20-F 1 pbraform20f2010.htm FORM 20F 2010 pbraform20f2010.htm - Generated by SEC Publisher for SEC Filing

 

As filed with the Securities and Exchange Commission on May 25, 2011

 

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, 2010

Commission File Number 001-15106

Petróleo Brasileiro S.A.—Petrobras

(Exact name of registrant as specified in its charter)

Commission File Number: 001-33121

Petrobras International Finance Company

(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)

Cayman Islands

(Jurisdiction of incorporation or organization)

__________

Avenida República do Chile, 65

20031-912 – Rio de Janeiro – RJ

Brazil

(Address of principal executive offices)

Almir Guilherme Barbassa
(55 21) 3224-2040 – barbassa@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)

4th Floor, Harbour Place

103 South Church Street

P.O. Box 1034GT – BWI

George Town, Grand Cayman

Cayman Islands

(Address of principal executive offices)

Sérvio Túlio da Rosa Tinoco

(55 21) 3224-1410 – ttinoco@petrobras.com.br
Avenida República do Chile, 65 – 3rd 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 2 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 2 Preferred Shares

New York Stock Exchange

6.125% Global Notes due 2016, issued by PifCo

New York Stock Exchange

3.875% Global Notes due 2016, issued by PifCo

New York Stock Exchange

5.875% Global Notes due 2018, issued by PifCo

New York Stock Exchange

7.875% Global Notes due 2019, issued by PifCo

New York Stock Exchange

5.75% Global Notes due 2020, issued by PifCo

New York Stock Exchange

5.375% Global Notes due 2021, issued by PifCo

New York Stock Exchange

6.875% Global Notes due 2040, issued by PifCo

New York Stock Exchange

6.750% Global Notes due 2041, issued by PifCo

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:

TITLE OF EACH CLASS:

9.750% Senior Notes due 2011, issued by PifCo

9.125% Global Notes due 2013, issued by PifCo

7.75% Global Notes due 2014, issued by PifCo

8.375% Global Notes due 2018, issued by PifCo

The number of outstanding shares of each class of stock of Petrobras and PifCo as of December 31, 2010 was:

7,442,454,142 Petrobras Common Shares, without par value 

5,602,042,788 Petrobras Preferred Shares, without par value

300,050,000 PifCo Common Shares, at par value U.S.$1 per share

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

Yes [Petrobras] No £ 

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

Large accelerated filer  [Petrobras]         Accelerated filer £         Non-accelerated filer [PifCo]

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

Page

Forward-Looking Statements

5

Glossary of Petroleum Industry Terms

7

Conversion Table

10

Abbreviations

11

Presentation of Financial Information 

12

Petrobras

12

PifCo

13

Recent Developments

13

Presentation of Information Concerning Reserves

14

PART I

Item 1.           Identity of Directors, Senior Management and Advisers

15

Item 2.           Offer Statistics and Expected Timetable

15

Item 3.           Key Information

15

Selected Financial Data

15

Risk Factors

18

Risks Relating to Our Operations

18

Risks Relating to PifCo

23

Risks Relating to Our Relationship with the Brazilian Federal Government

24

Risks Relating to Brazil

25

Risks Relating to Our Equity and Debt Securities

25

Item 4.           Information on the Company

28

History and Development

28

Overview of the Group

28

Exploration and Production

30

Refining, Transportation and Marketing

38

Distribution

44

Gas and Power

45

International

52

Corporate

57

Information on PifCo

58

Organizational Structure

60

Property, Plants and Equipment

62

Regulation of the Oil and Gas Industry in Brazil

62

Health, Safety and Environmental Initiatives

66

Insurance

68

Additional Reserves and Production Information

69

Item 4A.         Unresolved Staff Comments

79

Item 5            Operating and Financial Review and Prospects

79

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

79

Overview

79

Sales Volumes and Prices

80

Effect of Taxes on Our Income

81

Inflation and Exchange Rate Variation

81

Results of Operations

83

Additional Business Segment Information

96

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

97

Overview

97

Purchases and Sales of Crude Oil and Oil Products

98

Results of Operations—2010 compared to 2009

98

 

 

2


 

TABLE OF CONTENTS


Page

Results of Operations—2009 compared to 2008

99

Liquidity and Capital Resources

100

Petrobras

100

PifCo

104

Contractual Obligations

107

Petrobras

107

PifCo

107

Critical Accounting Policies and Estimates

107

Impact of New Accounting Standards

111

Research and Development

112

Trends

113

Item 6.           Directors, Senior Management and Employees

114

Directors and Senior Management

114

Compensation

121

Share Ownership

121

Fiscal Council

122

Petrobras Audit Committee

122

Other Advisory Committees

123

Petrobras Ombudsman

123

PifCo Advisory Committees

123

Employees and Labor Relations

123

Item 7.           Major Shareholders and Related Party Transactions

126

Major Shareholders

126

PifCo Related Party Transactions

128

Item 8.           Financial Information

129

Petrobras Consolidated Statements and Other Financial Information

129

PifCo Consolidated Statements and Other Financial Information

129

Legal Proceedings

130

Dividend Distribution

135

Item 9.           The Offer and Listing

136

Petrobras

136

PifCo

137

Item 10.         Additional Information

138

Memorandum and Articles of Incorporation of Petrobras

138

Restrictions on Non-Brazilian Holders

146

Transfer of Control

146

Disclosure of Shareholder Ownership

147

Memorandum and Articles of Association of PifCo

147

Material Contracts

151

Petrobras Exchange Controls

158

Taxation Relating to Our ADSs and Common and Preferred Shares

159

Taxation Relating to PifCo’s Notes

166

Documents on Display

170

Item 11.        Qualitative and Quantitative Disclosures about Market Risk

171

Petrobras

171

PifCo

174

Item 12.         Description of Securities other than Equity Securities

176

American Depositary Shares

176

 

 

 

3


 

TABLE OF CONTENTS

 

Page

PART II

Item 13.         Defaults, Dividend Arrearages and Delinquencies

177

Item 14.         Material Modifications to the Rights of Security Holders and Use of Proceeds

177

Item 15.         Controls and Procedures

177

Evaluation of Disclosure Controls and Procedures

177

Management’s Report on Internal Control over Financial Reporting

177

Changes in Internal Controls

178

Item 16A.      Audit Committee Financial Expert

178

Item 16B.       Code of Ethics

178

Item 16C.       Principal Accountant Fees and Services

179

Audit and Non-Audit Fees

179

Audit Committee Approval Policies and Procedures

180

Item 16D.      Exemptions from the Listing Standards for Audit Committees

180

Item 16E.       Purchases of Equity Securities by the Issuer and Affiliated Purchasers

180

Item 16F.       Change in Registrant’s Certifying Accountant

180

Item 16G.      Corporate Governance

180

PART III

Item 17.         Financial Statements

182

Item 18.         Financial Statements

182

Item 19.         Exhibits 

182

Signatures

186

Index To Audited Consolidated Financial Statements Petróleo Brasileiro S.A.—Petrobras

188

Index To Audited Consolidated Financial Statements Petrobras International Finance Company

188

 

 

 

4


 

FORWARD-LOOKING STATEMENTS

Many statements made in this annual report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act), that are not based on historical facts and are not assurances of future results.  Many of the forward-looking statements contained in this annual report may be identified by the use of forward-looking words, such as “believe,” “expect,” “anticipate,” “should,” “planned,” “estimate” and “potential,” among others.  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 petroleum, natural gas and oil products, petrochemicals, power generation, biofuels and other sources of renewable energy;

         our projected and targeted capital expenditures and other costs, commitments and revenues;

         our liquidity and sources of funding;

         development of additional revenue sources; and

         the impact, including cost, of acquisitions.

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 factors. These factors include, among other things:

         our ability to obtain financing;

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

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

         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;

         receipt of governmental approvals and licenses;

5


 

 

Table of Contents

         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; and

         other factors discussed below under “Risk Factors.”

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

This is the annual report of both Petróleo Brasileiro S.A.—Petrobras (Petrobras) and its direct wholly owned Cayman Islands subsidiary, Petrobras International Finance Company (PifCo).  PifCo’s operations, which consist principally of purchases and sales of crude oil and oil products, are described in further detail below.

Unless the context otherwise requires, the terms “Petrobras,” “we,” “us,” and “our” refer to Petróleo Brasileiro S.A.—Petrobras and its consolidated subsidiaries and special purpose companies, including Petrobras International Finance Company.  The term “PifCo” refers to Petrobras International Finance Company and its subsidiaries.

6


 

GLOSSARY OF PETROLEUM INDUSTRY TERMS

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

ANEEL

The Agência Nacional de Energia Elétrica (National Electrical Energy Agency), or ANEEL, is the federal agency that regulates the electricity industry in Brazil.

ANP

The Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (National Petroleum, Natural Gas and Biofuels Agency), or ANP, is the federal agency that regulates the oil, natural gas and renewable fuels industry in Brazil.

API°

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

Barrels

Barrels of crude oil.

BSW

Basic sediment and water, a measurement of the water and sediment content of flowing crude oil.

Catalytic cracking

A process by which hydrocarbon molecules are broken down (cracked) into lighter fractions by the action of a catalyst.

Coker

A vessel in which bitumen is cracked into its fractions.

Condensate

Light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.

CNPE

The Conselho Nacional de Política Energética (National Energy Policy Council), or CNPE, is an advisory body of the President of the Republic responsible for formulating energy policies and guidelines.

Deep water

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.

EWT

Extended well test.

Exploration Area

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

FPSO

Floating Production, Storage and Offloading Unit.

Heavy crude oil

Crude oil with API density less than or equal to 22°.

Intermediate crude oil

Crude oil with API density higher than 22° and less than or equal to 31°.

Light crude oil

Crude oil with API density higher than 31°.

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.

 

7


 

MME

The federal Ministry of Mines and Energy, or MME.

NGLs

Natural gas liquids, which are light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.

Oil

Crude oil, including NGLs and condensates.

Pre-salt reservoir

A geological formation containing oil or natural gas deposits located beneath an evaporitic layer.

Post-salt reservoir

A geological formation containing oil or natural gas deposits located above an evaporitic layer.

Proved reserves

Consistent with the definitions in the SEC’s Amended 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 average price during the 12-month period prior to December 31, 2010, 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, provides support for the engineering analysis on which the project or program was based.

Proved developed reserves.

Proved developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in 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 reserves estimate if the extraction is by means not involving a well.

 
 

8


 

Proved undeveloped reserves

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  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.

SS

Semi-submersible unit.

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. 

TLWP

Tension Leg Wellhead Platform.

Total depth

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

Ultra-deep water

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

 

9


 

 

Table of Contents

CONVERSION TABLE

1 acre

=

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 km2

=

247 acres

 

 

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)

 

 

10


 

 

Table of Contents

ABBREVIATIONS

bbl

Barrels

bn

Billion (thousand million)

bnbbl

Billion barrels

bncf

Billion cubic feet

bnm3

Billion cubic meters

boe

Barrels of oil equivalent

bbl/d

Barrels per day

cf

Cubic feet

GOM

Gulf of Mexico

GW

Gigawatts

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

mmbbl

Million barrels

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/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

P$

Argentine pesos

R$

Brazilian reais 

t

Metric ton

tcf

Trillion cubic feet

U.S.$

United States dollars

/d

Per day

/y

Per year

 

11


 

PRESENTATION OF FINANCIAL INFORMATION

In this annual report, references to “real,” “reais” or “R$” are to Brazilian reais and references to “U.S. dollars” or “U.S.$” are to the 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.

Petrobras

The audited consolidated financial statements of Petrobras and our consolidated subsidiaries as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the accompanying notes, contained in this annual report have been presented in U.S. dollars and prepared in accordance with U.S. generally accepted accounting principles, or U.S. GAAP.  See Item 5. “Operating and Financial Review and Prospects” and Note 2(a) to our audited consolidated financial statements.  U.S. GAAP differs in certain respects from International Financial Reporting Standards (IFRS), as issued by the International Financial Reporting Standards Board (IASB) and applied by Petrobras in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the Brazilian Securities and Exchange Commission (CVM).  Brazilian Corporate Law was amended in 2007 to permit accounting practices adopted in Brazil (Brazilian GAAP) to converge with IFRS.  We have prepared our consolidated financial statements, in reais, in accordance with IFRS beginning with the three-month period ended March 31, 2010.  We are currently evaluating the possibility of discontinuing U.S. GAAP reporting and adopting IFRS as issued by the IASB as the basis for the audited consolidated financial statements contained in our annual report on Form 20-F for the year ended December 31, 2011.

Our functional currency is the Brazilian real.  As described more fully in Note 2(a) to our audited consolidated financial statements, the U.S. dollar amounts as of the dates and for the periods presented in our audited consolidated financial statements have been recalculated or translated from the real amounts in accordance with the criteria set forth in Accounting Standard Codification – ASC Topic 830 – Foreign Currency Matters.  U.S. dollar amounts presented in this annual report have been translated from reais at the period-end exchange rate for balance sheet items and the average exchange rate prevailing during the period for income statement and cash flow items.

Unless the context otherwise indicates:

         historical data contained in this annual report that were not derived from the audited consolidated financial statements have been translated from reais on a similar basis;

         forward-looking amounts, including estimated future capital expenditures, have all been based on our Petrobras 2020 Strategic Plan, which covers the period from 2009 to 2020, and on our 2010-2014 Business Plan, and have been projected on a constant basis and have been translated from reais  at an estimated average exchange rate of R$1.78 to U.S.$1.00, in accordance with our 2010-2014 Business Plan.  In addition, in accordance with our 2010-2014 Business Plan and our 2011 Annual Business Plan, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$93 per barrel for 2011, U.S.$82 per barrel for 2012, U.S.$82 per barrel for 2013, U.S.$82 per barrel for 2014 and U.S.$82 per barrel for 2015 adjusted for our quality and location differences, unless otherwise stated; and

         estimated future capital expenditures are based on the most recently budgeted amounts, which may not have been adjusted to reflect all factors that could affect such amounts.

12


 

PifCo

PifCo’s functional currency is the U.S. dollar.  Substantially all of PifCo’s sales are made in U.S. dollars and all of its debt is denominated in U.S. dollars.  Accordingly, PifCo’s audited consolidated financial statements as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with U.S. GAAP and include PifCo’s wholly owned subsidiaries: Petrobras Europe Limited (PEL), Petrobras Finance Limited (PFL), Bear Insurance Company Limited (BEAR) and Petrobras Singapore Private Limited (PSPL).

