20-F 1 y22597e20vf.htm FORM 20-F 20-F
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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, 2005
     
Commission File Number 1-15106   Commission File Number: 333-14168
     
PETRÓLEO BRASILEIRO S.A. – PETROBRAS   Petrobras International Finance Company
(Exact name of registrant as specified in its charter)   (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   Cayman Island
(Jurisdiction of incorporation or organization)   (Jurisdiction of incorporation or organization)
 
     
    Harbour Place
    103 South Church Street, 4th floor
Avenida República do Chile, 65   P.O. Box 1034GT — BWI
20031-912 – Rio de Janeiro – RJ   George Town, Grand Cayman
Brazil   Cayman Islands
(Address of principal executive offices)   (Address of principal executive offices)
 
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*    
PETROBRAS American Depositary Shares (as evidenced by   New York Stock Exchange
American Depositary Receipts), each representing    
4 Common Shares    
     
PETROBRAS Preferred Shares, without par value*    
PETROBRAS American Depositary Shares (as evidenced by   New York Stock Exchange
American Depositary Receipts), each representing    
4 Preferred Shares    
*   Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.
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:
PIFCo U.S.$500,000,000 9.125% Senior Notes due 2007
PIFCo U.S.$450,000,000 9.875% Senior Notes due 2008
PIFCo U.S.$400,000,000 9.00% Global Step-Up Notes due 2008
PIFCo U.S.$600,000,000 9.750% Senior Notes due 2011
PIFCo U.S.$750,000,000 9.125% Global Notes due 2013
PIFCo U.S.$750,000,000 8.375% Global Notes due 2018
PIFCo U.S.$600,000,000 7.75% Global Notes due 2014
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock
as of the close of the period covered by this Annual Report:

At December 31, 2005, there were outstanding:
2,536,673,672 PETROBRAS Common Shares, without par value
1,849,478,028 PETROBRAS Preferred Shares, without par value
50,000 PIFCo Common Shares
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.
Yes þ No o
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 o No þ
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 þ No o
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 þ [Petrobras]   Accelerated filer o   Non-accelerated filer þ [PIFCo]
Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 o Item 18 þ
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 o No þ
 
 

 


Table of Contents

TABLE OF CONTENTS
             
FORWARD-LOOKING STATEMENTS     4  
CERTAIN TERMS AND CONVENTIONS     5  
PRESENTATION OF FINANCIAL INFORMATION     5  
 
  Petrobras     5  
 
  PIFCo     6  
PRESENTATION OF INFORMATION CONCERNING RESERVES     6  
  IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS     7  
  OFFER STATISTICS AND EXPECTED TIMETABLE     7  
  KEY INFORMATION     7  
 
  Selected Financial Data     7  
 
  Exchange Rates     13  
 
  Risk Factors     14  
 
  Risks Relating to Our Operations     14  
 
  Risks Relating to PIFCo     19  
 
  Risks Relating to the Relationship between us and the Brazilian Government     20  
 
  Risks Relating to Brazil     20  
  INFORMATION ON THE COMPANY     25  
 
  History and Development of Petrobras     25  
 
  Our Competitive Strengths     27  
 
  Overview by Business Segment     31  
 
  Exploration, Development and Production     31  
 
  Refining, Transportation and Marketing     44  
 
  Distribution     55  
 
  Natural Gas and Power     58  
 
  International     65  
 
  PIFCo     76  
 
  Organizational Structure     80  
 
  Property, Plants and Equipment     81  
 
  Regulation of the Oil and Gas Industry in Brazil     82  
 
  Health, Safety and Environmental Initiatives     88  
 
  Competition     90  
 
  Insurance     91  
  OPERATING AND FINANCIAL REVIEW AND PROSPECTS     92  
 
  Management’s Discussion and Analysis of Petrobras’ Financial Condition and Results of Operations     92  
 
  Overview     92  
 
  Sales Volumes and Prices     93  
 
  Effect of Taxes on our Income     95  
 
  Financial Income and Expense     96  
 
  Inflation and Exchange Rate Variation     96  
 
  Results of Operations     98  
 
  Business Segments     108  
 
  Management’s Discussion and Analysis of PIFCo’s Financial Condition and Results of Operations     110  
 
  Overview     110  
 
  Purchases and Sales of Crude Oil and Oil Products     110  
 
  Results of Operations     111  
 
  Liquidity and Capital Resources     112  
 
  Critical Accounting Policies and Estimates     121  
 
  Impact of New Accounting Standards     124  
 
  Research and Development     126  
 
  Trend Information     127  
  DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES     128  
 
  Directors and Senior Management     128  
 
  Compensation     136  
 
  Indemnification of Officers and Directors     136  

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  Share Ownership     136  
 
  Fiscal Council     137  
 
  Audit Committee     137  
 
  PIFCo     138  
 
  Employees and Labor Relations     138  
  MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS     140  
 
  Major Shareholders     140  
 
  Petrobras Related Party Transactions     141  
 
  PIFCo Related Party Transactions     142  
  FINANCIAL INFORMATION     145  
 
  Petrobras Consolidated Statements and Other Financial Information     145  
 
  PIFCo Consolidated Statements and Other Financial Information     145  
 
  Legal Proceedings     145  
 
  Dividend Distribution     150  
  THE OFFER AND LISTING     151  
  Petrobras      151  
 
  PIFCo     157  
  ADDITIONAL INFORMATION     157  
 
  Memorandum and Articles of Incorporation of Petrobras     157  
 
  Restrictions on Non-Brazilian Holders     165  
 
  Transfer of Control     165  
 
  Disclosure of Shareholder Ownership     165  
 
  Memorandum and Articles of Association of PIFCo     165  
 
  Material Contracts     169  
 
  Exchange Controls     170  
 
  Taxation relating to our ADSs and common and preferred shares     171  
 
  Taxation relating to PIFCo’s notes     178  
 
  Documents on Display     181  
 
  PIFCo Senior Notes     182  
 
  PIFCo Global Notes     184  
 
  Sale of Future Receivables     186  
  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK     189  
 
  Petrobras     189  
 
  PIFCo     195  
  DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES     196  
  DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES     196  
  MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS     196  
  CONTROLS AND PROCEDURES     196  
  AUDIT COMMITTEE FINANCIAL EXPERT     197  
  CODE OF ETHICS     197  
  PRINCIPAL ACCOUNTANT FEES AND SERVICES     197  
 
  Principal Accountant Fees     197  
 
  Audit and Non-Audit Fees     197  
 
  Audit Committee Approval Policies and Procedures     198  
  EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES     198  
  PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS     198  
  FINANCIAL STATEMENTS     198  
  FINANCIAL STATEMENTS     198  
 EX-8.1: LIST OF SUBSIDIARIES
 EX-10.1: CONSENT LETTER OF DEGOLYER AND MACNAUGHTON
 EX-12.1: PETROBRAS' CERTIFICATIONS
 EX-12.2: PIFCO'S CERTIFICATIONS
 EX-13.1: PETROBRAS' CERTIFICATIONS
 EX-13.2: PIFCO'S CERTIFICATIONS

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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, and Section 21E of the Securities Exchange Act of 1934, as amended, 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:
    regional marketing and expansion strategy;
 
    drilling and other exploration activities;
 
    import and export activities;
 
    projected and targeted capital expenditures and other costs, commitments and revenues;
 
    liquidity; and
 
    development of additional revenue sources.
     Because these forward-looking statements involve risks and uncertainties, there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. These factors include:
    general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates;
 
    international and Brazilian political, economic and social developments;
 
    our ability to find, acquire or gain access to additional reserves and to successfully develop our current ones;
 
    uncertainties inherent in making estimates of our reserves;
 
    our ability to obtain financing;
 
    competition;
 
    technical difficulties in the operation of our equipment and the provision of our services;
 
    changes in, or failure to comply with, governmental regulations;
 
    receipt of governmental approvals and licenses;
 
    military operations, terrorist acts, wars or embargoes;
 
    the cost and availability of adequate insurance coverage; and
 
    other factors discussed below under “Risk Factors.”
     These statements are not guarantees of future performance and are subject to certain risks, uncertainties and assumptions that are difficult to predict. Therefore, our actual results could differ materially from those expressed or forecast in any forward-looking statements as a result of a variety of factors, including those in “Risk Factors.”

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     All forward-looking statements are expressly qualified in their entirety by this cautionary statement, and you should not place reliance on any forward-looking statement contained in this annual report.
     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.
     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.
CERTAIN TERMS AND CONVENTIONS
     A glossary of petroleum industry terms, a table of abbreviations and a conversion table are presented beginning on page 204.
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 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, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, 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. We also publish financial statements in Brazil in reais in accordance with the accounting principles required by Law No. 6404/76, as amended, or Brazilian Corporation Law and the regulations promulgated by the Comissão de Valores Mobiliários (Brazilian Securities Commission, or the CVM), or Brazilian GAAP, which differs in significant respects from U.S. GAAP.
     We are required by Brazilian Corporation Law to change auditors every five years and to select auditors through a bidding process authorized by the Board of Directors. From June 2003 through December 31, 2005, Ernst & Young Auditores Independentes S/S served as our independent auditors and audited our financial statements for each of the years ended December 31, 2005, 2004 and 2003. PricewaterhouseCoopers Auditores Independentes audited our financial statements for each of the years ended December 31, 2002 and 2001. As of January 1, 2006, we hired KPMG Auditores Independentes to serve as our independent auditors.
     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 remeasured or translated from the real amounts in accordance with the criteria set forth in Statement of Financial Accounting Standards No. 52 of the U.S. Financial Accounting Standards Board, or SFAS 52. 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 consolidated financial statements have been translated from reais on a similar basis;

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    forward-looking amounts, including estimated future capital expenditures, have all been based on our 2005-2015 Strategic Plan and 2006-2010 Business Plan and have been projected on a constant basis and have been translated from reais in 2006 at an estimated average exchange rate of R$3.01 to U.S.$1.00, and future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$45.00 per barrel for 2006, and U.S.$30.00 per barrel for 2007 and U.S.$25.00 per barrel for 2008 and thereafter, 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.
     We signed a final agreement for the acquisition of Petrobras Energía Participaciones S.A., or PEPSA, and Petrolera Entre Lomas S.A., or PELSA, in October 2002 and the acquisition was approved by Argentine government agencies in May 2003. Our results of operations for 2002 do not include PEPSA and PELSA’s results and our results of operations for 2003 only include PEPSA and PELSA’s results from June through December of 2003. We acquired Liquigás Distribuidora S.A. (formerly Sophia do Brasil S.A. and Agip do Brasil S.A.) in August 2004. Our results of operations for 2004 only include Liquigás Distribuidora’s results from August to December of 2004. See Note 20 to our audited consolidated financial statements for further information about these acquisitions.
     We adopted FIN 46 in our financial statements for the year ended December 31, 2003. Our interest in certain project finance special purpose entities and gas-fired power plants were consolidated on a line-by-line basis in the income statement beginning as of January 1, 2004. Although this consolidation affected each line of the income statement, it did not have a significant impact on our net income.
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, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, 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, Petrobras Finance Limited and Bear Insurance Company Limited – BEAR
PRESENTATION OF INFORMATION CONCERNING RESERVES
     The estimates of our proved reserves of crude oil and natural gas as of December 31, 2005, included in this annual report have been calculated according to the technical definitions required by the U.S. Securities and Exchange Commission, or the SEC. DeGolyer and MacNaughton provided estimates of most of our net domestic reserves as of December 31, 2005. 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.
     We also file oil and gas reserve estimates with governmental authorities in most of the countries in which we operate. On January 16, 2006, we filed reserve estimates for Brazil with the Agência Nacional de Petróleo (the National Petroleum Agency, or the ANP), in accordance with Brazilian rules and regulations, totaling 11.36 billion barrels of crude oil and NGLs and 11,206.57 billion cubic feet of natural gas. The reserve estimates we filed with the ANP and those provided herein differ by approximately 25%. This difference is due to (1) the ANP requirement that we estimate proved reserves through the technical abandonment of production wells, as opposed to limiting reserve estimates to the life of our concession contracts as required by Rule 4-10 of Regulation S-X and (2) different technical criteria for booking proved reserves, including the use of 3-D seismic data to establish proved reserves in Brazil.

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     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 0.96 billion barrels of crude oil and NGLs and 4,355 billion cubic feet of natural gas, which differs by approximately 40 percent from reserve estimates provided herein because the SPE’s different technical guidelines allow for (1) the booking of reserves in Bolivia beyond the life of certain gas sale contracts and (2) the booking of reserves in Nigeria based on 3-D seismic data and certain oil recovery techniques, such as fluid injection, without the performance of pilot project tests.
     Bolivia and Venezuela announced certain nationalization measures, which we expect will have the effect of reducing our oil and gas reserves in these countries. As a result, the information concerning reserves in Bolivia and Venezuela as provided herein may change. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations¾ The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition.”
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 table sets 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, 2005 have been derived from our audited consolidated financial statements, which were audited by Ernst & Young Auditores Independentes S/S for each of the years ended December 31, 2005, 2004 and 2003 and by PricewaterhouseCoopers Auditores Independentes for each of the years ended December 31, 2002 and 2001. The information below should be read in conjunction with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and Item 5. “Operating and Financial Review and Prospects.”

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BALANCE SHEET DATA
                                         
    As of December 31,  
    2005     2004     2003     2002     2001  
            (in millions of U.S. dollars)          
Assets
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 9,871     $ 6,856     $ 8,344     $ 3,301     $ 7,360  
Accounts receivable, net
    6,184       4,285       2,905       2,267       2,759  
Inventories
    5,305       4,904       2,947       2,540       2,399  
Recoverable taxes
    2,087       1,475       917       672       664  
Advances to suppliers
    652       422       504       794       483  
Other current assets
    1,679       1,484       1,817       748       661  
 
                             
Total current assets
    25,778       19,426       17,434       10,322       14,326  
Property, plant and equipment, net
    45,920       37,020       30,805       18,224       19,179  
Investments in non-consolidated companies and other investments
    1,810       1,862       1,173       334       499  
Other assets:
                                       
Accounts receivables, net
    607       411       528       369       476  
Advances to suppliers
    489       580       416       450       403  
Petroleum and Alcohol Account-Receivable from the Brazilian government(1)
    329       282       239       182       81  
Government securities
    364       326       283       176       665  
Unrecognized pension obligation
                      61       187  
Restricted deposits for legal proceedings and guarantees
    775       699       543       290       337  
Recoverable taxes
    639       536       467       156       164  
Investments PEPSA and PELSA
                      1,073        
Goodwill
    237       211       183              
Prepaid expenses
    246       271       190       100       78  
Marketable securities
    129       313       806       208       212  
Fair value asset of gas hedge
    547       635                    
Others
    755       510       545       209       257  
 
                             
Total other assets
    5,117       4,774       4,200       3,274       2,860  
 
                             
Total assets
  $ 78,625     $ 63,082     $ 53,612     $ 32,154     $ 36,864  
 
                             
 
                                       
Liabilities and Shareholders’ equity
                                       
Current liabilities:
                                       
Trade accounts payable
  $ 3,838     $ 3,284     $ 2,261     $ 1,702     $ 1,783  
Taxes payable
    3,423       2,569       2,305       1,801       2,145  
Short-term debt
    950       547       1,329       671       1,101  
Current portion of long-term debt
    1,428       1,199       1,145       727       940  
Current portion of project financings
    2,413       1,313       842       239       680  
Current portion of capital lease obligations
    239       266       378       349       298  
Dividends and interest on capital payable
    3,068       1,900       1,955       307       93  
Payroll and related charges
    918       618       581       283       333  
Advances from customers
    609       290       258       119       26  
Employees’ postretirement benefits obligations — Pension
    206       166       160       89       117  
Other current liabilities
    1,063       1,176       823       976       528  
 
                             
Total current liabilities
    18,155       13,328       12,037       7,263       8,044  
Long-term liabilities:
                                       
Long-term debt
    11,503       12,145       11,888       6,987       5,908  
Project financings
    3,629       4,399       5,066       3,800       3,153  
Employees’ postretirement benefits obligations — Pension
    3,627       2,915       1,895       1,363       1,971  
Employees’ postretirement benefits obligation — Health Care
    3,004       2,137       1,580       1,060       1,409  
Capital lease obligations
    1,015       1,069       1,242       1,907       1,930  
Deferred income tax
    2,159       1,558       1,122       259       717  
Gas-fired power liabilities
          1,095       1,142              
Deferred Purchase Incentive
    144       153                    
Provision for abandonment of wells
    842       403       396              
Other liabilities
    556       497       541       350       406  
 
                             
 
                                       
Total long-term liabilities
    26,479       26,371       24,872       15,726       15,494  
 
                             
 
                                       
Minority interest
    1,074       877       367       (136 )     79  
 
                             

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    As of December 31,  
    2005     2004     2003     2002     2001  
            (in millions of U.S. dollars)          
Shareholders’ equity
                                       
Shares authorized and issued:
                                       
Preferred share
    4,772       4,772       2,973       2,459       1,882  
Common share
    6,929       6,929       4,289       3,761       2,952  
Capital reserve and other comprehensive income
    21,216       10,805       9,074       3,081       8,413  
 
                             
 
                                       
Total Shareholders’ equity
    32,917       22,506       16,336       9,301       13,247  
 
                             
 
                                       
Total liabilities and Shareholders’ equity
  $ 78,625     $ 63,082     $ 53,612     $ 32,154     $ 36,864  
 
                             
 
(1)   Prior to July 29, 1998, the Petroleum and Alcohol Account reflected the difference between our actual cost for imported crude oil and oil products and the price set by the Brazilian government, as well as the net effects on us of the administration of certain subsidies and of our fuel alcohol activities. From July 29, 1998 until December 31, 2001, the Petroleum and Alcohol Account was required to be adjusted by the PPE and certain fuel transportation and other reimbursable costs. As from the price deregulation on January 2, 2002, the Petroleum and Alcohol Account reflected only the outstanding balance owed to us by the Brazilian government and adjustments resulting from monetary correction and audits to the Account. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation—The Petroleum and Alcohol Account.”

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INCOME STATEMENT DATA
                                         
    For the Year Ended December 31,  
    2005     2004 (11)     2003 (11)     2002(11)     2001(11)  
    (in millions of U.S. dollars, except for share and per share data)  
Sales of products and services
  $ 74,065     $ 51,954     $ 42,690     $ 32,987     $ 34,145  
Value-added and other taxes on sales and services
    (14,694 )     (10,906 )     (9,527 )     (7,739 )     (8,627 )
CIDE(1)
    (3,047 )     (2,620 )     (2,249 )     (2,636 )      
Specific parcel price — PPE(2)
                            (969 )
Net operating revenues
  $ 56,324       38,428       30,914       22,612       24,549  
 
                             
Cost of sales(3)
    29,828       21,279       15,533       11,506       12,807  
Depreciation, depletion and amortization(4)(12)
    2,926       2,481       1,785       1,930       1,729  
Exploration, including exploratory dry holes(4)(5)
    1,009       613       512       435       404  
Selling, general and administrative expenses
    4,474       2,901       2,091       1,741       1,751  
Other operating expense(6)
    1,137       572       597       222       277  
 
                             
Total costs and expenses
    39,374       27,846       20,518       15,834       16,968  
Financial income
    710       956       634       1,142       1,375  
Financial expense
    (1,189 )     (1,733 )     (1,247 )     (774 )     (808 )
Monetary and exchange variation on monetary assets and liabilities, net
    248       450       509       (2,068 )     (915 )
Employee benefit expense
    (994 )     (650 )     (595 )     (451 )     (594 )
Other non-operating income (expense), net(7)
    (1,133 )     (670 )     (924 )     (1,395 )     (1,847 )
 
                             
 
Income before income taxes, minority interest, extraordinary item and accounting change
    14,592       8,935       8,773       3,232       4,792  
Income tax (expense) benefit:
                                       
Current
    (4,223 )     (2,114 )     (2,599 )     (1,269 )     (1,196 )
Deferred
    (218 )     (117 )     (64 )     116       (193 )
 
                             
Total income tax expense
    (4,441 )     (2,231 )     (2,663 )     (1,153 )     (1,389 )
 
                             
Minority interests in results of consolidated subsidiaries
    35       (514 )     (248 )     232       88  
 
                             
Income before extraordinary item and effect of change in accounting principle
    10,186       6,190       5,862       2,311       3,491  
 
                             
Extraordinary gain net of tax
    158                          
Cumulative effect of change in accounting principle, net of taxes(4)
                697              
Net income for the year
  $ 10,344     $ 6,190     $ 6,559     $ 2,311     $ 3,491  
 
                             
Weighted average number of shares Outstanding:(8)
                                       
Common(8)
    2,536,673,672       2,536,673,672       2,536,673,672       2,536,673,672       2,536,673,672  
Preferred(8)
    1,849,478,028       1,849,478,028       1,849,478,028       1,807,742,676       1,807,742,676  
Basic and diluted earnings per share:(8)(9)
                                       
Common and Preferred Shares(8)(9)
  $ 2.36     $ 1.41     $ 1.50     $ 0.53     $ 0.80  
Common and Preferred ADS(8)(9)
  $ 9.44     $ 5.64     $ 6.00     $ 2.12     $ 3.20  
Cash dividends per(8)(10):
                                       
Common and Preferred shares(8)(10)
  $ 0.68     $ 0.42     $ 0.37     $ 0.29     $ 0.42  
Common and Preferred ADS(8)(10)
  $ 2.72     $ 1.68     $ 1.48     $ 1.16     $ 1.68  
 
(1)   CIDE is a per-transaction tax due to the Brazilian government.

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(2)   According to specific legislation applicable to the Petroleum and Alcohol Account through December 31, 2001, the Petroleum and Alcohol Account was realized through collection of the Specific Parcel Price-PPE generated by the sale of the majority of basic oil products (gasoline, diesel oil and LPG). The PPE represented the difference between the selling prices of these products at the refinery (net of Imposto sobre Circulação de Mercadorias e Serviços (state value-added tax), or ICMS and other charges levied on sales), fixed in reais by the Brazilian Government, and the corresponding realization prices for such products, which is the basis for calculation net operating revenues. The realization prices (PR) for each oil product were determined on the basis of a pricing formula established by the Brazilian Government that, with a lag of approximately one month, reflected changes in oil products quotations on the international market and the exchange rate. When the invoicing price net of ICMS and PASEP/COFINS exceeded the realization price, the PPE collection was positive and reduced the balance of the Petroleum and Alcohol Account. Conversely, when the invoicing value net of ICMS and PASEP/COFINS was less than the realization price, the PPE collection was negative and increased the balance of the Petroleum and Alcohol Account. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation—The Petroleum and Alcohol Account.”
 
(3)   Amounts reported are net of impact of government charges and taxes of U.S.$68 million in 2001. The governmental regulations giving rise to such charges/credits and taxes were abolished in 2002.
 
(4)   In 2002, U.S.$284 million in abandonment costs were recognized as depreciation, depletion and amortization in accordance with SFAS 19. In 2003, as a result of our adoption of SFAS 143 — Accounting for Asset Retirement Obligations, depreciation on the asset retirement obligation was recorded under depreciation, depletion and amortization, while accretion expense was recorded under exploration, including exploratory dry holes. This change resulted in U.S.$43 million in abandonment costs being recognized as exploration, including exploratory dry holes in 2003. The cumulative effect of adoption is recorded separately.
 
(5)   In 2005, we reviewed and revised our estimated costs associated with well abandonment and the demobilization of oil and gas production areas, considering new information about date of expected abandonment and revised cost estimates to abandon. The changes to estimated asset retirement obligation were principally related to changing expectations about Brent prices, which led the correlated fields to have longer economic lives. This review resulted in a decrease in the related provision of U.S.$21 million with a gain recognized in net income, and recorded in the line titled exploratory costs for oil and gas exploration. See note 2(i) to our audited consolidated financial statements.
 
(6)   Amounts reported are net of impact of government charges and taxes of U.S.$45 million in 2001. The governmental regulations giving rise to such charges and taxes were abolished in 2002.
 
(7)   Amounts reported include financial charges in respect of the Petroleum and Alcohol Account of U.S.$2 million in 2002 and U.S.$16 million in 2001.
 
(8)   On July 22, 2005, our board of directors authorized a 4 for 1 stock split. For purposes of comparison, the weighted average number of shares outstanding, net income per share/ADS and cash dividends per share/ADS were restated for periods prior to the stock split, which became effective as of September 1, 2005. See note 10 to our audited consolidated financial statements.
 
(9)   Basic and diluted earnings per share for 2003 reflect our adoption of SFAS 143. That change in accounting principle altered our 2003 basic and diluted earnings per share from U.S.$1.34 (before effect of change in accounting principle) to U.S.$ 1.50 (after effect of change in accounting principle). And for 2005, the extraordinary item altered our basic and diluted earnings per share from U.S.$2.32 (before effect of extraordinary item) to U.S.$2.36 (after effect of extraordinary item).
 
(10)   Represents dividends declared in respect of the earnings of each period.
 
(11)   Certain amounts from prior years have been reclassified to conform to current year presentation standards. These reclassifications had no impact on the Company’s net income.
 
(12)   Including in 2005 an impairment charge relating to our operations in Venezuela.
PIFCo
     The following table sets 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, 2005 have been derived from PIFCo’s audited consolidated financial statements, which were audited by Ernst & Young Auditores Independentes S/S for each of the years ended December 31, 2005, 2004 and 2003 and by PricewaterhouseCoopers Auditores Independentes for each of the years ended December 31, 2002 and 2001. 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.”

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    For the Year Ended December 31,  
    2005     2004     2003     2002     2001  
            (in millions of U.S. dollars)          
Income Statement Data:
                                       
Sales of crude oil and oil products and Services:
                                       
Related Parties
  $ 13,974.4     $ 10,118.4     $ 5,543.0     $ 5,375.5     $ 5,860.6  
Others
    3,161.7       2,237.2       1,432.5       1,014.7       399.9  
Lease income(1)
                      36.1       10.7  
 
                             
 
  $ 17,136.1     $ 12,355.6     $ 6,975.5     $ 6,426.3     $ 6,271.2  
 
                             
 
                                       
Operating Expenses:
                                       
Cost of sales
                                       
Related Parties
    (7,780.3 )     (4,391.3 )     (2,851.4 )     (2,409.0 )     (1,648.1 )
Others
    (9,203.0 )     (7,844.7 )     (4,068.7 )     (3,962.5 )     (4,604.9 )
Lease expense(1)
                      (24.0 )     (10.5 )
Selling, general and Administrative expenses
                                       
Related parties
    (158.1 )     (98.7 )     (17.1 )            
Others
    (7.6 )     (1.1 )     (1.5 )     (1.2 )     (0.1 )
 
                             
 
    (17,149.0 )     (12,335.8 )     (6,938.7 )     (6,396.7 )     (6,263.6 )
 
                             
Operating income (loss)
    (12.9 )     19.8       36.8       29.6       7.6  
Financial income(2)
                                       
Related Parties
    765.5       568.6       401.7       201.9       155.4  
Others
    218.5       110.2       41.2       17.7       3.4  
Total
    984.0       678.8       442.9       219.6       158.8  
Financial expense(3)
                                       
Related Parties
    (409.8 )     (169.0 )     (111.9 )     (61.3 )     (67.4 )
Others
    (589.1 )     (592.2 )     (370.8 )     (253.4 )     (119.7 )
Total
    (998.9 )     (761.2 )     (482.7 )     (314.7 )     (187.1 )
Other income, net
                                       
Related Parties
          (0.5 )                  
Others
          4.0                   0.4  
 
                             
Net loss
  $ (27.8 )   $ (59.1 )   $ (3.0 )   $ (65.5 )   $ (20.3 )
 
                             
Balance Sheet Data (end of period):
                                       
Cash and cash equivalents
  $ 230.7     $ 1,107.3       664.2       260.6       48.6  
Trade accounts receivable
                                       
Related parties
    8,681.1       7,788.1       5,064.5       4,837.1       2,583.7  
Others
    212.7       153.6       109.4       57.1       44.7  
Notes receivable
                                       
Related parties
    3,909.3       1,936.9       1,726.4       1,631.6       283.0  
Export Prepayment
                                       
Related parties
    943.9       1,414.7       1,479.4       751.2       751.2  
Marketable Securities
    2,248.6       1,864.8       615.8       96.3        
 
                             
Total assets
    16,748.9       14,670.2       10,196.6       8,697.3       4,277.8  
 
                             
Trade accounts payable
                                       
Related parties
    950.7       562.1       271.0       292.0       288.1  
Other
    616.1       568.1       349.0       281.1       231.0  
Notes payable
                                       
Related parties
    8,080.3       6,435.0       2,442.8       3,688.2       334.6  
Short-term financing and current portion of long-term debt
    891.1       680.9       1,076.4       367.5       990.4  
Long-term debt(4)
    5,908.4       6,151.8       5,825.3       3,850.4       2,335.0  
Total stockholders’ equity
    8.0       35.7       94.8       43.9       49.4  
 
                             
Total liabilities and stockholders’ equity
    16,748.9       14,670.2       10,196.6       8,697.3       4,277.8  
 
                             
 
(1)   As a result of PIFCo’s transfer of PNBV, its leasing subsidiary, to us in January 2003, PIFCo had no lease income or lease expense in 2003, 2004 and 2005.

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(2)   Financial income represents primarily the imputed interest realized from PIFCo’s sales of crude oil and oil products to us.
 
(3)   Financial expense consists primarily of costs incurred by PIFCo in financing its activities in connection with the importation by us of crude oil and oil products.
 
(4)   Includes capital lease obligations of U.S.$601.7 million at December 31, 2002.
Exchange Rates
     All foreign exchange transactions are now carried out in a single foreign exchange market. Prior to March 14, 2005, there were two principal foreign exchange markets in Brazil, the commercial rate exchange market and the floating rate exchange market. Most trade and financial transactions were carried out on the commercial rate exchange market, including the purchase or sale of our shares or the payment of dividends with respect to our shares to shareholders outside Brazil. Transactions not carried out on the commercial rate exchange market were generally carried out on the floating rate exchange market.
     Foreign currencies may only be purchased through Brazilian financial institutions authorized to operate in such market and are subject to registration with the Central Bank electronic system. Foreign exchange rates are freely negotiated, but may be influenced by Central Bank intervention. The Central Bank of Brazil allows the real/U.S. dollar exchange rate to float freely, and it has intervened occasionally to control unstable movements in foreign exchange rates. We cannot predict whether the Central Bank or the Brazilian government will continue to let the real float freely or will intervene in the exchange rate market through a currency band system or otherwise.
     The real depreciated 52.3% in 2002 against the U.S. dollar, before appreciating 18.2% in 2003 and continuing to appreciate 8.1% in 2004 and 11.8% in 2005. As of June 21, 2006, the real has appreciated to R$2.238 per U.S.$1.00, representing an appreciation of approximately 4.4% in 2006 year-to-date The real may depreciate or appreciate substantially in the future. “—Risk Factors—Risks Relating to Brazil.”
     The following table provides information on the selling exchange rate, expressed in reais per U.S. dollar (R$/U.S.$), for the periods indicated. The table uses the commercial selling rate prior to March 14, 2005
                                 
    For the Year Ended December 31, (R$ /U.S.$)
    High   Low   Average (1)   Period End
Year ended December 31,
                               
2005
    2.762       2.163       2.435       2.341  
2004
    3.205       2.654       2.926       2.654  
2003
    3.662       2.822       3.075       2.889  
2002
    3.955       2.271       2.924       3.533  
2001
    2.835       1.935       2.352       2.320  
Month
                               
November 2005
    2.252       2.163       2.211       2.207  
December 2005
    2.374       2.180       2.286       2.341  
January 2006
    2.346       2.212       2.273       2.216  
February 2006
    2.222       2.118       2.159       2.136  
March 2006
    2.224       2.107       2.148       2.172  
April 2006
    2.172       2.089       2.131       2.089  
May 2006
    2.059       2.371       2.170       2.301  
June 2006 (through June 21)
    2.302       2.238       2.262       2.238  
 
Source: Central Bank of Brazil
 
(1)   Year-end figures stated for calendar years 2005, 2004, 2003, 2002 and 2001 represent the average of the month-end exchange rates during the relevant period. The figures provided for the months of calendar year 2006 and 2005, as well as for the month of June up to and including June 21, 2006, represents the average of the exchange rates at the close of trading on each business day during such period.
     Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or serious reasons to foresee such an imbalance, temporary restrictions on remittances from Brazil may be imposed by the Brazilian government. These types of measures may be taken by the Brazilian government in the future,

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including measures relating to remittances related to our preferred or common shares or American Depositary Shares, or ADSs. See “Risk Factors-Risks Relating to Brazil.”
Risk Factors
Risks Relating to Our Operations
Substantial or extended declines in the prices of crude oil and oil products may have a material adverse effect on our income.
     The major part of our revenue is derived from sales of crude oil and oil products. We do not, and will not, have control over the factors affecting international prices for crude oil and oil products. The average prices of Brent crude, an international benchmark oil, were approximately U.S.$ 54.38 per barrel for 2005, U.S.$38.21 per barrel for 2004 and U.S.$28.84 per barrel for 2003. Changes in crude oil prices typically result in changes in prices for oil products.
     Historically, international prices for crude oil and oil products have fluctuated widely as a result of many factors. These factors include:
    global and regional economic and political developments in crude oil producing regions, particularly in the Middle East;
 
    the ability of the Organization of Petroleum Exporting Countries (OPEC) and other crude oil producing nations to set and maintain crude oil production levels and prices;
 
    global and regional supply and demand for crude oil and oil products;
 
    competition from other energy sources;
 
    domestic and foreign government regulations;
 
    weather conditions; and
 
    global conflicts and acts of terrorism.
     Volatility and uncertainty in international prices for crude oil and oil products 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. In addition, 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.
Our ability to achieve our growth objectives depends on our ability to discover additional reserves and successfully develop them, and failure to do so could prevent us from achieving our long-term goals for growth in production.
     Our ability to achieve our growth objectives is highly dependent upon our ability to discover additional reserves, as well as to successfully develop our current reserves. In addition, our exploration activities 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 accidents 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 water (between 300 and 1,500 meters water depth) and ultra deep water (more than 1,500 meters). Deep water drilling represented approximately 36% of the exploratory wells we drilled in 2005, a higher proportion than for many other oil and gas producers.

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     Unless we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are extracted. If we fail to gain access to additional reserves we may not achieve our long-term goals for production growth and our results of operations and financial condition may be adversely affected.
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). 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 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. In Brazil, 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. In 2005, we experienced spills totaling 71,141 gallons of crude oil, as compared to 140,000 gallons in 2004 and 73,000 gallons in 2003. As a result of certain of these spills, we were fined by various state and federal environmental agencies, named the defendant in several civil and criminal suits and remain subject to several investigations and potential civil and criminal liabilities. See Item 8. “Financial Information—Legal Proceedings.” Waste disposal and emissions regulations may 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) routinely inspects our oil platforms in the Campos Basin, 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 remedy any damage that a project may cause to the environment (environmental compensation). 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.
     As environmental regulations become more stringent, 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. Because our capital expenditures are subject to approval by the Brazilian government, increased expenditures to comply with environmental regulations could result in reductions in other strategic investments. Any such reduction 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 litigation and arbitration.
     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. For example, on the grounds that drilling and production platforms may not be classified as sea-going vessels, the Brazilian Revenue Service asserted that overseas remittances for charter payments should be reclassified as lease payment and subject to a withholding tax of 25%. They have filed two tax assessments against us in the aggregate amount of R$3,157 million (approximately U.S.$1,098 million). See Item 8. “Financial Information—Legal Proceedings.”

