposal of Suape Petrochemical Complex in December 2017, we recognized an additional impairment charge of US$435 million, due to the lower exit price of these investments when compared to their carrying amount adjusted by the debt to be settled by us as part of the closing of such transaction. In 2018, this disposal was completed, after price adjustments established in the purchase and sale agreement. Reversals of impairment in the amount of US$86 million were accounted for in 2018.

Refining Capacity Abroad

Our international crude distillation capacity as of December 31, 2018 was 110 mbbl/d and the utilization factor for our international refinery was 91%.

 

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The following table shows the installed capacity of our international refineries as of December 31, 2018, and the average daily throughputs in 2018, 2017 and 2016, respectively.

 

Capacity and Average Throughput of Refineries

 

Name (Alternative Name)

   Location    Crude
Distillation
Capacity at
December 31,
2018
     Average Throughput(1)  
   2018 (2)      2017 (2)      2016  
          (mbbl/d)      (mbbl/d)  

Pasadena Refining System Inc.

   Texas (USA)      110        100.2        88.4        104.2  

Ricardo Eliçabe Refinery (3)

   Bahía Blanca (AR)      —          —          —          15.3  
     

 

 

          

Average crude oil throughput

           100.2        88.4        119.4  
     

 

 

    

 

 

    

 

 

    

 

 

 

Average external intermediate throughput

           7.5        5.2        6.5  
     

 

 

    

 

 

    

 

 

    

 

 

 

Total average throughput

        110        107.7        93.6        125.9  
     

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Consider oil (fresh feedstock) and external processed intermediate oil products.

(2)

For the years 2016 and 2017 we report the average crude oil throughput separately from the average external intermediate throughput.

(3)

We used to own this refinery through our interest in PESA, with capacity of 30.5 mbbl/d until July 2016, when we sold our entire participation in PESA, indirectly owned through Petrobras Participaciones S.L. (“PPSL”), to Pampa Energía.

The following table shows the average output of oil products of our international refinery in 2018, 2017 and 2016.

 

International Average Output of Oil Products

 
     2018      2017      2016  
     (mbbl/d)  

Total average output

     107        94        128  
  

 

 

    

 

 

    

 

 

 

Until January 2019, we participated in the refining sector in the United States and owned (i) 100% of the Pasadena Refining System Inc., which was an affiliate of Petrobras America Inc (PAI), and (ii) 100% of its related trading company, PRSI Trading, LLC. On January 30, 2019, Petrobras America Inc. (PAI) entered into a share purchase agreement with Chevron USA Inc. (Chevron) for the sale of the shares held by PAI on Pasadena Refining System Inc. (PRSI) and PRSI Trading LLC (PRST).

Sales Volumes Abroad

 

Sales Volumes Abroad, mbbl/d

 
     2018      2017      2016  

International Sales

     236        242        418  
  

 

 

    

 

 

    

 

 

 

Distribution

 

Distribution Key Statistics

 
     2018      2017      2016  
     (US$ million)  

Sales revenues

     27,960        27,567        27,927  

Income (loss) before income taxes

     722        802        96  

Property, plant and equipment

     1,529        1,862        1,936  

Capital Expenditures According to Our Plan Cost Assumptions

     136        109        139  

 

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Domestic Distribution

We are Brazil’s leading oil products distributor, operating through our subsidiary Petrobras Distribuidora, a publicly held company, listed at B3, in which we hold 71.25% of common shares. Petrobras Distribuidora has its own retail network and wholesale channels and supplies fuel wholesalers and retailers. Our distribution segment sells oil products that are primarily produced by our Refining, Transportation and Marketing segment, or RTM, and works to expand the domestic market for these oil products and for other fuels, including LPG, natural gas, ethanol and biodiesel.

The primary focus of our Distribution segment is to be the benchmark in the distribution of oil products and biofuels in Brazil, by innovating and providing value to our business, while promoting safe operations and environmental and social responsibility, strengthening our brand.

We supply and operate Petrobras Distribuidora, which accounts for 28.7% of the total Brazilian retail and wholesale distribution market. Petrobras Distribuidora distributes oil products, ethanol, biodiesel and natural gas to retail, commercial and industrial customers. In 2018, Petrobras Distribuidora sold the equivalent of 716 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion 41.9% was diesel.

At December 31, 2018, our Petrobras Distribuidora branded service station network was Brazil’s leading market retailer, with 7,665 service stations, according to Associação Nacional das Distribuidoras de Combustíveis, Lubrificantes, Logística e Conveniência (Plural). Petrobras Distribuidora owned and franchised stations that represented 23.9% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas in 2018, according to ANP and Plural.

Most Petrobras Distribuidora service stations are owned by third parties that use the Petrobras Distribuidora brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising. We own 686 of the Petrobras Distribuidora service stations and are required by law to subcontract the operation of these owned stations to third parties. We believe that our market share position is supported by a strong Petrobras Distribuidora brand image and by the remodeling of service stations and addition of lubrication centers and convenience stores.

Our wholesale distribution of oil products and biofuels under the Petrobras Distribuidora brand to commercial and industrial customers accounts for 42.8% of the total Brazilian wholesale market in 2018, according to ANP and Plural. Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.

Distribution Abroad

We also participate in the retail sector in other South American countries. See below our international distribution activities by region:

South America

We currently conduct distribution activities in Chile, Colombia and Uruguay and we used to conduct distribution activities in Paraguay:

 

   

In Chile, our operations included 281 service stations, the distribution and sales of fuel at airports and a lubricant plant. In July of 2016, we signed with Southern Cross Group (“SCG”) a contract for the sale of our entire interest in distribution in Chile. We also signed a temporary brand licensing agreement through which SCG will operate under our brand;

 

   

In Colombia, our operations include 119 service stations and a lubricant plant;

 

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In Paraguay, our operations included 196 service stations, the distribution and sales of fuel at three airports and an LPG refueling plant. A sale contract for the sale of all of our assets in Paraguay was signed and submitted to local authorities, and the sale of such assets closed on March 8, 2019.

 

   

In Uruguay, we have downstream operations in the country, including 88 service stations.

Gas and Power

 

Gas and Power Key Statistics

 
     2018      2017      2016  
     (US$ million)  

Gas and Power:

        

Sales revenues

     12,269        12,374        9,401  

Income (loss) before income taxes

     874        3,018        1,252  

Property, plant and equipment

     11,057        13,231        13,094  

Capital Expenditures According to Our Plan Cost Assumptions

     433        1,127        717  

Our Gas and Power segment comprises gas transmission and distribution, LNG regasification, the manufacture of nitrogen-based fertilizers, gas-fired, oil-fuelled and flex fuel power generation and power generation from renewable sources, including solar and wind sources.

The primary focus of our Gas and Power segment is to:

 

   

Monetize our natural gas resources;

 

   

Assure reliability and profitability in the supply of natural gas; and

 

   

Consolidate our electric energy business, exploring synergies between our natural gas supply and power generation capacities.

Domestic Gas and Power

For more than two decades, we have actively worked to simultaneously develop Brazil’s natural gas reserves and develop important infrastructure in order to assure flexibility and reliability in the supply of natural gas. As a result of this multi-year development program, Brazil has an integrated system centered around two main interlinked pipeline networks, a gas pipeline connection with Bolivia and an isolated pipeline in the northern region of Brazil (all together spanning over 9.190km). This network allows us to deliver to our customers natural gas processed in our gas facilities arriving from our onshore and offshore natural gas producing fields, mainly from Santos, Campos and Espírito Santo Basins, as well as the natural gas from our three LNG terminals, and from Bolivia. It is important to note that Brazilian pipeline networks are owned by TAG, TBG, Transportadora Sulbrasileira de Gás S.A (“TSB”) and Nova Transportadora do Sudeste (“NTS”). We are a shareholder with 100% shares of TAG, 51% shares of TBG and 25% shares of TSB, and concluded on April 4, 2017 the sale transaction of 90% of the company’s shares in NTS with pipelines of 2,043 kilometers of extension to Nova Infraestrutura Fundo de Investimentos em Participações (“FIP”), managed by Brookfield Brasil Asset Management Investimentos Ltda, an entity affiliated with Brookfield Asset Management.