RECENT DEVELOPMENTS

Global Offering of Shares

On September 29, 2010, we issued 2,293,907,960 common shares, including common shares in the form of American Depositary Shares (ADSs), and 1,788,515,136 preferred shares, including preferred shares in the form of ADSs, in a global public offering consisting of a registered offering in Brazil and an international offering, which included a registered offering in the United States. On October 1, 2010, we issued an additional 75,198,838 common shares (including common shares in the form of ADSs) and 112,798,256 preferred shares (including preferred shares in the form of ADSs) pursuant to the exercise of the underwriters’ over-allotment option. The aggregate proceeds of the global offering to us, after underwriting discounts and commissions and including the exercise of the underwriters’ over-allotment option, was approximately U.S.$70 billion. We applied the net proceeds from the global offering to pay the initial purchase price under the Assignment Agreement described below and to continue to develop all of our business segments in accordance with Petrobras’ 2010-2014 Business Plan.

Assignment Agreement (Cessão Onerosa

On September 3, 2010, we entered into an agreement with the Brazilian federal government (the 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 billion barrels of oil equivalent. For further information on the Assignment Agreement, see Item 10. “Material contracts—Petrobras—Assignment Agreement.”

 

13


 

PRESENTATION OF INFORMATION CONCERNING RESERVES

Petrobras continues to utilize the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report.  In accordance with these rules, adopted by Petrobras at year-end 2009, the year-end 2010 and 2009 reserve volumes have been estimated using 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 include non-traditional reserves, such as synthetic oil and gas.  Year-end 2008 reserve volumes were estimated using year-end prices.  In addition, the amended rules also adopted a reliable technology definition that permits reserves to be added based on field-tested technologies.  The adoption of the SEC’s rules for estimating and disclosing oil and gas reserves and the FASB’s issuance of the Accounting Standards Update No. 2010-03 “Oil and Gas Reserve Estimation and Disclosure” in December 2010 generated no material impact on our reported reserves or on our consolidated financial position or results of operations.  DeGolyer and MacNaughton (D&M) provided estimates of most of our net domestic reserves as of December 31, 2010.  D&M also provided estimates of most of our net international reserves where we are the operator as of December 31, 2010.  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 14, 2011, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling 12.91 billion barrels of crude oil and condensate and 14.24 trillion cubic feet of natural gas.  The reserve estimates filed with the ANP and those provided herein differ by approximately 25.9%.  This difference is due to: (i) the ANP requirement to estimate 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 current oil prices as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of reserves in Brazil.

We also file reserve estimates from our international operations with various governmental agencies under the guidelines of the Society of Petroleum Engineers, or SPE.  The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 0.47 billion barrels of crude oil and NGLs and 1,406 billion cubic feet of natural gas, which is approximately 15% higher than the reserve estimates calculated under Regulation S-X, as provided herein.  This difference occurs because of different technical criteria for booking proved reserves, including the use of current oil prices as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of international reserves.  In addition, we have not yet included all volumes from the Gulf of Mexico fields because there is no production history available for analogous reservoirs.

14


 

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

Petrobras

The following tables set forth our selected consolidated financial data, presented in U.S. dollars and prepared in accordance with U.S. GAAP.  The data for each of the five years in the period ended December 31, 2010 has been derived from our audited consolidated financial statements, which were audited by KPMG Auditores Independentes for the years ended December 31, 2010, 2009, 2008, 2007 and 2006.  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.”  Certain prior year amounts for 2009, 2008, 2007 and 2006 have been reclassified to conform to current year presentation standards.  These reclassifications had no impact on our net income or any material effect on our consolidated financial statements

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BALANCE SHEET DATA—PETROBRAS

 

As of December 31,

 

2010

2009

2008

2007

2006

 

(U.S.$ million)

Assets:

 

 

 

 

 

Total current assets

63,863

42,644

26,758

29,140

30,955

Property, plant and equipment, net

218,567

136,167

84,719

84,282

58,897

Investments in non-consolidated companies and other investments          

6,312

4,350

3,198

5,112

3,262

Total non-current assets

19,941

17,109

11,020

11,181

5,566

Total assets

308,683

200,270

125,695

129,715

98,680

Liabilities and shareholders’ equity:

 

 

 

 

 

Total current liabilities

33,552

30,965

24,756

24,468

21,976

Total long-term liabilities(1)

31,263

24,844

17,731

21,534

16,829

Long-term debt(2)

60,471

49,041

20,640

16,202

13,610

Total liabilities

125,286

104,850

63,127

62,204

52,415

Shareholders’ equity

 

 

 

 

 

Shares authorized and issued:

 

 

 

 

 

Preferred share

45,840

15,106

15,106

8,620

7,718

Common share

63,906

21,088

21,088

12,196

10,959

Capital reserve and other comprehensive income

71,748

57,864

25,715

44,363

25,622

Petrobras’ shareholders’ equity

181,494

94,058

61,909

65,179

44,299

Non-controlling interest

1,903

1,362

659

2,332

1,966

Total equity

183,397

95,420

62,568

67,511

46,265

Total liabilities and shareholders’ equity

308,683

200,270

125,695

129,715

98,680

 


(1)                  Excludes long-term debt.

(2)                  Excludes current portion of long-term debt.

INCOME STATEMENT DATA—PETROBRAS

 

For the Year Ended December 31,

 

2010

2009

2008

2007

2006

 

(U.S.$ million, except for share and per share data)

 

 

Net operating revenues

120,052

91,869

118,257

87,735

72,347

Operating income(1)

24,158

21,869

25,294

20,451

19,844

Net income for the year attributable to Petrobras(2)

19,184

15,504

18,879

13,138

12,826

Weighted average number of shares outstanding:(3)

 

 

 

 

 

Common

5,683,061,430

5,073,347,344

5,073,347,344

5,073,347,344

5,073,347,344

Preferred

4,189,764,635

3,700,729,396

3,700,729,396

3,700,729,396

3,699,806,288

Operating income per:(1)(3)

 

 

 

 

 

Common and Preferred Shares

2.45

2.49

2.88

2.33

2.26

Common and Preferred ADS(4)

4.90

4.98

5.76

4.66

4.52

Basic and diluted earnings per:(2)(3)

 

 

 

 

 

Common and Preferred Shares

1.94

1.77

2.15

1.50

1.46

Common and Preferred ADS(4)

3.88

3.54

4.30

3.00

2.92

Cash dividends per:(3)(5)

 

 

 

 

 

Common and Preferred shares

0.69

0.59

0.47

0.35

0.42

Common and Preferred ADS(4)

1.37

1.18

0.94

0.70

0.84

 


(1)           Beginning in 2008, we have accounted for employee benefit expenses for non-active participants as part of operating expenses rather than non-operating expenses.  This reclassification had no effect on our consolidated net income, other than disclosure of our consolidated statements of income.  Operating income amounts for all periods give effect to this reclassification.

(2)           Our net income represents our income from continuing operations.

(3)           We carried out a two-for-one stock split on April 25, 2008.  Share and per share amounts for all periods give effect to the stock split.

(4)           We carried out a four-for-one reverse stock split in July 2007 that changed the ratio of underlying shares to ADSs from four shares for each ADS to two shares for each ADS.  Per share amounts for all periods give effect to the stock split.

(5)           Represents dividends paid during the year.

 

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PifCo

The following tables set forth PifCo’s selected consolidated financial data, presented in U.S. dollars and prepared in accordance with U.S. GAAP.  The data for each of the five years in the period ended December 31, 2010 have been derived from PifCo’s audited consolidated financial statements, which were audited by KPMG Auditores Independentes for the years ended December 31, 2010, 2009, 2008, 2007 and 2006.  The information below should be read in conjunction with, and is qualified in its entirety by reference to, PifCo’s audited consolidated financial statements and the accompanying notes and Item 5. “Operating and Financial Review and Prospects.”

BALANCE SHEET DATA—PifCo

 

For the Year Ended December 31,

 

2010

2009

2008

2007

2006

 

(U.S.$ million)

Assets:

 

 

 

 

 

Total current assets

14,438

22,986

30,383

28,002

19,241

Property and equipment, net

1

2

2

1

1

Total other assets

3,543

3,377

2,918

4,867

2,079

Total assets

17,982

26,365

33,303

32,870

21,321

 

 

 

 

 

 

Liabilities and stockholder’s deficit:

 

 

 

 

 

Total current liabilities

5,893

13,175

28,012

27,686

9,264

Total long-term liabilities(1)

7,442

Long-term debt(2)

12,431

13,269

5,884

5,187

4,640

Total liabilities

18,324

26,444

33,896

32,873

21,346

Total stockholder’s deficit

(342)

(79)

(593)

(3)

(25)

Total liabilities and stockholder’s deficit

17,982

26,365

33,303

32,870

21,321

 


(1)                  Excludes long-term debt.

(2)                  Excludes current portion of long-term debt.

INCOME STATEMENT DATA—PifCo

 

For the Year Ended December 31,

 

2010

2009

2008

2007

2006

 

(U.S.$ million)

Net operating revenue

34,759

28,850

42,443

26,732

22,070

Operating income (loss)

2

578

(927)

127

(38)

Net (loss)/income for the year

(262)

487

(772)

29

(211)

 

 

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RISK FACTORS

Risks Relating to Our Operations

Exploration and production of oil in deep and ultra-deep waters involves risks.

Exploration and production of oil involves risks that are increased when carried out in deep and ultra-deep waters. The majority of our exploration and production activities are carried out in deep and ultra-deep waters, and the proportion of our deepwater activities will remain constant or increase due to the location of our pre-salt reservoirs in deep and ultra-deep waters. Our activities, particularly deep and ultra-deep water drilling, present several risks such as the risk of spills, explosions in platforms and drilling operations and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings.

Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events.

Substantial or extended declines and volatility in the international prices of crude oil, oil products and natural gas as well as a significant depreciation of the real in relation to the U.S. dollar may have a material adverse effect on us.

The majority of our revenue is derived primarily from sales of crude oil and oil products and, to a lesser extent, natural gas.  We do not, and will not, have control over the factors affecting international prices for crude oil, oil products and natural gas.  Changes in crude oil prices typically result in changes in prices for oil products and natural gas.  Historically, international prices for crude oil, oil products and natural gas have fluctuated widely as a result of many factors.  These factors include:

         global and regional economic and geopolitical developments in crude oil producing regions, particularly in the Middle East;

         the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain crude oil production levels and defend prices;

         global and regional supply and demand for crude oil, oil products and natural gas;

         global financial crises, such as the global financial crisis of 2008;

         competition from other energy sources;

         domestic and foreign government regulations; and

         weather conditions.

Volatility and uncertainty in international prices for crude oil, oil products and natural gas may continue.  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 the value of our proved reserves.  Significant decreases in the price of crude oil may cause us to reduce or alter the timing of our capital expenditures, and this could adversely affect our production forecasts in the medium term and our reserve estimates in the future.  In addition, our pricing policy in Brazil is intended to be at parity with international product prices over the long term.  In general we do not adjust our prices for diesel, gasoline and LPG during periods of volatility in the international markets.  As a result, material rapid or sustained increases in the international price of crude oil and oil products may result in reduced downstream margins for us, and we may not realize all the gains that our competitors realize in periods of higher international prices.  We are also exposed to this risk during periods of depreciation of the real   

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in relation to the U.S. dollar, as we sell oil and oil products in Brazil in reais and international prices for crude oil and oil products are set in U.S. dollars. A depreciation of the real reduces our prices in U.S. dollar terms and may lead to reduced margins in U.S. dollars.

 

Our ability to maintain our long-term growth objectives for oil production depends on our ability to successfully develop our reserves, and failure to do so could prevent us from achieving our long-term goals for growth in production.

Our ability to maintain our long-term growth objectives for oil production, including those defined in our 2010-2014 Business Plan, is highly dependent upon our ability to successfully develop our existing reserves and, in the long term, upon our ability to obtain additional reserves.  The development of the sizable reservoirs in deep and ultra-deep waters, including the pre-salt reservoirs that have been assigned to us by the Brazilian federal government, has demanded and will continue to demand significant capital investments.  A primary operational challenge, particularly for the pre-salt, will be allocating our resources to build the necessary infrastructure at considerable distances from the shore and securing qualified labor force and offshore oil services to develop reservoirs of such size and magnitude in a timely manner, a challenge that is particularly heightened by the fact that we are required to acquire a minimum level of goods and services from Brazilian providers.  We cannot guarantee that we will have or will be able to obtain, in the time frame that we expect, sufficient resources for the installation of infrastructure, hiring of qualified labor force and provisioning of offshore oil services necessary to exploit the reservoirs in deep and ultra-deep waters that the Brazilian federal government has licensed and assigned to us, or that it may license to us in the future, including as a result of the enactment of the new regulatory model for the oil and gas industry in Brazil.

Our exploration activities also expose us to the inherent risks of drilling, including the risk that we will not discover commercially productive crude oil or natural gas reserves.  The costs of drilling wells are often uncertain, and numerous factors beyond our control (such as unexpected drilling conditions, equipment failures or incidents, and shortages or delays in the availability of drilling rigs and the delivery of equipment) may cause drilling operations to be curtailed, delayed or cancelled.  These risks are heightened when we drill in deep and ultra-deep water.  In addition, increased competition in the oil and gas sector in Brazil may increase the costs of obtaining additional reservoirs in bidding rounds for new concessions.  We may not be able to maintain our long-term growth objectives for oil production unless we conduct successful exploration and development activities of our large reservoirs in a timely manner.

We may not obtain, or it may be difficult for us to obtain, financing for our planned investments, which may have a material adverse effect on us.

Under our 2010-2014 Business Plan, we intend to invest U.S.$224 billion between 2010 and 2014.  This amount does not include our funding requirements to acquire our rights under the Assignment Agreement or the capital expenditures that will be required to explore and develop the areas covered by the Assignment Agreement.  In order to implement our 2010-2014 Business Plan, including the development of our oil and natural gas exploration activities in the pre- and post-salt layers and the development of refining capacity sufficient to process increasing production volumes, we will need to raise significant amounts of debt capital in the financial and capital markets, including by, among other means, loans and issuing debt securities.  We cannot guarantee that we will be able to obtain the necessary financing in a timely and advantageous manner in order to implement our 2010-2014 Business Plan.

The Brazilian federal government maintains control over our investment budget and establishes limits on our investments and long-term debt.  As a state-controlled entity, we must submit our budget for approval every year to the Ministry of Planning, Budget and Management, the MME and the Brazilian Congress.  Our approved budget may not be sufficient to make all of the investments that we envision, and may prevent us from acquiring additional indebtedness in a certain fiscal year. In this case, if we are not able to obtain financing at reasonable terms and conditions that do not require approval by the Brazilian federal government and the Brazilian Congress, we may not be able to complete all or part of our planned investments, including those we have agreed to make to develop our oil and natural gas exploration activities, which will adversely affect our business.