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     We may also be subject to labor litigation in connection with recent changes in Brazilian laws relating to retirement benefits affecting our employees.
     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. Additionally, 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.
If the State of Rio de Janeiro enforces a law imposing ICMS on oil upstream activities, our results of operations and financial condition may be adversely affected.
     In June 2003, the State of Rio de Janeiro enacted a law, referred to as “Noel Law,” imposing ICMS on upstream activities. The constitutionality of the Noel Law is currently being challenged in the Brazilian Supreme Court (Supremo Tribunal Federal, or STF) and although the law is technically in force, the government of the State of Rio de Janeiro has not yet enforced it. Currently, the ICMS for fuels derived from oil is assessed at the point of sale but not at the wellhead level. If the State of Rio de Janeiro enforces the Noel Law, it is unlikely (depending on the grounds of the Supreme Court’s decision) that the other states would allow us to use the tax imposed at the wellhead level in Rio de Janeiro as a credit to offset the tax imposed at the sale level. Therefore, we would have to pay ICMS at both levels. We estimate that the amount of ICMS that we would be required to pay to the State of Rio de Janeiro could increase by approximately R$8.51 billion (U.S.$3.52 billion) per year. This increase could have a material adverse effect on our results of operations and financial condition.
Our participation in the domestic power market has generated losses and may not become profitable.
     Consistent with the global trend of other major oil and gas companies and to secure demand for our natural gas, we participate in the domestic power market. Despite a number of incentives introduced by the Brazilian government to promote the development of gas-fired power plants, development of such plants has been slow due to the market structure and regulation of the power industry, among other things. We have invested, alone or with other investors, in fourteen (twelve in operation and two under construction or development) of the 39 gas-fired power generation plants. Demand for energy produced by our gas-fired power plants has been lower than we expected mainly as a result of good hydrological conditions in the last years that increased the supply and lowered the prices of energy from hydroelectric power plants. The main risks associated with our gas-fired power business are:
    Physical demand for our installed capacity, which is influenced by the current and expected market prices of natural gas;
 
    The potential mismatch between contracted price indexation for energy to be sold by gas-fired power companies and the cost of natural gas or other substitute fuel supply; and
 
    The dependence on construction of pipelines and other infrastructure to transport and produce natural gas and the commitment to purchase firm quantities of natural gas to satisfy the requirement of the new regulatory model for power generation in order to sell under long term energy contracts.
As a result of the foregoing, our participation in the domestic power market has generated losses and may not become profitable.

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We may not be able to obtain financing for all of our planned investments, and failure to do so could adversely affect our operating results and financial condition.
     The Brazilian government maintains control over our 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 Ministry of Mines and Energy, and the Brazilian Congress for approval. If we cannot obtain financing that does not require Brazilian government approval, such as structured financings, we may not be free 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.
Currency fluctuations could have a material adverse effect on our financial condition and results of operations, because most of our revenues are in reais and a large portion of our liabilities are in foreign currencies.
     The principal market for our products is Brazil, and over the last three fiscal years over 78% of our revenues have been denominated in reais. A substantial portion of our indebtedness and some of our operating expenses and capital expenditures are, and are expected to continue to be, denominated in or indexed to U.S. dollars and other foreign currencies. In addition, during 2005 we imported U.S.$8.1 billion of crude oil and oil products, the prices of which were all denominated in U.S. dollars.
     The real depreciated 52.3% in 2002 against the U.S. dollar before appreciating 18.2%, 8.1% and 11.8% against the U.S. dollar in 2003, 2004 and 2005, respectively. As of June 21, 2006, the exchange rate of the real to the U.S. dollar was R$2.238 per U.S.$1.00, representing an appreciation of approximately 4.4% in 2006 year-to-date. The value of the real in relation to the U.S. dollar may continue to fluctuate and may include a significant depreciation of the real against the U.S. dollar as occurred in 2002. Any future substantial depreciation of the real may adversely affect our operating cash flows and our ability to meet our foreign currency-denominated obligations.
We are exposed to increases in prevailing market interest rates, which leaves us vulnerable to increased financing expenses.
     As of December 31, 2005, approximately 52.5% of our total indebtedness consisted of floating rate debt. We have not entered into derivative contracts or made other arrangements to hedge against interest rate risk. 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.
We are not insured against business interruption for our Brazilian operations and most of our assets are not insured against war and terrorism.
     We do not maintain coverage for business interruption for our Brazilian operations. If, for instance, our workers were to strike, the resulting work stoppages could have an adverse effect on us, as we do not carry insurance for losses incurred as a result of business interruptions of any nature, including business interruptions caused by labor action. In addition, we do not insure most of our assets against war and terrorism. A terrorist attack or an operational incident causing an interruption of our business could therefore have a material adverse effect on our financial condition or results of operations.
We are subject to substantial risks relating to our international operations, in particular in Latin America and the Middle East.
     We operate in a number of different countries, particularly in Latin America, West Africa and the Middle East 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 exchange or price controls;

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    the imposition of restrictions on hydrocarbon exports;
 
    the depreciation of local currencies;
 
    the nationalization of oil and gas reserves; or
 
    increases in export tax / income tax rates for crude oil and oil products.
     If one or more of the risks described above were to materialize 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.
     Of the countries outside of Brazil in which we operate, Argentina is the most significant, representing approximately 40% of our total international crude oil and natural gas production and 28% of our international proved crude oil and natural gas reserves at December 31, 2005. In response to the Argentine crisis, the Argentine government has made a number of changes in the regulatory structure of the electricity and gas sectors and has fixed export tax rates for crude oil, natural gas and oil products. We also have significant operations in Bolivia and Venezuela that represented, respectively, approximately 21% and 18% of our total international production in barrels of oil equivalent and 27% and 22% of our international proved crude oil and natural gas reserves at December 31, 2005. Both Bolivia and Venezuela have recently announced certain nationalization measures that may generate material losses to us. At present, there is much uncertainty in the political, economic and social situations, generally in these two countries. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations— The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition” for a description of the risks associated with these nationalization measures. Deterioration of the situation in Argentina, Bolivia or Venezuela may have an adverse effect on our results of operations and financial condition.
The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition.
     The Bolivian and Venezuelan governments have recently increased their participation in their respective domestic oil and gas industries, which may generate material losses to us.
     Our consolidated interests related to Bolivia include two refineries, oil and gas reserves, which represented approximately 2.7% of our total reserves at December 31, 2005 and our interest in the Bolivia-Brazil gas pipeline (GTB). We also hold a long-term gas supply agreement, or the GSA, for the purchase of natural gas from the Bolivian state oil company, Yacimientos Petrolíferos Fiscales Bolivianos —YPFB. We have been operating in Bolivia since 1996. As of December 31, 2005, the book value of Bolivia assets were U.S.$990million. On May 1, 2006, the Bolivian government announced that it would nationalize several industries in the country, including the oil and gas industry. As a result, our interest in the two refineries and the oil and gas reserves in Bolivia will be reduced. We have 180 days to comply with the terms and conditions of the nationalization, and it is uncertain if and how we will be compensated for our losses. In 2005, the natural gas we imported from Bolivia represented approximately 53% of our total natural gas sales. We supply this natural gas to the Brazilian market, including local distribution companies and gas-fired power plants in which we have an interest.
     Our interests in Venezuela include oil and gas reserves, which represented approximately 2.3% of our total reserves at December 31, 2005. In April 2005, the Venezuelan Energy and Oil Ministry instructed PDVSA to review thirty-two operating agreements signed by PDVSA with oil companies from 1992 through 1997. In addition, PDVSA was instructed to take measures in order to convert all effective operating agreements into state-controlled companies in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field, including agreements with our affiliates in connection with the areas of Oritupano Leona, La Concepcion, Acema and Mata. As a result, as of December 31, 2005, we recorded an impairment charge in order to adjust the book value of our Venezuelan assets in the amount of U.S.$134 million. In March 31, 2006, we, Petróleos de Venezuela S.A. (PDVSA) and Corporación Venezolana del Petróleo S.A. (CVP), entered into memorandums of understanding (MOUs) in order to effect the migration of the operating agreements to partially state-owned companies (“mixed

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companies”), whereby the interest of PDVSA in each mixed company will be 60%. The economic effects of the migration are effective since April 1, 2006. See Item 4. “Information on the Company—International—Venezuelan Operations.”
     As a result of the foregoing, we currently cannot estimate the degree to which these nationalization measures will affect us, and believe they may have a material adverse effect on our results of operations and financial condition.
Risks Relating to PIFCo
PIFCo may not earn enough money from its own operations to meet its debt obligations.
     PIFCo is a direct wholly-owned subsidiary of Petrobras incorporated in the Cayman Islands as an exempted company with limited liability. Accordingly, PIFCo’s financial position and results of operations are largely affected by our decisions, as its parent company. PIFCo has limited operations consisting principally of the purchase of crude oil and oil products from third parties and the resale of those products to us, with financing for such operations provided by us as well as third-party credit providers. PIFCo also buys and sells crude oil and oil products from and to us, third parties and affiliates on a limited basis. PIFCo’s ability to pay interest, principal and other amounts due on its outstanding and future debt obligations will depend upon a number of factors, including:
    our financial condition and results of operations;
 
    the extent to which we continue to use PIFCo’s services for market purchases of crude oil and oil products;
 
    our willingness to continue to make loans to PIFCo and provide PIFCo with other types of financial support;
 
    PIFCo’s ability to access financing sources, including the international capital markets and third-party credit facilities; and
 
    PIFCo’s ability to transfer its financing costs to us.
     In the event of a material adverse change in our financial condition or results of operations or in our financial support of PIFCo, PIFCo may not have sufficient funds to repay all amounts due on its indebtedness. See “Risks Relating to Our Operations “ 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.
If Brazilian law restricts us from paying PIFCo in U.S. dollars, PIFCo may have insufficient U.S. dollar funds to make payments on its debt obligations.
     PIFCo obtains substantially all of its funds from our payments in U.S. dollars for crude oil that we purchase from PIFCo. In order to remit U.S. dollars to PIFCo, we must comply with Brazilian foreign exchange control regulations, including preparing specified documentation to be able to obtain U.S. dollar funds for payment to PIFCo. If Brazilian law were to impose additional restrictions, limitations or prohibitions on our ability to convert reais into U.S. dollars, PIFCo may not have sufficient U.S. dollar funds available to make payment on its debt obligations. Such restrictions could also have a material adverse effect on the Brazilian economy or our business, financial condition and results of operations.
PIFCo may be limited in its ability to pass on its financing costs.
     PIFCo is principally engaged in the purchase of crude oil and oil products for sale to Petrobras, as described above. PIFCo regularly incurs indebtedness related to such purchases and/or obtain financing from us or

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third-party creditors. At December 31, 2005, approximately 20% of PIFCo’s indebtedness was floating-rate debt denominated in U.S. dollars. All such indebtedness has the benefit of our standby purchase obligation or other support. PIFCo has historically passed on its financing costs to us by selling crude oil and oil products to us at a premium to compensate for its financing costs. Although we intend to continue this practice in the future, we cannot assure you that we will. PIFCo’s inability to transfer its financing costs to us could have a material adverse effect on PIFCo’s business and on its ability to meet its debt obligations in the long term.
Risks Relating to the Relationship between us and the Brazilian Government
The Brazilian government, as our controlling shareholder, may cause us to pursue certain macroeconomic and social objectives that may have an adverse effect on our results of operations and financial condition.
     The Brazilian government, as our controlling shareholder, has pursued, and may pursue in the future, certain of its macroeconomic and social objectives through us. Brazilian law requires the Brazilian government to own a majority of our voting stock, and so long as it does, the Brazilian 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 government rather than to our own economic and business objectives. In particular, we continue to assist the Brazilian government to ensure that the supply of crude oil and oil products in Brazil meets 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.
If the Brazilian government reinstates controls over the prices we can charge for crude oil and oil products, such price controls could affect our financial condition and results of operations.
     In the past, the Brazilian government set prices for crude oil and oil products in Brazil, often below prices prevailing in the world oil markets. These prices involved elements of cross-subsidy among different oil products sold in various regions in Brazil. The cumulative impact of this price regulation system on us is recorded as an asset on our balance sheet under the line item “Petroleum and Alcohol Account—Receivable from the Brazilian government.” The balance of the account at December 31, 2005 was U.S.$329 million. All price controls for crude oil and oil products ended on January 2, 2002, however, the Brazilian government could decide to reinstate price controls in the future as a result of market instability or other conditions. If this were to occur, our financial condition and results of operations could be adversely affected.
We do not own any of the crude oil and natural gas reserves in Brazil.
     A guaranteed source of 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 government owns all crude oil and natural gas reserves in Brazil and the concessionaire owns the oil and gas it produces. We possess the exclusive right to develop our reserves pursuant to concession agreements awarded to us by the Brazilian government and we own the goods we produce under the concession agreements, but if the Brazilian government were to restrict or prevent us from exploiting these crude oil and natural gas reserves, our ability to generate income would be adversely affected.
Risks Relating to Brazil
The Brazilian 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 our results of operations and financial condition.
     The Brazilian 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 government’s response to these factors:

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    devaluations and other exchange rate movements;
 
    inflation;
 
    exchange control policies;
 
    social instability;
 
    price instability;
 
    energy shortages;
 
    interest rates;
 
    liquidity of domestic capital and lending markets;
 
    tax policy; and
 
    other political, diplomatic, social and economic developments in or affecting Brazil.
Political instability may adversely affect our results of operations and the price of our securities.
     The performance of the Brazilian economy has historically been influenced by the domestic political scenario. Political crises have, in the past, affected the confidence of investors and of the general public and resulted in economic slowdowns, adversely affecting the market price of the shares of publicly-listed companies.
     The Brazilian Congress is currently conducting investigations on, among other matters, allegations related to contributions to political campaigns that were unaccounted for or not publicly disclosed, including contributions made to various important members of the current federal administration. Such allegations have resulted in the replacement of key ministers and occupied most of Congress’ agenda. In addition, some allegations implicated other companies controlled by the Brazilian government. If these investigations were to impact the confidence of the general public and/or of investors, or result in an economic slowdown in Brazil, our results of operations and the price of our shares could be adversely affected.
     Additionally, presidential elections in Brazil will take place in 2006 and we cannot assure you that the next administration will maintain the economic policies that were adopted by the current administration. The uncertainties relating to the election may impact the confidence of the general public and of investors and the price of our securities may be adversely affected.
Inflation and government measures to curb inflation may contribute significantly to economic uncertainty in Brazil and to heightened volatility in the Brazilian securities markets and, consequently, may adversely affect the market value of our securities and financial condition.
     Our principal market is Brazil, which has, in the past, periodically experienced extremely high rates of inflation. Inflation, along with governmental measures to combat inflation and public speculation about possible future measures, has had significant negative effects on the Brazilian economy. The annual rates of inflation, as measured by the National Wide Consumer Price Index (Índice Nacional de Preços ao Consumidor Amplo, or IPCA), have decreased from 2,477.15% in 1993 to 916.46% in 1994 and to 5.97% in 2000. The same index increased to 9.30% in 2003, before decreasing to 7.60% in 2004 and to 5.69% in 2005. Considering the historically high rates of inflation, Brazil may experience higher levels of inflation in the future. The lower levels of inflation experienced since 1995 may not continue. Future governmental actions, including actions to adjust the value of the real, could trigger increases in inflation, which may adversely affect our financial condition.

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Access to international capital markets for Brazilian companies is influenced by the perception of risk in Brazil and other emerging economies, which may hurt our ability to finance our operations and the trading values of our securities.
     International investors generally consider Brazil to be an emerging market. As a result, economic and market conditions in other emerging market countries, especially those in Latin America, influence the market for securities issued by Brazilian companies. As a result of economic problems in various emerging market countries in recent years (such as the Asian financial crisis of 1997, the Russian financial crisis in 1998 and the Argentine financial crisis that began in 2001), investors have viewed investments in emerging markets with heightened caution. These crises produced a significant outflow of U.S. dollars from Brazil, causing Brazilian companies to face higher costs for raising funds, both domestically and abroad, and impeding access to international capital markets. Increased volatility in securities markets in Latin American and in other emerging market countries may have a negative impact on the trading value of our securities. We cannot assure you that international capital markets will remain open to Brazilian companies or that prevailing interest rates in these markets will be advantageous to us.
Risks Relating to our Equity and Debt Securities
The Brazilian securities markets are smaller, more volatile and less liquid than the major U.S. and European securities markets and therefore you may have greater difficulty selling the common or preferred shares underlying our ADSs
     The Brazilian securities markets are smaller, more volatile and less liquid than the major securities markets in the United States and other jurisdictions, and are not as highly regulated or supervised. The relatively small capitalization and liquidity of the Brazilian equity markets may substantially limit your ability to sell the common or preferred shares underlying our ADSs at the price and time you desire. These markets may also be substantially affected by economic circumstances unique to Brazil, such as currency devaluations.
The market for PIFCo’s notes may not be liquid.
     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.
You may be unable to exercise preemptive rights with respect to the common or preferred shares underlying the ADSs.
     Holders of ADSs that 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 U.S. Securities Act of 1933 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, Citibank N.A., as depositary, will attempt to sell the preemptive rights, and you 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.”
You may not be able to sell your ADSs at the time or the price you desire because an active or liquid market for our ADSs may not be sustained.
     Our preferred ADSs have been listed on the New York Stock Exchange since February 21, 2001, while our common ADSs have been listed on the New York Stock Exchange since August 7, 2000. We cannot predict whether an active liquid public trading market for our ADSs will be sustained on the New York Stock Exchange, where they are currently traded. Active, liquid trading markets generally result in lower price volatility and more efficient

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execution of buy and sell orders for investors. Liquidity of a securities market is often a function of the volume of the underlying shares that are publicly held by unrelated parties. We do not anticipate that a public market for our common or preferred shares will develop in the United States.
Restrictions on the movement of capital out of Brazil may impair your ability to receive dividends and distributions on, and the proceeds of any sale of, the common or preferred shares underlying the ADSs and may impact our ability to service certain debt obligations, including standby purchase agreements we have entered into in support of PIFCo’s notes.
     The Brazilian government may impose temporary restrictions on the conversion of Brazilian currency into foreign currencies and on the remittance to foreign investors of proceeds from their investments in Brazil. Brazilian law permits the Brazilian government to impose these restrictions whenever there is a serious imbalance in Brazil’s balance of payments or there are reasons to foresee a serious imbalance.
     The Brazilian government imposed remittance restrictions for approximately six months in 1990. Similar restrictions, if imposed, could impair or prevent the conversion of dividends, distributions, or the proceeds from any sale of common or preferred shares from reais into U.S. dollars and the remittance of the U.S. dollars abroad. The Brazilian government could decide to take similar measures in the future. In such a case, the depositary for the ADSs will hold the reais it cannot convert for the account of the ADS holders who have not been paid. The depositary will not invest the reais and will not be liable for the interest.
     Additionally, if the Brazilian government were to impose restrictions on our ability to convert reais into U.S. dollars, we would not be able to make payment on our dollar-denominated debt obligations. For example, any such restrictions could prevent us from making funds available to PIFCo, for payment of its debt obligations, certain of which are supported by us through standby purchase agreements.
If you exchange your ADSs for common or preferred shares, you 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 you decide to exchange your ADSs for the underlying common or preferred shares, you 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, you 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 you obtain your own certificate of registration or register under Resolution No. 2,689, of January 26, 2000, of the Conselho Monetário Nacional (National Monetary Council), which entitles registered foreign investors to buy and sell on the São Paulo Stock Exchange. In addition, if you do not obtain a certificate of registration or register under Resolution No. 2,689, you may be subject to less favorable tax treatment on gains with respect to the common or preferred shares.
     If you attempt to obtain your own certificate of registration, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to the common or preferred shares or the return of your capital in a timely manner. The custodian’s certificate of registration or any foreign capital registration obtained by you may be affected by future legislative or regulatory changes and we cannot assure you that additional restrictions applicable to you, the disposition of the underlying common or preferred shares or the repatriation of the proceeds from disposition will not be imposed in the future.

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You may face difficulties in protecting your interests as a shareholder because we are subject to different corporate rules and regulations as a Brazilian company and because holders of our common shares, preferred shares and ADSs have fewer and less well-defined shareholders’ rights than those traditionally enjoyed by United States shareholders.
     Our corporate affairs are governed by our bylaws and the Brazilian Corporation Law, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States, such as the States of Delaware or New York, or in other jurisdictions outside Brazil. In addition, your rights as an ADS holder, which are derivative of the rights of holders of our common or preferred shares, as the case may be, to protect your interests against actions by our board of directors may be fewer and less well-defined under Brazilian Corporation Law than those under the laws of other jurisdictions.
     Although insider trading and price manipulation are considered crimes under Brazilian law, the Brazilian securities markets are not as highly regulated and supervised as the U.S. securities markets or markets in some other jurisdictions. In addition, rules and policies against self-dealing and the preservation of shareholder interests may be less well-defined and enforced in Brazil than in the United States, putting holders of our common shares, preferred shares and ADSs at a potential disadvantage. Corporate disclosure may be less complete or informative than what may be expected of a U.S. public company.
     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 you 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, you may face greater difficulties in protecting your 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.
Preferred shares and the ADSs representing preferred shares generally do not give you voting rights.
     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.
Enforcement of our obligations under the standby purchase agreement might take longer than expected.
     We have entered into standby purchase agreements in support of PIFCo’s obligations under its notes and indentures. Our obligation to purchase from the PIFCo noteholders any unpaid amounts of principal, interest and other amounts due under the PIFCo notes and the indenture applies, subject to certain limitations, irrespective of whether any such amounts are due at maturity of the PIFCo notes or otherwise. See “Additional Information—PIFCo Senior Notes—Standby Purchase Agreements” and “Additional Information—PIFCo Global Notes—Standby Purchase Agreements.”
     We have been advised by our counsel that the enforcement of the standby purchase agreement in Brazil against us, if necessary, will occur under a form of judicial process that, while similar, has certain procedural differences from those applicable to enforcement of a guarantee and, as a result, the enforcement of the standby purchase agreement may take longer than would otherwise be the case with a guarantee.
We may not be able to pay our obligations under the standby purchase agreement in U.S. Dollars.
     Payments by us to PIFCo for the import of oil, the expected source of PIFCo’s cash resources to pay its obligations under the PIFCo notes, will not require approval by or registration with the Central Bank of Brazil. There may be other regulatory requirements that we will need to comply with in order to make funds available to

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PIFCo. If we are required to make payments under the standby purchase agreement, Central Bank of Brazil approval will be necessary. Any approval from the Central Bank of Brazil may only be requested when such payment is to be remitted abroad by us, and will be granted by the Central Bank of Brazil on a case-by-case basis. It is not certain that any such approvals will be obtainable at a future date. In case the PIFCo noteholders receive payments in reais corresponding to the equivalent U.S. Dollar amounts due under PIFCo’s notes, it may not be possible to convert these amounts into U.S. Dollars. We will not need any prior or subsequent approval from the Central Bank of Brazil to use funds we hold abroad to comply with our obligations under the standby purchase agreement.
We would be required to pay judgments of Brazilian courts enforcing our obligations under the standby purchase agreement only in reais.
     If proceedings were brought in Brazil seeking to enforce our obligations in respect of the standby purchase agreement, we would be required to discharge our obligations only in reais. Under the Brazilian exchange control limitations, 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 standby purchase agreement executed by us was 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 standby purchase agreement to make payments on PIFCo’s behalf. We have been advised by our external U.S. counsel that the standby purchase agreement 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 standby purchase agreement 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 standby purchase agreement, and we, at the time we entered into the standby purchase agreement:
    were or are insolvent or rendered insolvent by reason of our entry into the standby purchase agreement;
 
    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 believes 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 standby purchase agreement could be avoided, or claims with respect to the standby purchase agreement could be subordinated to the claims of other creditors. Among other things, a legal challenge to the standby purchase agreement 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 standby purchase agreement 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 standby purchase agreement 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 standby purchase agreement.
ITEM 4. INFORMATION ON THE COMPANY
History and Development of Petrobras
     We are a state-controlled company created pursuant to Law No. 2,004 (effective as of October 3, 1953). A state-controlled company is a Brazilian corporation created by special law, of which a majority of the voting capital must be owned by the Brazilian federal government, a state or a municipality. We are controlled by the Brazilian

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federal government, but our common and preferred shares are also publicly traded. 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.
     We were incorporated in 1953 and began operations in Brazil in 1954 as a wholly-owned government enterprise responsible for all hydrocarbon activities in Brazil. Since our foundation, our legal name has been Petróleo Brasileiro S.A.—Petrobras. From that time until 1995, we had a government-granted monopoly for all crude oil and natural gas production and refining activities in Brazil. On November 9, 1995, the Brazilian Constitution was amended to authorize the Brazilian government to contract with any state or privately owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. This amendment made possible the end of our legal monopoly in 1988.
     The crude oil and natural gas industry in Brazil has experienced significant reforms since the enactment of Law No. 9,478, or the Oil Law, on August 6, 1997, which established competition in Brazilian markets for crude oil, oil products and natural gas . Effective January 2, 2002, the Brazilian government deregulated prices for crude oil and oil products. See “—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.” The gradual transformation of the oil and gas industry since 1997 has led to increased participation by international companies in Brazil across all segments of our business, both as our competitors and partners.
     Based upon our 2005 consolidated revenues, we are the largest corporation in Brazil and one of the largest oil and gas companies in Latin America. In 2005, we had sales of products and services of U.S.$74,065 million, net operating revenues of U.S.$56,324 million and net income of U.S.$10,344 million.
     We engage in a broad range of oil and gas activities, which cover the following segments of our operations:
    Exploration and Production — Our exploration and production segment encompasses exploration, development and production activities in Brazil.
 
    Refining, Transportation and Marketing — Our refining, transportation and marketing segment encompasses refining, logistics, transportation and the purchase of crude oil, as well as the purchase and sale of oil products and fuel alcohol. Additionally, this segment includes the petrochemical and fertilizers division, which includes domestic petrochemical companies and our two domestic fertilizer plants.
 
    Distribution — Our distribution segment encompasses oil product and fuel alcohol distribution activities conducted by our majority owned subsidiary, Petrobras Distribuidora S.A. — BR in Brazil.
 
    Natural Gas and Power — Our natural gas and power segment encompasses the purchase, sale and transportation of natural gas produced in or imported into Brazil. Additionally, this segment includes our domestic electric energy commercialization activities as well as investments in domestic natural gas transportation companies, state owned natural gas distributors and gas-fired power plants.
 
    International — Our international segment encompasses international activities conducted in the following countries: Argentina, Angola, Bolivia, Colombia, Ecuador, Equatorial Guinea, Iran, Libya, Mexico, Nigeria, Paraguay, Peru, the United States, Tanzania,Turkey, Uruguay and Venezuela), which include Exploration and Production, Supply, Refining, Petrochemical, Fertilizers, Distribution and Gas and Energy.,
 
    Corporate — Our corporate segment includes those activities not attributable to other segments, including corporate financial management and overhead related with central administration.
     As a foreign private issuer, we are exempt from many of the corporate governance standards the New York Stock Exchange, or NYSE, applies to U.S. domestic issuers listed on the NYSE. In accordance with Section 303A.11 of the NYSE Listed Company Manual, we have posted a summary of significant differences between the NYSE standards and our corporate governance practice on our website, www.petrobras.com.br.

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Recent developments relating to compliance with the Sarbanes-Oxley Act
     Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, beginning with our Annual Report on Form 20-F for the fiscal year ending December 31, 2006, we will be required to furnish a report by our management on our internal control over financial reporting. This report will contain, among other matters, an assessment of the effectiveness of our internal controls over financial reporting as of the end of the fiscal year, including a statement as to whether or not our internal controls over financial reporting are effective. This assessment must include disclosure of any material weakness in our internal control over financial reporting identified by management.
     The report will also contain a statement that our auditors have issued a certification report on management’s assessment of such internal controls. Deloitte, Touche Tohmatsu has assisted our management in conducting a preliminary assessment and evaluation of our internal controls.. To comply with this requirement, we are creating a system of internal controls over financial reporting through the Integrated Program for Internal Control Systems and Valuation Methodology, known as “PRISMA”. PRISMA is a program that focuses on constantly reviewing our financial statements and information contained in our consolidated financial reports. In addition, the program follows orientations from the Public Company Accounting Oversight Board (PCAOB) and from the Committee of Sponsoring Organizations of the Treadway Commission (COSO), for the development of better internal control practices, as well as from Control Objectives for Information and Related Technology (COBIT), as it relates to information technology.
     Phases 1 and 2 of the PRISMA have already been implemented and we are currently implementing phase 3 of the program.
Competitive Strengths
     We have a number of key strengths, including:
    dominant market position in the production, refining and transportation of crude oil and oil products in Brazil;
 
    strong reserve base;
 
    deepwater technological expertise;
 
    cost efficiencies created by large scale operations combined with vertical integration among business segments;
 
    strong position in Brazil’s growing natural gas markets; and
 
    success in attracting international partners in all activities.
Dominant market position in the production, refining and transportation of crude oil and oil products in Brazil
     Our legacy as Brazil’s former sole supplier of crude oil and oil products has provided us with a fully developed operational infrastructure throughout Brazil and a large proved reserve base. Our long history, resources and established presence in Brazil permit us to compete effectively with other market participants and new entrants now that the Brazilian oil and gas industry has been deregulated. We operate all major development fields in Brazil and substantially all of the country’s refining capacity. Our average domestic daily production of crude oil and NGLs increased 12.8% in 2005, decreased 3.1% in 2004 and increased 2.7% in 2003.
Strong reserve base
     As of December 31, 2005, we had estimated proved developed and undeveloped crude oil and natural gas reserves of approximately 11.77 billion barrels of oil equivalent in Brazil and abroad. In addition, we have a

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substantial base of exploration acreage both in Brazil and abroad, which we are exploring by ourselves and with industry partners in order to continue to increase our reserves.
     As of December 31, 2005, our worldwide proved reserves to production ratio was 15.4 years.
     The majority of our reserves, including recent discoveries, are located in deep-water areas that generally require additional planning, more comprehensive evaluation and added lead time to begin production when compared to onshore production. In accordance with our Business Plan for the period from 2006 to 2010, we have been investing the necessary capital to build the offshore platforms needed to monetize these reserves. Although our proved reserve life is higher than the industry average, the additional planning required to bring deep-water areas into production also means that our percentage of proved undeveloped reserves may be higher than the industry average.
     We believe that our proved reserves will provide us with significant opportunities for sustaining and increasing production growth.
Deepwater technological expertise
     While developing Brazil’s offshore basins over the past 36 years, we have gained expertise in deepwater drilling, development and production techniques and technologies. We are currently in the process of developing technology to permit production from wells at water depths of up to 9,842 feet (3,000 meters).
     Our deepwater development and production expertise has allowed us to achieve high production volumes and relatively low lifting costs (excluding royalties, special government participation and rental of areas, which we refer to as “government take”). Our aggregate average lifting cost for crude oil and natural gas products in Brazil for 2005, excluding government take, increased to U.S.$5.73 per barrel of oil equivalent, as compared to U.S.$4.28 per barrel of oil equivalent for 2004. Including government take, our lifting costs increased to U.S.$14.65 per barrel of oil equivalent for 2005, as compared to U.S.$10.72 per barrel of oil equivalent for 2004.
Cost efficiencies created by large-scale operations combined with vertical integration among business segments
     As the dominant integrated crude oil and natural gas company in Brazil, we can be cost efficient as a result of:
    the location of over 80% of our proved reserves in large, contiguous and highly productive fields in the offshore Campos Basin, which allows for the concentration of our operational infrastructure, thereby reducing our total costs of exploration, development and production;
 
    the location of most of our refining capacity in the Southeast region, directly adjacent to the Campos Basin and situated within the country’s most heavily populated and industrialized markets; and
 
    the relative balance between our current production of 1,684 Mbpd, our refining throughput of 1,726 Mbpd and the Brazilian market total demand for hydrocarbon products of 1,800 Mbpd as of December 2005.
     We believe that these cost efficiencies created by our integration, our existing infrastructure and our balance allow us to compete effectively with other Brazilian producers and importers of oil products into the Brazilian market.
Strong position in Brazil’s growing natural gas markets
     We participate in most aspects of the Brazilian natural gas market. At present, the ability to meet the potential demand for natural gas is limited, due to constraints in gas supply and to a distribution infrastructure that is still under development. The prices we realize for natural gas, which depend on the costs of other energy sources it can replace, are approximately half of the current market price in the United States, where demand is more

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developed. The demand for natural gas in Brazil increased 11% in 2005. Although we cannot be certain that natural gas demand will continue to grow at annual rates similar to previous years, we expect continued growth as significant investments in gas transportation pipelines begin operating.
          Because of the diversity of our natural gas operations, we believe that we are well positioned to take advantage of the opportunity to meet potentially growing energy needs in Brazil through the use of natural gas. We intend to do so through our:
    increasing production of non-associated natural gas, and natural gas associated with our domestic crude oil production, combined with the necessary investments to process such gas from recent discoveries of non-associated gas reserves, mainly in the Santos Basin offshore in Brazil;
 
    planned investments in expansion of the natural gas transportation network throughout Brazil;
 
    increased participation in the natural gas distribution market through investments in 19 of the 25 natural gas distribution companies in Brazil;
 
    investments in gas-fired power plants, which serve as sources of demand for our natural gas; and
 
    seeking greater operational flexibility in our sources to improve our energy demand management.
Success in attracting international partners in all our activities
          As a result of our experience, expertise and extensive infrastructure network in Brazil, we have attracted partners in our exploration, development, refining and power activities such as Repsol-YPF, ExxonMobil, Shell, British Petroleum, Chevron-Texaco and Total. Partnering with other companies allows us to share risks, capital commitments and technology in our continuing development and expansion.
          We may face significant risks in our ability to take full advantage of these competitive strengths. See Item 3. “Key Information—Risk Factors.”
Strategy
     We intend to continue to expand our oil and gas exploration and production activities and pursue strategic investments within and outside of Brazil to further develop our business. We seek to evolve from a dominant integrated oil and gas company in Brazil into an energy industry leader in Latin America and a significant international energy company. In line with our Strategic Plan and to further these goals, we intend to:
    consolidate and increase competitive advantages in the Brazilian and South American oil and oil products market;
 
    selectively expand international activities in an integrated manner with the Company’s business;
 
    develop and lead the domestic natural gas market and act in an integrated manner in the gas and power market in the Southern Cone;
 
    selectively expand our activities in the domestic and Southern Cone petrochemicals market; and
 
    selectively perform in the renewable energy market.
Consolidate and increase competitive advantages in the Brazilian and South American oil and oil products market
          Our 2006-2010 Business Plan contemplates capital expenditures of approximately U.S.$28 billion in exploration and development activities in Brazil. Through these investments, we plan to implement 17 big scope

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projects, among others, aimed at increasing production to 2.3 million bpd by 2010. Our 2006-2010 Business Plan contemplates capital expenditures of approximately U.S.$7.1 billion in exploration and development activities outside of Brazil. These investments will be primarily exploration and development activities in South America. Our other areas of focus will be the Gulf of Mexico and West Africa. At December 2005, we had exploration, development and production rights in 54 million gross and 35 million net acres (220,000 gross and 141,000 net square kilometers) outside Brazil.
     At the same time that we seek to expand production, we intend to increase proved reserves, focused on deepwater exploration in Brazil. Our goal is to maintain a ratio of 15.4 years of reserves to production sustainable in the long-term. We have net exploration, development and production rights in 35.3 million acres (142,691 square kilometers) in Brazil. We expect to continue to participate selectively with major regional and international oil and gas companies in bidding for new concessions and in developing large offshore fields.
     Our domestic production in 2005 supplied approximately 80% of the crude oil feedstock for our refinery operations in Brazil, as compared to 76% in 2004 and 80% in 2003. We expect an increasing percentage of the crude oil feedstock to be supplied by our relatively lower cost domestic production, as our overall domestic production increases. Because our domestic refining capacity constitutes 98.5% of the Brazilian refining capacity, we supply almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to satisfying our internal consumption requirements with respect to wholesale marketing operations and petrochemical feedstock.
    Our refineries were originally designed to process light imported crude oil, whereas our current reserves and production increasingly consist of heavier crude oil. We are in the process of improving and adapting our refineries to better process our domestic production of heavier crude oil.
Selectively expand international activities in an integrated manner with the Company’s business.
     In the near term, we expect to expand internationally by using our existing asset base or participating in selective partnerships in core activities where we have a competitive advantage. We consider our core activities to be integrated oil and gas operations throughout South America and deepwater exploration and development off the U.S. Gulf Coast, Colombia and West Africa. We also have exploration interests in Angola, Argentina, Bolivia, Colombia, Ecuador, Peru, Nigeria, Equatorial Guinea, Iran, the Gulf of Mexico, Tanzania, Turkey and Libya.
Develop and lead the domestic natural gas market and act in an integrated manner in the gas and power market in the Southern Cone
     Through our participation in all segments of the natural gas market, both in Brazil and abroad, we seek to meet domestic natural gas demand. We intend to continue to expand our participation in the natural gas market by:
    developing the natural gas industry on an integrated manner with other areas of our Company in the production chain and consumption; and
 
    taking advantage of growing opportunities in the power industry in an integrated manner with other natural gas market areas in which our Company already operates.
     As a result of our investments and the growing importance of natural gas as a cleaner energy alternative, we anticipate that the proportion of revenues and assets represented by natural gas operations will increase, leading to a greater impact of these activities on our results of operations.