Natural Gas

Our principal markets for natural gas are:

 

   

Industrial, commercial and retail customers;

 

   

Thermoelectric generation; and

 

   

Consumption by our refineries and fertilizer plants.

 

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The table below shows the sources of our natural gas supply, our sales and internal consumption of natural gas, and revenues in our local gas distribution operations for each of the past three years.

 

Supply and Sales of Natural Gas in Brazil, mmm3/d

 
     2018      2017      2016  

Sources of natural gas supply

        

Domestic production

     48.9        53.7        44.0  

Imported from Bolivia

     22.1        24.0        28.4  

LNG

     6.8        5.0        3.8  
  

 

 

    

 

 

    

 

 

 

Total natural gas supply

     77.8        82.7        76.2  
  

 

 

    

 

 

    

 

 

 

Sales of natural gas

        

Sales to local gas distribution companies(1)

     38.6        36.7        34.8  

Sales to gas-fired power plants

     16.4        20.7        18.0  
  

 

 

    

 

 

    

 

 

 

Total sales of natural gas

     55.0        57.4        52.8  
  

 

 

    

 

 

    

 

 

 

Internal consumption (refineries, fertilizer and gas-fired power plants)(2)

     22.8        25.3        23.4  

Revenues (US$ billion)(3)

     8.7        7.9        6.4  

 

(1)

Includes sales to local gas distribution companies in which we have equity interest.

(2)

Includes gas used in the transport system.

(3)

Includes natural gas sales revenues from the Natural Gas segment to other operating segments, service and other revenues from natural gas companies.

Our volume of natural gas sales to industrial, gas fired electric power generation, commercial and retail customers in 2018 was 55.0 mmm³/d, representing a decrease of 4.2% compared to 2017. This decrease is attributable to a lower power generation from gas-fired power plants, although there was an increase in sales to local gas distribution companies due to the growth of our industrial activities from 2017 to 2018. Natural gas consumption by refineries and fertilizer plants decreased by 2.5%. Currently, our main focus is to provide logistics and processing solutions for our planned natural gas production from the pre-salt fields. In 2019, we plan to continue to invest in:

(i) Construction of a new gas offshore pipeline—Route 3—with capacity of 636 mmcf/d (18 mmm³/d) connecting the Santos Basin pre-salt producing fields to Itaboraí processing plant. The initial operation is scheduled to start by the end of 2021.

(ii) Construction of a natural gas processing plant with capacity of 742 mmcf/d (21 mmm³/d), located in city of Itaboraí, Rio de Janeiro State, also associated with the pre-salt reservoirs in the Santos Basin. The Itaboraí facility is scheduled to start operations by 2021.

(iii) Development of basic engineering design phase for Caraguatatuba natural gas processing plant upgraded project, related to pre-salt reservoirs in Santos Basin.

(iv) Development of basic engineering design phase for a new natural gas plant to be located in the state of Sergipe, associated with deep water reservoirs in Sergipe Basin.

We also own and operate three LNG regasification terminals capable to receive FSRUs (Floating Storage and Regasification Units), one in Guanabara Bay (state of Rio de Janeiro) with a send-out capacity of 706 mmcf/d (20 mmm3/d), another in Pecém (state of Ceará) in Northeastern Brazil with a send-out capacity of 247 mmcf/d (7 mmm3/d) and the last one located in the Todos os Santos Bay (state of Bahia), with a send-out capacity of 706 mmcf/d (20 mmm3/d).

 

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In 2018, we imported 32 LNG cargos in Brazil, as compared to 27 in 2017. In addition, in 2018, we kept our commercial activities primarily abroad, with 12 trading operations overseas (including 11 offshore purchases, 11 offshore sales and one reload from Brazil).

We also own and operate 23 natural gas processing units (including units managed by our E&P, Gas and Power, and RTM business segments) – 20 in Brazil and 3 in Bolivia, with a total processing capacity of 149.02 million m3/day. Our natural gas processing units are located in Amazonas, Ceará, Rio Grande do Norte, Alagoas, Sergipe, Bahia, Espírito Santo, Rio de Janeiro, São Paulo and Bolívia, and are capable of processing natural gas in its gaseous and condensed form.

The total average volume of natural gas processed in Brazil in 2018 was 65.04 million m³/day, 9.3% higher than in 2017. In 2018, after the processing of natural gas, the main products were 53.12 million m³/day of natural gas and 3.47 million tons/day of GLP. Other than natural gas produced in Brazil, we also receive natural gas from Bolivia, through a gas pipeline, and liquefied natural gas, imported from other countries in specialized vessels and regasified in terminals in Brazil.

The total average volume of natural gas processed in Bolivia in 2018 was 22.1 million m³/day, 7.8% less than 2017.The map below shows gas pipeline networks, LNG terminals and natural gas processing plants.

 

LOGO

 

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We hold stakes in nineteen of the twenty-seven natural gas distributors in Brazil. Through Gaspetro, in which we have a 51% stake, we hold interests ranging from 23.5% to 100% in these distributors. In addition, Petrobras Distribuidora operates in the Espírito Santo state and we hold a 71.25% stake in this distributor. The three most significant distributors in our portfolio (by volume) are CEG Rio, Bahiagás and Copergás, all of which are held through Gaspetro and their combined averaged gas distributed volumes in 2018 amounted to 13 mmm³/d, representing 53% of the averaged gas distributed volumes of our nineteen natural gas distributors during 2018.

Long-Term Natural Gas Commitments

When we began construction of the Bolivia-Brazil pipeline (“GASBOL”) in 1996, we entered into a long-term Gas Supply Agreement, or GSA, with the Bolivian state-owned company Yacimientos Petroliferos Fiscales Bolivianos, or YPFB, to purchase certain minimum volumes of natural gas at prices linked to the international fuel oil price through 2019, after which the agreement may be extended until all contracted volume has been delivered. At the moment, we estimate that the agreement will be extended through 2023 under the current conditions.

Our volume obligations under the ship-or-pay arrangements entered into with Gas Transboliviano S.A. (GTB) and Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (TBG) were originally designed to match our gas purchase obligations under the GSA through 2019.

Regarding GASBOL’s Bolivian side, while YPFB has shipper´s obligations, Petrobras agreed to pay, on behalf of YPFB, the amounts related to 24 mmm3/d directly to GTB until 2019 and pre-paid 6 mmm3/d until 2039.

For GASBOL’s Brazilian side, after 2020, there is 12 mmm3/d of remaining volume commitment related to Bolivian gas imports and 5.2 mmm3/d to extra capacity between Paulínia, São Paulo state, and Araucária, Paraná state. Any additional capacity must be contracted through a public process conducted by Agência Nacional do Petróleo, Gás Natural e Biocombustíveis, or ANP, in accordance with Brazilian law.

The table below shows our contractual commitments under these agreements for the five-year period from 2019 through 2023.

Besides the aforementioned contracts, we also have obligations under the ship-or-pay contracts entered into with Nova Transportadora do Sudeste (NTS) and Transportadora Associada de Gás (TAG) to transport natural gas produced in Brazil and import LNG to gas distribution companies, power plants and oil refineries.