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

The proved crude oil and natural gas reserves set forth in this annual report are our estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made) according to applicable regulations.  Our proved developed crude oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  There are uncertainties in estimating quantities of proved reserves related to prevailing crude oil and natural gas prices applicable to our production, which may lead us to make revisions to our reserve estimates.  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.

Access to crude oil and natural gas reserves is essential to an oil and gas company’s sustained production and generation of income.  Under Brazilian law, the Brazilian federal government owns all subsoil accumulations of crude oil and natural gas in Brazil and the concessionaire owns the oil and gas it produces from those subsoil accumulations pursuant to concession agreements.  We possess the exclusive right to develop the volumes of crude oil and natural gas included in our reserves pursuant to concession agreements awarded to us by the Brazilian federal government and we own the hydrocarbons we produce under those concession agreements.  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.  In addition, we may be subject to fines by the ANP and our concessions may be revoked if we do not comply with our obligations under our concessions.

The new regulatory model for the oil and gas industry in Brazil and the Assignment Agreement may be challenged in Brazilian courts.

The new regulatory model for the oil and gas industry in Brazil, enacted in 2010, establishes new rules for the exploration and production of oil and natural gas in the pre-salt areas in Brazil.  See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Current Regulatory Framework.” The assignment agreement we entered into with the Brazilian federal government on September 3, 2010 (Assignment Agreement), under which the government assigned to us exploration and production rights to oil, natural gas and other fluid hydrocarbons in pre-salt areas not under concession, of 5 billion barrels of oil equivalent, is a separate law that was also approved by Congress and enacted in 2010.

Challenges to the constitutionality or legality of the new regulatory model for the oil and gas industry in Brazil, including challenges to the Assignment Agreement, may be brought before the Brazilian Supreme Court (Supremo Tribunal Federal, or STF) or the Brazilian Superior Court of Justice (Superior Tribunal de Justiça, or STJ).  Challenges to the constitutionality or legality of the new regulatory model may relate to our status as the exclusive operator in all pre-salt areas not yet under concession, in addition to other areas that the CNPE may deem strategic, and the fact that exploration and production rights in such areas will be granted to us without a public bidding process. Challenges to the constitutionality or legality of the Assignment Agreement may relate to the direct award of exploration and production rights to us without a public bidding, contract price paid for the transfer of rights or the conditions, methodologies and results arising from the revision process pursuant to the terms of the Assignment Agreement.  If the new regulatory model for the oil and gas industry in Brazil, including the Assignment Agreement, is determined to be wholly or partly unconstitutional or illegal, uncertainties about the regulation of the oil and gas sector in which we operate may arise, including questions about the validity of the legal relationships that are based on the new regulatory model, including the rights acquired under the Assignment Agreement.

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In addition, we cannot assure you that the price paid for the transfer of rights will not be challenged.  We and our directors may be the subject of legal proceedings questioning the approval and the execution of the Assignment Agreement as being detrimental to the interests of our non-controlling shareholders.

We do not know whether a challenge to the constitutionality or legality of the new regulatory model for the oil and gas industry in Brazil, including the Assignment Agreement, will arise, nor can we predict, in the event it does arise, the outcome of any such legal proceeding.

The Assignment Agreement we entered into with the Brazilian federal government is a related party transaction.  

The transfer of oil and gas exploration and production rights to us related to specific pre-salt areas is governed by the Assignment Agreement, which is a contract between the Brazilian federal government, our controlling shareholder, and us. The negotiation of the Assignment Agreement involved significant issues, including negotiations regarding (1) the area covered by the transfer of rights, consisting of exploratory blocks; (2) the volume, on a barrels of oil equivalent basis, that we may extract from this area; (3) the price to be paid for the transfer of rights; (4) the terms of the subsequent revision of the contract price and volume under the Assignment Agreement; and (5) the terms providing for the reallocation of volumes among the exploratory blocks assigned to us.  This contract includes provisions for a subsequent revision of the contract terms, which are subject to oil and industry prices at the time the revision is made.  Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if it is determined that 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. If it is determined, on the other hand, that the revised contract price is lower than the initial contract price, the Brazilian federal government will make a payment to us.  This will require a negotiation with the Brazilian federal government pursuant to the terms of the Assignment Agreement.

The Assignment Agreement provides for the reallocation of volumes among the exploratory blocks assigned to us if oil and gas production is deemed economically unviable in one or more blocks for geologic reasons that would prevent the fulfillment of the Assignment Agreement as a result of the revision process.  Such reallocation would result in a revision of the volume of barrels of oil equivalent we would have to produce per block, which could prevent us from producing the maximum amount of barrels of oil equivalent contemplated under the Assignment Agreement.  In the event that we cannot produce such maximum amount, the Brazilian federal government has contractually undertaken the obligation to compensate us for the volumes not produced pursuant to the terms of the Assignment Agreement. 

Over the course of the life of the Assignment Agreement, novel issues may arise in the implementation of the revision process and reallocation provisions that will require negotiations between related parties.

 

We are subject to numerous environmental and health regulations that have become more stringent in the recent past and may result in increased liabilities and increased capital expenditures.

Our activities are subject to a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment, both in Brazil and in other jurisdictions in which we operate.  Particularly in Brazil, our oil and gas business is subject to extensive regulation by several governmental agencies, including the ANP, the ANEEL, the Brazilian Water Transportation Agency (Agência Nacional de Transportes Aquaviários) and the Brazilian Land Transportation Agency (Agência Nacional de Transportes Terrestres). 

Failure to observe or comply with these laws and regulations could result in penalties that could adversely affect our operations.  In Brazil, for example, we could be exposed to administrative and criminal sanctions, including warnings, fines and closure orders for non-compliance with these environmental regulations, which, among other things, limit or prohibit emissions or spills of toxic substances produced in connection with our operations.  Waste disposal and emissions regulations may also require us to clean up or retrofit our facilities at substantial cost and could result in substantial liabilities.  The Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis (Brazilian Institute of the Environment and Renewable Natural Resources, or IBAMA) and the ANP routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions in connection with its inspections.  In addition, we are subject to environmental laws that require us to incur significant costs to cover damage that a project may cause to the environment.  These additional costs may have a negative impact on the profitability of the projects we intend to implement or may make such projects economically unfeasible.

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As environmental regulations become more stringent, and as new laws and regulations relating to climate change, including carbon controls, become applicable to us, it is probable that our capital expenditures for compliance with environmental regulations and to effect improvements in our health, safety and environmental practices will increase substantially in the future.  We cannot guarantee that we will be able to maintain or renew our licenses and permits if they are revoked or if the applicable environmental authorities oppose or delay their issuance or renewal.  Increased expenditures to comply with environmental regulations, mitigate the environmental impact of our operations or restore the biological and geological characteristics of the areas in which we operate may result in reductions in other strategic investments.  Any substantial increase in expenditures for compliance with environmental regulations or reduction in strategic investments may have a material adverse effect on our results of operations or financial condition.

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

We are currently a party to numerous legal proceedings relating to civil, administrative, environmental, labor and tax claims filed against us.  These claims involve substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us, including a tax dispute amounting to approximately U.S.$2.7 billion.  See Item 8. “Financial Information—Legal Proceedings.”  In the event that claims involving a material amount and for which we have no provisions were to be decided against us, or in the event that the losses estimated turn out to be significantly higher than the provisions made, the aggregate cost of unfavorable decisions could have a material adverse effect on our financial condition and results of operations.  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 preclude them from focusing on our core business.  Depending on the outcome, certain litigation could result in restrictions on our operations and have a material adverse effect on certain of our businesses.

We are vulnerable to increased financing expenses resulting from increases in prevailing market interest rates and exchange rate fluctuation.

As of December 31, 2010, approximately 60.3% — U.S.$41,462 million of our total indebtedness — consisted of floating rate debt.  In light of cost considerations and market analysis, we decided not to enter into derivative contracts or make other arrangements to hedge against the risk of an increase in interest rates.  Accordingly, if market interest rates (principally LIBOR) rise, our financing expenses will increase, which could have an adverse effect on our results of operations and financial condition.

Fluctuations in exchange rates, especially a depreciation of the real  in relation to the U.S. dollar rate, may also increase our financing expenses as most of our revenues have been denominated in reais, while some of our operating expenses and capital expenditures and a substantial portion of our indebtedness are, and are expected to continue to be, denominated in or indexed to U.S. dollars and other foreign currencies.

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

We do not maintain coverage for business interruptions of any nature for our Brazilian operations, including business interruptions caused by labor action.  If, for instance, our workers 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 financial condition or results of operations.

We are subject to substantial risks relating to our international operations.

We operate in several countries, particularly in South America and West Africa, that can be politically, economically and socially unstable.  The results of operations and financial condition of our subsidiaries in these countries may be adversely affected by fluctuations in their local economies, political instability and governmental actions relating to the economy, including:

         the imposition of price controls;

         the imposition of restrictions on hydrocarbon exports;

         the fluctuation of local currencies against the real

         the nationalization of oil and gas reserves;

         increases in export tax and income tax rates for crude oil and oil products; and

         unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.

If one or more of the risks described above were to materialize we may lose part or all of our reserves in the affected country and we may not achieve our strategic objectives in these countries or in our international operations as a whole, which may result in a material adverse effect on our results of operations and financial condition.  For more information about our operations outside Brazil, see Item 4. “Information on the Company¾International.” 

Risks Relating to PifCo

PifCo’s operations and debt servicing capabilities are dependent on us.

PifCo’s financial position and results of operations are directly affected by our decisions.  PifCo is a direct wholly owned subsidiary of Petrobras incorporated in the Cayman Islands as an exempted company with limited liability.  Currently, PifCo purchases crude oil and oil products from third parties and sells them to us.  PifCo also purchases crude oil and oil products from us and sells them outside Brazil.  Accordingly, intercompany activities and transactions, and therefore PifCo’s financial position and results of operations, are affected by decisions made by us.  Additionally, PifCo sells and purchases crude oil and oil products to and from third parties and related parties, mainly outside Brazil.  Commercial operations are carried out under market conditions and at market prices.

PifCo is gradually reducing its sales of crude oil and oil products to us and will gradually reduce its sales of crude oil and oil products to third parties, and will eventually cease these commercial operations altogether.  At that time, PifCo will become a finance subsidiary functioning as a vehicle for us to raise capital for our operations outside of Brazil through the issuance of debt securities in the international capital markets, among other means.  PifCo’s ability to service and repay its indebtedness is consequently dependent on our own operations.  Financing for PifCo’s commercial operations is provided by us, as well as third-party credit providers in favor of whom we provide credit support.  Our support of PifCo’s debt obligations has been and will continue to be made through unconditional and irrevocable guaranties of payment.

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Our own financial condition and results of operations, as well as our financial support of PifCo, directly affect PifCo’s operational results and debt servicing capabilities.  For a more detailed description of certain risks that may have a material adverse impact on our financial condition or results of operations and therefore affect PifCo’s ability to meet its debt obligations, see “Risks Relating to Our Operations.”

PifCo depends on us to service its indebtedness to third parties.

PifCo is gradually reducing its sales of crude oil and oil products to us and will gradually reduce its sales of crude oil and oil products to third parties and will eventually cease these commercial operations altogether, as described above.  PifCo regularly incurs indebtedness and will continue to do so as our finance subsidiary.  PifCo depends, and will continue to depend, on financing and credit support from us to service its indebtedness to third parties.  All such indebtedness has the benefit of a guaranty or other equivalent credit support from us.  If for any reason we are not permitted to continue to finance PifCo’s operations or continue to provide credit support to the indebtedness it incurs, this would have a materially adverse effect on PifCo’s ability to meet its debt obligations.

Risks Relating to Our Relationship with the Brazilian Federal Government

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

The Brazilian federal government, as the principal shareholder of a mixed capital company such as ours, has pursued, and may pursue in the future, certain of its macroeconomic and social objectives through us, as permitted by law.  Brazilian law requires the Brazilian federal government to own 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, a majority of 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.

In particular, we continue to assist the Brazilian federal government to ensure that the supply and pricing of crude oil and oil products in Brazil meet Brazilian consumption requirements.  Accordingly, we may make investments, incur costs and engage in sales on terms that may have an adverse effect on our results of operations and financial condition.  Prior to January 2002, prices for crude oil and oil products were regulated by the Brazilian federal government, occasionally set below prices prevailing in the world oil markets.  We cannot assure you that price controls will not be reinstated in Brazil.  

We may not be able to obtain financing for some of our planned investments, and failure to do so could adversely affect our operating results and financial condition.

The Brazilian federal government maintains control over our investment budget and establishes limits on our investments and long-term debt.  As a state-controlled entity, we must submit our proposed annual budgets to the Ministry of Planning, Budget and Management, the MME and the Brazilian Congress for approval.  If our approved budget reduces our proposed investments and incurrence of new debt and we cannot obtain financing that does not require Brazilian federal government approval, we may not be able to make all the investments we envision, including those we have agreed to make to expand and develop our crude oil and natural gas fields.  If we are unable to make these investments, our operating results and financial condition may be adversely affected.

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Risks Relating to Brazil

The Brazilian federal government has historically exercised, and continues to exercise, significant influence over the Brazilian economy. Brazilian political and economic conditions have a direct impact on our business and may have a material adverse effect on us.

The Brazilian federal government’s economic policies 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 Brazilian federal government’s response to these factors:

         devaluations and other exchange rate movements;

         inflation; 

         exchange control policies;

         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

         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 Equity and Debt Securities

The size, volatility, liquidity and/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.

Petrobras shares are some of the most liquid in the São Paulo Stock Exchange (BM&FBOVESPA), 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.

The market for PifCo’s notes may not be liquid.

Some of PifCo’s notes are not listed on any securities exchange and are not quoted through an automated quotation system.  We can make no assurance as to the liquidity of or trading markets for PifCo’s notes.  We cannot guarantee that the holders of PifCo’s notes will be able to sell their notes in the future.  If a market for PifCo’s notes does not develop, holders of PifCo’s notes may not be able to resell the notes for an extended period of time, if at all.

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

Holders of ADSs who are residents of the United States may not be able to exercise the preemptive rights relating to the common or preferred shares underlying our ADSs unless a registration statement under the Securities Act is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available.  We are not obligated to file a registration statement with respect to the common or preferred shares relating to these preemptive rights, and therefore we may not file any such registration statement.  If a registration statement is not filed and an exemption from registration does not exist, JPMorgan Chase Bank, N.A., 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 Association of Petrobras—Preemptive Rights.”