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Selectively expand our activities in the domestic and Southern Cone petrochemicals market
     We intend to expand activities in the petrochemical and fertilizer markets by seeking strategic partnerships and creating synergies with existing business. Our 2006-2010 Business Plan contemplates investments of approximately U.S.$2.0 billion in petrochemical business. Such investment will be aimed at increasing production of our basic petrochemicals, including polyolefins (polyethylene and polypropylene), acrylic acid and terephtalic acid. We believe that the growth of petrochemical activities will generate synergies with refining activities and we intend to take benefit of the expected growth in the petrochemical market in Brazil. We also intend to build a basic petrochemical complex that will integrate refinery units and petrochemical facilities to produce petrochemical raw materials such as ethylene, propylene, aromatics and its petrochemical derivatives, such as polyethylene and polypropylene. The total estimated aggregate investment for the construction of this petrochemical complex is approximately U.S.$6.5 billion and it is expected that it will begin operating in 2012.
Selectively perform in the renewable energy market
     We intend to develop some renewable energy alternatives in Brazil. Our priorities for investments in renewable sources of energy are:
    bio-diesel production and H-bio;
 
    wind power generation;
 
    biomass energy; and
 
    photo voltaic.
Overview by Business Segment
Exploration, Development and Production
Summary and Strategy
     Our exploration and production segment includes exploration, development and production activities in Brazil. We began domestic production in 1954 and international production in 1972. As of December 31, 2005, our estimated net proved crude oil and natural gas reserves in Brazil were approximately 10.58 billion barrels of oil equivalent. Crude oil represented 85% and natural gas represented 15% of these reserves. Our proved reserves are located principally in the Campos Basin.
     During 2005, our average daily domestic production was 1,684 Mbpd of crude oil and NGLs and 1.643 billion cubic feet of natural gas per day. Our aggregate average lifting costs for crude oil and natural gas in 2005 were U.S.$5.73 per barrel of oil equivalent in Brazil (excluding government take).
     We conduct exploration, development and production activities in Brazil through concession contracts. Under the terms of the Oil Law, in 1998 we were granted the concession rights to areas where we were already producing or could demonstrate we could explore or develop within a certain time frame. We refer to these concessions as Round zero. In a number of concessions, we have joint ventures with foreign partners to explore and develop the concessions. In conjunction with the majority of these arrangements, we received a carried interest for capital expenditures made during the exploration phase, with our partners incurring all capital expenditures until the development of a commercial discovery commences.
     At December 31, 2005, we held 418 areas, representing 35.3 million net acres (142,691 square kilometers). We currently have joint venture agreements for exploration and production in Brazil with 26 foreign and domestic companies. We are also active in exploration and production activities outside Brazil. For a full description of our international activities, see "—International—Exploration and Production.” In addition, we have added to our

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exploration acreage through our participation in bidding rounds that have been conducted annually by the ANP since 1999.
     Our main strategies in exploration, development and production in Brazil are to increase production and reserves by:
    strengthening our expertise in deep and ultra-deep waters;
 
    focusing on profitable opportunities on-shore and in shallow water fields;
 
    implementing new practices and new technologies in areas with high exploitation degree in order to optimize recovery factor;
 
    developing exploratory efforts in new frontiers in order to assure a sustainable reserve/production ratio.
Principal Domestic Oil and Gas Producing Regions
     Our annual daily production in Brazil has generally grown over the years. In 1970, we produced 164 Mbpd of crude oil, condensate and natural gas liquids in Brazil. We increased production to 181 Mbpd in 1980, 654 Mbpd in 1990, 1,271 Mbpd in 2000 and 1,684 Mbpd in 2005. In describing our oil and gas producing regions, reservoirs refer to underground formations containing producible oil or gas. Fields are areas that contain one or more reservoirs. Blocks are sections of a sedimentary basin where we carry out oil and gas exploration and production activities under concession contracts.
     Our main domestic oil and gas producing regions are:
Campos Basin
     The Campos Basin is the largest oil and gas producing region, and covers approximately 28.4 million acres (115 thousand square kilometers). Since exploration activities in this area began in 1968, over 45 hydrocarbon reservoirs have been discovered in this region in a 7.5 thousand square kilometers concession area, including eight large oil fields in deepwater and ultra deepwater. In terms of proved hydrocarbon reserves and annual production, the Campos Basin is the largest oil basin in Brazil and one of the most prolific oil and gas areas in South America. Annual crude oil production volume in the region increased steadily for the past ten years until 2004, when oil production in the Campos Basin decreased to 1,204 Mbpd from 1,252 Mbpd in 2003. In 2005, oil production in the Campos Basin increased to 1,405 Mbpd. The Campos Basin’s oil production accounted for approximately 83% of Brazilian oil production in 2005.
     At December 31, 2005, we produced crude oil from 36 fields in the Campos Basin and its proved crude oil reserves were 7.89 billion barrels, representing 81% of our total proved crude oil reserves. In 2005, the crude oil we produced in the Campos Basin had an average API gravity of 23.5 and an average water cut of 1%. We currently have 26 floating production systems, 13 fixed platforms and 5,226 kilometers of pipeline and flexible pipes operating in 45 fields at water depths of 262 to 6,188 feet (80 to 1,886 meters) in the Campos Basin.
Espírito Santo Basin
     We have made several discoveries of light oil and natural gas in the Espírito Santo Basin. We currently have exploration rights to 23 blocks in this Basin, 12 onshore and 11 offshore, with an exploration acreage of 10.4 thousand square kilometers. During 2005, we produced 42.7 Mboe per day of oil and natural gas in the Espírito Santo Basin (25.7 Mboe onshore and 17.1 Mboe offshore). On February 21, 2006, we began gas production in the Basin’s Peroá Field.

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Santos Basin
     The Santos Basin represents one of the most promising exploration areas. In January of 2006, we approved the Master Plan for Development of Natural Gas and Oil Production in the Santos Basin, with a base of exploration and production in the city of Santos, in the state of São Paulo. We currently have exploration rights to 26 blocks in the Santos Basin, with an exploration acreage of 40.7 thousand square kilometers (as compared to 13.7 thousand square kilometers under concession in the Campos Basin). Current production of oil and natural gas is 10.87 Mboe per day in the Coral and Merluza fields. We have drilled the first exploratory well in the ultra-deep waters of the Basin and have found evidence of oil.
Properties
     The following table sets forth our developed and undeveloped gross and net acreage by oil region and associated crude oil and natural gas production:
                                                 
                                    Average     Average  
                                    Oil and     Oil and  
                                    Natural Gas     Natural Gas  
                                    Production for     Production for  
                                    the Year     the Year  
    Production Acreage as pf     Ended     Ended  
    December 31.,2005     December 31,     December 31,  
    Developed     Undeveloped     2005(1)(4)     2004(1)(4)  
    Gross(2)     Net(2)     Gross(2)     Net(2)        
            (in acres)             (boe per day) (3)  
Brazil(1)
                                               
Offshore
                                               
Campos Basin
    1,714,851       1,681,740       138,374       99,580       1,530,147       1,311,208  
Other offshore
    320,979       281,196       329,874       291,327       64,510       68,909  
Total offshore
    2,035,830       1,962,936       468,248       390,907       1,594,657       1,380,117  
Onshore
    1,045,466       1,045,466       131,949       131,950       363,203       377,603  
 
                                   
Total Brazil
    3,081,296       3,008,402       600,197       522,857       1,957,860       1,757,720  
International
                                               
Onshore
    4,225,975       2,584,034       2,967,718       1,871,834       245,828       247,122  
Offshore
    123,825       36,381       642,109       81,778       12,909       15,516  
 
                                   
Total International
    4,349,800       2,620,415       3,609,827       1,953,612       258,737       262,638  
Total
    7,431,096       5,628,817       4,210,024       2,476,469       2,216,597       2,020,358  
 
(1)   Over 75% of our production of natural gas is associated gas.
 
(2)   A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
 
(3)   See “Conversion Table” for the ratios used to convert cubic feet of natural gas to barrels of oil equivalent.
 
(4)   Includes production from shale oil reserves, natural gas liquids and reinjected gas volumes, which are not included in our proved reserves figures.

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     The following table sets forth our total gross and net productive wells as of December 31, 2005:
                         
    Productive Wells
    Oil   Gas   Total
Gross productive wells
                       
Brazil
    8,968       468       9,436  
International
    5,896       302       6,198  
Total
    14,864       770       15,634  
Net productive wells
                       
Brazil
    8,954       465       9,419  
International
    4,361       235       4,596  
Total
    13,315       700       14,015  
     Productive wells are those producing or capable of production. A gross well is one in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
Deepwater Expertise
     We are the leader in deepwater drilling, with recognized expertise in deepwater exploration, development and production. We have developed expertise over many years and have achieved significant milestones, including the following:
    in January 2003, we drilled the world’s second horizontal deepwater multilateral well in the Barracuda-Caratinga field, in Campos Basin, at an water depth of 2,999 feet (914 meters), consisting of two legs for each well;
 
    at December 31, 2005, we were operating 37 wells at water depths in excess of 3,281 feet (1,000 meters)
 
    at December 31, 2005, we had drilled 400 wells at water depths in excess of 3,281 feet (1,000 meters), the deepest well being an exploration well in water depth of 9,360 feet (2,853 meters).
     Because many of Brazil’s richest oil fields are located offshore in deep waters, we intend to continue to focus on deepwater production technology to increase our proved reserves and future domestic production. See Item 5. “Operating and Financial Review and Prospects—Research and Development.” Our main exploration and development efforts involve offshore fields neighboring existing fields and production infrastructure, where higher drilling costs have been offset by higher drilling success ratios and relatively higher production. On a per-well basis, the exploration, development and production costs offshore are generally higher than those onshore. We believe, however, that offshore production is cost-effective, because historically:
    we have been more successful in finding and developing crude oil offshore, as a result of the existence of a larger number and size of oil reservoirs offshore as compared to onshore reservoirs and a greater volume of offshore seismic data collected; and
 
    we have been able to spread the total costs of exploration, development and production over a large base, given the size and productivity of our offshore reserves. Offshore production has exceeded onshore production by a per barrel production ratio of 5.92:1 in 2005, 4.96:1 in 2004 and 5.20:1 in 2003.
     We currently extract hydrocarbons from offshore wells in waters with depths of up to 6,188 feet (1,886 meters), and we have been developing technology to permit production from wells at water depths of up to 9,843 feet (3,000 meters). Set forth below is the distribution, by water depth, of offshore oil production in 2005 and 2004.

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OFFSHORE PRODUCTION BY WATER DEPTH
                 
Depth   Percentage in 2005   Percentage in 2004
0-400 meters (0-1,312 feet)
    18 %     21 %
400-1,000 meters (1,312 feet-3,281 feet)
    56 %     55 %
More than 1,000 meters (3,281 feet)
    26 %     24 %
Exploration Activities
Concessions in Brazil
     We had the right to exploit all exploration, development and production areas in Brazil as a result of the monopoly granted to us by Brazilian Law. When regulatory changes in the Brazilian oil and gas sector began in 1998, monopoly ended. On August 6, 1998, we signed concession contracts with the ANP for all of the areas we had been using prior to 1998. Those concession contracts covered 397 areas, consisting of 231 production areas, 115 exploration areas and 51 development areas, for a total area aggregating 113.3 million gross acres (458.5 thousand square kilometers).
     At December 31, 2005, we had 418 areas, consisting of 243 production areas, 134 exploration areas and 41 development areas, for a total area aggregating 43.3 million gross acres (175.4 thousand square kilometers). This total area represents 2.7% of the Brazilian sedimentary basins.
Recent discoveries
     In 2005, we declared the commercial feasibility of many new oil and gas fields, the main ones being located in the Espírito Santo, Campos and Santos Basins. We also made minor discoveries in the onshore coastal basins of Sergipe-Alagoas, Potiguar, Recôncavo and Espírito Santo. In 2005, we presented ANP Declarations of Commerciality for eight (8) new oil and gas fields.
     The Papa-Terra field is located in the southern Campos basin and operated by us (with a 62,5% interest) in partnership with Chevron-Texaco, with recoverable volumes that we believe may reach 700 million to 1 billion boe. In addition, we discovered new oil accumulation inside the ring-fence limits of the Marlim Leste field, in deeper reservoirs than the usual ones for the Campos Basin.
     In the offshore Santos Basin we discovered light crude oil and gas in the Tambaú and Uruguá fields, with recoverable volumes of more than 270 million boe.
     In the Espírito Santo Basin we discovered both light crude oil and gas in the Canapu field.
     In the onshore coastal basins we discovered and declared commercial the fields of Acauã, in the Potiguar basin, Anambé, in the Sergipe-Alagoas basin, Jandaia, in the Recôncavo basin and Inhambú in the Espírito Santo basin.
     We have a 35% interest in the Abalone, Ostra, Nautilus and Argonauta fields declared commercial by Shell, operator of the concession, in the northern part of the Campos basin, adjacent to the Jubarte/Cachalote area.
     We had a 55% success ratio for our exploration wells during 2005, with 38 wells classified as discovery or producing wells.
Auctions of exploration rights
     Since 1999, ANP has conducted auctions of exploration rights, which are open to us and qualified companies. We have competed in the public auctions, acquiring a large number of exploration rights, as detailed in

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the table below. We have also relinquished a considerable number of the exploratory areas in which we were not interested or successful in exploring.
     The following chart summarizes our success in the exploration bidding rounds conducted by the ANP during the last three years:
                                 
    Exploration   Development   Production   Total
Event
                               
Areas held (December 31, 2002)
    58       39       234       331  
Areas redefined (July 2003) (BCAM-40)
    1       0       0       1  
Areas relinquished (August 6, 2003)
    (22 )     0       0       (22 )
Areas won on Bid, Round 5
    17       0       0       17  
New concession (January 29, 2003) (Guajá)
    0       1       0       1  
New concession (August 4, 2003) (Cavalo-Marinho)
    0       1       0       1  
Areas redefined (February 3, 2003) (Coral)
    0       (1 )     1       0  
Areas redefined (July 15, 2003) (Beija-Flor)
    0       (1 )     1       0  
Joint concession COG to CCN (1)
    0       0       (1 )     (1 )
Joint concession CDL to MP (2)
    0       0       (1 )     (1 )
Areas relinquished (BAS-104)
    0       (1 )     0       (1 )
Areas relinquished (Arraia)
    0       (1 )     0       (1 )
Joint concession CR to FBL (3)
    0       (1 )     0       (1 )
Areas relinquished (ALS-32)
    0       (1 )     0       (1 )
Areas held (December 31, 2003)
    54       35       234       323  
Areas won on Bid, Round 6
    36       0       0       36  
Areas obtained through acquisitions (BT-REC-4, BT-POT-9, BT-ES-4, BM-C-14, BM-S-14 and BM-S-22)
    6       0       0       6  
Joint concession SMI to PJ (4)
    0       0       (1 )     (1 )
New concession (January 15, 2004) (Baleia Franca)
    0       1       0       1  
New concession (January 15, 2004) (Golfinho)
    0       1       0       1  
New concession (January 15, 2004) (Mexilhão)
    0       1       0       1  
New concession (January 19, 2004) (Azulão)
    0       1       0       1  
New concession (January 19, 2004) (Japim)
    0       1       0       1  
New concession (August 30, 2004) (Piranema)
    0       1       0       1  
New concession (December 20, 2004) (Baleia Anã)
    0       1       0       1  
New concession (December 20, 2004) (Baleia Azul)
    0       1       0       1  
New concession (December 20, 2004) (Baleia Bicuda)
    0       1       0       1  
New concession (December 22, 2004) (Salema Branca)
    0       1       0       1  
Areas held (December 31, 2004)
    96       45       233       374  

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    Exploration   Development   Production   Total
Areas won on Bid, Round 7
    39       0       0       39  
Areas relinquished (until December 31, 2005) (BM-FZA-1)
    (1 )     0       0       (1 )
New concession (February 1, 2005) (Jandaia)
    0       1       0       1  
New concession (April 4, 2005) (Anambé)
    0       1       0       1  
New concession (July 14, 2005) (Acauã)
    0       1       0       1  
New concession (November 24, 2005) (Inhambu)
    0       1       0       1  
New concession (December 27, 2005) (Papa-Terra)
    0       1       0       1  
New concession (December 29, 2005) (Uruguá)
    0       1       0       1  
New concession (December 29, 2005) (Tambaú)
    0       1       0       1  
New concession (December 29, 2005) (Canapú)
    0       1       0       1  
Areas redefined (January 17, 2005) (Rio Joanes)
    0       (1 )     1       0  
Areas redefined (February 1, 2005) (Fazenda Sori)
    0       (1 )     1       0  
Areas redefined (February 25, 2005) (Camaçari)
    0       (1 )     1       0  
Areas redefined (March 3, 2005) (Jandaia)
    0       (1 )     1       0  
Areas redefined (April 1, 2005) (Fazenda Matinha)
    0       (1 )     1       0  
Areas redefined (April 12, 2005) (Quererá)
    0       (1 )     1       0  
Areas redefined (June 18, 2005) (Rio da Serra)
    0       (1 )     1       0  
Areas redefined (August 11, 2005) (Anambé)
    0       (1 )     1       0  
Areas redefined (August 13, 2005) (Fazenda Santa Rosa)
    0       (1 )     1       0  
Areas redefined (November 24, 2005) (Inhambu)
    0       (1 )     1       0  
Joint concession BBI to CHT(5)
    0       (1 )     0       (1 )
Joint concession NPE to DEN (6)
    0       (1 )     0       (1 )
Total areas held (as of December 31, 2005)
    134       41       243       418  
Net area held in million acres (as of December 31, 2005)
    31,727,205       522,856       3,008,401       35,258,462  
 
(1)   COG — Córrego Grande, CCN — Córrego Cedro Grande
 
(2)   CDL — Cardeal, MP — Massapê
 
(3)   CR — Curió, FBL — Fazenda Belém
 
(4)   SMI — São Miguel, PJ — Pajeú
 
(5)   BBI — Baleia Bicuda, CHT — Cachalote
 
(6)   NPE — Norte de Pescada, DEN — Dentão

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Joint Ventures
     As of December 31, 2005, we had 68 exploration agreements and 16 production agreements. Our participation ranges from 30% to 85% in the exploration agreements, and in 47 of the 68 agreements we are principally responsible for conducting the exploration activities. During 2005, we entered into 23 partnership projects relating to exploration activities. As of December 31, 2005, we had partnerships in exploration with 20 foreign and domestic companies.
Drilling Activities
     During 2005, we drilled a total of 361 wells, 292 development wells and 69 exploratory wells. Of those wells, 251 development wells and 36 exploratory wells were located onshore and 41 development wells and 33 exploratory wells were located offshore. These numbers refer to the wells we drilled in 2005, but such wells may not have been evaluated or reclassified in 2005. The table “Exploratory and Development Wells” below indicates the number of wells which were evaluated and reclassified in 2005.
     We plan to expand exploration and development activities in 2006 by:
    drilling approximately 92 new exploratory and approximately 356 new development wells;
 
    shooting and processing two-dimensional and three-dimensional seismic surveys; and
 
    constructing onshore and offshore production and support facilities.
     The following table sets forth the number of wells we drilled, or in which we participated, and the results achieved, for the periods indicated.
EXPLORATORY AND DEVELOPMENT WELLS
                                         
    Campos                
Period   Basin   Other   Onshore   International   Total
2005 Net Exploratory Wells Drilled
    19       14       36       4       73  
Successful
    14       7       17       4       42  
Unsuccessful
    5       7       19       0       31  
Net Development Wells Drilled
    20       3       187       207       417  
Successful
    19       3       181       206       409  
Unsuccessful
    1       0       6       1       8  
2004 Net Exploratory Wells Drilled
    21       19       14       7       61  
Successful
    16       9       4       2       31  
Unsuccessful
    5       10       10       5       30  
Net Development Wells Drilled
    25       2       208       235       470  
Successful
    24       2       205       230       461  
Unsuccessful
    1       0       3       5       9  
2003 Net Exploratory Wells Drilled
    21       10       7       4       42  
 
                                       
Successful
    7       2       2       2       13  
Unsuccessful
    14       8       5       2       29  
Net Development Wells Drilled
    12       0       264       26       302  
 
                                       
Successful
    12       0       256       26       294  
Unsuccessful
    0       0       8       0       8  

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     The following table sets forth our fleet of drilling rig units. We will use these owned and leased rigs to support future exploration, production and development activities. Most of the offshore rigs are operated in the Campos Basin.
DRILLING UNITS
                                                 
    2005     2004     2003  
    Brazil     International     Brazil     International     Brazil     International  
Land rigs for onshore exploration and development
    22       19       19       28       15       10  
Owned
    13       0       13       0       13       0  
Leased
    9       19       6       28       2       10  
Semi-submersible rigs
    17       1       18       0       17       0  
Owned
    3       0       4       0       4       0  
Leased
    14       1       14       0       13       0  
Drill ships
    7       2       7       1       8       1  
Owned
    0       0       0       0       0       0  
Leased
    7       2       7       1       8       1  
Jack-up rigs
    7       1       6       0       6       0  
Owned
    6       0       6       0       5       0  
Leased
    1       1       0       0       1       0  
Moduled rigs for offshore exploration and development
    11       0       11       0       9       0  
Owned
    9       0       8       0       6       0  
Leased
    2       0       3       0       3       0  
Total
    64       23       61       29       55       11  
Development Activities
     Development occurs after completion of exploration and appraisal, and prior to hydrocarbon production, and involves the installation of production facilities including platforms and pipelines. We have an active development program in existing fields and in the discovery and recovery of new reserve finds. Over the last five years, we have concentrated development investments in the deepwater fields located in the Campos Basin, where most of our proved reserves are located. We develop fields in stages of production, which we refer to as modules. As of December 31, 2005, we had a total of 7,961 oil and gas producing wells in Brazil, of which 7,283 were onshore and 678were offshore.
Campos Basin Fields
     Marlim. The Marlim field is located at water depths between 2,133 and 3,445 feet (650—1,050 meters). It is our largest field based on production. Average production of crude oil during 2005 was 466.2 Mbpd, or more than 33% of total production in the Campos Basin. We have developed the Marlim field in five modules. We currently have seven floating production systems with total capacity of 710 Mbpd operating in Marlim field. We have a total of 73 production wells and 46 injection wells, and expect to drill four wells in 2006. Peak production of 586.3 Mboe was achieved in 2002.
     Roncador. The Roncador field is located in water depths between 4,921 and 6,234 feet (1,500—1,900 meters). Average production of crude oil during 2005 was 83.0 Mbpd. The first module of the development of this field consisted of Platform P-36, which sank in March 2001, and which was producing 80 Mbpd prior to the accident. Since the loss of P-36, we have contracted a temporary Floating Production Storage and Offloading unit (FPSO Brazil) with capacity of 90 Mbpd. First oil from this unit was attained on December 8, 2002. A total of seven wells, which were previously attached to P-36, have been attached to the new FPSO unit. A second platform (P-52) with a 180 Mbpd capacity is under construction. First oil from the unit is expected in 2007. A total of 20 production wells are planned in this module, including nine which were completed before the sinking of P-36.

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     The contracts for a third production unit, with production capacity of 180 Mbpd, were signed on June 17, 2004. The production unit consists of an FPSO (P-54), which is expected to begin production in 2007. A total of eleven production wells and six injection wells are planned.
     Marlim Sul (South Marlim). The Marlim Sul field is located at water depths between 2,789 and 7,874 feet (850—2,400 meters). Production of crude oil began on December 17, 2001. In 2005, average production for Marlim Sul was 197 Mbpd. We plan to develop the Marlim Sul field in two modules. The first module includes a production system consisting of a semi-submersible platform (P-40), with a total capacity of 155 Mbpd an FSO (P-38) and one FPSO unit (Marlim Sul) with a total capacity of 100 Mbpd 13 wells are currently producing through P-40, out of a total of 16 planned production wells and ten injection wells. Production from the Marlim Sul FPSO unit began on June 7, 2004 and is currently producing 71.0Mboe per day.
     The contracts for a second module, with a production capacity of 180 Mbpd, were signed on June 17, 2004. On December 5, 2005, Petrobras contracted funding for U.S.$402 million towards the construction. The production system consists of a semi-submersible unit (P-51), which is expected to begin production in 2008. A total of 14 production wells and ten injection wells are planned.
     Barracuda and Caratinga. The Barracuda and Caratinga fields are located at water depths between 2,274 and 3,899 feet (700—1,200 meters). Oil production began in December 2004 through FPSO unit P-43. Another FPSO unit, P-48, started production in the Caratinga field in February 2005. Each FPSO unit has capacity of 150 Mbpd. A total of 32 production wells and 22 injection wells are planned for the two fields. In 2005, the average production for Barracuda was 124,333 bpd and for Caratinga was 80,302 bpd.
     Albacora Leste (East Albacora). Albacora Leste is located at water depths between 3,609 and 4,921 feet (1,100—1,500 meters). FPSO unit (P-50) with capacity of 180 Mbpd started production on April 21, 2006. A total of 16 production wells and 14 injection wells are planned.
     Other developments in the Campos Basin include: (1) the Jubarte field, which will bring into production an FPSO (P-34) with 60 Mbpd capacity, (2) the Frade field, and (3) the Marlim Leste field, that will have an FPU unit (P-53) with a 180 Mbpd capacity. A contract to increase the production capacity of P-34 to 60 Mbpd was signed on June 17, 2004. During 2005, we made additional discoveries of crude oil in the Jubarte and Marlim Leste fields and we declared the commercial feasibility of the Papa-Terra field.
Espírito Santo Basin Fields
     In February of 2006, we started gas production in the Peroá Field, reaching more than 1 million cubic meters per day. The Peroá platform is projected to process 8 million cubic meters per day and investments include one fixed platform, one submarine gas pipeline and one Gas Treatment Unit (UTGC).
     The Golfinho field, already producing through a pilot system, that consists of an FPSO unit (Seillean) with a capacity of 25 Mbpd will be developed through three modules. Module I of the Golfinho Field started production on May 8 with a chartered FPSO named Capixaba, which has a capacity to produce 100 thousand barrels per day and has a storage capacity of 1.6 million barrels.The FPSO (Cidade de Vitória) to be allocated to Module II will have a production capacity of 100 thousand barrels per day and will be able to store up to 1.6 million barrels. Finally, an FPSO to Module III will be chartered, with a production capacity of 100 thousand barrels per day.
     Some of these fields are being financed through project financings. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Project Finance.”
Santos Basin Fields
     In January of 2006, we approved a Master Plan for Development of Natural Gas and Oil Production in the Santos Basin comprising Five Poles: Merluza, Mexilhão, BS-500, Southern and Central.

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     This Master Plan includes the expansion of the Merluza-1 Platform’s output to 2.5 million cubic meters of gas per day, the installation of the Merluza-2 Platform, with a production capacity of 8 million cubic meters of gas per day, and the installation of the Mexilhão Platform with a production capacity of 15 million cubic meters of gas per day.
     We also plan to install a gas treatment plant on the coast of São Paulo State to be integrated with the projects in order to expand the Merluza Pole and develop the Mexilhão Pole.
     In the BS-500 block we began studies for the production of the Uruguá and Tambaú Fields.
     In the Southern area, the Coral platform is already operational, currently producing 9,000 barrels of oil per day. There are plans to start production in the Cavalo Marinho Field in the future with production estimated at similar levels to that of Coral.
     Finally, the Central area is in the exploratory stage. We see a major potential in this area of the Santos Basin, informally known as a cluster.
Production Activities
     Our domestic crude oil and natural gas production activities involve fields located on Brazil’s continental shelf off the coast of nine Brazilian states, of which the Campos Basin is the most important region, and onshore in eight Brazilian states. We are also producing crude oil and natural gas in nine other countries: Angola, Argentina, Bolivia, Colombia, Ecuador, Mexico, Peru, the United States, and Venezuela. See “—International.”
     The following table sets forth average daily crude oil and natural gas production, average sales price and average lifting costs for each of 2005, 2004 and 2003:
                         
    For the Year Ended December 31,  
    2005     2004     2003(1)  
Crude Oil and NGL Production (in Mbpd)
                       
Brazil (2)
                       
Offshore
                       
Campos Basin
    1,405       1,204       1,252  
Other
    36       38       39  
 
                 
Total offshore
    1,441       1,242       1,291  
Onshore
    243       251       248  
 
                 
Total Brazil
    1,684       1,493       1,540  
International
    163       168       161  
 
                 
Total crude oil and NGL production
    1,847       1,661       1,701  
 
                 
Crude Oil and NGL Average Sales Price (U.S. dollars per Bbl)
                       
Brazil
  $ 45.42     $ 33.49     $ 27.01  
International
    34.91       26.51       23.77  
Natural Gas Production (in Mmcfpd)
                       
Brazil(3)
                       
Offshore
                       
Campos Basin
    752       645       657  
Other
    172       184       186  
 
                 
Total offshore
    924       829       843  
Onshore
    719       762       657  
 
                 
Total Brazil
    1,643       1,590       1,500  
 
                 
International
    575       564       510  
 
                 
Total natural gas production
    2,218       2,154       2,010  
 
                 
Natural Gas Average Sales Price (U.S. dollars per Mcf)
                       
Brazil(4)
  $ 2.17     $ 1.93     $ 1.79  
International(5)
    1.64       1.17       1.26  
Aggregate Average Lifting Costs (oil and natural gas) (U.S. dollars per boe)
                       
Brazil
                       
With government take
  $ 14.65     $ 10.72     $ 8.62  
Without government take
    5.73       4.28       3.48  
International
    2.90       2.60       2.46  

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(1)   International production figures for 2003 include PEPSA and PELSA as of January 1, 2003, although our interests were only acquired in May 2003.
 
(2)   Brazilian figures include production from shale oil reserves and natural gas liquids, which are not included in our proved reserves figures.
 
(3)   Brazilian figures include reinjected gas volumes, which are not included in our proved reserves figures.
 
(4)   Excludes (1) exploration and production overhead; (2) costs related to intra-company transfers of oil products to our exploration and production division; (3) costs of sales of oil products produced in natural plants overseen by our exploration and production department; and (4) price of oil and gas bought from partners in certain joint ventures.
 
(5)   Excludes (1) royalties; (2) special government participation; and (3) rental of areas.
     Average Brazilian production of crude oil and NGL for 2005 increased 12.8% relative to 2004, reaching 1,684 Mbpd, principally as a result of the start-up of FPSO-MLS in June 2004, the P-43 platform in December 2004 and the P-48 platform in February 2005.
Reserves
     Our estimated worldwide proved reserves of crude oil and natural gas as of December 31, 2005 totaled 11.77 billion barrels of oil equivalent, including:
    9.72 billion barrels of crude oil and NGLs; and
 
    12,351.9 billion cubic feet of natural gas.
     We calculate reserves based on forecasts of field production, which depend on a number of technical parameters, such as seismic interpretation, geological maps, well tests and economic data. All reserve estimates involve some degree of uncertainty. The uncertainty depends mainly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of this data. Therefore, the reliability of reserve estimates depends on factors that are beyond our control and many of such factors may prove to be incorrect over time.
     DeGolyer and MacNaughton, or D&M, reviewed and certified 90.6% of our domestic proved crude oil, condensate and natural gas reserve estimates as of December 31, 2005. The estimates for the certification were performed in accordance with Rule 4-10 of Regulation S-X of the SEC.
     As of December 31, 2005, our domestic proved developed crude oil reserves represented 45% of our total domestic proved developed and undeveloped crude oil reserves. Our domestic proved developed natural gas reserves represented 44% of our total domestic proved developed and undeveloped natural gas reserves. Total domestic proved hydrocarbon reserves on a barrel of oil equivalent basis increased at an average annual growth rate of 4.7 % in the last five years. Natural gas proved reserves increased at an average annual growth rate of 7.7% over the same period.