 

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     2019      2020      2021      2022      2023  

Purchase commitments to YPFB

              

Volume obligation (mmm3/d)(1)

     24.06        24.06        24.06        24.06        24.06  

Volume obligation (mmcf/d)(1)

     850.00        850.00        850.00        850.00        850.00  

Brent crude oil projection (US$)(2)

     65.54        67.00        72.00        75.00        75.00  

Estimated payments (US$ million)(3)

     1,640.98        1,477.36        1,496.62        1,695.87        1,802.60  

Ship-or-pay contract with GTB

              

Volume commitment (mmm3/d)

     30.08        6.00        6.00        6.00        6.00  

Volume commitment (mmcf/d)

     1,062.28        211.89        211.89        211.89        211.89  

Estimated payments (US$ million)(4)(5)

     114.30        —          —          —          —    

Ship-or-pay contract with TBG (7)

              

Volume commitment (mmm3/d)(6)

     35.28        17.20        17.20        11.20        11.20  

Volume commitment (mmcf/d)

     1,245.91        607.42        607.42        395.53        395.53  

Estimated payments (US$ million)(4)

     445.96        117.81        119.83        5.63        5.66  

Ship-or-pay contract with NTS

              

Volume commitment (mmm3/d)

     158.205        158.205        158.205        158.205        158.205  

Volume commitment (mmcf/d)

     5,587.01        5,587.01        5,587.01        5,587.01        5,587.01  

Estimated payments (US$ million)(4)

     1,301.55        1,321.41        1,344.06        1,359.60        1,367.51  

Ship-or-pay contract with TAG (7)

              

Volume commitment (mmm3/d)

     75.87        75.87        75.87        75.87        75.87  

Volume commitment (mmcf/d)

     2,679.35        2,679.35        2,679.35        2,679.35        2,679.35  

Estimated payments (US$ million)(4)

     1,596.24        1,608.45        1,636.02        1,654.94        1,664.56  

 

(1)

23.95% of contracted volume supplied by Petrobras Bolivia.

(2)

Brent crude oil price forecast based on our 2019-2023 Business Plan.

(3)

Estimated payments are calculated using gas prices expected for each year based on our Brent crude oil price forecast. Gas prices may be adjusted in the future based on contract clauses and amounts of natural gas purchased by us may vary annually.

(4)

Amounts calculated based on current prices defined in natural gas transport contracts.

(5)

No estimated payments from 2020 due to Contract TCO-Bolivia prepayment.

(6)

Includes ship-or-pay contracts relating to TBG’s capacity increase.

(7)

We are undertaking divestment processes for TAG, expected to occur until the end of 2019. The ship-or-pay contracts shown with TBG and TAG are not included in our audited consolidated financial statements, since such contracts are intercompany transactions.

Natural Gas Sales Contracts

We sell our gas primarily to local gas distribution companies and to gas-fired plants generally based on standard take-or-pay, long-term supply contracts. This represents 70% of our total sale volumes, and the price formulas under these contracts are mainly indexed to an international fuel oil basket. Additionally, we have a number of sales contracts designed to create flexibility in matching customer demand with our gas supply capabilities. These include interruptible long-term gas sales contracts.

 

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In 2018, we continued to renegotiate some existing long-term natural gas sales contracts with local distribution companies of natural gas in order to promote adjustments to commercial conditions tailored to specific market demands, concluding in negotiations with four local distribution companies that represent 46% of the non-thermoelectric natural gas market, with an average price increase of 64%. This increase resulted from certain factors: (i) change of the parametric formula applicable to the price of natural gas and (ii) annual variation of the indexes that apply to the price of natural gas, i.e. oil baskets that follow the Brent index and the exchange rate. The renegotiations will continue in 2019 with 15 remaining local distribution companies. The table below shows our future gas supply commitments from 2019 to 2023, including sales to both local gas distribution companies and gas-fired power plants:

 

Future Commitments under Natural Gas Sales Contracts, mmm3/d

   2019      2020      2021      2022      2023  

To local gas distribution companies:

              

Related parties(1)

     17.51        17.55        17.34        15.16        14.72  

Third parties

     21.15        20.95        20.92        18.63        18.61  

To gas-fired power plants:

              

Related parties(1)

     2.41        1.61        2.22        2.31        2.46  

Third parties

     11.74        10.75        11.28        12.13        11.87  
  

 

 

    

 

 

    

 

 

       

Total(2)

     52.81        50.85        51.76        48.23        47.67  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Estimated amounts to be invoiced (US$ billion)(3)(4)

     5.23        5.92        6.20        5.66        6.23  

 

(1)

For purposes of this table, “related parties” include all local gas distribution companies and power generation plants in which we have an equity interest and “third parties” refer to those in which we do not have equity interest.

(2)

Estimated volumes are based on “take or pay and ship or pay” agreements in our contracts, expected volumes and contracts under negotiation (including renewals of existing contracts), not maximum sales.

(3)

Estimates are based on outside sales and do not include internal consumption or transfers.

(4)

Prices may be adjusted in the future, according to formula defined in contract, and actual amounts may vary.

Power

Brazilian electricity needs are mainly supplied by hydroelectric power plants (104,139 MW of installed capacity), including small hydroelectric power plants, which in total account for 63.6% of Brazil’s current generation capacity, according to the Brazilian National Electric Agency (Agência Nacional de Energia Elétrica—ANEEL). Hydroelectric power plants are dependent on the annual level of rainfall; in the years where rainfall is abundant, Brazilian hydroelectric power plants will generate more electricity and consequently less generation from thermoelectric power plants will be demanded. The total installed capacity of the Brazilian National Interconnected Power Grid (Sistema Interligado Nacional) in 2018 was 163,654 MW, according to ANEEL. Of this total, 6,148 MW (or 3.8%) was available from 20 thermoelectric plants we operate. These plants are designed to supplement power from the hydroelectric power plants.

In 2018, hydroelectric power plants in Brazil generated 47,707 MWavg, which corresponded to 72% of Brazil’s total electricity needs (66,428 MWavg), according to the Brazilian National Electric System Operator (Operador Nacional do Sistema Elétrico- ONS). Hydroelectric generation capacity is supplemented by other sources of energy (wind, coal, nuclear, fuel oil, diesel oil, natural gas, and others). Total electricity generated by these sources, according to ONS, averaged 18,720 MW in 2018, of which our thermoelectric power plants contributed 2,205MWavg, as compared to 3,165 MWavg in 2017 and 2,252 MWAvg in 2016.

 

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Electricity Sales and Commitments for Future Generation Capacity

Under Brazil’s power pricing regime, a thermoelectric power plant may sell only electricity that is certified by the MME and which corresponds to a fraction of its installed capacity. This certificate is granted to ensure a constant sale of commercial capacity over the course of years to each power plant, given its role within Brazil’s system to supplement hydroelectricity power during periods of unfavorable rainfall. The amount of certified capacity for each power plant is determined by its expected capacity to generate energy over time.

The total capacity certified by the MME (garantia física) may be sold through long-term contracts in auctions to power distribution companies (standby availability), sold through bilateral contracts executed with free customers and used to meet the energy needs of our own facilities.

In exchange for selling this certified capacity, the thermoelectric power plants shall produce energy whenever requested by the national operator (ONS). In addition to a capacity payment, thermoelectric power plants also receive a reimbursement for its variable costs (previously declared to MME to calculate its commercial certified capacity) incurred whenever they are requested to generate electricity.