If holders of our ADSs exchange their ADSs for common or preferred shares, they risk losing the ability to remit foreign currency abroad and forfeiting Brazilian tax 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.  If holders of ADSs decide to exchange their ADSs for the underlying common or preferred shares, they will be entitled to continue to rely, for five Brazilian business days from the date of exchange, on the custodian’s certificate of registration.  After that period, such holders may not be able to obtain and remit U.S. dollars abroad upon the disposition of the common or preferred shares, or distributions relating to the common or preferred shares, unless they obtain their own certificate of registration or register under Resolution No. 2,689, of January 26, 2000, of the National Monetary Council (Conselho  Monetário Nacional, or CMN), which entitles registered foreign investors to buy and sell on the BM&FBOVESPA.  In addition, if such holders do not obtain a certificate of registration or register under Resolution No. 2,689, they may be subject to less favorable tax treatment on gains with respect to the common or preferred shares.

If such holders attempt to obtain their own certificate of registration, they may incur expenses or suffer delays in the application process, which could delay 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 obtained by such holders may be affected by future legislative or regulatory changes and we cannot assure such holders that additional restrictions applicable to them, the disposition of the underlying common or preferred shares, or the repatriation of the proceeds from the process will not be imposed in the future.

Holders of 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 against actions by our board of directors 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.  There is also a less active plaintiff’s bar dedicated to the enforcement of shareholders’ rights in Brazil than in the United States.  In addition, shareholders in Brazilian companies ordinarily do not have standing to bring a class action.

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.

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Holders of our ADSs may encounter difficulties in the exercise of voting rights and preferred shares and the ADSs representing preferred shares generally do not give holders of ADSs voting rights.  

Holders of ADSs may encounter difficulties in the exercise of some of their rights as a shareholder if they hold our ADS rather than the underlying shares.  For example, if we fail to provide the depositary with voting materials on a timely basis, holders of ADSs may not be able to vote by giving instructions to the depositary on how to vote for them.

In addition, a portion of our ADSs represents our preferred shares.  Under Brazilian law and our bylaws, holders of preferred shares generally do not have the right to vote in meetings of our stockholders.  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 of Petrobras—Voting Rights” for a discussion of the limited voting rights of our preferred shares.

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

If proceedings were brought in Brazil seeking to enforce our obligations in respect of the guaranty relating to PifCo’s notes, we would be required to discharge our obligations only in reais.  Under the Brazilian exchange control rules, 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, may be satisfied in reais at the rate of exchange, as determined by the Central Bank of Brazil, in effect on the date of payment.

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

PifCo’s obligation to make payments on the PifCo 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 PifCo’s issuance of these notes.  To the extent that the guaranty is held to be a fraudulent conveyance or unenforceable for any other reason, the holders of the PifCo notes would not have a claim against us under the relevant guaranty and will solely have a claim against PifCo.  We cannot assure you that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of the PifCo noteholders relating to any avoided portion of the guaranty.

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Item 4.                  Information on the Company

History and Development

Petróleo Brasileiro S.A.—Petrobras—was incorporated in 1953 to conduct the Brazilian federal government’s hydrocarbon activities.  We began operations in 1954 and have been carrying out crude oil and natural gas production and refining activities in Brazil on behalf of the government.

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.  On August 6, 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 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.  See “Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”   

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

Pursuant to Law No. 12,276, 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 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 billion barrels of oil equivalent.  The initial purchase price for our rights under the Assignment Agreement was R$74,807,616,407, which was equivalent to U.S.$42,533,327,500 as of September 1, 2010.  On September 29, 2010, we issued 2,293,907,960 common shares (including common shares in the form of ADSs) and 1,788,515,136 preferred shares (including preferred shares in the form of ADSs) in a global public offering consisting of a registered offering in Brazil and an international offering that included a registered offering in the United States.  On October 1, 2010, we issued an additional 75,198,838 common shares (including common shares in the form of ADSs) and 112,798,256 preferred shares (including preferred shares in the form of ADSs) pursuant to the exercise of the underwriters’ over-allotment option.  We applied part of the net proceeds from the global offering to pay the initial purchase price under the Assignment Agreement.  In order to ensure transparency, our board of directors created a special committee comprised of minority shareholder representatives to monitor the transfer of rights transaction.  We complied with all Brazilian Corporate Law requirements in carrying out the capitalization process, including the protection of the rights of our minority shareholders. 

Our common and preferred shares have been traded on the BM&FBOVESPA since 1968.  Petrobras was incorporated as a state-controlled company under Law No. 2,004 (effective October 3, 1953), and a majority of our voting capital must be owned by the Brazilian federal government.  As of December 31, 2010, the Brazilian federal government owned 48.3% of our outstanding capital stock and 63.6% of our voting shares.  We operate through subsidiaries, joint ventures, and associated companies 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 telephone number is (55-21) 3224-4477.

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Overview of the Group

We are an integrated oil and gas company that is the largest corporation in Brazil and one of the largest companies in Latin America in terms of revenues.  As a result of our legacy as Brazil’s former sole supplier of crude oil and oil products and our ongoing commitment to development and growth, we operate most of Brazil’s producing oil and gas fields and hold a large base of proved reserves and a fully developed operational infrastructure.  In 2010, our average domestic daily oil production was 2,004 mboe/d, an estimated 97.5% of Brazil’s total.  Over 79% of our domestic proved reserves are in large, contiguous and highly productive fields in the offshore Campos Basin, which allows us to optimize our infrastructure and limit our costs of exploration, development and production.  In 41 years of developing Brazil’s offshore basins we have developed special expertise in deepwater exploration and production, which we exploit both in Brazil and in other offshore oil provinces.

We operate substantially all the refining capacity in Brazil.  Most of our refineries are located in Southeastern Brazil, within the country’s most populated and industrialized markets and adjacent to the Campos Basin that provides most of our crude oil.  Our domestic refining capacity of 2,007 mbbl/d is well balanced with our domestic refining throughput of 1,798 mbbl/d and sales of oil products to domestic markets of 1,960 mbbl/d.  We are also involved in the production of petrochemicals.  We distribute oil products through our own “BR” network of retailers and to wholesalers.

We participate in most aspects of the Brazilian natural gas market.  We expect the percentage of natural gas in Brazil’s energy matrix to grow in the future as we expand our production of both associated and non-associated gas, mainly from offshore fields in the Campos, Espírito Santo and Santos Basins, and extend Brazil’s gas transportation infrastructure.  We use LNG terminals and import natural gas from Bolivia to meet demand and diversify our supply.  We also participate in the domestic power market primarily through our investments in gas-fired thermoelectric power plants.  In addition, we participate in the fertilizer business, which is another important source of natural gas demand. 

Outside of Brazil, we are present in more than 20 countries.  In South America, our operations extend from exploration and production to refining, marketing, retail services and natural gas pipelines.  In North America, we produce oil and gas and have refining operations in the United States.  In Africa, we produce oil in Angola and Nigeria, and in Asia, we have refining operations in Japan.  In other countries, we are engaged only in oil and gas exploration. 

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

Our activities comprise five business segments:  

         Exploration and Production: oil and gas exploration, development and production in Brazil;

         Refining, Transportation and Marketing: downstream activities in Brazil, including refining, logistics, transportation, oil products and crude oil exports and imports and petrochemicals;

         Distribution: distribution of oil products to wholesalers and through our “BR” retail network in Brazil;

         Gas and Power: gas transportation and distribution, electric power generation using natural gas and renewable energy sources and fertilizer production; and

         International: exploration and production, refining, transportation and marketing, distribution and gas and power operations outside of Brazil.

Our Corporate segment comprises our financing activities not attributable to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and health care plans for inactive participants.  Since 2009, our Corporate segment has included the results from our Biofuels operations.  In prior years, results from our Biofuels operations were included in our Gas and Power segment.

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The following table sets forth key information for each business segment in 2010:

Key Information by Business Segment, 2010

 

Exploration and Production

Refining, Transportation and Marketing

Distribution

Gas and Power

International

Corporate

Eliminations

Group Total

 

(U.S.$ million)

Net operating revenues

54,284

97,540

37,308

8,507

13,463

(91,050)

120,052

Income (loss) before income tax

24,556

2,278

1,101

1,014

1,076

(3,416)

(778)

25,831

Total assets at December 31

137,193

69,487

7,529

29,907

16,170

53,707

(5,310)

308,683

Capital expenditures

22,222

15,356

482

4,099

2,167

752

45,078

 

Exploration and Production  

Exploration and Production Key Statistics

 

2010

2009

2008

 

(U.S.$ million)

Exploration and Production:

 

Net operating revenues

54,284

38,777

59,024

Income before income tax

24,556

14,588

31,657

Total assets at December 31

137,193

77,596

51,326

Capital expenditures

22,222

16,488

14,293

 

Oil and gas exploration and production activities in Brazil are the largest component of our portfolio.  We have gradually increased production over the past four decades, from 164 mbbl/d of crude oil, condensate and natural gas liquids in Brazil in 1970 to 2,004 mbbl/d in 2010.  We aim to grow oil and gas reserves and production sustainably and be recognized for excellence in Exploration and Production operations.

The primary focus of our E&P segment is to:

         Continue to explore and develop the Campos Basin, leveraging the current infrastructure to drill in deeper horizons in existing concessions, including pre-salt reservoirs, and using new technologies for secondary recovery in producing fields;

         Explore and develop Brazil’s two other most promising offshore basins, Espírito Santo (light oil, heavy oil and gas) and Santos (gas and light oil), with a particular focus on pre-salt development;

         Develop associated and non-associated gas resources in the Santos Basin and elsewhere to meet Brazil’s growing demand for gas and to increase the contribution of Brazilian gas production as a proportion of total domestic gas supply; and

         Sustain and increase production from onshore and shallow fields through drilling and enhanced recovery operations.

During 2010, our oil and gas production from Brazil averaged 2,165.5 mboe/d, of which 76.7% was oil and 23.3% was natural gas.  On December 31, 2010, our estimated net proved crude oil and natural gas reserves in Brazil were 12.14 billion boe, of which 86% was crude oil and 14% was natural gas.  Brazil provided 89.8% of our worldwide production in 2010 and accounted for 95% of our worldwide reserves at December 31, 2010 on a barrels of oil equivalent basis.  Historically, approximately 85% of our total Brazilian production has been oil.  In connection with the development of the pre-salt, the contribution of natural gas to total hydrocarbon production is expected to grow.  In 2010, we drilled a total of 561 development wells, of which 78 were offshore and 483 were onshore.

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As of December 31, 2010, we had 138 exploration agreements covering 198 blocks, corresponding to a gross exploratory acreage of 130,000 km2 (32.1 million acres), or a net exploratory acreage of 105,000 km2 (25.9 million acres), and 31 evaluation plans.  We are exclusively responsible for conducting the exploration activities in 66 of the 138 exploration agreements.  As of December 31, 2010, we had exploration partnerships with 75 foreign and domestic companies.  We conduct exploration activities under 120 of our 138 partnership agreements. 

We focus much of our exploration effort on deepwater drilling, where the discoveries are substantially larger and our technology and expertise create a competitive advantage.  In 2010, we invested a total of U.S.$4.08 billion in exploration activities in Brazil.  We drilled a total of 116 gross exploratory wells in 2010, of which 49 were offshore and 67 onshore, with a success ratio of 57%.

Brazil’s richest oil fields are located offshore, most of them in deep waters.  Since 1971, when we started exploration in the Campos Basin, we have been active in these waters and we have become globally recognized as innovators in the technology required to explore and produce hydrocarbons in deep and ultra-deep water.  We operate more production (on a boe basis) from fields in deep and ultra-deep water than any other company.  In 2010, offshore production accounted for 87% of our production and deepwater production accounted for 76% of our production in Brazil.  In 2010, we operated 201 wells in water deeper than 1,000 meters (3,281 feet), and we drilled around 24 exploratory wells in water deeper than 1,000 meters (3,281 feet).

Offshore exploration, development and production costs are generally higher than those onshore, but we have been able to offset these higher costs by higher drilling success ratios, larger discoveries and greater production volumes.  We have historically been successful in finding and developing significant oil reservoirs offshore, which has allowed us to achieve economies of scale by spreading the total costs of exploration, development and production over a large base.  By focusing on opportunities that are close to existing production infrastructure, we limit the incremental capital requirements of new field development.

Historically, our offshore exploration and production activities were focused on post-salt reservoirs.  The discovery of the Lula field (formerly Tupi) in 2006 marked the beginning of a new chapter in our E&P history.  In recent years, we have focused our offshore exploration efforts on pre-salt reservoirs located in a region approximately 800 km (497 miles) long and 200 km (124 miles) wide stretching from the Campos to the Santos Basins.  Our existing contracts in this area cover 26.6% (approximately 45,615 km2 or 11.3 million acres) of the pre-salt areas, including the pre-salt areas assigned to us under Concession Contracts and the Assignment Agreement.  An additional 4% (approximately 9,000 km2 or 2.2 million acres) is under concession to other oil companies for exploration.  The remaining 69.4% (approximately 103,000 km2 or 25.4 million acres) of the pre-salt region is open acreage area, not licensed yet, and the licensing of new pre-salt areas will be made under a production-sharing regime under Law No. 12,351, enacted on December 22, 2010.

Since 2005, we have drilled 52 exploratory wells as operator in this 149,000 km2 (36.8 million acres) pre-salt area, 88% of which have yielded discoveries of hydrocarbon resources.  We hold interests ranging from 20% to 100% in the pre-salt exploration areas under concession to us.  In the southern part of the Santos Basin, where the salt layer is thick and the hydrocarbons have been more perfectly preserved, we have made several particularly promising discoveries since 2006, including those made in Blocks BM-S-11 (Iara, Lula and Cernambi fields) and BM-S-9 (Carioca and Guará).  In the northern part of the region, we made significant discoveries in 2008 and early 2010 in the area known as Parque das Baleias and in the Barracuda, Marlim and Caratinga fields, all of which are in the Campos Basin. As a result, we are committing substantial resources to develop these pre-salt discoveries, which are located in deep and ultra-deep waters at total depths of up to 8,000 meters (26,245 feet).