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     The following table sets forth our estimated net proved developed and undeveloped reserves and net proved developed reserves of crude oil and natural gas by region as of December 31, 2005, 2004 and 2003:
WORLDWIDE ESTIMATED NET PROVED RESERVES
                                                         
                                                    Combined
    Brazil   International   Global
            Natural                   Natural           Proved
    Crude Oil   Gas(1)(3)   Combined(2)(3)   Crude Oil   Gas(1)   Combined(2)   Reserves
    (MMbbl)   (Bcf)   (Mmboe)   (MMbbl)   (Bcf)   (Mmboe)   (Mmboe)
Net Proved Developed and Undeveloped Reserves:
                                                       
 
                                                       
Reserves as of December 31, 2003
    9,051.4       8,111.4       10,403.3       720.7       3,090.9       1,235.9       11,639.2  
Revisions of previous estimates
    (414.9 )     (262.1 )     (458.6 )     (18.8 )     276.4       27.3       (431.3 )
Extensions, discoveries and improved recovery
    1,129.3       582.6       1,226.4       60.6       116.5       80.0       1,306.4  
Sales of reserves in place
    0.0       0.0       0.0       0.0       0.0       0.0       0.0  
Purchase of reserves in place
    0.0       0.0       0.0       0.6       18.5       3.7       3.7  
Production for the year
    (522.4 )     (477.6 )     (602.0 )     (61.1 )     (209.5 )     (96.0 )     (698.0 )
Reserves as of December 31, 2004
    9,243.4       7,954.3       10,569.1       702.0       3,292.8       1,250.9       11,820.0  
Revisions of previous estimates
    123.0       842.4       263.4       0.5       (32.6 )     (4.97 )     258.4  
Extensions, discoveries and improved recovery
    252.0       996.9       418.2       38.4       38.8       44.9       463.1  
Purchase of reserves in place
    0       0       0       0.0       0.0       0.0       0  
Sales of reserves in place
    0       0       0       0.0       0.0       0.0       0  
Production for the year
    (584.5 )     (529.8 )     (672.8 )     (58.8 )     (210.9 )     (93.9 )     (766.7 )
Reserves as of December 31, 2005
    9,033.9       9,263.8       10,577.9       682.1       3,088.1       1,196.8       11,774.7  
 
                                                       
Net Proved Developed Reserves:
                                                       
As of December 31, 2003
    3,629.5       4,398.1       4,362.5       404.1       2,548.4       828.8       5,191.3  
As of December 31, 2004
    4,129.8       4,427.6       4,867.7       383.1       2,495.2       799.0       5,666.7  
As of December 31, 2005
    4,071.7       4,088.8       4,753.2       365.9       2,333.7       754.9       5,508.1  
 
(1)   Natural gas liquids are extracted and recovered at natural gas processing plants downstream from the field. The volumes presented for natural gas reserves are prior to the extraction of natural gas liquids.
 
(2)   See “Conversion Table” for the ratios used to convert cubic feet of natural gas to barrels of crude oil equivalent. Production of shale oil and associated reserves are not included.
 
(3)   Natural gas reserve data for 2005 presented in this table in cubic feet have been restated using a conversion of 6000 cubic feet of natural gas per barrel of oil equivalent, such conversion rate being consistent with prior years volumetric statements. The FAS 69 information originally published together with the consolidated financial statements for December 31, 2005 converted the natural gas reserves using 5613 cubic feet per barrel of oil, such factor being related to specific gravity and calorific content of Petrobras’ fields rather than the international average standard. As Petrobras’ natural gas reserves and production are accounted for in cubic meters, this change which is only for convenience presentation of barrel of oil equivalent, has no effect on the financial results nor on the physical natural gas reserves.
     The following tables set forth our crude oil and natural gas proved reserves by region, as of December 31, 2005, 2004 and 2003:

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CRUDE OIL NET PROVED RESERVES BY REGION
                                                 
    As of December 31,
    2005   2004   2003
    Proved           Proved           Proved    
    Developed and   Proved   Developed and   Proved   Developed and   Proved
    Undeveloped   Developed   Undeveloped   Developed   Undeveloped   Undeveloped
    (MMbbl)
Brazil
                                               
Offshore
                                               
Campos Basin
    7,886.0       3,395.9       8,130.4       3,422.7       8,089.1       2,899.6  
Other
    388.3       101.3       335.4       106.1       159.8       111.7  
 
                                               
Total offshore
    8,274.3       3,497.2       8,465.8       3,528.8       8,248.9       3,011.3  
 
                                               
Onshore
    759.6       574.5       777.6       601.0       802.5       618.2  
 
                                               
Total Brazil
    9,033.9       4,071.7       9,243.4       4,129.8       9,051.4       3,629.5  
 
                                               
 
                                               
International
                                               
Other South America(1)
    625.8       350.8       678.4       367.0       703.9       387.6  
West Coast of Africa
    42.6       8.6       11.8       11.8       14.0       14.0  
Gulf of Mexico
    13.7       6.5       11.8       4.3       2.8       2.4  
Total international
    682.1       365.9       702.0       383.1       720.7       404.1  
 
                                               
Total
    9,716.0       4,437.6       9,945.4       4,512.9       9,772.1       4,033.6  
 
                                               
 
(1)   Includes Argentina, Bolivia Colombia, Ecuador, Peru and Venezuela.
NATURAL GAS NET PROVED RESERVES BY REGION:
                                                 
    As of December 31,
    2005   2004   2003
    Proved           Proved           Proved    
    Developed and   Proved   Developed and   Proved   Developed and   Proved
    Undeveloped   Developed   Undeveloped   Developed   Undeveloped   Undeveloped
    (Bcf)
Brazil
                                               
Offshore
                                               
Campos Basin
    3,836.5       1,772.3       4,039.3       1,820.4       4,096.2       1,598.0  
Other
    2,912.1       720.9       1,337.5       854.0       1,291.2       959.5  
 
                                               
Total offshore
    6,748.6       2,493.2       5,376.8       2,674.4       5,387.4       2,557.5  
 
                                               
Onshore
    2,515.2       1,595.6       2,577.5       1,753.2       2,724.0       1,840.6  
 
                                               
Total Brazil
    9,263.8       4,088.8       7,954.3       4,427.6       8,111.4       4,398.1  
 
                                               
 
                                               
International
                                               
Other South America(1)
    2,951.7       2,270.2       3,162.2       2,456.2       3,058.2       2,526.8  
Gulf of Mexico
    136.5       63.5       130.6       39.0       32.7       21.6  
Total international
    3,088.1       2,333.7       3,292.8       2,495.2       3,090.9       2,548.4  
 
                                               
Total
    12,351.9       6,422.5       11,247.1       6,922.8       11,202.3       6,946.5  
 
                                               
 
(1)   Includes Argentina, Bolivia, Colombia, Peru and Venezuela.
     Please see “Supplementary Information on Oil and Gas Producing Activities” in our audited consolidated financial statements for further details on our proved reserves.
Refining, Transportation and Marketing
Summary and Strategy
     Our refining, transportation and marketing business segment encompasses the refining, transportation and marketing of crude oil, oil products and fuel alcohol, including investments in petrochemicals.
     We own and operate 11 refineries in Brazil, with total processing capacity of 1.99 million barrels per day. There are only two other competing refineries in Brazil, which have an aggregate installed capacity of approximately 0.03 million barrels per day. Our domestic refining capacity constitutes 98.5% of the Brazilian refining capacity. We built nine of our 11 refineries prior to 1972, and we completed the last refinery (Henrique

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Lage) in 1980. At that time, we were only producing 200 Mbpd of crude oil in Brazil. Our refineries were built to process light imported crude oil. Subsequent to their completion, we discovered large reserves of heavier crude oil in Brazil. As a result, we are continually upgrading and improving our refineries to process heavy crude oil.
     We approved initial studies for construction of a new refinery in the Northeast of Brazil. With an estimated investment of U.S.$2.5 billion in the industrial complex of Porto de Suape, in the state of Pernambuco. The refinery will have the capacity to process 200 Mbpd of heavy oil with the start of operations planned for 2011.
     We process as much of our domestically produced crude oil as possible through our refineries, and supply the remaining demand within Brazil by importing crude oil (which we also process in our refineries) and oil products. As our own domestic production increases and refinery upgrades enable us to process more throughput efficiently in the next few years, we expect to import proportionately less crude oil and oil products. Until January of 2002, we were the sole supplier of oil products to the Brazilian market. Now that we are no longer the sole supplier of oil products to the Brazilian market, we intend to reevaluate our import strategy and may reduce imports to the extent such reductions improve our profitability. We also export, to the extent that our production of oil products exceeds Brazilian demand or our refineries are unable to process the growing domestic crude oil production.
     We transport oil products and crude oil to domestic wholesale and export markets through a coordinated network of marketing centers, storage facilities, pipelines and shipping vessels. As the single supplier for almost fifty years of a country that ranks as the 12th largest oil-consuming nation in the world, according to the June 2005 issue of Statistical Review of the World, we have developed a large and complex infrastructure. Our refineries are generally located near Brazil’s population and industrial centers and near our production areas, which creates logistical efficiencies in our operations.
     In accordance with the requirements of the Oil Law, we have placed our shipping assets into a separate subsidiary, Petrobras Transporte S.A., or Transpetro. This subsidiary leases storage and pipeline facilities and provides open access to these assets to all market participants. Our petrochemicals business is now also included in the refining, transportation and marketing segment.
     Our main strategies in refining and transportation are to:
    strenghthen solution and relationship processes to the client, by understanding the client’s value chain and adjusting the services and products portfolio;
 
    expand processing, transporting and commercialization activities, using bio-energy sources and raw material produced by us;
 
    diversify our business portfolio, focusing on synergy among assets;
 
    expand activities in the petrochemical and fertilizer industries, by seeking strategic partnerships and promoting synergies with our other operations;
 
    improve efficiency in all stages of logistic processes by using a variety of transportation systems and focusing on operational excellence, safety standards and high quality services; and
 
    apply state of the art technology on oil processing to promote energy and environmental efficiency.
     Our refining, transportation and marketing results are reflected in the “Supply” segment in our audited consolidated financial statements.
Refining
     At December 31, 2005, we had total installed refining capacity of 1.99 million barrels per day, which, according to Petroleum Intelligence Weekly, made us the 8th largest refiner of oil products in the world among publicly traded companies in 2005. Worldwide, we processed an average of 1.69 million barrels of crude oil per day

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in 2005, which represents a utilization rate of 84.9% for the year, calculated over total capacity. This compares with an 85% average utilization rate in 2004 and an 81% average utilization rate in 2003.
     Our domestic production in 2005 supplied approximately 80% of the crude oil feedstock for our refinery operations in Brazil, as compared to 76% in 2004 and 80% in 2003. We expect an increasing percentage of the crude oil feedstock to be supplied by our relatively lower cost domestic production, as our overall domestic production increases. Because our domestic refining capacity constitutes 98.5% of the Brazilian refining capacity, we supply almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to satisfying our internal consumption requirements with respect to wholesale marketing operations and petrochemical feedstock.
     Our refineries are located throughout Brazil, with heavy concentration in the Southeast where demand for domestic products is greatest, due to significant industrial activity and large population centers. Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities. This configuration facilitates access to crude oil supply and major end-user markets in Brazil.
Refinery Production and Capacity
     In Brazil in 2005, we processed a total of 633 million barrels of crude oil or on daily basis 1.69 million barrels per day. Our Brazilian production supplied approximately 80% of this crude oil. Our average refining costs (consisting of variable costs and excluding depreciation and amortization) in Brazil were U.S.$1.90 per barrel in 2005, U.S.$ 1.38 per barrel in 2004 and U.S.$1.17 per barrel in 2003. Due to the heavier crude characteristic of many Brazilian fields, we have invested in equipment for conversion of heavy crude oil into lighter products. The majority of our heavy crude conversion capacity is located in our refineries: Landulpho Alves, Duque de Caxias, Paulínia, Presidente Bernardes, Gabriel Passos and Henrique Lage. The following table describes the installed capacity, refining throughput and utilization factor of our refineries for each of 2005, 2004 and 2003:
REFINING STATISTICS
                                                                         
    2005   2004           2003
    Capacity   Throughput(1)   Utilization(2)   Capacity   Throughput(1)   Utilization(2)   Capacity   Throughput(1)   Utilization (2)
Refineries   (Mbpd)   (Mbpd)   (%)   (Mbpd)   (Mbpd)   (%)   (Mbpd)   (Mbpd)   (%)
Paulínia
    365       320       88 %     365       351       96 %     365       297       81 %
Landulpho Alves (9)
    332       249       75       323       237       73       323       200       62  
Duque de Caxias (9)
    275       242       88       242       230       95       242       214       88  
Henrique Lage
    251       241       96       251       236       94       251       219       87  
Alberto Pasqualini(3)
    189       116       61       189       103       54       189       105       56  
Pres. Getúlio Vargas(4)
    189       186       98       189       165       87       189       191       101  
Pres. Bernardes
    170       157       92       170       154       91       170       164       96  
Gabriel Passos
    151       131       87       151       132       87       151       129       85  
Manaus
    46       44       96       46       45       98       46       44       96  
Capuava
    53       35       66       53       46       87       53       44       83  
Fortaleza
    6       5       83       6       5       83       6       5       83  
Total Brazilian (9)
    2,027       1,726       85     1,985       1,704       86       1,985       1,612       81  
 
                                                                       
 
                                                                       
Gualberto Villarroel(5)
    40       25       63     40       22       55       40       18       45  
Ricardo Eliçabe(6)
    31       26       84       31       30       98       31       30       97  
Guillermo Elder Bell(5)
    20       16       80       20       16       80       20       15       75  
San Lorenzo (7)
    38       37       97       38       33       89       38       33       87  
Del Norte (8)
                                                     
Total International
    129       104       81       129       101       78       129       96       74  
 
                                                                       
Total
    2,156       1,830       85 %     2,114       1,805       85 %     2,114       1,708       81 %
 
                                                                       
 
(1)   Throughput does not include slop or any reprocessed feedstock.
 
(2)   Utilization was calculated based on crude oil and NGL only.
 
(3)   We do not own 100% of this refinery.
 
(4)   Because of improvements to the crude plant of this refinery, its output can now slightly exceed the nameplate capacity originally registered with and acknowledged by the National Petroleum Agency in Brazil in 2003.

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(5)   Located in Bolivia. We expect that our participation in this refinery will be reduced as a result of the Bolivian nationalization program announced on May 1, 2006.
 
(6)   Located in Argentina.
 
(7)   Located in Argentina. We acquired this refinery through our acquisition of Petrobras Energía, formerly Perez Companc.
 
(8)   Located in Argentina. Del Norte statistics are not included since we own just 28.5% of that refinery.
 
(9)   Includes NGL Capacity (Mbpd): Landulpho Alves = 9, Duque de Caixas = 33.
     We operate our refineries, to the extent possible, to satisfy Brazilian demand. Brazil demands a proportionally high amount of diesel, relative to gasoline, which together represent more than half of our production. Because we operate refineries to maximize the output of diesel fuel for which demand in Brazil is greater than our internal production, we produce volumes of gasoline and fuel oil in excess of Brazilian demand and such excess must be exported.
     Brazil’s demand for oil products has been relatively constant for the last three years, but we continue to increase our refinery throughput, thereby reducing the amount of products we must import to satisfy demand. We have also increased our exports of refined products. The following table sets forth our domestic production volume for our principal oil products for each of 2005, 2004 and 2003:
DOMESTIC PRODUCTION VOLUME OF OIL PRODUCTS
                                                 
    2005   %   2004   %   2003   %
    (Mbpd)           (Mbpd)           (Mbpd)        
Product
                                               
Diesel
    660.1       38.0 %     657.0       38.7 %     623.4       38.0 %
Gasoline
    324.5       18.7     292.8       17.3       290.9       17.8  
Fuel oil
    257.8       14.9     279.9       16.5       266.4       16.2  
Naphtha and jet fuel
    218.5       12.6     220.2       13.0       219.6       13.4  
Other
    274.3       15.8     245.7       14.5       238.6       14.6  
 
                                               
 
                                               
Total
    1,735.2       100.0 %     1695.6       100.0 %     1,638.9       100.0 %
 
                                               
Refinery Investments and Improvements
     In recent years, we have made investments in our refinery assets in order to improve yields of middle and lighter distillates, which typically generate higher margin sales and reduce the need to import such products. Our principal strategy with respect to refinery operations is to maximize throughput of domestic crude oil. Since the heavy domestic crude oil produces a higher proportion of fuel oil for each barrel of crude oil processed, production of fuel oil is expected to remain relatively constant as throughput of additional Brazilian crude oil offsets new investment in conversion capacity and the production of coke which can be converted into middle distillates products.
     We plan to invest in refinery projects designed to:
    enhance the value of Brazilian crude oil by increasing capacity to refine greater quantities of heavier crude oil that is produced domestically;
 
    increase production of oil products demanded by the Brazilian market that we currently must import, such as diesel;
 
    improve gasoline and diesel quality to comply with stricter environmental regulations currently being implemented; and
 
    reduce emissions and pollutant streams.

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Major Refinery Projects
     Included in our Strategic Plan are a number of upgrades to key refineries. Our major investments are generally (1) coker to further break down heavy oil into middle distillates or (2) hydro treatment units that reduce sulfur to produce products that meet international standards. We believe our hydro-treatment units will make it possible to offer diesel fuel containing a maximum sulfur content of 0.05% (starting in 2012), thus meeting stricter environmental standards being implemented under Brazilian law. The principal refineries and planned investments (2006 – 2010) are as follows:
     
Refinery   Objective
Alberto Pasqualini (REFAP)
  Expansion and modernization of refinery, including the installation of a coker, residue fluid cat. craking unit, and upgrade gasoline and diesel quality.
 
   
Presidente Getúlio Vargas Refinery (REPAR)
  Installation of coker, expansion of existing refinery unit and units to upgrade the quality of diesel and gasoline.
 
   
Henrique Lage (REVAP)
  Installation of coker and units to upgrade the quality of diesel and gasoline.
 
   
Paulínia Refinery (REPLAN)
  Upgrade the quality of diesel and gasoline.
 
   
Landulpho Alves (RLAM)
  Expansion of existing refinery unit and units to upgrade the quality of diesel and gasoline.
 
   
Duque de Caxias Refinery (REDUC)
  Expansion of existing refinery, installation of a coker and units to upgrade the quality of diesel and gasoline.
 
   
Gabriel Passos Refinery (REGAP)
  Expansion of the coker and upgrade the quality of diesel and gasoline.
 
   
Presidente Bernardes Refinery (RPBC)
  Upgrade the quality of gasoline.
 
   
Capuava Refinery (RECAP)
  Upgrade the quality of diesel and gasoline.
Imports
     During 2005 we continued to import crude oil and oil products because domestic production was not sufficient to satisfy Brazilian demand for certain products. In addition, because the bulk of our domestic reserves consist of heavy crude oil, we need to import lighter crude oils to create an adequate mix of oils to satisfy Brazilian demand and to permit refining by our refineries.
     Imported crude oil is transferred into our refineries for storage and processing, with a small percentage being sold to the other two Brazilian refiners. Imported oil products are sold to the retail market in Brazil through distributors, including our subsidiary BR.
     The average daily volume of our imports of crude oil has decreased to 352 Mbpd in 2005, as compared to 450 Mbpd in 2004 because of the increase in domestic crude oil production. Part of such increase was allocated to our refineries as result of an improvement of heavy oil conversion capacity and part was allocated to crude oil exports.

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     The following table sets forth the percentage of crude oil that we imported during each of 2005, 2004 and 2003 by region.
IMPORTS OF CRUDE OIL BY REGION
                         
    2005   2004   2003
    Volume (%)
Region
                       
Africa
    67.5 %     73.4 %     63.7 %
Middle East
    29.4       24.2       30.9  
Central and South America/Caribbean
    3.1       2.4       3.1  
Oceania
    0.0       0.0       0.9  
Europe
    0.0       0.0       1.4  
 
                       
Total
    100.0 %     100.0 %     100.0 %
     In 2005, our total costs of imports of crude oil from all these regions was U.S.$6,035 million, as compared to U.S.$5,191 million in 2004 and U.S.$3,541 million in 2003.
     We purchased approximately 19.4%, 17.7% and 23.4% of our crude oil imports in 2005, 2004 and 2003, respectively, pursuant to one-year term contracts, which are considered to be long-term contracts within the industry standard practice. We are also a significant buyer of crude oil and oil products from suppliers in the international spot market.
     Imports of oil products also decreased to 95 Mbpd in 2005, as compared to 110 Mbpd in 2004 and 122 Mbpd in 2003, primarily as a result of the increase in domestic production. LPG decreased due to replacement by natural gas, and increase in the production as a result of the revamping of the refineries and an increase in production due to the addition of FCC catalizer additives. For distillates, the decrease in the imported amounts is a result of the increase in our processing capacity. For naphtha the increase is a result of imports of light naphtha used in oil chains. The following table sets forth the volume of oil products imported during each of 2005, 2004 and 2003:
IMPORTS OF OIL PRODUCTS
                         
    2005   2004   2003
    Volume (Mbbl)
Oil Product
                       
LPG
    6,268       11,537       12,034  
Distillates(1)
    16,740       16,879       23,183  
Naphtha
    8,243       7,231       5,026  
Others(2)
    3,523       4,487       4,225  
 
                       
Total
    34,774       40,134       44,468  
 
                       
 
(1)   Includes gasoline, diesel fuel and some intermediate fractions.
 
(2)   Includes Algerian NGLs, fuel oil, Ethanol, Methanol and others.
     In 2005, total costs of oil product imports, measured on a cost-insurance-and-freight basis, was U.S.$2,108 million, as compared to U.S.$1,721 million in 2004 and U.S.$1,542 million in 2003. For a discussion of import purchase volumes and prices, see Item 5. “Operating and Financial Review and Prospects—Sales Volumes and Prices—Import Purchase Volumes and Prices.”
     Exports
     We also export that portion of oil products processed by our refineries that exceed Brazilian demand. In addition, we export domestic crude oil that we are unable to process in our refineries because of limited conversion capacity. Our total exports increased to 214 MMbbl in 2005 from 186 MMbbl in 2004 as a result of the increase in production of domestic crude oils and the decrease in the local demand for inferior environmental quality products. The following table sets forth the volumes of oil products we exported during each of 2005, 2004 and 2003:

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EXPORTS OF OIL AND OIL PRODUCTS(1)
                         
    2005   2004   2003
    (Mbbl)
Crude Oil
    96,155       66,319       84,899  
Fuel Oil (including bunker fuel)
    63,896       107,104       85,740  
Gasoline
    17,240       11,510       13,656  
Other
    9,716       1,288       8,250  
 
                       
Total
    187,007       186,221       192,545  
 
                       
 
(1)   The figure includes sales made by PIFCo to unaffiliated third parties, including sales of oil and oil products purchased internationally.
     The total value of our crude oil and oil products exports, measured on a free-on-board basis, was U.S$10,086 million in 2005, U.S.$8,938 million in 2004 and U.S.$5,335 million in 2003.
Transportation
     The Oil Law requires that a separate company operate and manage the transportation network for crude oil, oil products and natural gas in Brazil, so we created a wholly-owned subsidiary, Transpetro, in 1998 to build and manage our vessels, pipelines and maritime terminals and handle various other transportation activities. In May 2000, Transpetro also took over the operation of our transportation network and storage terminals to comply with legal requirements. As of October 1, 2001, with the approval from the ANP, these pipelines and terminals were leased to Transpetro, which started to offer its transportation services to us and to third parties. As the owner of the facilities leased to Transpetro, we retain the right of preference for its shipments, based on the historical level of transportation assessed for each pipeline, formally assigned by the ANP. The excess capacity is available to third parties on a non-discriminatory basis and under equal terms and conditions.
     Prior to the enactment of the Oil Law, we were the only company authorized to ship oil products to and from Brazil and to own and operate Brazilian pipelines. Additionally, only vessels flying the Brazilian flag were entitled to carry shipments to and from Brazil. Pursuant to the Oil Law, the ANP now has the power to authorize any company or consortium organized under Brazilian law to transport crude oil, oil products and natural gas for use in the Brazilian market or in connection with import or export activities, and to build facilities for use in any of these activities. The Oil Law has also provided the basis for open competition in the construction and operation of pipeline facilities.
Pipelines and Terminals
     We own, operate and maintain an extensive network of crude oil and natural gas pipelines connecting our terminals to refineries and other points of primary distribution throughout Brazil. At December 31, 2005, our onshore and offshore crude oil and oil products pipelines totalled 6,245 miles or 10,048 kilometers in length, our natural gas pipelines aggregated approximately 5,705 miles or 9,179 kilometers in length, including the Brazilian side (1,612 miles or 2,593 kilometers) of the Bolivia-Brazil pipeline, and our flexible pipelines totalled 1,804 miles or 2,902 kilometers in length.

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NATURAL GAS PIPELINES IN BRAZIL
(NATURAL GAS PIPELINES MAP)

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CRUDE OIL AND OIL PRODUCTS PIPELINES IN BRAZIL
(CRUDE OIL AND OIL PRODUCTS PIPELINES MAP)
     In March 2005, we signed all of the financing documents for the Plano Diretor de Escoamento e Tratamento (PDET) project originally designed to enhance our crude oil transportation system extending from the most productive fields, located in the Campos Basin, to the refineries located in the Southeast region of Brazil.
     At the end of 2003, change in State of Rio de Janeiro Legislating required evaluation of economic feasibility of the original concept of the onshore portion of PDET. After that, we announced the cancellation of the onshore portion of the PDET project and a revision to the project’s original design.
     Under the revised project, the original offshore fixed platform (PRA-1) will be connected to five offshore production platforms through pipelines and will transfer the crude oil to a floating, storage and offloading platform (FSO) and two monobuoys, which will in turn facilitate the transfer of the crude oil to shuttle tankers or the export of the crude oil to other countries. The shuttle tankers will transport the oil to the Southeast terminals where it will be pumped to existing onshore pipelines connected to refineries in Rio de Janeiro, Minas Gerais and São Paulo. The PDET project will cost approximately U.S.$760 million and is expected to start its commercial operation in the first quarter of 2007. This project will permit to increase the flow of oil produced in the Campos Basin by up to 630 Mbpd.
     Transpetro also operates 44 storage terminals with nominal aggregate capacity of 65.0 million barrels of oil equivalent. At December 31, 2005, tankage capacity at these terminals consisted of 35.2 million barrels of crude oil, 27.3 million barrels of oil products and fuel alcohol and 2.5 million barrels of LPG. In 2005, Transpetro began to operate a new storage terminal (TNC—Norte Capixaba Terminal) with the nominal tankage capacity of 491 M barrels.
     Transpetro is currently evaluating alternatives to improve the efficiency of its transportation system, including improvements to the monitoring and control of the pipeline network through the gradual implementation of a supervisory control and data acquisition system, which, when completed, will monitor the pipelines and storage facilities located throughout the country.

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     Transpetro implemented the first phase of the project and inaugurated a centralized control and operating center in June 2002, in its headquarters in Rio de Janeiro. Currently, there are a national back-up master station and two regional master stations connected through satellite communication. Tank-farms and pump stations are equipped with mini stations connected to the regional master stations. Transpetro’s goal is to be able to operate all of its domestic pipelines remotely, initially via the regional stations, and ultimately via the centralized control and operating center located in its headquarters in Rio de Janeiro. In 2005, the Centralized Control and Operating Center began to operate a new gas pipeline, GASCAB III. We will continue to develop this project. In addition, Transpetro has been investing in the development of a pipeline integrity program (Programa de Integridade de Dutos) to ensure the integrity and safety of its pipelines operations.
Shipping
     At December 31, 2005, our fleet consisted of the following 52 vessels (46 owned and 6 bareboat chartered), 32 of which are single hulled and 20 of which are double hulled:
OWNED/BAREBOAT CHARTERED VESSELS
                 
    Number   Capacity
            (deadweight tonnage in thousands)
Type of Vessel
               
Tankers
    44       2,443.4  
Liquefied petroleum gas tankers
    6       40.2  
AHTS Anchor Handling Tug Supply
    1       2.2  
FSO Floating, Storage and Offloading
    1       28.9  
 
               
Total
    52       2,514.7  
 
               
     These vessels are currently operated by Transpetro and their activities are mainly concentrated in the Brazilian coastline, South America (Venezuela and Argentina), Mediterranean Sea, Caribbean Sea, Gulf of Mexico, West Africa and the Persian Gulf. The single-hulled ships only operate in areas where environmental legislation permits, including Brazil, Venezuela, Argentina and the West Coast of Africa. The double-hulled ships operate in other international locations in accordance with applicable laws. Our shipping operations support the transportation of crude oil from offshore production systems, our import and export of crude oil and oil products and our coastal trade. Our Business Plan calls for investment of U.S.$1.0 billion to renew our fleet, by adding 53 vessels by 2015. The table below sets forth the types of products and quantities of such products we transported during each of the years indicated.
PRODUCTS AND QUANTITIES TRANSPORTED
                         
    2005   2004   2003
    (millions of tons)
Product
                       
Crude oil
    92.38       88.4       96.6  
Oil Products
    40.42       34.0       28.1  
Fuel Alcohol
    0.04              
 
                       
 
                       
Total
    132.84       122.4       124.7  
 
                       
 
                       
Percentage transported by our owned/bareboat chartered fleet
    43 %     45.1 %     45.3 %
Coastal transport as a percentage of total tonnage
    67 %     61.1 %     64.2 %
     The average monthly-chartered tonnage in 2005 amounted to 5.9 million deadweight tons, as compared to 4.6 million deadweight tons in 2004 and 4.0 million deadweight tons in 2003. The chartered tonnage is continuously adjusted to our needs for overall market supply cost reduction. Our aggregate annual cost for vessel charters was U.S.$972.01 million in 2005, U.S.$701 million in 2004 and U.S.$537 million in 2003.

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Petrochemicals
     We conduct petrochemical activities with the exception of naphtha sales through our subsidiary, Petrobras Química S.A., or Petroquisa. Petroquisa is a holding company with interests in nine operational petrochemical companies involved in the production and sale of basic petrochemical products and utilities. At December 31, 2005, our ownership percentage of the total capital of these investees ranged from 8.45% to 85.04% and our ownership percentage of the voting capital of these investees ranged from 10.02% to 70.45%. The total book value of these investments was U.S.$820 million on December 31, 2005. Most of such interests are minority voting interests.
     The basic supply feedstock used in Brazil’s petrochemical industry is naphtha . Until 2001, we were the sole supplier of naphtha to Brazil’s petrochemical industry. Following regulatory change in 2002, the petrochemical industry began importing naphtha directly. In 2005, the industry imported approximately 35.6% of its naphtha needs, and we supplied the remainder from our refining operations.
     The shareholder equity in the affiliate companies of the petrochemicals business increased by U.S.$12 million between 2004 and 2005. We currently expect to maintain a presence in the petrochemicals industry principally by participating in projects integrated with our refineries. We expect that our selective investments in petrochemicals will consolidate our involvement in the entire value chain and will help integrate our basic and refining products. Although we have divested certain interests in the petrochemical segment in the past, we plan to increase the current level of investments, as part of our downstream strategy.
     In line with our strategy of stimulating demand for natural gas products, we also continue to invest in Rio Polímeros S.A.,(Gas Chemical Complex). Located next to our Duque de Caxias Refinery (REDUC). The complex has a nominal plant capacity of 540,000 tons per year of polyethylene and 79,000 tons per year of propylene produced from ethane and propane extracted from natural gas originated in the Campos Basin. In addition to Petroquisa, the three other investors are BNDESPAR and two leading private Brazilian petrochemical companies, Suzano and Unipar. Petroquisa holds a 16.7% interest of the voting and preferred capital in Rio Polímeros. Of the approximately U.S.$1.08 billion budgeted construction cost, 60% is being provided by long-term loans from, or guaranteed by, U.S. Ex-Im Bank, BNDES (the Brazilian Federal Development Bank) and SACE (the Italian Export Credit Agency), and 40% is funded by equity investments. Rio Polímeros has been in operation since late 2005. In the first quarter of 2006, the Contractor ran reliability and performance tests in order to reach the guaranteed acceptance level and operational stage. On March 31, 2006 the test and commissioning phase of Rio Polímeros was concluded.
     According to our 2006-2010 Business Plan, we intend to spend approximately U.S.$2.0 billion in capital expenditures in our Brazilian petrochemicals operation. Such investment will be aimed at increasing production of basic petrochemicals, including polyolefins (polyethylene and polypropylene), acrylic acid and terephtalic acid. These projects will be carried out with other partners. Additionally, the preliminary technical and economic feasibility studies carried out by Petrobras identified the construction of a basic petrochemical complex as an important opportunity. This complex would integrate refinery units and petrochemical facilities to produce petrochemical raw materials like ethylene, propylene, aromatics and its petrochemical derivatives, like polyethylene and polypropylene, in order to supply the growing demand for such products in the Brazilian market. We are currently evaluating the conceptual project for this petrochemical complex. On March 28, 2006 we defined that the Petrochemical Complex of Rio de Janeiro will be built on the border of Itaboraí and São Gonçalo, in the State of Rio de Janeiro, with capacity to process 150 Mbpd and produce petrochemical raw material in the following quantities: 1,3 million tons/year of ethylene, 0.9 million tons/year of propylene, 0.36 million tons/year of benzene, 0.7million tons/year of p-xylene and oil derivatives such as 0.7 million tons/year of coke and small amounts of diesel oil and naphtha. The total global investment is estimated to reach U.S.$6.5 billion, including the second generation units, polyethylenes, polypropylene, styrene and ethylene-glycol. The complex is expected to be operating in 2012.
     On April 29, 2005, Odebrecht, Norquisa and ODBPAR (the Odebrecht Group) and Petroquisa entered into a second amendment to the memorandum of understanding under which Petroquisa had an option to acquire an amount of Braskem voting shares sufficient to increase its existing participation in Braskem to up to 30% of Braskem voting share capital (which we refer to as “Option Shares”). Such memorandum also eliminated the restriction on Petroquisa from owning interests in other petrochemical companies or projects following its possible exercise of the option. On March 31, 2006, after appraisals carried out by the concerned parties, Petroquisa decided

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not to exercise the Option Shares, as the parties were not able to reach a consensus regarding the terms and conditions for this exercise. The current shareholding structure of Braskem will not suffer any change, as the shareholding position currently held by Petroquisa of 10.02% in the voting capital and 8.45% in the total share capital of Braskem will be maintained, as well as the provisions of the Memorandum of Understanding for a Shareholders Agreement of Copene Petroquímica do Nordeste S.A. (the former name of Braskem), signed by Odebrecht and Petroquisa.
     On September 16, 2005, Petroquisa and Braskem incorporated Petroquímica Paulínia S.A.—PPSA, a joint venture between the two companies, contributing 40% and 60% of the entity’s capital, respectively. PPSA’s purpose is to implement a polypropylene unit in Paulínia-SP and to use a polymer-grade propylene supplied by us as raw material for its operations, with capacity of 300 thousand tons per year and a global investment estimated at U.S.$240 million. The commercial operations are projected to begin in the first quarter of 2008. To date, Petroquisa has invested R$3 million.
     On November 28, 2005, Petroquisa, Mossi & Ghisolfi and Citene signed a Memorandum of Understanding in which Mossi & Ghisolfi and Citene agreed to conduct a feasibility study relating to the development of a Purified Terephthalic Acid Plant in Pernambuco. The study showed favorable results. In March of 2006, Petroquisa and Citene signed a new memorandum regarding the creation of a company to implement the project and Mossi & Ghisolfi withdrew from the project. Petroquisa and Citene are considering whether to involve a new partner in the project and are currently negotiating the joint venture, which will be responsible for the development of the project. The plant will have a capacity of 550 thousand tons per year. We are projecting that an investment of U.S.$492 million through 2009 will be required for this project, as an estimate of the start-up costs of the plant through 2009.
     On April 17, 2006, our Board of Directors approved the incorporation of all outstanding shares of Petroquisa. Currently, we hold approximately 99% of Petroquisa’s capital stock and the remaining 1% is dispersed among minority shareholders. The main purpose of the share incorporation is to align the strategic interests of both companies. Under the terms of the incorporation, each lot of 1,000 common or preferred shares issued by Petroquisa will be exchanged for 4,496 preferred shares of our Company. As a result of such incorporation, we will issue 886,670 new preferred shares. In accordance with Brazilian Corporation Law, the share incorporation is still subject to approval by the shareholders of both companies, and the dissenting shareholders of Petroquisa have the right to withdraw.
Distribution
Summary and Strategy
Through Petrobras Distribuidora S.A., or BR, we distribute oil products and, fuel alcohol to retail, commercial and industrial customers throughout Brazil. Our operations are supported by tankage capacity of approximately 14.6 million boe, at 111 storage facilities and 96 aviation product depots at airports throughout Brazil.
     Our main strategies in distribution and marketing are to:
    be the preferred brand of the consumer, with a multi-business retail network that offers excellence in the quality of products and services, expanded leadership and guaranteed expected profitability; and
 
    add value to our system, by being the leader in all consumer market segments, launching new products, services and innovative solutions and by assuring the preference for our brand.
     As of 2005, Liquigás Distribuidora became the official name of our liquefied petroleum gas (gás liquefeito de petróleo, or LPG) distribution company, previously called Agip do Brasil S.A. and Sophia do Brasil S.A. Agip do Brasil S.A. was acquired in August 2004 to expand our participation in the LPG distribution sector and to consolidate our presence in the distribution market. By the end of 2005, Liquigás Distribuidora held a 21.8% market share and ranked third in the LPG distribution market based on sales volume according to Sindigás (Sindicato Nacional das Empresas Distribuidoras de Gás Liqüefeito de Petróleo).