In 2018, the commercial capacity certified by MME for all thermoelectric power plants controlled by us was 3,900 MWavg, although our total generating capacity was 6,148 MWavg. Of the total 4,720 MWavg of commercial capacity available (capacidade comercial disponível or lastro) for sale in 2018, approximately 59% was sold as standby availability in public auctions in the regulated market (compared to 62% in 2017) and approximately 26% was committed under bilateral contracts and self-production (i.e. sales to related parties) (compared to 25% in 2017).

Under the terms of standby availability contracts, we are paid a fixed amount whether or not we generate any power. Additionally, whenever we have to deliver energy under these contracts, we receive an additional payment for the energy delivered that is set on the auction date and is revised monthly or annually based on inflation-adjusted international fuel price indexes.

Our future commitments under bilateral contracts and self-production are of 1,309 MWavg in 2019, 1,056 MWavg in 2020, and 1,141 MWavg in 2021. The agreements expire gradually, with the last contract expiring in 2028. As existing bilateral contracts expire, we will sell our remaining certified commercial capacity under contracts in new auctions to be conducted by MME or through the execution of new bilateral contracts.

The table below shows the evolution of our installed thermoelectric power plants’ capacity, our purchases in the free market and the associated certificated commercial capacity.

 

     2018      2017      2016  

Installed power capacity and utilization

        

Installed capacity (MW)

     6,148        6,148        6,148  

Certified commercial capacity (MWavg)

     3,900        4,040        4,197  

Purchases in the free market (MWavg)

     821        888        345  

Commercial capacity available (Lastro) (MWavg)

     4,720        4,928        4,542  

 

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The table below shows the allocation of our sales volume between our customers and our revenues for each of the past three years:

 

     Volumes of Electricity
Sold (MWavg)
 
     2018      2017      2016  

Total sale commitments

     4,020        4,270        4,463  

Bilateral contracts

     832        788        835  

Self-production

     399        424        456  

Public auctions to distribution companies

     2,788        3,058        3,172  

Generation volume

     2,205        3,165        2,252  

Revenues (US$ million)(1)

     3,066        4,162        2,470  

 

(1)

Includes electricity sales revenues from the Power segment to other operating segments, service and other revenues from electricity companies.

Fertilizers

Our fertilizer plants in Bahia, Sergipe and Paraná produce ammonia and urea for the Brazilian market. The units in Bahia and Paraná also produce automotive liquid reducing agents (ARLA-32) and the unit in Sergipe also can produce ammonium sulfate. The combined production capacity of these plants is 1,852,000 t/y of urea, 1,406,000t/y of ammonia, 319,000 t/y of ammonium sulfate and 800,000 t/y of ARLA-32, however the ammonium sulfate unit in Sergipe did not operate in 2018. Most of our ammonia production is used to produce urea, and the excess production is mainly sold in the Brazilian market. In 2018, we reduced the utilization rate of these plants, resulting in a decrease of 15.53% in sales compared to 2017, as reflected in our economic evaluation carried out monthly.

The table below shows our ammonia and urea sales and revenues for each of the past three years:

 

     Ammonia and Urea (t/y)  
     2018      2017      2016  

Ammonia

     209,157        279,621        286,268  

Urea

     751,782        858,051        1,033,648  

Revenues (US$ million)(1)

     323        370        465  

 

(1)

Includes nitrogenous fertilizers sales revenues from the fertilizer segment to other operating segments, services and other revenues from fertilizers companies.

Due to major changes in our business context, in 2015, we suspended investments in the following fertilizer projects:

UFN III, with the capacity to produce 1.2 mmt/y of urea and 70 mt/y of ammonia from 2.2 mmm³/d of natural gas; and

UFN V, with the capacity to produce 519,000 t/y of ammonia from 1.3 mmm3/d of natural gas.

In May 2018, we announced the beginning of negotiations with Acron, a Russian company focused on fertilizers production and commercialization, regarding the process of divesting 100% of our assets in Araucaria Nitrogenados S.A. (“ANSA”) and in the Nitrogen Fertilizer Unit III (“UFN III”).

The UFN V fertilizing project was cancelled in January 2016.

 

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In March 2018, we decided to mothball our fertilizer plants located in Sergipe (“Fafen-SE”) and Bahia (“Fafen-BA”). Later, on October 30, 2018, we postponed the mothballing process to January 2019. On January 31, 2019, a Bahia court granted an injunction to suspend the mothballing process of Fafen-BA. However, on March 20, 2019, the court issued a favorable decision reversing the injunction, allowing us to continue the mothballing process. The decision to mothball these units is aligned with our strategic position to fully withdraw from fertilizer production activities, as set forth in our 2019-2023 Business Plan.

In January 2019, we initiated the process to lease Fafen-SE and Fafen-BA by starting the prequalification process, in order to qualify companies that wish to participate in future biddings for the leasing of plants, including the ammonia and urea maritime terminals in the Port of Aratu (BA).

In February 2019, we initiated the mothballing process of Fafen-SE and we continue with the lease bidding process for this unit and for Fafen-BA. We are still waiting for proposals from potential interested parties.

In 2018, we recognized impairment loss of US$ 114 million for the fertilizer plant UFN III (Unidade de Fertilizantes e Nitrogenados III) because its fair value was less than its book value.

In 2017, we decided to halt our operations in Fafen-BA and Fafen-SE, following our plans to optimize our investment portfolio as set out in our 2018-2022 business plan. We assessed for impairment separately and since we could not estimate cash flow projections for the period covered by the former business plan, an impairment loss amounting to US$412 million was recognized with respect to these fertilizer plants.

We recognized impairment losses for the fiscal year ended December 31, 2016 of US$153 million with respect to the UFN III fertilizer facility and of US$140 million with respect to Araucária fertilizer facility, mainly attributable to (i) the use of a higher discount rate, (ii) the appreciation of the real against the U.S. dollar for both projects and (iii) an increase in estimated production costs in Araucária.

For further information, see Note 14 to our audited consolidated financial statements.

Renewable Energy

We have invested, alone and in partnership with other companies, in renewable power generation sources in Brazil, including wind. We currently participate in joint ventures in four wind power plants (Mangue Seco 1, 2, 3 and 4) and we hold indirect interests in two small hydroelectric power plants (Areia and Água Limpa) through our associate Termoelétrica Potiguar S,A – TEP. Additionally, a solar power plant unit UFVAR integrates our assets. The power generation capacity we have (alone and through the equity interests we hold in renewable energy companies) is equivalent to 3.6 MW of hydroelectric capacity, 1.1 MW of solar capacity and 51.5 MW (49.5%) of the 104 MW of Mangue Seco, 1,2,3 and 4 wind capacity. We and our partners sell energy from these plants directly to the Brazilian federal government auctions.

Additionally, we signed in 2018 two memoranda of understanding, one with the Norwegian company Equinor ASA – Equinor (formerly Statoil), to evaluate a joint business development in the offshore wind energy industry in Brazil and another with the French companies Total and Total Eren, to analyze the joint business development in solar energy and wind onshore energy segments in Brazil.

 

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Gas and Power Abroad

We also participate in the gas and power sector in other South American countries. See below our international activities by region:

South America

We conduct gas and power activities in Argentina, Bolivia and in Uruguay.

 

   

In Argentina, through PESA, we previously owned four electric power plants, Pichi Picún Leufú (hydrogeneration), Genelba (gas powered combined cycle), Genelba Plus (gas powered) and EcoEnergia (Cogeneration), and we previously held an interest in two other electric power plants, Central Termelétrica José de San Martín S.A. and Central Termelétrica Manuel Belgrano S.A. and we also previously had a stake in a natural gas transportation company called TGS (Transportadora Gas del Sur). In July 2016, we sold our entire stake in PESA, owned through Petrobras Participaciones S.L. (“PPSL”), to Pampa Energía. Through Petrobras International Braspetro B.V.—PIB BV (Netherlands), we have an interest of 34% in Compañia Mega S.A., a natural gas separation facility.

 

   

In Bolivia, we hold an 11% interest in GTB, owner of the Bolivian section of the Bolivia-to-Brazil (BTB) pipeline that transports natural gas we produce in Bolivia to the Brazilian market.

 

   

In Uruguay, we participate in the two companies that are responsible for the distribution of natural gas by pipelines in the country: (i) Distribuidora de Gás Montevideo S.A., our wholly-owned subsidiary that supplies natural gas to the Montevideo area; and (ii) Conecta S.A., our subsidiary, in which we hold a 55% equity interest (the remaining 45% belongs to ANCAP, Uruguay’s state oil company), that supplies natural gas to the rest of country.

Biofuels

 

Biofuels Key Statistics

 
     2018      2017     2016  
     (US$ million)  

Biofuel:

       

Sales revenues

     255        213       240  

Income (loss) before income taxes

     3        (57     (351

Property, plant and equipment

     90        89       100  

Capital Expenditures According to Our Plan Cost Assumptions

     16        35       96  

Brazil is a global leader in the use and production of biofuels. Since March 2015, the anhydrous ethanol content requirement for the gasoline sold in Brazil is 27%. Biodiesel also has a mandatory blend of 10% in all diesel fuel sold in Brazil since March 2018.

 

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We recognized impairment losses for the fiscal year ended December 31, 2016 on equity-method investments, amounting to US$208 million, mainly related to the former investees Guarani S.A. and Nova Fronteira Bioenergia S.A. For further information on our partnerships and divestments completed in 2018, see Item 4. “Information on the Company—Overview of the Group.” For further information on impairment, see Note 14 to our audited consolidated financial statements.

Biodiesel

In 2018, we supplied 16.1% of Brazil’s biodiesel (assuming 100% of BSBIOS Indústria e Comércio de Biodiesel Sul Brasil S.A. (BSBIOS Sul Brasil) production. We directly own three biodiesel plants (Quixadá biodiesel plant had its own operation stopped in November 2016 due to weak economic results) and it is in restorative hibernation state) and, through our 50% interest in BSBIOS Sul Brasil, we own two additional plants. The biodiesel production capacity of these five plants totals 18.4 mbbl/d.

Ethanol

We have historically been producers of ethanol and sugar and sold the exceeding electricity generated from burning sugarcane bagasse. However, we have strategically decided to leave the biodiesel and ethanol production market, preserving technological competencies in areas with greater development potential. In parallel, we have entered into a number of strategic transactions to that end. In February 2018, we sold, through an auction at B3, shares of São Martinho S.A. (SMTO3). After the sale of 6.6% stake in the total capital of São Martinho S.A., we no longer hold any participation in this company.

Corporate

 

Corporate Key Statistics

 
     2018     2017     2016  
     (US$ million)  

Corporate:

      

Income (loss) before income taxes

     (10,514     (18,111     (13,723

Property, plant and equipment

     1,237       1,629       1,819  

Capital Expenditures According to Our Plan Cost Assumptions

     155       132       230  

Our corporate segment comprises activities that cannot be attributed to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retired employees and their dependents.

In 2018 and 2017, our loss before income taxes included the investigations settled with the DoJ and the SEC, in the amount of US$895 million, and the provision for the class action settlement, in the amount of US$3,449 million.

 

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List of direct subsidiaries and joint operations

As of December 31, 2018, we had 21 direct subsidiaries and two direct joint operations as listed below. Eighteen are entities incorporated under the laws of Brazil and three are incorporated abroad. We also have indirect subsidiaries (including PGF). See Exhibit 8.1 for a complete list of our subsidiaries and joint operations, including their full names, jurisdictions of incorporation and our percentage of equity interest.

 

PETROBRAS
    
BRAZIL        ABROAD
        
Petrobras Distribuidora S.A.—BR      Petrobras Netherlands B.V.—PNBV
        
Petrobras Transporte S.A.—Transpetro      Petrobras International Braspetro—PIB BV
        
Petrobras Logística de Exploração e Produção S.A.—PB-LOG      Braspetro Oil Services Company—Brasoil
        
Transportadora Associada de Gás S.A.—TAG     
      
Petrobras Gás S.A.—Gaspetro     
      
Petrobras Biocombustível S.A.     
      
Petrobras Logística de Gás—Logigás     
      
Liquigás Distribuidora S.A.     
      
Araucária Nitrogenados S.A.     
      
Termomacaé Ltda.     
      
Breitener Energética S.A.     
      
Termobahia S.A.     
      
Baixada Santista Energia S.A.     
      
Petrobras Comercializadora de Energia Ltda.—PBEN     
      
Fundo de Investimento Imobiliário RB Logística—FII     
      
Petrobras Negócios Eletrônicos S.A.—E-Petro     
      
Termomacaé Comercializadora de Energia Ltda     
      
5283 Participações Ltda.     
      
Fábrica Carioca de Catalisadores S.A.—FCC (*)     
      
Ibiritermo S.A. (*)     
      
(*) Joint operations.     

Property, Plant and Equipment

Our most important tangible assets are wells, platforms, refining facilities, pipelines, vessels, other transportation assets, power plants as well as fertilizers and biodiesels plants. Most of these are located in Brazil. We own and lease our facilities and some owned facilities are subject to liens, although the value of encumbered assets is not material.

We have the right to exploit crude oil and gas reserves in Brazil under concession and production sharing agreements, but the reserves themselves are the property of the government under Brazilian law. Item 4. “Information on the Company” includes a description of our reserves and sources of crude oil and natural gas, key tangible assets, and material plans to expand and improve our facilities.

 

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As of December 31, 2018, our property, plant and equipment included US$19,306 million (US$22,614 million as of December 31, 2017) related to the Assignment Agreement entered into by us and the Brazilian federal government in 2010, which grants us the right to carry out prospecting and drilling activities for oil, natural gas and other liquid hydrocarbons located in the pre-salt area, subject to a maximum production of five billion barrels of oil equivalent.

The information gathered made possible the identification of volumes exceeding five million barrels of oil equivalent. However, discussions with the Brazilian federal government are ongoing, and a draft amending the agreement is under the TCU review. For additional information on the TCU review, see “Regulation of the Oil and Gas Industry in Brazil—Assignment Agreement (Cessão Onerosa) and Global Offering.”

For detailed information on the Assignment Agreement see Note 12.4 to our audited consolidated financial statements ended December 31, 2018 and also Item 10. “Additional Information—Material Contracts—Assignment Agreement”.

We recognized impairment charges of US$2,120 million in 2018 (US$836 million in 2017) on property, plant and equipment and intangible assets. Further information about impairment of our assets is provided in Note 14 to our audited consolidated financial statements.

Moreover, following the adoption of IFRS 16, right-of-use assets arising from lease arrangements will be presented as property, plant and equipment. As a result, the amount of this line item within our statement of financial position will increase significantly as set out in Note 6 to our audited consolidated financial statements ended December 31, 2018. We estimate an increase of approximately US$28 billion in the balance of property, plant and equipment due to the initial application of this standard.

Regulation of the Oil and Gas Industry in Brazil

Concession Regime for Oil and Gas

Under Brazilian law, the Brazilian federal government owns all crude oil and natural gas subsoil accumulations in Brazil. The Brazilian federal government holds a monopoly over the exploration, production, refining and transportation of crude oil and oil products in Brazil on its continental shelf, with the exception that companies that were engaged in refining and distribution in 1953 were permitted to continue those activities. Between 1953 and 1997, we were the Brazilian federal government’s exclusive agent for exploiting its monopoly, including the importation and exportation of crude oil and oil products.

As part of a comprehensive reform of the oil and gas regulatory system, the Brazilian Congress amended the Brazilian Constitution in 1995 to authorize the Brazilian federal government to contract with any state or privately-owned company to carry out upstream, oil refining, cross-border commercialization and transportation activities in Brazil of oil, natural gas and their respective products. In August 1997, Brazil enacted Law No. 9,478, which established a concession-based regulatory framework, ended our exclusive right to carry out oil and gas activities, and allowed competition in all aspects of the oil and gas industry in Brazil. Since that time, we have been operating in an increasingly deregulated and competitive environment. Law No. 9,478/1997 also created an independent regulatory agency, the ANP, to regulate the oil, natural gas and renewable fuel industry in Brazil, and to create a competitive environment in the oil and gas sector. Effective January 2, 2002, Brazil deregulated prices for crude oil, oil products and natural gas.

Law No. 9,478/1997 established a concession-based regulatory framework and granted us the exclusive right to exploit crude oil reserves in each of our producing fields under the existing concession contracts for an initial term of 27 years from the date when they were declared commercially profitable. These are known as the “Round Zero” concession contracts. This initial 27-year period for production can be extended at the request of the concessionaire and subject to approval from the ANP.

 

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Starting in 1999, all areas not already subject to concessions became available for public bidding conducted by the ANP. All the concessions that have been granted to us since then were granted through our participation in public bidding rounds or by the Transfer of Rights Agreement. In 2016, the ANP granted us an extension of the production phase of the concession agreement related to Marlim Field and Voador Field until August 2052 and an extension related to Ubarana Field until August 2034. In 2017, the ANP granted us an extension of the production phase of the concession agreement related to Araçás Field until August 2052. In 2018, the ANP granted us an extension of the production phase of the concession agreement related to the Marlim Sul Field, the Marlim Leste Field, Canto do Amaro Field and the Fazenda Alegre Field until 2052.

Taxation under Concession Regime for Oil and Gas

According to the Law No. 9,478/1997 and under our concession agreements for exploration and production activities with ANP, we are required to pay the government the following:

 

   

Signing bonuses paid upon the execution of the concession agreement, which are based on the amount of the winning bid, subject to the minimum signing bonuses published in the relevant bidding guidelines (edital de licitação);

 

   

Annual retention bonuses for the occupation or retention of areas available for exploration and production, at a rate established by the ANP in the relevant bidding guidelines based on the size, location and geological characteristics of the concession block;

 

   

Special participation charges at a rate ranging from 0 to 40% of the net income derived from the production of fields that reach high production volumes or profitability, according to the criteria established in the applicable legislation. Net revenues are gross revenues, based on reference prices for crude oil or natural gas established by Decree No. 2,705 and ANP regulatory acts, less royalties paid, investments in exploration, operational costs and depreciation adjustments and applicable taxes. In 2018, we paid this tax on 17 of our fields, namely Albacora, Albacora Leste, Baleia Azul, Baleia Franca, Barracuda, Caratinga, Jubarte, Leste do Urucu, Lula, Manati, Marlim, Marlim Leste, Marlim Sul, Mexilhão, Rio Urucu, Roncador and Sapinhoá; and

 

   

Royalties, to be established in the concession contracts at a rate ranging between 5% and 10% of gross revenues from production, based on reference prices for crude oil or natural gas established by Decree No. 2,705 and ANP regulatory acts. In establishing royalty rates in the concession contracts, the ANP also takes into account the geological risks and expected productivity levels for each concession. Most of our crude oil production is currently taxed at the maximum royalty rate.

Law No. 9,478/1997 also requires concessionaires of onshore fields to pay to the owner of the land a participation fee that varies between 0.5% and 1.0% of the sales revenues derived from the production of the field.

Production-Sharing Contract Regime for Unlicensed Pre-Salt and Potentially Strategic Areas

Discoveries of large oil and natural gas reserves in the pre-salt areas of the Campos and Santos Basins prompted a change in the legislation regarding oil and gas exploration and production activities.

In 2010, three laws were enacted to regulate exploration and production activities in pre-salt and other potentially strategic areas not subject to existing concessions: Law No. 12,351, Law No. 12,304, and Law No. 12,276. The enacted legislation does not impact the existing pre-salt concession contracts, which cover approximately 28% of the pre-salt areas.

 

 

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Law No. 12,351/2010 regulates production-sharing contracts for oil and gas exploration and production in pre-salt areas not under concession and in potentially strategic areas to be defined by the CNPE. Under Law No. 13,365/2016, which modified Law 12,351/2010, we are no longer required to be the exclusive operator of these areas. CNPE must offer us preference to operate the blocks under production-sharing regime. As part of this regulatory change, we have to announce whether we will exercise our preference right for each of the areas offered, up to thirty (30) days after the notice by the CNPE and present our justifications. After our announcement, CNPE will propose to the Office of the Presidency which areas should be operated by us. The exploration and production rights for these areas will be offered under public bids. Regardless of whether we exercise our right of preference, we will also be able to participate, at our discretion, in the bidding process to increase our interest in these areas. Nonetheless, the winning bidder will be the company that offers to the Brazilian federal government the highest percentage of “profit oil,” which is the production of a certain field after deduction of royalties and “cost oil,” which is the cost associated with oil production.

Law No. 12,734 became partially effective on November 30, 2012, and amended Law 12,351, establishing a royalty rate of 15% applicable to the gross production of oil and natural gas under future production sharing contracts.

Law No. 12,304/2010, authorized the incorporation of a new state-run non-operating company that will represent the interests of the Brazilian federal government in the production-sharing contracts and will manage the commercialization contracts related to the Brazilian federal government’s share of the “profit oil.” This new state-owned company was incorporated on August 1, 2013, named Pré-Sal Petróleo S.A.—PPSA, and will participate in operational committees, with a casting vote and veto powers, as defined in the contract, and will manage and control costs arising from production-sharing contracts. Where production-sharing contracts are concerned, PPSA will exercise its specific legal activities alongside the ANP, the independent regulatory agency that regulates and oversees oil and gas activities under all exploration and production regimes, and the CNPE, the entity that sets the guidelines to be applied to the oil and gas sector, including with respect to the new regulatory model.

Assignment Agreement (Cessão Onerosa) and Global Offering

Pursuant to Law No. 12,276/2010, we entered into an agreement with the Brazilian federal government on September 3, 2010 (Assignment Agreement), under which the government assigned to us the right to conduct activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas, subject to a maximum production of five bnboe. The initial contract price for our rights under the Assignment Agreement was R$74,808 million, which was equivalent to US$19,306 as of December 31, 2018. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”

As a result of the activities under the Assignment Agreement, we have declared the commerciality for the fields of Búzios, Sépia, Itapu, Sul de Lula, Sul de Sapinhoá, Norte and Sul de Berbigão, Norte and Sul de Sururu and Atapu. The commercial production started in the first semester of 2018.

We have created an internal committee to negotiate the revision of the Assignment Agreement with representatives of the Brazilian federal government (i.e., representatives of MME, Ministry of Finance, and the ANP). Both the ANP and we have hired consultancy services provided by international companies specialized in the oil industry (DeGolyer and MacNaughton and Gaffney, Cline & Associates) to help out with the negotiation.