Our 2010-2014 Business Plan, which was released in June 2010 prior to the signing of the Assignment Agreement,  foresees investments of U.S.$33 billion from 2010 to 2014 (not including investments by our partners) to develop  our then-existing  concessions in the pre-salt areas, or approximately 31% of our total domestic capital expenditures for exploration and production through 2014.  In May 2011, our board of directors approved the annual revision of the Santos Basin pre-salt development plan (PLANSAL), which foresees capital expenditures of up to U.S.$73 billion through 2015 in the Santos Basin pre-salt areas, 74% of which is being provided by us and the remainder by our partners. This annual revision to the PLANSAL also provides for the development of the areas transferred to us by the Assignment Agreement while successfully reducing capital expenditures planned for the development of the Santos Basin pre-salt areas by 45% since 2008.

 

We have also implemented a variety of programs designed to increase oil recovery from existing fields and reduce natural declines from producing fields.

Our exploration and production activities outside Brazil are included in our International business segment.  See “—International.”

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Information about our principal oil and gas producing fields in Brazil is summarized in the table below.

Principal Oil and Gas Producing Fields in Brazil

Basin

Fields

Petrobras %

Type

Fluid(1) 

Alagoas

Pilar

100%

Onshore

Light Oil/Natural Gas

 

 

 

 

 

Camamu

Manati

35%

Shallow

Natural Gas

 

 

 

 

 

Campos

Albacora

100%

Shallow

Intermediate Oil

 

 

 

Deepwater

Intermediate Oil

 

Albacora Leste

90%

Deepwater

Ultra-deepwater

Intermediate Oil

 

Baleia Azul

100%

Deepwater

Intermediate Oil

 

Baleia Franca

100%

Deepwater

Intermediate Oil

 

Barracuda

100%

Deepwater

Intermediate Oil

 

Bijupirá/Salema

22.4%(2)

Deepwater

Intermediate Oil

 

Cachalote

100%

Deepwater

Intermediate Oil

 

Caratinga

100%

Deepwater

Intermediate Oil

 

Espadarte

100%

Deepwater

Intermediate Oil

 

Jubarte

100%

Deepwater

Heavy Oil

 

Maromba

62.5%

Deepwater

Heavy Oil

 

Marlim

100%

Deepwater

Heavy Oil

 

Marlim Leste

100%

Deepwater

Intermediate Oil

 

Marlim Sul

100%

Deepwater

Ultra-deepwater

Intermediate Oil

 

Namorado

100%

Shallow

Intermediate Oil

 

Ostra

35%

Deepwater

Heavy Oil

 

Pampo

100%

Shallow

Intermediate Oil

 

Pargo

100%

Shallow

Intermediate Oil

 

Roncador

100%

Ultra-deepwater

Intermediate Oil

 

Voador

100%

Deepwater

Heavy Oil

 

 

 

 

 

Espírito Santo

Fazenda Alegre
Peroá
Golfinho

100%
100%
100%

Onshore
Shallow
Deepwater
Ultra-deepwater

Heavy Oil
Light Oil
Intermediate Oil
Intermediate Oil

 

Canapu

100%

Deepwater

Natural Gas

 

Camarupim

76%

Deepwater

Natural Gas

 

 

 

 

 

Potiguar

Canto do Amaro

100%

Onshore

Intermediate Oil/Natural Gas
Heavy Oil/Natural Gas

 

 

 

 

 

Recôncavo

Jandaia
Miranga

100%
100%

Onshore
Onshore

Light Oil
Light Oil/Natural Gas

 

 

 

 

 

Santos

Merluza

100%

Shallow

Natural Gas

 

Mexilhão

100%

Shallow

Natural Gas

 

Uruguá

100%

Deepwater

Intermediate Oil/Natural Gas

 

Tambaú

100%

Deepwater

Natural Gas

 

Lula

65%

Ultra-deepwater

Intermediate Oil

 

Cernambi

65%

Ultra-deepwater

Intermediate Oil

 

 

 

 

 

Sergipe

Carmópolis

100%

Onshore

Intermediate Oil

 

Sirirízinho

100%

Onshore

Intermediate Oil

 

 

 

 

 

Solimões

Leste do Urucu

100%

Onshore

Light Oil/Natural Gas

 

Rio Urucu

100%

Onshore

Light Oil/Natural Gas

 


(1)                  Heavy oil = up to 22° API; intermediate oil = 22° API to 31° API; light oil = greater than 31° API

(2)                  Petrobras is not the operator in this field.

We have historically conducted exploration, development and production activities in Brazil through concession contracts, which we have obtained through participation in bid rounds conducted by the ANP.  Some of our existing concessions were granted by the ANP without an auction in 1998, as provided by Law No. 9,478.  These are known as the “Round Zero” concession contracts.  Since such time, we have participated in all of the auction rounds, most recently in December 2008.

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Our domestic oil and gas exploration and production efforts are primarily focused on three major basins offshore in Southeastern Brazil: Campos, Espírito Santo and Santos.  The following map shows our concession areas in Brazil as of December 2010.

 

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The map below shows the location of the pre-salt reservoirs as well as the status of our exploratory activities there.

 

Campos Basin  

The Campos Basin, which covers approximately 115,000 km2 (28.4 million acres), is the most prolific oil and gas basin in Brazil as measured by proved hydrocarbon reserves and annual production.  Since we began exploring this area in 1971, over 60 hydrocarbon accumulations have been discovered, including eight large oil fields in deep water and ultra-deep water.  The Campos Basin is our largest oil- and gas-producing region, producing an average 1,676.9 mbbl/d of oil and 13.6 mmm3/d (480.3 mmcf/d) of associated natural gas during 2010, 81.5% of our total production from Brazil.  In 2010 we produced oil at an average rate of 1,676.9 mbbl/d from 43 fields in the Campos Basin and held proved crude oil reserves representing 84% of our total proved crude oil reserves in Brazil.  We held proved natural gas reserves in the Campos Basin representing 48% of our total proved natural gas reserves in Brazil.  We operated 40 floating production systems, 14 fixed platforms and 6,680 km (4,151 miles) of pipeline and flexible pipes in water depths from 80 to 1,886 meters (262 to 6,188 feet), delivering oil with an average API gravity of 22.9° and an average BSW of 1%. 

We have also made important progress in pre-salt E&P activities in the Campos Basin.  In the pre-salt region of the Campos Basin, we have drilled a total of 25 wells.  In February 2010 we made a promising discovery of 28° API oil at our ultra-deep exploratory well in the Barracuda area, which followed a significant discovery of intermediate oil (30° API) in the Parque das Baleias area in November 2008.  In the Jubarte field in the Campos Basin off the coast of the State of Espírito Santo, an EWT using a single well pilot system produced at an average rate of 17 mbbl/d from September 2008 to February 2011.  We expect to accelerate pre-salt production in Parque das Baleias using existing infrastructure in the area.  We started producing from the Baleia Franca field in the second half of 2010 using the existing FPSO Capixaba.  In 2012, we expect to start up a pilot system exclusively dedicated to pre-salt exploration in the Baleia Azul region using another FPSO.

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In 2010, the startup of operations at FPSO Capixaba located in the Cachalote field and P-57 located in the Jubarte field in the offshore Campos Basin added combined capacities of 280 mbbl/d of oil and 5.5 mmm3/d of natural gas.

We expect that future new source production from the Campos Basin will be predominantly from deepwater oil fields.  We are currently developing nine major projects in the Campos Basin:  Marlim Sul Module 3, Roncador Modules 3 and 4, Papa-Terra, Aruanã (BM-C-36) EWT and long-term production system, Jubarte Phase II, Parque das Baleias and the pre-salt reservoirs of Baleia Azul.

At December 31, 2010, we held exploration rights to 21 blocks in the Campos Basin, comprising 6,374 km2 (1.5 million acres).

Principal Campos Basin Development Projects

Field

Unit Type

Production Unit

Crude Oil
Nominal Capacity (bbl/d)

Natural Gas
Nominal Capacity

(mcf/d)

Water Depth (meters)

Start Up (year)

Notes

Marlim Sul–Module 3

SS

P-56

100,000

211,884

1,700

2011

 

Lead Aruanã (BM-C-36) EWT

FPSO

Cidade de Rio das Ostras

27,000

10,594

950

2011

Existing FPSO chartered from Teekay

Baleia Azul

FPSO

Anchieta

100,000

88,285

1,400

2012

Existing FPSO chartered from SBM

Roncador–Module 3

SS

P-55

180,000

211,884

1,790

2012

 

Roncador–Module 4

FPSO

P-62

180,000

211,884

1,550

2013

 

Papa-Terra–Module 1

TLWP

P-61

0

0

1,180

2013

Production by P-63

Papa-Terra–Module 2

FPSO

P-63

150,000

31,783

1,170

2013

 

Baleia Azul

FPSO

P-58

180,000

211,884

1,400

2013

 

Lead Aruanã (BM-C-36)

FPSO

Brasil

100,000

63,565

950

2013

Existing FPSO chartered from SBM

Jubarte Phase II

FPSO

P-57

180,000

70,628

1,260

2010

Production ramp-up in 2011

 

 

 

 

 

 

 

 

 

Espírito Santo Basin  

We have made several discoveries of light oil and natural gas in the Espírito Santo Basin, which covers approximately 75,000 km2 (18.5 million acres) offshore and 14,000 km2 (3.5 million acres) onshore.  At December 31, 2010, we were producing oil at an average rate of 68.7 mbbl/d from 47 fields and held proved crude oil reserves representing 0.71% of our total proved crude oil reserves in Brazil.  At December 31, 2010, we were producing natural gas at an average rate of 4.2 mmm3/d (148.3 mmcf/d) and held proved natural gas reserves representing 6% of our total proved natural gas reserves in Brazil. 

In 2010, we began operations at the Canapu project served by the FPSO Cidade de Vitória with capacity to produce 2 mmm3/d (70.6 mmcf/d).

In addition to developing new production projects, we are also optimizing existing resources in the Espírito Santo area by constructing the Sul Norte Capixaba gas pipeline with capacity to transport 7 mmm3/d (247.2 mmcf/d).  The pipeline, which runs from the Parque das Baleias area to the Cacimbas gas treatment unit, is expected to come online in 2012.

On December 31, 2010, we held exploration rights to 19 blocks, three onshore and 16 offshore, comprising 8,086 km2 (1.9 million acres).

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Santos Basin

The Santos Basin, which covers approximately 348,900 km2 (86 million acres) off the city of Santos, in the State of São Paulo, is one of the most promising exploration areas offshore Brazil and the focus of our plans to develop domestic natural gas.  In 2010, we produced oil at an average rate of 32.7 mbbl/d from two fields and one exploration area and held proved crude oil reserves representing 7% of our total proved crude oil reserves in Brazil.  Our average natural gas production in 2010 was 0.8 mmm3/d (28.3 mmcf/d) and our proved natural gas reserves in the Santos Basin represented 24% of our total proved natural gas reserves in Brazil. 

In recent years we have been carrying out plans to increase our gas production and build supporting infrastructure in the Santos and Espírito Santo Basins.  These plans are now reaching fruition, and we expect that they will increase our average gas production capacity in the Santos Basin from 0.8 mmm3/d (28.3 mmcf/d) in 2010 to 15.4 mmm3/d (543.9 mmcf/d) by the end of 2011.  In 2010 we started up post-salt operations at FPSO Cidade de Santos platform located in the Uruguá field, which produces 30 mbbl/d of light oil and is expected to produce 1 mmm3/d (35.3 mmcf/d) of gas in 2011 and as much as 7.9 mmm3/d (279.0 mmcf/d) of gas in 2012.  Mexilhão, located in shallow waters in the Santos Basin Block BS-400, is scheduled to come online in 2011 with initial production of approximately 1.9 mmm3/d (67.0 mmcf/d), potentially increasing to 9.3 mmm3/d (328.4 mmcf/d) in 2012.  An EWT at the SS-11 Atlantic Zephyr platform, located in the BM-S-40 block, also started up in 2010.  We are using the results of the EWT to develop a long-term production system for this block, including a plan to install the FPSO Cidade de Itajaí, with an expected capacity of 80 mbbl/d of oil.

The Santos Basin pre-salt was also a central focus of E&P activities in 2010.  We continue to concentrate our efforts on gathering information about the pre-salt reservoirs in the region and testing drilling technologies to improve efficiency and minimize costs in the near term.  During the next phase, which we will start in 2013, we plan to install several FPSOs in the Santos Basin pre-salt.  The subsequent phase, beginning in 2017, will include the application of improved technologies and engineering specifically designed for the pre-salt fields.

In May 2009, we initiated production in the pre-salt region of the Santos Basin with an EWT at Tupi (now called the Lula field) that has produced on average 15 mbbl/d.  In 2010, we declared the commerciality of that area, presenting development plans for the Lula and Cernambi fields and installing the first system capable of producing in the long-term at Lula, FPSO Cidade de Angra dos Reis, with a production capacity of 100 mbbl/d.  We also started the second EWT in the pre-salt region of the Santos Basin at Guará.

In 2010, we drilled eight new wells, increasing to 20 the number of wells in the pre-salt region of the Santos Basin.  We expect to start drilling up to 24 new wells in this region in 2011. 

All six blocks and one contingent block assigned to us under the Assignment Agreement are located in the pre-salt region of the Santos Basin.  We are developing these blocks in an integrated manner with the areas we already have under concession.  Over the next four years, we will move ahead with our exploration program and are targeting first oil at the Franco prospect by 2015.

On December 31, 2010, we held exploration rights to 47 blocks in the Santos Basin, comprising 29,302 km2 (7.2 million acres).  

 

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Principal Santos Basin Development Projects

Field

Unit Type

Production Unit

Crude Oil
Nominal Capacity (bbl/d)

Natural Gas
Nominal Capacity

(mcf/d)

Water Depth (meters)

Start Up (year)

Notes

Mexilhão

Fixed Platform

PMXL-1

0

529,710

170

2011

 

Lula Nordeste EWT

FPSO

BW Cidade de São Vicente

30,000

35,314

2,100

2011

Existing FPSO chartered from BW Offshore

Guará EWT

FPSO

Dynamic Producer

30,000

35,314

2,100

2011

Existing FPSO chartered from PETROSERV

Tiro e Sidon (BM-S-40)

SS

Cidade de Itajai

80,000

70,628

200

2012

Chartered from Teekay

Guara Pilot

FPSO

Cidade de São Paulo

120,000

176,573

2,141

2013

Chartered from Schahin/Modec

Lula Nordeste Pilot

FPSO

Cidade de Paraty

120,000

176,573

2,100

2013

Chartered from Queiroz Galvão/SBM

Guara – Module 2

FPSO

n/d

150,000

211,884

2,100

2014

 

Cernambi – Module 1

FPSO

n/d

150,000

211,884

2,100

2014

 

 

Other Basins  

We produce hydrocarbons and hold exploration acreage in 19 other basins in Brazil.  Of these, the most significant are the shallow offshore Camamu Basin and the onshore Potiguar, Recôncavo, Sergipe, Alagoas and Solimões Basins.  While our onshore production is primarily in mature fields, we plan to sustain and slightly increase production from these fields in the future by using enhanced recovery methods.

We had a total of 286 production agreements as of December 31, 2010, and were the 100% owner in 256 of them.  We are operators under nine of our 30 partnership agreements.

Critical Resources in Exploration and Production

We have sought to ensure that critical service sector resources are sufficient to permit us to move ahead with our E&P plans.  Because offshore Brazil is geographically isolated from other offshore drilling areas, and because we often drill in unusually deep waters, we plan carefully for our future drilling rig needs.  By using a combination of our own rigs and units that we contract for periods of three years or longer, we have historically ensured the availability of drilling units to meet our needs, and paid lower average daily rates than if we had contracted the units on a spot basis.  We continually evaluate our need for rigs, renew our drilling contracts, contract ahead for rigs as needed, and stimulate new rig construction by signing long-term operating leases with drilling contractors for rigs that are not yet built.

In the last three years we have successfully eased pressures related to a limited supply of deepwater rigs.  Whereas in 2008 we only had three rigs capable of drilling in water depths greater than 2000 meters (6,560 feet), we had 13 as of December 31, 2010, and we expect to have 30 by 2013.  We have entered into three to ten-year contracts for 22 additional drilling rigs to engage in deepwater exploration of our offshore fields.  These rigs will arrive in Brazil and begin operations during 2011 and 2012.  Of these 22 rigs, one will have the capacity to operate in water depths of up to 1,500 meters (4,920 feet), one will have the capacity to operate in water depths of up to 1,900 meters (6,233 feet), three will be capable of operating in water depths of up to 2,000 meters (6,560 feet), seven will be capable of operating in water depths of up to 2,400 meters (7,830 feet), and 10 will be capable of drilling in water depths of up to 3,000 meters (9,840 feet).  All of these rigs will be chartered by us and have been built or are being built in shipyards outside Brazil.

In addition to these 22 new drilling rigs already contracted, we have also announced plans for 28 rigs to be built in Brazil, supporting the development of the Brazilian rig building industry so that it can meet our long-term needs.  To this end, we have awarded one contract for seven drilling rigs to be built in the Atlântico Sul shipyard in Pernambuco State.  These rigs will be owned by Sete Brasil S.A. (Sete BR), a Brazilian company in which we hold a 10% interest.  We expect to fulfill our future drilling requirements with a combination of rigs built in Brazil, supplemented when needed by the international fleet of deepwater rigs.

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For our shallow water segment, we are building and will operate two jack-up drilling units designed to operate in water depths of up to 107 meters (350 feet) with High Pressure High Temperature (HPHT) capabilities.  We expect to begin operating these units in 2012.

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

 

2010

2009

2008

 

Leased

Owned

Leased

Owned

Leased

Owned

Onshore

22

12

31

13

25

11

Offshore, by water depth (WD)

44

8

36

8

31

8

Jack-up rigs

1

4

2

4

2

4

Floating rigs:

43

4

34

4

29

4

500 to 1000 meters WD

11

2

9

2

9

2

1001 to 2000 meters WD

19

2

20

2

17

2

2001 to 3000 meters WD

13

0

5

0

3

0

           

We announced in November 2010 that we had signed two contracts worth a total of U.S.$3.46 billion for the construction of eight hulls for FPSOs to be used in the pre-salt area of the Santos Basin.  The FPSOs will be built in the State of Rio Grande do Sul.  These units are part of the new strategy for the construction of production units that emphasizes project simplification and the use of standardized equipment.  By producing identical hulls in series we expect to accelerate construction, gain economies of scale and minimize costs.

We are also increasing our use of industry standard equipment instead of developing our own customized equipment.  We intend to minimize costs by increasing supervision over suppliers and dividing engineering procurement and construction packages into smaller pieces.

Refining, Transportation and Marketing   

 

Refining, Transportation and Marketing Key Statistics

 

2010

2009

2008

 

(U.S.$ million)

Refining, Transportation and Marketing:

 

 

 

Net operating revenues

97,540

74,307

95,659

Income (loss) before income tax

2,278

9,980

(3,017)

Total assets at December 31

69,487

49,969

27,166

Capital expenditures

15,356

10,466

7,234

 

We are an integrated company with a dominant market share in our home market.  We own and operate 12 refineries in Brazil, with a total net distillation capacity of 2,007 mbbl/d, and are one of the world’s largest refiners.  As of December 31, 2010, we operated 90% of Brazil’s total refining capacity.  We supplied almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of our Distribution segment.  We operate a large and complex infrastructure of pipelines and 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.

We also import and export crude oil and oil products.  We import certain oil products, particularly diesel, for which Brazilian demand exceeds refining capacity.  We expect the need for imports to decline in the future as we build additional refining capacity and upgrade our refineries to facilitate the processing of domestically produced crudes. 

Our Refining, Transportation and Marketing segment also includes petrochemical operations that add value to the hydrocarbons we produce and meet the needs of the growing Brazilian economy. 

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We participate in refining, transportation and marketing operations outside of Brazil through our International business segment.  See “—International.”

Refining

Our refining capacity in Brazil as of December 31, 2010, was 2,007 mbbl/d and our average throughput during 2010 was 1,798 mbbl/d.

The following table shows the installed capacity of our Brazilian refineries as of December 31, 2010, and the average daily throughputs of our refineries in Brazil and production volumes of principal oil products in 2010, 2009 and 2008.

Capacity and Average Throughput of Refineries

 

 

Crude
Distillation
Capacity at
December 31,
2010

 

 

 

Average Throughput

Name (Alternative Name)

Location

2010

2009

2008

 

 

(mbbl/d)

(mbbl/d)

LUBNOR

Fortaleza (CE)

7

8

7

6

RECAP (Capuava)

Capuava (SP)

53

36

44

45

REDUC (Duque de Caxias)

Rio de Janeiro (RJ)

242

256

238

256

REFAP (Alberto Pasqualini)

Canoas (RS)

189

145

169

142

REGAP (Gabriel Passos)

Betim (MG)

151

143

140

143

REMAN (Isaac Sabbá)

Manaus (AM)

46

42

41

39

REPAR (Presidente Getúlio Vargas)

Araucária (PR)

189

170

185

183

REPLAN (Paulínia)

Paulinia (SP)

396

316

341

324

REVAP (Henrique Lage)

São Jose dos Campos (SP)

252

238

241

205

RLAM (Landulpho Alves)

Mataripe (BA)

279

250

220

254

RPBC (Presidente Bernardes)

Cubatão (SP)

170

160

165

168

RPCC (Potiguar Clara Camarão)

Guamaré (RN)

34

33

 

 

Total

 

2,007

1,798 

1,791 

1,765 

 

In recent years, we have made substantial investments in our refinery system for the following purposes:

 

         Improve gasoline and diesel quality to comply with stricter environmental regulations;

         Increase crude slate flexibility to process more Brazilian crude, taking advantage of light/heavy crude price differentials; and

         Reduce the environmental impact of our refining operations.

In 2010, we invested a total of U.S.$6,681 million in our refineries, of which U.S.$5,342 million was invested for hydrotreating units to improve the quality of our diesel and gasoline, U.S.$1,203 million for coking units to convert heavy oil into lighter products, and U.S.$136 million for debottlenecking projects.

During 2011, we expect to complete the following investment projects at our refineries:

         Diesel quality upgrades at RECAP and RLAM; and

         Gasoline quality upgrades at REFAP, RPBC, REDUC, REGAP, REVAP, RLAM and RECAP.

The following refinery upgrades are underway for expected completion between 2012 and 2014:

         Diesel quality upgrades at REGAP, REPAR, REPLAN and RPBC;

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         Gasoline quality upgrades at REPAR; and

         Delayed coking units at Abreu e Lima Refinery, Comperj, Premium Refinery – 1st Phase and REPAR.

The following refinery upgrade projects are scheduled for completion after 2014:

         Diesel quality upgrades at REDUC; and

         Mild thermal cracking units to improve diesel and gasoline quality at REMAN.

By the end of 2013, we will reduce the maximum sulfur content of the diesel produced in our refineries from 1800 ppm to 500 ppm, and six of our refineries will be producing 50 ppm sulfur diesel.  By the beginning of 2014, we will reduce the maximum sulfur content of the gasoline produced in our refineries from 1,000 ppm to 50 ppm.

Major Refinery Projects        

Brazil has one of the world’s most dynamic economies with above average rates of demand growth for automotive fuels.  We are planning capacity expansions to meet the needs of this growing market and add value to our growing volumes of crude oil production in Brazil.  We are currently building two new refining facilities:

         Complexo Petroquímico do Rio de Janeiro—Comperj, an integrated refining and petrochemical complex.  We broke ground in 2008, and began construction in 2010.  The 165 mbbl/d refining operation is scheduled to start up in 2013.  A second phase, scheduled for 2018, will increase capacity to 330 mbbl/d and add petrochemicals manufacturing.  

         Abreu e Lima, a refinery in Northeastern Brazil in a proposed partnership with Petróleos de Venezuela S.A. (PDVSA), the Venezuelan state oil company.  This refinery is designed to process 230 mbbl/d of crude oil to produce 162 mbbl/d of low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke.  We expect operations to come on stream in 2013.

We are in the planning stage for two new refineries in Northeastern Brazil.  Both refineries will be designed to process 20° API heavy crude oil, maximize production of low sulfur diesel, and also produce LPG, naphtha, low sulfur kerosene, bunker fuel and petroleum coke.  Both will be integrated with marine storage terminals.

         Premium I in the State of Maranhão will be built in two phases of 300 mbbl/d each.

         Premium II in the State of Ceará will have processing capacity of 300 mbbl/d.

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

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

 

2010

2009

2008

 

 

 

 

Diesel

716

737

694

Gasoline

351

331

343

Fuel oil

243

243

255

Naphtha

133

143

136

LPG

132

135

142

Jet fuel

80

74

65

Other

176

159

153

Total domestic output of oil products

1,832

1,823

1,787

Installed capacity

2,007

1,942

1,942

Utilization (%)

90

92

91

Domestic crude oil as % of total feedstock processed

82

79

78

 


(1)                  Unaudited.

(2)                  As registered by the ANP.

 

Domestic Sales Volumes, mbbl/d

 

2010

2009

2008

Diesel

809

740

760

Gasoline

394

338

344

Fuel oil

100

101

110

Naphtha

167

164

151

LPG

218

210

213

Jet fuel

92

77

75

Other

180

140

84

Total oil products

1,960

1,770

1,737

Ethanol and other products

99

96

88

Natural gas

319

240

321

Total domestic market

2,378

2,106

2,146

Exports

698

707

676

International sales and other operations

593

541

552

Total international market

1,291

1,248

1,228

Total sales volumes

3,669

3,354

3,374

 

Delivery Commitments  

We sell crude oil under a variety of contractual obligations, primarily through long-term and spot-market contracts.  Our spot-market contracts specify the delivery of fixed and determinable quantities, subject to a price negotiation with third parties on a delivery-by-delivery basis. We are contractually committed under one long-term supply contract to deliver a total of approximately 300 mbbl/d in 2011, 200 mbbl/d in 2012 and 200 mbbl/d in 2013 of crude oil. We have met all contractual delivery commitments, and we believe our domestic proved reserves are sufficient to allow us to continue to deliver all contracted volumes.  We expect our contractual delivery obligations to increase over the next nine years as we increase our crude oil production.  For 2011, approximately 55% of our exported domestic crude oil production will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports  

We use exports and imports of crude oil and oil products to balance our domestic production and refinery capacity with market needs and optimize our refining margins.  Much of the crude oil we produce in Brazil is heavy or intermediate, and we import some light crude to balance the slate for our refineries, which were originally designed to run on lighter imported crude, and export heavier crude that is surplus to our needs. 

 

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We import diesel, for which there is insufficient production capacity in our Brazilian refineries.  We export fuel oil, of which 65 mbbl/d was exported as bunker fuel.  Our imports and exports of other products, such as gasoline, depend on demand levels and relative pricing in the Brazilian market.  The table below shows our exports and imports of crude oil and oil products in 2010, 2009 and 2008:

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

 

2010

2009

2008

Exports(1) 

 

 

 

Crude oil

497

478

439

Fuel oil (including bunker fuel)

153

150

152

Gasoline

14

38

40

Other

33

39

42

Total exports

697

705

673

Imports

 

 

 

Crude oil

316

396

373

Diesel and other distillates

177

78

127

LPG

58

45

40

Gasoline

9

0

0

Naphtha

42

25

23

Other

13

3

7

Total imports

615

547

570

 


(1)                  Includes sales made by PifCo to unaffiliated third parties, including sales of oil and oil products purchased internationally.

Logistics and Infrastructure

We own and operate an extensive network of crude oil and oil products pipelines in Brazil that connect our terminals, refineries and other primary distribution points.  On December 31, 2010, our onshore and offshore, crude oil and oil products pipelines extended 15,199 km (9,397 miles).  We operate 28 marine storage terminals and 20 other tank farms with nominal aggregate storage capacity of 63 million barrels.  Our marine terminals handle an average 10,422 tankers annually.  We are working in partnership with other companies to develop and expand Brazil’s ethanol pipeline and logistics network.

Until 1998, we held the monopoly on oil and natural gas pipelines in Brazil and shipping oil products to and from Brazil.  The deregulation of the Brazilian oil sector in that year provided for open competition in the construction and operation of pipeline facilities and gave the ANP the power to authorize entities other than Petrobras to transport crude oil, natural gas and oil products.  In accordance with this deregulation, we transferred our transportation and storage network and fleet to a separate wholly owned subsidiary, Petrobras Transporte S.A.—Transpetro, to allow third parties to access our excess capacity on a non-discriminatory basis.  We enjoy preferred access to the Transpetro network based on our historical usage levels and, in practice, third parties make very limited use of this network.

We operate a fleet of owned and chartered vessels.  These provide shuttle services between our producing basins offshore Brazil and the Brazilian mainland, and shipping to other parts of South America and internationally.  The fleet includes double-hulled vessels, which operate internationally where required by law, and single-hulled vessels, which operate in South America and Africa only.  We are increasing our fleet of owned vessels to replace older vessels, decrease our dependency on chartered vessels and exposure to charter rates tied to the U.S. dollar, and accommodate growing production volumes.  Upgrades will include replacing single-hulled tankers with double-hulled vessels and replacing vessels nearing the end of their 25-year useful life.  Our long-term strategy continues to focus on the flexibility afforded by operating a combination of owned and chartered vessels.