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     In 2005, we sold 173.9 million barrels of oil products to wholesale customers, with gasoline and diesel fuel representing approximately 85% of these sales. Of our total sales in 2005, 157.8 million barrels of oil products were supplied to BR for retail marketing. The following table sets forth our oil product sales to wholesale customers and retail distributors for each of 2005, 2004 and 2003:
OIL PRODUCT SALES
                         
    2005   2004   2003
    (MMbbl)
Product
                       
Diesel
    228.1       224.9       208.3  
Gasoline
    114.3       104.8       101.8  
Fuel oil
    77.2       106.1       98.5  
Naphtha and jet fuel
    79.3       81.5       76.6  
Others
    343.5       129.1       283.2  
 
                       
Total
    842.4       646.4       768.4  
 
                       
 
                       
Customer
                       
Wholesalers
                       
Diesel
    105.5       106.6       100.2  
Gasoline
    43.0       42.9       41.0  
Others
    25.4       25.6       26.0  
 
                       
Total wholesalers
    173.9       175.1       167.2  
 
                       
 
                       
Retail distributors
                       
BR
    157.8       145.1       133.6  
Third parties
    510.7       326.2       467.6  
 
                       
Total retail distributors
    668.5       471.3       601.2  
 
                       
Total customers
    842.4       646.4       768.4  
 
                       
Retail
     As of December 31, 2005, our sales network in Brazil included 6,933 retail service stations compared to 6,785 as of December 31, 2004, and comprised approximately 24.5% of the total number of service stations in Brazil, all under the brand name “BR.” Over 50% of these BR stations are located in the South and Southeast regions of Brazil, where over 59% of Brazil’s total population of 180 million reside. Of these 6,933 service stations, 5,885 were active stations and BR owned 763. As required under Brazilian law, BR subcontracts the operation of all its service stations to third parties. The other 6,170 service stations were owned and operated by dealers, who use the BR brand name under license with BR facilities as their exclusive suppliers. BR provides technical support, training and advertising for its network of service stations.
     In 2005, 295 of our service stations also sold vehicular natural gas, compared to 245 in 2004 and 204 in 2003. The sales from these stations consisted of 17,208 million cubic feet (487 million cubic meters) in 2005, representing 25.1% of Brazilian market share, 15.005 million cubic feet (425 million cubic meters) in 2004, representing 27% of Brazilian market share and 14,554 million cubic feet (412 million cubic meters) in 2003, representing 31.2% of Brazilian market share.

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     The table below sets forth market share (based on volume) for retail sales of different products in Brazil for each of 2005, 2004 and 2003:
BR MARKET SHARE IN DISTRIBUTION
                         
    2005   2004   2003
Fuel oil
    64.8 %     64.4 %     65.2 %
Diesel
    31.9       28.6       26.1  
Gasoline
    25.0       22.1       21.1  
Fuel alcohol
    32.2       31.2       33.3  
 
                       
Total
    33.8 %     31.6 %     30.8 %
 
                       
     Prices to retailers have generally tended to remain consistent between competing distributors, particularly due to the low margin in the sector. Therefore, competition among distributors continues to be primarily based on product quality, service and image.
     During 2005, approximately 27% of the retail sales at service stations in Brazil were made through BR-owned or franchised entities. We believe that our market share position has remained strong over the past several years due to the strong brand name recognition of BR, the remodeling of service stations and the addition of lubrication centers and convenience stores.
     In 1996, BR created the “De olho no Combustível” program (“Eye on the Fuel” program), which is a certification program designed to ensure that the fuels sold to end consumers at service station networks are identical in content to the fuels originating from our refineries. We have already certified 4,496 service stations under this program.
     The retail market for gasoline and diesel fuel in Brazil is highly competitive and we expect that prices will be subject to continuing pressure. Accordingly, we intend to build upon the strong brand image that we have established in Brazil to enhance profitability and customer loyalty. We plan to take the following actions through 2010:
    selectively expand our service stations network, reinforcing the Petrobras image;
 
    increase the use of client fidelity programs and new technologies; and
 
    reduce operating and administrative costs and provide services, such as financial services and controls, through investments in advanced telecommunications and data processing technology.
     We participate in the retail sector in Argentina, where we currently own 746 retail service stations that operate under the brand names Petrobras (451 stations), Eg3 (248 stations) and San Lorenzo (47 stations). We also have a participation in the retail sector in Bolivia, Colombia, Paraguay and Uruguay, with 104, 39, 131 and 89 retail service stations respectively.
Commercial and Industrial
     We distribute oil products to commercial and industrial customers through BR. Our major customers are aviation, transportation and utility companies and government entities, all of which generate relatively stable demand. We have a market share in the commercial and industrial distribution segment in excess of 33.8% which has remained relatively constant over the past several years.

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     Set forth below are commercial and industrial sales statistics for each of 2005, 2004 and 2003:
COMMERCIAL AND INDUSTRIAL RETAIL SALES BY PRODUCT
                         
    For the Year Ended December 31,
    2005   2004   2003
            (Mboe)        
Fuel oil
    22,850       24,649       27,729  
Diesel
    78,241       70,521       60,117  
Gasoline
    36,690       32,147       28,710  
Jet fuels
    15,784       15,020       14,343  
Fuel alcohol
    5,132       4,147       3,286  
Lubricants
    1,601       1,460       1,256  
Others
    24,943       22,609       23,198  
 
                       
Total
    185,241       170,554       158,638  
 
                       
Natural Gas and Power
Summary and Strategy
     Our natural gas and power activities encompasses the purchase, sale and transportation of natural gas produced in or imported into Brazil. Additionally, this segment includes our domestic electric energy commercialization activities as well as participation in domestic natural gas transportation companies, state-owned natural gas distributors and gas-fired power plants.
     The natural gas market in Brazil has been growing steadily. The Brazilian government estimated that, in 2005, natural gas consumption represented approximately 9,3% of primary energy use, as compared to 8,9% in 2004 and 7,7% in 2003. In addition, the Brazilian government estimates that natural gas will represent 11% of primary energy use by 2010. We expect that a portion of this growth will come from increased industrial demand as well as from the replacement of fuel oil by cleaner energy sources. The development of natural gas-fired power plants in Brazil will also add growth to the natural gas market. During the last three years, industrial consumption of natural gas has increased at a compounded annual growth rate of 8.0% while vehicular consumption has increased approximately 13,2%. In 2005, industrial and vehicular consumption have grown 7.15% and 20.2%, respectively.
     To capitalize on these growth opportunities, we have adopted a vertically integrated strategy. As a result of our petroleum exploration and production activities in Brazil, we produce significant amounts of associated natural gas as a by-product.
     Our main strategies in the natural gas and power segment are to:
    develop the natural gas industry in an integrated manner with other areas of the Company, in Brazil and other South American countries;
 
    take advantage of growing opportunities in the power industry in an integrated manner with other natural gas market sector in which our Company already operates; and
 
    develop some renewable energy alternatives and the Mecanismos de Desenvolvimento Limpo – MDL, or Clean Development Mechanisms, as well as coordinate and implement activities related to energy efficiency to the Petrobras system and final consumers.
     Our natural gas and power results are reflected in the “Gas and Energy” segment in our audited consolidated financial statements.

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Natural Gas
Pipelines
We developed and built the Bolivia-Brazil natural gas pipeline, which has a total capacity of 1,060 MMscfd (30 MMcmd). The pipeline is 1,969 miles (3,150 kilometers) in length, running from Rio Grande in Bolivia to Porto Alegre in Southern Brazil. The Bolivia-Brazil pipeline connects to our domestic pipeline system that transports natural gas from the Campos and Santos Basins. This pipeline was designed to supply gas to some of our power and petrochemical plants. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations¾ The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition.”
          The Cabiúnas project comprises transportation and processing facilities of natural gas from the offshore oil fields in the Campos Basin of the State of Rio de Janeiro. This project has been operational since the second semester of 2005 and increased the transportation capacity from the previous 290 million cubic feet (8.2 million cubic meters) per day to a total of 476 million cubic feet (13.5 million cubic meters) per day of associated gas, while reducing the volumes of natural gas currently flared on offshore platforms and alleviating existing constraints on oil production from these platforms. In 2005, the average daily volume of natural gas flared on the offshore platforms of the Campos Basin was 130.7 million cubic feet (3.7 million cubic meters).
          We are currently developing the Southeast and the Northeast Gas Pipeline Networks (Malha Sudeste and Malha Nordeste). This project, which is known as the Malhas Project, will create additional transportation capacity by expanding the existing natural gas infrastructure and delivering natural gas to markets in the Northeast and Southeast regions of Brazil. This project includes the construction of an approximately 808 miles (1,300 kilometers) pipeline network, which is expected to start operations gradually during the years of 2006 and 2007, at a total cost of approximately U.S.$1.5 billion.
          The projected pipeline to deliver natural gas to the state of Amazonas in Northern Brazil (Coari – Manaus Gas Pipeline), will have a length of 382 kilometers, and the project to deliver liquefied petroleum gases to the same state (Urucu-Coari LPG Pipeline), will have a length of 279 kilometers.
Local Distribution Companies
     We sell natural gas in Brazil to local gas distribution companies, since under Brazilian law, each state has the monopoly over local distribution . Most states have established companies to act as local gas distributors and we have interests in some of these companies.
     We appoint the majority of the technical and commercial directors of all distribution companies in which we hold a minority shareholding stake.
          In December 2004, Gaspetro acquired a 40% equity interest in Gasmig, the gas distribution company of the State of Minas Gerais, for R$154 million (U.S.$58 million). In connection with this acquisition, we assumed the obligation to construct natural gas pipelines to be financed by Cemig. In July 2005, Gaspetro also increased its participation in CEG-Rio, the gas distribution company of the State of Rio de Janeiro, by acquiring an additional 12.41% of shares of CEG-Rio from Gás Natural SGD for R$39.3 million (U.S.$16.5 million). Gaspetro now holds 37.41% of CEG-Rio’s shares.
     Currently we hold, through our subsidiary PETROBRAS Gás S.A. — GASPETRO, 19 minority interests in natural gas distribution companies in many states of Brazil. However, 5 Companies (CEBGÁS, GOIASGÁS, RONGÁS, GASAP and GASMAR) have not yet started their operations. We are not shareholders in the following companies: MTGÁS, COMGAS, CIGAS, GAS BRASILIANO, SPS and CEG. Also, in the state of Espírito Santo, we have the exclusive rights to distribute natural gas through our subsidiary BR.
     In 2005, the gas distribution companies in which we have an interest (ALGÁS, BAHIAGÁS, CEGÁS, CEG-RIO, COMPAGÁS, COPERGÁS, MSGAS, GASPISA, PBGÁS, POTIGÁS, SCGÁS, SERGAS, SULGAS and

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GASMIG) held total assets of R$ 2,289 million (U.S.$ 978million) compared with R$2,250 million (U.S.$848 million) in 2004. The assets are mainly an aggregate pipeline extension of 2,654 miles (4,272 kilometers).
     Although in 2005 the average volume of gas distribution, of the companies in which we have an interest was almost the same as in 2004 (692 million cubic feet of natural gas per day, or 19.6 million cubic meters per day), the total net operational revenue in 2005 was R$3.467 billion (U.S.$1.481 billion) as compared to R$3.010 billion (U.S.$1.134 billion) in 2004.
     The total net income of the companies in which we have an interest increased, and reached R$ 299.0 million (U.S.$ 127.8 million) last year compared with R$ 277.1 million (U.S.$ 104.4 million) in 2004. Such increase resulted from the appreciation of the Brazilian real against the U.S. dollar and the increase in the consumption by industrial and vehicular segments, which generate a higher margin, as opposed to gas-fired power plants, in which the use of gas was reduced.
     In 2005, investments on the companies in which we have an interest reached a total of R$ 290.8million (U.S.$ 124.2million) compared to R$ 277.3 million (U.S.$ 104.4million) in 2004.
     Some of the operating distribution companies in which we have an interest has entered into long term gas supply contracts with us under which such companies have gas purchase obligations (in the case of contracts relating to Brazilian gas), and ship-or-pay and gas purchase obligations (in the case of contracts relating to Bolivian gas or with gas-fired power producers). These ship-or-pay and gas purchase contracts do not allow net settlement by either the buyer or the seller, and no market mechanism exists for net settlement.
          The following table sets forth our domestic sales of natural gas to affiliated and non-affiliated local distribution companies for each of 2005, 2004 and 2003:
DOMESTIC SALES OF NATURAL GAS TO LOCAL DISTRIBUTION COMPANIES
                         
    Year Ended December 31,
    2005   2004   2003
(in MMscfd)    
Total sales annual average(i)
    1,289       1,164       978  
Annual sales growth(i)
    11 %     19 %     13.4 %
 
(i)   The volume of natural gas sold to local distribution companies (thermal and non-thermal). Our internal consumption and natural gas received by internal transfer are not included.
Commitments and Sales Contracts
Our investment in the Bolivia-Brazil gas pipeline was the result of a 1996 gas supply agreement, or the GSA, for the purchase of natural gas between the Bolivian state oil company, Yacimientos Petrolíferos Fiscales Bolivianos –YPFB, and us. The GSA requires us to purchase from YPFB specified quantities of natural gas transported through the pipeline over a 20-year term. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations¾ The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition.”
          Gas purchase commitments. Under our contracts with YPFB for the purchase of natural gas, we have agreed to purchase minimum volumes of natural gas from Bolivia at a formula price that varies with the price of fuel oil. We have purchased and paid in 2005, 2004 and 2003, approximately U.S.$799 million, U.S.$544 million and U.S.$362 million, respectively. Such increase resulted from higher prices (which reflected the international prices for oil and fuel) and the increase in the imported amounts: 22.96 MM m3/d in 2005, as opposed to 19.94 MM m3/d in 2004 and 14.17 MM m3/d in 2003. During 2002 and 2003 we purchased less than the minimum volumes set under our agreement with YPFB, and therefore we paid a total amount of U.S.$81 million to satisfy our purchase commitment. Set forth below are the minimum volumes we have agreed to under these contracts, together with an estimate of the amounts we are obligated to pay for such minimum volumes:

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NATURAL GAS PURCHASE COMMITMENTS
                                         
    2006   2007   2008   2009   2010
Volume Obligation (Mmcmpd)
    24       24       24       24       24  
Volume Obligation (Mmcfd)
    850       850       850       850       850  
Estimated Payments (U.S.$ million)(1)
    1,025       921       759       654       634  
 
(1)   Amounts calculated based on current prices set forth under the agreements projected constant to the future. Prices may be adjusted in the future and actual amounts may vary. Of these amounts, 25.3% are related to Petrobras Bolivia.
          In connection with the above gas purchase contract, we entered into a contract, effective October 2002, with a gas producer to reduce the volatility of prices under the gas purchase contract through 2019 – the Natural Gas Price Volatility Reduction Contract, or PVRC. The volume covered by the PVRC represents approximately 43% of the anticipated volume under the gas purchase contract. See “Qualitative and Quantitative Disclosure about Market Risk—Petrobras—Commodity Price Risk” and Note 23 to our audited financial statements.
          Ship-or-pay commitments. In order to support the financing for the Bolivia-Brazil pipeline, we also have entered into unconditional ship-or-pay purchase obligations for the transportation of natural gas with Gás Transboliviano or GTB and Transportadora Brasileira Gasoduto Bolivia-Brasil or TBG, the companies which own and operate the Bolivian and Brazilian portions of the pipeline, respectively. TBG’s portion of the pipeline financing is consolidated in our balance sheet. Our volume obligations under the ship-or-pay arrangements are generally designed to meet the gas purchase obligations with respect to our gas purchase contracts with YPFB. The total capacity of 1,060 MMscfd (30 MMcmd) also includes a transportation capacity option of 212 MMscfd (6 MMcmd), valid for a 40-year term. This transportation capacity option was granted to us in consideration for our agreed investment of approximately U.S.$379 million in the Bolivia-Brazil gas pipeline. The total estimated project cost was U.S.$1.9 billion. In 2005, 2004 and 2003, Petrobras made total payments of approximately U.S.$532 million, U.S.$348 million and U.S.$504 million, respectively. Of these amounts, approximately U.S.$473.5 million, U.S.$302 million and U.S.$463 million corresponded, respectively, to payments made to TBG for the transportation of natural gas. Set forth below are the minimum volumes we have agreed to under the ship-or-pay arrangements, together with an estimate (assuming certain changes in the U.S. Consumer Price Index (CPI)) of the amounts we are obligated to pay for such minimum volumes:
NATURAL GAS SHIP-OR-PAY COMMITMENTS
                                         
    2006   2007   2008   2009   2010
Volume Commitment (Mmcmpd)(1)
    59.51       59.51       59.51       59.51       59.51  
Volume Commitment (Mmcfpd)(1)
    2,102       2,102       2,102       2,102       2,102  
Estimated Payments (U.S.$ million)(1)
    487.73       490.57       492.61       494.70       496.75  
 
(1)   The figures for TBG and GTB are consolidated.
          Natural gas sales contracts. In light of these gas purchase and ship-or-pay obligations, we have entered into or negotiated firm gas sale and ship-or-pay sale arrangements to sell our domestic and international natural gas to local gas distribution companies and gas-fired power plants, most of which we operate and in which we own a minority interest.
          The arrangements with the gas-fired power plants are made through contracts with the local distribution companies, which in turn enter into back-to-back arrangements with the gas-fired power plants, and a portion of the gas buyer’s payments is usually guaranteed to us by the parent companies of the gas-fired power companies or through financial guarantees. Our total sales of natural gas, which includes sales to gas-fired power companies, for 2005, 2004 and 2003, were approximately U.S.$2,398 million, U.S.$1,876 million and U.S.$1,580 million, respectively. The table below sets forth the commitments by local gas distribution companies and by gas-fired power plants for the firm purchase of volumes of natural gas from us beginning in 2006, together with an estimate of the amounts obligated to be paid for such volumes:

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NATURAL GAS SALES CONTRACTS
                                         
    2006   2007   2008   2009   2010
    (in Mmscfd)
To Local Gas Distribution Companies
                                       
Related parties(i)
    585       624       647       668       686  
Third parties
    494       534       430       423       425  
To Power Generation Plants
                                       
Related parties(i)
    27       27       55       55       55  
Third parties
    184       184       184       184       184  
Total
    1,290       1,369       1,316       1,330       1,350  
 
                                       
Estimated Contract Receipts (U.S.$ million)(ii)(iii)
  $ 2,023     $ 2,111     $ 1,923     $ 1,916     $ 1,985  
 
(i)   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.
 
(ii)   Figures show revenues net of taxes. Estimates are based on firm contracts and do not include internal consumption or transfers. Estimated volumes are based on “take or pay” agreements in our contracts, not maximum sales.
 
(iii)   Prices may be adjusted in the future and actual amounts may vary.
          Pricing. On June 1, 2001, the Brazilian government instituted a mechanism which allows a U.S. dollar indexed component of the natural gas pricing mechanism to be passed through to gas-fired power plants for a period of 12 years, pursuant to Portaria No. 176 (a joint regulatory act issued by the Ministry of Mines and Energy and the Ministry of Finance), which was updated by Portaria No. 234 issued on July 22, 2002. See “—Regulations of the Oil and Gas Industry in Brazil—Price Regulation—Natural Gas.” This mechanism has enabled us to sell natural gas to a number of gas-fired power plants that were unwilling to purchase natural gas under the prior gas price regulation because it requires the buyer to take the intra-year exchange rate risk. Under the new formula, exchange rate variations are reflected in gas prices annually, while we will be remunerated at market based interest rates for any resulting delay in gas price adjustments.
Power
          Brazil currently has an installed electricity generation capacity of approximately 91,314 MW. More than 96% of this capacity is interconnected to form one single integrated system, with approximately 76% of the electricity supplied to that system coming from hydroelectric sources. Consumption of electricity grew annually at a rate of 4.5% during the 1990s. As a result of the rapid growth in electricity demand, combined with the limited investment in the sector during the last two decades and a high dependency on hydroelectric power (and consequently susceptibility to a prolonged drought), we believe substantial additional generation capacity needs to be developed in Brazil. In recognition of the need for such capacity and in order to promote the development of gas-fired power plants, the Brazilian government established the Thermoelectric (gas-fired) Priority Program (PPT).
New Regulatory Model
          A new regulatory model for the power sector was introduced on March 16, 2004 with the enactment of the New Industry Model Law. Under the new model, assured energy availability may be sold under regulated contracts or free contracts. Energy availability sold under regulated contracts must be acquired by means of public auctions and energy availability sold under the free market is negotiated freely through bilateral contracts. The new regulatory model also creates incentives for investments in power generation.
          The first auction for new power plants was held in December of 2005. We participated in the auction and sold 1,391 MW of energy from our gas-fired power plants with the intention of securing long-term contracts. The contracts represented 42% of the energy sold in the auction.

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Status of Investments
          We believe our participation in the construction and development of gas-fired power plants has strategic benefits for our business because:
    our participation in the power sector helps create a market for natural gas made available through our investments in the natural gas business;
 
    we are able to build “inside the fence” co-generation plants close to our refineries and other facilities, which provide us with a reliable and inexpensive source of electricity for use in our own refineries; and
 
    these co-generation plants also produce steam for use by our refineries and in onshore crude oil recovery enhancement projects. The production and consumption of steam reduces the overall costs of generating electricity, making such electricity cost competitive relative to other gas-fired power generation, including new hydroelectric developments.
          In addition, we concluded a program for the acquisition of certain gas-fired power plants, in order to mitigate the losses resulting from contractual obligations previously suffered.
          The main purpose of these acquisitions is to reduce our financial exposure in connection with these merchant gas-fired power plants. See “—Financial Exposure.”
Financial Exposure
          To encourage the development of some of the gas-fired power plants in which we participate with an equity interest, or to which we sell our natural gas, we have entered into agreements to provide economic support to such gas-fired power plants. Our obligations under these agreements were structured as tolling arrangements whereby we agree to provide each of the inputs to produce electricity and operate the plant, as well as off-take the electricity, remunerating the thermoelectric plant at a price that will service capital (equity and debt).
          We have only entered into tolling arrangements with gas-fired power plants in which we have an equity interest. Our power commitments under the tolling agreements are as follows:
POWER OFFTAKE PROJECTED COMMITMENTS
                         
PLANT   2006   2007   2008
    (Average MW)
FAFEN
    138       138       138  
TermoBahia
    186       186       186  
Total NE Tolling Arrangements
    324       324       324  
Ibiritermo
    226       226       226  
Total S/SE Tolling Arrangements
    226       226       226  
          The total generating capacity in respect of which we have tolling commitments, based upon commitments of projects under construction or in operation, is 550 MW in 2006.
          We expect that the electricity we purchase under the tolling agreements will be partly used for demand in our facilities, estimated to be 319 MW in 2006, 362 MW in 2007 and 382 MW in 2008, allocated between the Northeast and South/Southeast regions of Brazil. UTE FAFEN has a power purchase agreement for the sale of electric power to third parties (distributors /concessionaires). By the end of the fourth quarter of 2005, we sold energy availability in auctions coordinated by the MME, by means of energy agreements of 15 years, starting as of 2008, with increasing volumes, reaching 1391 MW in 2010. Our commercial strategy is to continue the sale of our remaining capacity in public auctions to distributors and the sale to large consumers through power purchase agreements.

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          After the acquisition of UTES Eletrobolt, TermoCeará and Macae Merchant between April 2005 and April 2006, we ended our financial exposure with third parties relating to contingency contributions.
          In January 2003, Companhia Paranaense de Energía, or Copel, ceased making its monthly capacity payments to UEG Araucária Ltda. — UEGA (an independent gas-fired power producer that initiated operations in September 2002 and which is 60% owned by El Paso, 20% by Copel and 20% by us). In April 2003, UEGA initiated arbitration proceedings before the ICC International Court of Arbitration to recover damages from Copel’s default under the Power Purchase Agreement entered into between the two parties. In March 2006, we settleled this claim. At the termination of the contract, the nominal value of the debt, not recognized by Copel, amounted to R$272 million to be recovered against future supplies of gas. As part of the settlement, we will receive from Copel Geração S.A., a subsidiary of Copel, R$150 million in 60 monthly installments beginning January 2010. Copel is a guarantor of this obligation. Under terms of our settlement agreement, we also agreed with Copel’s acquisition of El Paso’s quotas in UEGA. In addition, we will seek to meet the fuel supply needs for operating UEGA on a best efforts basis from 2006 to 2010. This fuel may be in the form of natural gas or some other alternative energy source. This settlement agreement resolves the existing dispute in relation to the contract for the supply of gas to UEGA.
Renewable Energy Alternative
          Our strategy in energy development is based on renewable energy, energy efficiency and the potential gains in carbon credits due to the prevented emissions promoted by these activities.
Renewable Energy
          The main projects relating to renewable energy resources are biodiesel production and electricity generation by wind power plants. Our Strategic Plan establishes 481 thousand cubic meters per year of biodiesel availability and 169MW of electrical generation capacity installed, as a target for 2010.
          Three biodiesel production plants of 44,000 tons per year will each be installed and we are analyzing investments in wind power plants under the terms of Incentive Program of Brazilian Government for Alternative Energy Sources, or Proinfa. In addition, we have initiated a technical-economical feasibility study regarding the implementation of small hydropower plants in the Northeast.
Sustainable Development
          Our actions relating to sustainable energy development in 2005 aimed to evaluate the implementation of eligible projects to obtain carbon credit certificates according to the Clean Development Mechanism (MDL), as well as to propose sales policies regarding these certificates. We have studied the technical viability and necessary baseline methodologies in order to obtain approval for the projects.
Energy Efficiency
          The consolidation of our energy use and the enhancement of energy efficiency in our units were the Internal Energy Conservation Program’s main activities.
          In 2005, there was a relative reduction in the burning of fossil fuels saving approximately 2,700 barrels of equivalent oil per day; a volume that resulted in savings of approximately U.S.$10 million and that prevented emissions of approximately 390 thousand tons of CO2 in 2005.
          In addition, the National Oil and Natural Gas Derivates Rationalization Program, or Conpet, a governmental program coordinated by us, was extended to more than 23% of the vehicles subject to the program, overcoming the mark of 10% established at the beginning of the year. On environmental matters, this performance means that the program prevented the emissions of about 920 thousand tons of CO2 into atmosphere.

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International
Summary and Strategy
          In 2005, approximately 8.0% of our net revenues were generated outside Brazil. We seek to evolve from an integrated oil and gas company in Brazil to an energy industry leader in Latin America and a strong international player.
          Currently, we plan to focus our non-Brazilian exploration, development and production activities regionally, in areas where we can successfully exploit our competitive advantages, such as deepwater drilling. We particularly intend to drill off the west coast of Africa and the Gulf of Mexico and onshore in South America. We recently acquired rights to participate in four exploration blocks offshore Angola. We are also expanding our interests in South America in the downstream segment. During 2006, the following new assets were bought: one lubricant plant, service stations and convenience stores in Colombia; service stations and one LPG re-fueling plant in Paraguay; and service stations, one aviation supply facility, one asphalt commercialization plant, and one natural gas distribution company in Uruguay.
          We have budgeted U.S.$7.1 billion in capital expenditures for the period from 2006 to 2010 for international investments.
          Our main strategies in the international segment are to:
    seek leadership position as an integrated energy company throughout Latin America;
 
    expand exploration and production operations, in the Gulf of Mexico and Western Africa.
 
    accelerate monetization of our natural gas reserves;
 
    expand our international opportunities to grow and diversify our portfolio of international activities;
 
    broaden the recognition and increase the value of the Petrobras brand name outside Brazil; and
 
    add value to the production of Petrobras’ heavy oil.
          Our international results are reflected in the “International” segment in our audited consolidated financial statements.
Exploration and Production
          During 2005 we conducted international exploration activities in Argentina, Bolivia, Colombia, Nigeria, the United States and Venezuela. In addition, we are currently performing studies to evaluate blocks where we hold interests in Angola, Argentina, Colombia, Mexico, Nigeria, the United States, Iran, Equitorial Guinea, Tanzania, Turkey and Libya. Production activities were conducted in Angola, Argentina, Bolivia, Colombia, Ecuador, Mexico, Peru, the United States, and Venezuela. Collectively, these activities represented 14.8% of our total capital expenditures for crude oil and natural gas exploration and production. Our capital expenditures for international exploration and development were U.S.$1,067 million for 2005, U.S.$666 million for 2004 and U.S.$428 million for 2003. The following table provides information about the allocation of such expenditures for each of 2005, 2004 and 2003:

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DISTRIBUTION OF CAPITAL EXPENDITURES IN INTERNATIONAL EXPLORATION ACTIVITIES
                         
    2005     2004     2003  
Argentina
    7.2 %     3.1 %     5.6 %
Bolivia
    4.4       0.2       0.7  
Colombia
    4.6       3.5       4.4  
Peru, Ecuador and Venezuela
    0.3       2.4       28.7  
 
                 
South America
    16.5       9.2       39.4  
West Coast of Africa
    47.8       52.0       15.6  
Gulf of Mexico
    33.9       36.8       42.5  
Others
    1.8       2.0       2.5  
 
                 
Total
    100.0 %     100.0 %     100.0 %
 
                 
Development
          Over the past three years, we have participated in the development of a number of fields internationally. These include: four in Colombia (Guando, Rio Ceibas, Yaguara and Santiago), two in the United States (GB 200 and North Coulomb), one in Angola (Block 2), two in Nigeria (Akpo and Agbami), many fields in Argentina concentrated in the Neuquen and Austral basins (most importantly the Medanito, Puesto Hernandez, Rio Néuquen, Santa Cruz I and Santa Cruz II fields), three in Bolivia (San Alberto, San Antonio, and Colpa Caranda), two in Ecuador (Block 18 and Block 31), one in Peru (Lote X) and four in Venezuela (Ortiupano-Leona, Mata, Acema and La Concepción).
          In 2005, our net production outside of Brazil averaged 162.8 barrels per day of crude oil and NGLs and 95.9 barrels of oil equivalent of natural gas per day at an average lifting cost of U.S.$2.90 per barrel. The following table provides information on the allocation of our international development activities for each of 2005, 2004 and 2003.
ALLOCATION OF CAPITAL EXPENDITURES IN INTERNATIONAL DEVELOPMENT ACTIVITIES
                         
    2005     2004     2003  
Argentina
    36.2 %     41.9 %     62.2 %
Peru
    8.3       10.9        
Ecuador
    16.7       7.4        
Bolivia
    1.7       1.5       7.1  
Colombia
    4.6       6.8       14.3  
Venezuela
    15.9       28.4        
 
                 
 
                       
South America
    83.4       96.9       83.8  
West Coast of Africa
    15.0       1.4       14.7  
Gulf of Mexico
    1.6       1.7       1.5  
 
                 
Total
    100.0 %     100.0 %     100.0 %
 
                 
Argentine Activities
          With the acquisition of 58.6% of PEPSA (formerly Perez Companc), which owned 98.2% of PESA (formerly PECOM Energía S.A.), in 2002, we reinforced our position as an exploration and production leader in South America,. On January 21, 2005, the extraordinary shareholders’ meetings of PESA, EG3 S.A. (EG3), Petrobras Argentina S.A. (PAR), and Petrolera Santa Fe SRL (PSF), approved the merger of EG3, PAR and PSF into PESA, which was the surviving company. Prior to the merger, we held a 99.6% interest in EG3 and a 100% interest in each of PAR and PSF, through our subsidiary Petrobras Participaciones SL, or PPSL. Pursuant to the merger, PPSL received 230,194,137 newly issued class B shares of PESA, representing 22.8% of PESA’s capital stock. As a result of the merger, PEPSA’s ownership interest in PESA declined from 98.21% to 75.8%. Considering our 58.62% participation in PEPSA, we now own a 67.2% total participation in PESA.