 

 

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The National Council for Energy Policy, through Resolution No. 12/2018, recommended to the MME, the prior submission of the draft amendment to the Assignment Agreement for analysis by the TCU. The MME sent the draft amendment to the TCU on September 14, 2018. The revision of the Assignment Agreement is still subject to the completion of the analysis by the TCU and approval by the National Council for Energy Policy and our governing bodies (i.e., our board of executive officers and our board of directors). The decision to be taken by our board of executive officers must take into consideration recommendations from our Minority Committee. The draft amendment currently under analysis by the TCU consolidates one of the several scenarios discussed among the Brazilian federal government and our commissions, which may result in a credit in favor of us. However, any amount to be received by us can only be confirmed after completion of the applicable stages.

Natural Gas Law of 2009

In March 2009, the Brazilian Congress enacted Law No. 11,909, or Gas Law, regulating activities in the gas industry, including transport, processing, storage, liquefaction, regasification and commercialization. The Gas Law created a concession regime for the construction and operation of new pipelines to transport natural gas of general interest, while maintaining an authorization regime for pipelines subject to international agreements. According to the Gas Law, after a certain exclusivity period, operators (transportadores) will be required to grant access to transport pipelines and maritime terminals, except LNG terminals, to third parties in order to maximize utilization of capacity.

The Gas Law authorized the ANP to regulate prices for the use of gas transport pipelines subject to the new concession regime and to approve prices submitted by carriers (carregadores), according to previously established criteria, for the use of new gas transport pipelines subject to the authorization regime.

Authorizations previously issued by the ANP for natural gas transport will remain valid for 30 years from the date of publication of the Gas Law, and initial carriers (carregadores iniciais) were granted exclusivity in these pipelines for 10 years. All pipelines that our subsidiaries currently own and operate in Brazil are subject to an authorization regime. The ANP will issue regulations governing third-party access and carrier compensation if no agreement is reached between the parties.

The Gas Law also authorized certain consumers, who can purchase natural gas on the open market or obtain their own supplies of natural gas, to construct facilities and pipelines for their own use in the event local gas distributors controlled by the states, which have monopoly over local gas distribution, do not meet their distribution needs. These consumers are required to delegate the operation and maintenance of the facilities and pipelines to local gas distributors, but they are not required to sign gas supply agreements with the local gas distributors.

In December 2010, Decree No. 7,382 was enacted in order to regulate Chapters I to VI and VIII of the Gas Law as it relates to activities in the gas industry, including transportation and commercialization. Since the publication of this decree, a number of administrative regulations were enacted by the ANP and the MME in order to regulate various issues related to the Gas Law and Decree No. 7,382 that needed to be further clarified. Among those is ANP Resolution No. 51/2013, which prevents a carrier from holding any equity interest in companies holding concessions or authorizations for gas transport pipelines. Resolution No. 51/2013 applies only to the concessions granted after its publication, not affecting, therefore, the transportation of our natural gas production through pipelines operated by its subsidiaries and subject to the previous authorization regime.

Another important resolution is ANP Resolution No. 52/2011, which (i) establishes that it is the responsibility of ANP to authorize the activity of commercialization of natural gas, within the competence of the Brazilian federal government; (ii) regulates the registration of the gas seller agent, and (iii) regulates the registration of gas sales and purchase agreements.

 

 

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In June 2016, the MME created the program Gas to Grow, or Gás para Crescer, which aims to promote a competitive market environment to achieve the effective development of gas trading in Brazil, enabling the entry of new agents into the gas market. Therefore, new regulations on the natural gas market shall be created in 2019.

In December 2018, Decree No. 9.616 amended Decree No. 7.382/2010 to allow the change of gas transmission system from capacity hired under the point-to-point system on long-term contracts to an entry-exit system.

Price Regulation

Until Law No. 9,478 in 1997, the Brazilian federal government had the power to regulate all aspects of the pricing of crude oil, oil products, ethanol, natural gas, electric power and other energy sources. In 2002, the government eliminated price controls for crude oil and oil products, although it retained regulation over certain natural gas sales contracts and electricity. Concurrently, the Brazilian federal government is authorized to adjust taxes applicable to crude oil, oil and natural gas products, in order to balance price stability to end consumers and also to increase its tax revenues, which it has done eventually.

In May 2018, the Brazilian federal government established a diesel subsidy program by Provisional Measures No. 838 and 847 (later converted into Law No. 13,723) and regulated by Decree No. 9,392, both dated of May 30, 2018, and Decrees No. 9,454/2018 and No. 9,403/2018, extended to all producers and importers, for the period between May 30, 2018 and December 31, 2018.

Law No. 13,723, enacted on October 4, 2018, establishes a subsidy program offered by the Brazilian federal government as an incentive for agents that commercialize diesel to reduce their prices and keep them stable during a predetermined period. In return, those who choose to join the program, may obtain a refund for the discount offered, if there is evidence that diesel has been commercialized under a price equal or lower to the price defined for the predetermined period.

We adhered to all phases of the economic subsidy program for the commercialization of diesel.

Environmental Regulations

All phases of the crude oil and natural gas business present environmental risks and hazards. Our facilities in Brazil are subject to a wide range of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment, and they fall under the regulatory authority of the Conselho Nacional do Meio Ambiente (National Council for the Environment, or CONAMA).

Our offshore activities are subject to the administrative authority of IBAMA, which issues operating and drilling licenses. We are required to submit reports, including safety and pollution monitoring reports to IBAMA in order to maintain our licenses. This way, we maintain an ongoing communication channel with the environmental bodies, in order to improve issues connected with the environmental management of our exploration, production and refining processes of oil and natural gas. Recently, we designed actions and measures, together with IBAMA, to adjust the disposal of water produced in some of our offshore platforms in order to accommodate recently issued requirements by IBAMA. All of these actions are being met by us within the schedule previously defined, which end date is expected to be in 2020.

In addition to help ensuring the safety of navigation, the Brazilian maritime authority also works towards the prevention of environmental pollution, with random or periodic surveys of offshore units.

 

 

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Most of the onshore environmental, health and safety conditions are controlled either at the federal or the state level depending on the localization of our facilities and the type of activity under development. However, it is also possible for these conditions to be controlled on a local basis whenever the activities generate a local impact or are established in a county conservation unit. Under Brazilian law, there is strict and joint liability for environmental damage, mechanisms for enforcement of environmental standards and licensing requirements for polluting. Activities.

Individuals or entities whose conduct or activities cause harm to the environment are subject to criminal, civil and administrative sanctions. Government environmental protection agencies may also impose administrative sanctions for noncompliance with environmental laws and regulations, including:

 

   

Fines;

 

   

Partial or total suspension of activities;

 

   

Requirements to fund reclamation and environmental projects;

 

   

Forfeiture or restriction of tax incentives or benefits;

 

   

Closing of establishments or operations; and

 

   

Forfeiture or suspension of participation in credit lines with official credit establishments.

We are subject to a number of administrative and legal proceedings relating to environmental matters. For more information about these proceedings, see Item 8. “Financial Information—Legal Proceedings.” And Note 30 to our audited consolidated financial statements included in this annual report.

In 2018, we invested US$0.8 billion in environmental projects, compared to US$0.8 billion in 2017 and US$0.9 billion in 2016. These investments continued to be primarily directed at reducing emissions and wastes from industrial processes, managing water use and effluents, remedying impacted areas, implementing new environmental technologies, upgrading our pipelines and improving our ability to respond to emergencies.

New Taxation Model for the Oil and Gas Industry

On December 28, 2017, the Brazilian federal government enacted Law No. 13,586, which outlined a new taxation model for the oil and gas industry and, along with the Decree 9,128/2017, established a new special regime for exploration, development and production of oil, gas and other liquid hydrocarbons named Repetro-Sped, which will expire in December 2040.