We plan to take delivery of 49 new vessels by 2015, all to be built in Brazilian shipyards.  We have ongoing contracts with five shipyards for delivery of 41 large oil tankers, bunkering vessels and LPG carriers between 2011 and 2015.  We expect to contract an additional eight product tankers in 2011. 

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The table below shows our operating fleet and vessels under contract as of December 31, 2010. 

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2010

 

In Operation

Under Contract/Construction

 

Number

Tons Deadweight Capacity

Number

Tons Deadweight Capacity

Owned fleet: 

 

 

 

 

Tankers

40

2,495,451

33

3,570,350

LPG tankers

6

40,171

8

42,200

Anchor Handling Tug Supply (AHTS)

1

2,163

0

0

Floating, Storage and Offloading (FSO)

1

28,903

0

0

Layed-up vessel

4

148,620

0

0

Total

52

2,715,308

41

3,612,550

 

 

 

 

 

Chartered vessels:  : 

 

 

 

 

Tankers

214

21,841,155

 

 

LPG tankers

25

515,568

 

 

Total

239

22,356,723

 

 

 

Petrochemicals

 

Our petrochemicals operations provide a growing market for the crude oil and other hydrocarbons we produce, increase our value added and provide domestic sources for products that would otherwise be imported.  Our strategy is to increase domestic production of basic petrochemicals and engage in second generation and biopolymer activities through investments in companies in Brazil and abroad, capturing synergies within all our businesses. 

 

In the past, the Brazilian petrochemicals industry was fragmented with a large number of small companies, many of which were not internationally competitive and were therefore poor customers for our petrochemical feedstocks.  In a series of mergers and a capital subscription completed in 2010, we have participated in consolidating and restructuring the Brazilian petrochemicals industry by creating Brazil’s largest petrochemicals company and one of the largest producers of thermoplastic resin in the Americas, Braskem S.A. (Braskem).  Braskem is a publically traded company in which we hold a 36.1% interest.  The controlling shareholder, with 38.3%, is Odebrecht S.A. (Odebrecht).  Braskem operates 31 petrochemical plants, produces basic petrochemical and plastics, and conducts related distribution and waste processing operations.

The table below sets forth the primary production capacities of Braskem as of December 31, 2010:

Braskem: Nominal Capacity by Petrochemical Type

 

(mmt/y)

Braskem

 

Ethylene

3.77

Propylene

1.59

Polyethylene

3.06

Polypropylene

2.88

PVC

0.51

Cumene

0.32

 

 

 

On April 1, 2011, we announced the acquisition of Innova S.A. from Petrobras Energia International S.A., a wholly owned subsidiary of Petrobras Argentina S.A., for U.S.$332 million.  Innova S.A. is located in the Petrochemical Complex of Triunfo in the State of Rio Grande do Sul in Southern Brazil.  The acquisition will allow us to further our goals related to the development of the Brazilian petrochemicals sector while permitting Petrobras Argentina S.A. to concentrate on activities in Argentina.

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We have three new petrochemcials projects under construction or in various stages of engineering or design:

         Complexo Petroquímico do Rio de Janeiro—Comperj: we have plans to develop a petrochemicals complex to be integrated with the Comperj refinery to produce materials for the plastics industry;

         PetroquímicaSuape Complex in Pernambuco:  to produce purified terephthalic acid (PTA), polyethylene terephthalate (PET) resin, and polymer and polyester filament textiles; and

         Companhia de Coque Calcinado de Petróleo—Coquepar:  calcined petroleum coke plants in Rio de Janeiro and Paraná. 

Distribution  

Distribution Key Statistics

 

2010

2009

2008

 

(U.S.$ million)

Distribution:

 

 

 

Net operating revenues

37,308

29,672

30,892

Income before income tax

1,101

960

1,245

Total assets at December 31

7,529

6,127

4,775

Capital expenditures

482

369

309

 

We are Brazil’s leading oil products distributor, operating through our own retail network, through our own wholesale channels, and by supplying other fuel wholesalers and retailers.  Our Distribution segment sells oil products that are primarily produced by our Refining, Transportation and Marketing segment (RTM), and works to expand the domestic market for these oil products and for other fuels, including LPG, ethanol and biodiesel. 

 

The primary focus of our Distribution segment is to:

         Lead the market in the domestic distribution of oil products and biofuels, increasing our market share and profitability through an integrated supply chain; and

         Become the preferred brand of our consumers while upholding and promoting social and environmental responsibility.

We supply and operate Petrobras Distribuidora S.A.—BR, which accounts for 38.8% of the total Brazilian retail and wholesale distribution market.  BR distributes oil products, ethanol and biodiesel, and vehicular natural gas to retail, commercial and industrial customers.  In 2010, BR sold the equivalent of 797.5 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (44.4%) was diesel.

At December 31, 2010, our BR branded service station network was Brazil’s leading retail marketer, with 7,306 service stations, or 19.2% of the stations in Brazil.  BR-owned and franchised stations make up 30.9% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas and lubricants. 

Most BR stations are owned by franchisees that use the BR brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising.  We own 767 of the BR 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 BR brand image and by the remodeling of service stations and addition of lubrication centers and convenience stores.  

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 Our wholesale distribution of oil products and biofuels under the BR brand to commercial and industrial customers accounts for 56.1% of the total Brazilian wholesale market.  Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.

We also sell oil products produced by RTM to other retailers and to wholesalers.

Our LPG distribution business, Liquigas Distribuidora, held a 22.3% market share and ranked second in LPG sales in Brazil in 2010, according to the ANP. 

Oil products sales in Brazil increased 9.0% in 2010 compared to 2009.  This increase was due mainly to Brazil’s economic growth and its corresponding growth in household income and consumer credit.

We participate in the retail sector in other South American countries through our International business segment.  See “—International.”

Gas and Power  

Gas and Power Key Statistics

 

2010

2009

2008

 

(U.S.$ million)

Gas and Power:

 

 

 

Net operating revenues

8,507

5,966

9,345

Income (loss) before income tax

1,014

496

(443)

Total assets at December 31

29,907

25,361

15,348

Capital expenditures

4,099

5,116

4,256

 

For more than two decades, we have been working actively to develop simultaneously Brazil’s natural gas reserves, production, infrastructure and markets.  As a result of our efforts, natural gas in 2009 supplied 8.7% of Brazil’s total energy needs, compared to 3.7% in 1998, and is projected to supply 14.2% of Brazil’s total energy needs by 2020, according to Empresa de Pesquisa Energética, a branch of the MME.

 

In 2010, our Exploration and Production operations produced 63.3 mmm3/d (2,235.44 mmcf/d) of natural gas.  The development plans for these operations are expected to result in substantial increases in gas production from the Espírito Santo and Santos Basins off the Brazilian coast, including from pre-salt reservoirs.  We expect domestic gas production to play an increasingly important role in the supply mix, but we will continue to import gas from Bolivia and use LNG imports selectively to provide supplemental supplies, particularly to meet surges in demand from the power sector. 

Our Gas and Power segment is responsible for monetizing and delivering the gas produced by our Exploration and Production segment, and gas purchased from other sources, including imported LNG.  The segment comprises gas transmission and distribution, LNG regasification, the manufacture of nitrogen-based fertilizers, gas-fired power generation, and power generation from renewable sources, including solar, wind and small-scale hydroelectric.

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

         Add value by monetizing Petrobras’ associated and non-associated natural gas resources;

         Assure flexibility and reliability in the commercialization of natural gas;

         Expand the use of LNG to meet Brazilian gas demand and diversify our supply of natural gas;

         Optimize our thermoelectric power plant portfolio and supplement it with power generation from renewables; and

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         Create an additional flexible means of monetizing our natural gas resources by investing in capacity to manufacture nitrogen fertilizers.     

Natural Gas

Following a multi-year infrastructure development program, including investments of approximately U.S.$13.33 billion (R$26.98 billion) in the last five years, we have built an integrated system centered around two main, interlinked, pipeline networks that allows us to deliver natural gas from our main offshore natural gas producing fields in the Campos and Espírito Santo Basins, as well as from two LNG terminals and a gas pipeline connection with Bolivia.

Our natural gas pipelines span 9,239 km (5,741.2 miles), including:

         Malha Sudeste (Southeast Network) (2,273.7 km/1,412.8 miles) serving Brazil’s most industrialized region, including Rio de Janeiro and São Paulo;

         Malha Nordeste (Northeast Network) (2,183.4 km/1,356.7 miles);

         Gasene (Southeast Northeast Interconnection Gas Pipeline) (1,387 km/861.8 miles);

         A 2,593 km (1,611.2 miles) Brazilian portion of the Bolivia-Brazil natural gas pipeline in Southeastern Brazil; and

         Urucu-Coari-Manaus pipeline (802.5 km/498.7 miles) and branches, connecting the Solimões Basin to Manaus and other northern cities.

In 2010, we invested U.S.$3.41 billion in our pipeline network, completed the Gasene interconnector, and extended our total network by 1,696 km (1,054 miles) as compared to 2009.   The following pipelines commenced operations in 2010:

Natural Gas Pipelines Starting Operations in 2010

Name

Route

Length (km/miles)

Capacity

 

 

 

 

Gascac

Cacimbas-Catu (completes Gasene)

954 km (593 miles)

up to 20 mmm³/d (706.3 mmcf/d)

Gasduc III

Cabiúnas-Reduc

181 km (112.5 miles)

40 mmm3/d (1,412 mmcf/d)

Gasbel II

Volta Redonda - Queluzito

268.9 km (167 miles)

up to 5 mmm³/d (176.6 mmcf/d)

Paulínia-Jacutinga

Paulínia-Jacutinga

93 km (58 miles)

up to 5.0 mmm3/d (176.6 mmcf/d)

Pilar-Ipojuca

Pilar-Ipojuca

189.1 km (117.5 miles)

up to 15 mmm³/d (529.7 mmcf/d)

GASCAV-UTG Sul Capixaba

Cabiúnas - UTG

10 km (6.2 mile)

2 mmm³/d (70.63 mmcf/d)

 

                        In 2011, we plan to invest a further U.S.$1.5 billion for incremental additions to our gas transportation system.

 

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The map below shows our existing pipelines and our pipelines under construction.

We own and operate two LNG terminals, one in Rio de Janeiro with a send-out capacity of 20 mmm3/d (706 mmcf/d), and the other in Pecém (Ceará) in Northeastern Brazil with a send-out capacity of 7 mmm3/d (247 mmcf/d).  The terminals are supported by two LNG regasification vessels with capacities of 14 mmm3/d (494 mmcf/d) and 7 mmm3/d (247 mmcf/d).  These terminals and regasification ships give us the flexibility to import gas to supplement domestic natural gas supplies.  In 2010, we purchased 41 LNG cargoes, of which 36 were imported into Brazil and 5 were sold in international markets.  In addition, we plan to build a third LNG terminal in the State of Bahia, the construction of which will begin in 2012 and which we expect to be completed in 2013. 

We hold interests ranging from 24% to 100% in 20 of Brazil’s 27 local gas distribution companies.  In Espírito Santo State we hold exclusive rights to distribute natural gas through our BR subsidiary.  We estimate that we had a 23% net equity interest in the combined 49.0 mmm3/d (1,730 mmcf/d) of natural gas distributed by Brazil’s local distribution companies in 2010.

47


 

According to our estimates, our two most significant holdings, CEG Rio and Bahiagás, are Brazil’s third and fourth largest gas distributors. These companies, together with independent distributors Comgás and CEG supply 64% of the Brazilian market.  

Principal Natural Gas Local Distribution Holdings

Name

State

Group Share %

Average Gas Sales in 2010 (mmm3/d) 

Customers

 

 

 

 

 

CEG RIO

Rio de Janeiro

37.41

6,075

24,506

BAHIAGAS

Bahia

41.50

3,677

5,719

GASMIG

Minas Gerais

40.00

2,635

292

COPERGÁS

Pernambuco

41.50

2,342

3,415

 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

 

2010

2009

2008

Sources of natural gas supply

 

 

 

Domestic production

28.6

23.0

30.3

Imported from Bolivia

27.1

22.4

30.4

LNG

7.6

0.7

0.0

Total natural gas supply

63.3

46.1

60.7

Sales of natural gas

 

 

 

Sales to local gas distribution companies(1)

37.2

32.4

36.8

Sales to gas-fired power plants

12.2

4.1

12.8

Total sales of natural gas

49.4

36.5

49.6

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

13.9

9.6

11.1

Revenues (U.S.$ billion)(3)

4.7

3.5

5.1

 

 

 

 


(1)                  Includes sales to local gas distribution companies in which we have an equity interest.

(2)                  Includes gas used in the transport system.

(3)                  Excludes internal consumption.

Natural gas consumption in Brazil by industrial, commercial and retail customers increased 15% in 2010 compared to 2009.  This increase was due mainly to Brazil’s economic growth and more competitive pricing of natural gas sold through short-term auctions.  Natural gas consumption in the power generation industry increased 198% from 2009 to 2010 due to reduced rainfall and higher industrial output.  Natural gas consumption by refineries and fertilizer plants increased 20%.

Long-Term Natural Gas Commitments  

When we began investment in the Bolivia-Brazil pipeline in 1996, we entered into long-term contracts with three companies:

         Gas Supply Agreement (GSA) with the Bolivian state-owned company Yacimientos Petrolíferos Fiscales Bolivianos (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.  On December 18, 2009, Petrobras and YPFB signed the fourth amendment to the GSA, which provides for additional payments to YPFB for liquids contained in the natural gas purchased by Petrobras through the GSA, of between U.S.$100 million and U.S.$180 million per year, retroactive to May 2007.  As of February 2010, Petrobras has paid all obligations owed for 2007.  Additional payments for subsequent years will be paid after YPFB fulfills conditions precedent established in the amendment;

         Ship-or-Pay agreement with Gás Transboliviano (GTB), owner and operator of the Bolivian portion of the pipeline to transport certain minimum volumes of natural gas through 2019; and

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         Ship-or-Pay agreement with Transportadora Brasileira Gasoduto Bolivia-Brasil (TBG), owner and operator of the Brazilian portion of the pipeline to transport certain minimum volumes of natural gas through 2019.

Our volume obligations under the ship-or-pay arrangements were generally designed to match our gas purchase obligations under the GSA.  The tables below show our contractual commitments under these agreements for the five-year period from 2011 through 2015.