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          As of December 31, 2005, our combined crude oil and natural gas proved reserves in Argentina were approximately 793 million barrels of oil equivalent, approximately 51.6% of which were proved developed reserves and approximately 48.4% of which were proved undeveloped reserves.
          PESA’s production in Argentina is concentrated in the Neuquén and Austral Basins. PESA holds 579 thousand net acres under production concessions in the Neuquén Basin and 2,632 thousand net acres under production concessions in the Austral Basin. Our gross production acreage in Argentina amounted to 5,828 thousand acres (3,587 thousand net), and we have a total of 2,943 gross productive wells (1,721 thousand net). For the year ended December 31, 2005, combined crude oil and natural gas production in Argentina averaged 105.1 thousand barrels of oil equivalent per day.
          In the downstream segment we have refining capacity of 68 thousand barrels per day, distributed in two refineries operating with a throughput rate of 88%. We also have a 28.5% interest in Refinaria Del Norte. We also participate in the retail sector in Argentina, where we currently own 746 retail service stations that operate under the brand names Petrobras (451 stations), Eg3 (248 stations) and San Lorenzo (47 stations).
          We also participate, through PESA, in petrochemical businesses, in which we have three plants, Puerto General San Martin, Zarate and Campana in Argentina, where we also have a 40% participation in Petroquímica Cuyo. PESA also owns a petrochemical integrated complex for the production of ethylbenzene, styrene, and polystyrene plant in Brazil, INNOVA, a wholly-owned subsidiary of PESA.
Exchange of assets — PETROBRAS and REPSOL — YPF
          On December 28, 2000, PETROBRAS and Repsol YPF entered into a Contract for the Exchange of Assets, under which PETROBRAS, in exchange of shares of EG3 in Argentina, sold to Repsol YPF a 30% share in Refinaria Alberto Pasqualini, or REFAP, the right to sell fuels in 230 gas stations of BR Distribuidora and a 10% interest in Albacora Leste field.
          The contract established that the parties receiving the shares of EG3 and REFAP should, in the course of eight years after January 1, 2001, review every year the reference values of EG3 Group and REFAP S.A., to adjust them so that at the end of the period the definitive value of the shares of EG3 and REFAP (denominated escalators), as well as definitive assets position and payment thereof to the creditor, under common agreement between the parties. Under the Escalators Liquidation Agreement entered into on December 29, 2005, and effective as of January 1, 2006, the companies performed early and definitive liquidation of the escalators.
          The final value, including monetary restatement, due by Repsol YPF to PETROBRAS, related to EG3 share, for the full period of 8 (eight) years, including the projections for 2006, 2007 and 2008 amounted to U.S.$335 million. Of this amount U.S.$95 million were applied to reduce property, plant and equipments and U.S.$158 million recorded as extraordinary gain, net of U.S.$82 million of income tax.
          The final value, including monetary restatement, due by PETROBRAS to Repsol YPF, related to 30% shareholding in REFAP, for the full period of 8 (eight) years, including the projections for 2006, 2007 and 2008 amounted to U.S.$255 million. This amount was recorded as component of other expenses, net.
          Those amounts are definitive, and not subject to review or verification by any of the parties, thus liquidating application and quantification of escalators, as provided for in the Escalators Liquidation Agreement.
Project MEGA
          We own a 34% participation in the MEGA project (representing a total investment of U.S.$728 million), a joint venture among us, Repsol-YPF and Dow Chemical to fractionate natural gas liquids. The project consists of a natural gas processing plant in Loma La Lata (Province of Neuquén), a 600 km extension pipeline and a separating plant and port, storage and effluent treatment facilities in Bahía Blanca (Province of Buenos Aires). We are obligated under an off-take contract to take minimum volumes of LPG and natural gasoline, if delivered, at market

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prices. We have also recently signed a Reference Value termination Agreement with REPSOL-YPF relating to the valuation of Refineria Alberto Pasqualini (“REFAP”) shares.
          While the MEGA project reached mechanical completion and met or exceeded the performance tests established for the release of the sponsors’ guarantees, the lenders maintained that other conditions required for the release were not met. The sponsors agreed in December of 2003 to extend their guarantees until December 31, 2005 and to permit all lenders the right to put their MEGA notes to the sponsors immediately prior to the guarantees’ expiration. In addition, the sponsors granted MEGA’s fixed rate noteholders the right to exercise their put immediately. In turn, the sponsors were granted call option rights to redeem MEGA notes. On January 15, 2004, all fixed rate noteholders exercised their put option rights. As a result of these events, we purchased our respective share of MEGA’s fixed rate notes (U.S.$58 million). On December 2004, we exercised our call option right (U.S.$54 million) in connection with our share of MEGA’s floating rate notes in the same manner as the other shareholders. Also, in December 2004, MEGA pre-payed all the floating rate notes to the noteholders . The remaining, fixed rate notes issued by MEGA are owned by its shareholders. In December 2004, the shareholders entered into a Waiver Agreement to amend the covenants of the Indenture governing the notes to restrict certain financial operations by MEGA. In March and August 2005, MEGA pre-payed all the fixed rate notes, and thus cancelled them.
Other interests of PESA
          Regarding the Gas and Energy sector, we participate, through PESA, as indirect shareholder in TGS, which owns a 7,450 km extension pipeline with current firm contracted transport capacity of 71.4 MMcmd and a gas processing plant located in Bahía Blanca, with a processing capacity of 43 million MMcmd.
          As far as the electricity assets in Argentina, also through PESA, we cover the entire productive chain. We account for 6.5% of the country’s electricity generation through ownership interests in two generation plants, Pichi Picún Leufú (hydrelectric generation) and Genelba (gas-fired power generation). We also have an indirect interest in Transener, Argentina’s largest transmission company and owner of 95% of Argentina’s high-tension network. PESA has a commitment to divest such interest, as provided under the Resolution issued by Comisión Nacional de Defensa de la Competencia (the Argentine antitrust authority), approving the transfer of control of PEPSA to us. PESA also maintains an important presence in the central area of Buenos Aires, an area with more than 2.1 million customers, through Edesur, Argentina’s largest energy distribution company by volume.
          During 2005, PESA prepaid the total outstanding principal amount of certain Class K and M notes under its Global Notes Program in a total amount of U.S.$335 million. In connection with these series of notes, PESA was subject to compliance with certain covenants, including restrictions on payments of dividends and capital expenditures. As a result of the prepayment, its obligations under these covenants are no longer in effect. PESA also prepaid the outstanding amount of Class C medium term notes for U.S.$63 million.
Bolivian Activities
          As of December 31, 2005, our combined crude oil and natural gas proved reserves in Bolivia were approximately 321.1 million barrels of oil equivalent, all of which were proved developed reserves. Approximately 90% of our proved developed reserves in Bolivia are natural gas reserves. We drilled one exploration well in Bolivia in 2005, but we found that it was not commercially feasible. For the year ended December 31, 2005, our combined crude oil and natural gas production in Bolivia averaged 54 thousand barrels of oil equivalent per day.
          On May 1, 2006, the new Bolivian government, by decree, nationalized the oil and gas companies operating in Bolivia, subject to a 180-day transition period. This decree established that the state-owned YPFB will become a partner in every asset belonging to the oil and gas sector. We have a 35% interest in the San Alberto and San Antonio Fields (the other partners are Empresa Petrolera Andina (50%) and Total Bolivia (15%)) and in the assets listed below. During this transition period, we expect that we will be involved in complex negotiations with YPFB and the Bolivian government regarding the enforcement of the decree. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations¾ The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition.”

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          The following assets will also be subject to the abovementioned decree:
  (i)   Our 44.5% of the shares of Transierra S.A, the owner and operator of the Yacuiba-Rio Grande gas pipeline (GASYRG), a pipeline in Bolivia that connects the gas fields in the south of Bolivia to the Bolivia-Brazil pipeline. Presently the pipeline has a capacity of 17 MMcmd, and installation of another compression unit will increase the capacity to 23 MMcmd. Investment for this project totaled more than U.S.$375 million. We also provided all the capital for the San Marcos pipeline, which presently transports less than 0.1 MMcmd of natural gas to the city of Puerto Suárez (Bolivia), on the Brazilian border.
 
  (ii)   Our 21% interest in a natural gas compression plant in Rio Grande, Bolivia, which has a capacity to compress up to 34.0 MM cmd.
 
  (iii)   Our 51% interest in Petrobras Bolivia Refinación—PBR, ex-Empresa Boliviana de Refino (EBR), with Petrobras Energia S.A. – PESA as the other partner, with 49% of the equity. PBR owns two Bolivian refineries located in Cochabamba and Santa Cruz de la Sierra, with production capacity of 60 thousand barrels of crude oil per day, operating with a throughput rate of 67%. PBR wholly owns Petrobras Bolivia Distribución—PBD, ex-Empresa Boliviana de Distribución, or EBD, a company with a network of 104 service stations.
Venezuelan Activities
          As of December 31, 2005, PESA’s rights in Venezuela for exploration and production were held under operating service contracts. In April 2006, PESA, Petróleos de Venezuela S.A. (PDVSA) and Corporación Venezolana del Petróleo SA (CVP) entered into a Memorandum of Understanding in order to effect migration of the operating agreements to partially state-owned companies, which will have the effect of nationalizing the oil and gas reserves in Venezuela. The economic effects of the migration came into force starting April 1, 2006. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations¾ The recent nationalization measures taken by the Bolivian and Venezuelan governments may have an adverse effect on our results of operations and financial condition” for a description of the risks associated with these measures.
          As of December 31, 2005, estimated proved oil and gas reserves attributable to PESA’s operations in Venezuela amount to 269 million barrels of oil equivalent, accounting for 35.4% of PESA’s total reserves. Estimated proved oil and gas reserves attributable to the company’s operations in Venezuela are calculated on the basis of the contractual structure in force as of such date.
          Operating Services Agreement
          In 1994, during what is referred to as the second round bids, PESA was awarded the first service contract by PDVSA at the Oritupano-Leona field to provide production services for a 20-year period. (We refer to the contracts awarded pursuant to the second round bids as the second round operating agreements.) Oritupano-Leona is an approximately 215,000 net acre block located in the Oriental basin that includes 272 producing wells.
          The Oritupano Leona joint venture’s sole customer for the sale of oil production was PDVSA. Per our operating service agreement, PDVSA was the sole owner of the facilities, assets and/or operating equipment used by the joint venture to conduct the activities provided for in this agreement. For the provision of production services, we received (1) a variable fee based on production volumes plus (2) an additional fee for reimbursement of capital expenditures. The contract had a cap on the amount, which we can collect, which was reset quarterly based on the market price of oil. As of December 2005, this cap was approximately U.S.$37.9 per barrel. The contract also established an incentive, which was not subject to the cap, for any production over 155 million barrels of oil, calculated using a rate per barrel that is based on variations of certain crude oil prices. During the first quarter of 2005, cumulative field production exceeded the 155 million barrel production level and, since then, any additional production had been subject to the incentive. This additional compensation was subsequently limited by the application of the 66.67% limit on sales price imposed by the Venezuelan government under the provisional agreements relating to migration to the partially state-owned companies.

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          In 1997, during what is referred to as the third round bids, PDVSA awarded PESA three 20-year service contracts for the exploration and production of Acema, La Concepción and Mata blocks. (We refer to the contracts awarded pursuant to the third round bids as the third round operating agreements and the three blocks awarded to us during those bids, namely the Acema, La Concepción and Mata blocks, as the third-round blocks.) The bids were initially made through joint ventures. PESA had a 90% interest in the La Concepción block and an 86.2% interest in the Acema and Mata oil blocks. La Concepción is an approximately 55,000 net acre block located in the Maracaibo basin with 116 producing wells. Acema and Mata, located in the Oriental basin, are approximately 64,000 and 45,000 net acre blocks with 18 and 57 producing wells, respectively. According to the concession contracts, PDVSA was the sole owner of the facilities, assets, and operating equipment. PESA received a fee for each barrel delivered which has a fixed component related to contractual baseline production and a variable component related to the incremental production that covered investments and production costs, plus a gross profit up to a maximum that is tied to a basket of international oil prices.
          Nationalization measures by the Venezuelan government
          In April 2005, the Venezuelan Energy and Oil Ministry instructed PDVSA to review the thirty-two operating agreements signed by PDVSA with oil companies from 1992 through 1997, including agreements with our affiliates in connection with the areas of Oritupano Leona, La Concepción, Acema and Mata. According to the Venezuelan Energy and Oil Ministry, each of these operating agreements includes clauses that do not comply with the Venezuelan Hydrocarbon Law enacted in 2001.
          The Venezuelan government has instructed PDVSA to take measures in order to convert all effective operating agreements into state-controlled contracts in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field. Regarding such agreements, the government instructed PDVSA that the total amount of accumulated payments to contractors during the calendar year 2005 would not exceed 66.67% of the value of oil and gas produced under the related agreement.
          During 2005, PDVSA took several actions in connection with the operating agreements as a way to promote the nationalization, including, among others:
  (a)   PDVSA approved a reduced amount of development investments for the Oritupano Leona area;
 
  (b)   Difficulties for the reception by PDVSA of the oil produced were verified;
 
  (c)   Partial payment in bolivares of the billings. In this regard, in June 2005, PDVSA notified Petrobras Energía Venezuela, S.A. that it would thereafter pay in bolivares the portion of the compensation provided in the operation contracts currently in effect related to the domestic component of the materials and services provided. Such decision conflicts with the provisions of the operation contracts mentioned above, under which PDVSA is required to make such payments in U.S. dollars. During the transition phase, and until PDVSA performed an audit to determine the portion attributable to the domestic component, PDVSA decided that it would pay 50% of the amounts set forth in such contracts in U.S. dollars and the remaining 50% in bolivares. Subsequently and based on the collections related to 2005 third quarter production, the portion of the payment in bolivars was reduced to 25%;
 
  (d)   The SENIAT (National Integrated Tax Administration Service) performed several tax inspections on the companies that operate the 32 oil operating contracts, and as a result of these inspections, challenged prior tax filings. In this regard, as of December 31, 2005, we recorded a U.S.$ 18 million loss; and
 
  (e)   an increase in income tax rate from 34% to 50%.
     On September 29, 2005, Petrobras Energía Venezuela S.A. signed provisional agreements with PDVSA, whereby it agreed to negotiate the terms and conditions related to the conversion of the agreements in the areas of Oritupano Leona, La Concepción, Acema and Mata, and also acknowledged the application of the 66.67% cap over the value paid to contractors. The provisional agreement for the Oritupano Leona area was signed subject to the approval of PESA’s General Shareholders’ Meeting and of the shareholders of PEPSA, which were favorable to the agreements.

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          In April 2006, PESA entered into Memorandums of Understanding (MOUs) in order to effect migration of the operating agreements of the Oritupano Leona, La Concepción, Acema and Mata areas to partially state-owned companies. Pursuant to the abovementioned MOUs, interest of private investors in the partially state-owned companies will be limited to 40%, with the Venezuelan Government holding a 60% interest. PESA’s indirect interest in the Oritupano Leona, La Concepción, Acema and Mata areas will be 22%, 36%, 34.5% and 34.5%, respectively. Before these MOUs, PESA’s indirect interest in the Oritupano Leona, La Concepción, Acema and Mata areas were 55%, 90%, 86.2% and 86.2%, respectively. The economic effects of the migration became effective on April 1, 2006.
          The MOUs establish that CVP will recognize a divisible and transferable credit in favor of the private companies that will compose the partially state-owned companies. PESA was awarded a credit in the amount of U.S.$ 88.5 million. This credit will not bear interest and may only be used for future investments in oil and gas exploration, development or production activities in Venezuela.
          Execution of the MOUs is subject to approval of the relevant authorities, including the National Assembly, as specified below, and PESA’s Board of Directors.
          The organization of the partially state-owned companies and the terms and conditions governing the performance of primary activities thereby are also subject to approval of the Venezuelan Ministry of Energy and Oil and the Venezuelan National Assembly.
          As of December 31, 2005, we recorded an impairment charge of U.S.$134 million in order to adjust the book value of our Venezuelan assets to their recoverable value.
Ecuadorian Activities
          In Ecuador, PESA operates Blocks 18 and 31. As of December 31, 2005, PESA held a 70% and 100% interest in Block 18 and 31, respectively.
          Block 18 is located in the Oriente basin of Ecuador, having a significant potential of 28º to 33° API light crude oil reserves. The concession for production activities in Block 18 is for an initial 20-year term from October 2002. Once this term expires, Ecuadorian hydrocarbon laws provides for the possibility of an additional five-year extension period.
          Block 18 production accounted for 5% of PESA’s total average production in barrels of oil equivalent in 2005. It has eight productive wells, two are located at the Pata field and six are located at the Palo Azul field. In addition, the area has early production facilities that can handle a daily gross production of 20,000 barrels per day. In 2005, PESA drilled 11 development wells and 3 workovers were completed with very good results; the 12-inch, 15.6 km-long export pipeline was built; and the expansion of the temporary processing plant was completed. Development of Block 18 will continue through drilling and construction of facilities to increase treatment capacity.
          Block 31 is located in a highly sensitive ecological area of the Amazon jungle in the central part of the eastern border of the upper Amazon basin and covers an area of 494 thousand net acres. Pursuant to the block’s production sharing agreement between Petroecuador and PESA, Petroecuador is entitled to a crude oil production share ranging between 15% and 17%, depending on the field’s daily crude oil production and crude oil gravity.
          PESA has conducted extensive exploratory work in Block 31, including the drilling of four exploratory wells, which led to the discovery of the Apaika/Nenke, Obe, and Minta fields. Significant investments are required to the development, but changes in PESA’s investment strategy following the Argentine crisis have resulted in a redefinition of the amounts and timing of the original investment plan.
          In August 2004, the Minister of Energy of Ecuador approved an environmental impact study, completing all of the required steps for the approval of the development plan with a 20-year exploitation period. In the initial three-year period, the plan contemplates investments of U.S.$75 million, and an obligation to provide Petroecuador with a guaranty of 20% of this amount. In December 2005, as part of these contemplated investments, PESA built a pier on the southern border of the Napo River and a 12.7 km access road. Due to limitations imposed by the Ministry

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of the Environment in Ecuador (MAE) relating to works within Parque Nacional Yasuní, works were temporarily suspended. Petrobras Energía Ecuador, MAE and the Ministry of Energy and Mines of Ecuador are working to agree on a new development plan for Block 31. Based on the proposal submitted by the Company, the new development project associated with the Apaika and Nenke fields will minimize impact on Parque Nacional Yasuní. PESA will use cutting-edge technology in connection with oil production and environmental protection, this certainly being an example of integration between oil production activities and nature.
          As regards exploitation of Blocks 18 and 31, the Company signed an agreement with OCP (Oleoducto de Crudos Pesados), whereby an oil transportation capacity of 80,000 bbl/d is secured for a 15-year term, starting November 10, 2003. Under the “Ship or Pay” transportation agreement, the Company must fulfill its Ship or Pay contractual obligations for the aggregate oil volume committed, even though no crude oil is transported, and pay, together with other participants, a fee covering OCP operating costs and financial services. As of December 31, 2005, such fee amounted to U.S.$2.26 per barrel.
          Additionally, Petrobras Energía S.A., or PESA, has a 15-year ship or pay agreement for 80,000 barrels per day through the OCP pipeline in Ecuador. Estimated payments respective to the commitment are approximately U.S.$300 million for the next five year term, and U.S.$820 million total contract value. In January 2005, PESA entered into a provisional sale agreement with Teikoku Oil Co., based in Japan, subject to final approval by the Ministry of Energy of Ecuador. Upon approval, PESA will transfer 40% of its rights and interest in Blocks 18 and 31 and the corresponding rights and obligations, including in the OCP, to Teikoku Oil Co. See “—International—Ecuadorian Activities.”
          In January 2005, PESA entered into an agreement with Teikoku whereby, after obtaining approval by the Ministry of Energy of Ecuador, we will transfer 40% of our rights and interest in Blocks 18 and 31. In addition, once production in Block 31 reaches an average of 10,000 barrels of oil per day for a period of 30 consecutive days, Teikoku has agreed to assume 40% of the rights and obligations resulting from the crude oil transportation agreement entered into with OCP.
          As of December 31, 2005, PESA’s crude oil proved reserves in Ecuador were approximately 51.3 million of barrels of oil and its oil production averaged 9.1 thousand barrels per day.
Peruvian Activities
          Through PESA, we have the rights to oil and gas production in Lote X, a 116 thousand acre block in Peru’s Talara Basin. PESA has entered into a long-term sales contract under which Perupetro (the Peruvian state-owned company) is obligated to purchase all of the production from Lote X at market prices. The sales contract will expire in July 2006. As of December 31, 2005, PESA’s combined crude oil and natural gas proved reserves in Peru were approximately 109 million of barrels of oil equivalent and its combined oil and gas production averaged 14.4 thousand barrels per day.
          In May 2004, PESA entered into a contract with Repsol Exploración Perú S.A. to perform certain exploration activities jointly in Block 57, which is located in the Ucayali basin. Pursuant to this contract, PESA participate in Block 57 with a 35.15% interest. The assignment is subject to approval by the governmental authorities and the Company is negotiating the joint operation agreement with Occidental and the other partner, Repsol.
          As of November 2004, PESA entered into an agreement with Occidental for the assignment to Petrobras Energía de Perú S.A. of 30% of the rights in the License Agreement for Hydrocarbon Exploration and Production in Lote 103. The assignment is subject to approval by the governmental authorities and the Company is negotiating the joint operation agreement with Occidental and the other partner, Repsol.
          In 2005, PESA entered into license agreements for hydrocarbon exploration and production in Lote 58 and Lote 110 at the Ucayali Basin (adjacent to Camisea) and in Lote 112 at the Marañón Basin. Perupetro has recently awarded Petrobras Energía del Perú S.A Lote 117 located at the Marañón Basin.

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Uruguayan Activities
          In December 2004, we entered the Uruguayan market through the acquisition of 55% of the voting shares of Conecta S/A, which is one of the two local natural gas distribution companies operating in Uruguay, for U.S.$3.2 million. The other 45% of the Conecta’s voting shares remains with the state-owned Administratión Nacional de Combustibles Alcohol y Portland — ANCAP.
          Conecta operates approximately 317 km of gas pipelines, and has exclusivity to supply small to medium size consumers with demand of up to 5,000 cmpd. Conecta presently has 4400 clients, mostly with residential buildings, selling approximately 39,300 cmpd. We estimate that this represents about 20% of the total Uruguayan demand for natural gas, which is located near the gas pipelines in the cities of Paysandu and Ciudad de la Costa. Conecta’s revenues in 2005 were U.S.$ 3.1 million.
          In November of 2005, in line with our Strategic Plan, our board of directors approved the acquisition of 51% of the capital of Gaseba Uruguay—Grupo Gaz de France S.A. (“Gaseba Uruguay S.A.”), a natural gas distribution concession in Montevideo, Uruguay. This concession runs for a term of 30 years and aims to enhance our natural gas business in Uruguay.
          At the end of 2005, we signed a Share Purchase Agreement for the acquisition of Shell’s fuel and lubricant retail and commercial businesses in Uruguay. We now control 89 services stations, and installations for aviation fuel and asphalt, salling and a marine fuels business.
Paraguayan Activities
          At the end of 2005, Petrobras signed a Share Purchase Agreement for acquisition of Shell’s fuel and lubricant retail and commercial businesses in Paraguay. The Company now controls 134 services stations, with 52 convenience stores installations for aviation fuel supply and one LPG refueling plant.
Colombian Activities
          During 2005, we signed a farm-in contract in Colombia with Hocol, which allowed us to acquire interests in the Upar, San Jacinto, Rio Paez, Achira and Rio Cabrera Blocks.
          We have interests in eighteen exploration contracts and six production contracts in Colombia. We are the operating company in twelve of these contracts.
          As of December 31, 2005, our combined crude oil and natural gas proved reserves in Colombia were approximately 32 million of barrels of oil equivalent and our combined oil and gas production averaged 16.6 thousand barrels per day.
          At the end of 2005, we signed a Share Purchase Agreement for acquisition of Shell’s fuel, retail and commercial businesses, in Colombia, Paraguay and Uruguay for approximately US$140 million. We now control 139 services stations, with 17 convenience stores and installations for commercialization of aviation fuel and asphalt.
          We carried out seismic studies in Block Tayrona, a 45,000km2 offshore block in the Caribbean Sea of Colombia, in association with Exxon and Ecopetrol. We are the operator of the concession during the exploration phase.

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African Activities
          We have interests in four blocks in Nigeria, OPL-216, OPL-246, OPL-324 and OPL-315. We are partners in Agbami Field, on OPL-216, operated by Chevron, presently on development phase, where first oil will occur in mid 2008, from a FPSO with a production capacity of 250,000 bopd. In 2005, we have drilled 6 development wells in Agbami field. We have participation also in Akpo field, on OPL-246, operated by Total, with production scheduled to commence in the end of 2008, also by the means of a FPSO (175,000 bopd), now under construction. Two other discoveries are under appraisal on Block OPL-246: Egina and Preowey fields, where we drilled one successful extension well each, in 2005. Agbami and Akpo are both considered as World Class oil fields and our share in their production shall correspond to an aggregate of 67,000 bopd at their peak.
          We withdrew from the exploration block OPL-250 and we are the operating company in two other exploration blocks, OPL-324 and OPL-315 where drilling activity will occur in 2006 and 2007. Participation in Block OPL-315 was acquired in the last Nigerian Bid Round, held in August 2005.
          On March 12, 2005, we signed an exploration and joint production agreement with Libya’s state-owned National Oil Corporation (NOC). This agreement provides for the exploration of four blocks in Area 18, which have an extension of 10,307 square kilometers and are located in the Mediterranean Sea at water depths of 200 to 700 meters. We own a 70% interest in a consortium with Oil Search Limited (OSL) and will be the operating company in the area. Under the agreement, the exploration phase will last five years and may be extended for 25 more years if discoveries are made. At least U.S.$21 million will be invested in the exploration phase and we will be required to drill a well and conduct seismic evaluations.
          The Angolan branch of our wholly-owned subsidiary, Petrobras International Braspetro B.V., has continued to perform as a non-operating partner in two licenses under petroleum sharing agreements. No exploratory drilling was carried out in Angola during 2005. As of December 31, 2005, our combined crude oil and natural gas proved reserves in Angola were approximately 8.59 million of barrels of oil equivalent and our oil production averaged 6.73 thousand barrels per day in this month. For the year 2005, oil production averaged 8.3 thousand barrels per day.
          We recently participated in three bidding rounds promoted by Angolan government in 2006 and acquired interests in 4 exploration blocks offshore Angola: deep water Blocks 15/06, 18/06 and 26, being the operator in the latter two, and shallow water Block 6, also holding the operatorship. Drilling activity in such blocks shall begin not earlier than 2008. Block 18/06 is the remaining area of Block 18, operated by BP. Likewise Block 18/06 which is the remaining area of Block 15/06, operated by Exxon.
          In 2004, we signed a joint production agreement with the Tanzanian government and the state-owned oil company, Tanzania Petroleum Development Corporation (TPDC). This agreement provides for the exploration of Block 5, which has an extension of 9,250 square kilometers and is located in the Mafia Basin at water depths of 300 to 3000 meters. The agreement will be in force for up to 11 years. In 2005, we conducted geological studies on Block 5. Petrobras was awarded a new exploration asset in 2005, the Block 6, with an extension of 9,250 square kilometers, adjacent to Block 5, whose production sharing agreement are under negotiations at the time of this writing.
Middle East Activities
          We have signed a contract with Iran’s state-owned company, National Iranian Oil Company (NIOC), for the exploration of Block Tusan in shallow waters of the Persian Gulf. We own a 100% interest in this block. The exploration will be carried out by our Iranian subsidiary Petrobras Middle East B.V., which was organized in October 2004. During 2005, we evaluated other exploration opportunities in the Middle East.
Turkey Activities
          We were the winner of two of the three blocks offered in the bidding process for deepwater exploration and production in the Black Sea held by the Turkish Türkýye Petrollerý Anoným Ortaklidi – (TPAO) National Oil Company.

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          We and TPAO will soon begin negotiating all the pertinent contractual documentation, ensuring us 50% participation in the exploration and production of Blocks 3920 (Kirklarelli) and 3922 (Sinop).
          According to our completed technical evaluation, the two blocks that we purchased are the ones that present the best geological possibilities. The Kirklarelli Block, located in the western part of the Turkish sector of the Black Sea, has an average depth of 1,200 meters, and the Sinop Block is on the eastern side of the Black Sea, and has an average depth of 2,200 meters.
Gulf of Mexico Activities
          Petrobras America, Inc., or PAI, our wholly-owned subsidiary, continues to expand its activities in the Gulf of Mexico’s deep and ultra-deep waters through “farm-in” agreements (by which PAI, rather than obtaining an interest directly from the relevant government authorities, acquires an interest from a party who has already obtained such interest), and participation in leases and sales conducted by the United States Minerals Management Service (the U.S. industry regulator). As of December 31, 2005, PAI held interests in 271 offshore blocks in the Gulf of Mexico from shallow to ultra-deep waters, 180 of which were operated by our subsidiary. On March 21, 2006, we announced that we tendered the highest bids for 10 out of 17 blocks in the central U.S. sector of the Gulf of Mexico at an auction organized by the MMS.
          As a result of its participation in Gulf of Mexico Lease Sale 196, Petrobras was awarded a total of 53 exploration blocks: 18 blocks strengthened its position in ultra-deep oil prospects while 26 blocks granted a strong coverage on the westernmost part of the Gulf, where we now hold full control over 10 prospects with good potential for gas. The first drilling will begin later in 2006.
          The average production in the Gulf of Mexico reached only 4,600 bopd, approximately 60% of the target, mainly due to the effects of Hurricanes Rita and Katrina.
          In September 2005, PAI announced that its first Gulf of Mexico well confirmed the extension of the Cottonwood Discovery, located in the Garden Banks 244 Block. Having now confirmed the extension of the gas field, the company has begun a fast-track development of the gas reservoirs, aiming at starting production by early 2007. Petrobras has an 80% participating interest and is the operator of the block. The area of Garden Banks is one of the four core areas selected by Petrobras as a priority for exploration in the U.S. waters of the Gulf of Mexico, which also include the ultra deepwater, the very deep reservoirs of the shallow water shelf and the westernmost area of Gulf of Mexico. According to the Business Plan we recently announced, the total investments allocated to the Gulf of Mexico in the period 2006-2010 will reach $1.5 billion.
          In November 2005, we signed a Memorandum of Understanding with Astra Oil Company (“Astra”), combining forces to establish a joint venture trading and refining company in the United States. On February 3, 2006, the PETROBRAS Board of Directors approved a purchase and sale agreement with Astra Oil Trading NV for the acquisition of 50% interest of the refinery Pasadena Refining System Inc. (PRSI), formerly Crown Refinery in Pasadena, Texas, for approximately U.S.$370 million.The initial business plan calls for joint venture operation with respect to the trading and commercial management of the Pasadena Refining System (PRSI), formerly the Crown Refinery in Pasadena Texas. The PRSI refinery is currently being upgraded to meet new Environment Protection Agency (EPA) Clean Air Standards for gasoline and diesel, and as soon as reasonably practical, the refinery will also be modified to handle a wide range of heavy crude and feedstock, including our production from the Marlim field.
          Mexican Activities
          In 2003, as part of the bidding launched by Petróleos Mexicanos (PEMEX) for the operation of areas under multiple service contracts, contracts for the Cuervito and Fronterizo blocks were awarded to a joint venture composed of us (45% interest), the Japanese company Teikoku (40%) and the Mexican company Diavaz (15%). There are 12 gas discoveries in this block, which shall be developed with a total expenditure of U.S.$510 million.

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PIFCo
          PIFCo was established on September 24, 1997 as a wholly-owned subsidiary of Braspetro Oil Services Company, or Brasoil, a wholly-owned subsidiary of Petrobras Internacional S.A. (Braspetro), which has since been absorbed by us. PIFCo was initially incorporated under the name Brasoil Finance Company, which was changed by special resolution of PIFCo’s shareholders to Petrobras International Finance Company on September 25, 1997. On January 14, 2000, the board of directors of Braspetro and Petrobras approved the transfer of 100% of PIFCo’s voting shares from Brasoil to us. Since April 1, 2000, PIFCo has been our wholly-owned subsidiary. On October 21, 2005, we replaced the existing Memorandum and Articles of Association in its entirety, with a new amended and restated Memorandum and Articles of Association.
          PIFCo is a tax exempt company incorporated with limited liability under the laws of the Cayman Islands. PIFCo’s registered office is located at Harbour Place, 103 South Church Street, 4th floor, George Town, Grand Cayman, Cayman Islands, and PIFCo’s telephone number is 55-21-3224-1410.
PIFCo Business Overview
          PIFCo was incorporated in order to facilitate and finance the import of crude oil and oil products by us into Brazil. Accordingly, PIFCo’s primary function is to act as an intermediary between third-party oil suppliers and us by engaging in crude oil and oil product purchases from international suppliers and reselling crude oil and oil products in U.S. dollars to us on a deferred payment basis, at a price which includes a premium to compensate PIFCo for its financing costs. PIFCo is generally able to obtain credit to finance purchases on the same terms granted to us, and PIFCo buys crude oil and oil products at the same price that suppliers would charge us directly.
          As part of our strategy to expand our international operations and facilitate our access to international capital markets, PIFCo engages in borrowings in international capital markets supported by us, primarily through standby purchase agreements of the related securities.
          In addition, PIFCo also engages in a number of activities that are conducted by three wholly-owned subsidiaries:
    Petrobras Europe Limited, or PEL, a United Kingdom company that acts as an agent and advisor in connection with our trading activities in Europe, the Middle East, the Far East and North Africa;
 
    Petrobras Finance Limited, or PFL, a Cayman Islands company, that carries out a financing program supported by future sales of bunker fuel and fuel oil; and
 
    Bear Insurance Company Limited, or BEAR, a company incorporated in Bermuda that contracts insurance for us and our subsidiaries.
          As part of our restructuring of our international business segment, in January 2003, PIFCo transferred to us Petrobras Netherlands B.V., or PNBV, a Dutch company engaged in leasing activities of primarily offshore equipment to be used by us for exploration and production of crude oil and natural gas. PNBV became our wholly-owned subsidiary, effective as of January 2003.
          Beginning in 2004, as part of our restructuring of our offshore subsidiaries in order to centralize trading operations, PIFCo has engaged in limited exports of oil and oil products and has begun to store oil and oil products in Asia.
          In April 2006, PIFCo incorporated a new wholly-owned subsidiary: Petrobras Singapore Private Limited, or PSPL, a company incorporated in Singapore to trade crude oil and oil products in connection with our trading activities in Asia. This company has not yet initiated operations.