This regime provides for the continuation of total tax relief over goods imported with temporary permanence in Brazil, as previously established by the former Repetro (Special Customs Regime for the Export and Import of Goods designated to Exploration and Production of Oil and Natural Gas Reserves), and adds this relief to goods permanently held in Brazil. Accordingly, the absence of the need to return such goods to foreign countries eliminates future cost of removal. This benefit allowed for the migration of all the goods acquired in the former REPETRO to the REPETRO-Sped.

Since 2018, we have been transferring the ownership of oil and gas assets under this regime from our foreign subsidiaries to the parent company in Brazil and we expect to finish this process in 2020.

Following the creation of Repetro-Sped, some Brazilian states, pursuant to a decision by the Brazilian National Council of Finance Policies (CONFAZ), agreed to grant tax incentives relating to VAT (ICMS) over transactions under this regime to the extent each state enacts its specific regulation providing for the tax relief on oil and gas industry.

 

 

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Health, Safety and Environmental Initiatives

The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated energy company.

We have a Health, Safety and Environmental (HSE) Committee (Comitê de Segurança, Meio Ambiente e Saúde) composed of three members of our board of directors who are responsible for assisting our board in the following matters:

 

   

Definition of strategic goals in relation to HSE matters;

 

   

Establishment of global policies related to the strategic management of HSE matters within our group of companies; and

 

   

Assessment of the conformity of our strategic plan to its global HSE policies, among others.

Our efforts to address health, safety and environmental concerns and ensure compliance with environmental regulations (which in 2018 totaled an investment of R$5.9 billion, or US$1.6 billion) involve the management of environmental costs related to production and operations, pollution control equipment and systems, projects to rehabilitate degraded areas, hazardous waste minimization actions, safety procedures and initiatives for emergency prevention and control, health and safety programs as well as:

 

   

An HSE management system that seeks to minimize the impacts of operations and products on health, safety and the environment, reduce the use of natural resources and pollution and prevent accidents;

 

   

The Frota Nacional de Petroleiros (National Fleet of Vessels) has been fully certified by the International Maritime Organization (IMO) International Management Code for Safe Operation of Ships and for Pollution Prevention (ISM Code) since December 1997;

 

   

Regular and active engagement with the MME and IBAMA, in order to discuss environmental issues related to new oil and gas production projects and other transportation and logistical aspects of our operations;

 

   

A strategic goal to reduce the intensity of greenhouse gas emissions from our operations, along with a set of performance indicators with targets to monitor progress with respect to this goal; and

 

   

HSE functional participation in divestment projects and in the stage-gate process of capital projects. We evaluate each of our operational projects to identify risks and to ensure compliance with all of our HSE requirements and the adoption of the best HSE practices throughout a project’s life cycle. In addition, we conduct more extensive environmental studies for new projects when required by applicable environmental legislation.

In 2018, our emissions were 62 million tons of CO2 equivalent. In 2017, we issued 67 million tons of CO2 equivalent and, in 2016, 66.5 million tons of CO2 equivalent. We are committed to reducing the intensity of greenhouse gas emissions from our processes and products through several initiatives, including reduction of gas flaring, energy efficiency measures and operational improvements.

The global reductions were mostly due to a lower production of electricity in our thermal power facilities. Excluding power generation and considering only oil and gas activities, we also observe a 5 year trend in emissions reductions, despite increased production. We are committed to improving the operational carbon intensity of our operations, through initiatives such as the reduction of gas flaring, configuration of new assets and operational improvements.

 

 

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In March 2018, our board of directors has approved our participation in the Oil and Gas Climate Initiative (OGCI). This is one of the main initiatives of the oil and gas sector to mitigate greenhouse gas emissions. OGCI Climate investments, the initiative’s investment arm to support the development, deployment and expansion of low-emission technologies will be around US$1 billion over the next ten years, with disbursements distributed equally among all OGCI members during this period. The participation in OGCI is aligned with our business strategy, as disclosed in our 2019-2023 Business Plan, and reinforces our commitment to reduce emissions and toward a more efficient energy matrix. Additionally, in September 2018, we joined the World Bank’s “Zero Routine Flaring by 2030” program.

Eliminating fatal accidents and achieving performance levels comparable to the best international oil and gas operators when it comes to the prevention of injuries to our employees and third parties are the two most important goals set by our safety management. Although we develop prevention programs in all of our operating units, we recorded 6 fatalities involving our own and contractors’ employees in 2018 (compared to 7 in 2017). We investigate all accidents reported in order to identify their causes and then take preventive and corrective actions, which are regularly monitored once they are adopted. In cases of serious accidents, we send out company-wide alerts to enable other operating units to assess the probability of similar events occurring in their own operations.

Environmental Remediation Plans and Procedures

As part of our environmental plans, procedures and efforts, we maintain detailed response and remediation contingency plans to be implemented in the event of an oil spill or leak from our offshore operations. The execution of these programs are approved and authorized by IBAMA.

In order to respond to these events, we have dedicated oil spill recovery vessels fully equipped for oil spill control and firefighting, support boats and other vehicles, additional support and recovery boats available to fight offshore oil spills and leaks, containment booms, absorbent booms and oil dispersants, among other resources. These resources are distributed in Environmental Defense Centers (CDAs), located in strategic areas, in order to ensure rapid and coordinated response to onshore or offshore oil spills.

We have around 300 trained workers available to respond to oil spills 24 hours a day, seven days a week, and we can mobilize additional trained workers for shoreline cleanups on short notice from a large group of trained environmental agents in the country. While these workers are located in Brazil, they are also available to respond to an offshore oil spill outside of Brazil.

Since 2012, we have been a shareholder of the Oil Spill Response Limited—OSRL, an international organization that brings together over 160 corporations, including oil major, national/independent oil companies, energy related companies as well as other companies operating elsewhere in the oil supply chain. OSRL participates in the Global Response Network, an organization composed of several other companies dedicated to fighting oil spills. As a member of the OSRL, we have access to all resources available through that network, and we also subscribe to their Subsea Well Intervention Services, which provides swift international deployment of response-ready capping and containment equipment. The capping equipment is stored and maintained at bases worldwide, including Brazil. An OSRL Brazilian base opened in March 2014 and is now operational.

In 2018, we conducted 21 emergency drills of regional scope with the Brazilian navy, the civil defense, firefighters, the military police, environmental organizations and local governmental and community entities.

We set up a Zero Spill Plan, aiming at optimizing management and reducing the risk of oil spills in our operations. This plan encompasses investments to improve the management of processes and to ensure the integrity of our equipment and installations. Additionally, we have a model of communication, processing and recording of oil spills that permits the daily monitoring of these incidents, their impacts and mitigation measures. In 2018, we had oil spills totaling 18.47 m3, compared to 35.8 m3 in 2017 and 51.9 m3 in 2016.

 

 

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We continue to evaluate and develop initiatives to address HSE concerns and to reduce our exposure to HSE risks on capital projects and operations.

Insurance

We maintain several insurance policies, including policies against fire, operational risk, engineering risk, property damage coverage for onshore and offshore assets such as fixed platforms, floating production systems and offshore drilling units, hull insurance for tankers and auxiliary vessels, third party liability insurance and transportation insurance. The coverages of these policies are contracted according to the objectives we define and the limitations imposed by the global insurance and reinsurance markets. Although some policies are issued in Brazil, most of our policies are reinsured abroad with reinsurers rated A- or higher by Standard & Poor’s, or 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$2.5 billion for refineries and US$2.1 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 civil responsibility policy with respect to our onshore and offshore activities in Brazil, including losses related to third parties 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 (“P&I”) 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