Commitments to Purchase and Transport Natural Gas in Connection with Bolivia-Brazil Pipeline

 

2011

2012

2013

2014

2015

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 (U.S.$)(2)

72.00

77.40

82.90

82.30

81.30

Estimated payments (U.S.$ million)(3)

1,899.65

1,874.02

2,007.05

2,073.52

2,049.25

 

 

 

 

 

 

Ship-or-pay contract with GTB

 

 

 

 

 

Volume commitment (mmm3/d)

30.00

30.00

30.00

30.00

30.00

Volume commitment (mmcf/d)

1,059.00

1,059.00

1,059.00

1,059.00

1,059.00

Estimated payments (U.S.$ million)(5)

137.10

137.78

138.46

139.14

139.82

 

 

 

 

 

 

Ship-or-pay contract with TBG

 

 

 

 

 

Volume commitment (mmm3/d)(4)

35.28

35.28

35.28

35.28

35.28

Volume commitment (mmcf/d)

1,246.09

1,246.09

1,246.09

1,246.09

1,246.09

Estimated payments (U.S.$ million)(5)

498.15

501.32

510.42

526.34

526.87

 


(1)           25.3% of contracted volume supplied by Petrobras Bolivia.

(2)           Brent price forecast based on our 2020 Strategic Plan.

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

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

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

  

Gas Sales Contracts  

In recent years, we have introduced a variety of supply contracts designed to create flexibility in matching customer demand with our gas supply capabilities.  These include flexible, interruptible and preferential gas supply contracts as well as auction mechanisms for short-term contracts.  In 2010, we introduced weekly electronic auctions offering short-term natural gas volumes that had been reserved for gas-fired power plants, but were not dispatched.

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The table below shows our future gas supply commitments from 2011 to 2015, including sales to both local gas distribution companies and gas-fired power plants. 

Future Commitments under Natural Gas Sales Contracts, mmm3/d

 

2011

2012

2013

2014

2015

To local gas distribution companies:

 

Related parties(1)

17.40

18.90

19.71

20.13

20.23

Third parties

18.05

18.04

17.75

17.65

17.80

To gas-fired power plants:

 

 

 

 

 

Related parties(1)

4.23

4.41

3.44

3.45

3.46

Third parties

5.02

6.52

8.28

9.78

9.87

Total(2)

44.70

47.87

49.17

51.01

51.36

Estimated contract revenues (U.S.$ billion)(3)(4)

5.7

6.1

6.2

6.3

6.4

 


(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 an equity interest.

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

(3)           Figures show revenues net of taxes.  Estimates are based on outside sales and do not include internal consumption or transfers.

(4)           Prices may be adjusted in the future and actual amounts may vary.

Short-Term Natural Gas Commitments  

In 2009, we contributed to the development of a short-term market for natural gas sales, focusing on the industrial market as an alternative to the market for power generation when the power plants are not being dispatched.  Sales under these short-term contracts were accomplished by an electronic auction system conducted by means of the Internet.  These auctions commercialized natural gas volumes reserved for but not otherwise utilized by local gas distributors, and allowed us to offer end users more competitive prices.  On average, 4.4 mmm³/d of natural gas were sold under these short-term contracts in 2009, with volumes reaching 7.8 mmm³/d in 2010.  The last auction resulted in a sales record of 9.4 mmm³/d for a four-month delivery period.

In April 2010, we implemented a new method for selling short-term natural gas.  On a weekly basis, we offer for sale to the non-thermoelectric market volumes of natural gas that had been originally reserved for gas-fired power plants but that were not dispatched.  Under this method, weekly sales begin with orders from gas distribution companies for deliveries to be made within the subsequent four-week period.  Depending on the availability and cost of natural gas during that period, we have the option of either accepting or rejecting the orders.  This new method allowed us to sell an average of 300,000 m³/d of natural gas, with a sales record of 1.6 mmm³/d in May 2010.

Fertilizers

We are expanding production of nitrogenous fertilizers in order to meet the growing needs of Brazilian agriculture, to substitute for imports, and to expand the market for natural gas.  Effective January 1, 2010, we transferred our fertilizer business from the Refining, Transportation and Marketing segment to the Gas and Power segment in order to better exploit business synergies.

Our fertilizer plants in Bahia and Sergipe produce ammonia and urea for the Brazilian market.  In 2010, these plants sold a combined 235,739 t of ammonia and 772,059 t of urea.  We are currently building a facility with the capacity to produce 200,000 m3/year of ARLA 32, an aqueous 32.5% urea solution.  We are also conducting feasibility studies for up to four additional fertilizer facilities.

Power  

To further our goal of developing natural gas demand in Brazil, we have invested in power plants and the associated system of gas supply contracts.  These plants are designed to supplement power from the hydroelectric stations that supply an average of 90% of the country’s electric power needs in a given year.  Gas-fired power is particularly needed during times of peak demand, high economic growth, and drought.

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We own interests in 25 thermoelectric power plants with a combined installed capacity at year-end 2010 of 5,771 MW, equivalent to 64% of Brazil’s total thermoelectric capacity.  Of this total, 5,372 MW was in thermoelectric plants controlled by us and 99% (5,340 MW) was gas-fired.  Under Brazil’s power pricing regime, we may sell only power-generating capacity that is certified by the MME.  At year-end 2010, due to gas supply constraints, the MME certified 3,619 MWavg of commercial capacity, or 67% of the installed capacity controlled by us. 

In 2010, the Brazilian hydroelectric system generated 48,270 MWavg of electricity, or 89% of the country’s needs.  The Sistema Interligado Nacional—SIN (National Interconnected Power System), was called upon to supplement this power with an average 5,943 MW, of which we generated an average 1,837 MW of electricity in 2010, compared to 525 MW in 2009. 

We also export energy to neighboring countries.  In 2010, we exported 110.2 MWavg to Argentina and Uruguay.   

Commitments for Future Generation Capacity and Electricity Sales

Under a 2007 agreement with the ANEEL, we are committed to increasing our ability to supply power to the grid by increasing natural gas supplies, including LNG, converting some existing power plants to dual-fuel operation and leasing backup oil-fired power plants.  By 2011 we are committed to supply up to 5,609 MW of installed capacity and expect to have an average 3,669 MW certified capacity available for sale, exclusive of our own power requirements.

The table below shows the installed capacity and commercial capacity of the thermoelectric power plants controlled by us for 2010 through 2013 under our agreement with the ANEEL: 

Installed Power Capacity and Utilization

 

2010

2011

2012(2)

2013

Gross installed capacity (MW)

5,372

5,609

5,205

5,205

Certified commercial capacity(1) (MWavg)

3,619

3,669

3,353

3,462

 


(1)                  Weighted average of certified commercial capacity for the year.

(2)                  Our installed and commercial capacity will be reduced in 2012 due to the termination of our lease of the Araucaria thermoelectric power plant.

In 2010, we invested U.S.$358.2 million (R$630.8 million) in thermoelectric generation.

We sell our power output under long-term contracts for “standby availability” and long-term bilateral contracts, primarily with power distribution companies.  Of the total 3,579 MWavg of power available for sale in 2012 (including the certified commercial capacity of our plants and 226 MWavg of power purchased from third parties), approximately 45% has already been sold as standby availability in the 2005 and 2006 auctions, and approximately 55% has been committed under bilateral contracts.  We also have the option to fulfill our contractual commitments by purchasing power from third parties.

The following table summarizes our commitments under standby availability and bilateral contracts, power purchased from third parties, and the power we expect to be available for sale.

Power Available for Sale and Power Commitments

 

2009

2010

2011

2012

2013

 

(MWavg)

Total available for sale:

 

Commercial capacity (MW) (1)

2,811

3,619

3,669

3,353

3,462

Purchased from third parties

329

234

202

226

200

Commitments:

 

 

 

 

 

Standby availability auctions

821

1,391

1,596

1,596

1,596

Bilateral contracts

2,103

2,442

2,214

1,983

1,587

Remaining available for sale (1)(2)

216

20

61

0

479

 


(1)      Projections based on existing capacity and expected supply of gas.

(2)      Represents the remaining commercial capacity available for sale beginning in 2011.

 

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In the 2005 and 2006 auctions, we sold standby availability of 1,391 and 205 MWavg, respectively, on 15-year contracts beginning in 2008 to 2011. Under the terms of these contracts, we will be compensated a fixed amount whether or not we generate any power, and we receive an additional amount for the energy we actually generate at a price that is set on the date of the auction and revised annually based on an inflation-adjusted fuel oil basket. This represented most of our capacity that is eligible to be sold through the auction system.  We have been compensated for the standby availability from the 2005 and 2006 auctions since 2008, with the capacity compensation stepping up through 2011, at which time it stabilizes. These contracts generate losses when our actual costs of generating power increase and our prices do not rise accordingly.

Our future commitments under bilateral contracts are 2,275 MWavg in 2011, 1,983 MWavg in 2012 and 2,066 MWavg in 2013.  The agreements will run off gradually, with the last contract expiring in 2028.  As existing bilateral contracts run-off, we will sell our remaining certified power-generation capacity under short- and medium-term bilateral contracts and auctions conducted by us and by the MME.

Renewable Energy

We have invested, alone and in partnership with other companies, in renewable power generation sources in Brazil including wind and small hydroelectric plants.  Our net interests are equivalent to 316.5 MW of hydroelectric capacity and 105.8 MW of wind capacity.  We and our partners sell energy from these plants directly to the Brazilian federal government via “reserve energy” auctions.

International   

International Key Statistics

 

2010

2009

2008

 

(U.S.$ million)

International:

 

 

 

Net operating revenues

13,463

10,197

10,940

Income (loss) before income tax

1,076

232

(605)

Total assets at December 31

16,170

14,914

13,439

Capital expenditures

2,167

2,111

2,908

 

We have operations in more than 20 countries outside Brazil, encompassing all phases of the energy business.  The primary focus of our international operations is to:

 

         Use our technical expertise in deepwater exploration and production to participate in high-potential and frontier offshore regions; and

         Integrate international downstream operations aligned with our domestic activities.

International Upstream Activities  

Most of our international activities are in exploration and production of oil and gas.  We have long been active in Latin America.  In the Gulf of Mexico and West Africa, we focus on opportunities to leverage the deepwater expertise we have developed in Brazil.  We have preliminary exploratory efforts underway in other regions.

In 2010, our net production outside Brazil averaged 146 mbbl/d of crude oil and NGLs and 16 mmm3/d (566 mmcf/d) of natural gas, representing 10% of our total production on a barrels of oil equivalent basis.

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Table of Contents

The table below shows our main exploration and production projects being developed worldwide. Additional information about certain of these projects and our exploration and production activities is provided in the text that follows.

Countries

Main International Exploration and Production Assets in Development

Main projects in development

Phase

Operated by

Petrobras interest (%)

South America          

 

 

 

 

1

Argentina(1)

Sierra Chata
Parva Negra
El Tordillo
La Tapera – Puesto Quiroga
25 de Mayo – Medanito
Puesto Hernandés

Production
Exploration
Production
Production
Production
Production

Petrobras
Petrobras
Partner
Partner
 Petrobras
Petrobras

46
100
36
36
100
38

2

Bolivia

San Alberto
San Antonio
Ingre
Itaú

Production
Production
Exploration
Exploration

Petrobras
Petrobras
Partner
Petrobras

35(2)
35(2)
100(2)
30(2)

3

Colombia

Balay 1
Tayrona
Cebucan
Villarica Norte

Exploration
Exploration
Exploration
Exploration

Petrobras
Petrobras
Petrobras
Petrobras

45
40
50
50

4

Peru

Lote 10
Lote 57
Lote 58

Production
Exploration
Exploration

Petrobras
Partner
Petrobras

100
45.16
100

5

Uruguay

Block 3
Block 4

Exploration
Exploration

Partner

Petrobras

40

40

6

Venezuela

Oritupano-Leona
Acema
La Concepción
Mata

Production
Production
Production
Production

Partner
Partner
Partner
Partner

40(3)
40(3)
40(3)
40(3)

North America

 

 

 

 

7

Mexico

Cuervito
Fronterizo

Production
Production

Petrobras
Petrobras

45(4)
45(4)

8

U.S.

Cascade
Chinook
Coulumb (MC-613)
Cottonwood
St. Malo
Tiber
Stones
Big Bend
Latigo
Logan

Development
Development
Production
Production
Development
Development
Development
Exploration
Exploration
Exploration

Petrobras
Petrobras
Partner
Petrobras
Partner
Partner
Partner
Petrobras
Partner
Partner

100
66.67
33.33
100
25
20
25
50
50
35

 

 

 

 

 

 

Africa

 

 

 

 

9

Angola

Block 2
Block 6
Block15
Block 18
Block 26
Block 34

Production
Exploration
Exploration
Exploration
Exploration
Exploration

Partner
Petrobras
Partner
Petrobras
Petrobras
Partner

28
40
5
30
80
30

10

Namibia

2714A

Exploration

Partner

50

11

Nigeria

Akpo
Agbami
Egina
Egina South
Preowei
OPL 315

Production
Production
Development
Exploration
Exploration
Exploration

Partner
Partner
Partner
Partner
Partner
Petrobras

20
13
20
20
20
45

 

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Table of Contents

Countries

Main International Exploration and Production Assets in Development

Main projects in development

Phase

Operated by

Petrobras interest (%)

12

Tanzania

Block 5
Block 6

Exploration
Exploration

Petrobras
Petrobras

100
100

Europe

 

 

 

 

13

Portugal

Camarão
Mexilhão

Exploration
Exploration

Petrobras
Petrobras

50
50

Asia

 

 

 

 

14

India

Cauvery

Exploration

Partner

 25 

Oceania

 

 

 

 

15

Australia

North Carnarvon

Exploration

Partner

50

16

New Zealand

Block 52707

Exploration

Petrobras

100

           

 


(1)                  Most of  the Argentine exploration and production projects are held through our indirect 67.2% share in PESA.

(2)                  Production-sharing contract, under which Petrobras’ expenditures are reimbursed only if exploration results in economically viable oil discoveries.

(3)                  Joint venture through PESA.

(4)                  Non-risk service contract, under which Petrobras’ expenditures are reimbursed regardless of whether exploration results in economically  viable oil discoveries.

 

During 2010, our capital expenditures for international exploration and production totaled U.S.$1.9 billion, representing 8.3% of our total exploration and production capital spending.

South America  

We are present in Argentina, Bolivia, Colombia, Ecuador, Peru, Venezuela and Uruguay.