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PIFCo’s Principal Commercial Activities
          PIFCo’s principal activity is the purchase of crude oil and oil products for resale to us and, to a limited extent, third parties. PIFCo acquires substantially all of its crude oil and oil products either through purchases on the spot market or short-term supply contracts. PIFCo acquires a small portion of its crude oil and oil products through long-term supply contracts. PIFCo’s crude oil and oil product purchase obligations are, in most instances, guaranteed by us. PIFCo sells the products to us at the purchase price it paid, plus a premium, determined in accordance with a formula designed to pass on PIFCo’s average costs of capital to us.
          In addition, PIFCo finances its oil trading activities principally from commercial banks, including lines of credit and commercial paper programs, as well as through inter-company loans from us and the issuance of notes in the international capital markets.
          The following chart illustrates how PIFCo acts as the intermediary between international crude oil suppliers and us.
(FLOW CHART)
          PIFCo purchases crude oil and oil products from international oil suppliers on a free-on-board (F.O.B.) basis under standard terms that traditionally require payment within 30 days from the bill of lading. We buy crude oil and oil products from PIFCo under terms that allow for payment up to 330 days from the date of the bill of lading. Since February 2005, we began to buy crude oil and oil products from PIFCo under terms that allow for payment up to 330 days from the date of the bill of lading. Before February 2005, we bought crude oil and oil products from PIFCo under terms that allowed for payment up to 270 days from the date of the bill of lading. We would typically be unable to meet the 30-day payment term imposed by international suppliers because of the complexity of Brazilian customs and importing regulations. For example, if a shipment to which a bill of lading relates must be delivered to different parts of Brazil, different sets of documents must be delivered to each delivery point. Depending on the unloading ports’ locations, this process may be completed up to 120 days from the vessel’s departure. Because PIFCo is not subject to the Brazilian regulations applicable to us, PIFCo can pay the international supplier on time without having to produce these different sets of documents. To cover its financing costs, PIFCo includes a premium when it sells crude oil and oil products to us.
PIFCo’s subsidiaries are:
Petrobras Europe Limited (PEL)
          In May 2001, PIFCo established PEL, a wholly-owned subsidiary incorporated and based in the United Kingdom, to consolidate our trade activities in Europe, the Middle East, the Far East and North Africa. These activities consist of advising on, and negotiating the terms and conditions for, crude oil and oil products supplied to PIFCo and us, as well as marketing Brazilian crude oil and crude oil products exported to the geographic areas in which PEL operates. PEL plays an advisory role in connection with these activities and undertakes no direct or additional commercial or financial risk. PEL provides these advisory and marketing services as an independent

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contractor, pursuant to a services agreement between PEL and us. In exchange, we compensate PEL for all costs incurred in connection with these activities, plus a margin.
Petrobras Finance Limited (PFL)
          In December 2001, PIFCo established PFL, a wholly-owned subsidiary incorporated and registered in the Cayman Islands. PFL primarily purchases fuel oil from us and sells the products in the international market in order to generate export receivables to cover its obligations to transfer these receivables to a trust under an exports prepayment program. Until June 1, 2006, PFL also purchased bunker fuel from us. The exports prepayment program helps provide PFL with the funding necessary to purchase oil products from us, as described below.
Bear Insurance Company Limited (BEAR)
          In January 2003, PIFCo received BEAR from Brasoil. This transaction took place as part of the restructuring of our international business segment. BEAR currently serves as an intermediary for us, advising on, and negotiating the terms and conditions of, certain of our insurance policies.
Petrobras Singapore Private Limited (PSPL)
          In April 2006, PIFCo incorporated a new wholly-owned subsidiary: Petrobras Singapore Private Limited, or PSPL, a company incorporated in Singapore to trade crude oil and oil products in connection with our trading activities in Asia. This company has not yet initiated operations.
Exports Prepayment Program
          We sell and deliver fuel oil and, subject to certain conditions, other oil products (collectively, the “Eligible Products”) to PFL under two principal agreements: Master Export Contract and the Prepayment Agreement. Until June 1, 2006, bunker fuel was also an Eligible Product under the Agreement. The PF Export Receivables Master Trust, or the Trust, was formed under the laws of the Cayman Islands to provide PFL with the funding necessary to purchase Eligible Products from Petrobras and resell these products through the arrangements described below.
          On December 21, 2001, the Trust issued to PFL U.S.$750 million of Senior Trust Certificates (collectively, the “Series 2001 Senior Trust Certificates”) and U.S.$150 million of Junior Trust Certificates (the “Series 2001 Junior Trust Certificates,” that together are called the “Series 2001 Trust Certificates”). PFL in turn offered the Series 2001 Senior Trust Certificates in four series (series A-1, A-2, B and C) to certain certificate holders.
          On May 21, 2003, the Trust issued to PFL U.S.$550 million of Senior Trust Certificates (the “Series 2003-A Senior Trust Certificates”), maturing on June 1, 2015. On the same date, the Trust issued U.S.$200 million of Senior Trust Certificates (the “Series 2003-B Senior Trust Certificates”), maturing on June 1, 2013. The Series 2003-A Senior Trust Certificates, along with the Series 2003-B Senior Trust Certificates and the Series 2001 Senior Trust Certificates, represent senior undivided beneficial interests in the property of the Trust (other than certain charitable property held by the Trust).
          On the same date, the Trust also issued to PFL U.S.$110 million in Series 2003-A Junior Trust Certificates and U.S.$40 million in Series 2003-B Junior Trust Certificates (collectively, the “Series 2003 Junior Trust Certificates. The Series 2003 Junior Trust Certificates represent, together with the 2001 Junior Trust Certificates, junior subordinated undivided beneficial interests in the property of the Trust (other than the charitable property).
          The series 2003-A Senior Trust Certificates, the 2003-B Senior Trust Certificates and the 2003-A Junior Trust Certificates, the 2003-B Junior Trust Certificates are referred to collectively as series 2003 Trust Certificates.
          PFL agreed to transfer to the Trustee, in return for the Series 2001 Senior Trust Certificates and Series 2001 Junior Trust Certificates, the right to a specified amount of receivables to be generated from PFL’s sale of Eligible Products with a value equal to the aggregate amount scheduled to be paid in respect of the Series 2001 Senior Trust Certificates and the Series 2001 Junior Trust Certificates. PFL also agreed to transfer the Trustee, in return for the

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Series 2003 Senior Trust Certificates and Series 2003 Junior Trust Certificates, the right to an additional specified amount of receivables to be generated from PFL’s sale of Eligible Products with a value equal to the aggregate amount scheduled to be paid in respect of the Series 2003 Senior Trust Certificates and the Series 2003 Junior Trust Certificates.
          The value of receivables scheduled to be designated for sale in any quarterly period represents a portion, but not all, of the receivables expected to be generated from the sale of Eligible Products by PFL in such period. The remainder of such receivables remain the property of PFL.
          The timely payment of interest on, and scheduled principal of, each series of the Series 2001 Senior Trust Certificates is unconditionally and irrevocably guaranteed under financial guaranty insurance policies issued by XL Capital Assurance Inc., MBIA Insurance Corporation or Ambac Assurance Corporation (collectively, the “Enhancers”). The timely payment of interest on, and scheduled principal of, the Series 2003-B Senior Trust Certificates is unconditionally and irrevocably guaranteed under a financial guaranty insurance policy issued by MBIA Insurance Corporation. The Series 2003-A Senior Trust Certificates do not have the benefit of any financial guaranty insurance policy.
          In addition to the Series 2001 Trust Certificates and the Series 2003 Senior Trust Certificates currently outstanding, additional series of senior trust certificates (which may or may not benefit from a financial guaranty insurance policy) may be issued to PFL from time to time if Petrobras agrees to sell additional Eligible Products to PFL in an amount that is adequate to make all required payments under the additional series of senior trust certificates and certain other conditions are met.
          In May 2004, PFL and the PF Export Trust executed an amendment to the Trust Agreement allowing the Junior Trust Certificates, which amounted to U.S.$300 million as of December 31, 2004, to be set-off against the related Notes, rather than paid in full, after fulfillment of all obligations pursuant to the Senior Trust Certificates. This amendment to the Trust Agreement had the effect of allowing amounts related to the Junior Trust Certificate to be reported net in the financial statements.
          On September 1, 2005, PFL prepaid the floating rate Senior Trust Certificates (Series 2001-A2 and 2001-C) in accordance with the applicable provisions of the governing agreements. In order to facilitate this advance payment, Petrobras prepaid to PFL the amount of U.S.$330.3 million related to the export prepayment program.
          On March 1, 2006, PFL prepaid the fixed rate Senior Trust Certificates (Series 2001-A1 and 2001-B) in accordance with the applicable provisions of the governing agreements. In order to facilitate this advance payment, Petrobras prepaid to PFL an amount of U.S.$333.9 million related to the export prepayment program. As a result of this prepayment, U.S.$150 million of Junior Trust Certificates were cancelled by offsetting the Certificates with the obligation to deliver future receivables.
     On May 23, 2006, PFL has successfully completed a solicitation of consents from holders of the Series 2003-A 6.436% Senior Trust Certificates due 2015 issued by PF Export Receivables Master Trust. The amendments sought to eliminate exports of bunker fuel from the transaction so that the securities will be collateralized only by receivables from sales of fuel oil exported by PETROBRAS and to reduce the minimum average daily gross exports of fuel oil for any rolling twelve-month period. PFL also obtained the consent from the holders of Series 2003-B 3,748% due 2013. The amendments became effective on June 1, 2006.
Petrobras’ Bunker Fuel and Fuel Oil Business
          As described above, PFL, a wholly-owned subsidiary of PIFCo, purchases fuel oil from Petrobras and sells the products in the international market in order to generate export receivables to cover its obligations under the exports prepayment program. Until June 1, 2006, PFL also purchased bunker fuel from us but since then we have been selling bunker fuel in the international market directly and this product is no longer subject to our exports prepayment program.
          Bunker fuel is a common term for marine fuels that are burned in the boilers or engines of ships. Petrobras produces and exports two types of bunker fuel: intermediate fuel oil or marine fuel (for ships’ main engines and, occasionally, auxiliary engines) and marine diesel fuel or marine gas oil (for auxiliary engines and main engines of military vessels).
          Petrobras’ bunker fuel production in 2005 was 28,000 Mbbl, as compared to 27,425 Mbbl in 2004 and 26,741 Mbbl in 2003. Petrobras’ total bunker fuel production totaled 139,503 Mbbl for the period from January 1, 2001 to December 31, 2005. Petrobras exports approximately 82% of the bunker fuel it produces, with the exception of bunker fuel used by Petrobras’ fleet. Bunker fuel sold in Brazil by Petrobras to ships owned by non-Brazilian companies is considered an export under Brazilian regulations.

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PETROBRAS’ ANNUAL BUNKER FUEL PRODUCTION
                                         
    2005     2004     2003     2002     2001  
    (Mbbl)  
Export
    22,948       22,452       21,402       23,653       21,438  
Domestic Consumption
    1,313       1,061       1,048       1,620       1,533  
Petrobras Fleet
    3,739       3,912       4,291       4,596       4,497  
 
                             
Total
    28,000       27,425       26,741       29,869       27,468  
 
                             
          Fuel oil originates from residual fractions of distillation units at the refinery and from other processes such as deasphalting. Diluents in the form of lighter cutter stocks are mixed into the residue pool to create the desired viscosity for different types of fuel oil.
          Major buyers of Petrobras’ fuel oil include utilities, refineries and traders. Fuel oil is used by industries and utilities to run machinery and generate electricity. Commercial buildings and homes employ fuel oil for heating purposes, and refineries use fuel oil for blending purposes.
Fuel Oil Export Sales
          The following table sets forth Petrobras’ fuel oil export sales for the period from 2001 to 2005:
FUEL OIL EXPORT SALES
                                         
    2005   2004   2003   2002   2001
Millions of U.S.$
    1,077.6       1,306.1       967.3       697.0       658.0  
Millions of Barrels
    25.5       47.5       38.4       30.8       31.5  
Organizational Structure
          All of our 19 direct subsidiaries listed below are incorporated under the laws of Brazil, except PIFCo, Petrobras International Braspetro B.V. (PIB BV), Braspetro Oil Company (BOC), Braspetro Oil Services Company (Brasoil) and Petrobras Netherlands B.V. (PNBV), which are incorporated abroad. See Exhibit 8.1 for a complete list of our subsidiaries.

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          The following diagram sets forth our significant consolidated subsidiaries as of December 31, 2005:
(FLOW CHART)
Property, Plants and Equipment
Petrobras
          Under Brazilian law, the Brazilian government owns all crude oil and natural gas reserves within Brazil, and we have certain rights to exploit those reserves pursuant to concessions. Substantially all of our property, consisting of refineries and storage, production, manufacturing and transportation facilities, is located in Brazil. Our main owned and leased tangible assets consist of our wells, our platforms, our refining facilities, our pipelines, our vessels and other transportation assets and our power plants. Some of these assets are subject to liens but the value of such encumbered assets is not material. See Item 4. “Information on the Company” for a description of our reserves, sources of crude oil and natural gas, main tangible assets and material plans for expansion and improvements in our facilities.

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PIFCo
          PIFCo does not own or lease any material tangible properties or fixed assets. The majority of PIFCo’s assets consist of leasehold improvements, computers and furniture. In January 2003, PIFCo transferred its subsidiary PNBV to us as part of our restructuring of our subsidiaries according to the areas of business each subsidiary deals in.
Regulation of the Oil and Gas Industry in Brazil
Regulatory Framework
          Under Brazilian law, the Brazilian government owns all crude oil and natural gas reserves in Brazil. Additionally, Article 1 of Law No. 2,004 of 1953 granted the Brazilian government a monopoly over the research, exploration, production, refining and transportation of crude oil and oil products in Brazil and its continental shelf, subject only to the right of companies engaged in crude oil refining and the distribution of oil products at that time to continue those activities. Under Article 2 of Law No. 2,004, the Brazilian government made us its exclusive agent for purposes of exploiting the Brazilian government’s monopoly. In 1988, when it enacted the current Brazilian Constitution, the Brazilian Congress incorporated Article 1 of Law No. 2,004 into the Constitution and included within the scope of the Brazilian government’s monopoly the importation and exportation of crude oil and oil products.
          Beginning in 1995, the Brazilian government undertook a comprehensive reform of the country’s oil and gas regulatory system. On November 9, 1995, the Brazilian Congress amended the Brazilian Constitution to authorize the Brazilian government to contract with any state or privately-owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. Accordingly, this amendment made it possible to end our government-granted monopoly. The amendment was implemented by the enactment of the Oil Law No. 9,478, which revoked Law No. 2,004.
          The Oil Law provided for the establishment of a new regulatory framework, ending our exclusive agency and enabling competition in all aspects of the oil and gas industry in Brazil. As a result of this constitutional amendment and the subsequent and ongoing implementation of the changes under the Oil Law, its amendments and related regulations, we have been operating in an environment of gradual deregulation and increasing competition.
          The Oil Law also created an independent regulatory agency, the ANP. The ANP’s function is to regulate the oil and natural gas industry in Brazil. A primary objective of the ANP is to create a competitive environment for oil and gas activities in Brazil that will lead to the lowest price and best services for consumers. Among its principal responsibilities is to regulate concession terms for upstream development and award new exploration concessions. See Item 10. “Additional Information—Material Contracts—Petrobras—Concession Agreements with the ANP.”
          The Oil Law granted us the exclusive right to exploit the crude oil reserves in all fields where we had previously commenced production, in accordance with the concession agreement entered into with the ANP on August 6, 1998. For each concession area, we were granted an exclusivity period of 27 years as of the date the field was declared to be commercially profitable.
          The Oil Law also established a procedural framework for us to claim exclusive exploratory rights for a period of up to three years, which was later extended to five years, with respect to areas where we could demonstrate that we had “established prospects” prior to the enactment of the Oil Law. In order to perfect our claim to explore and develop these areas, we had to demonstrate that we had the required financial capacity to carry out these activities, either alone or through other cooperative arrangements.
          Each year we are required to submit our capital expenditures budget for the following fiscal year to the Ministry of Planning, Budget and Management and the Ministry of Mines and Energy. Once reviewed by those offices, the capital expenditures budget is then submitted to the Brazilian Congress for approval. As a result of this process, the total level of our capital expenditures for each fiscal year is regulated, although the specific application of funds is left to our discretion. Since mid-1991, we have obtained substantial amounts of our financing from the

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international capital markets, mainly through the issuance of commercial paper and short, medium and long-term notes, and have increasingly been able to raise long-term funds for large capital expenditure items such as rigs and platforms.
          Our strategic objectives and planning are subject to supervision by the Ministry of Planning, Budget and Management. Our activities are also subject to regulation by the Ministry of Finance and the Ministry of Mines and Energy, among others. In addition, since our common and preferred shares and ADSs are traded on the São Paulo Stock Exchange and the New York Stock Exchange, respectively, we are also regulated by the Comissão de Valores Mobiliários (Brazilian Securities Commission, or the CVM), the Securities and Exchange Commission and Comisión Nacional de Valores, or the CNV, as of April 27, 2006.
          Brazil is not a member of OPEC, but we have been invited to attend OPEC meetings as an observer. Therefore, neither Brazil nor we are bound by OPEC guidelines. However, to the extent that OPEC influences international crude oil prices, our prices are affected, as our prices are linked to international crude oil prices.
Price Regulation
          Since January 2, 2002, pursuant to Law No. 9,990, and as set forth below, the Brazilian government eliminated price controls for crude oil and oil products, except for the natural gas sold for qualifying gas-fired power plants. This led to increased competition and further price adjustments, as other companies were allowed to participate in the Brazilian market and import and export crude oil, oil products and natural gas to and from Brazil.
          Prices remain regulated, however, for certain natural gas sales contracts and electricity.
          To permit the taxation of all imported crude oil, oil products and natural gas in conjunction with the opening of the market to all participants, the Brazilian government established an excise tax to be applied with respect to the sale and import of crude oil, oil products and natural gas products (Contribuição de Intervenção no Domínio Econômico, Contribution for Intervention in the Economic Sector, or CIDE). Until April 30, 2004, the amounts paid as CIDE could be deducted from the payments of the PIS/PASEP and COFINS taxes.
          As of May 1, 2004, important changes were made regarding the taxation of oil products sales. The amount paid as CIDE that can be deducted from PIS (Programa de Integração Social)/PASEP (Programa de Formação do Patrimônio do Servidor Público) and COFINS (Contribuição para o Financiamento da Seguridade Social) was reduced to zero. The PIS/PASEP tax and the COFINS tax previously ad valorem taxes on imported products were converted into specific value taxes, and the CIDE tax was changed to the following rates:
                 
    PIS/PASEP and    
Product   COFINS rate   CIDE
    (reais/m3, except LPG/metric ton)
Gasoline
    R$261.60       280.0  
Diesel
    148.00       70.0  
Jet Fuel
    71.20        
LPG
    167.70        
          For certain trading transaction, the taxpayer may still opt to pay the PIS/PASEP tax and the COFINS as ad valorem taxes.
          Since the implementation of the Oil Law in 1997 and through December 31, 2001, the Brazilian oil and gas sector was significantly deregulated and the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government:
    introduced a new methodology for determining the price of oil products designed to track prevailing international prices and the real/U.S. dollar exchange rate;

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    eliminated regulation of the cost at which we could record imported crude oil and oil products in our cost of sales;
 
    gradually eliminated controls on wholesale prices at which we could sell our oil products, except for diesel, gasoline and LPG;
 
    effective July 28, 1998, eliminated transportation cost equalization subsidies known as Frete para Uniformização de Preços (Freight for the Uniformity of Prices, or FUP), in the case of transportation subsidies for oil products, and Frete para Uniformização de Preços do Álcool (Freight for the Uniformity of Prices of Alcohol, or FUPA), in the case of transportation subsidies for fuel alcohol; and
 
    continued to require that we act as the Brazilian government’s administrator for the fuel alcohol program.
          Until the passage of the Oil Law 9,478 in 1997, the Brazilian government had the power to regulate all aspects of the pricing of crude oil, oil products, fuel alcohol and other energy sources in Brazil, including natural gas and energy.
Crude Oil and Refined Oil Products
          Pursuant to the Oil Law and subsequent legislation as per Law No. 10,336 dated December 19, 2001., the oil and gas markets in Brazil underwent regulatory change beginning January 2, 2002. As part of this action:
    the Brazilian government no longer set sales prices for crude oil and oil products; and
 
    the Brazilian government established CIDE, an excise tax payable to the Brazilian government required to be paid by producers, blenders and importers upon sales and purchases of specified oil and fuel products at a set amount for different products based on the unit of measurement typically used for such products.
          Until enactment of the Oil Law, the Brazilian government regulated all aspects of the pricing of crude oil and oil products in Brazil, from the cost of crude oil imported for use in our refineries, to the price of refined oil products charged to the consumer.
Natural Gas
          Starting in January 2002, price controls on natural gas prices in Brazil were eliminated. Some contracts that were signed under the old system of price controls are still in force, but new contracts must contain clauses ensuring that prices are freely negotiated amongst the parties.
The Petroleum and Alcohol Account — Certification t and Settlement
          As provided in the Oil Law 9,478, the fuel market in Brazil was freed of price controls as of January 1, 2002, permitting other companies to produce and sell on the domestic market and, also, import and export oil and oil products. Additionally, as of January 1, 2002, we were no longer required to charge the prices established by the Brazilian government on the sale of oil products, and the realization price is no longer established by a formula adjusted to the international market.
          Considering the liberation of the market and current legislation, as of January 1, 2002, the Petroleum and Alcohol Account is no longer used to reimburse expenses related to the supply of oil products and fuel alcohol to us and third parties. The movements in the account for periods after 2002 relate only to (i) payments and adjustments mandated by the Agência Nacional do Petróleo — ANP with no impact on the income statement and (ii) adjustments resulting from the audit of the account by the ANP.

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          The ANP/STN Integrated Audit Committee submitted, on June 23, 2004, its final report certifying and approving the balance of the Petroleum and Alcohol account. The conclusion of this audit process for the Petroleum and Alcohol account establishes the basis for concluding the settlement process between the Brazilian government and us.
          As defined in Law No. 10,742 dated October 06, 2003, the settlement of the Petroleum and Alcohol account with the Brazilian government should have been completed by June 30, 2004. We have been working with the Ministry of Mines and Energy – MME and Secretary of the National Treasury – STN in order to resolve remaining issues necessary to conclude the settlement process.
          To facilitate the required settlement, on June 30, 1998, the Brazilian government issued National Treasury Bonds-Series H to us, representing the credit owed to us by the Brazilian government from the Petroleum and Alcohol Account. The bonds were placed with a federal depositary to support the balance of this account.
          The National Treasury Bonds-Series H matured on June 30, 2004. As of June 30, 2004, there were 138,791 National Treasure Bonds-Series H outstanding in the amount of U.S.$56 million against the balance of the Petroleum and Alcohol Account was U.S.$241 million. On July 2, 2004, the Brazilian Government made a deposit in an account in our name of U.S.$56 million for payment of the bonds. However, only U.S.$3 million of this amount was made available to us. We do not have access to the remaining U.S.$53 million, which represent a partial guarantee of the balance of the Petroleum and Alcohol Account, according to the determination of the Secretaria do Tesouro Nacional (STN). The legal, valid and binding nature of the account is not affected by any difference between the balance of the account and the value of the outstanding bonds.
          The remaining balance of the Petroleum and Alcohol account may be paid as follows: (1) National Treasury Bonds issued at the same amount as the final balance of the Petroleum and Alcohol account; (2) offset of the balance of the Petroleum and Alcohol account, with any other amount we owed to the Brazilian Government, including taxes; or (3) by a combination of the above options.
          The following table summarizes the changes in the Petroleum and Alcohol Account for 2005, 2004 and 2003:
                         
    For the Year Ended December 31,  
    2005     2004     2003  
    (in millions of U.S. dollars)  
Opening balance
  $ 282     $ 239     $ 182  
Reimbursements to third parties: subsidies paid to fuel alcohol producers
                5  
Reimbursements to Petrobras: transport of oil products
          1        
Financial income
    9       4       10  
Results of certification/audit process conducted by the Brazilian government
          16        
Partial settlement
          (3 )      
Translation gain (loss)(1)
    38       25       42  
 
                 
Ending balance
  $ 329     $ 282     $ 239  
 
                 
 
(1)   Exchange rate translation gains (losses) are recorded as a component of cumulative translation adjustments.
          The U.S.$47 million increase in the balance of the Petroleum and Alcohol Account during 2005 was primarily a result of the 11.8% appreciation of the real against the U.S. dollar.
Exploration and Development Regulation
          During the time we had a government-granted monopoly in Brazil for oil and gas operations, we had the right to exploit all production, exploration and development areas in Brazil. When government-granted monopoly

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was terminated, the Brazilian government was allowed to contract with any state or privately owned company for the development of the upstream and downstream segments of the Brazilian oil and gas sector. Before establishing bidding rounds for concessions, the Brazilian government granted us the exclusive right to exploit crude oil reserves where we had previously commenced operations. In 1998, the ANP started to conduct bidding rounds to grant concessions for production, exploration and development areas, and we were required to compete for concessions.
          With the effectiveness of the Oil Law and the regulations promulgated by the ANP thereunder, concessionaires are required to pay the government the following:
    signature bonuses;
 
    rentals for the occupation or retention of areas;
 
    special participation; and
 
    royalties.
          The minimum signature bonuses are published in the bidding rules for the concessions being auctioned, but the actual amount is based on the amount of the winning bid and must be paid upon the execution of the concession agreement.
          The rentals for the occupation and retention of the concession areas are determined for in the related bidding rules and are payable annually. For purposes of calculating rentals, the ANP takes into consideration factors such as the location and size of the relevant concession block, the sedimentary basin and its geological characteristics.
          Special participation is an extraordinary charge we must pay in the event of high production volumes and/or profitability from our fields, according to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation rate, whenever it is due, varies between 0% and 40% depending on:
    volume of production; and
 
    whether the block is onshore or offshore and, if offshore, whether it is shallow or deep water.
          Under the Oil Law and applicable regulations, the special participation is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate) less:
    royalties paid;
 
    investment in exploration;
 
    operational costs; and
 
    depreciation adjustments and applicable taxes.
          The ANP is also responsible for determining monthly royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession contract (contrato de concessão). Virtually all of our production currently pays the maximum 10% rate. In determining the royalties applicable to a particular concession block, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected.

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          The Oil Law also requires concessionaires of onshore fields to pay to the owner of the land a special participation fee that varies between 0.5% and 1.0% of the net operating revenues derived from the production of the field.
Environmental Regulations
          All phases of the crude oil and natural gas business present environmental risks and hazards. Our facilities in Brazil are subject to a wide range of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment. At the federal level, our offshore activities and those which involve more than one state of the Federation are subject to the administrative authority of the Brazilian Institute for the Environment and Renewable Natural Resources, or IBAMA, and to the regulatory authority of the Conselho Nacional do Meio Ambiente (National Council for the Environment), which issues operating or drilling licenses. Maintenance of the licenses requires the submission of reports, including safety and pollution monitoring reports (IOPP) to IBAMA. Onshore environmental, health and safety conditions are controlled at the state rather than federal level. Law No. 6,938 of August 31, 1981, and subsequent regulations and decrees established strict liability for environmental damage, mechanisms for enforcement of environmental standards and licensing requirements for polluting activities.
          CONAMA’s Resolution No. 23 of 1994 requires us to conduct environmental studies in connection with a number of our activities. We must eliminate, mitigate, or compensate relevant parties for, any adverse environmental effects identified through these studies.
          On December 27, 2000, Law No. 10,165, modifying Law No. 6,938, created the Taxa de Controle e Fiscalização Ambiental (Environmental and Fiscalization Control Tax, or TCFA). The law empowers IBAMA to collect, on a quarterly basis, certain fees from us and other companies that meet a minimum revenue threshold, are engaged in potentially environmentally damaging activities and/or are exploiting natural resources within Brazil. At present, we do not consider this fee imposed by IBAMA to be material. The Confederação Nacional da Indústria (Brazilian Industry Confederation, or CNI), is currently contesting these fees as unconstitutional.
          Brazilian environmental laws and regulations provide for restrictions and prohibitions on spills and releases or emissions of various hazardous substances produced in association with our operations. Brazilian environmental laws and regulations also govern the operation, maintenance, abandonment and reclamation of wells, refineries, terminals, service stations and other facilities. Compliance with these laws and regulations can require significant expenditures, and violations may result in fines and penalties, some of which may be material. In addition, operations and undertakings that have a significant environmental impact, especially the drilling of new wells and expansion of refineries, require us to apply for environmental impact assessments in accordance with federal and state licensing procedures. In accordance with Brazilian environmental laws, we have proposed the execution of, or we have entered into, environmental commitment agreements with the environmental protection agencies and/or the federal or state public ministries, in which we agree to undertake certain measures in order to complete the environmental licensing for several of our operating facilities.
          Under Law No. 9,605 of February 12, 1998, individuals or entities whose conduct or activities cause harm to the environment are subject to criminal and administrative sanctions, as well as any costs to repair the actual damages resulting from such harm. Individuals or legal entities that commit a crime against the environment are subject to penalties and sanctions that range from fines to imprisonment, for individuals, or, suspension or interruption of activities or prohibition to enter into any contracts with governmental bodies for up to ten years for legal entities. The government environmental protection agencies may also impose administrative sanctions on those who do not comply with the environmental laws and regulations, including, among others:
    fines;
 
    partial or total suspension of activities;
 
    obligations to fund recovery works and environmental projects;

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    forfeiture or restriction of tax incentives or benefits;
 
    closing of the establishments or undertakings; and
 
    forfeiture or suspension of participation in credit lines with official credit establishments.
          Under Law No. 9,966 of 2000, entities operating organized ports and port installations and owners or operators of platforms and its support installations must perform independent environmental audits every two years, with a view to evaluating the environmental management and control systems in their units. We are in full compliance with this law.
          Law No. 9,985 of July 19, 2000 establishes an environmental compensation of at least 0.5% of the value of a project relating to activities that have a negative environmental impact that cannot be mitigated. This compensation may only be applied in conservation units, as defined by the Sistema Nacional de Unidades de Conservação da Natureza (the National System of Nature Conservation Units, or the SNUC). Environmental agencies are still implementing this law, but they may attempt to apply it in a retroactive manner.
          In 2005, we invested approximately U.S$430 million in environmental projects as compared to approximately U.S.$490 million in 2004. These investments were primarily directed at reducing emissions and wastes resulting from industrial processes, managing water use and effluents, remedying impacted areas, obtaining oil collectors for our environmental protection centers and other new equipment to improve our response to emergency situations, implementing new environmental technologies, upgrading our pipelines and paying environmental compensation.
          In March 2006, the Brazilian Congress enacted Law No. 11,284, which, among other things, creates the concept of environmental insurance as an economic policy instrument. Brazilian companies will be required to purchase environmental insurance only once the Brazilian Congress approves a new law to regulate Law No. 11,284 that expressly creates this obligation. We do not know the terms and conditions under which environmental insurance will be contracted in the future and, therefore, we cannot estimate whether the requirement to purchase environmental insurance will have a material adverse effect in our business, financial condition and results of operations.
          We are subject to a number of administrative proceedings and civil and criminal claims relating to environmental matters. See Item 8. “Financial Information — Legal Proceedings—Environmental Claims.”
Health, Safety and Environmental Initiatives
Initiatives
          The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated energy company. In order to address and prioritize health, safety and environmental concerns and ensure compliance with environmental regulations, we have:
    developed the PEGASO program to upgrade our pipelines and other equipment, implement new technologies, improve our emergency response readiness, reduce emissions and residues and prevent environmental accidents. From April 2000 to December 2005, we spent approximately U.S$3.519 billion under this program, including the Programa de Integridade de Dutos (Pipeline Integrity Program) through which we conduct inspections of, and improvements to, our pipelines. In 2005, we spent approximately U.S$545 million in connection with the PEGASO program;
 
    proposed the execution of, or entered into, environmental commitment agreements with several environmental protection agencies and/or the federal or state public ministries, in which we agree to undertake certain measures in order to complete the environmental licensing for several of our operating facilities;

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    integrated our corporate health department into the already existing corporate environment and safety department, thereby facilitating the development of systematic, company-wide procedures to handle concerns related to health, safety and the environment, or HSE.
 
    established our new HSE policy and corporate guidelines, which focus on principles of sustainable development, compliance with legislation and the availability and use of environmental performance indicators;
 
    undertook capital investments to reduce the HSE risk of our operations, including making improvements to our refineries and transportation facilities and developing and implementing oil pollution prevention guidelines;
 
    built nine environmental protection centers and seven advanced bases for oil spill prevention, control and response, established local and regional, onshore and offshore contingency plans involving public services and communities to deal with oil spills, and chartered three dedicated oil spill recovery vessels (OSRVs) fully equipped for oil spill control and fire fighting;
 
    received HSE integrated management certificates for our operating units. As of December 2005, Petrobras owned 45 certificates for its operating units in Brazil and 21 for units abroad. These certificates acknowledge the compliance of our HSE management system with ISO 14001 (environment), and BS 8800 or OHSAS 18001 (health and safety) standards. Because some of those certificates cover more than one site, the total number of certified sites is 172 in Brazil and 25 abroad. The Frota Nacional de Petroleiros (National Fleet of Vessels) has been fully certified by the IMO International Management Code for Safe Operation of Ships and for Pollution Prevention (ISM Code) since December 1997;
 
    implemented through the Programa de Segurança de Processo (Process Safety Program) standardized, company-wide guidelines for HSE management, for effectively investigating incidents and for strengthening our institutional commitment to HSE through employee training. The HSE Management Manual developed through that program is a day-to-day management tool currently being applied in all of our operating units;
 
    developed an Air Emissions Management System, in conjunction with an international consulting company, for our operations in Brazil and South America. The system gathers information about emissions of sulfur dioxide, nitrogen oxides, carbon monoxide, the main greenhouse gases (carbon dioxide, methane and nitrous oxide), volatile organic compounds (VOCs) and particulate material, allowing us to improve the management of our emissions. We have registered our 2004 Annual Emissions Summary in the Global Greenhouse Gas Register of the World Economic Forum. The report gathers data provided by the Air Emissions Management System and is available for public access through the Forum’s website;
 
    participated in negotiations conducted by the Brazilian Ministry of Mines and Energy of new regulations of environmental compensation related to the implementation of new projects;
 
    participated with the Brazilian Ministry of Mines and Energy and IBAMA in a governmental follow-up group created to supervise the implementation of the new planned gas pipelines;
 
    participated regularly in the discussion agenda of the Brazilian Ministry of Mines and Energy and the Ministry of the Environment about environmental issues affecting our business;
 
    participated directly in discussions with the Ministry of the Environment and IBAMA regarding issues that could affect Petrobras’ business;

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          In addition, we conduct environmental studies for all new projects as required by Brazilian environmental legislation, and our HSE department evaluates each and every project with a total budget exceeding U.S$25 million to confirm its compliance with all HSE requirements.
          We will continue to evaluate and develop initiatives to address HSE concerns and to reduce our exposure to HSE risks.
          Our Executive Board has approved the building of three biodiesel production plants, with a total capacity of 132,000 tons per year. The plants will demand an investment of about U.S.$86.6 million and are expected to begin operations in December of 2007;
          We have bought 70,000 cubic meters of biodiesel, certified with the “social fuel” label, to be delivered throughout 2006. Social fuel is fuel manufactured under a government program designed to promote family-run agricultural enterprises;
          Petrobras Distribuidora is going to participate in the construction of 13 small hydropower plants (SHPs), with a total capacity of 288 MW. The project was already approved by the National Agency for Electrical Energy, under the Brazilian Program for Incentive to Alternative Electric Energy Sources — PROINFA, and will demand an investment of about (R$1.3 billion). The SHPs will be controlled by a holding company named Brasil PCH. 49% of the common shares of that company will be owned by Petrobras Distribuidora.
Management
          We have a HSE Management Committee, which was created by our executive officers to ensure that HSE issues are addressed throughout the company. The committee is composed of executive managers of our different business segments and of directors of our controlled companies, BR Distribuidora and Transpetro. The work of the HSE Management Committee is supported by four permanent subcommittees and by temporary commissions and work groups, each one responsible for a specific HSE issue, such as licensing and environmental compensation, operational risk assessment, management of change, emissions and climate change, new projects, product stewardship and acquisition of goods.
          We have also created an Environmental Committee, which is composed of three members of our Board of Directors, including our Chairman and our Chief Executive Officer. The committee is responsible for, among other things: (1) overseeing and managing environmental and work safety issues affecting us; (2) establishing measurable environmental targets and ensuring compliance; and (3) recommending changes in environmental, health and safety policy, if necessary, to our board of directors. The Environmental Committee charter is still subject to approval by our Board of Directors.
Competition
          As a result of the regulatory reform of the oil and gas industry in Brazil, we expect to face increasing competition both in our downstream and upstream operations.
          In the exploration and production segment, the Brazilian government’s auction process for new exploratory areas has enabled multinational and regional oil and gas companies to begin exploring for crude oil in Brazil. If these companies discover crude oil in commercial quantities and are able to develop it economically, we expect that competition with our own production will increase.
          In the past, we have faced little competition as a result of the prevailing laws that effectively gave us a monopoly. With the end of this monopoly and regulatory reform, other participants may now explore, produce, transport and distribute oil products in Brazil. As a result, some participants have already begun importing refined oil products, which will compete with oil products from our Brazilian refineries, as well as the oil products we currently import. We now have to compete with global imports at international prices. We expect that this additional competition may affect the prices we can charge for our oil products, which in turn will affect the profit we can make. We estimate that we had a market share of approximately 98.2% in the Brazilian oil production segment in

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2005. We do not have meaningful competitors in the oil production segment in Brazil. In the oil exploration segment, we estimate that the exploration activities conducted solely by us represented approximately 88% (number of exploration wells we drilled solely compared to the total number of exploration wells drilled in Brazil in 2005) of the Brazilian oil exploration market in 2005 and the exploration activities conducted by us in conjunction with other partners represented approximately 92% (number of exploration wells we drilled solely and with partners compared to the number of exploration wells drilled in Brazil in 2005) of the oil exploration market in Brazil in 2005. Our main competitors in the oil exploration segment are Agip, Devon, Shell, Maersk, Statoil, Chevron Texaco, Encana and El Paso.
          We also expect continued competition in our distribution segment, where we currently face the most significant competition of any of our business segments. In particular, we face competition from small distributors, many of which have been able, and may continue to be able, to avoid paying sales taxes and mix their gasoline with inexpensive solvents, enabling them to sell gasoline at prices below ours. We had a market share of approximately 34 % in the Brazilian oil products distribution segment according to Sindicom, a Brazilian industry association of oil and gas distribution companies. Our main competitors in this segment are Ipiranga, Shell, Esso, and Texaco.
          In the natural gas and power segment, we expect competition from new entrants that are acquiring interests in natural gas distribution and gas-fired power generation companies, and existing competitors that are expanding operations in order to consolidate their position in Brazil. We had a market share of approximately 94% in the Brazilian natural gas segment based on 2005 volumes sold to the Local Distribution Companies and total natural gas market, according to the Associação Brasileira das Empresas de Gás Natural (the Brazilian Society of Natural Gas Companies, or ABEGÁS).
          In the international segment, we plan to continue expanding operations, although we expect to face continuing competition in the areas in which we are already active, including the Gulf of Mexico, Africa and the Southern Cone. We have already become a major player in some of the countries in which we have international operations. In Argentina, we estimate that we have a market share of 13.3% for auto fuel and 10.4% for lubricants. In Bolivia, we have a market share of 96% of the oil refining market, 40.6% of the fuel market, and 66% of lubricants.
Insurance
          Our insurance programs principally focus on the concentration of risks and the importance and replacement value of assets. Under our risk management policy, risks associated with our principal assets, such as refineries, tankers, our fleet and offshore production and drilling platforms, are insured for their replacement value with third-party Brazilian insurers. Although the policies are issued in Brazil, most of our policies are reinsured abroad with reinsurers rated BBB+ or higher by Standard & Poor’s rating agency or B++ or higher by A.M. Best. Substantially all of our international operations are insured or reinsured by our Bermudian subsidiary Bear Insurance Company Limited following exactly the same rating criteria.
          Less valuable assets, such as small auxiliary boats, certain storage facilities, and some administrative installations, are self-insured. We do not maintain coverage for business interruption, except for a minority of our international operations. We also do not maintain coverage for our wells for substantially all of our Brazilian operations.
          Since November 2000, we maintain coverage for operational third-party liability with respect to our onshore and offshore activities, including environmental risks such as oil spills. The insurance policy covers any damage resulting from either our or our affiliates’ activities, with the exception of our international activities, which have their own insurance and are therefore not included in this policy. In Brazil, our coverage in this policy is of up to U.S.$250 million per accident in the aggregate (fines imposed by government authorities are not covered). In case of an accident, this coverage may not be sufficient to compensate us for losses incurred. Although we do not insure most of our pipelines, we have insurance against damage or loss resulting from specific incidents, as well as oil pollution from our pipelines.
          We also maintain coverage for risks associated with transportation, hull and machinery risk. Since 1999, we have directors and officers insurance coverage. All projects and installations under construction are insured in

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compliance with the terms of the relevant financing agreements, usually through a performance bond in connection with completion of the contract and/or other damage and liability insurance. All projects and installations under construction that have an estimated maximum loss above U.S.$40 million are covered by a construction policy.
          The premium for renewing our property risk insurance policy for a 12-month period commencing June 2005 was U.S$29.4 million. This represented an increase of 16.5% over the preceding 12-month period. The increase was primarily due to an increase in the insured value of our assets, which in the same period, increased by 22.9%, from U.S.$26.6 billion to U.S$32.7 billion. Since 2001, our risk retention has increased and our deductibles may reach U.S.$40 million in certain cases.
          Our facilities are regularly subject to risk surveys undertaken by international risk consultants. The reports and recommendations prepared in these surveys are made public, as well as the actions taken by us to meet these recommendations. All the significant accidents and their causes, as well as the improvements we make to our HSE standards are periodically released to the public.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
Management’s Discussion and Analysis of Petrobras’ Financial Condition and Results of Operations
          You should read the following discussion of our financial condition and results of operations together with our audited consolidated financial statements and the accompanying notes beginning on page F-1 of this annual report.
Overview
          We earn income from:
    domestic sales, which mainly consists of sales of oil products (such as gasoline, diesel oil, jet fuel, fuel oil, naphtha and liquefied petroleum gas), natural gas, petrochemical products and electricity;
 
    export sales, which consist primarily of sales of crude oil and oil products;
 
    international sales (excluding export sales), which consist of sales of crude oil, natural gas and oil products that are produced and refined abroad; and
 
    other sources, including services, investment income and foreign exchange gains.
Our expenses include:
    costs of sales (which is comprised of labor expenses, costs of operating and purchases of crude oil and oil products); maintaining and repairing property, plants and equipment; depreciation and amortization of fixed assets and depletion of oil fields; and costs of exploration;
 
    selling (which include expenses for transportation and distribution of our products), general and administrative expenses; and
 
    interest expense and foreign exchange losses.
Year to year fluctuations in our income are the result of a combination of factors, including:
    the volume of crude oil, oil products and natural gas we produce and sell;
 
    changes in international prices of crude oil and oil products, which are denominated in U.S. dollars;
 
    related changes in domestic prices of crude oil and oil products, which are denominated in reais;
 
    fluctuations in the real/U.S. dollar and Argentine Peso/U.S. dollar exchange rates;
 
    Brazilian political and economic conditions; and

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    the amount of taxes and duties that we are required to pay with respect to our operations, by virtue of our status as a Brazilian company and our involvement in the oil and gas industry.
Sales Volumes and Prices
     The profitability of our operations in any particular accounting period is related to the sales volume of, and prices for, the crude oil, oil products and natural gas that we sell. Our consolidated net sales in 2005 totaled approximately 1,025,033 million barrels of crude oil equivalent, representing U.S.$56,324 million in net operating revenues, as compared to approximately 989,719 million barrels of crude oil equivalent, representing U.S.$38,428 million in net operating revenues in 2004 and approximately 923,482 million barrels of crude oil equivalent and U.S.$30,914 million in net operating revenues in 2003.
     As a vertically integrated company, we process most of our crude oil production in our refineries and sell the refined oil products primarily in the Brazilian domestic market. Therefore, it is oil product prices, rather than crude oil prices, that most directly affect our financial results.
     Oil product prices vary over time as the result of many factors, including the price of crude oil. The average prices of Brent crude, an international benchmark oil, were approximately U.S.$54.38 per barrel in 2005, U.S.$38.21 per barrel for 2004 and U.S.$28.84 per barrel for 2003. For December 2005, Brent crude oil prices averaged U.S.$56.63 per barrel, but during 2006 through April, Brent crude oil prices have increased, averaging U.S.$64.03 per barrel. This increase in average crude oil prices also affected international prices for oil products.
Domestic Sales Volumes and Prices
     During 2005, approximately 72.4% of our net operating revenues were derived from sales of crude oil and oil products in Brazil, as compared to 73.2% in 2004 and 74.0% in 2003. As export volumes of crude oil and oil products have increased, domestic sales as a percentage of net operating revenues have declined.
     Our revenues are principally derived from sales in Brazil. The following table sets forth our sales by volume of oil products, natural gas and fuel alcohol for each of 2005, 2004 and 2003 as well as a reconciliation to our consolidated sales:

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    For the Year Ended December 31,  
    2005     2004     2003  
            Net     Net             Net     Net             Net     Net  
            Average     Operating             Average     Operating             Average     Operating  
    Volume     Price     Revenues     Volume     Price     Revenues     Volume     Price     Revenues  
    (Mbbl,                     (Mbbl,                     (Mbbl,                
    except as                     except as                     except as                
    otherwise             (U.S.$ in     otherwise             (U.S.$ in     otherwise             (U.S.$ in  
    noted)     (U.S.$)(1)     millions)     noted)     (U.S.$)(1)     millions)     noted)     (U.S.$)(1)     millions)  
Energy products:
                                                                       
Automotive gasoline
    104,901     $ 60.08     $ 6,302       100,712     $ 41.58     $ 4,188       94,364     $ 38.28     $ 3,612  
Diesel
    242,831       68.20       16,561       240,237       44.64       10,725       219,622       40.64       8,925  
Fuel oil
    36,243       40.81       1,479       39,654       28.45       1,128       43,475       27.92       1,214  
Liquid petroleum gas
    77,891       34.55       2,691       76,982       28.14       2,166       73,575       27.07       1,992  
 
                                                           
Total energy products
    461,866               27,033       457,585               18,207       431,036               15,743  
 
                                                           
Non-energy products:
                                                                       
Petrochemical naphtha
    57,281       53.49       3,064       57,595       42.28       2,435       57,291       32.03       1,835  
Others
    80,953       58.35       4,724       77,652       41.96       3,258       73,901       33.69       2,490  
 
                                                           
Total non-energy products
    138,234               7,788       135,247               5,693       131,192               4,325  
 
                                                           
Fuel alcohol
    126       23.81       3       455       30.77       14       458       39.30       18  
Natural gas (BOE)
    83,090       21.77       1,809       77,310       18.61       1,439       64,517       18.94       1,222  
 
                                                           
Sub-total
    683,316       53.61       36,633       670,597       37.81       25,353       627,203       33.97       21,308  
 
                                                           
Distribution net sales
    201,347       78.53       15,811       182,327       57.36       10,458       158,635       50.39       7,994  
Intercompany net sales
    (187,268 )     62.22       (11,651 )     (164,730 )     46.69       (7,692 )     (143,339 )     44.81       (6,423 )
 
                                                         
Total domestic market
    697,395       58.49       40,793       688,194       40.86       28,119       642,499       35.61       22,879  
 
                                                           
Export net sales
    187,008       47.79       8,938       186,221       31.81       5,923       192,545       27.71       5,335  
International net sales and Others
    140,630       43.93       6,178       115,304       35.33       4,074       88,438       29.89       2,643  
 
                                                                       
 
                                                           
Sub-Total
    327,638       46.14       15,116       301,525       33.15       9,997       280,983       28.39       7,978  
 
                                                           
Services
                    415                       312                       57  
 
                                                         
Consolidated net sales
    1,025,033             $ 56,324       989,719             $ 38,428       923,482             $ 30,914  
 
                                                           
 
(1)   Net average price calculated by dividing net sales by the volume for the year.
          During 2005, we announced one increase in gasoline and diesel prices due to the elevated prices of crude oil and oil products on the international market. The price increases in the table below reflect the increases in billing at Petrobras refineries, without ICMS:
          Price increase announced on September 9, 2005:
                 
    Percentage Increase in Price
    (increase to customers including    
    taxes(CIDE / PIS / COFINS))   (net increase to Petrobras)
Gasoline
    16.4 %     10.0 %
Diesel
    14.8 %     12.0 %
Export Sales Volumes and Prices
     While our principal market is the Brazilian market, as our domestic production of crude oil has increased, we have begun to export greater amounts of crude oil and oil products that exceed Brazilian demand. We also export volumes of domestically produced heavy crude oil that our refineries are unable to process operationally or economically. See Item 4. “Information on the Company—Refining, Transportation and Marketing.” Our export volumes of crude oil and oil products totaled 187,008 million barrels of crude oil equivalent in 2005, as compared to 186,221 million barrels of crude oil equivalent in 2004 and 192,545 million barrels of crude oil equivalent in 2003. We base our crude oil export prices on international prices, as adjusted to reflect specific market conditions. We determine export prices of our oil products and natural gas by reference to market conditions, as well as direct

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negotiations with our clients. As a result of an increase in average prices and volume of export sales of crude oil and oil products, the total value of our crude oil and oil product exports (measured on a free-on-board basis) in 2005 was U.S.$ 8,938 million, as compared to U.S.$5,923 million in 2004 and U.S.$5,335 million in 2003, representing approximately 15.9% of our net operating revenues in 2005, as compared to 15.4% in 2004 and 17.3% in 2003. See Item 4. “Information on the Company—Refining, Transportation and Marketing-Exports.”
International Volumes and Prices
     We produce, refine, transport, distribute and market crude oil and natural gas internationally. Sales from production outside Brazil to sources outside Brazil were U.S.$3,038 million in 2005, U.S.$2,840 million in 2004 and U.S.$1,974 million in 2003, representing approximately 5.4% of our net operating revenues in 2005, as compared to 7.4% in 2004 and 6.4% in 2003. We expect our international sales to continue growing as our international production continues to grow and we increase our refining and distribution capacity abroad. See Item 4. “Information on the Company—International.”
Import Purchase Volumes and Prices
     We continue to import lighter crude oil for blending in our own refineries, as well as smaller quantities of diesel, liquefied petroleum gas, naphtha and other oil products, to attend the demand of the Brazilian retail market. We have continuously upgraded our refineries to handle heavier crude oil in order to reduce our purchases of imported crude oil and oil products by refining a greater portion of our heavier crude oil production. This has positively affected the margin between our net operating revenues and cost of goods sold, since it is less expensive to produce crude oil domestically than it is to import crude oil. In 2005, the net margin increased to 18.4% as compared to 16.1% in 2004, as a result of a decrease in imported crude oil to 352 Mbpd in 2005, from 450 Mbpd in 2004.
     Prior to December 31, 2001, we were the only company permitted to import oil products to supply the Brazilian market’s demand for these products. Now that other parties are permitted by law to import oil products and supply the market, we continue to reevaluate our strategy in order to achieve optimal levels of imports for our profitability. We imported a total of 34.8 million barrels of oil products in 2005, as compared to 40.1 million barrels of oil products in 2004 and 44.5 million barrels in 2003. See Item 4. “Information on the Company—Refining, Transportation and Marketing-Imports.”
Effect of Taxes on our Income
General
     In addition to taxes paid on behalf of federal, state and municipal governments, such as the Imposto sobre Circulação de Mercadorias e Serviços, or ICMS, we are required to pay three principal charges on our oil production activities in Brazil:
    Royalties, which generally correspond to a percentage between 5% and 10% of production, are calculated based on a reference price for crude oil or natural gas, and will thus vary with the international price of crude oil. The ANP also takes into account the geological risks involved, and productivity levels expected, with respect to a particular concession. Virtually all of our crude oil production is currently taxed at the maximum royalty rate.
 
    Special Participation, which applies to our larger, more profitable fields, and ranges from 0% to 40% depending on the volumes of crude oil produced in the fields, the location of the fields (including whether they are onshore or offshore), water depth and number of years that the field has been in production. In 2005, the tax was charged on 20 of our fields, including Marlim, Albacora, Roncador, Leste do Urucu, Rio Urucu, Canto do Amaro, Marimbá, Marlim Sul, Namorado, Carapeba, Pampo, Bicudo, Barracuda, Caratinga, Cherne, Pilar, Fazenda Alegre, Miranga, Carmópolis and Bijupirá. The tax is based on net revenues of a field, which consists of gross revenues less royalties paid, investments in exploration, operational costs and depreciation adjustments and applicable taxes. The Special Participation Tax uses as a reference international oil prices converted to reais at the current exchange rate.
 
    Retention Bonus, which is a tax payable on those concessions that are available for exploration and production, and is calculated at a rate established by the ANP, taking into consideration factors such as the location and size of the relevant concession block, the sedimentary basin and its geological characteristics.

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     These charges imposed by the Brazilian government are included in our cost of goods sold. Additionally, we are subject to tax on our income at an effective rate of 25% and a social contribution tax at an effective rate of 9%, the standard corporate tax rate in Brazil. See Note 4 to our audited consolidated financial statements.
Potential Change in ICMS Legislation
     In June 2003, the State of Rio de Janeiro enacted a law (State Law nº 4.117, dated June, 27th, 2003, also known as “Noel Law”) imposing the ICMS on upstream activities. The law was regulated by Decree nº 34.761, dated February 3, 2004, which was suspended by Decree nº 34.783 of February 4th, 2004, for an undetermined period of time. Nevertheless, the State of Rio de Janeiro may choose to enforce the law at any time.
     The constitutionality of this law is currently being challenged. The claim was filed by the Federal Prosecutor and the Attorney General has given a favorable legal opinion. The Supreme Court provisionally did not suspend the effectiveness of the law.
     In accordance with legislation currently in force, the ICMS for fuels derived from oil is assessed at the point of sale but not at the wellhead level. As a result, the tax is mainly collected in the states where the sales of fuels are made. If the State of Rio de Janeiro enforces the new law, it is unlikely that the other states would allow us to use the tax imposed at the wellhead level in Rio de Janeiro as a credit to offset the tax imposed at the sale level. Therefore, we would have to pay ICMS at both levels, unless we are successful in challenging this tax in court. If the Supreme Court decides that this law is constitutional, our ability to challenge the payment of ICMS at both levels will depend on the ground of the Supreme Court’s decision.
     We estimate the amount of ICMS that we would be required to pay to the State of Rio de Janeiro could increase by approximately R$8.51 billion (U.S.$3.52 billion) per year as a result of this change in legislation. This increase could have a material adverse effect on our results of operations and financial condition.
Financial Income and Expense
     We derive financial income primarily from interest on cash and cash equivalents. The bulk of our cash equivalents are short-term Brazilian government securities, including securities indexed to the U.S. dollar. We also hold substantial balances in U.S. dollar deposits.
     Our financial income was U.S.$710 million in 2005, U.S.$956 million in 2004 and U.S.$634 million in 2003.
     We incur financial expenses from short and long-term debt denominated in U.S. dollars, reais and other currencies. Our financial expenses were U.S.$1,189 million in 2005, U.S.$1,733 million in 2004 and U.S.$1,247 million in 2003. In addition, we capitalized U.S.$612 million in interest in 2005, as compared to U.S.$267 million in 2004 and U.S.$184 million in 2003.
Inflation and Exchange Rate Variation
Inflation
     Since the introduction of the real as the new Brazilian currency in July 1994, inflation in Brazil has remained relatively stable, although it increased markedly in 2002. Inflation was 1.2% in 2005, 12.1% in 2004 and 7.7% in 2003, as measured by the IGP-DI, a general price index. Inflation has had, and may continue to have, effects on our financial condition and results of operations. A large percentage of our total costs are in Reais, and our suppliers and service providers generally attempt to increase their prices to reflect Brazilian inflation. These increases are counteracted by the adjustments that we make to our prices to offset the effects of inflation and an appreciation of the U.S. dollar against the real.
Exchange Rate Variation
     Since we adopted the real as our functional currency in 1998, fluctuations in the value of the real against the U.S. dollar, particularly devaluations of the real, have had, and will continue to have, multiple effects on our results of operations. Our reporting currency for all periods is the U.S. dollar. We maintain our financial records in reais,

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and translate our statements of operations into U.S. dollars at the average rate for the period. The amounts reported in our statements of operations in any given period will be reduced at the same rate as the real has devalued in relation to the U.S. dollar during that period. During 2005, there was an 11.8% appreciation of the real against the U.S. dollar, as compared to an 8.1% appreciation in 2004 and an 18.2% depreciation in 2003.
     Virtually all of our sales are of crude oil or oil products, which generally trade freely in the international markets at prices expressed in U.S. dollars. From July 1998 through the end of 2001, our net operating revenues reflected changes in the U.S. dollar/real exchange rate, with a one month delay, because the formula used by the government to set realization prices for crude oil and oil products included adjustments based on exchange rate variations. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”
     Since January 2, 2002, when prices were deregulated, we have been free to establish prices for our products based on market conditions and have generally been able to maintain parity with international prices. As a result, although substantially all of our revenues are in reais, they have been, and continue to be, linked to U.S. dollar-based international prices. When the real depreciates against the U.S. dollar, assuming international prices remain constant in U.S. dollars, we may increase the prices for our products in reais, in which case our net operating revenues in reais increase. An increase in our reais net operating revenue, however, is not reflected in our net operating revenue when reported in U.S. dollars, when the real depreciates.
     Another effect of depreciation is that our operating costs and expenses when expressed in U.S. dollars tend to decline. This happens primarily due to the fact that a substantial portion of our costs and operating expenses is denominated in reais. Prior to 2003, our reais-denominated costs increased at a rate slower than the depreciation. Accordingly, the effect was to decrease costs of locally supplied products and services when reported in U.S. dollars.
     The opposite effects occur when the real appreciates against the US dollar such as in 2004 and 2005.
     In recent periods, the exchange rate variation has had the following additional effects, among others, on our financial condition and results of operations:
    We record the remeasurement effects of our non-reais denominated assets and liabilities held in Brazil (e.g., cash, cash equivalents and financial obligations) in our statements of income. Primarily because of our substantial liabilities denominated in foreign currency, we recorded a U.S.$269 million net foreign exchange gain in our 2005 statement of income, compared to a U.S.$368 million net foreign exchange gain in 2004 and a U.S.$2,433 million net foreign exchange loss in 2003. To the extent these variations are not recognized in a transaction (such as the repayment of the debt in the period in which there is a depreciation), the foreign exchange gain is added back for purposes of determining our cash flow;
 
    Our other assets and liabilities in Brazil, primarily accounts receivable, inventories and property, plant and equipment, cash and cash equivalents and government securities, pension plan liabilities, health care benefits and deferred income taxes, are all translated into U.S. dollars. Therefore, any depreciation (appreciation) of the real against the U.S. dollar will be reflected as a reduction (gain) in the U.S. dollar value of those assets and liabilities, charged directly to shareholders’ equity. These currency translation effects are beyond our control. Accordingly, we recorded a U.S.$3,107 million credit directly to shareholders’ equity in our statement of changes in shareholders’ equity for 2005, without affecting net income, to reflect the appreciation of the real against the U.S. dollar of approximately 11.8%, as compared to a credit of U.S.$1,911 million in 2004 to reflect the appreciation of 8.1% and a charge of U.S.$2,856 million in 2003 to reflect the depreciation of 18.2%.
     Foreign currency translation adjustments reflecting a depreciation have the greatest impact on the balance sheet of a company such as ours, whose assets are primarily denominated in reais, but whose liabilities are primarily denominated in foreign currencies. The reductions in our asset values charged to shareholders’ equity, however, do not necessarily affect our cash flows, since our revenues and cash earnings are to a large degree linked to the U.S. dollar, and a portion of our operating expenses are linked to the real.
     The exchange rate variation also impacts the amount of retained earnings available for distribution by us when measured in U.S. dollars. Amounts reported as available for distribution in our statutory accounting records prepared

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in accordance with Brazilian accounting principles decrease or increase when measured in U.S. dollars as the real depreciates or appreciates against the U.S. dollar. In addition, the exchange rate variation creates foreign exchange gains and losses that are included in our results of operations determined in accordance with Brazilian accounting principles and that affect the amount of our unretained earnings available for distribution.
Results of Operations
     The differences in our operating results from year to year occur as a result of a combination of factors, including primarily: the volume of crude oil, oil products and natural gas we produce and sell, the price at which we sell our crude oil, oil products and natural gas and the differential between the Brazilian inflation rate and the depreciation or appreciation of the real against the U.S. dollar. The table below shows the amount by which each of these variables has changed during the last three years:
                         
    2005   2004   2003
Crude Oil and NGL Production (Mbpd)
                       
Brazil
    1,684       1,493       1,540  
International
    163       168       161  
Total Crude Oil and NGL
                       
Production
    1,847       1,661       1,701  
Change in Crude Oil and NGL Production
    11.2 %     (2.4 )%     10.8 %
Average Sales Price for Crude (bpd in U.S.$)
                       
Brazil
  $ 45.42     $ 33.49     $ 27.01  
International
  $ 34.91     $ 26.51     $ 23.7  
Natural Gas Production (Mmcfpd)
                       
Brazil
    1,644       1,590       1,500  
International
    576       564       510  
Total Natural Gas Production
    2,220       2,154       2,010  
Change in Natural Gas Production (sold only)
    3.1 %     7.2 %     21.8 %
Average Sales Price for Natural Gas (Mcf in U.S.$)
                       
Brazil
    2.17       1.93       1.79  
International
    1.64       1.17       1.26  
Year End Exchange Rate
    2.34       2.65       2.89  
Appreciation (Depreciation) during the year
    11.8 %     8.1 %     18.2 %
Inflation Rate (IGP-DI)
    1.2 %     12.1 %     7.7 %
Results of Operations for the year ended December 31, 2005(“2005”) compared to the year ended December 31, 2004 (“2004”).
          The comparison between our results of operations for 2005 and 2004 has been affected by the 16.8% decrease in the average Real/U.S. dollar exchange rate for 2005 as compared to the average Real/U.S. dollar exchange rate for 2004. We refer to this change in the average exchange rate as the “16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.”
          The exchange variation resulting from monetary assets and liabilities related to operations of consolidated subsidiaries whose functional currency is not Reais are not eliminated in the consolidation process and such results are accounted for as cumulative translation adjustments.
          Certain prior year amounts have been reclassified to conform to current year presentation standards. These reclassifications had no impact on the Company’s net income.

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Revenues
          Net operating revenues increased 46.6% to U.S.$56,324 million for 2005, as compared to U.S.$38,428 million for 2004. This increase was primarily attributable to an increase in prices of our products, both in the domestic market and outside Brazil, an increase in sales volume in the domestic market, and the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
          Consolidated sales of products and services increased 42.6% to U.S.$74,065 million for 2005, as compared to U.S.$51,954 million for 2004, primarily due to the increases mentioned immediately above.
          Included in sales of products and services are the following amounts that we collected on behalf of the federal or state governments:
    Value-added (ICMS), PASEP, COFINS and other taxes on sales of products and services and social security contributions. These taxes increased 34.7% to U.S.$14,694 million for 2005, as compared to U.S.$10,906 million for 2004, primarily due to the increase in prices and sales volume of our products and services; and
 
    CIDE, the per-transaction tax due to the Brazilian government, which increased 16.3% to U.S.$3,047 million for 2005, as compared to U.S.$2,620 million for 2004. This increase was primarily attributable to the increase in sales volume of our products and services and to the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Cost of sales (excluding Depreciation, Depletion and Amortization)
          Cost of sales for 2005 increased 40.2% to U.S.$29,828 million, as compared to U.S.$21,279 million for 2004. This increase was principally a result of:
    a U.S.$1,834 million increase in taxes and charges paid to the Brazilian government totaling U.S.$5,410 million for 2005, as compared to U.S.$3,576 million for 2004, including an increase in the special participation charge (an extraordinary charge payable in the event of high production and/or profitability from our fields) to U.S.$3,016 million for 2005, as compared to U.S.$1,883 million for 2004, as a result of higher international oil prices;
 
    a U.S.$1,654 million increase in the cost of imports due to higher prices for the products imported;
 
    a U.S.$1,375 million increase in costs attributable to: (1) maintenance and technical services for well restoration, materials, support for vessels, undersea operations, freight with third parties (these prices tend to accompany to international oil prices) consumption of chemical products to clear out and eliminate toxic gases – principally at Marlim; and (2) higher personnel expenses primarily related to: overtime payments as set forth in our collective bargaining agreement; an increase in our workforce; and a revision in the actuarial calculations relating to future health care and pension benefits;
 
    a U.S.$1,281 million increase in costs associated with our international trading activities, due to increases in volume and prices from offshore operations, conducted by PIFCo;
 
    a U.S.$561 million increase in costs associated with a 9.0% increase in our international market sales volumes;
 
    a U.S.$534 million increase in costs in our Argentinean subsidiary PEPSA mainly due to oil products purchases as a result of total capacity utilization of its refineries and higher sales volume of petrochemical products;
 
    a U.S.$198 million increase in costs associated with a 1.7% increase in our domestic sales volumes; and

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    the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Depreciation, depletion and amortization
          We calculate depreciation, depletion and amortization of exploration and production assets on the basis of the units of production method. Depreciation, depletion and amortization expenses increased 17.9% to U.S.$2,926 million for 2005, as compared to U.S.$2,481 million for 2004. This increase was primarily attributable to the following:
    increased property, plant and equipment expenditures, and increased crude oil and natural gas production; and
 
    the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Exploration, including exploratory dry holes
          Exploration costs, including exploratory dry holes increased 64.6% to U.S.$1,009 million for 2005, as compared to U.S.$613 million for 2004. We adopted the amended FAS 19-1 effective January 1, 2005, without material impact. This increase was primarily attributable to the following:
    the increase of U.S.$196 million due to a revision in the estimated expenses for dismantling oil and gas producing areas and future well abandonment that affected the exploration costs and was related to new commercial areas, increased estimates of cost to abandon and changes in asset retirement obligations estimates provided by operators in joint ventures;
 
    an increase of U.S.$98 million in geological and geophysical expenses;
 
    an increase of U.S.$16 million in dry holes expenses; and
 
    the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Impairment of oil and gas properties
          For 2005, we recorded an impairment charge of U.S.$156 million, as compared to an impairment charge of U.S.$65 million for 2004. During 2005, the impairment charge was primarily related to investments in Venezuela (U.S.$134 million), due to the tax and legal changes implemented by the Ministry of Energy and Petroleum of Venezuela (MEP). During 2004, the impairment charge was related to producing properties in Brazil and principle amounts were related to the Company’s Cioba off-shore field (U.S.$30 million). See Note 10 (d) to our consolidated financial statements for the year ended December 31, 2005.
Selling, general and administrative expenses
          Selling, general and administrative expenses increased 54.2% to U.S.$4,474 million for 2005, as compared to U.S.$2,901 million for 2004.
          Selling expenses increased 38.7% to U.S.$2,141 million for 2005, as compared to U.S.$1,544 million for 2004. This increase was primarily attributable to the following:
    an increase of U.S.$338 million in expenses mainly associated with the transportation costs of oil products due mainly to an increase in the exports; and
 
    the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
          General and administrative expenses increased 71.9% to U.S.$2,333 million for 2005, as compared to U.S.$1,357 million for 2004. This increase was primarily attributable to the following:

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    an increase of approximately U.S.$287 million in employee expenses due to the increase in our workforce and salaries; and an increase in the actuarial calculations relating to future health care and pension benefits due to changes in actuarial assumptions;
 
    an increase of approximately U.S.$212 million in expenses related to technical consulting services in connection with our increased outsourcing of selected non-core general activities; and
 
    the 16.8% increase in the average value of the Real against the U.S. dollar in 2005, as compared to 2004.
Research and development expenses
          Research and development expenses increased 60.9% to U.S.$399 million for 2005, as compared to U.S.$248 million for 2004. This increase was primarily related to additional investments in programs for environmental safety, to deepwater and refining technologies of approximately U.S.$101 million and to the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Other operating expenses
          Other operating expenses amounted to U.S.$582 million for 2005, as compared to U.S.$259 million for 2004.
          The charges for 2005 were:
    a U.S.$304 million expense for idle capacity from gas-fired power plants;
 
    a U.S.$153 million loss related to our investments in certain gas-fired power plants resulting from our contractual obligations to cover losses;
 
    a U.S.$64 million expense for unscheduled stoppages of plants and equipment; and
 
    a U.S.$61 million increase in contractual losses from compliance with our ship or pay commitments with respect to our investments in the OCP pipeline in Ecuador.
          The charges for 2004 were:
    a U.S.$110 million expense for idle capacity from gas-fired power plants;
 
    a U.S.$85 million expense for unscheduled stoppages of plant and equipment; and
 
    a U.S.$64 million increase in contractual losses from compliance with our ship or pay commitments with respect to our investments in the OCP pipeline in Ecuador.
Equity in results of non-consolidated companies
          Equity in results of non-consolidated companies decreased 19.2% to a gain of U.S.$139 million for 2005, as compared to a gain of U.S.$172 million for 2004, primarily due to the results of our investments in:(a) certain gas-fired power and petrochemical companies being lower as certain of these entities have been subsequently purchased and are now consolidated on a line by line basis; and (b) as a result of losses in investments in certain affiliated companies of Petrobras Energia Venezuela S.A, in the amount of U.S.$19 million.

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Financial income
          We derive financial income from several sources, including interest on cash and cash equivalents. The majority of our cash equivalents are short-term Brazilian government securities, including securities indexed to the U.S. dollar. We also hold U.S. dollar deposits.
          Financial income decreased 25.7% to U.S.$710 million for 2005 as compared to U.S.$ 956 million for 2004. This decrease was primarily attributable to the reduction of fair value adjustments on gas hedge transactions in the amount of U.S.$460 million.
          This decrease was partially offset by an increase in financial interest income from short-term investments, in the amount of U.S.$138 million, primarily attributable to increased investments in securities in 2005 as compared to 2004, due to higher amount of cash and cash equivalents. A breakdown of financial income and expenses is shown in Note 14 to our consolidated financial statements for the year ended December 31, 2005.
Financial expenses
          Financial expenses decreased 31.4% to U.S.$1,189 million for 2005, as compared to U.S.$1,733 million for 2004. This decrease was primarily attributable to:
    a U.S.$345 million increase in our interest expense capitalized as part of the cost of construction and development of crude oil and natural gas production projects. A breakdown of financial income and expenses is shown in Note 14 to our consolidated financial statements for the year ended December 31, 2005;
 
    a U.S.$130 million decrease of expenses related to hedge transactions; and
 
    a U.S.$120 million decrease in expenses relating to repurchases of our own securities.
Monetary and exchange variation on monetary assets and liabilities, net
          Monetary and exchange variation on monetary assets and liabilities, net generated a gain of U.S.$248 million for 2005, as compared to a gain of U.S.$450 million for 2004. The decrease in monetary and exchange variation on monetary assets and liabilities, net is primarily attributable to the effect of the 11.8% year ended value appreciation of the Real against the U.S. dollar during 2005, as compared to the 8.1% appreciation of the Real against the U.S. dollar during 2004.
Employee benefit expense for non-active participants
          The employee benefit expense consists of financial costs associated with expected pension and health care costs. Our employee benefit expense increased 52.9% to U.S.$ 994 million for 2005, as compared to U.S.$650 million for 2004. This increase in costs was primarily attributable to an increase of U.S.$212 million in the annual actuarial calculation of our pension and health care plan liability and to the 16.8% average increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.
Other taxes
          Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, decreased 15.2% to U.S.$373 million for 2005, as compared to U.S.$440 million for 2004. This decrease was primarily attributable to the decrease of U.S.$149 million in the PASEP/COFINS taxes on financial income, due to a reduction to zero in the applicable rate as of August 2, 2004. This decrease was partially offset by the 16.8% increase in the value of the Real against the U.S. dollar in 2005, as compared to 2004.

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Other expenses, net
          Other expenses, net are primarily composed of gains and losses recorded on sales of investments, institutional relations and cultural project expenses and certain other non-recurring charges. Other expenses, net increased 123.6% to U.S.$899 million for 2005, as compared to U.S.$402 million for 2004.
          The most significant charges for 2005 were: