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, 2004
Anderson Square Building
P.O. Box 714
George Town, Grand Cayman
Cayman Islands
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:
New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
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, 2004, there were outstanding:
634,168,418 PETROBRAS Common Shares, without par value
462,369,507 PETROBRAS Preferred Shares, without par value
50,000 PIFCo Common Shares
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 xNo ¨
Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ¨ Item 18 x
TABLE OF CONTENTS
ITEM 1.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 8.
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ITEM 9.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
ITEM 15.
ITEM 16A.
ITEM 16B.
ITEM 16C.
ITEM 16D.
ITEM 16E.
ITEM 17.
ITEM 18.
ITEM 19.
ABBREVIATIONS
CONVERSION TABLE
SIGNATURES
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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:
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:
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, 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 190.
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, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, 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 (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 Brazilian Corporation Law and the regulations promulgated by the Comissão de Valores Mobiliários (Brazilian Securities Commission, or the CVM) “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. Since June 2003, Ernst & Young Auditores Independentes S/S has served as our independent auditors and audited our financial statements for each of the years ending December 31, 2004 and 2003. PricewaterhouseCoopers Auditores Independentes audited our financial statements for each of the years ending December 31, 2002, 2001 and 2000.
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,
forward-looking amounts, including estimated future capital expenditures, have been projected on a constant basis and have been translated from Reais in 2005 at an estimated average exchange rate of R$3.0147 to U.S.$1.00, and future calculations involving an assumed price of crude oil have been
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calculated using a Brent crude oil price of U.S.$23.00 per barrel for 2005 and thereafter, adjusted for our quality and locational differences, unless otherwise stated; and
We signed a final agreement for the acquisition of Petrobras Energia 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 financings special purpose entities and thermoelectric plants were consolidated on a line-by-line basis in the income statement beginning as of January 1, 2004. Although there were effects in 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, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, 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, Bear Insurance Company Limited – BEAR (which Brasoil, a Petrobras subsidiary, transferred to PIFCo in January 2003) and Petrobras Netherlands B.V. (which PIFCo transferred to Petrobras in January 2003). See Item 5. “Operating and Financial Review and Prospects” and Note 1 to the PIFCo audited consolidated financial statements.
PRESENTATION OF INFORMATION CONCERNING RESERVES
The estimates of our proved reserves of crude oil and natural gas as of December 31, 2004, 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, 2004. 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 14, 2005, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling 11.1 billion barrels of crude oil and NGLs and 11,814 billion cubic feet of natural gas. The reserve estimates we filed with the ANP and those provided herein differ by more than five percent. 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. We also file reserve estimates from our international operations with various governmental agencies under the guidelines of the Society of Petroleum Engineers (SPE). The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 1.0 billion barrels of crude oil and NGLs and 5,188 billion cubic feet of natural gas, which differs by approximately 50 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.
3
Not applicable.
Selected Financial Data
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, 2004 have been derived from our audited consolidated financial statements, which were audited by Ernst & Young Auditores Independentes S/S for each of the years ending December 31, 2004 and 2003 and by PricewaterhouseCoopers Auditores Independentes for each of the years ending December 31, 2002, 2001 and 2000. 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
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories
Recoverable taxes
Advances to suppliers
Other current assets
Total current assets
Property, plant and equipment, net
Investments in non-consolidated companies and other investments
Other assets:
Accounts receivables, net
Petroleum and Alcohol Account-Receivable from the Federal government(1)
Government securities
Unrecognized pension obligation
Restricted deposits for legal proceedings and guarantees
Investments PEPSA and PELSA
Goodwill
Prepaid expenses
Marketable securities
Fair value asset of gas hedge
Others
Total other assets
Total assets
Liabilities and Shareholders’ equity
Current liabilities:
Trade accounts payable
Taxes payable
Short-term debt
Current portion of long-term debt
Current portion of project financings
Current portion of capital lease obligations
Dividends and interest on capital payable
Payroll and related charges
Advances from customers
Employees’ postretirement benefits obligations – Pension
Other current liabilities
Total current liabilities
Long-term liabilities:
Long-term debt
Project financings
Employees’ postretirement benefits obligation – Health Care
Capital lease obligations
Deferred income tax
Thermoelectric liabilities
Deferred Purchase Incentive
Provision for abandonment of wells
Other liabilities
Total long-term liabilities
Minority interest
Shareholders’ equity
Shares authorized and issued:
Preferred share
Common share
Capital reserve and other comprehensive income
Total Shareholders’ equity
Total liabilities and Shareholders’ equity
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INCOME STATEMENT DATA
Sales of products and services
Value-added and other taxes on sales and services
CIDE(1)
Specific parcel price – PPE(2)
Net operating revenues
Cost of sales(3)
Depreciation, depletion and amortization(4)
Exploration, including exploratory dry holes(4)(5)
Selling, general and administrative expenses
Other operating expense(6)
Total costs and expenses
Financial income
Financial expense
Monetary and exchange variation on monetary assets and liabilities, net
Employee benefit expense
Other non-operating income (expense), net(7)
Income before income taxes,
minority interest and accounting change
Income tax (expense) benefit:
Current
Deferred
Total income tax expense
Minority interests in results of consolidated subsidiaries
Income before effect of change in accounting principle
Cumulative effect of change inaccounting principle, net of taxes(4)
Net income for the year
Weighted average number of shares Outstanding:(8)
Common/ADS
Preferred/ADS
Basic and diluted earnings per share:
Common/ADS(9)
Preferred/ADS(9)
Cash dividends per share(10):
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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, 2004 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, 2004 and 2003 and by PricewaterhouseCoopers Auditores Independentes for each of the years ended December 31, 2002, 2001 and 2000. 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.”
Income Statement Data:
Sales of crude oil and oil products and Services:
Related Parties
Lease income(1)
Operating Expenses:
Cost of sales
Lease expense(1)
Selling, general and Administrative expenses
Related parties
Operating income
Financial income(2)
Total
Financial expense(3)
Gain on materials and equipment
Other income, net
Net income (loss)
Balance Sheet Data (end of period):
Cash and cash Equivalents
Trade accounts receivable
Notes receivable
Export Prepayment
Marketable Securities
Other
Notes payable
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Short-term financing and current portion of long-term debt
Total stockholders’ equity
Total liabilities and stockholders’ equity
Exchange Rates
Until March 14, 2005, there were two principal foreign exchange markets in Brazil, the commercial rate exchange market and the floating rate exchange market. The National Monetary Council enacted Resolution No. 3.265, dated March 4, 2005, consolidating both exchange markets in one single Foreign Exchange Market, effective as of March 14, 2005. Before this recent unification of the markets, the commercial rate exchange market and the floating rate exchange market practiced similar prices and had similar liquidity but were subject to different regulation. 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.
All foreign exchange transactions are now carried out in the unified foreign 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 continue to be 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. As of June 23, 2005, the Real has appreciated to R$2.3932 per U.S.$1.00, representing an appreciation of approximately 9.8% in 2005 year-to-date. The Real may depreciate or appreciate substantially in the future. “—Risk Factors—Risks Relating to Brazil.”
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The following table provides information on the selling exchange rate, expressed in reais per U.S. dollar (R$/US$), for the periods indicated. The table uses the commercial selling rate prior to March 14, 2005.
Year ended December 31,
2004
2003
2002
2001
2000
Month
December 2004
January 2005
February 2005
March 2005
April 2005
May 2005
June 2005 (through June 23)
Source: Central Bank of Brazil
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, including measures relating to remittances related to our preferred or common 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.
A significant amount 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.$38.21 per barrel for 2004, U.S.$28.84 per barrel for 2003 and U.S.$25.02 per barrel for 2002. 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:
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We expect continued volatility and uncertainty in international prices for crude oil and oil products. 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 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 1500 meters) and ultra deep water (above 1500 meters). Deep water drilling represented approximately 56.6% of the exploratory wells drilled in 2004, a higher proportion than for many other oil and gas producers.
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 and may prove to be incorrect over time, 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 2004, we experienced spills totaling 140,000 gallons of crude oil, as compared to 73,000 gallons in 2003 and 52,000 gallons in 2002. 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. 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
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us to incur significant costs to remedy any damage that a project may cause to the environment (compensação ambiental). 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.” In addition, recent changes in Brazilian laws relating to retirement benefits affecting our employees may increase our exposure to labor litigation in the future.
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 a 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 the Imposto sobre Circulação de Mercadorias e Serviços (state sales tax, or ICMS) on upstream activities. Although the law is technically in force, the government of the State of Rio de Janeiro has yet to enforce 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 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. The constitutionality of this law is currently being challenged at the Brazilian Supreme Court. If the law is declared constitutional and the State of Rio de Janeiro enforces the law against us, 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$5.85 billion (U.S.$2 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 former Brazilian government to promote the development of thermoelectric power plants, development of such plants has been slow. We have invested in 12 (ten in operation and two under construction or development) of the 39 gas-fired power generation plants being built or proposed to be built in Brazil under the program to promote the development of thermoelectric plants, known as the Programa Prioritário de Termoeletricidade (Thermoelectric Priority Program, or PPT). Demand for energy produced by our thermoelectric plants has been lower than we expected mainly as a
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result of good hydrological conditions in the last years that increased the supply and lowered the prices of energy from hydroelectric power plants.
In 2002, the Brazilian Congress passed a law increasing government intervention in the domestic power market, and in 2003 the current administration proposed a new regulatory model for the energy sector. Although the new model for the energy sector creates certain incentives for investments in power generation, the changes implemented by it have not reduced our risks of losses. See Item 4. “Information on the Company—Natural Gas and Power—New Regulatory Model.”
Our participation in the domestic power market has generated losses and may not become profitable and it may continue to adversely affect our operating results and financial condition.
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 80% 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 2004 we imported U.S.$6.9 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% and 8.1% against the U.S. dollar in 2003 and 2004, respectively. As of June 23, 2005, the exchange rate of the Real to the U.S. dollar was R$2.3932 per U.S.$1.00, representing an appreciation of approximately 9.8% in 2005 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 devaluation 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, 2004, approximately 55% 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 a material 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, and as a result, we could suffer losses that could have a material adverse effect on our financial condition or results of operations. If 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
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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 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:
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, resulting in a material adverse effect on our results of operations and financial condition.
Of the countries in which we operate, our operations in Argentina are the most significant, representing approximately 5.6% of our total crude oil and natural gas production and 3.3% of our proved crude oil and natural gas reserves at December 31, 2004. In response to the Argentine crisis, the Argentine government has made a number of changes in the regulatory structure, including increasing government control over the price structure of many industries, such as the oil and gas sector. In addition, our operations in Bolivia represented approximately 2.3% of our total production in barrels of oil equivalent and 2.8% of our proved crude oil and natural gas reserves at December 31, 2004. Recent political unrest in Bolivia has targeted foreign companies’ participation in Bolivia’s natural gas industry, which resulted in a significant increase in royalties and taxes in May 2005 and calls by some groups for nationalization of the energy industry. Protests by opposition groups eventually led to the resignation of President Carlos Mesa in June 2005, after a mere 19 months in office. The Bolivian political, economic and social situation, generally, and the country’s energy policy, in particular, remains extremely volatile and unpredictable. Future policy decisions in Argentina and Bolivia may adversely affect our investments in each country. A deterioration in the situation of Argentina and Bolivia may have a material adverse effect on our results of operation 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 third parties 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:
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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 third-party creditors. At December 31, 2004, approximately 15.5% 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 on 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 prevailing prices on 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, 2004 was U.S.$282 million. All price controls for crude
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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. We possess the exclusive right to develop our reserves pursuant to concession agreements awarded to us by the Brazilian government, 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:
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, financial condition and results of operations.
Our principal market is Brazil, which has, in the past, periodically experienced extremely high rates of inflation. Inflation, along with recent 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 Consumer Price Index (Índice Nacional de Preços ao Consumidor), have decreased from 2,489.1% in 1993 to 929.3% in 1994 and to 5.3% in 2000. The same index increased to 9.4% during 2001 and to 14.7% in 2002, before decreasing to 10.4% in 2003 and to 6.1% in 2004.
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Brazil may experience high levels of inflation in the future. The lower levels of inflation experienced since 1994 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 results of operations and financial condition.
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.”
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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 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 mixed-capital 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 PIFCo. If we are required to make payments under the standby purchase agreement, Central Bank of Brazil
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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, Mr. Nilton de Almeida Maia, 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:
then our obligations under the standby purchase agreement could be avoided, or claims in respect of 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.
History and Development of Petrobras
We are a mixed-capital company created pursuant to Law No. 2,004 (effective as of October 3, 1953). A mixed-capital 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 federal government, but our common and preferred shares are also publicly traded. Our principal executive office is
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located at Avenida República do Chile, 65, 20035-900 - Rio de Janeiro - RJ, Brazil and our telephone number is (55-21) 3224-4477.
We began operations in Brazil in 1954 as a wholly-owned government enterprise responsible for all hydrocarbon activities in Brazil. 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 eliminated our legal monopoly.
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 in order to benefit end-users. 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 2004 consolidated revenues, we are the largest corporation in Brazil and one of the largest oil and gas companies in Latin America. In 2004, we had sales of products and services of U.S.$51,954 million, net operating revenues of U.S.$37,452 million and net income of U.S.$6,190 million.
We engage in a broad range of oil and gas activities, which cover the following segments of our operations:
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 weaknesses in our internal control over financial reporting identified by management.
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The report will also contain a statement that our auditors have issued an attestation report on management’s assessment of such internal controls. To comply with this requirement, we are creating a system of internal controls over financial reporting based on the recommendation of the Committee of Sponsoring Organizations of the Treadway Commission (COSO), formed by accounting and auditing companies in the United States. The COSO system is expected to be the prevailing system adopted by companies subject to Section 404 of the Sarbanes-Oxley Act. The implementation of the COSO system is being conducted in five different levels with the participation of our chief financial officer and chief executive officer, our internal control committee formed by executive officers of our business areas, the managers of each of our business units, our internal auditors and our Board of Directors.
Our Competitive Strengths
We have a number of key strengths, including:
Our 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 decreased 3.1% in 2004, as compared to an increase of 2.7% in 2003 and 12.3% in 2002.
Our strong reserve base
As of December 31, 2004, we had estimated proved developed and undeveloped crude oil and natural gas reserves of approximately 11.82 billion barrels of oil equivalent in Brazil and abroad. In addition, we have a 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, 2004, our worldwide proved reserves to production ratio was 16.9 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 strategic plan for the period from 2004 to 2010, or Strategic Plan, 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.
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Our deepwater technological expertise
While developing Brazil’s offshore basins over the past 35 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 2004, excluding government take, increased to U.S.$4.33 per barrel of oil equivalent, as compared to U.S.$3.48 per barrel of oil equivalent for 2003. Including government take, our lifting costs increased to U.S.$10.77 per barrel of oil equivalent for 2004, as compared to U.S.$8.62 per barrel of oil equivalent for 2003.
Our cost efficiencies created by our large scale operations combined with our vertical integration within each of our business segments
As the dominant integrated crude oil and natural gas company in Brazil, we can be cost efficient as a result of:
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.
Our strong position in Brazil’s potentially growing natural gas markets
We participate in most aspects of the Brazilian natural gas market. At present, the demand for natural gas is limited, due in part to a distribution infrastructure that is still developing. The prices we realize for natural gas, which depend on the costs of other energy sources it can replace, are less than half of the current market price in the United States, where demand is more developed. The demand for natural gas in Brazil increased 22% in 2004, outpacing the 14% average increase in demand of the previous four years. 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:
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Our 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.”
Our Business 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:
Expand production while increasing reserves
We seek to generate production growth from the continued development of our proved undeveloped reserve base of 6.2 billion barrels of oil equivalent at December 31, 2004, representing 52.1% of our total proved reserves. Our 2004-2010 budget contemplates capital expenditures of approximately U.S.$53.6 billion in development activities for this seven-year period, including U.S.$5.9 billion to be financed through project financings. The majority of these capital expenditures, U.S.$32.1 billion, will be directed towards exploration and production activities, of which U.S.$26.2 billion will be directed towards domestic exploration and production activities. We intend to increase our effort in production to produce lighter crude oil from our newly discovered reserves.
At the same time that we seek to expand production, we intend to increase our proved reserves, principally through exploration focused on deepwater exploration in Brazil. We have net exploration, development and production rights in 26.8 million acres (108,291 square kilometers) in Brazil. We expect to continue to participate
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selectively with major regional and international oil and gas companies in bidding for new concessions and in developing our large offshore fields.
We also intend to pursue international exploration and production opportunities with industry participants primarily in South America, the Gulf of Mexico and the west coast of Africa. As a result of this strategy, we participate in joint ventures, which have resulted in discoveries in Agbami and Akpo (off the coast of Nigeria) and in a deepwater field in the Gulf of Mexico (Cascade Project). In 2004, we participated in a tender for exploration blocks in Libya and Iran. At December 2004, we had exploration, development and production rights in 19.2 million gross and 9.7 million net acres (78,000 gross and 39,000 net square kilometers) outside Brazil.
Upgrade our refineries to increase their ability to process heavier domestic crude production while at the same time fulfilling a growing percentage of the current demands of the Brazilian market and meeting stricter quality standards.
Our refineries were originally constructed to process light imported crude oil, whereas our current reserves and production increasingly consist of heavier crude oil. We plan to improve and adapt our refineries to better process our domestic production of heavier crude oil by continuing to:
Expand international operations through internal growth and by participating selectively in new partnerships in core areas where we have competitive advantages.
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 and West Africa. We acquired exploration interests in Iran, Argentina, Colombia, in the Gulf of Mexico and Tanzania during 2004 and we have recently acquired an exploration interest in Libya.
Develop and improve systematic, company-wide initiatives to address health, safety and environmental concerns and ensure compliance with environmental regulations
The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated oil, gas and energy company. In order to address and prioritize health, safety and environmental concerns and ensure compliance with environmental regulations, we have taken several measures, of which the most extensive is the Programa de Excelência em Gestão Ambiental e Segurança Operacional (Program for Excellence in Environmental Management and Operational Safety, or PEGASO). Through the program, we seek to improve technology, upgrade our pipelines, reduce emissions and wastes, improve our emergency response readiness and prevent environmental accidents. Another important initiative is the Programa de Segurança de Processo (Process Safety Program) that aims to strengthen our corporate commitment to safety through the implementation of standardized, company-wide health, safety and environmental guidelines. See “Health, Safety and Environmental Initiatives.”
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Expand the natural gas market in Brazil to ensure a market for the natural gas that we produce or acquire through existing off take obligations
Through our participation in all segments of the natural gas market, both in Brazil and abroad, we seek to stimulate and meet natural gas demand. We intend to continue to expand our participation in the natural gas market by:
As a result of our investments and the growing importance of natural gas as an energy alternative, we anticipate that the proportion of our revenues and assets represented by our natural gas operations will increase, leading to a greater impact of these activities on our results of operations.
Operate successfully and transparently in a deregulated market.
Since the beginning of market liberalization in 1997 and price deregulation in 2002, we have been preparing for market competition. In order to meet the challenges of competition, we have:
We continue the process of transforming our corporate culture and bylaws to encourage greater transparency and accountability to shareholders, and we believe that these corporate changes better position us to compete in a deregulated market, increase investor confidence in our company and enhance our market value.
In addition to the changes we have implemented in our bylaws, we have adopted the following policies and procedures:
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
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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.
Meet targeted operating costs and return on capital, while being socially and environmentally responsible and contributing to the development of Brazil and other countries where we operate.
We are undertaking a number of initiatives to control our operating costs. We are targeting a reduction in the aggregate average lifting costs in Brazil for crude oil and natural gas in order to achieve lifting costs of U.S.$3.00 per barrel of oil equivalent in 2010 (excluding government take) as compared to U.S.$4.33 per barrel of oil equivalent in 2004. We will seek to reduce our operating costs per barrel by a number of means, including:
Up to now, these measures have not been effective in reducing our lifting costs, which have increased over the last three years, primarily because (1) approximately 60% of our lifting costs are denominated in Reais, which appreciated against the U.S. dollar by 18.2% and 8.1% in 2003 and 2004, respectively and (2) costs associated with oil field services tend to increase when the price of oil increases, which has occurred over the last few years. See Item 4. “Information on the Company—Exploration, Development and Production—Production Activities.”
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, 2004, our estimated net proved crude oil and natural gas reserves in Brazil were approximately 10.6 billion barrels of oil equivalent. Crude oil represented 87.5% and natural gas represented 12.5% of these reserves. Our proved reserves are located principally in the Campos Basin.
During 2004, our average daily domestic production was 1.5 million barrels per day of crude oil and NGLs and 1,590 billion cubic feet of natural gas per day. Our aggregate average lifting costs for crude oil and natural gas in 2004 were U.S.$4.33 per barrel of oil equivalent in Brazil (excluding government take).
We conduct our 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 concession as Round O. In a number of our concessions, we have agreed with foreign partners to jointly 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.
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At December 31, 2004, we held 374 areas, representing 26.8 million net acres (108,291 square kilometers). We currently have joint venture agreements for exploration and production in Brazil with approximately 29 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 exploration acreage through our participation in bidding rounds that have been conducted annually by theAgência Nacional de Petróleo (the National Petroleum Agency, or the ANP) since 1999.
Our main strategies in exploration, development and production in Brazil are to:
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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 1,493 Mbpd in 2004, which represented a decrease from the 1,540 Mbpd produced in 2003. 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.
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, we discovered over 40 hydrocarbon reservoirs have been discovered in this region in a 6.3 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. In 2004, Campos Basin’s oil production decreased to 1,203.7 Mbpd from 1,252 Mbpd in 2003. Campos Basin’s oil production accounted for approximately 80% of Brazilian oil production.
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At December 31, 2004, we produced crude oil from 31 fields in the Campos Basin and our proved crude oil reserves were 8.1 billion barrels, representing 81.4% of our total proved crude oil reserves. In 2004, the crude oil we produced in the Campos Basin had an average API gravity of 23.5° and an average water cut of 1.2%. We currently have 23 floating production systems, 13 fixed platforms and 3,643 kilometers of pipeline operating in 31 fields at water depths of 262 to 6,188 feet (80—1,886 meters) in the Campos Basin.
Santos Basin
The Santos Basin represents one of our most active and promising exploration areas. We currently have exploration rights to 20 blocks in the Santos Basin, with a combined acreage of 28.5 thousand square kilometers (as compared to 6.3 thousand square kilometers under concession in the Campos Basin). Current production of oil and natural gas is 11.0 Mboe per day in the Coral and Merluza fields.
Espírito Santo Basin
In partnership with Shell and Chevron Texaco, we have made several discoveries of heavy crude oil. We currently have exploration rights to 15 blocks in the Espírito Santo Basin, with a combined acreage of 5.7 thousand square kilometers. During 2004, we produced 40.9 Mboe per day of oil and natural gas in the Espírito Santo Basin (28.2 Mboe onshore and 12.7 Mboe offshore).
Solimões Basin
The Solimões Basin is primarily a natural gas producing region, which covers approximately 235 million acres (950,000 square kilometers) in the Amazon region. During 2004, we produced 116.1 Mboe per day of oil and natural gas in the Solimões Basin.
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 Oil andNatural GasProduction forthe Year
EndedDecember 31,
Brazil(1)
Offshore
Other offshore
Total offshore
Onshore
Total Brazil
International
Total International
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The following table sets forth our total gross and net productive wells as of December 31, 2004:
Gross productive wells
Brazil
Net productive wells
Productive wells are producing wells and wells capable of production. A gross well is a well 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 well is the sum of the fractional working interests owned in gross wells expressed as hole numbers and fractions thereof.
Deepwater Expertise
We are a leader in deepwater drilling, with recognized expertise in deepwater exploration, development and production. We have developed our expertise over many years and have achieved significant milestones, including the following:
Because many of Brazil’s richest oil fields are located offshore in deep waters, we intend to continue to focus on our 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 our 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 of an offshore well are generally higher than those costs for an onshore well. We believe, however, that offshore production is cost-effective, because historically:
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 2004 and 2003.
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OFFSHORE PRODUCTION BY WATER DEPTH
Depth
0-400 meters (0-1,312 feet)
400-1,000 meters (1,312 feet-3,281 feet)
More than 1,000 meters (3,281 feet)
Exploration Activities
Our Concessions in Brazil
We had the right to exploit all exploration, development and production areas in Brazil as a result of the monopoly that was granted to us by the Brazilian government. When the Brazilian oil and gas sector was deregulated beginning in 1998, our government-granted 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, 2004, we had 374 areas, consisting of 233 production areas, 96 exploration areas and 45 development areas, for a total area aggregating 37.8 million gross acres (153.1 thousand square kilometers). This total area represents 2.4% of the Brazilian sedimentary basins.
Recent discoveries
During 2004, we discovered five new crude oil fields onshore, two of them in the Potiguar bay, and the other three in the states of Bahia, Alagoas and Espírito Santo. These discoveries were not significant as compared to our crude oil discoveries in 2003. As a result, during 2004 we focused our efforts on proving and developing the reserves discovered in 2003. During this process, we found reservoirs of light crude oil and gas in the Espírito Santo Basin in 2004. In the first quarter of 2005, we found reservoirs of light crude oil in the Santos Basin.
Exploration bidding rounds
Since 1999, the ANP has conducted bidding rounds for exploration rights, which are open to us and qualified third parties. We have competed in the public auctions conducted by the ANP, acquiring a large number of exploration rights, as detailed in 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:
Event
Areas held (December 31, 2001)
Areas relinquished (May 2002) (BA-1)
Areas won on Bid, Round 4
Areas relinquished (August 6, 2002) (BM-CAL-1 and BM-C-6)
Areas relinquished (August 2002) (BS-2)
Areas relinquished (September 2002) (BES-2)
New concession (February 6, 2002) (Siri)
New concession (August 27, 2002) (Asa Branca)
New concession (November 22, 2002) (Manati)
New concession (December 11, 2002) (Jubarte)
New concession (December 27, 2002) (Cachalote)
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Areas relinquished (March 13, April 24, 2002
Areas redefined (April 26, May 10, August 6, August 10, October 9 and December 12, 2002)
Areas relinquished (Caraúna - PETROBRAS not operator)
Areas held (December 31, 2002)
Areas redefined (July 2003) (BCAM-40)
Areas relinquished (August 6, 2003)
Areas won on Bid, Round 5
New concession (January 29, 2003) (Guajá)
New concession (August 4, 2003) (Cavalo-Marinho)
Areas redefined (February 3, 2003) (Coral)
Areas redefined (July 15, 2003) (Beija-Flor)
Joint concession COG to CCN (1)
Joint concession CDL to MP (2)
Areas relinquished (BAS-104)
Areas relinquished (Arraia)
Joint concession CR to FZB
Areas relinquished (ALS-32)
Areas held (December 31, 2003)
Areas won on Bid, Round 6
Areas obtained through acquisitions (BT-REC-4, BT-POT-9, BT-ES-4, BM-C-14, BM-S-14 and BM-S-22)
Joint concession SMI to PJ
New concession (January 15, 2004) (Baleia Branca)
New concession (January 15, 2004) (Golfinho)
New concession (January 15, 2004) (Mexilhão)
New concession (January 19, 2004) (Azulão)
New concession (January 19, 2004) (Japim)
New concession (August 30, 2004) (Piranema)
New concession (December 20, 2004) (Baleia Anã)
New concession (December 20, 2004) (Baleia Azul)
New concession (December 20, 2004) (Baleia Bicuda)
New concession (December 22, 2004) (Salema Branca)
Total areas held (as of December 31, 2004)
Net area held in million acres (as of December 31, 2004)
Joint Ventures
As of December 31, 2004, we had 65 exploration and development agreements with respect to our concessions with numerous oil and gas companies. Our percentage participation ranges from 20% to 90%, and in 44 of the 65 agreements, we are principally responsible for conducting the exploration and development activities. During 2004, we entered into 20 partnership projects relating to exploration activities. As of December 31, 2004, we had partnerships with 29 foreign and domestic companies. The exploration and development activities we conduct through joint ventures do not represent a material percentage of our total exploration and development activities.
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Drilling Activities
During 2004, we drilled a total of 355 wells, 279 development wells and 76 exploratory wells. Of those wells, 211 development wells and 27 exploratory wells were located onshore and 68 development wells and 49 exploratory wells were located offshore. We plan to drill 440 new development wells during 2005. These numbers refer to the wells we drilled in 2004, but such wells may not have been evaluated or reclassified in 2004. The table “Exploratory and Development Wells” below indicates the number of wells which were evaluated and reclassified in 2004.
We plan to expand our exploration and development activities in 2005 by:
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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
Period
Net Development Wells Drilled
The following table sets forth our total fleet of drilling rig units. We will use these owned and leased rigs to support our future exploration, production and development activities. Most of the offshore rigs are operated in the Campos Basin.
DRILLING UNITS
Land rigs for onshore exploration and development
Owned
Leased
Semi-submersible rigs
Drill ships
Jack-up rigs
Moduled rigs for offshore exploration and development
Development Activities
The development stage occurs after the completion of exploration and appraisal and prior to hydrocarbon production, and involves the development 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 our development investments in the deepwater fields located in the Campos Basin, where most of our proved reserves are located. We develop our fields in stages of production, which we refer to as modules. As of December 31, 2004, we had a total of 7,958 oil and gas producing wells in Brazil, of which 7,307 were onshore and 651 were offshore.
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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 2004 was 482.6 Mbpd, or more than 53% of total production in the Campos Basin. We have developed the Marlim field in five modules. We currently have seven floating production systems with a total capacity of 690 Mbpd operating in the Marlim field. We have a total of 83 production wells and 46 injection wells, and expect to drill one well in 2005. Peak production of 586.3 Mboe was achieved in 2002.
Roncador. The Roncador field is located at water depths between 4,921 and 6,234 feet (1,500—1,900 meters). Average production of crude oil during 2004 was 92.2 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 a capacity of 90 Mbpd. First oil from this unit was attained on December 8, 2002. A total of eight 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 the nine, which were completed before the sinking of P-36. During 2004, we made a significant discovery of crude oil in the Roncador field.
The contracts for a third production unit, with production capacity of 190 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 ten 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 2004, the average production for Marlim Sul was 179.4 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) and an FPSO unit and has a total capacity of 255 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 40.5 Mboe per day.
The contracts for a second module, with a production capacity of 180 Mbpd, were signed on June 17, 2004. 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.
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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, which was constructed in Singapore and moved to Brazil for completion and which was installed in the Barracuda field. Another FPSO unit, P-48, was converted in Brazil and started production in the Caratinga field in February 2005. Each FPSO unit has a capacity of 150 Mbpd. A total of 32 production wells and 22 injection wells are planned for the two fields.
Albacora Leste (East Albacora). Albacora Leste is located at water depths between 3,609 and 4,921 feet (1,100—1,500 meters). First oil is expected in the end of 2005. An FPSO unit (P-50) with a capacity of 180 Mbpd is currently being converted in Rio de Janeiro. A total of 16 wells and 14 injection wells are planned. We are the operator and Repsol-YPF is a partner with a 10% interest.
Other Planned Developments
Other developments include: (1) the Jubarte field, already producing through a pilot system, that consists of an FPSO unit (Seillean) with a capacity of 20 Mbpd that will, in phase I of the field development, be replaced by another FPSO (P-34) with 60 Mbpd capacity in the end of 2005, (2) the Frade field, which we are developing in partnership with Chevron Texaco and (3) the Marlim Leste field, that will have an FPSO unit (P-53) with a 180 Mbpd capacity, currently in the bidding phase. A contract to increase the production capacity of P-34 to 60 Mbpd was signed on June 17, 2004. During 2004, we made discoveries of crude oil in the Jubarte and Marlim Leste fields.
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.”
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 area, and onshore in eight Brazilian states. We are also producing crude oil and natural gas in eight other countries: Angola, Argentina, Bolivia, Colombia, Ecuador, Peru, the United States and Venezuela. See “—International.”
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The following table sets forth our average daily crude oil and natural gas production, our average sales price and our average lifting costs for each of 2004, 2003 and 2002:
Crude Oil and NGL Production (in Mbpd)
Brazil (2)
Total crude oil and NGL production
Crude Oil and NGL Average Sales Price (U.S. dollars per Bbl)
Natural Gas Production (in Mmcfpd)
Brazil(3)
Total natural gas production
Natural Gas Average Sales Price (U.S. dollars per Mcf)
Brazil(4)
International(5)
Aggregate Average Lifting Costs (oil and natural gas) (U.S. dollars per boe)
With government take
Without government take
International(6)
Average Brazilian production of crude oil and NGL for 2004 decreased 3.1% relative to 2003, reaching 1.5 million barrels per day, principally as a result of:
Reserves
Our estimated worldwide proved reserves of crude oil and natural gas as of December 31, 2004 totaled approximately 11.82 billion barrels of oil equivalent, including:
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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.
As of December 31, 2004, our domestic proved developed crude oil reserves represented 44.7% of our total domestic proved developed and undeveloped crude oil reserves. Our domestic proved developed natural gas reserves represented 55.7% 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 a compounded annual growth rate of 2.5% from the end of 1997 to 10.6 billion barrels of oil equivalent at the end of 2004. Natural gas as a percentage of total domestic proved hydrocarbon reserves increased 1.1% over the same period, representing an increase in volume from 5,782 billion cubic feet in 1997 to 7,954 billion cubic feet at the end of 2004, increasing at a compounded annual growth rate of 5.4% from the end of 1997 to 2004.
DeGolyer and MacNaughton, or D&M, reviewed and certified 91% of our domestic proved crude oil, condensate and natural gas reserve estimates as of December 31, 2004. The estimates for the certification were performed in accordance with Rule 4-10 of Regulation S-X of the SEC.
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, 2004, 2003 and 2002:
WORLDWIDE ESTIMATED NET PROVED RESERVES
CombinedGlobalProvedReserves
Net Proved Developed and Undeveloped Reserves:
Reserves as of December 31, 2002
Revisions of previous estimates
Extensions, discoveries and improved recovery
Purchase of reserves in place
Sales of reserves in place
Production for the year
Reserves as of December 31, 2003
Reserves as of December 31, 2004
Net Proved Developed Reserves:
As of December 31, 2002
As of December 31, 2003
As of December 31, 2004
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The following tables set forth our crude oil and natural gas proved reserves by region, as of December 31, 2004, 2003 and 2002:
CRUDE OIL NET PROVED RESERVES BY REGION
Proved
Developed and
Undeveloped
Developed
Other South America(1)
West Coast of Africa
Gulf of Mexico
Total international
NATURAL GAS NET PROVED RESERVES BY REGION
and
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
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.
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We own and operate 11 refineries in Brazil, with a 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 98.6% of the Brazilian refining capacity. We built nine of our 11 refineries prior to 1972, and we completed the last refinery (Henrique 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 larger reserves of heavier crude oil in Brazil. As a result, we are continually upgrading and improving our refineries to process a heavier crude slate.
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 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 the market is deregulated and 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 our production of oil products exceeds Brazilian demand or our refineries are unable to process our 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 2004 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 we believe 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:
Our refining, transportation and marketing results are reflected in the “Supply” segment in our audited consolidated financial statements.
Refining
On December 31, 2004, we had a total refining installed capacity of approximately 2.1 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 2004. Worldwide, we processed an average of 1.8 million barrels of oil per day in 2004, which represents a utilization rate of 85% for the year, calculated on total capacity. This compares with an 81% average utilization rate in 2003 and an 83% average utilization rate in 2002.
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Our domestic production in 2004 supplied approximately 76% of the crude oil feedstock for our refinery operations in Brazil, as compared to 80% in 2003 and 79% in 2002. We expect an increasing percentage of our 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 98.6% 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 a heavy concentration in the Southeast region of the country where the 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 our access to crude oil supply and major end-user markets in Brazil.
Refinery Production and Capacity
For 2004, we processed, in Brazil, 623 million barrels of crude oil or 1.7 million barrels per day. Our average refining costs (consisting of variable costs and excluding depreciation and amortization) in Brazil were U.S. $1.36 per barrel in 2004, U.S.$1.17 per barrel in 2003 and U.S.$0.91 per barrel in 2002. Our production in Brazil supplied approximately 76% of this crude oil. Due to the heavier crude characteristic of many Brazilian fields, we have invested in equipment and machinery that allows us to convert heavy crude oil to lighter products. The majority of our heavy crude conversion capacity is located in our largest refineries located near our heavy crude oil reserves in the Campos Basin: Landulpho Alves, Duque de Caxias, Paulínia, Presidente Bernardes, Gabriel Passos and Henrique Lage.
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The following table describes the installed capacity, refining throughput and utilization of our refineries for each of 2004, 2003 and 2002:
REFINING STATISTICS
Refineries
Capacity
(Mbpd)
Throughput(1)
Utilization(2)
(%)
Paulínia
Landulpho Alves
Duque de Caxias
Henrique Lage
Alberto Pasqualini(3)
Pres. Getúlio Vargas(4)
Pres. Bernardes
Gabriel Passos
Manaus
Capuava
Fortaleza
Total Brazilian
Gualberto Villarroel(5)
Ricardo Eliçabe(6)
Guillermo Elder Bell(5)
San Lorenzo (7)
Del Norte (8)
We operate our refineries, to the extent possible, to satisfy Brazilian demand. Brazil demands a proportionally high amount of diesel, relative to gasoline, both of which together represent more than half of our production. Because we operate our 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 2004, 2003 and 2002:
DOMESTIC PRODUCTION VOLUME OF OIL PRODUCTS
Product
Diesel
Gasoline
Fuel oil
Naphtha and jet fuel
Refinery Investments and Improvements
In recent years, we have made investments in our refinery assets in order to improve our 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 our refinery operations is to maximize throughput of domestic crude oil. Since our heavy domestic crude oil produces a higher proportion of fuel oil for each barrel of crude oil processed, production
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of fuel oil is expected to remain relatively constant as throughput of additional Brazilian crude oil offsets new investment in conversion capacity.
We plan to invest in refinery projects designed to:
Major Refinery Projects
Included in our Strategic Plan are a number of upgrades to our key refineries. Our major investments are generally (1) coking units to further break down our 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% to metropolitan regions around Brazil, thus meeting stricter environmental standards being implemented under Brazilian law. The principal refineries and planned investments are as follows:
Refinery
Objective
Imports
During 2004 we continued to import crude oil and oil products because our own production is not sufficient to satisfy Brazilian demand. In addition, because the bulk of our domestic reserves consist of heavy crude oil, we need
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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 increased to 450,000 barrels per day in 2004, as compared to 319,000 barrels per day in 2003 because Brazilian demand for oil products increased in 2004 and, although we refined more domestic crude oil in 2004 as compared to 2003, it was not sufficient to meet the increased Brazilian demand. We opted to import more crude oil instead of oil products to meet the increased demand for oil products in Brazil in 2004. The average daily volume of imports of crude oil decreased from 326,000 barrels per day in 2002 to 319,000 in 2003. The following table sets forth the percentage of crude oil that we imported during each of 2004, 2003 and 2002 by region.
IMPORTS OF CRUDE OIL BY REGION
Region
Africa
Middle East
Central and South America/Caribbean
Oceania
Europe
In 2004, our total costs of imports of crude oil from all these regions was U.S.$5,191 million, as compared to U.S.$3,541 million in 2003 and U.S.$3,162 million in 2002.
We purchased approximately 17.7% of our 2004 crude oil imports and 23.4% of our 2003 crude oil imports pursuant to one-year term contracts, which are considered to be long-term contracts within the industry standard practice. During 2004 we had one long-term contract providing for the supply of crude oil to us in Brazil with suppliers from Saudi Arabia. This contract was renewed under the same terms and will expire on January 31, 2006. We are also a significant buyer of crude oil and oil products from suppliers in the international spot market.
The volume of imports of oil products also decreased to 109,981 barrels per day in 2004, as compared to 121,827 barrels per day in 2003 and 215,121 barrels per day in 2002, primarily as a result of the increase in the domestic refinery production. The following table sets forth the volume of oil products that we imported during each of 2004, 2003 and 2002:
IMPORTS OF OIL PRODUCTS
Oil Product
LPG
Distillates(1)
Naphtha
Others(2)
In 2004, our total costs of oil product imports, measured on a cost-insurance-and-freight basis, was U.S.$1,721 million, as compared to U.S.$1,542 million in 2003 and U.S.$2,086 million in 2002. 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.”
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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 decreased to 186,221 Mbbl in 2004 from 192,545 Mbbl in 2003 as a result of the increase in Brazilian demand for oil products. The following table sets forth the volumes of oil products we exported during each of 2004, 2003 and 2002:
EXPORTS OF OIL AND OIL PRODUCTS(1)
Crude oil
Fuel oil (including bunker fuel)
The total value of our crude oil and oil products exports, measured on a free-on-board basis, was U.S.$5,923 million in 2004, U.S.$5,335 million in 2003 and U.S.$4,760 million in 2002.
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 our storage terminals to comply with the requirements of the Oil Law. 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 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 offered 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 our refineries and other points of primary distribution throughout Brazil. At December 31, 2004, our onshore and offshore crude oil and oil products pipelines aggregated 6,449 miles or 10,377 kilometers in length, our natural gas pipelines aggregated approximately 6,192 miles or 9,963 kilometers in length - including the Brazilian side (1,612 miles or 2,593 kilometers) of the Bolivia-Brazil pipeline, and our flexible pipelines aggregated 1,523 miles or 2,451 kilometers in length.
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NATURAL GAS PIPELINES IN BRAZIL
CRUDE OIL AND OIL PRODUCTS PIPELINES IN BRAZIL
In March 2005, we signed all of the financing documents for the PDET project originally designed to enhance our crude oil transportation system extending from our most productive fields, located in the Campos Basin, to our refineries located in the Southeast region of Brazil.
At the end of 2003, the government of Rio de Janeiro enacted a law creating severe obstacles to the economic feasibility of the original concept of the onshore portion of PDET. After three months of ultimately unsuccessful negotiations with the Rio de Janeiro State government, 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 the increase the flow of oil produced in the Campos Basin by up to 630,000 barrels per day.
Transpetro also operates 43 storage terminals with aggregate capacity of 63.3 million barrels of oil equivalent. At December 31, 2004, tankage capacity at these terminals consisted of 34.1 million barrels of crude oil, 26.7 million barrels of oil products and fuel alcohol and 2.5 million barrels of LPG.
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Transpetro is currently evaluating alternatives to improve the efficiency of its transportation system, including evaluating improvements to the monitoring and control of the crude oil and natural gas and oil products 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. 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 2004, the centralized control and operating center began to operate a new oil pipeline (OCAB) from Barra do Furado to Cabiúnas, and a new gas pipeline (GASEB) from Sergipe to Bahia. 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, 2004, 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, with aggregate deadweight tonnage of 2.51 million:
OWNED/BAREBOAT CHARTERED VESSELS
Type of Vessel
Tankers
Liquefied petroleum gas tankers
AHTS Anchor Handling Tug Supply
FSO Floating, Storage and Offloading
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 Strategic Plan calls for an investment of U.S.$1.2 billion from 2004 to 2010 to renew our fleet, by adding 53 additional 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
Oil Products
Fuel Alcohol
Percentage transported by our owned/bareboat chartered fleet
Coastal transport as a percentage of total tonnage
The average monthly-chartered tonnage in 2004 amounted to 4.6 million deadweight tons, as compared to 4.0 million deadweight tons in 2003 and 3.9 million deadweight tons in 2002. 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.$701 million in 2004, U.S.$537 million in 2003 and U.S.$431 million in 2002.
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Petrochemicals
We conduct our petrochemical activities through our subsidiary, Petrobras Química S.A., or Petroquisa, with the exception of naphtha sales. Petroquisa is a holding company that holds interests in eight operational petrochemical companies involved in the production and sale of basic petrochemical products, derivative petrochemical products and utilities. At December 31, 2004, 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.$918 million on December 31, 2004. Most of such interests are minority voting interests. In 2004, Petroquisa increased its participation in one of its investees, Petroquímica Triunfo, from 45.22% to 70.45% of its voting capital and from 59.92% to 85.04% of its total capital, through an acquisition from Dow Chemical for U.S.$ 32.5 million.
The basic supply feedstock used in Brazil’s petrochemical industry is naphtha, an oil based product. Until 2001, we were the sole supplier of naphtha to Brazil’s petrochemical industry. Following deregulation of the product in 2002, the petrochemical industry began importing naphtha directly. In 2004, the industry imported approximately 33% of its naphtha needs, and we supply the remainder from our refining operations.
Our petrochemicals business, based on the equity in results of affiliate companies, accounted for U.S.$13 million in 2004. 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 solidify our involvement in the entire value chain, integrating refining and basic and derivative products. Although we have divested certain interests in the petrochemical segment in the past, we plan to increase the current level of our 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., which is located next to our Duque de Caxias refinery (REDUC). 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, of which our portion is approximately U.S.$72 million. At December 31, 2004, we had spent approximately U.S.$66 million of this total. We expect Rio Polímeros to be operational by mid-2005 with nominal capacity plant of 540,000 tons per year of polyethylene and 79,000 tons per year of propylene. The polyethylene and propylene will be produced from ethane and propane extracted from natural gas originated in the Campos Basin.
According to our 2004-2010 Strategic Plan, we intend to spend approximately U.S.$1.1 billion in capital expenditures in our petrochemicals operation from 2004 to 2010. Such investment will be aimed at increasing production of our basic petrochemicals, including polyolefins (polyethylene and polypropylene), acrylic acid and terephtalic acid. These projects will be carried out in conjunction 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. This opportunity is now under study.
In April 2005, we sold our interest in Companhia Alagoas Industrial – CINAL for US$2.9 million, as its output was not related to our core business.
On April 29, 2005, Odebrecht, Norquisa and ODBPAR (the Odebrecht Group) and Petroquisa entered into a second amendment of the memorandum of understanding, which granted an option to Petroquisa 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”). Petroquisa must do so by December 31, 2005, through the contribution of its ownership interest in companies located in the Triunfo Petrochemical Complex and in other companies considered strategic by Braskem (which we refer to as “Assets”). If the value of the Assets is
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insufficient for Petroquisa to obtain the desired level of ownership, Odebrecht Group will sell the remaining Option Shares. On the other hand, if the value of the Assets would permit Petroquisa to increase its participation in Braskem to more than 30% of Braskem voting shares, Petroquisa will be limited to 30% and will use the additional Assets to acquire class “A” preferred shares. Petroquisa must inform the other parties to the agreement what assets it intends to contribute by September 29, 2005. Odebrecht Group has the right to terminate the option if it determines that Petroquisa has not included in the Assets its ownership interests in companies that Odebrecht Group considers essential in the Triunfo Petrochemical Complex.
The valuation process of the Assets in order to allow for the possible exercise of the option will begin by October 14, 2005. The Option Shares will be valued using the discounted cash flow method, without giving effect to any control premium. The Second Amendment eliminates the restriction on Petroquisa from owning interests in other petrochemical companies or projects following its exercise of the option. Simultaneously with the exercise of the option, the parties have agreed to enter into a shareholders’ agreement in respect of their ownership interests in Braskem.
Distribution
Through BR, we distribute oil products, fuel alcohol and natural gas to retail, commercial and industrial customers throughout Brazil. Our retail customers in Brazil include Shell Brasileira de Petróleo S.A., Esso Brasileira de Petróleo S.A., Companhia de Petróleo Ipiranga S.A. and Texaco do Brasil S.A. Our operations are supported by tankage capacity of approximately 8.0 million boe, at 115 storage facilities and 102 aviation product depots at airports throughout Brazil.
Our main strategies in distribution and marketing are to:
On August 9, 2004, BR acquired Agip do Brasil S.A. from its parent company ENI B.V. for approximately U.S.$511 million. Agip do Brasil S.A. is a liquefied petroleum gas (LPG), fuel and lubricant distributor operating in Brazil under the Liquigás, Novogás and Tropigás brands for LPG distribution and the Agip, Companhia São Paulo de Petróleo and Ipê brands for fuel distribution. This acquisition should enable us to increase BR’s share of the LPG distribution market as well as consolidate its presence in the automotive fuel distribution market in certain regions of the country. On January 1, 2005, we changed the name of Agip do Brasil to Liquigás Distribuidora S.A. Liquigás will be responsible for our LPG segment, which will also include LPG’s commercialization in bulk. Agip’s fuel and lubricant distribution business will be operated by BR.
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In 2004, we sold 175.1 million barrels of oil products to wholesale customers, with gasoline and diesel fuel representing approximately 85.4% of these sales. Of our total sales in 2004, 145.1 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 2004, 2003 and 2002:
OIL PRODUCT SALES
Customer
Wholesalers
Total wholesalers
Retail distributors
BR
Third parties
Total retail distributors
Total customers
Retail
As of December 31, 2004, our sales network in Brazil included 6,785 active and non-active retail service stations compared to 7,000 as of December 31, 2003, and comprised approximately 24% of the total number of service stations in Brazil, all under the brand name “BR.” Over 63% of these BR stations are located in the South and Southeast regions of Brazil, where over 59% of Brazil’s total population of 170 million reside. Of these 6,785 service stations, 5,047 were active stations and BR owned 631. As required under Brazilian law, BR subcontracts the operation of all its service stations to third parties. The other 6,154 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 2004, 245 of our service stations also sold vehicular natural gas, compared to 204 in 2003 and 170 in 2002. The sales from these stations consisted of 15,005 million cubic feet (425 million cubic meters) in 2004, representing 27% of Brazilian market share, 14,554 million cubic feet (412 million cubic meters) in 2003, representing 31.2% of Brazilian market share and 13,245 million cubic feet (375 million cubic meters) in 2002, representing 60.6% of Brazilian market share.
The table below sets forth market share (based on volume) for retail sales of different products in Brazil for each of 2004, 2003 and 2002:
DISTRIBUTION MARKET SHARE
Fuel alcohol
Source: Petrobras - based on figures provided by Sindicato dos Distribuidores de Combustíveis-Sindicom
Prices to retailers have generally tended to remain consistent between competing distributors, particularly due to the low margin usually provided. Therefore, competition among distributors continues to be primarily based on product quality, service and image.
During 2004, approximately 24.6% of the retail sales at service stations in Brazil were through BR-owned or franchised entities. We believe that our market share position has remained strong over the past several years due to
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the strong brand name recognition of BR, the remodeling of our service stations and the addition of lubrication centers and convenience stores.
In 1996, BR created the “De olho no Combustível” program (the “Eye on the Fuel” program), which is designed to ensure that the fuels sold to end consumers at our service station networks are identical in content to the fuels originating from our refineries. We have already certified 3,896 service stations under this program.
The 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:
We participate in the retail sector in Argentina, where we currently own 727 retail service stations that operate under the brand names Petrobras (330 stations), Eg3 (337 stations) and San Lorenzo (60 stations). We also have a participation in the retail sector in Bolivia with 103 retail service stations.
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 32.8%, which has remained relatively constant over the past several years.
Set forth below are commercial and industrial sales statistics for each of 2004, 2003 and 2002:
COMMERCIAL AND INDUSTRIAL SALES BY PRODUCT
Jet fuels
Lubricants
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 thermal electric companies.
The natural gas market in Brazil has been growing steadily. In 2004, we estimate that natural gas consumption represented approximately 7.5% of Brazil’s primary energy consumption, as compared to 6.5-7.0% in 2003 and 5.5-6.0% in 2002. The Brazilian government has estimated that natural gas will represent 12% of primary energy
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consumption by 2010. We expect that a portion of this growth will come from increased industrial demand as well as from the Brazilian government’s environmental policies encouraging the replacement of traditional industrial fuels with cleaner energy sources. The development of natural gas-fired thermoelectric plants in Brazil will also aid growth in the natural gas market. During the last three years, we estimate that industrial consumption of natural gas has grown by 75% while vehicular consumption has grown by approximately 70%.
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. We have also invested heavily in production facilities and pipeline capacity to import natural gas from Bolivia, where we, and other oil companies, have discovered substantial non-associated reserves. To secure a market for our natural gas, we have been investing in domestic gas distribution companies, as well as in thermoelectric plants, with the intention to further develop the market for our natural gas.
Our main strategies in the natural gas and power segment are to:
Our natural gas and power results are reflected in the “Gas and Energy” segment in our audited consolidated financial statements.
Natural Gas
Pipelines
Our main pipeline investment has been the development and construction of 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, representing 40% of the existing Brazilian onshore gas pipelines, and 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. We are a significant investor in the Bolivia-Brazil natural gas pipeline, holding an 11% interest in GTB—Gas TransBoliviano S.A., or GTB, the corporate entity owning the Bolivian portion of the pipeline, and a 51% interest in TBG—Transportadora Brasileira do Gasoduto Bolívia-Brasil S.A., or TBG, the corporate entity owning the Brazilian portion of the pipeline. This pipeline is currently in operation and it supplies gas to some of our power and petrochemical plants, including the Uruguaiana Power Plant and the Triunfo Petrochemical Plant.
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 minimum specified quantities of natural gas transported through the pipeline over a 20-year term.
We are also investing in other major domestic natural gas projects: Cabiúnas, the Southeast and the Northeast Gas Pipeline networks, Urucu – Manaus Gas Pipeline and the Southeast – Northeast Gas Pipeline (GASENE).
The Cabiúnas project comprises transportation and processing facilities of natural gas from the offshore oil fields in the Campos Basin to the State of Rio de Janeiro, and includes the construction of an undersea facility for storage of natural gas during declines in consumption. We expect this project to be operational by the second
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semester of 2005 and to increase transportation capacity from the current 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 2004, the average daily volume of natural gas flared on the offshore platforms of the Campos Basin was 88 million cubic feet (2.5 million cubic meters).
We are currently developing the Southeast and the Northeast Gas Pipeline Networks (Malha Sudeste and Malha Nordeste) jointly with private capital investors (the Malhas Project). These projects 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. These projects include the construction of an approximately 890-mile (1,423 kilometers) pipeline network, which is expected to start operations in 2007, at a total cost of approximately U.S.$1,000 million. We are currently negotiating with private capital investors an additional investment of U.S.$900 million for this gas pipeline network.
We are negotiating a long-term financing for a project to deliver natural gas to the states of Amazonas in Northern Brazil (Urucu – Manaus Gas Pipeline). Another long term financing is being negotiated for the Southeast-Northeast Gas Pipeline (GASENE). This pipeline, with a length of 1,280 kilometers, will connect the Southeast and Northeast gas pipeline networks allowing the interconnection of the Brazilian natural gas network system (Rede Básica de Transporte de Gás Natural). This pipeline will link more gas supply sources to demand and increase the existing gas pipeline network’s overall reliability.
Local Distribution Companies
We sell natural gas in Brazil to local gas distribution companies, as under Brazilian law, each state has the monopoly right to distribute gas within a certain region. Most states established companies to act as local gas distributors and sold minority interests in them. We have invested actively in local gas distribution companies, and we currently have minority interests in 19 natural gas distribution companies from a total of 26 existing companies. Of the 19 companies in which we have minority interests, 14 are currently in operation. These companies have an aggregate pipeline extension of 1,800 miles (2,900 kilometers). In 2004, these gas distribution companies sold an average of 585.7 million cubic feet of natural gas per day (16.4 million cubic meters) and generated total net operating revenues of R$2.6 billion (U.S.$0.9 billion), as compared to R$2.4 billion (U.S.$0.8 billion) in 2003. We invested in gas distribution companies through BR until March 2002, and subsequently sold these investments to our subsidiary, Petrobras Gás S.A.–Gaspetro. In the State of Espírito Santo, we have the exclusive rights to distribute natural gas through BR.
In December 2004, Gaspetro acquired a 40% equity interest in Gasmig, the gas distribution company of the State of Minas Gerais, from Cemig 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 2004, Gaspetro also increased its participation in CEG-Rio, the gas distribution company of the State of Rio de Janeiro, by acquiring an additional 9.86% of common shares and 13.68% of preferred shares from Gás Natural SGD for R$46.8 million (U.S.$16.5 million). Gaspetro now holds 26.2% and 43.4% of CEG-Rio’s common and preferred shares, respectively.
We serve as the technical and commercial operator in all of the distribution companies in which we have a minority shareholding stake. Each of the distribution companies in operation 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 thermoelectric power producers). These ship-or-pay and gas purchase contracts do not permit net settlement by either the buyer or the seller, and no market mechanism exists for net settlement.
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The following table sets forth our domestic sales of natural gas to affiliated and non-affiliated local distribution companies for each of 2004, 2003 and 2002:
DOMESTIC SALES OF NATURAL GAS TO LOCAL DISTRIBUTION COMPANIES
Total sales annual average
Annual sales growth
Commitments and Sales Contracts
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 2004, 2003 and 2002, approximately U.S.$638 million, U.S.$452 million and U.S.$260 million, respectively. During 2003 and 2002 we purchased less than the minimum volumes set under our agreement with YPFB, and therefore we were obligated to make payments of U.S.$29 million and US$52 million, respectively. Set forth below are the minimum volumes we have agreed to under these contracts, together with an estimate of the amounts we are obligated to pay for such minimum volumes:
NATURAL GAS PURCHASE COMMITMENTS
Volume Obligation (Mmcmpd)
Volume Obligation (Mmcfd)
Estimated Payments (U.S.$ million)(1)
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 GTB and 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 (TCO) 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 2004, 2003 and 2002, Petrobras made total payments of approximately U.S.$488 million, U.S.$443 million and U.S.$253 million, respectively. Of these amounts, approximately U.S.$260 million, U.S.$246 million and U.S.$205 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
Volume Commitment (Mmcmpd)
Volume Commitment (Mmcfpd)
Additionally, Petrobras Energia 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.$304 million for the next five year term, and U.S.$863 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
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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.”
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 thermoelectric plants, most of which we operate and in which we own a minority interest.
The arrangements with the thermoelectric plants are made through contracts with the local distribution companies, which in turn enter into back-to-back arrangements with the thermoelectric plants, and a portion of the gas buyer’s payments is usually guaranteed to us by the parent companies of the thermoelectric companies or through financial guarantees. Our total sales of natural gas, which includes sales to thermoelectric companies, for 2004, 2003 and 2002, were approximately U.S.$1,876 million, U.S.$1,580 million and U.S.$952 million, respectively. The table below sets forth the commitments by local gas distribution companies and by thermal power plants for the firm purchase of volumes of natural gas from us beginning in 2005, together with an estimate of the amounts obligated to be paid for such volumes:
NATURAL GAS SALES CONTRACTS(1)
To Local Gas Distribution
Companies
Related parties(2)
To Power Generation Plants
Related parties(2)(4)
Estimated Contract Receipts (U.S.$ million)(3)
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 thermoelectric 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 thermoelectric 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.
Renegotiation of the GSA
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.
Since November 2002, we, or the Brazilian government on our behalf, have been attempting to renegotiate the terms of the GSA with YPFB to achieve reductions in the volume and price of natural gas we are required to purchase under the GSA. This renegotiation has been suspended due to the political instability in Bolivia. We cannot
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predict whether such renegotiation will continue in the future. See “Risk Factors—Risks Relating to our Operations— We are subject to substantial risks relating to our international operations, in particular in Latin America and the Middle East.”
Incentives to Distribution Companies. In order to accelerate the expansion of the natural gas market in Brazil, increase consumption and ultimately reduce the financial exposure from our ship-or-pay commitments, we announced in December 2003 a new program of discounts for natural gas distributors in certain regions of Brazil. Distributors in the states of São Paulo, Minas Gerais, Paraná, Santa Catarina, Rio Grande do Sul, and Mato Grosso do Sul will pay a discounted price for volumes sold in addition to contracted amounts, establishing also a ceiling price. If actual amounts sold exceed 40% of contracted amounts, we would reduce the base price according to a progressive schedule. Due to changes in the electricity market and in oil prices this program has been discontinued, except for the ceiling price.
Power
Brazil currently has an installed electricity generation capacity of approximately 80,000 MW. More than 97% of this capacity is interconnected to form one single integrated system, with approximately 86% of the electricity supplied to that system coming from hydroelectric sources. Annual 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 thermoelectric plants, the Brazilian government established the Thermoelectric Priority Program (PPT).
History of the PPT
The PPT, as originally envisioned in February 2000, prioritized the development of 49 new thermoelectric plants to meet Brazil’s growing electricity demand requirements. These PPT thermoelectric plants were to have increased Brazil’s generation capacity by approximately 17,000 MW by 2003. Despite a number of incentives introduced by the Brazilian government to promote the PPT, those thermoelectric power plants under development have been slow to progress. Developers have faced numerous difficulties, including inability to pass on financial and operating costs in U.S. dollars following a devaluation of the Brazilian Real in each of 2001 and 2002, the reluctance of many distribution companies to sign power purchase agreements because of existing supply contracts and lower consumer demand for thermoelectric power as a result of excess supply of hydroelectric power. In light of these difficulties, the Brazilian government reviewed the PPT and reduced the program to 39 projects, representing a planned 13,500 MW of additional capacity.
In line with our strategies in this segment, we decided to participate in the PPT either as a minority shareholder, offtaker or both, in a number of strategically important thermoelectric plants. Initially, we were planning to participate in 26 of the PPT projects, with total capacity of approximately 10,500 MW, of which 4,500 MW corresponds to our purchase commitments at that time.
Current Status of PPT
Due to decreased rainfall in 2000 and 2001 in Brazil and the subsequent shortfall of hydroelectric power to meet Brazilian demand, the Brazilian government implemented a rationing program from the beginning of June of 2001 until the end of February 2002. This created a permanent reduction in demand of approximately 7%, according to recent Brazilian government estimates, resulting from the more rational use of electricity achieved during this period. Additionally, since the end of the rationing program, heavy rains have filled the main reservoirs of the country. As a result, in the short term, existing hydroelectric capacity is sufficient to meet the energy needs of the
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country. The combination of exceptional hydrological conditions and demand reduction has limited, in the short-term, the price and volume at which we can sell electricity from thermoelectric plants.
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, energy may be sold under regulated contracts or free contracts. Energy sold under regulated contracts must be acquired by means of public auctions and energy sold under the free market is negotiated freely through bilateral contracts. The new regulatory model also creates incentives for the investment in power generation.
The first energy auction for existing power plants occurred in December 2004. The first auction for new power plants will occur in 2005. We may participate in such auction to sell energy from our thermo power plants with the intention of securing long-term contracts under prices that will generate good returns.
The effects of the new regulatory model on our operations are still uncertain, since most of the changes introduced by the new law have yet to be tested.
Status of our Investments
We believe our participation in the construction and development of thermoelectric plants has strategic benefits for our business for several reasons:
Although our Strategic Plan calls for an increase in capacity, our plans will ultimately depend upon the level of demand for electricity in general and the success of our electricity marketing efforts. Nonetheless, we intend to acquire a significant number of thermoelectric plants in 2005, especially thermoelectric plants to which we owe contingent payments in order to reduce our financial exposure.
Following this strategy, on April 29, 2005, we acquired Sociedade Fluminense de Energia (SFE), the owner of the Eletrobolt thermoelectric plant, a plant with a capacity of 388 MW located in Seropédica in the State of Rio de Janeiro. We acquired SFE from a group of banks for a purchase price of US$65 million. We have also signed a term sheet on March 24, 2005 for the acquisition of the Termoceará thermoelectric plant from MPX for US$137 million (including the assumption of indebtedness). The execution of a definitive acquisition agreement is subject to certain conditions precedent, including the conclusion of a due diligence of the company. Finally, we also own 100% of TermoRio S.A, an independent power producer under construction. We initially owned 50% of TermoRio S.A., and the remaining 50% was owned by NRG. In April 2002, NRG exercised a put option requesting us to buy its shares and credits in TermoRio. The put option was subject to an arbitration proceeding that ended in February 2005 and required us to purchase NRG’s interest in TermoRio for approximately U.S. $83 million.
The main purpose of these acquisitions was to reduce our financial exposure in connection with these merchant thermal power plants. See “—Financial Exposure.”
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Financial Exposure
To encourage the development of some of the thermoelectric 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 thermoelectric power plants. Our obligations under these agreements are either structured as:
We have only entered into tolling arrangements with thermoelectric plants in which we have an equity interest. Our power commitments under merchant and tolling agreements are as follows:
POWER OFFTAKE PROJECTED COMMITMENTS(1)
NE Tolling Arrangements with consolidated entities
NE Tolling Arrangements with unconsolidated entities
Total NE Tolling Arrangements
S/SE Tolling Arrangements with consolidated entities
S/SE Tolling Arrangements with unconsolidated entities
Total S/SE Tolling Arrangements
The total amount of electricity in respect of which we have tolling or capacity commitments, based upon commitments of projects under construction or in operation, is 3,645 MW as of the end of 2004, of which 2,215 MW come from firm tolling agreements and 1,430 MW from contingent capacity payments.
We expect that the electricity we purchase under tolling agreements will be partly used for consumption in our facilities, estimated to be approximately 300 MW per year, equally allocated between the Northeast and South/Southeast regions of Brazil, as well as firm power sales contracts to third party distributors and industrial consumers. Currently, we do not expect to enter into tolling or capacity arrangements with respect to future thermoelectric plants. Our strategy is to sell all of the other energy in respect of which we have purchase commitments through medium and long-term Power Purchase Agreements, or PPAs. However, as a result of current price levels, we have also negotiated certain shorter-term contracts. As of April 1, 2005, PPAs included offtake commitments totaling 2,370 average MW for 2005, 1,630 average MW for 2006 and 1,700 average MW for 2007, including PPAs executed by merchant power plants. In order to further manage our power purchase commitments, we are continuing to implement an aggressive plan to negotiate medium and long-term PPAs with distributors, industrial consumers and trading companies.
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We continue to have contractual commitments related to our energy operations which would be payable to third parties. These contractual commitments include the purchase of energy, supply of natural gas and reimbursement of operating expenses of thermoelectric power plants. These commitments were incurred in connection with the PPT. Our energy commitments include the following:
Employing a discount rate of 12.0% per year, the net present value of the maximum financial exposure of the energy segment is approximately U.S.$855 million at December 31, 2004.
In January 2003, Companhia Paranaense de Energia - COPEL ceased making its monthly capacity payments to UEG Araucária Ltda. - UEGA (an independent 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 PPA entered into between the two parties. This arbitration proceeding is currently pending. As of December 2003, the capacity payments would have totaled approximately U.S.$72 million if the PPA had remained in effect.
In 2004, approximately 10.9% 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. Additionally, we are integrating our natural gas activities in Brazil with the natural gas network in Bolivia and Argentina. We are also increasing our downstream operations in South America and have acquired refineries and service stations in Argentina and Bolivia.
We have budgeted U.S.$7.5 billion in capital expenditures for the period from 2004 to 2010 for all of our international investments.
Our main strategies in the international segment are to:
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Our international results are reflected in the “International” segment in our audited consolidated financial statements.
Exploration and Production
During 2004 we conducted significant international exploration activities in Angola, 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 and the United States. Production activities were conducted in Angola, Argentina, Bolivia, Colombia, Ecuador, Peru, the United States and Venezuela. Collectively, these activities represented approximately 12.7% 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.$666 million for 2004, U.S.$428 million for 2003 and U.S. $224 million for 2002. The following table provides information about the allocation of such expenditures for each of 2004, 2003 and 2002:
DISTRIBUTION OF INTERNATIONAL EXPLORATION ACTIVITIES
Argentina
Bolivia
Colombia
PEPSA(1)
South America
Development
Over the past three years, we have participated in the development of a number of fields internationally. These include: many fields in Argentina concentrated in Neuquen and Austral basins (the most important fields were Medanito, Puesto Hernandez, Rio Néuquen, Santa Cruz I and Santa Cruz II), three in Bolivia (San Alberto, San Antonio, and Colpa Caranda), six in Colombia (Guando, Rio Ceiba, Yaguara, Venganza, Purificación and Revancha), two in the United States (GB 200 and North Coulomb), one in Angola (Tubarão), one in Nigeria (Agbami), 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 2004, our net production outside of Brazil averaged 168,489 barrels per day of crude oil and NGLs and 94,150 barrels of oil equivalent of natural gas per day at an average lifting cost of U.S.$2.60 per barrel. The following table provides information on the allocation of our international development activities for each of 2004, 2003 and 2002.
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ALLOCATION OF INTERNATIONAL DEVELOPMENT ACTIVITIES
Peru
Ecuador
Venezuela
Argentine Activities
With our 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, especially in Argentina, where we already maintained activities. As of December 31, 2004, our combined crude oil and natural gas proved reserves in Argentina were approximately 393 million barrels of oil equivalent, approximately 59% of which were proved developed reserves and approximately 41% of which were proved undeveloped reserves. In 2004, we drilled three exploratory wells in Argentina, which resulted in two discoveries, the Puesto Olivério and Estación Agua Fresca Fields in the Austral Basin.
PESA’s production in Argentina is concentrated in the Neuquén and Austral Basins. PESA owns 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 4,027 thousand acres (3,211 thousand net), and we have a total of 2,536 gross productive wells (1,498 thousand net). For the year ended December 31, 2004, our combined crude oil and natural gas production in Argentina averaged 114.5 thousand barrels of oil equivalent per day.
In the downstream segment we have a refining capacity of 69 thousand barrels per day, distributed in two refineries operating with a throughput rate of 91%. We also have a 28.5% interest in Refinaria Del Norte. We also participate in the retail sector in Argentina, where we currently own 727 retail service stations that operate under the brand names Petrobras (330 stations), Eg3 (337 stations) and San Lorenzo (60 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. We also own a petrochemical plant in Brazil, INNOVA, through PESA.
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 prices.
The sponsors financed approximately 70% of the project costs with a U.S.$472 million loan from commercial banks and other institutional lenders. The loan was structured to be non-recourse to the sponsors following the termination of sponsor completion guarantees to the lenders during the construction period for their respective shares in the project (Repsol-YPF 38%, Petrobras 34%, and Dow Chemical 28%). The guarantees were originally set to expire on December 31, 2001, but were subsequently extended to December 31, 2003.
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
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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, canceling them. 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.
Regarding the Gas and Energy sector, we participate, through PESA, as shareholder in TGS, which owns a 7,400 km extension pipeline with a transport capacity of 62 MMcmd and a gas processing plant located in Bahía Blanca, with a processing capacity of 42 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 our ownership interests in three generation plants—two hydroelectric (Piedra Del Águila and Pichi Picún Leufú) and one thermoelectric (Genelba). We also have an interest in Transener, Argentina’s largest transmission company and owner of 95% of Argentina’s high-tension network. 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.
On January 21, 2005, special shareholders’ meetings of each of PESA, EG3 S.A., or EG3, Petrobras Argentina S.A., or PAR, and Petrolera Santa Fe SRL, or PSF, approved the merger of the latter three companies into PESA. PESA is the surviving entity from the merger. Prior to the merger, through our subsidiary PPSL, we held a 99.6% interest in EG3 and a 100% interest in each of PAR and PSF. 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, the interest of PEPSA in PESA declined to 75.8%. Considering our 58.62% participation in PEPSA, we now own a 67.2% total indirect participation in PESA.
EG3 was mainly engaged in the refining and processing of oil and oil by-products and the distribution and marketing of liquid and gaseous fuels, and lubricants through gas stations and fuel retail outlets. EG3 had a refinery located at Bahía Blanca, Buenos Aires, with a crude processing capacity of approximately 31,000 barrels per day, EG3 had a wide network of gas stations (approximately 621) throughout the country that operate under the Petrobras and EG3 brands.
PAR was mainly engaged in oil and gas production. PAR owned a concession for a production area at the Noroeste basin, with a production volume of approximately 7,000 barrels of oil equivalent per day and proved reserves of 17 million barrels of oil equivalent as of December 31, 2004.
PSF was engaged in oil and gas production. PSF had concessions for five oil fields, which were located in the Neuquén, San Jorge and Cuyana basins. These fields had an aggregate production volume of approximately 12,000 barrels of oil equivalent per day and proved reserves of 78 million barrels of oil equivalent as of December 31, 2004.
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 US$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 US$63 million.
Bolivian Activities
As of December 31, 2004, our combined crude oil and natural gas proved reserves in Bolivia were approximately 336 million barrels of oil equivalent, all of which were proved developed reserves. Approximately
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89% of our proved developed reserves in Bolivia are natural gas reserves. We did not drill any new exploration wells in Bolivia in 2004.
We have a 35% interest in the San Alberto and San Antonio gas fields (the other partners are Empresa Petrolera Andina (50%) and Total Bolivia (15%)). For the year ended December 31, 2004, our combined crude oil and natural gas production in Bolivia averaged 45.5 thousand barrels of oil equivalent per day.
We own 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 transports natural gas to the city of Puerto Suárez (Bolivia), on the Brazilian border.
We acquired an interest in a natural gas compression plant in Rio Grande, Bolivia, which has a capacity to compress up to 1,546 million cubic feet per day.
We have a 100% interest in Empresa Boliviana de Refino (EBR). EBR owns two Bolivian refineries located in Cochabamba and Santa Cruz de la Sierra, with an estimated maximum production capacity of 60,000 barrels of crude oil per day. EBR wholly owns Empresa Boliviana de Distribución, or EBD, a company with a network of 103 gas stations.
Venezuelan Activities
PESA’s exploration and production rights in Venezuela are held under operating service contracts. In 1994 Petróleos de Venezuela S.A. (PDVSA) awarded our first contract at the Oritupano-Leona field. As of December 31, 2004, PESA’s combined crude oil and natural gas proved reserves in Venezuela were approximately 281 million barrels of oil equivalent, approximately 45.7% of which were proved developed reserves and approximately 54.3% of which were proved undeveloped reserves.
As of December 2004, PESA had four productions fields in the country. PESA’s gross production acreage in Venezuela amounted to 585 thousand acres (379 thousand net), and PESA has a total of 667 gross productive wells (430 thousand net). For the year ended December 31, 2004, PESA’s combined crude oil and natural gas production in Venezuela averaged 51.3 thousand barrels per day.
Ecuadorian Activities
In Ecuador, PESA operates Blocks 18 and 31. As of December 31, 2004, PESA held a 70% and 100% interesin 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 3.8% of PESA’s total average production in barrels of oil equivalent in 2004. It has seven productive wells, one is 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 2004, PESA started to expand production facilities and build an oil pipeline with a view to increasing production to approximately 50,000 barrels per day by the end of the first semester of 2005. In addition, construction started in connection with the definitive oil pipeline for transportation of the block production.
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.
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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 2004, as part of these contemplated investments, PESA commenced construction of a pier on the Napo River.
Future oil production in Block 31 will be shipped through a heavy crude oil pipeline known as OCP. PESA has entered into a 15-year ship-or-pay transportation contract under which OCP has committed to provide it with a shipping capacity of 80,000 barrels per day.
In January 2005, we 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, 2004, PESA’s crude oil proved reserves in Ecuador were approximately 53 million of barrels of oil and its oil production averaged 6.2 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. As of December 2004, Lote X had 2,366 production wells. 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 expires in 2006. As of December 31, 2004, PESA’s combined crude oil and natural gas proved reserves in Peru were approximately 105 million of barrels of oil equivalent and its combined oil and gas production averaged 12.8 thousand barrels per day.
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 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 Potland – ANCAP.
Conecta operates approximately 300 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 4,200 clients from approximately 4,100 residences. We estimate that this represents 10% of the market located in the neighborhood of the gas pipelines in the cities of Paysandu and Ciudad del a Costa. Conecta’s revenues in 2004 were US$2.7 million.
Colombian Activities
During 2004, we signed two new contracts in Colombia, acquiring interests in the Tayrona (40%) and Villanueva (50%) Blocks. We drilled one wildcat well in Monicongo, which did not result in a commercially feasible discovery.
We have interests in seven exploration contracts and seven production contracts in Colombia. We are the operating company in 12 of these contracts. Under these contracts, we drilled a total of 42 wells, 33 of which were located in Guando.
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As of December 31, 2004, our combined crude oil and natural gas proved reserves in Colombia were approximately 37 million of barrels of oil equivalent and our combined oil and gas production averaged 16.8 thousand barrels per day.
African Activities
We have interests in four blocks in Nigeria and we are the operating company in one of them. In 2004, we drilled one successful well in Egina, operated by Total, and four in Agbami, operated by Chevron Texaco. The Agbami well is currently being developed and the Egina field is under appraising. We also were successful in drilling our first deepwater well outside Brazil, which set new depth records in Nigeria.
Our 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 2004. As of December 31, 2004, our combined crude oil and natural gas proved reserves in Angola were approximately 12 million of barrels of oil equivalent and our oil production averaged 10.4 thousand barrels per day.
In 2004, we signed a joint production agreement with the Tanzania 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 will conduct geological studies to determine whether additional seismic acquisitions will occur.
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 has an extension of 10307 square kilometers and is 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 20 more years if discoveries are made. A total of US$21 million will be invested in the exploration phase and we will be required to drill a well and conduct seismic evaluations.
Middle East Activities
In 2004, we 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. We are currently evaluating other exploration opportunities in the Middle East.
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. As of December 31, 2004, PAI held participations in 222 offshore blocks in the Gulf of Mexico in shallow to ultra-deep waters.
In 2004, PAI participated in the drilling of four exploration wells (three wildcats and one appraisal). One of the wildcat wells resulted in the discovery of gas in the Coulomb North field, in which we have a 33.3% participation. This discovery set a new world record for production in deep waters at depths of 7,549 feet (2,301 meters). The production in this well started 78 days after its discovery. PAI also participated in the drilling of an appraisal well in St. Malo (25% participation), which resulted in an increase of the initial reserve estimates.
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%).
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There are 12 gas discoveries in this block, which will be developed with a total expenditure of U.S.$510 million. In 2004, we started the development and production of these discoveries by drilling eight production wells.
In 2004, we acquired new exploration acreage by acquiring (1) rights to explore 37 new blocks (most of them located in the under explored Corpus Christi region) through our participating in the Lease Round 192 and (2) an interest in the Treasure Bay Project, comprising 60 blocks, through a farm-in deal.
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.
PIFCo is a tax exempt company incorporated with limited liability under the laws of the Cayman Islands. PIFCo’s registered office is located at Anderson Square Building, P.O. Box 714, 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.
In addition, PIFCo also engages in a number of activities that are conducted by three wholly-owned subsidiaries:
In January 2003, PIFCo transferred 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, to us as part of our restructuring of our international business segment. 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.
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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.
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. 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 sell 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 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.
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Petrobras Finance Limited (PFL)
In December 2001, PIFCo established PFL, a wholly-owned subsidiary incorporated and registered in the Cayman Islands. PFL primarily purchases bunker and 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. 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.
Exports Prepayment Program
We sell and deliver bunker fuel and 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. 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 in four series (collectively, the “Series 2001 Senior Trust Certificates”) and U.S.$150 million of Junior Trust Certificates (the “Series 2001 Junior Trust Certificates,” and together with the Series 2001 Senior Trust Certificates, 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, and together with the Series 2003-A Senior Trust Certificates and the Series 2003-B Senior Trust Certificates, the “Series 2003 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).
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 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
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“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.
Petrobras’ Bunker Fuel and Fuel Oil Business
As described above, PFL, a wholly-owned subsidiary of PIFCo, purchases bunker and 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.
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 2004 was 27,425 Mbbl (“Mbbl” stands for thousand barrels), as compared to 26,741 Mbbl in 2003 and 29,869 Mbbl in 2002. Petrobras’ total bunker fuel production totaled 159,613 Mbbl for the period from January 1, 2000 to December 31, 2004. Petrobras exports approximately 94% 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.
PETROBRAS’ ANNUAL BUNKER FUEL PRODUCTION
Export
Domestic Consumption
Petrobras Fleet
Fuel oil originates from residual fractions or 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.
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Fuel Oil Export Sales
The following table sets forth Petrobras’ fuel oil export sales for the period from 2000 to 2004:
FUEL OIL EXPORT SALES
Millions of U.S.$
Millions of Barrels
Organizational Structure
All of our 15 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.
The following diagram sets forth our significant consolidated subsidiaries as of December 31, 2004:
Property, Plants and Equipment
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 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 main areas of business.
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 adopted the 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 eliminated our government-granted monopoly. The amendment was implemented by the adoption of the Oil Law, 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 and, in case of drilling success, development 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 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 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 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.
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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) and the Securities and Exchange Commission.
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 thermoelectric 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). As of May 1, 2004, important changes were made regarding the taxation of oil products sales. The PIS/PASEP tax and the COFINS tax previously ad valorem taxes on imported products, were converted into specific value taxes at the following rates:
Jet Fuel
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For certain trading transaction, the taxpayer may still opt to pay the PIS/PASEP tax and the COFINS as ad valorem taxes.
The specific tax rates for CIDE, and the amounts paid which could be used as credits against PIS/PASEP and COFINS amounts also changed and are now the following:
Fuel Oil
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:
Until the passage of the Oil Law 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, the oil and gas markets in Brazil were deregulated beginning January 2, 2002. As part of this action:
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.
Our natural gas operation is subject to a number of rules, including Portaria No. 3 (relating to the sale of domestic natural gas), Portaria No. 176 (relating to the maximum price for natural gas sold to certain PPT thermoelectric plants) andPortaria No. 45 (relating to the transportation price for domestic natural gas sold to local gas distribution companies).
On June 1, 2001, the Ministry of Mines and Energy and the Ministry of Finance adopted Portaria No. 176, establishing a ceiling price for natural gas to be sold to certain of the thermoelectric plants that are part of the PPT, to be applicable for a twelve-year period. Each qualifying thermoelectric plant will have the right to purchase natural gas at prices that are determined as described below.
For the initial consecutive twelve-month period starting on the date the gas consumption begins, a fixed price in Reais will be set based on the reference price in United States dollars per MMBTU, initially set at U.S.$2.58 per MMBTU, converted into Reais based on the exchange rate in effect on that date. For subsequent consecutive twelve-month periods, the ceiling price will be adjusted annually for changes in the United States producer price index and the U.S. dollar exchange rate with respect to the portion of the ceiling price relating to imported natural gas (set by the regulation at 80%) and for changes in the IGP-M with respect to the portion of the ceiling price relating to domestic natural gas (set by the regulation at 20%), reflecting the current mix of natural gas supplied to these qualifying thermoelectric plants. The annual adjustment in the ceiling price related to imported gas is based on the previous twelve-month period rate and the projected volume of natural gas to be sold to the qualifying thermoelectric plant during the succeeding twelve-month period. The price will be adjusted to reimburse the natural gas supplier, on a per invoice basis, for any shortfalls caused by a Real devaluation. Similarly, the qualifying thermoelectric plant will be reimbursed for overpayments, calculated on a per invoice basis, resulting from a Real appreciation during the period.
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The applicable interest rate on the net shortfall or overpayment amount with respect to each qualifying thermoelectric plant will be the SELIC rate, the interest rate applicable to certain Brazilian government securities. In addition, interest projected to be accrued during the immediately succeeding twelve-month period on the net shortfall or overpayment amount will be added. Any portion of the shortfall or overpayment amount that is not reimbursed through these adjustments in the ceiling price will be included in the adjustment to the ceiling price for subsequent consecutive twelve-month periods until reimbursed in full.
The PPT allows qualifying thermoelectric plants to pass on to their customers any increases in pricing resulting from these adjustments.
The Petroleum and Alcohol Account
Prior to the deregulation of oil prices in 2002, the Petroleum and Alcohol Account was a special account that reflected the impact on us of the Brazilian government’s regulatory policies for the Brazilian oil industry and its fuel alcohol program. From 2002 onwards, the Petroleum and Alcohol Account only reflects the balances existing at the time of price deregulation plus accrued monetary correction to account for inflation.
Prior to July 29, 1998, this account recorded the difference between the cost established by the Brazilian government and our actual cost for imported crude oil and oil products, as well as the net effects on us of the administration of the FUP and FUPA subsidies and all of the related regulations (the FUP/FUPA programs). For example, if the cost established by the Brazilian government for crude oil and oil products was lower than our actual costs to import these products, the difference would be recorded as a credit owed by the Brazilian government to us in the Petroleum and Alcohol Account.
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 that had not been phased out. The net impact on us of our fuel alcohol activities was also recorded in the Petroleum and Alcohol Account.
Article 74 of the Oil Law required settlement of the Petroleum and Alcohol Account by the Brazilian government on or before full implementation of price deregulation was completed. This deregulation was phased in over several years and was implemented in full on January 2, 2002. 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 US$56 million and the balance of the Petroleum and Alcohol Account was US$241 million. On July 2, 2004, the Brazilian Government made a deposit in an account in our name of US$56 million for payment of the bonds. However, only US$3 million of this amount was made available to us. We do not have access to the remaining US$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). As of December 31, 2003 and 2002, the value of the bonds amounted to US$59 million and US$46 million, respectively. 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.
Certification of the Petroleum and Alcohol Account
The changes in the Petroleum and Alcohol Account in the period from July 1, 1998 to December 20, 2002 are subject to audits by the ANP. The results of the audit will be the basis for settlement of the account with the Brazilian government. The term for settlement of the Petroleum and Alcohol Account had been extended to June 30, 2004, thereby extending the term for certification of the outstanding balance in the Petroleum and Alcohol Account. However, the settlement has not yet occurred.
The ANP/STN Integrated Audit Committee submitted, on June 23, 2004, its final report certifying and approving the balance of the Petroleum and Alcohol Accounts for the period from July 1, 1998 to December 31, 2001, together with monetary restatement through the present date. The conclusion of this audit process for the
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Petroleum and Alcohol account, and the parties’ concurrence as to final amount, establishes the basis for concluding the settlement process between the Brazilian government and PETROBRAS.
As defined by Provisional Measure No. 123 dated June 26, 2003, made into Law No. 10.742 dated October 6, 2003, the settlement of accounts should have been completed by June 30, 2004. PETROBRAS has been in contact with the STN with a view to resolving the differences in order to resolve remaining issues between the parties in order to conclude the settlement process as established by Provisional Measure No. 2.181-45, of August 24, 2001.
In accordance with the applicable laws and regulations, and subject to our approval, the settlement of the Petroleum and Alcohol Account may be in the form of:
The following table summarizes the changes in the Petroleum and Alcohol Account for 2004, 2003 and 2002:
Opening balance
Advances (Collections)-PPE
Reimbursements to third parties:
Subsidies paid to fuel alcohol producers
Total reimbursements to third parties
Reimbursements to Petrobras:
Transport of oil products
Net result of fuel alcohol commercialization activities(1)
Total reimbursements to Petrobras
Total reimbursements
Results of certification/audit process
conducted by the Brazilian government(2)
Partial settlement
Translation gain (loss)(3)
Ending balance
The U.S.$43 million increase in the balance of the Petroleum and Alcohol Account during 2004 was primarily a result of the audit process conducted by the ANP and the 8.1% 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 our government-granted monopoly 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.
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With the effectiveness of the Oil Law and the regulations promulgated by the ANP thereunder, concessionaires are required to pay the government the following:
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 provided 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:
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 less:
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.
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, we are subject to the administrative authority
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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 certain of our activities. We must eliminate, mitigate, or compensate the relevant parties for, the 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, for legal entities, suspension or interruption of activities or prohibition to enter into any contracts with governmental bodies for up to ten years. 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:
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.
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Law No. 9,985 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. Environmental agencies are still implementing this law, but they may attempt to apply it in a retroactive manner.
In 2004, we invested approximately U.S.$490 million in environmental projects as compared to approximately U.S.$750 million in 2003. 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 providing environmental compensation.
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 oil, gas and energy company. In order to address and prioritize health, safety and environmental concerns and ensure compliance with environmental regulations, we have:
received HSE certificates for all our operating units. By December 2004, 57 operating units, 33 in Brazil and 24 abroad, had been certified by the management systems standards ISO 14001 (environment), and BS 8800 or OHSAS 18001 (health and safety), and 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). With the integration of our management
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processes, which is currently being implemented, we will obtain only one ISO 14001 and one OHSAS 18001 certificate for all our Brazilian refineries, fertilizer plants and two downstream corporate units. We expect to obtain such certificate in September 2005;
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.
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. The work of the HSE Management Committee is supported by three permanent subcommittees, two temporary commissions and one temporary work group, each one responsible for a specific HSE issue, such as licensing and environmental compensation and risk assessment.
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 deregulation of the oil and gas industry in Brazil, we expect to face increasing competition both in our downstream and upstream operations.
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In our 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 full deregulation, 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 96.7% in the Brazilian oil production segment in 2004. 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 39.3% of the Brazilian oil exploration market in 2004 and the exploration activities conducted by us in conjunction with other partners represented approximately 46.8% of the oil exploration market in Brazil in 2004. 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 32.8% in the Brazilian oil 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 our natural gas and power segment, we expect competition from new entrants that are acquiring interests in natural gas distribution and thermoelectric generation companies, and existing competitors that are expanding operations in order to consolidate their position in Brazil. We had a market share of approximately 7.7% in the Brazilian natural gas and power segment based on 2004 revenues, according to the Brazilian National Energetic Balance for 2004, or BEN 2004, published by the Ministry of Mines and Energy.
In our international segment, we are planning to continue expanding our 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 14.7% for auto fuel and 8.1% for lubricants. In Bolivia, we have a market share of 98% of the oil refining market, 25% of the fuel market, and 63% 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
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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 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.
The premium for renewing our property risk insurance policy for a 12-month period commencing June 2004 was U.S.$25.2 million. This represented a decrease of 21% over the preceding 12-month period. The decrease was primarily due to a change in the insurance market which became more competitive and a better perception of our risk by the market due to our risk management and HSE policies. In the same period, the insured value of our assets increased by 28%, from U.S.$20.8 billion to U.S.$26.6 billion. Since 2001, our risk retention has increased and our deductibles may reach U.S.$20 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.
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-2 of this annual report.
Overview
We earn income from:
Our expenses include:
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Year to year fluctuations in our income are the result of a combination of factors, including:
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 2004 totaled approximately 989,719 million barrels of crude oil equivalent, representing U.S.$37,452 million in net operating revenues, as compared to approximately 923,481 million barrels of crude oil equivalent, representing U.S.$30,797 million in net operating revenues in 2003 and approximately 911,817 million barrels of crude oil equivalent and U.S.$22,612 million in net operating revenues in 2002.
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.$38.21 in 2004, U.S.$28.84 per barrel for 2003 and U.S.$25.02 per barrel for 2002. For December 2004, Brent crude oil prices averaged U.S.$39.53 barrel, but during 2005 (through February), Brent crude oil prices have increased, averaging U.S.$44.88 per barrel. This increase in average crude oil prices also affected international prices for oil products.
Domestic Sales Volumes and Prices
During 2004, approximately 72.5% of our net operating revenues were derived from sales of crude oil and oil products in Brazil, as compared to 73.9% in 2003 and 76.0% in 2002. As export volumes of crude oil and oil products have increased, domestic sales as a percentage of net operating revenues have declined.
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Our revenues are principally derived from sales in Brazil. The following table sets forth our domestic sales by volume of oil products, natural gas and fuel alcohol for each of 2004, 2003 and 2002:
Energy products:
Automotive gasoline
Liquid petroleum gas
Total energy products
Non-energy products:
Petrochemical naphtha
Total non-energy products
Natural gas (BOE)
Sub-total
Distribution net sales
Intercompany net sales
Total domestic market
Export net sales
International net sales
Sub-Total
Services
Consolidated net sales
During 2004, we announced three increases 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 charts below reflect the increases in billing at Petrobras refineries, without ICMS.
Price increase announced on June 15, 2004:
Price increase announced on October 15, 2004:
Price increase announced on November 26, 2004:
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 186,221 million barrels of crude oil equivalent in 2004, as compared to
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192,545 million barrels of crude oil equivalent in 2003 and 202,003 million barrels of crude oil equivalent in 2002. 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 negotiations with our clients. As a result of an increase in average prices for export sales of crude oil and oil products, partially offset by a decrease in the volume of exports, the total value of our crude oil and oil product exports (measured on a free-on-board basis) in 2004 was U.S. $5,923 million, as compared to U.S.$5,335 million in 2003 and U.S.$4,610 million in 2002, representing approximately 15.8% of our net operating revenues in 2004, as compared to 17.3% in 2003 and 19.9% in 2002. 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.$2,840 million in 2004, U.S.$1,974 million in 2003 and U.S.$588 million in 2002, representing approximately 7.6% of our net operating revenues in 2004, as compared to 6.4% in 2003 and 2.6% in 2002. 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. However, in 2004 the margin between our net operating revenues and cost of goods sold was lower than in 2003 as a result of an increase of imported crude oil to 155 million barrels in 2004 from 116 million barrels in 2003. This increase was mainly due to the growth of demand of oil products in Brazil that could not be met by our own crude oil production, which decreased in 2004 as compared to 2003. As we further upgrade our refineries to handle larger quantities of our heavy crude oil, our level of imports will tend to decrease. Our imports of crude oil had decreased to 116.1 million barrels in 2003, as compared to 117.6 million barrels of crude oil in 2002.
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 an optimal level of imports for our profitability. We imported a total of 40.1 million barrels of oil products in 2004, as compared to 44.5 million barrels of oil products in 2003 and 78.5 million barrels in 2002. See Item 4. “Information on the Company—Refining, Transportation and Marketing-Imports.”
Effect of Taxes on our Income
General
In addition to collecting sales and value-added taxes, such as the Imposto sobre Circulação de Mercadorias e Serviços, or ICMS, on behalf of federal and state governments, we pay three principal taxes on our oil producing activities in Brazil:
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These taxes imposed by the Brazilian government are included in our cost of goods sold, and therefore have a significant effect on our total lifting costs. 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 Imposto sobre Circulação de Mercadorias e Serviços (state sales tax, or ICMS) on upstream activities. The law was regulated by Decree nº 34.761, 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 at the Brazilian Supreme Court (Supremo Tribunal Federal – STF). The claim was filed by the Federal Prosecutor and the Attorney General has given a favorable legal opinion. The Supreme Court 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 were 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$5.85 billion (U.S.$2.0 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.$911 million in 2004, U.S.$602 million in 2003 and U.S.$1,142 million in 2002.
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.$1,733 million in 2004, U.S.$1,247 million in 2003 and U.S.$774 million in 2002. In addition, we capitalized U.S.$267 million in interest in 2004, as compared to U.S.$184 million in 2003 and U.S.$139 million in 2002.
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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 limited, although it increased markedly in 2002. Inflation was 12.1% in 2004, 7.7% in 2003 and 26.4% in 2002, 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, 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 2004, there was a 8.1% appreciation of the Real against the U.S. dollars, as compared to a 18.2% appreciation in 2003 and a 52.3% devaluation in 2002.
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.
Another effect of devaluation 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 devaluation. Accordingly, the effect was to decrease costs of locally supplied products and services when reported in U.S. dollars.
In recent periods, the exchange rate variation has had the following additional effects, among others, on our financial condition and results of operations:
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
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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.$1,911 million credit directly to shareholders’ equity in our statement of changes in shareholders’ equity for 2004, without affecting net income, to reflect the appreciation of the Real against the U.S. dollar of approximately 8.1%, as compared to a credit of U.S.$2,856 million in 2003 to reflect the appreciation of 18.2% and a charge of U.S.$5,452 million in 2002 to reflect the devaluation of 52.3%.
Foreign currency translation adjustments reflecting a devaluation have the greatest impact on the balance sheet of a company such as ours, whose assets are primarily denominated in Reais, but whose liabilities are primarily denominated in foreign currencies. The reductions in our asset values charged to shareholders’ equity, however, do not necessarily affect our cash flows, since our revenues and cash earnings are to a large degree linked to the U.S. dollar, and a portion of our operating expenses are linked to the Real.
The exchange rate variation also impacts the amount of retained earnings available for distribution by us when measured in U.S. dollars. Amounts reported as available for distribution in our statutory accounting records prepared in accordance with Brazilian accounting principles decrease or increase when measured in U.S. dollars as the Real depreciates or appreciates against the U.S. dollar. In addition, the exchange rate variation creates foreign exchange gains and losses that are included in our results of operations determined in accordance with Brazilian accounting principles and that affect the amount of our unretained earnings available for distribution.
Results of Operations
The differences in our operating results from year to year occur as a result of a combination of factors, including primarily: the volume of crude oil, oil products and natural gas we produce and sell, the price at which we sell our crude oil, oil products and natural gas and the differential between the Brazilian inflation rate and the depreciation or appreciation of the Real against the U.S. dollar. The table below shows the amount by which each of these variables has changed during the last three years:
Crude Oil and NGL Production (Mbpd)
Total Crude Oil and NGL Production
Change in Crude Oil and NGL Production
Average Sales Price for Crude (bpd in U.S.$)
Natural Gas Production (Mmcfpd)
Total Natural Gas
Production
Change in Natural Gas Production (sold only)
Average Sales Price for Natural Gas (Mcf in U.S.$)
Year End Exchange Rate
Appreciation (Devaluation) during the year
Inflation Rate (IGP-DI)
Results of Operations for the year ended December 31, 2004 (“2004”) compared to the year ended December 31, 2003 (“2003”).
The comparison between our results of operations for 2004 and 2003 has been affected by the 4.8% decrease in the average Real/U.S. dollar exchange rate for 2004 as compared to the average Real/U.S. dollar exchange rate for 2003. For ease, we refer to this change in the average exchange rate as the “4.8% increase in the value of the Real against the U.S. dollar in 2004, as compared to 2003.”
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Revenues
Net operating revenues increased 21.6% to U.S.$37,452 million for 2004, as compared to U.S.$30,797 million for 2003. 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 4.8% increase in the value of the Real against the U.S. dollar in 2004, as compared to 2003.
Consolidated sales of products and services increased 21.7% to U.S.$51,954 million for 2004, as compared to U.S.$42,690 million for 2003, 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:
Cost of sales for 2004 increased 31.7% to U.S.$20,303 million, as compared to U.S.$15,416 million for 2003. This increase was principally a result of:
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 39.0% to U.S.$2,481 million for 2004, as compared to U.S.$1,785 million for 2003. This increase was primarily attributable to the following:
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Exploration, including exploratory dry holes
Exploration costs, including exploratory dry holes increased 19.7% to U.S.$613 million for 2004, as compared to U.S.$512 million for 2003. This increase was primarily attributable to the following:
These increases were partially offset by a decrease of U.S.$196 million due to a revision in the estimated expenses for dismantling oil and gas producing areas and future well abandonment.
Impairment of oil and gas properties
For 2004, we recorded an impairment charge of U.S.$65 million, as compared to an impairment charge of U.S.$70 million for 2003. The impairment charge in 2004 related to capital expenditures for Brazilian fields in production, but with only marginal reserves. We also recorded an impairment charge of U.S.$13 million due to goodwill assessment. In 2003, the impairment charge was related to certain of our oil and gas producing properties in Brazil, Colombia and Angola. These charges were recorded based upon our annual assessment of these fields using prices consistent with those used in our overall strategic plan and discounted at a rate of 10%, a rate consistent with the rate used for internal project valuations.
Selling, general and administrative expenses increased 38.7 % to U.S.$2,901 million for 2004, as compared to U.S.$2,091 million for 2003.
Selling expenses increased 51.4% to U.S.$1,544 million for 2004, as compared to U.S.$1,020 million for 2003. This increase was primarily attributable to the following:
General and administrative expenses increased 26.7% to U.S.$1,357 million for 2004, as compared to U.S.$1,071 million for 2003. This increase was primarily attributable to the following:
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Research and development expenses
Research and development expenses increased 23.4% to U.S.$248 million for 2004, as compared to U.S.$201 million for 2003. This increase was primarily related to additional investments in programs for environmental safety, deepwater and refining technologies of approximately U.S.$36 million and to the 4.8% increase in the value of the Real against the U.S. dollar in 2004, as compared to 2003.
Other operating expenses
Other operating expenses decreased 20.6% to an expense of U.S.$259 million for 2004, as compared to an expense of U.S.$326 million for 2003.
The charges for 2004 were:
The charges for 2003 were:
Equity in results of non-consolidated companies
Equity in results of non-consolidated companies increased 22.0% to a gain of U.S.$172 million for 2004, as compared to a gain of U.S.$141 million for 2003, due primarily to a U.S.$21 million gain as a result of the consolidation of PEPSA and PELSA and their equity method investees for the full year in 2004, as opposed to approximately seven months in 2003.
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 increased 51.3% to U.S.$911 million for 2004 as compared to U.S.$602 million for 2003. This increase was primarily attributable to fair value adjustments on gas hedge transactions, which was partially offset by a decrease in financial interest income from short-term investments due to higher investments in securities indexed to the U.S. dollar in 2004 when compared to 2003, resulting in lower income due to the effect of the 8.1% appreciation of the Real against the U.S. dollar during 2004, as compared to the 18.2% appreciation of the Real against the U.S. dollar during 2003. A breakdown of financial income and expenses is shown in Note 14 to our audited consolidated financial statements for the year ended December 31, 2004.
Financial expense increased 39.0% to U.S.$1,733 million for 2004, as compared to U.S.$1,247 million for 2003. This increase was primarily attributable to an increase of approximately U.S.$233 million in financial expenses resulting from PEPSA’s hedge operations; as well as a loss of U.S.$137 million on repurchases of our own securities.
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Monetary and exchange variation on monetary assets and liabilities, net generated a gain of U.S.$450 million for 2004, as compared to a gain of U.S.$509 million for 2003. The decrease in monetary and exchange variation on monetary assets and liabilities, net is primarily attributable to the effect of the 8.1% appreciation of the Real against the U.S. dollar during 2004, as compared to the 18.2% appreciation of the Real against the U.S. dollar during 2003.
Employee benefit expense consists of financial costs associated with expected pension and health care costs. Our employee benefit expense increased 9.2% to U.S.$650 million for 2004, as compared to U.S.$595 million for 2003. This increase in costs was primarily attributable to an increase of U.S.$25 million from the annual actuarial calculation of our pension and health care plan liability and to the 4.8% increase in the value of the Real against the U.S. dollar in 2004, as compared to 2003.
Other taxes
Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, increased 32.1% to U.S.$440 million for 2004, as compared to U.S.$333 million for 2003. This increase was primarily attributable to the following:
Other expenses, net
Other expenses, net are primarily composed of gains and losses recorded on sales of fixed assets, general advertising and marketing expenses and certain other non-recurring charges. Other expenses, net decreased to an expense of U.S.$357 million for 2004, as compared to an expense of U.S.$700 million for 2003.
The most significant charges for 2004 were:
The most significant charges for 2003 were:
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Income tax (expense) benefit
Income before income taxes, minority interest and accounting changes increased 1.8% to U.S.$8,935 million for 2004, as compared to U.S.$8,773 million for 2003. The income tax expense decreased 16.2% to U.S.$2,231 million for 2004, as compared to an expense of U.S.$2,663 million for 2003, primarily due to the additional tax benefits related to interest on shareholders’ equity that amounted to U.S.$650 million for 2004, as compared to U.S.$364 million for 2003.
The reconciliation between the tax calculated based upon statutory tax rates to income tax expense and effective rates is shown in Note 4 to our audited consolidated financial statements for the year ended December 31, 2004.
Cumulative effect of change in accounting principle
As of January 1, 2003, we generated a gain of U.S.$697 million (net of U.S.$359 million of taxes) resulting from the adoption of SFAS No. 143 – Accounting for Asset Retirement Obligations. The adjustment was due to the difference in the method of accruing end of life asset retirement obligations under SFAS 143, as compared with the method required by SFAS 19 – Financial Accounting and Reporting by Oil and Gas Producing Companies.
Increase of authorized capital
The General Extraordinary Shareholders Meeting, held in conjunction with the General Ordinary Meeting on March 29, 2004, approved an increase in authorized capital from R$30 billion (U.S.$10.4 billion) to R$60 billion (U.S.$20.8 billion).
Natural gas derivative contract
In connection with a long-term contract to buy gas (Gas Supply Agreement or “ the GSA”) to supply thermoelectric plants and for other uses in Brazil, we entered into a contract, effective October 2002, with a gas producer that constituted a derivative financial instrument under SFAS 133. This contract, the Natural Gas Price Volatility Reduction Contract (or PVRC), matures in 2019 and was executed with the purpose to reduce the volatility of price respective to the GSA.
At inception, the PVRC had a positive value to us of U.S.$169 million, which is deemed a deferred purchase incentive and is being amortized into income on the basis of the volumes anticipated under the PVRC. The liability was U.S.$153 million at December 31, 2004 and generated a gain in the amount of U.S.$11 million, net of deferred tax effect of U.S.$5 million.
The PVRC is being accounted for under SFAS 133 as a derivative instrument, since the Company did not satisfy the documentation required for hedge accounting, and is being marked to its calculated fair value with changes in such value recognized in income. As of December 31, 2004, we recorded a derivative asset based on the fair value calculation in the amount of U.S.$635 million, and a mark-to-market gain in the amount of U.S.$365 million, net of deferred tax effect of US$188 million.
See Note 23 to our audited consolidated financial statements for the year ended December 31, 2004.
Results of Operations for the year ended December 31, 2003 (“2003”) compared to the year ended December 31, 2002 (“2002”).
The comparison between our results of operations has been impacted by the Real’s appreciation against the U.S. dollar, due to the fact that the average Real/U.S. dollar exchange rate for 2003 was 5.2% lower than the average exchange rate for 2002.
Net operating revenues increased 36.2% to U.S.$30,797 million for 2003, as compared to net operating revenues of U.S.$22,612 million for 2002. This increase was primarily attributable to the alignment of prices of certain oil products in the Brazilian market with international prices of such products at the end of 2002. The
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increase in net operating revenues was also attributable, to a lesser extent, to an increase in sales volume outside Brazil (international sales), which includes sales conducted by PEPSA and PELSA. This increase was partially offset by a 4.4% reduction in sales volume in the domestic market, primarily due to a decrease in Brazilian consumer demand. See “—Sales Volumes and Prices—Domestic Sales Volumes and Prices.”
Our consolidated sales of products and services increased 29.4% to U.S.$42,690 million for 2003, as compared to U.S.$32,987 million for 2002.
Included in sales of products and services are the following amounts which we collected on behalf of the federal or state governments:
Cost of sales for 2003 increased 34.0% to U.S$15,416 million, as compared to U.S.$11,506 million for 2002. This increase was principally a result of:
These increases were partially offset by:
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Depreciation, depletion and amortization relating to exploration and production assets are calculated on the basis of the units of production method. Depreciation, depletion and amortization expenses decreased 7.5% to U.S.$1,785 million for 2003, as compared to U.S.$1,930 million for 2002. This decrease was primarily attributable to the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002, and to the effect of the adoption of SFAS 143 in 2003. In 2002, U.S.$281 million in abandonment costs were recognized as depreciation, depletion and amortization in accordance with SFAS 19. In 2003, as a result of the adoption of SFAS 143, depreciation on the asset retirement obligation was recorded under depreciation, depletion and amortization, while accretion expense was recorded under exploration, including exploratory dry holes. See “—Impact of New Accounting Standards—SFAS 143.” This change resulted in U.S.$21 million in abandonment costs being recognized as depreciation, depletion and amortization in 2003. The decrease in depreciation, depletion and amortization, was partially offset by an increase of depreciation, depletion and amortization expenses of approximately U.S.$182 million incurred in connection with the activities of PEPSA and PELSA.
Exploration costs, including exploratory dry holes increased 17.7% to U.S.$512 million for 2003 as compared to U.S.$435 million for 2002. This increase was primarily attributable to the increase of approximately U.S.$49 million in exploration costs, including exploratory dry holes in connection with the consolidation of PEPSA and PELSA and U.S.$43 million in abandonment costs recognized. The increase in exploration costs, including exploratory dry holes, was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
For 2003, we recorded an impairment charge of U.S.$70 million, as compared to an impairment charge of U.S.$75 million for 2002. In 2003, the impairment charge was related to certain of our oil and gas producing properties in Brazil, Colombia and Angola. In 2002, the impairment charge was related to certain of our oil and gas producing properties in Brazil and Angola. These charges were recorded based upon our annual assessment of our fields using prices consistent with those used in our overall strategic plan and discounted at a rate of 13%.
Selling, general and administrative expenses increased 20.1% to U.S.$2,091 million for 2003, as compared to U.S.$1,741 million for 2002.
Research and development expenses increased 36.7% to U.S.$201 million for 2003, as compared to U.S.$147 million for 2002. This increase was primarily related to our additional investments in programs for environmental
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safety, deepwater and refining technologies of approximately U.S.$62 million, and was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
Other operating Expenses
For 2003 we recognized losses amounting to U.S.$326 million under other operating expenses which were composed of:
Equity in results of non-consolidated companies registered a gain of U.S.$141 million for 2003, as compared to a loss of U.S.$178 million for 2002. This increase was primarily attributable to:
We derive financial income from several sources, including:
Financial income decreased 47.3% to U.S.$602 million for 2003, as compared to U.S.$1,142 million for 2002. This decrease was primarily attributable to a reduction in financial interest income from short-term investments, which declined 79.4% to U.S.$163 million for 2003, as compared to U.S.$793 million for 2002. The reduction in financial income was also attributable to the 5.2% decrease in the value of the Real against the U.S. dollar for 2003, as compared to 2002. This decrease was partially offset by an increase of financial income of approximately U.S.$80 million resulting from the consolidation of PEPSA and PELSA in our 2003 financial results.
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Financial expense increased 61.1% to U.S.$1,247 million for 2003, as compared to U.S.$774 million for 2002. This increase was primarily attributable to our additional debt and an increase of approximately U.S.$194 million in financial expenses resulting from the consolidation of PEPSA and PELSA in our 2003 financial results.
Monetary and exchange variation on monetary assets and liabilities, net registered a gain of U.S.$509 million for 2003, as compared to a loss of U.S.$2,068 million for 2002. Approximately 90% of our long-term indebtedness was denominated in foreign currencies during each of 2003 and 2002. The fluctuation in monetary and exchange variation on monetary assets and liabilities, net was primarily attributable to the effect of the 18.2% appreciation of the Real against the U.S. dollar during 2003, as compared to a 52.3% depreciation of the Real against the U.S. dollar during 2002.
Employee benefits expense
Employee benefit expense consists of financial costs associated with pension and health care budgets. Our employee benefit expense increased 31.9% to U.S.$595 million for 2003, as compared to U.S.$451 million for 2002. This rise in costs was attributable to an increase of U.S.$166 million from the annual actuarial calculation of our pension and health care plan liability. The increase was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, decreased 7.5% to U.S.$333 million for 2003, as compared to U.S.$360 million for 2002. This decrease was primarily attributable to the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002, and the decrease of U.S.$61 million in the PASEP/COFINS taxes payable in respect of foreign exchange gains on assets, resulting from transactions with affiliates with assets denominated in foreign currencies.
Other expenses, net are primarily composed of gains and losses recorded on sales of fixed assets, general advertising and marketing expenses and certain nonrecurring charges. Other expenses, net for 2003 decreased to an expense of U.S.$700 million, as compared to an expense of U.S.$857 million for 2002. The most significant charges were:
The most significant charges for 2002 were:
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Income before income taxes, minority interest and accounting changes increased from U.S.$8,773 million for 2003 to U.S.$3,232 million for 2002. As a result, we recorded an income tax expense of U.S.$2,663 million for 2003, as compared to an expense of U.S.$1,153 million for 2002.
The reconciliation between the tax calculated based upon statutory tax rates to income tax expense and effective rates is discussed in Note 4 to our consolidated financial statements as of December 31, 2003.
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Business Segments
Set forth below is selected financial data by segment for 2004, 2003 and 2002:
SELECTED FINANCIAL DATA BY SEGMENT
Exploration, Development and Production (Exploration and Development Segment)
Net revenues to third parties(1)
Intersegment net revenues
Total net operating revenues
Net income
Capital expenditures
Refining, Transportation and Marketing (Supply Segment)
Net revenues to third parties(1) (2)
Total net operating revenues (2)
Net income (2)
Distribution (Distribution Segment)
Natural Gas and Power (Gas and Energy Segment)
Net revenues to third parties (1)
International (International Segment)
Net income (loss) (2)
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Management’s Discussion and Analysis of PIFCo’s Financial Condition and Results of Operations
You should read the following discussion of PIFCo’s financial condition and results of operations together with PIFCo’s attached audited consolidated financial statements and the accompanying notes beginning on page F-143. PIFCo’s audited consolidated financial statements and the accompanying notes have been presented in U.S. dollars and prepared in accordance with U.S. GAAP. In addition, as our subsidiary, PIFCo also prepares financial statements in accordance with accounting practices adopted in Brazil.
PIFCo is our wholly-owned subsidiary. Accordingly, PIFCo’s financial position and results of operations are significantly affected by our decisions, as its parent company. PIFCo’s ability to meet its outstanding debt obligations depends on a number of factors, including:
PIFCo earns income from:
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PIFCo’s operating expenses include:
Purchases and Sales of Crude Oil and Oil Products
PIFCo typically purchases crude oil and oil products in transactions with payment terms of approximately 30 days. We typically pay for shipments of crude oil and oil products that PIFCo sells over a period of up to 270 days, which allows us sufficient time to assemble the necessary documentation under Brazilian law to commence the payment process for such shipments. During this period, PIFCo typically finances the purchase of crude oil and oil products through either funds previously provided by us or third-party trade finance arrangements. The difference between the amount PIFCo pays for crude oil and oil products and the amount we pay for that same crude oil and oil products is deferred and recognized as part of PIFCo’s financial income on a straight-line basis over the period in which our payments to PIFCo come due.
Results of operations for the year ended December 31, 2004 (“2004”) compared to the year ended December 31, 2003 (“2003”).
Net Loss
PIFCo had a net loss of U.S.$59.1 million in 2004, as compared to a net loss of U.S.$3.0 million in 2003.
Sales of Crude Oil and Oil Products and Services
PIFCo’s sales of crude oil and oil products and services increased 77.1% from U.S.$6,975.5 million in 2003 to U.S.$12,355.6 million in 2004. This increase was primarily due to (1) a 27.1 % increase in the volume of sales of crude oil and oil products to us, (2) an increase in exports of crude oil and oil products, principally to PETROBRAS AMERICA INC. – PAI (“PAI”), as a result of PIFCo’s new role as an intermediary for our exports that PIFCo assumed from another affiliate of ours beginning January 1, 2004, which increased sales volumes of crude oil and oil products by approximately 16.2% in 2004, (3) a 32.5% increase in the average price of Brent crude oil from U.S.$28.84 per barrel during 2003 to U.S.$38.21 per barrel during 2004 and (4) an increase in the volume of offshore sales of crude oil and oil products purchased from third parties and sold to third parties and affiliates.
Cost of Sales
Cost of sales increased 76.8% from U.S.$6,920.2 million in 2003 to U.S.$12,236.0 million in 2004. This increase was primarily due to a 27.1% increase in the volume of sales of crude oil and oil products to us, additional sales linked to PIFCo’s new export activities, principally to PAI, a 32.5% increase in the average price of Brent crude oil from U.S.$28.84 per barrel during 2003 to U.S.$38.21 per barrel during 2004, as well as an increase in the volume of offshore sales of crude oil and oil products purchased from third parties and sold to third parties and affiliates.
Selling, General and Administrative Expenses
PIFCo’s selling, general and administrative expenses consist primarily of shipping costs and fees for services, including accounting, legal and rating services. These expenses increased from U.S.$18.6 million in 2003 to U.S.$99.8 million in 2004, of which U.S.$96.8 million consisted of shipping expenses. In July 2003, our management decided to assign the responsibility for payment of shipping expenses previously paid by us, to PIFCo. PIFCo’s expects shipping costs to figure permanently as part of its selling, general and administrative expenses.
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Financial Income
PIFCo’s financial income consists of the financing of sales to us, inter-company loans to us and investments in marketplace securities and other financial instruments. PIFCo’s financial income increased 53.3% from U.S.$442.9 million in 2003 to U.S.$678.8 million in 2004, primarily due to an increase in the amount of sales to us, an increase in the interest component of the formula by which we reimburse PIFCo for its financing costs and for receipt of payments beyond the time periods previously agreed with us, and an increase in interest income from short-term investments.
Financial Expense
PIFCo’s financial expense consists of interest paid and accrued on its outstanding indebtedness and other fees associated with its issuance of debt. PIFCo’s financial expense increased 57.7% from U.S.$482.7 million in 2003 to U.S.$761.2 million in 2004, primarily due to a register of an expense in the amount of U.S.$64.2 million related to the difference between the face value and the market value of the repurchase of some of its outstanding securities.
PIFCo had a net loss of U.S.$3.0 million in 2003, as compared to a net loss of U.S.$65.5 million in 2002.
PIFCo’s sales of crude oil and oil products and services increased 9.2% to U.S.$6,975.5 million in 2003, from U.S.$6,390.2 million in 2002, primarily due to a 16.5% increase in the average price of Brent crude oil from U.S.$24.76 per barrel in 2002 to U.S.$28.84 per barrel in 2003, a 9.7% increase in the volume of sales made by its subsidiary, PFL, in connection with our exports prepayment program and due to the favorable effects of the Iraq war and the effects, primarily in the first quarter, of the political and economic crisis in Venezuela on international prices and supplies of crude oil and oil products. The increase was partially offset by a reduction in the volume of oil products PIFCo sold to us as a result of the contraction in the Brazilian economy and the consequent loss of purchasing power among the population.
Lease income
As a result of PIFCo’s transfer of PNBV to us, PIFCo had no income from leases in 2003. In 2002, PIFCo’s lease income was U.S.$36.1 million.
Cost of sales increased 8.6% to U.S.$6,920.1 million in 2003, from U.S.$6,371.5 million in 2002, primarily due to the 16.5% increase in the average price of Brent crude oil in 2003, as compared to 2002, and the 9.7% increase in sales made by PIFCo’s subsidiary PFL in connection with our exports prepayment program. The increase was partially offset by a reduction in the volume of oil products sold to us as a result of lower demand for such products in the Brazilian market.
Lease Expense
As a result of PIFCo’s transfer of PNBV to us, PIFCo had no expense related to leases in 2003. In 2002, PIFCo’s lease expense was U.S.$24.0 million.
PIFCo’s selling, general and administrative expenses consist primarily of shipping costs and fees for services, including accounting and legal services. These expenses increased to U.S.$18.6 million in 2003, as compared to
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U.S.$1.2 million in 2002, of which U.S.$17.1 million consisted of shipping expenses. In 2003, our management decided to assign to PIFCo the responsibility for payment of shipping expenses previously paid by us. From this point forward, PIFCo expects shipping costs to figure permanently as part of its selling, general and administrative expenses.
Gross Profit
PIFCo’s gross profit reflects profits from its third-party sales of crude oil and oil products and services (since PIFCo record profits from sales of crude oil and oil products to us as financial income). PIFCo’s gross profit increased 24.3% to U.S.$36.8 million in 2003, as compared to U.S.$29.6 million in 2002, as a result of the 16.5% increase in the average price of Brent crude oil from U.S.$24.76 per barrel in 2002 to U.S.$28.84 per barrel in 2003 and due to the favorable effects of the Iraq war and the effects, primarily in the first quarter, of the political and economic crisis in Venezuela on international prices and supplies of crude oil and oil products.
PIFCo’s financial income consists of the financing of sales to us and inter-company loans to us, investments in marketplace securities and other financial instruments. Our financial income increased to U.S.$442.9 million in 2003, from U.S.$219.6 million in 2002, primarily due to an increase in loans to related parties and interest received as a result of increases in the time period previously agreed with us for receipt of payments related to sales of crude oil and oil products to Petrobras from up to 120 days in early 2002 to up to 270 days beginning in May 2002 and continuing for the remainder of 2002 and throughout all of 2003, increases in the periods of time for receipt of payments beyond the time periods previously agreed with us and a modification of the interest component of the payment formula by which we reimburse PIFCo for its financing costs. In January 2003, this formula was adjusted in order to more fully pass on PIFCo’s average costs of capital to us.
PIFCo’s financial expense consists of interest paid and accrued on its outstanding indebtedness and other fees associated with PIFCo’s issuance of debt. PIFCo’s financial expense increased 53.3% to U.S.$482.7 million in 2003, as compared to U.S.$314.7 million in 2002, primarily due to the increase in the amount of its long-term indebtedness. PIFCo’s long-term indebtedness increased to U.S.$5,825.3 million at December 31, 2003, as compared to U.S.$3,248.7 million at December 31, 2002. The increase in financial expense was partially offset by the lower average interest rate on its outstanding debt.
Liquidity and Capital Resources
Our principal uses of funds are for capital expenditures, dividend payments and repayment of debt. We have historically met these requirements with internally generated funds, short-term debt, long-term debt, project financings and sale and lease back agreements. We believe these sources of funds, together with our strong cash and cash equivalents on hand, will continue to allow us to meet our currently anticipated capital requirements. In 2005, our major cash needs include planned capital expenditures of U.S.$ 9,818 million, announced dividends of U.S.$ 1,900 million and payments of U.S.$ 2,778 million on our long-term debt, leasing and project financing obligations.
Financing Strategy
The objective of our financing strategy is to help us achieve the targets set forth in our Strategic Plan released on May 14, 2004, which provides for capital expenditures of U.S.$ 53.6 billion from 2004-2010. We also aim to increase the average life of our debt portfolio and reduce our cost of capital through a variety of medium and long-term financing arrangements, including supplier financing, project financings, bank financing, securitizations and issuances of debt and equity securities.
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Government Regulation
The Ministry of Planning, Budget and Management controls the total amount of medium and long-term debt that we and our Brazilian subsidiaries are allowed to incur through the annual budget approval process (Plano de Dispêndio Global, or PDG). Before issuing medium and long-term debt, we and our Brazilian subsidiaries must also obtain the approval of the National Treasury shortly before issuance.
In accordance with Senate Resolution Nº 96/89 the level of our borrowings is subject to an annual maximum amount, exclusive of certain permitted commercial obligations, based on shareholders’ equity, debt service expense and other factors as of the prior year and subject to certain ongoing quarterly adjustments. For 2004, the maximum level of debt that Petrobras and its Brazilian subsidiaries could incur was set at U.S.$958 million. The maximum level was set at U.S.$932 million for 2003 and U.S.$824 million for 2002.
All of our foreign currency denominated debt, as well as the foreign currency denominated debt of our Brazilian subsidiaries requires registration with the Central Bank. The issuance of debt by our international subsidiaries, however, is not subject to registration with the Central Bank or approval by the National Treasury. In addition, all issuances of medium and long-term notes and debentures require the approval of our board of directors. Borrowings that exceed the approved budget amount for any year also require approval from the Brazilian Senate.
Sources of Funds
Our Cash Flow
At December 31, 2004, we had cash and cash equivalents of U.S.$ 6,856 million as compared to U.S.$ 8,344 million at December 31, 2003.
Operating activities provided net cash flows of U.S.$ 8,833 million in 2004, as compared to U.S.$ 7,303 million in 2003. This increase was due primarily to the increase in net operating revenues in 2004.
Net cash used in investing activities increased to U.S.$8,421 million in 2004, as compared to U.S.$ 5,519 million in 2003. This increase was due primarily to our investments in capital expenditures associated with our operating activities and to the acquisition of Liquigás Distribuidora S.A.
Financing activities used net cash of U.S.$ 2,204 million in 2004, as compared to providing net cash in the amount of U.S.$ 2,376 million in 2003. This change in the balance of the cash flows was due primarily to higher dividend and short-term debt payments in 2004, and the decreased amount of Global Notes issued in the international capital markets in 2004, as compared to issuances in 2003.
Short-Term Debt
Our outstanding short-term debt serves mainly to support our imports of crude oil and oil products, and is provided almost completely by international banks and under our commercial paper program. At December 31, 2004, our short-term debt (excluding current portions of long-term obligations) decreased to U.S.$ 547 million as compared to U.S.$ 1,329 million at December 31, 2003. The decreased use of short-term credit facilities was related to our decision to take steps to lengthen our debt profile and pay down short-term debt. Our short-term debt is denominated principally in U.S. dollars.
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Long-Term Debt
Our total outstanding consolidated long-term debt consists primarily of the issuance of securities in the international capital markets, debentures in the domestic capital markets, amounts outstanding under facilities guaranteed by export credit agencies and multilateral agencies, and financing from the Banco Nacional de Desenvolvimento Econômico e Social (the Brazilian National Development Bank, or BNDES) and other financial institutions. Outstanding long-term debt, plus the current portion of our long-term debt, totaled U.S.$13,344 million at December 31, 2004 (U.S.$6,377 million representing PIFCo’s debt), as compared to U.S.$13,033 million (U.S.$6,049 million representing PIFCo’s debt) million at December 31, 2003. Included in these figures at December 31, 2004 are the following international debt issues:
Notes
9.00% Notes due 2004(1)
10.00% Notes due 2006
6.625% Step Down Notes due 2007(1)
PIFCo’s 9.125% Notes due 2007(2)
PIFCo’s 9.875% Notes due 2008(2)
PIFCo’s 6.75% Senior Trust Certificates due 2010(3)
PIFCo’s Floating Rate Senior Trust Certificates due 2010(3)
PIFCo’s 9.750% Notes due 2011(2)
PIFCo’s 6.60% Senior Trust Certificates due 2011(3)
PIFCo’s Floating Rate Senior Trust Certificates due 2013(3)
PIFCo’s 4.750% Senior Exchangeable Notes due 2007(4)
PIFCo’s Global Step-up Notes due 2008(5)
PIFCo’s 9.125% Global Notes due 2013(6)
PIFCo’s 8.375% Global Notes due 2018(6)
PIFCo’s 3.748% Senior Trust Certificates due 2013(3)(7)
PIFCo’s 6.436% Senior Trust Certificates due 2015(3)(8)
9.375% Notes due 2013(9)
PIFCo’s 7.75% Global Notes due 2014(2)
The increase in our long-term debt was due primarily to the issuance on September 8, 2004, through PIFCo, of U.S.$600 million of Global Notes for 98.63% of their face value, with an annual coupon of 7.75% due 2014. The issuance reflects our efforts to continue to lengthen our debt profile.
We describe the average interest rates on our long-term debt in Note 13 to our consolidated financial statements. As of December 31, 2004, 39% of our long-term debt had an average interest rate of 6% or less and an additional 36% of our long-term debt had an average interest rate that ranged from 8% to 10%.
In addition to issuing foreign currency denominated debt in the international capital markets, we have historically issued Real denominated debentures in the local capital markets. These debentures are floating-rate obligations, and the coupon is based on an index plus a fixed spread.
We did not issue any Real-denominated debentures in 2004 or 2003. Outstanding debentures totaled U.S.$1,088 million at December 31, 2004, as compared to U.S.$928 million at December 31, 2003.
Project Finance
Since 1997, we have utilized project financings to provide capital for our large exploration and production and related projects, and more recently, for the development of natural gas processing and transportation systems. All of these projects, and their related debt obligations, are on-balance sheet and accounted for under the line item “Project Financings” until December 31, 2002. Since December 31, 2003, the special purpose companies related to these project financings are consolidated in accordance with FIN 46 on a line-by-line basis. Under the contractual arrangements, we are responsible for completing the development of the projects, their operation, paying all operating expenses relating to the projects and remitting a portion of the net proceeds generated from the fields to fund the special purpose companies’ debt and return on equity payments. At the end of each financing project, we have the option to purchase the project assets from the special purpose company or, in some cases, acquire control over the special purpose company itself. Outstanding project financings, plus the current portion of our project
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financings, totaled U.S.$5,712 million at December 31, 2004, as compared to U.S.$5,908 million at December 31, 2003.
During 2004, we made capital expenditures of U.S.$557 million (7.2% of our total capital expenditures) in connection with exploration and development projects in the Campos Basin, a number of which are being financed through project financings.
Of the U.S.$1,506 million projected amount of expenditures for project financings in 2005, we expect that approximately U.S.$267 million will be used by our exploration and production segment (U.S.$77 million of which will be used in our Barracuda-Caratinga field), U.S.$1,036 million by our gas and energy segment and U.S.$204 million by our other segments.
At December 31, 2004, the long-term portion of project financings becomes due in the following years:
2006
2007
2008
2009
2010 and thereafter
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. In its opinion, PIFCo’s strong cash position at hand and its ability to access international capital markets will continue to allow it to meet its anticipated cash needs and financial obligations.
As an offshore non-Brazilian company, PIFCo is not legally obligated to receive prior approval from the Brazilian National Treasury to incur debt or register debt with the Central Bank. As a matter of policy, however, the issuance of any debt is recommended by any of our Chief Financial Officer, Executive Board or Board of Directors, depending on the aggregate principal amount and the tenor of the debt to be issued.
PIFCo’s Cash Flow
At December 31, 2004, PIFCo had cash and cash equivalents of U.S.$1,107.3 million, as compared to U.S.$664.2 million at December 31, 2003. This increase in cash was primarily a result of an increase in long-term loans received from us. PIFCo’s operating activities used net cash of U.S.$2,322.0 million in 2004, as compared to using net cash of U.S.$1,306.6 million in 2003, primarily as a result of an increase in outstanding receivable from sales to related parties. Its investing activities used net cash of U.S.$1,406.2 million in 2004, as compared to using net cash of U.S.$684.4 million in 2003, primarily as a result of a increase in marketable securities and an increase in notes receivable issued to related parties. PIFCo’s financing activities provided net cash of U.S.$4,171.3 million in 2004, as compared to providing net cash of U.S.$2,394.6 million in 2003, primarily as a result of an increase in long-term loans from related parties and issuance of US$ 600.0 million Global Notes.
Accounts Receivable
Accounts receivable from related parties increased 53.8% from U.S.$5,064.5 million at December 31, 2003 to U.S.$7,788.1 million at December 31, 2004, as a result of an increase of sales of oil and oil products to us.
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PIFCo’s Short-Term Borrowings
PIFCo’s short-term borrowings are denominated in U.S. dollars and consist of lines of credit and loans payable. At December 31, 2004, it had access to short-term capital through U.S.$1,111.9 million in guarantees, primarily in the form of irrevocable letters of credit supporting oil imports, as compared to U.S.$274.6 million in guarantees at December 31, 2003. At December 31, 2004 it had accessed U.S.$535.8 million in lines of credit, including the current portion of long-term lines of credit, as compared to U.S.$1,015.3 million accessed at December 31, 2003. The weighted average annual interest rate on these short-term borrowings was 4.3% at December 31, 2004, as compared to 3.9% at December 31, 2003. At December 31, 2004 and 2003, PIFCo had fully utilized all available lines of credit for purchase of imports.
PIFCo renewed its commercial paper program in May 2003 in an aggregate principal amount of U.S.$160 million in order to finance its working capital requirements. Its commercial paper program is rated A1+ by Standard & Poor’s and P-1 by Moody’s and is supported by a letter of credit issued by Barclays Bank and a standby purchase agreement with us. At December 31, 2004 and December 31, 2003, PIFCo had no commercial paper notes outstanding.
The short-term portion of PIFCo’s notes payable to related parties, which are principally composed of notes payable to us, increased from U.S.$2,442.8 million at December 31, 2003 to U.S.$2,881.5 million at December 31, 2004, primarily as a result of its short-term financing needs.
PIFCo’s Long-Term Borrowings
During 2004, PIFCo contracted from us U.S.$3,553.5 million in long-term loans due 2010, with interest rates ranging from 4.9% to 5.8%. The transaction extended the financial terms respective to certain short-term Notes payable creating liquidity for PIFCo and such liquidity was partially used to fund purchases of securities by the exclusive investment fund.
At December 31, 2004, PIFCo had outstanding U.S.$631.8 million in long-term lines of credit due between 2006 and 2012, as compared to U.S.$377.5 million at December 31, 2003. PIFCo also had outstanding:
U.S.$1,261.9 million (U.S.$153.7 million current portion) in connection with our exports prepayment program. On December 21, 2001, the Trust (PF Export) issued to PFL, PIFCo’s subsidiary, U.S.$750 million of Senior Trust Certificates in four series and U.S.$150 million of Junior Trust Certificates. In
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addition, on May 13, 2003, the Trust issued U.S.$550 million in 6.436% Senior Trust Certificates due 2015, and on May 14, 2003, the Trust issued U.S.$200 million in 3.748% Senior Trust Certificates due 2013 and an additional U.S.$150 million of Junior Trust Certificates. In May 2004, PFL and the PF Export Trust executed an amendment to the Trust Agreement allowing the Junior Trust Certificates to be set-off against the related Notes, rather than paid in full, after fulfillment of all obligations pursuant to the Senior Trust Certificates. The effect of this amendment is that amounts related to the Junior Trust Certificates are now presented net, rather than gross in PIFCo’s consolidated financial statements, and thus U.S.$300 million has been reduced from the “long-term debt” liability caption respective to sales of rights to future receivables, with a similar reduction to the asset line item “assets related to export prepayments.”
An investment fund, in which PIFCo has a stake, carries out the repurchases of its securities, among other investments. These repurchased securities were reclassified as financings, thus reducing its short term and long term financing balance by U.S.$3.2 million and U.S.$146.0 million, respectively, at December 31, 2004. In 2004, an expense was registered in the amount of U.S.$64.2 million representing the difference between the face value and the market value of the repurchased securities.
The following table shows the sources of PIFCo’s current and long-term debt at December 31, 2004 and 2003:
CURRENT AND LONG-TERM DEBT
Financing institutions
Senior notes
Global Step-up Notes
Global Notes
Sale of rights to future receivables
Senior exchangeable notes
Assets related to export prepayment to be offset against sales of rights to future receivables
Repurchased securities
Extinguished securities
At December 31, 2004 and 2003, we had amounts invested abroad in an exclusive investment fund that held debt securities of some of our group companies in the amount of U.S.$ 2,013 million and U.S.$ 920 million, respectively. Once these securities are purchased by the fund, the related amounts, together with applicable interest, are removed from the presentation of marketable securities and long-term debt.
Off Balance Sheet Arrangements
As noted above, all of our project financings are on-balance sheet. At December 31, 2004, neither we nor PIFCo had off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our or PIFCo’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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Uses of Funds
In 2004, we continued to prioritize capital expenditures for the development of crude oil and natural gas production projects through internal investments and through structured undertakings with partners. We invested a total of U.S.$7,718 million in 2004, a 17.8% increase from our investments in 2003. Our increased capital expenditures in 2004 were primarily directed towards increasing our production capabilities in the Campos Basin, modernizing our refineries and expanding our pipeline transportation and distribution system. We spent U.S.$4,574 million (59.3%) in 2004 in our domestic exploration and development projects mainly in the Campos Basin, which includes investments financed through our project financings. PIFCo primarily utilizes funds to finance its oil trading activities.
The following table sets forth our consolidated capital expenditures (including project financings and investment in thermoelectric power plants) for each of our business segments for 2004, 2003 and 2002:
Supply
Gas and Energy
Corporate
On May 14, 2004, we announced our Strategic Plan, which contemplates total budgeted capital expenditures of U.S.$53.6 billion in the period from 2004 through 2010, approximately U.S.$46.1 billion of which will be directed towards our activities in Brazil, while U.S.$7.5 billion will be directed to our activities abroad. We expect that the majority of our capital expenditures from 2004 through 2010, approximately U.S.$32.1 billion, will be directed towards exploration and production, of which U.S.$26.2 billion is slated for our activities in Brazil.
Our Strategic Plan for 2004 to 2010 contemplates greater domestic expenditures in our construction activities and other projects. We estimate that of the U.S.$46.1 billion in domestic capital expenditures for 2004 to 2010, at least U.S.$31.7 billion (69%) will be utilized to pay for equipment and services provided by Brazilian contractors, suppliers and other service providers.
Our capital expenditures budget for the year 2005, including our project financings, is U.S.$9.8 billion, allocated among each of our business segments as follows: (i) Exploration and Production: U.S.$5.2 billion; (ii) Downstream: U.S.$1.2 billion; (iii) International: U.S.$1.7 billion; (iv) Gas and Energy: U.S.$1.2 billion; (v) Distribution: U.S.$0.2 billion; and (vi) Corporate: U.S.$0.3 billion.
We plan to meet our budgeted capital expenditures primarily through internally generated cash and issuances in the international capital markets. Our actual capital expenditures may vary substantially from the projected numbers set forth above as a result of market conditions and the cost and availability of the necessary funds.
Dividends
In 2004 we paid dividends of approximately U.S.$1,809 million (U.S.$1.65 per share). Approximately 80% of such amount was paid in the form of interest on capital.
At our general shareholders’ meeting held on March 31, 2005, our shareholders approved a distribution of dividends of U.S.$1,900 million (U.S.$1.73 per share) based on the year-end exchange rate as proposed by our Board of Directors. Of this amount, U.S.$1,239 million (U.S.$1.13 per share based on the year-end exchange rate) had previously been approved by our Board of Directors and was distributed to shareholders on February 15, 2005 in the form of interest on capital. The remaining U.S.$661 million, including U.S.$413 million of interest on capital,
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was paid to our shareholders on May 17, 2005. All such payments are made in Brazilian reais and are monetary restated as from December 31, 2004 up to the date of actual payment according to the variation of the SELIC rate. On June 17, 2005 our Board of Directors approved payment to shareholders in the form of interest on capital totaling R$2,194 million, to be distributed by January 2006 based on a record date of June 30, 2005.
Contractual obligations
The following table summarizes our outstanding contractual obligations at December 31, 2004, excluding deferred income tax and trade accounts payable.
Balance Sheet Items:
Long-Term Debt Obligations
Pension Fund Obligations(1)
Project Finance Obligations
Capital (Finance) Lease Obligations
Total Balance Sheet Items
Other Long-Term Contractual Obligations:
Natural Gas Ship-or-Pay Commitments
Contract Service Obligations
Natural Gas Supply Agreements
Operating Lease Obligations
Purchase Obligations
International Purchase Obligations
Total Other Long-Term Contractual Obligations
The following table summarizes PIFCo’s outstanding contractual obligations at December 31, 2004, excluding deferred income tax and trade accounts payable.
Contractual Obligations
Notes Payable - Long term
Purchase obligations - Long term
Risk Management Activities
We and PIFCo are exposed to a number of market risks arising in the normal course of business. We and PIFCo may use derivative and non-derivative instruments to manage these risks. For a description of our risk management activities, see Item 11. “Qualitative and Quantitative Disclosures About Market Risk.”
Critical Accounting Policies and Estimates
The following discussion describes those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting estimates we make in these contexts require us to make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
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The discussion addresses only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are used to help make investment decisions about oil and gas properties. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less then reasonable certainty of recoverability and are classified as either probable or possible. Probable reserves are reserves that are more likely to be recovered than not and possible reserves are less likely to be recovered than not.
The estimation of proved reserves is an ongoing process that takes into account engineering and geological information such as well logs, pressure data and fluid sample core data. Proved reserves can also be divided in two categories: developed and undeveloped. Developed proved reserves are expected to be recovered from existing wells including reserves behind pipe, or when the costs necessary to put them in production are relatively low. For undeveloped proved reserves, significant investments are necessary, including drilling new wells and installing production or transportation facilities.
We use the “successful efforts” method to account for our exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to ensure that commercial quantities of reserves have been found or that additional exploration work is under way or planned in a timeframe reasonable to the Petrobras development cycle and with consideration to ANP timing requirements. Exploratory well costs not meeting either of these tests are charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method because it provides a more timely accounting of the success or failure of our exploration and production activities.
Impact of Oil and Gas Reserves on Depreciation and Depletion
The calculation of unit-of-production depreciation and depletion is a critical accounting estimate that measures the depreciation and depletion of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) asset cost. Proved undeveloped reserves are considered in the amortization of leasehold acquisition costs. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability they are based on estimates that are subject to some variability. This variability may result in net upward or downward revisions of proved reserves in existing fields, as more information becomes available through research and production. We revised our proved reserves in the last three years, decreasing our proved reserves by 431.3 million barrels of oil equivalent in 2004, decreasing our proved reserves by 665.5 million barrels of oil equivalent in 2003 and increasing our proved reserves by 948.0 million barrels of oil equivalent in 2002. While the revisions we have made in the past are an indicator of variability, they have had a small impact on the unit-of-production rates because they have been small compared to our large reserves base.
Impact of Oil and Gas Reserves and Prices on Testing for Impairment
A substantial part of our property, plant, and equipment — U.S.$37.0 billion, net of accumulated depletion, at December 31, 2004—consists of oil and gas producing properties. These properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future and discounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves, except in circumstances where it is probable that
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additional non-proved reserves will be developed and contribute to cash flows in the future; the percentage of probables that we include in cash flows does not exceed our past success ratios in developing probable reserves.
We perform asset valuation analyses on an ongoing basis as a part of our management program. These analyses monitor the performance of assets against corporate objectives. They also assist us in reviewing whether the carrying amounts of any of our assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices.
In general, we do not view temporarily low oil prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand fundamentals. Accordingly, any impairment tests that we perform make use of our long-term price assumptions for the crude oil and natural gas markets. These are the same price assumptions that are used in our planning and budgeting processes and our capital investment decisions, and they are considered to be reasonable, conservative estimates given market indicators and past experience. Significantly lower future oil and gas prices could lead to impairments in the future, if such decreases were considered to be indicative of long-term trends. Additionally, significant changes in production curve expectation, discount and/or required production and lifting costs, could affect impairment analysis. While such uncertainties are inherent to this estimation process, the amount of impairment charges in past years has been small relative to the total value of oil and gas producing properties: U.S.$65 million in 2004, U.S.$70 million in 2003 and U.S.$75 million in 2002. Bases on our experience, we believe that future variability in estimates will have a small impact on both assets and expense.
Pension and Other Post-Retirement Benefits
The determination of the expense and liability relating to our pension and other post-retirement benefits involves the use of judgment in the determination of actuarial assumptions. These include estimates of future mortality, withdrawal, changes in compensation and discount rate to reflect the time value of money as well as the rate of return on plan assets. These assumptions are reviewed at least annually and may differ materially from actual results due to changing market and economic conditions, regulatory events, judicial rulings, higher or lower withdrawal rates or longer or shorter life spans of participants.
According to the requirements of SFAS 87, and subsequent interpretations, the discount rate should be based on current prices for settling the pension obligation. Applying the precepts of SFAS 87 in historically inflationary environments such as Brazil creates certain issues as the ability for a company to settle a pension obligation at a future point in time may not exist as long-term financial instruments of suitable grade may not exist locally as they do in the United States.
Although the Brazilian market has been demonstrating signs of stabilization under the present economic model, as reflected in market interest rates, it is not yet prudent to conclude that market interest rates will be stable. Although SFAS 87 offers limited guidance, we consider it appropriate to use actuarial assumptions, which include an estimate of long-term inflation (i.e., nominal rates).
On December 31, 2004, we adopted a new actuarial methodology regarding the calculation of Accumulated Benefit Obligation (ABO), by excluding the effects of long term inflation. In the past, we had applied a terminal methodology in the calculation of our ABO, an approach permitted under EITF 88-1. At December 31, 2004, we elected a change in methodology to a going concern calculation of the ABO, a more preferable application of principle per EITF 88-1. The change in accounting principle application impacted only the liability balance and amount not recognized in the shareholders equity having no effect in our income statement for 2004.
In addition, in 2004, the Executive Board of PETROBRAS approved a change to a new mortality table relating to actuarial assumptions of our pension and healthcare plans in Brazil. This new mortability table reflects changes with respect to the profile of employees, retirees and pensioners, based on longevity, age of invalidity and invalid mortality tables. The main purpose of the change was to strengthen our benefit plans in light of a more accurate evaluation of the greater life expectancy of the plan beneficiaries.
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The progressive increase in longevity has direct impact on the plan’s estimated and provisioned volume of commitments and obligations and in our liabilities under the line “employees’ post-retirement benefit obligation” and in our shareholders’ equity under the line “amounts not recognized as net periodic pension cost,” net of tax. The restated estimates have no impact on the results for the fiscal year ended December 31, 2004.
Amounts not recognized as net periodic pension cost are values calculated as the difference between the forecasted restatement of the net value of the obligations according to the actuarial assumptions and the variations effectively occurring over time. These amounts are to be amortized and posted to the results of subsequent fiscal years over the average life expectancy of the pension plan’s members.
Litigation, Tax Assessments and Other Contingencies
Claims for substantial amounts have been made against us arising in the normal course of business. We are sometimes held liable for spills and releases of oil products and chemicals from our operating assets. In accordance with the guidance provided by U.S. GAAP, we accrue for these costs when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. At December 31, 2004, we had accrued U.S.$256 million for litigation contingencies. Significant management judgment is required to comply with this guidance and it includes management’s discussion with our attorneys, taking into account all of the relevant facts and circumstances. We believe that payments required to comply with these laws and regulations will not vary significantly from our estimated costs, and thus will not have a material adverse effect on our operations or cash flows. In past periods, the difference between the actual payout and the amount of the accrued liability, with respect to contingency estimation, has been insignificant, with no material income statement impact in the period of the payout. Our annual cash payouts for contingencies relating to claims against Petrobras, the parent company, have been less than U.S.$58.5 million in each of the last five years.
Asset Retirement Obligations and Environmental Remediation
Under various contracts, permits and regulations, we have material legal obligations to remove equipment and restore the land or seabed at the end of operations at production sites. Our most significant asset removal obligations involve removal and disposal of offshore oil and gas production facilities worldwide. We accrue the estimated discounted costs of dismantling and removing these facilities at the time of installation of the assets. We also estimate costs for future environmental clean-up and remediation activities based on current information on costs and expected plans for remediation. The aggregate amount of estimated costs on a discounted basis for asset retirement and environmental remediation accrued at December 31, 2004 was U.S.$403 million. Estimating asset retirement, removal and environmental remediation costs requires performing complex calculations that necessarily involve significant judgment because our obligations are many years in the future, the contracts and regulation shave vague descriptions of what removal and remediation practices and criteria will have to be met when the removal and remediation events actually occur and asset removal technologies and costs are constantly changing, along with political, environmental, safety and public relations considerations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty. However, given the significant amount of time to the ultimate retirement date, any modifications in technological specifications, legal requirement, or other matters, would not have a materially adverse effect on any one reporting period.
In 2004, we reviewed and revised our estimated costs associated with well abandonment and the demobilization of oil and gas production areas, considering new information about date of expected abandonment and revised cost estimates to abandon. The changes to estimated asset retirement obligation were principally related to changing expectations about Brent prices, which led the correlated fields to have longer economic lives. This review resulted in a decrease in the related provision of US$ 196 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.
Derivative transactions
SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Accounting for derivative transactions requires us to employ significant judgment to arrive at assumptions to compute fair market values which are used as the basis for recognition of the derivative instruments in the financial statements. Such measurement may depend on the use of estimates such as estimated future prices, long term interest rates and inflation indexes, and becomes increasingly complex when the instrument being valued does not have counterparts with similar characteristics traded in an active market.
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In the course of our business we have entered into contracts that meet the definition of derivatives under SFAS 133, certain of which have not qualified to receive hedge accounting. For the majority of these contracts, the estimates involved in the calculations for the fair value of such derivative instruments have not been considered likely to have a material impact in our financial position had we used different estimates, due to the majority of our derivative instruments being traditional over the counter instruments with short term maturities.
However, the estimates and assumptions used are critical to the determination of the mark to market value on one long term gas price contract that was signed in October 2002, with a gas producer and which constituted a derivative financial instrument under the requirements of SFAS 133. This contract was signed in connection with the long term contract to buy gas (“The Gas Supply Agreement” or “GSA”) to supply thermoelectric plants and for other uses in Brazil. The Natural Gas Price Volatility Reduction Contract (the “PVRC”), with maturity in 2019, was executed with the purpose to reduce the volatility of price under the GSA. The volume covered by the PVRC represents approximately 43% of the anticipated volume under the GSA.
Under the PVRC contract we recognize mark to market gains or losses according to the increase or decreases of the derivative’s fair value. Considering that there is no market quotations for natural gas for such a long duration as that of the PVRC, the fair value was calculated based on simulation using a mean reversion model developed by us. The most significant model assumptions at December 31, 2004 include starting prices of crude oil of US$ 39.53 per barrel, an average fuel oil basket (i.e., the price index of the GSA) of US$ 23.58 per barrel and a volatility of crude oil of 25% a.a. Other parameters of the model, including the long run average of crude oil, fuel oil spread to crude, correlations and inflation indexes were estimated based on historical averages.
Impact of New Accounting Standards
SFAS 19-1
The FASB adopted FASB Staff Position (“FSP SFAS 19-1”) on April 4, 2005, which amends SFAS 19 to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves that justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the viability of the project. The guidance in FSP SFAS 19-1 shall be applied prospectively in the third quarter of 2005 and we do not expect that it will have a material effect on our financial position or results from operations (see notes 2(s) and 27 to our audited consolidated financial statements for information related to the accounting policy currently practiced by us with respect to suspended exploratory wells).
FIN 46
In January 2003, the FASB issued Interpretation No. 46 (FIN 46)—Consolidation of Variable Interest Entities. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities disclosed by enterprises that do not control them through a majority voting interest. Under FIN 46, entities are required to be consolidated by an enterprise that has the obligation to absorb the majority of expected losses, or the right to receive the majority of expected returns from such entities. Entities identified with these characteristics are called variable interest entities and the interest that enterprises have in these entities are called variable interests. These interests may derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards to the enterprise with the controlling financing interest in such entities, irrespective of such enterprises’ voting interest in such entities.
We adopted FIN 46 in our 2003 financial statements. Such adoption resulted in the consolidation of a number of special purpose entities related to project financing arrangements in which we had an interest, and which were deemed to be variable interest entities for which we were the primary beneficiary. Prior to adoption of FIN 46, a significant portion of our share of commitments and debt obligations, as well as fixed asset contributions, were related to project financings and already included in the consolidated financial statements as the project financing transactions qualified as capital leases. As a result, adoption of FIN 46 related to the special purpose companies formed in connection with project finance arrangements did not have a significant impact on our financial condition or operating results. While we do not have specific assets set aside and established as collateral for these special purpose entities, we do have certain contractual obligations relating to the debt of the special purpose entities.
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As a result of our adoption of FIN 46, at December 31, 2003 we consolidated three thermoelectric power plants that we had previously accounted for as capital leases. With respect to these three thermoelectric plants, we elected to consolidate both assets and liabilities and results of operations, but that election did not have a material impact on our financial condition or operating results. We also determined that we are the primary beneficiary of three additional thermoelectric plants for which we have certain contractual obligations to bear energy market risk. The effect of the consolidation of the assets and liabilities of these three thermoelectric power plants at December 31, 2003 was an increase in our fixed assets of U.S.$1,142 million and an increase in our liabilities of U.S.$1,142 million. We did not consolidate the results of operations of these three thermoelectric plants in 2003 because at year-end 2003, FIN 46 only required balance sheet consolidation. However, results of operations for these companies were consolidated in 2004.
SFAS 153
FASB issued FASB Statement No. 153, “Exchanges of Non-monetary Assets — An Amendment of APB Opinion No. 29”, (“SFAS 153”) in December of 2004. SFAS 153 will be effective for us for asset-exchange transactions beginning on July 1, 2005. Under APB No. 29, assets received in certain types of non-monetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by SFAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, we have not engaged in a large number of non-monetary asset exchanges for significant amounts, and thus do not expect a material impact upon adoption.
FIN 47
FASB issued FASB Interpretation No 47, “Accounting for Conditional Asset Retirement Obligations, in March of 2005. FIN 47 clarifies the term “conditional asset retirement obligation” as used SFAS143 in order to avoid diversity in accounting practice with respect to the effect of uncertainties about the timing and/or method of settlement that are conditional on a future event, when recognizing the fair value of a liability for an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We do not expect that the adoption of FIN 47 will have a material effect on our financial position or results from operations when it becomes effective on December 31, 2005.
Research and Development
Since 1966, we have maintained a dedicated research and development facility in Rio de Janeiro, Brazil. As of December 31, 2004, we had 1560 employees working in this facility. We engage in joint research projects with universities and other research centers in Brazil and abroad. We spent U.S.$32 million in 2004 on joint projects with Brazilian universities and technological institutions, as compared to U.S.$28.5 million in 2003 and U.S.$18.4 million in 2002. Additionally, we participate in technology exchange and assistance projects with other oil and gas and oilfield service companies for other areas of our business. These transfers of technology are based on partnership agreements focusing on the exchange of information with respect to offshore systems and development of deepwater technologies and involve no material cost to us.
Our research and development facility researches various aspects of our oil and gas operations, including exploration, drilling, production, reservoir engineering and geology, fluid separation, well completion and refining process technology. This facility also engages in research on industrial catalysts, lubricants, fine chemicals, fuels, additives, petrochemicals and polymers for other areas of our business. Our research facility is also responsible for the basic design of new offshore fixed and semi-submersible platforms and subsea production systems, as well as new and reconstructed refining units, and has facilitated the development of important technologies, including semi-submersible production platforms capable of operating in water depths of up to 6,562 feet (2,000 meters).
As of December 31, 2004, we had 24 floating production systems in operation (12 semi-submersibles, 10 FPSO and 2 FSO). We have obtained 98 patents in Brazil and 193 abroad for a significant number of the technologies produced through research and development activities during the three-year period ended December 31, 2004.
Of the projects in which we are currently involved, three programs are key to our technological development activities. The first project, originally named PROCAP, is our technological development program for deepwater
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production systems, which was established in 1986 with a budget of U.S.$52 million to develop additional deepwater and ultra deepwater technology. This program is aimed at developing the fields discovered in waters of depths up to 3281 feet (1000 meters), enhancing recovery of oil and gas reserves, and extending the life of producer wells. In 1992, Petrobras initiated PROCAP 2000, which pursued the same objectives as PROCAP but at a depth of 7562 feet (2000 meters). In 2000, PROCAP 3000 was launched with a budget of U.S.$128 million over five years to provide technological solutions to produce and support the next phases of development of Marlim Sul, Roncador, Marlim Leste, Albacora Leste, Jubarte, the deep and ultra-deep blocks in the Santos and Espírito Santo basins, Gulf of Mexico and West Africa, in order to achieve production and extraction in water depths up to 9,842 feet (3,000 meters).
The second project, the Renewable Energy Technology Program – PROGER was created in 2004 to promote the research and development of technologies to enable and optimize the use of renewable energy sources. Such sources provide light, heating, air conditioning, mechanical force, transportation, telecommunications and fuel with minimum impact to the environment, reducing the effects of world climate changes caused by the use of hydrocarbons. The challenge we face with this program is to make the use of such energy sources more economical and to enable their widespread use. This program focuses on the research and development of wind energy, solar energy, biomass energy, bio-fuels (including bio-diesel), and energy from the sea and geo-thermal energy, among other sources.
The third project, the Strategic Refining Technology Development Program—PROTER, was created in 1994 for the development of heavy crude oil refining technology to transform it into lighter high-performance oil products. This program aims at developing new technologies and optimizing existing ones for the refining of our domestic heavy oil in a cost-effective way. We have been making substantial investments to accomplish this goal. Our professionals test novel refining techniques in our prototype plants, which are later introduced at our refineries. Many innovations developed under this program have been implemented in our refineries.
In addition to these projects, we have developed several other projects designed to:
PIFCo does not engage in research and development.
Trend Information
Crude oil prices
International oil prices increased at a record rate in 2004. The main factors driving this price increase include:
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Although our oil prices are influenced by international oil prices, the price we charge for oil is generally lower than international prices. The main reasons for such spread relate to the fact that the oil we produce is heavier, which requires more refining expenses, and there is less refining capacity available capable of processing our heavy oil. This spread increased in 2004.
Oil products prices
The prices for fuel oil did not grow as much as other oil products. With the increase in demand for oil products, refineries used more heavy oil that produces more residues, including fuel oil, than light oil. Because the demand was concentrated on light and medium oil products, there was an excess supply of fuel oil. This generated an increase in the price difference between heavy and light petroleum.
The use of substantially all available refining capacity in 2004 resulted in a year of record profit margins for the refining industry.
We expect that several of the structural factors contributing to growth in demand in 2004 will continue to influence the market. As a result, we believe that the trends described above will continue in the next few years.
For a description of other trends that might affect our financial condition and results of operation, see Item 4. “Information on the Company—Competition.”
Directors and Senior Management
Directors of Petrobras
Our board of directors is composed of a minimum of five and a maximum of nine members and is responsible for, among other things, establishing our general business policies. The members of the board of directors are elected at the annual general meeting of shareholders.
Under Brazilian Corporation Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates.
Furthermore, our bylaws enable each of (i) minority preferred shareholders that together hold at least 10% of the total capital stock (excluding the controlling shareholders); and (ii) minority common shareholders, to elect one member to our board of directors. Additionally, according to Law No. 10,683 of May 28, 2003, one of the members of the board of directors is appointed by the Minister of Budget and Management. Our bylaws provide that, independently from the exercise of the rights above granted to minority shareholders, the Brazilian government always has the right to appoint the majority of our directors. The maximum term for a director is one year, but re-election is permitted. In accordance with the Brazilian Corporation Law, the shareholders may remove any director from office at any time with or without cause at an extraordinary meeting of shareholders. Following an election of board members under the cumulative vote procedure, the removal of any board member by an extraordinary meeting of shareholders will result in the removal of all the other members, after which new elections must be held.
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We currently have nine directors. The following table sets forth certain information with respect to these directors:
BOARD OF DIRECTORS OF PETROBRAS
Name
Business Address
Palácio do Planalto, 4º andar, sala 16
Praça dos Três Poderes
Ministério da Fazenda – MF
70048-900, Brasília – DF
Rua Jeronimo da Veiga, 45, 13º andar Bairro Itaim Bibi 04536-000
São Paulo—SP
Av. Farrapos, 1811
90220-005, Porto Alegre – RS
Dilma Vana Rousseff - Ms. Rousseff has been the chair of our board of directors since January 3, 2003. She served as Minister of Mines and Energy of Brazil from January 1, 2003 until June 16, 2005, when she was appointed to be Minister Chief of Staff of Brazil. She has also served as: State Secretary of Energy, Mines and Communications of the State of Rio Grande do Sul (1993-1994 and 1999-2002); President of the Fundação de Economia e Estatística do Estado do Rio Grande do Sul (Economy and Statistics Foundation of the State of Rio Grande do Sul, 1991-1993); and Secretary of Finance of Porto Alegre (1986-1988). Ms. Rousseff has also participated, as Coordinator of the Infrastructure Group, in the previous Governmental Transition Team, which was created to facilitate the transition of power to the current government. Ms. Rousseff has a bachelors degree in economics from the Federal University of Rio Grande do Sul (1977), a masters degree in economic theory from the University of Campinas, São Paulo (1979) and is currently pursuing a doctorate degree in monetary and financial economy at the University of Campinas.
Jaques Wagner - Mr. Wagner has been a member of our board of directors since February 17, 2003. On January 1, 2003, Mr. Wagner was named Minister of Labor by President Luiz Ignacio Lula da Silva, leaving this position on January 26, 2004, to become Special Secretary to the Council of Economic and Social Development of the Presidency of the Republic. He has also served as: Representative before the Brazilian House of Representatives (1990-2002) and founder and director of the Sindicato dos Trabalhadores na Indústria Química do Estado da Bahia (State of Bahia Chemical Industry Workers’ Union, 1987-1989). Mr. Wagner is also a founder of the Workers’ Party and the Central Única dos Trabalhadores (Workers’ Unified Organization) in the State of Bahia.
Antonio Palocci Filho - Mr. Palocci has been a member of our board of directors since January 3, 2003 and is also a member of the board of directors of BR. Since January 1, 2003, he has held the post of Minister of Finance of
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Brazil. He has also served as: Mayor of Ribeirao Preto (2000-2002 and 1993-1996); Representative before the Brazilian House of Representatives (1999-2000); Representative before the State of São Paulo House of Representatives (1991-1992); and Councillor for the Municipality of Ribeirão Preto (1989-1990). Mr. Palocci has also served as President of the Partido dos Trabalhadores(Workers’ Party) for the State of São Paulo (1997-1998).
José Eduardo de Barros Dutra - Mr. Dutra has been a member of our board of directors since January 3, 2003 and is also a member of the boards of directors of BR, Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. In January 2003, the President of Brazil appointed him our president. He has also served as: Senator of the Republic of Brazil from the State of Sergipe (1995-2003) and President of the Sindicato dos Mineiros do Estado de Sergipe (State of Sergipe Miners Union, 1989-1994). Mr. Dutra has also served as leader of the Workers’ Party (1996-1997) and member of the Workers’ Party National Executive Committee, and has worked as a geologist on various projects.
Gleuber Vieira - Mr. Vieira has been a member of our board of directors since January 3, 2003 and is also a member of the board of directors of BR. Since 1987 he has been a General of the Brazilian Army and in 1995 he became a four star General. He has also served as: Chief of the Departamento de Ensino e Pesquisa (Learning and Research Department) of the Brazilian Army (1995-1997); Chief of the Brazilian Army (1999-2002); and Minister of the Army (1999-2002).
Arthur Antonio Sendas – Mr. Sendas is a member of our Board of Directors since March 29, 2004. He is also a member of the Board of Directors of Petrobras Distribuidora S/A. since March 29 2004. He is the President of the Sendas Group, which ranks as the leader in the retail sector in the state of Rio de Janeiro. Mr. Sendas is vice-president of the Advisory Council of the Brazilian Supermarkets Association—Abras and for five years represented the private sector on the National Monetary Council; he is president of the Board of Directors and the Executive Board of Sendas S/A., president of Sendas Empreendimentos e Participações Ltda., president of Sendas Agropecuária S/A., president of the Executive Board of Sendas Comércio Exterior S/A., president of the Executive Board of Casa Show S/A., president of the Board of Directors of Sendas Distribuidora S/A. The Sendas Group, through its various subsidiaries, owns approximately one-half of the supermarket chain under the following four brand names in the state of Rio de Janeiro: Sendas, Pão de Açúcar, Extra and ABC Barateiro, has significant equity stakes in large shopping centers, engages in residential and commercial construction projects and organizes coffee exports to the United States, Europe, Asia and the rest of Latin America, among other activities. He also sits on the Board of Directors of Cia. Brasileira de Distribuição—Pão de Açúcar, a group that coordinates the supervision of supermarket chains across 12 Brazilian states, and is a member Catholic University of Rio de Janeiro’s Development Council and president of the Board of Directors of the City of Rio de Janeiro Development Agency—Agência Rio.
Claudio Luiz da Silva Haddad - Mr. Haddad has been a member of our board of directors since January 22, 2003 and is also a member of the board of directors of BR. He also serves as a member of the Board of Directors of Grupo Abril. Since March 1999, he has been President and Chief Financial Officer of Ibmec São Paulo, a not-for-profit business and economics school in São Paulo. Mr. Haddad is the President and founder of Veris Educacional S.A. and the founder of Instituto Futuro Brasil, a think tank. He is a monthly contributor to the Brazilian magazine Valor Econômico. He has also served as: Chief Executive Officer of Banco de Investimentos Garantia S.A. (1992-1998), an investment bank specializing in fixed income and equity trading that was bought by Credit Suisse First Boston in 1998; Partner of Banco de Investimentos Garantia S.A. (1983-1998); Chief Economist of Banco de Investimentos Garantia S.A (1976-1979); and Director of the Central Bank of Brazil, responsible for public debt and open market operations (1980-1982). Mr. Haddad was a Professor of Economics at the Graduate School of Economics of Fundação Getúlio Vargas (1974-1980).
Fabio Colletti Barbosa - Mr. Barbosa has been a member of our board of directors since January 3, 2003 and is also a member of the board of directors of BR. Since 1998, he has been the Chief Executive Officer of the Banco ABN Amro Real S.A. He has also served as: Chief Executive Officer of ABN Amro Bank/São Paulo (1996-1998); Director of Corporate Banking & Finance of ABN Amro Bank/São Paulo (1995-1996); President of LTCB Latin America Ltda. (1992-1995), the Latin American affiliate of the Long Term Credit Bank of Japan; and member of the Treasury Department of Nestlé (1974-1986). Mr. Barbosa is also a member of the board of directors and the executive board of the Federação Brasileira das Associações de Bancos (Brazilian Bank Associations Federation—FEBRABAN), of Editora Abril and of the Conselho de Desenvolvimento Econômico e Social do Governo Federal (Brazilian Government Social and Economic Development Council).
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Jorge Gerdau Johannpeter - Mr. Johannpeter has been a member of our board of directors since October 19, 2001. He also serves as: coordinator of Ação Empresarial Brasileira (Brazilian Corporate Action), a non-governmental Brazilian organization addressing developmental issues; President of the Superior Council ofPrograma Gaúcho da Qualidade e Produtividade (Program for Quality and Productivity of the State of Rio Grande do Sul, or PGQP), which works with the public and private sectors in the implementation of total quality management; representative of the American Society for Quality (ASQ) in Brazil, a 104,000-member professional association headquartered in Milwaukee, Wisconsin that is dedicated to advanced learning and knowledge exchange to improve business results; member of the Board of Directors of Instituto Brasileiro de Siderurgia (the Brazilian Steel Institute, or the IBS); President of the Superior Council and founder of Movimento Brasil Competitivo (Competitive Brazil Movement, or MBC); member of the Board of Directors and Executive Committee of the International Iron and Steel Institute (IISI) and member of the Brazilian Government Social and Economic Development Council.
Directors of PIFCo
PIFCo is managed by a board of directors, consisting of three members, and by its executive officers. The board of directors is responsible for preparing PIFCo’s year-end accounts, convening shareholders’ meetings and reviewing and monitoring its financial performance and strategy. Although not required by PIFCo’s bylaws, it is PIFCo’s policy that the Chairman and all of its executive officers be Petrobras employees.
PIFCo’s directors serve indefinite terms and can be removed with or without cause. The following table sets forth certain information about PIFCo’s board of directors.
BOARD OF DIRECTORS OF PIFCo
Date of Birth
Position
Almir Guilherme Barbassa
Marcos Antonio Silva Menezes
Nilo Carvalho Vieira Filho
Almir Guilherme Barbassa. Mr. Barbassa has been PIFCo’s Chairman and Chief Executive Officer and Executive Manager of Corporate Finance of Petrobras since July 12, 1999. He joined Petrobras in 1974 and served in Braspetro as Financial Manager in the Middle East, North Africa, the United States and Brazil, and as Financial Director from 1993 to 1999. In addition, he was a professor in the economics department of the Petrópolis Catholic University and of the Faculdades Integradas Bennett from 1973 to 1979.
Marcos Antonio Silva Menezes. Mr. Menezes has been PIFCo’s Director and Executive Manager of the Accounting Department of Petrobras since 1998. He joined Petrobras in 1976 and served as Deputy Superintendent of the former SEFIN – Financial Services (1995-1998). He currently serves as a member of the fiscal council of Companhia de Gás de Minas Gerais – GASMIG (since 2005) and BRASKEM S.A. (since 2005), as well as the chairman of the fiscal council of Instituto Brasileiro de Petróleo e Gás (since 1998) and Organização Nacional das Indústrias de Petróleo—ONIP (since 1999).
Nilo Carvalho Vieira Filho. Mr. Vieira has been PIFCo’s Executive Manager of Marketing and Trading since June 25, 2004. He joined Petrobras in March 1985 as a supply engineer. Since then, he has occupied the positions of supply manager at Petrobras (1990-1994), head of external trading (1995-1999), Director of Braspetro (2000-2001) and Director of Eg3 in Argentina (2002-2004).
Executive Officers of Petrobras
Our board of executive officers, composed of one president and up to six executive officers, is responsible for our day-to-day management. Under our bylaws, the board of directors is entitled to elect the executive officers, including the president. The president must be chosen from among the members of the board of directors. All of the executive officers must be Brazilian nationals and reside in Brazil. The maximum term for executive officers is
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three years, but re-election is permitted. The board of directors may remove any executive officer from office at any time with or without cause. Four of the current executive officers are experienced managers, engineers or technicians from Petrobras, one of whom has served on the board of directors of one of our subsidiaries.
The following table sets forth certain information with respect to our executive officers:
EXECUTIVE OFFICERS OF PETROBRAS
Current Term
José Eduardo de Barros Dutra
J. S. Gabrielli de Azevedo
Renato de Souza Duque
Guilherme de Oliveira Estrella
Paulo Roberto Costa
Ildo Luís Sauer
Nestor Cuñat Cerveró
José Eduardo de Barros Dutra - Mr. Dutra has been President of our company since January 3, 2003 and has been a member of our board of directors since January 3, 2003. For biographical information regarding Mr. Dutra, see “—Directors and Senior Management of Petrobras—Our Board of Directors.”
J. S. Gabrielli de Azevedo - Mr. Gabrielli has been our Chief Financial Officer and Investor Relations Officer since January 31, 2003. Currently, Mr. Gabrielli is also a member of the boards of directors of Petrobras Energia Participaciones S.A. and of Petrobras Energia S.A. He holds a Ph.D. in economics from Boston University. He served as dean of the Economic Sciences School of the Federal University of Bahia and superintendent of the Fundação de Apoio a Pesquisa e Extensão (Foundation for Support of Research and Extension—Fapex). He was also a visiting researcher at the London School of Economics and Political Science in 2000 and 2001.
Renato de Souza Duque - Mr. Duque has been our Manager of Corporate Services since January 31, 2003. Currently, Mr. Duque is also a member of the boards of directors of Petrobras Energia Participaciones S.A., Petrobras Energia S.A. and Petrobras Gás S.A.—GASPETRO and Chief Executive Officer of Petrobras Negócios Eletrônicos S.A. He has been at our company since 1978, as a Petroleum Engineer, where he has held several positions, including: Manager of Human Resources for all of our operational units in the Exploration and Production area; Manager of Drilling Operations in the Campos Basin; and Manager of our owned platforms.
Guilherme de Oliveira Estrella - Mr. Estrella has been our Managing Director of Exploration and Production since January 31, 2003. Currently, Mr. Estrella is also a member of the boards of directors and executive boards of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A., and also serves as Chairman of the Board of the Instituto Brasileiro de Petróleo e Gás (Brazilian Oil and Gas Institute). He worked at our company from 1965 until 1994, when he retired as a geologist of our Exploration Department. Before his retirement, he held several other positions, including: General Superintendent (1989-1993); Superintendent of Research and Development for exploration, drilling and production (1985-1989); Head of the Exploration Division (1981-1985); Head of the Organic Geochemistry Sector (1981); Head of the Brazilian East Coast Basin Interpretation Sector of our Exploration Department—DEPEX/RJ (1978-1981); and Exploration Manager of Petrobras Internacional S.A.—BRASPETRO for Iraq (1976-1978). Mr. Estrella has also served as director of the Instituto Brasileiro de Petróleo e Gás.
Paulo Roberto Costa – Mr. Paulo Roberto has been our Director of Refining, Transportation and Marketing since May 14, 2004. Mr. Paulo Roberto graduated in Mechanical Engineering from the Federal University of Paraná in 1976 and specialized in Off-shore Engineering at Petrobras. From 1979 to 1994 he worked on platform installation and production development at the Campos basin in the areas of Engineering, Support Management and
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as Superintendent of the Southeastern Production Region. In 1995 he was promoted to General Manager of E&P Sul (Southern Brazil Exploration and Production), with responsibility for the Santos and Pelotas basins. In 1996 he became general manager for Logistics in the E&P area. From May 1997 to 1999 he headed up the Gas Segment, responsible for commercialization of natural gas. He was Director of Petrobras Gas S.A.-Gaspetro from May 1999 to December 2000. From January 2001 to April 2003, he was General Manager for Logistics at Petrobras of Natural Gas Segment. He has been Managing Director of TBG-Transportadora Brasileira Gasoduto Bolívia Brasil since April 2003. In May 14, 2004 he was appointed Downstream Director of Petróleo Brasileiro S.A. – Petrobras.
Ildo Luis Sauer—Dr. Sauer has been our Director for Gas and Energy since January 31, 2003. Currently, Dr. Sauer is also a member of the board of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. He holds a Ph.D. in nuclear engineering from the Massachusetts Institute of Technology. He also holds a MSc degree from COPPE—Federal University of Rio de Janeiro in Energy Planning/Nuclear Power. He is Professor at the Instituto de Eletrotécnica e Energia da Universidade de São Paulo (Electrotechnical and Energy Institute of the University of São Paulo), on leave, where he has published more than 100 technical papers and supervised more than 40 doctoral and master theses in the field. Previously, he has worked as a consultant at TecSauer Consultoria Ltda. and as manager of the nuclear reactor project for the Brazilian Navy.
Nestor Cuñat Cerveró - Mr. Cerveró has been our Manager of International Activities since January 31, 2003. Currently, Mr. Cerveró is also a member of the boards of directors of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. He has worked at our company since 1975, where he held several positions, including: Energy Manager, Programa de Termelétricas (Thermoelectrical Plants Program); Thermoelectrical Plants Manager of the Participations Superintendency; assistant to the CEO for the development of new ventures and partnerships; and Head of the Energy Sector of our industrial area. He has also represented our company at the boards of directors of several thermo-electrical energy companies and acted as assistant to the Presidência da Comercializadora Brasileira de Energia Emergencial (Presidency of the Brazilian Supplier of Emergencial Energy—CBEE) of the Ministry of Mines and Energy.
Executive Officers of PIFCo
All of the current executive officers are experienced managers from Petrobras, some of whom have served on the boards of directors of Petrobras subsidiaries and in representative offices abroad. The executive officers work as a board and are responsible for PIFCo’s day-to-day management. PIFCo’s executive officers serve indefinite terms and can be removed with or without cause.
The following table sets forth certain information about PIFCo’s executive officers.
EXECUTIVE OFFICERS OF PIFCo
Year ofAppointment
Guilherme Pontes Galvão França
Daniel Lima de Oliveira
Mariângela Monteiro Tizatto
Nilton Antônio de Almeida Maia
Gérson Luiz Gonçalves
Isabela Cesário de Faria Alvim
Guilherme Pontes Galvão França. Mr. França became an executive officer of PIFCo on March 7, 2005. He also serves as Manager of Clean Products Supply and Trading since December 2004. He joined Petrobras in 1982 and worked as a Commercialization and Supply Analyst in the logistics area of Petrobras from 1982 to 1990. In 1990 he moved to the trading area specializing in Lubricants and fuel oil. From 1993 to 2000, Mr. França served as Manager of Special Products Domestic Sales. From 2001 to 2004, he served as Manager of LPG Trading and Domestic Sales.
Daniel Lima de Oliveira. Mr. Lima de Oliveira became an executive officer of PIFCo on April 19, 2000. Mr. Lima is the acting chief financial officer of PIFCo. He joined Petrobras in 1976 as a supply engineer in the Commercial Department. In 1982 he moved to the Financial Department where he worked in the short-term credit
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division and served as Assistant to the General Manager. From 1984 until 1988, he served as Financial Manager of Petrobras’ London office. From 1988 to 1992, Mr. Lima de Oliveira served as manager at Braspetro. From 1992 to 1995, he served as Long-Term Credit Division Manager at Petrobras Financial Department. From 1995 to 1999, he served as a financial manager of Petrobras’ New York office. Since January 2002, he has been a director of Petrobras International Braspetro BV (PIB BV) and Braspetro Oil Services Company—BRASOIL and since March 2004 he has been a member of the Borad of Directors of REFAP S/A. He has served as PIFCo’s financial manager since 1999.
Mariângela Monteiro Tizatto. Ms. Tizatto has served as PIFCo’s Accounting Manager since April 4, 1998. She joined Petrobras in 1989 as an accountant in the Accounting Department. Since 1999, she has served as Petrobras’ General Manager for Accounting Operations. From 1990 to 1995, she was Manager of Petrobras’ Consolidated Accounting System, and from 1995 to 1999, she served as Manager of Petrobras’ Division of Corporate Accounting. Before joining Petrobras, Ms. Tizatto was Manager of Auditing for Deloitte Touche Tohmatsu, where she worked for seven years. She was also a professor of advanced accounting at the Faculdade Moraes Junior in Rio de Janeiro (1990).
Nilton Antônio de Almeida Maia. Mr. Maia has served as PIFCo’s Legal Manager since April 19, 2000. He joined Petrobras in 1984 as an internal auditor. He has served as a tax consultant to Petrobras’ Legal Department, and since early 2000, has served as General Manager for the Finance and Tax Division. Mr. Maia also currently serves as General Counsel for Petrobras. He has completed post-graduate degrees in law, with specializations in energy and tax law, from the Universidade Cândido Mendes and the Universidade Estácio de Sá.
Gerson Luiz Gonçalves. Mr. Gonçalves has served as PIFCo’s Auditor Manager since April 19, 2000. He joined the Internal Audit Department of Petrobras in 1976 and has been Petrobras’ Executive Manager for Internal Auditing for the last six years. He is responsible for all of Petrobras’ internal accounting control activities. Mr. Gonçalves is a member of the Brazilian Institute of Internal Auditors (AUDIBRA) and of the United States’ Institute of Internal Auditors (IIA).
Isabela Cesário de Faria Alvim. Ms. Alvim has served as PIFCo’s Secretary since April 2004. She joined Petrobras in 1984 as an analyst for Maritime Transport. In 1995 she moved from the Planning Department to the Financial Department. Ms. Alvim has served as Manager of Trade Lines, Guarantees and Structured Finance since 2001. She has been Subsidiaries’ Manager since April 2004.
Compensation
For 2004, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was approximately U.S.$2.0 million.
In addition, the members of the board and the executive officers receive certain additional benefits generally provided to our employees and their families, such as medical assistance, payment of educational expenses and supplementary social security benefits.
We have no service contracts with our directors providing for benefits upon termination of employment. We have a compensation and succession committee in the form of an advisory committee. See “—Advisory Committees—Petrobras.”
PIFCo’s directors and executive officers are paid by Petrobras in respect of their function as Petrobras’ employees, but they do not receive any additional compensation, pension or other benefits from PIFCo or Petrobras in respect of their functions as PIFCo’s directors or officers, as the case may be.
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Indemnification of Officers and Directors
Our bylaws require us to defend our senior management in administrative and legal proceedings and to maintain insurance coverage to protect senior management from liability arising from the performance of their functions. Subject to certain limitations, the policy reimburses losses and expenses due to wrongful acts of our directors and officers, such as breach of duty, neglect, error, misstatement, misleading statements, omission or acts by our directors and officers in the performance of their position, or any matter claimed against them solely by reason of their functions or positions, including the purchase or sale of our securities. Coverage includes the advancement of defense costs.
Share Ownership
As of May 31, 2005, the members of our board of directors, our executive officers, the members of our fiscal council, and close members of their families, as a group, beneficially held a total of 12 common shares and 510 preferred shares of our company. Accordingly, on an individual basis, and as a group, our directors, executive officers, fiscal council members, and close members of their families beneficially owned less than one percent of any class of our shares. The shares held by our directors, executive officers, fiscal council members, and close members of their families have the same voting rights as the shares of the same type and class that are held by our other shareholders. None of our directors, executive officers, fiscal council members, or close members of their families holds any options to purchase common shares or preferred shares. Petrobras does not have a stock option plan for its directors, officers and employees.
PEPSA has two stock option programs that grant its executive officers and senior managers options to (1) purchase shares of PEPSA at a set exercise price or to receive cash equal to the difference between the average market price of PEPSA shares during the 20 days prior to exercise date and the exercise price and (2) receive shares of PEPSA at no cost or receive cash equal to the market value of such shares.
As of May 31, 2005, PIFCo’s share capital was composed of 50,000 shares of common stock. All of PIFCo’s issued and outstanding shares of common stock are owned by us.
Fiscal Council
We have established a permanent fiscal council (conselho fiscal) in accordance with applicable provisions of the Brazilian Corporation Law, composed of up to five members. As required by the Brazilian Corporation Law our fiscal council is independent of our management and external auditors. The fiscal council’s responsibilities include, among others: (i) monitoring management’s activities and (ii) reviewing our annual report and financial statements. The members and their respective alternates are elected by the shareholders at the annual general shareholder’s meeting. Holders of preferred shares without voting rights and minority common shareholders are each entitled, as a class, to elect one member and his respective alternate to the fiscal council. The Brazilian government has the right to appoint the majority of the members of the fiscal council and their alternates. One of these members and his respective alternate are appointed by the Minister of Finance representing the Brazilian Treasury. The members of the fiscal council are elected at our annual general shareholders’ meeting for a one-year term and reelection is permitted.
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The following table lists the current members of the fiscal council:
FISCAL COUNCIL
Year of First Appointment
Marcus Pereira Aucélio
Denise Maria Ayres de Abreu
Túlio Luiz Zamin
Nelson Rocha Augusto
Maria Lúcia de Oliveira Falcón
The following table lists the alternate members of the fiscal council:
Eduardo Coutinho Guerra
Osvaldo Peterson Filho
Edison Freitas de Oliveira
Maria Auxiliadora Alves da Silva
Celso Barreto Neto
Advisory Committees
We also have three advisory committees to our board of directors as follows: Comitê de Auditoria, the audit committee, Comitê de Remuneração e Sucessão, the compensation and succession committee, and Comitê de Meio Ambiente, the environmental committee. The committee members are composed exclusively of members of our board of directors.
On June 17, 2005, our Board of Directors approved the appointment of our audit committee to satisfy the audit committee requirements of the Sarbanes-Oxley Act of 2002 and Rule 10A-3 under the Securities Exchange Act of 1934.
The audit committee is responsible for, among other things: (1) making recommendations to our Board of Directors with respect to the appointment, compensation and retention of our independent auditor; (2) assisting in the resolution of conflicts between management and the independent auditor with respect to our financial statements; and (3) establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal control and auditing matters, including procedures for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters. The members of our audit committee are Fabio Colletti Barbosa, Gleuber Vieira and Jaques Wagner.
Our audit committee’s charter is being amended to meet the audit committee requirements of the Sarbanes-Oxley Act of 2002 and Rule 10A-3 under the Securities Exchange Act of 1934, including the incorporation of the powers mentioned above, and we expect such amendments to be officially approved on or before July 31, 2005.
The compensation and succession committee is responsible for, among other things: (1) proposing remuneration packages for members of the board of directors and for the executive officers; (2) proposing performance targets for the executive officers; and (3) evaluating the effectiveness of procedures designed to retain talented employees. The members of our compensation and succession committee are Cláudio Luiz da Silva Haddad, Fabio Colletti Barbosa and Jaques Wagner.
The environmental 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 members of our environmental committee are Dilma Vana Rousseff, Jorge Gerdau Johannpeter and José Eduardo de Barros Dutra.
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PIFCo does not have any committees to its board of directors.
Employees and Labor Relations
We had 52,037 employees on December 31, 2004, compared to 48,798 employees on December 31, 2003 and 46,723 on December 31, 2002. The increase in the number of our employees in 2004 is primarily a result of the implementation of a hiring policy designed to meet our demand for more employees. This increased demand has resulted from the growth of our business and our desire to reduce the number of outsourced personnel. Expenses relating to employees of the parent company amounted to approximately R$4,374 million (U.S.$1,495 million) in 2004, R$3,612 million (U.S.$1,175 million) in 2003 and R$3,019 million (U.S.$1,033 million) in 2002. During 2004, these expenses represented 70% of our consolidated employee expenses.
Of the 52,037 employees of Petrobras on December 31, 2004, the parent company employed 39,091. Of these 39,091 employees, 27,404 occupied mid-level positions related to operations and administrative support, and 10,749 worked as upper-level employees in engineering and administration. The remaining 938 employees of the parent company were maritime employees. 67% of the parent company’s workforce was located in the Southeast region of Brazil, 27% was located in the Northeast region, and the remaining 6% was elsewhere.
We negotiate annually collective bargaining agreements with the Oil Workers’ Unified Federation, the union to which our onshore employees are affiliated, and the Maritime Employee’s Union, the union to which our maritime employees are affiliated. The current collective bargaining agreement with the Oil Workers’ Unified Federation was signed on November 29, 2004, and is retroactive to September 1, 2004. This collective bargaining agreement will expire on August 31, 2005. The current collective bargaining agreement with the maritime employees’ union was signed on April 11, 2005, and is retroactive to November 1, 2004. This collective bargaining agreement will expire on October 31, 2005.
We consider our relations with our employees and with the Oil Worker’s Unified Federation and maritime employee’s union to be satisfactory.
Under the terms of the new collective bargaining agreements for our onshore and maritime employees, we agreed, among other things, to increase the salary of oil workers by 7.81% and grant a single level pay scale raise to all employees, effective retroactively to September and November 2004, respectively.
A labor strike has not caused a material decrease in production since 1995, when our oil workers held a 30-day strike to protest the amendment to the Brazilian constitution under which we ceased to be the Brazilian government’s exclusive agent in the Brazilian hydrocarbon industry. The strike caused a significant decrease in our production and refining output and led to a substantial increase in the level of our imports. Since then, the most significant strike occurred in 2001, when our oil workers were on strike for five days. During 2004, there were work disturbances during the period of negotiation of the new collective bargaining agreements, which included partial work stoppages lasting 24 hours and delays to initiate the working day. Such disturbances did not have a negative effect on our results.
We spent approximately R$274.7 million (U.S.$93.9 million) on employee training in 2004 at our training centers, as compared to R$275.1 million (U.S.$89.5 million) in 2003.
With the enactment of the Oil Law and the emergence of competitors in the Brazilian oil sector, we have developed a strategic plan to provide incentives to attract new employees and to retain existing ones. We have also implemented a management improvement plan, which will focus on training our management-level employees to enable them to develop the skills necessary to operate in a free-market economy. As part of our employee incentives, we have merit-based promotions and, as permitted by Brazilian law, a profit sharing plan with predetermined criteria. Pursuant to this plan, the amount of the profit sharing is determined by our Board of Directors and the manner of distribution is determined by negotiation with the labor unions representing our
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employees. However, under Brazilian law, the profit sharing plan will be subject to an annual limit equal to 25% of total proposed dividends for the year.
Our profit sharing distributions to our employees within the entire Petrobras Group were R$783 million (U.S.$295 million) for 2004, R$894 million (U.S.$291 million) for 2003 and R$444 million (U.S.$152 million) for 2002. At Petrobras’ annual general shareholders’ meeting held on March 31, 2005, its shareholders approved a profit sharing distribution to Petrobras employees (excluding subsidiaries) of R$660 million (U.S.$248 million) for 2004. In April and May 2005, Petrobras approved an additional profit sharing distribution totalling R$66.0 million (U.S.$29.9 million) to complement this amount. Our subsidiaries approved a total profit sharing distributions to their employees of R$123 million (U.S.$46 million) at their annual general shareholders’ meetings in March 2005.
Our Pension and Health Care Plans
We sponsor a contributory defined benefit pension plan known as PETROS, which covers approximately 80% of our employees. The principal objective of PETROS has been to supplement the social security pension benefits of our employees, as well as employees of our subsidiaries and affiliates, certain other companies and PETROS itself. Employees that participate make mandatory monthly contributions. Our historical funding policy has been to make annual contributions to the plan in the amount determined by actuarial appraisals. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. We made contributions of U.S.$435 million in 2004, as compared to contributions of U.S.$402 million in 2003. We recorded a liability of U.S.$3,081 million in 2004, U.S.$2,055 million in 2003 and U.S.$1,452 million in 2002 for the excess of the actuarial value of our obligation to provide future benefits over the fair value of the plan assets used to satisfy that obligation. See Note 18 to our audited consolidated financial statements.
In addition, some of our consolidated subsidiaries, including PEPSA and Liquigás, have defined benefit plans with substantially similar items.
On May 11, 2001, our board of directors approved the creation of a new mixed benefit plan for existing, active and inactive employees. The plan, Petrobras VIDA, was designed to attract and retain qualified professionals and to reduce our pension obligations. The Secretaria de Previdência Complementar (Supplemental Pension Plan Secretariat), the government entity empowered to authorize the creation of pension plans in Brazil, and other relevant authorities, approved the plan on September 20, 2001. In 2004, we cancelled the Petrobras VIDA plan as a result of certain legal proceedings filed by the Oil Workers Federation in connection with the plan. See Item 8. “Financial Information—Legal Proceedings—Labor Claims.”
Since the PETROS plan is not admitting new participants since August 9, 2002, employees hired since that date are covered by specific insurance policies, and will continue to be covered by such policies until we are able to offer them a supplemental pension plan.
During the negotiation of our collective bargaining agreement in 2003, a working group composed of representatives of Petrobras, the Oil Workers Federation and PETROS was created to evaluate our current pension system and formulate recommendations for change. The working group presented its preliminary conclusions to our management in 2004, but our management has requested additional information, which has not yet been provided.
We maintain a health care benefit plan (AMS), which offers defined benefits and covers all employees (active and inactive) together with their dependents. We manage the plan, with the employees contributing fixed amounts to cover principal risks and a portion of the costs relating to other types of coverage in accordance with participation tables defined by certain parameters, including salary levels.
Our commitment related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The health care plan is not funded or otherwise collateralized by assets. Instead, we make benefit payments based on annual costs incurred by plan participants.
The actuarial gains and losses arising from the differences between the actuarial assumptions and the costs effectively incurred are respectively included or excluded when defining the net actuarial liability. These gains and losses are amortized over the average remaining service period of the active employees. In 2004, we have revised
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some of these actuarial assumptions. See Item 5. “Operating and Financial Review and Prospects—Critical Accounting Policies and Estimates—Pension and Other Post-Retirement Benefits”
With the exception of sixteen employees of PEL, PIFCo’s personnel consist solely of Petrobras employees, and PIFCo relies on Petrobras to provide all administrative functions.
Major Shareholders
Our capital stock is composed of common shares and preferred shares, all without par value. On May 31, 2005, there were 634,168,418 outstanding common shares and 462,369,507 outstanding preferred shares. On April 24, 2000, effective as of May 23, 2000, our board of directors approved a 1 for 100 reverse stock split.
We have convened an extraordinary shareholders’ meeting for July 22, 2005 to approve a resolution to split our shares. If approved, each of our common and preferred shares will be split into four common and preferred shares, respectively. After the share split, our outstanding shares will be comprised of 2,536,673,672 common shares and 1,849,478,028 preferred shares and each of our ADS will represent 4 common or preferred shares, as the case may be.
Under the Brazilian Corporation Law, as amended, the number of non-voting shares of our company may not exceed two-thirds of the total number of shares. The Brazilian government is required by law to own at least a majority of our voting stock and currently owns 55.7% of our common shares, which are our only voting shares. The Brazilian government does not have any special voting rights, other than the right to always appoint a majority of our directors, irrespective of the rights our minority shareholders may have to elect directors, set forth in our by-laws.
The following table sets forth information concerning the ownership of our common shares and preferred shares as of May 31, 2005 by the Brazilian government, certain public sector entities and our officers and directors as a group. We are not aware of any other shareholder owning more than 5% of our common shares.
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Shareholder
Brazilian government
BNDES Participações S.A.-BNDESPAR
Other Brazilian public sector entities
All directors and executive officers as a Group (15 persons)
In August 2000, the Brazilian government sold 180,609,768 of our common shares, reducing its percentage of ownership of our common shares from 84% to the current preferred 55.7%. In July 2001, BNDES sold 41,381,826 of our preferred shares, which constituted its entire holdings of our preferred shares.
On March 29, 2004 our shareholders approved an increase in our authorized capital from R$30 billion (U.S.$10.2 billion) to R$60 billion (U.S.$20.4 billion).
As of May 31, 2005, approximately 38.5% of our preferred shares and approximately 27.5% of our common shares were held of record in the United States directly or in the form of American Depositary Shares. As of May 31, 2005, we had approximately 176,470,211 record holders of preferred shares, or American Depositary Shares representing preferred shares, and approximately 174,204,004 record holders of common shares, or American Depositary Shares representing common shares, in the United States.
As of May 31, 2005, PIFCo’s capital stock was composed of 50,000 shares of common stock. All of PIFCo’s issued and outstanding shares are owned by us.
Petrobras Related Party Transactions
Board of Directors
Direct transactions with interested members of our board of directors or our executive officers require the approval of our board of directors. None of the members of our board of directors, our executive officers or close members of their families has had any direct interest in any transaction we effected which is or was unusual in its nature or conditions or material to our business during the current or the three immediately preceding financial years or during any earlier financial year, which transaction remains in any way outstanding or unperformed. In addition, we have not entered into any transaction with related parties which is or was unusual in its nature or conditions during the current or the three immediately preceding financial years, nor is any such transaction proposed, that is or would be material to our business.
We have no outstanding loans or guarantees to the members of our board of directors, our executive officers or any close member of their families.
For a description of the shares beneficially held by the members of our board of directors and close members of their families, see Item 6. “Directors, Senior Management and Employees—Share Ownership.”
Brazilian Government and PETROS
We engage in numerous transactions in the ordinary course of business with our controlling shareholder, the Brazilian government, and with other companies controlled by it, including financings from BNDES and banking, asset management and other transactions with Banco do Brasil S.A.
The above mentioned transactions with Banco do Brasil had a net amount of US$3,891 million as of December 31, 2004.
As of December 31, 2004, we recorded transactions with the Brazilian government and other subsidiaries controlled by it relating to accounts receivable due to oil products supply through our consolidated subsidiary BR Distsribuidora in the amount of U.S.$264 million.
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As of December 31, 2004, we had a receivable (the Petroleum and Alcohol Account) from the Brazilian government, our controlling shareholder, of U.S.$282 million secured by a U.S.$53 million blocked deposit account. See Item 4. “Regulation of the Oil and Gas Industry in Brazil—The Petroleum and Alcohol Account.”
We also have restricted deposits made by us which serve as collateral for legal proceedings involving the Brazilian government. As of December 31, 2004, these deposits amounted to U.S.$418 million.
Additionally, according to Brazilian law, we are only permitted to invest in securities issued by the Brazilian Government in Brazil. This restriction does not apply to investment outside of Brazil. As of December 31, 2004, the value of these government securities which have been directly acquired and held by us amounted to U.S.$87 million.
We also have accounted for related party transactions with PETROS, basically composed of government securities advanced by us to compose the plans assets. As of December 31, 2004, the value of these securities amounted to U.S.$326 million. In addition, PETROS also makes direct investments in government securities.
For additional information regarding our principal transactions with related parties, see Note 26 to our audited consolidated financial statements.
PIFCo Related Party Transactions
As a result of being our wholly-owned subsidiary, PIFCo has numerous transactions with us and other affiliated companies in the ordinary course of business. PIFCo’s primary business is to serve 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 represents a premium to compensate PIFCo for its financing costs. Substantially all of PIFCo’s revenues are generated by transactions with us.
Since PIFCo’s inception there have been no, and there are no proposed, material transactions with any of PIFCo’s officers and directors. PIFCo does not extend any loans to its officers and directors.
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PIFCo’s transactions with related parties resulted in the following balances in 2004 and 2003:
Accounts receivable
Notes receivable(1)
Exports Prepayment
Other non current
Exports prepayment
Liabilities
Trade accounts Payable
Notes payable(1)
Unearned income
Long-term liabilities
Notes payable (1)
Long-term
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PIFCo’s principal transactions with related parties are as follows:
Sales of crude oil and oil products and services
PETROBRAS
REFAP S.A.
Petrobras America, Inc.—PAI
BR Distribuidora
EG3 S.A.
Braspetro Oil Services Company—BRASOIL
Companhia MEGA S.A.
Eg3 S.A.
Fronape International Company
PIB.B.V.
PEBIS
Petrobras Energia
Lease income (expense)
Selling, general and administrative expense
Braspetro Oil Company—BOC
PIB.B.V
Marlim
Other Income and Expense
PNBV
Petrobras Consolidated Statements and Other Financial Information
See Item 18. “Financial Statements” and “Index to Financial Statements.”
PIFCo Consolidated Statements and Other Financial Information
Legal Proceedings
We are currently subject to numerous proceedings relating to civil, criminal, administrative, environmental, labor and tax claims. Several individual disputes account for a significant part of the total amount of claims against
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us. Our audited consolidated financial statements only include provisions for probable and reasonably estimable losses and expenses we may incur “in connection with pending litigation, including the proceedings described below under “Environmental Claims.” See Note 21 to our audited consolidated financial statements. The table below sets forth our recorded financial provisions by type of claim:
PROVISIONS BY TYPE OF CLAIM(1)
Labor claims
Tax claims
Civil claims
Commercial claims and other contingencies
Claims against Petrobras, the parent company, which as of December 31, 2004, corresponded to approximately 34.9% of the total amount of claims against us, have decreased and the amounts paid by us in respect of legal claims against Petrobras in each of the last five years have never exceeded U.S.$58.5 million. As of December 31, 2004, we estimated that the total amount of claims against us, excluding disputes involving non-monetary claims or claims not reasonably estimable in the current stage of the proceedings, was approximately U.S.$7.1 billion.
The most significant claims are described below:
On November 23, 1992, Porto Seguro Imóveis Ltda., a minority shareholder of Petroquisa, filed a lawsuit against us in a State Court of Rio de Janeiro for alleged losses suffered as a result of the sale of the share participation held by Petroquisa in various petrochemical companies included in the National Privatization Program (Programa Nacional de Desestatização). The plaintiff in the lawsuit requests that we, as controlling shareholder of Petroquisa, be compelled to reinstate the damages made to Petroquisa’s equity, as a consequence of the corporate acts that approved the minimum sales price attributed to its share participation in the capital of the privatized companies. An initial decision on January 14, 1997 held us liable to Petroquisa for damages in an amount equivalent to U.S.$3.406 million. Additionally, we were required to pay the plaintiff 5% of the indemnification amount as a premium as well as lawyers’ fees of 20% over that amount. However, since the amount due is payable to Petroquisa, not the plaintiff, and we own 99.0% of Petroquisa’s share capital, the actual disbursement, in case the decision is not dismissed, will be limited to such 25% of the damages amount, or U.S.$851 million. We appealed and prevailed in canceling the judgment, but a subsequent appellate decision on March 30, 2004 found us liable for U.S.$2.36 billion, plus a 5% premium and 20% of attorney’s fees, all payable to Petroquisa. We will now file appeals to both the Superior Justice Tribunal and to the Federal Supreme Court.
On May 28, 1981, Kallium Mineração S.A. brought an action against Petromisa, our former subsidiary, in the Federal Court of the State of Rio de Janeiro alleging damages of R$1,044 million (U.S.$450 million) relating to the rescission of a contract to develop a potassium salt mine. On August 10, 1999, the trial judge dismissed most of the plaintiff’s claims and ordered us to indemnify the plaintiff only with respect to the preliminary research expenses it had incurred. Both parties have appealed the decision. If Kallium prevails on appeal, we would be required to pay an additional amount of 10% of any judgment to cover attorneys’ fees.
Several individuals have filed a lawsuit (an ação popular) against us, Repsol-YPF and the Brazilian government seeking to unwind the 2001 exchange of certain of our operating assets in Brazil for some of YPF’s operating assets in Argentina. The plaintiffs maintain that the assets exchanged were not properly valued and that, therefore, the transaction was not in our best interests. On September 5, 2002, the Fourth Chamber of the Brazilian Federal Court of Appeals for the Fourth Region granted an injunction to the plaintiffs. The Superior Court of Justice of Brazil suspended the injunction, stressing that the transaction had been approved by the Brazilian antitrust authorities, the ANP and the Brazilian Federal Audit Court. We are awaiting a final disposition on the merits.
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Certain independent distributors located throughout Brazil have brought civil claims against us. Collectively, these claims total approximately R$821.48 million (U.S.$394 million) and aim at the restitution of the ICMS retained from such distributors and collected by us in favor of many states, plus damages. We believe these taxes were properly collected and represent valid state value-added tax credits. However, in connection with these claims, approximately R$76 million (U.S.$32 million) in injunctive relief was declared against us in various local courts and seized from our accounts in several jurisdictions in anticipation of favorable judgments for the distributors. Upon appeal, these rulings were subsequently overruled, but we are awaiting a final disposition on the merits of these cases.
On behalf of the special purpose company involved in the U.S.$2.5 billion Barracuda/Caratinga project financing, we were party to a negotiation with Halliburton and its subsidiary, Kellogg Brown & Root, Inc., KBR, relating to certain project construction delays and cost overruns. Prior to settlement, the total amount of the KBR remaining claims against the special purpose company was approximately U.S.$375 million and the total amount of claims that we and the special purpose company had against Halliburton and KBR, in addition to liquidated damages, and was approximately U.S.$380 million. On December 6, 2004, with the approval by the project lenders, we reached an agreement with Halliburton and KBR for settlement of these claims releasing all parties from the claims. As part of the settlement arrangements, the amounts due under the original contracts were readjusted including an additional payment of U.S.$79 million to KBR and we agreed, on behalf of the special purpose company of the project, to receive from KBR on December 7, 2004 only part of the total amount of certain mobilization payment repayment, the balance being paid with accrued interest in installments due up to February 2005. Additionally, we agreed to extend certain construction deadlines and reduce the scope of the works to be performed by KBR to complete the construction of the oil platforms to be delivered in connection with the project and perform works related to the assisted operation phase after the platforms depart their docks.
On January 18, 2000, a pipeline connecting one of our terminals to a refinery in Guanabara Bay ruptured, causing a release of approximately 341,000 gallons of crude oil into the bay. We undertook action to control the spill in an effort to prevent the oil from threatening additional areas. As a result of this spill, 338 individual lawsuits were filed by fishermen of the State of Rio de Janeiro claiming damages in an aggregate amount of approximately R$100 million. Approximately half of the cases brought so far have been decided against us. In addition, the Federation of Fishermen of the State of Rio de Janeiro filed a lawsuit against us claiming damages of approximately R$537 million. On February 7, 2002, the judge hearing this matter found that damages were due, but not in the amount claimed. Both parties appealed this decision. On October 8, 2002, the Court of Appeals of the State of Rio de Janeiro denied the appeal filed by the plaintiff and dismissed the claim with respect to all fishermen who had already settled their claims against us or who had already filed individual lawsuits against us, and also with respect to certain other fishermen. These dismissals dramatically reduced the number of plaintiffs who could be entitled to damages. We have filed additional appeals and are awaiting a final decision.
Labor Claims
We are a defendant in five labor lawsuits filed by the Oil Workers Federation with three different state labor courts related to our alleged failure to index salaries in accordance with the official inflation rates published by the Brazilian government during the years 1987, 1989 and 1990. The lawsuits are each at different stages of the litigation process.
On November 23, 2001, the Oil Workers Federation, which represents approximately 96.7% of our workers, filed a lawsuit against the Supplemental Pension Plan Secretariat, seeking to prevent the approval of Petrobras VIDA. An initial judicial decision by a lower court annulled the plan, but that decision is currently being reviewed by an appeals court. Although some employees had already opted to migrate to the plan, an injunction was granted on January 10, 2002, which resulted in the suspension of the plan and which prevented us from including any employees under this plan. In 2004, we cancelled this plan. See Item 6. “Directors, Senior Management and Employees—Employees and Labor Relations—Our Pension and Health Care Plans.”
Tax Claims
We received several tax assessments from the INSS alleging irregular presentation of documentation by construction companies and other service providers under contract with us with regard to their INSS contributions. The INSS seeks to hold us jointly and severally liable for contributions not made by these providers. We are analyzing each of the INSS’s assessments in order to attempt to recover payments that we made to the INSS with respect to these tax assessments. In addition, we intend to take action against service providers in order to recover any amounts paid and not recovered from the INSS. Because it is unlikely that we will successfully obtain a reversal of the INSS’s decision through the agency’s administrative procedures, at December 31, 2004, we had a balance of U.S.$107 million in our provision to cover future payments to the INSS.
Federal tax authorities (Delegacia da Receita Federal) have served us with a tax assessment of approximately R$566 million related to a withholding tax (IRRF) that they believe should have been paid in connection with remittances we made abroad between 1999 and 2002. The remittances were related to the purchase of imported oil by Petrobras. According to the federal tax authorities, such remittances corresponded to interest payments, which they believe would give rise to the tax levy they claim. However, the importation documents do not make reference to the alleged interest payments. Petrobras is currently challenging the tax assessment.
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The Rio de Janeiro branch of the Brazilian Revenue Service (Secretaria da Receita Federal) has asserted that, under Brazilian law, drilling and production platforms may not be classified as sea-going vessels and therefore should not be chartered but leased. Based on this interpretation of Brazilian law, overseas remittances for charter payments would be reclassified as lease payments, and would be subject to withholding tax at the rate of 25%. The Brazilian Revenue Service has filed two tax assessments against us in connection with the withholding tax (IRRF) on foreign remittances of payments related to the charter of vessels of movable platform types. On February 17, 2003, the Brazilian Revenue Service served us with a tax assessment notice for R$93 million (approximately U.S.$32 million) covering disputed taxes for 1998. On June 27, 2003, the Brazilian Revenue Service served us with a tax assessment notice for R$3,064 million (approximately U.S.$1,066 million) covering disputed taxes for the period from 1999 to 2002. We appealed the two unfavorable rulings from the Brazilian Revenue Service with respect to these tax assessments to a higher administrative court. On February 24, 2005, the Sixth Chamber of the First Taxpayers’ Council of the Ministry of Finance denied two voluntary appeals filed by us, upholding the tax assessments imposed by the Federal Revenue Office in Rio de Janeiro when it held that drilling and production platforms may not be classified as sea-going vessels and therefore should be leased, not chartered. We will continue to appeal the tax assessment at the federal administrative level and later at the federal judicial level, if necessary.
Environmental Claims
In the period between 2000 to 2004, we experienced several accidents, some of them leading to significant oil spills: 140,000 gallons in 2004, 73,000 gallons in 2003, 52,000 gallons in 2002 and 691,000 gallons in 2001. As a result of certain of these accidents, we remain subject to several administrative, civil and criminal investigations and proceedings. We cannot predict whether additional litigation will result from those accidents or whether any such additional proceedings would have a material adverse effect on us. See Note 21(d) to our audited consolidated financial statements.
January 2000 spill—Guanabara Bay
On January 18, 2000, a pipeline connecting one of our terminals to a refinery in Guanabara Bay ruptured, causing a release of approximately 341,000 gallons of crude oil into the bay. We undertook action to control the spill in an effort to prevent the oil from threatening additional areas. We have spent approximately R$104 million in connection with the clean-up efforts and fines imposed by IBAMA in connection with this spill, and are subject to several legal proceedings as a result of this spill, including:
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July 2000 Spill—Curitiba
On July 16, 2000, an oil spill occurred at our President Getúlio Vargas refinery, located approximately 15 miles (24 kilometers) from Curitiba, capital of the State of Paraná, releasing approximately 1.06 million gallons of crude oil into the surrounding area. We spent approximately R$74 million on the clean-up effort and fines imposed by the State of Paraná authorities. In addition, in relation to this spill:
February 2001 spill—Rivers in the State of Paraná
On February 16, 2001, our Araucária-Paranaguá pipeline ruptured as a result of an unusual movement of the soil and spilled approximately 15,059 gallons of fuel oil into several rivers located in the State of Paraná. On February 20, 2001, we finalized the cleaning of the river surfaces, recovering approximately 13,738 gallons of fuel oil. As a result of the accident:
March 2001 gas explosion and spill—Roncador field
On March 15, 2001, a gas explosion inside one of the columns of the P-36 production platform, located in the Roncador field (75 miles off the Brazilian coast) led to the death of 11 employees and eventual sinking of the platform. The accident also caused 396,300 gallons of oil to spill into the ocean. As a result of the accident:
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October 2002 FPSO accident
On October 13, 2002, a power blackout in FPSO P-34, which is located in the Barracuda-Caratinga fields, affected the ship’s water balance system and caused water to move from storage tanks located in one side of the ship to the tanks located in the opposite side, causing the FPSO to roll up to an angle of 40 degrees. Four days later, the stability of the ship had been restored, without casualties or spill of oil into the sea. As a result of the investigation of this accident, several measures to prevent similar accidents were incorporated into our Programa de Excelência Operacional-PEO(Operational Excellence Program). In connection with the accident:
Pollution
On January 15, 1986, the Public Ministry of the State of São Paulo and the União dos Defensores da Terra (Union for Defense of the Earth), filed a public civil action against us and 23 other companies in the State Court of São Paulo for alleged damages caused by pollution. This lawsuit is entering the discovery phase. Although the plaintiffs alleged damages of U.S.$89,500 in an initial pleading filed with the Court, the Public Ministry of the State of São Paulo has publicly stated that U.S.$800 million will be ultimately required to remedy the alleged environmental damage. The Court refused to assert joint and several liability of the defendants, and we believe that it will be difficult to determine the environmental damage attributable to each defendant.
There is no litigation or governmental proceeding pending or, to PIFCo’s knowledge, threatened against PIFCo’s or any of its subsidiaries that, if adversely determined, would have a significant effect on its financial position or profitability.
Dividend Distribution
The tables below describe our dividend payments for the last five fiscal years, including amounts paid in the form of interest on shareholders’ equity.
Dividends paid to shareholders
Dividends paid to minority interests
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For our policy on mandatory dividend distribution see Item 10. “Additional Information—Memorandum and Articles of Incorporation of Petrobras—Payment of Dividends and Interest on Shareholders’ Equity” and Item 10. “Additional Information—Memorandum and Articles of Incorporation of Petrobras—Mandatory Distribution.” We may change our dividend policy at any time within the limits set forth by Brazilian law.
For a description of PIFCo’s dividend distribution policy, see “Item 10. Additional Information—Memorandum and Articles of Association of PIFCo—Rights and Obligations of Shareholders—Dividends.”
Trading Markets
Our shares and ADSs are listed or quoted on the following markets:
Our common and preferred shares are traded on the São Paulo Stock Exchange since 1968. Our ADSs representing one common share and our ADSs representing one preferred share are traded on the New York Stock Exchange since 2000 and 2001, respectively. Citibank N.A. serves as the depositary for both the common and preferred ADSs. Our common and preferred shares are traded on the LATIBEX since 2002. The LATIBEX is an electronic market created in 1999 by the Madrid stock exchange in order to enable trading of Latin American equity securities in euro denominations.
We are currently applying for listing of our shares on the Buenos Aires Stock Exchange, but we cannot predict when or whether our application will be approved.
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Price Information
São Paulo Stock Exchange
The tables below set forth reported high and low closing sale prices in Reais per common and preferred share and the reported average daily trading volume in common and preferred shares on the São Paulo Stock Exchange for the periods indicated. The table also sets forth prices in U.S. dollars per common and preferred share at the commercial market rate for the purchase of U.S. dollars, as reported by the Central Bank of Brazil, for each of the dates of such quotations. See Item 3. “Key Information—Exchange Rates” for information with respect to exchange rates applicable during the periods set forth below.
2003:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2004:
2005:
November
December
January
February
March
April
May
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The tables below set forth the reported high and low closing sale prices per ADSs representing one common share and ADSs representing one preferred share and their reported average daily trading volume on the New York Stock Exchange for the periods indicated.
Reais per ADS representing
One Common Share
U.S. dollars per ADS representing
Average Number
of ADS representing
Traded per Day
One Preferred Share
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Markets
The São Paulo Stock Exchange
In Brazil, securities are traded only on the São Paulo Stock Exchange, with the exception of electronically traded public debt securities. Privatization auctions are conducted on the Rio de Janeiro Stock Exchange.
If you were to trade in our common or preferred shares on the São Paulo Stock Exchange, your trade would settle in three business days after the trade without adjustment of the purchase price for inflation. The seller is ordinarily required to deliver the shares to the exchange on the second business day following the trade date. Delivery of and payment for shares are made through the facilities of the clearinghouse, or Companhia Brasileira de Liquidação e Custódia, known as CBLC.
The São Paulo Stock Exchange is a nonprofit entity owned by its member brokerage firms. Trading on each exchange is limited to member brokerage firms and a number of authorized nonmembers. The São Paulo Stock Exchange has two open outcry trading sessions each day from 11:00 a.m. to 1:30 p.m. and from 2:30 p.m. to 6:00 p.m. Brazil local time, except during daylight savings time in the United States. During daylight savings time in the United States, the sessions are from 10:00 a.m. to 1:00 p.m. and from 2:00 p.m. to 5:00 p.m. Brazil local time, to closely mirror New York Stock Exchange trading hours. Trading is also conducted between 11:00 a.m. and 6:00 p.m., or between 10:00 a.m. and 5:00 p.m. during daylight savings time in the United States, on an automated system known as the Sistema de Negociação Assistida por Computador (Computer Assisted Trading System) on the São Paulo Stock Exchange. The São Paulo Stock Exchange also permits trading from 6:30 p.m. to 7:30 p.m. (or from 5:45 p.m. to 7:00 p.m. during daylight savings time in the United States) on an online system connected to traditional and internet brokers called the “After Market.” Trading on the After Market is subject to regulatory limits on price volatility and on the volume of shares transacted through internet brokers. There are no specialists or officially recognized market makers for our shares.
In order to better control volatility, the São Paulo Stock Exchange adopted a “circuit breaker” system pursuant to which trading sessions may be suspended for a period of thirty minutes or one hour whenever the indices of these stock exchanges fall below the limits of 10% or 15%, respectively, in relation to the index registered in the previous trading session.
The São Paulo Stock Exchange is less liquid than the New York Stock Exchange or other major exchanges in the world. At December 31, 2004, the aggregate market capitalization of the 394 companies listed on the São Paulo Stock Exchange was approximately U.S.$340.9 billion and the ten largest companies represented approximately 49% of the total market capitalization of all listed companies. All the outstanding shares of an exchange-listed company may trade on the São Paulo Stock Exchange, but in most cases, less than half of the listed shares are
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actually available for trading by the public. The remainder is held by small groups of controlling persons, by governmental entities or by one principal shareholder.
Trading on the São Paulo Stock Exchange by a holder not deemed to be domiciled in Brazil for Brazilian tax and regulatory purposes (a “non-Brazilian holder”) is subject to certain limitations under Brazilian foreign investment legislation. With limited exceptions, non-Brazilian holders may only trade on the São Paulo Stock Exchange in accordance with the requirements of Resolution No. 2,689 of January 26, 2000 of the National Monetary Council. Resolution No. 2,689 requires that securities held by non-Brazilian holders be maintained in the custody of, or in deposit accounts with, financial institutions duly authorized by the Central Bank of Brazil and the CVM. In addition, Resolution No. 2,689 requires non-Brazilian holders to restrict their securities trading to transactions on Brazilian stock exchanges or qualified over-the-counter markets. With limited exceptions, non-Brazilian holders may not transfer the ownership of investments made under Resolution No. 2,689 to other non-Brazilian holders through a private transaction.
The Brazilian custodian for the common and preferred shares underlying the ADSs must, on behalf of the depositary for the ADSs, register with the Central Bank of Brazil to remit U.S. dollars abroad for payments of dividends, any other cash distributions or sales proceeds upon the disposition in Brazil of the shares. In the event that a holder of ADSs exchanges ADSs for common or preferred shares, the holder will be entitled to continue to rely on the custodian’s registration for five business days after the exchange. Thereafter, the holder 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 shares, unless the holder obtains a new registration. See Item 10. “Additional Information—Exchange Controls” and “—Additional Information—Brazilian Tax Considerations—Taxation of Gains” for a description of exchange controls and certain tax benefits extended to non-Brazilian holders who qualify under Resolution No. 2,689.
Regulation of the Brazilian Securities Markets
The Brazilian securities markets are principally governed by Law No. 6,385 of December 7, 1976, and the Brazilian Corporation Law, each as amended and supplemented, and by regulations issued by the CVM, which has regulatory authority over the stock exchanges and securities markets generally, the National Monetary Council, and the Central Bank of Brazil, which has licensing authority over brokerage firms and regulates foreign investment and foreign exchange transactions. These laws and regulations, among others, provide for disclosure requirements applicable to issuers of traded securities, restrictions on insider trading and price manipulation and protection of minority shareholders. They also provide for licensing and oversight of brokerage firms and governance of the Brazilian stock exchanges. However, the Brazilian securities markets are not as highly regulated and supervised as the U.S. securities markets.
Under the Brazilian Corporation Law, a company is either public (companhia aberta), such as we are, or privately held (companhia fechada). All public companies, including us, are registered with the CVM and are subject to reporting requirements. A company registered with the CVM may have its securities traded on the Brazilian stock exchanges or in the Brazilian over-the-counter market. Our common and preferred shares are listed and traded on the São Paulo Stock Exchange and may also be traded privately, subject to some limitations.
To be listed on the São Paulo Stock Exchange, a company must apply for registration with the CVM and the São Paulo Stock Exchange.
We have the option to ask that trading in our securities on the São Paulo Stock Exchange be suspended in anticipation of a material announcement. Trading may also be suspended on the initiative of the São Paulo Stock Exchange or the CVM, among other reasons, based on or due to a belief that a company has provided inadequate information regarding a material event or has provided inadequate responses to the inquiries by the CVM or the São Paulo Stock Exchange.
The Brazilian over-the-counter market consists of direct trades between individuals in which a financial institution registered with the CVM serves as intermediary. No special application, other than registration with the CVM, is necessary for securities of a public company to be traded in this market. The CVM requires that it be given notice of all trades carried out in the Brazilian over-the-counter market by the intermediaries.
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PIFCo’s common stock is not registered and there is no trading market for it. PIFCo’s Senior Notes are listed in the Luxembourg Stock Exchange. PIFCo’s other debt securities have not been listed on any securities exchange.
Memorandum and Articles of Incorporation of Petrobras
We are a publicly traded company duly registered with the CVM under No. 951-2. Article 3 of our bylaws establishes our corporate purposes as research, prospecting, extraction, processing, trade and transportation of crude oil from wells, shale and other rocks, of its derivatives, natural gas and other fluid hydrocarbons, as well as other related or similar activities, such as activities connected with energy, including research, development, production, transportation, distribution, sale and trade of all forms of energy, as well as other related or similar activities. We may conduct outside Brazil, directly or through our subsidiaries, any of the activities within our corporate purpose.
Qualification of Directors
Brazilian law provides that only shareholders of a company may be appointed to its board of directors, but there is no minimum share ownership or residency requirement for qualification as a director. Members of our board of executive officers must be Brazilian nationals and reside in Brazil. Our directors and executive officers are prevented from voting on any transaction involving companies in which they hold more than 10% of the total capital stock or of which they have held a management position in the period immediately prior to their taking office. Under our bylaws, shareholders set the aggregate compensation payable to directors and executive officers. The Board of Directors allocates the compensation among its members and the executive officers.
Allocation of Net Income
At each annual general shareholders’ meeting, our board of directors is required to recommend how net profits for the preceding fiscal year are to be allocated. The Brazilian Corporation Law defines net profits as net income after income taxes and social contribution taxes for such fiscal year, net of any accumulated losses from prior fiscal years and any amounts allocated to employees’ and management’s participation in our profits. In accordance with the Brazilian Corporation Law, the amounts available for dividend distribution or payment of interest on shareholders’ equity equals net profits less any amounts allocated from such net profits to the legal reserve.
We are required to maintain a legal reserve, to which we must allocate 5% of net profits for each fiscal year until the amount for such reserve equals 20% of our paid-in capital. However, we are not required to make any allocations to our legal reserve in a fiscal year in which the legal reserve, when added to our other established capital reserves, exceeds 30% of our capital. The legal reserve can only be used to offset losses or to increase our capital.
As long as we are able to make the minimum mandatory distribution described below, we must allocate an amount equivalent to 0.5% of subscribed and fully paid-in capital at year-end to a statutory reserve. The reserve is used to fund the costs of research and technological development programs. The accumulated balance of this reserve cannot exceed 5% of the subscribed and fully paid-in capital stock.
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Brazilian law also provides for three discretionary allocations of net profits that are subject to approval by the shareholders at the annual general shareholders’ meeting, as follows:
Mandatory Distribution
Under Brazilian Corporation Law, the bylaws of a Brazilian corporation may specify a minimum percentage of the amounts available for distribution by such corporation for each fiscal year that must be distributed to shareholders as dividends or interest on shareholders’ equity, also known as the mandatory distributable amount, which cannot be lower than 25% of the adjusted net profit for the fiscal year. Under our bylaws, the mandatory distributable amount has been fixed at an amount equal to not less than 25% of our net profits, after the allocations to the legal reserve, contingency reserve and unrealized revenue reserve. Furthermore, the net profits that are not allocated to the reserves above to fund working capital needs and investment projects as described above or to the statutory reserve must be distributed to our shareholders as dividends or interest on shareholders’ equity.
The Brazilian Corporation Law, however, permits a publicly held company, such as ours, to suspend the mandatory distribution if the board of directors and the fiscal council report to the annual general shareholders’ meeting that the distribution would be inadvisable in view of the company’s financial condition. The suspension is subject to approval of holders of common shares. In this case, the board of directors must file a justification for such suspension with the CVM. Profits not distributed by virtue of the suspension mentioned above shall be allocated to a special reserve and, if not absorbed by subsequent losses, shall be distributed as soon as the financial condition of the company permits such payments.
Payment of Dividends and Interest on Shareholders’ Equity
We are required by the Brazilian Corporation Law and by our bylaws to hold an annual general shareholders’ meeting by the fourth month after the end of each fiscal year at which, among other things, the shareholders have to decide on the payment of an annual dividend. The payment of annual dividends is based on the financial statements prepared for the relevant fiscal year.
Law No. 9,249 of December 26, 1995, as amended, provides for distribution of interest attributed to shareholders’ equity to shareholders as an alternative form of distribution. Such interest is limited to the daily pro ratavariation of the TJLP interest rate, the Brazilian government’s long-term interest rate.
We may treat these payments as a deductible expense for corporate income tax and social contribution purposes, but the deduction cannot exceed the greater of:
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Any payment of interest on shareholders’ equity to holders of ADSs or common shares, whether or not they are Brazilian residents, is subject to Brazilian withholding tax at the rate of 15% or 25%. The 25% rate applies if the beneficiary is resident in a tax haven. See “—Brazilian Tax Considerations.” The amount paid to shareholders as interest attributed to shareholders’ equity, net of any withholding tax, may be included as part of any mandatory distribution of dividends. Under the Brazilian Corporation Law, we are required to distribute to shareholders an amount sufficient to ensure that the net amount received, after payment by us of applicable Brazilian withholding taxes in respect of the distribution of interest on shareholders’ equity, is at least equal to the mandatory dividend.
Under the Brazilian Corporation Law and our bylaws, dividends generally are required to be paid within 60 days following the date the dividend was declared, unless a shareholders’ resolution sets forth another date of payment, which, in either case, must occur prior to the end of the fiscal year in which the dividend was declared. The amounts of dividends due to our shareholders are subject to financial charges at the SELIC rate (an interest rate applicable to certain Brazilian government securities) from the end of each fiscal year through the date we actually pay such dividends. Shareholders have a three-year period from the dividend payment date to claim dividends or interest payments with respect to their shares, after which the amount of the unclaimed dividends reverts to us.
Holders of preferred shares are entitled to priority in the distribution equal to the greater of a 5% of their pro rata share of our paid-in capital, or 3% of their shares book value with a participation equal to the common shares in corporate capital increases obtained from the incorporation of reserves and profits.
Our board of directors may distribute dividends or pay interest based on the profits reported in interim financial statements. The amount of interim dividends distributed cannot exceed the amount of our capital reserves.
Shareholders’ Meetings
Our shareholders have the power to decide on any matters related to our corporate purposes and to pass any resolutions they deem necessary for our protection and development, through voting at a general shareholders’ meeting.
We convene our shareholders’ meetings by publishing a notice in the Diário Oficial da União (Official Gazette), Jornal do Commercio, Gazeta Mercantil and Valor Econômico. The notice must be published no fewer than three times, beginning at least 15 calendar days prior to the scheduled meeting date. The notice must contain the meeting’s agenda and, in the case of a proposed amendment to the bylaws, an indication of the subject matter. For ADS holders, we are required to provide notice to the ADS depositary at least 30 calendar days prior to a shareholders’ meeting.
The board of directors or, in some specific situations set forth in the Brazilian Corporation Law, the shareholders, call our general shareholders’ meetings. A shareholder may be represented at a general shareholders’ meeting by an attorney-in-fact, so long as the attorney-in-fact was appointed within a year of the meeting. The attorney-in-fact must be a shareholder, a member of our management, a lawyer or a financial institution. The attorney-in-fact’s power of attorney must comply with certain formalities set forth by Brazilian law.
In order for a valid action to be taken at a shareholders’ meeting, shareholders representing at least one quarter of our issued and outstanding common shares must be present at the meeting. However, in the case of a general meeting to amend our bylaws, shareholders representing at least two-thirds of our issued and outstanding common shares must be present. If no such quorum is present, the board may call a second meeting giving at least eight calendar days notice prior to the scheduled meeting in accordance with the rules of publication described above. The quorum requirements will not apply to the second meeting, subject to the voting requirements for certain matters described below.
Voting Rights
Pursuant to the Brazilian Corporation Law and our bylaws, each of our common shares carries the right to vote at a general meeting of shareholders. The Brazilian government is required by law to own at least a majority of our
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voting stock. Preferred shares generally do not confer voting rights, except as described below. We may not restrain or deny the voting rights without the consent of the majority of the shares affected.
Holders of common shares, voting at a general shareholders’ meeting, have the exclusive power to:
Except as otherwise provided by law, resolutions of a general shareholders’ meeting are passed by a simple majority vote by holders of our common shares. Abstentions are not taken into account.
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The approval of holders of at least one-half of the issued and outstanding common shares is required for the following actions involving our company:
According to the Brazilian Corporation Law, the approval of the holders of a majority of the outstanding adversely affected preferred shares at a special meeting, as well as shareholders representing at least one-half of the issued and outstanding common shares is required for the following actions:
Decisions on our transformation into another type of company requires the unanimous approval of our shareholders, including the preferred shareholders.
Our preferred shares will acquire voting rights if we fail to pay the minimum dividend to which such shares are entitled for three consecutive fiscal years. The voting right shall continue until payment has been made. Preferred shareholders also obtain the right to vote if we enter into a liquidation process.
Under Brazilian Corporation Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates. Furthermore, minority common shareholders holding at least 10% of our voting capital also have the right to appoint or dismiss one member to or from our fiscal council.
Preferred shareholders holding, individually or as a group, 10% of our total capital have the right to appoint and/or dismiss one member to or from our board of directors. Preferred shareholders have the right to separately appoint and/or dismiss one member to or from our fiscal council.
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Our bylaws provide that, independently from the exercise of the rights above granted to minority shareholders, through cumulative voting process, the Brazilian government always has the right to appoint the majority of our directors.
Preemptive Rights
Pursuant to the Brazilian Corporation Law, each of our shareholders has a general preemptive right to subscribe for shares or securities convertible into shares in any capital increase, in proportion to the number of shares held by them. In the event of a capital increase that would maintain or increase the proportion of capital represented by the preferred shares, holders of preferred shares would have preemptive rights to subscribe to newly issued preferred shares only. In the event of a capital increase that would reduce the proportion of capital represented by the preferred shares, holders of preferred shares would have preemptive rights to subscribe to any new preferred shares in proportion to the number of shares held by them, and to common shares only to the extent necessary to prevent dilution of their interests in our total capital.
A period of at least 30 days following the publication of notice of the issuance of new shares or securities convertible into shares is allowed for exercise of the right, and the right is negotiable. According to our bylaws, our board of directors may eliminate preemptive rights or reduce the exercise period in connection with a public exchange made to acquire control of another company or in connection with a public offering of shares or securities convertible into shares.
In the event of a capital increase by means of the issuance of new shares, holders of ADSs, of common or preferred shares, would have, except under circumstances described above, preemptive rights to subscribe for any class of our newly issued shares. However, you may not be able to exercise the preemptive rights relating to the preferred shares underlying your ADSs unless a registration statement under the Securities Act is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. See Item 3. “Key Information—Risk Factors—Risks Relating to our Equity and Debt Securities.”
Redemption and Rights of Withdrawal
Brazilian law provides that, under limited circumstances, a shareholder has the right to withdraw his or her equity interest from the company and to receive payment for the portion of shareholder’s equity attributable to his or her equity interest.
This right of withdrawal may be exercised by the holders of the adversely affected common or preferred shares in the event that we decide:
Holders of our common shares may exercise their right of withdrawal in the event we decide:
The right of withdrawal may also be exercised by our dissenting shareholders in the event we decide:
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This right of withdrawal may also be exercised in the event that the entity resulting from a merger, incorporação de ações, as described above, or consolidation or spin-off of a listed company fails to become a listed company within 120 days of the shareholders’ meeting at which such decision was taken.
Any redemption of shares arising out of the exercise of such withdrawal rights would be made based on the book value per share, determined on the basis of the last balance sheet approved by our shareholders. However, if a shareholders’ meeting giving rise to redemption rights occurred more than 60 days after the date of the last approved balance sheet, a shareholder would be entitled to demand that his or her shares be valued on the basis of a new balance sheet dated within 60 days of such shareholders’ meeting. The right of withdrawal lapses 30 days after publication of the minutes of the shareholders’ meeting that approved the corporate actions described above. We would be entitled to reconsider any action giving rise to withdrawal rights within 10 days following the expiration of such rights if the withdrawal of shares of dissenting shareholders would jeopardize our financial stability.
Other Shareholders’ Rights
According to the Brazilian Corporation Law, neither a company’s bylaws nor actions taken at a general meeting of shareholders may deprive a shareholder of some specific rights, such as:
Liquidation
In the event of a liquidation, holders of preferred shares are entitled to receive, prior to any distribution to holders of common shares, an amount equal to the paid-in capital with respect to the preferred shares.
Conversion Rights
According to our bylaws, our common shares are not convertible into preferred shares, nor are preferred shares convertible into common shares.
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Liability of Our Shareholders for Further Capital Calls
Neither Brazilian law nor our bylaws provide for capital calls. Our shareholders’ liability for capital calls is limited to the payment of the issue price of the shares subscribed or acquired.
Form and Transfer
Our shares are registered in book-entry form and we have hired Banco do Brasil to perform all the services of safe-keeping and transfer of shares. To make the transfer, do Brasil makes an entry in the register, debits the share account of the transferor and credits the share account of the transferee.
Our shareholders may choose, at their individual discretion, to hold their shares through CBLC. Shares are added to the CBLC system through Brazilian institutions, which have clearing accounts with the CBLC. Our shareholder registry indicates which shares are listed on the CBLC system. Each participating shareholder is in turn registered in a registry of beneficial shareholders maintained by the CBLC and is treated in the same manner as our registered shareholders.
Dispute Resolution
Our bylaws provide for mandatory dispute resolution through arbitration, in accordance with the rules of the Câmara de Arbitragem do Mercado (Market Arbitration Chamber), with respect to any dispute regarding us, our shareholders, the officers, directors and fiscal council members and involving the provisions of the Brazilian Corporation Law, our bylaws, the rules of the National Monetary Council, the Central Bank of Brazil and the CVM or any other capital markets legislation, including the provisions of any agreement entered into by us with any stock exchange or over-the-counter entity registered with the CVM, relating to adoption of differentiated corporate governance practices.
However, decisions of the Brazilian government, as exercised through voting in any general shareholders’ meeting, are not subject to this arbitration proceeding, in accordance with Article 238 of the Brazilian Corporation Law.
Self-dealing Restrictions
Our controlling shareholder, the Brazilian government, and the members of our board of directors, board of executive officers and fiscal council are required, in accordance with our bylaws, to:
Restrictions on Non-Brazilian Holders
Non-Brazilian holders face no legal restrictions on the ownership of our common or preferred shares or of ADSs based on our common or preferred shares, and are entitled to all the rights and preferences of such common or preferred shares, as the case may be.
However, the ability to convert dividend payments and proceeds from the sale of common or preferred shares or preemptive rights into foreign currency and to remit such amounts outside Brazil is subject to restrictions under foreign investment legislation which generally requires, among other things, the registration of the relevant investment with the Central Bank of Brazil. Nonetheless, any non-Brazilian holder who registers with the CVM in
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accordance with Resolution No. 2,689 may buy and sell securities on the São Paulo Stock Exchange without obtaining a separate certificate of registration for each transaction.
In addition, Annex V to Resolution No. 1,289 of the National Monetary Council, as amended, known as Annex V Regulations, allows Brazilian companies to issue depositary receipts in foreign exchange markets. We currently have an ADR program for our common and preferred shares duly registered with the CVM and the Central Bank of Brazil. The proceeds from the sale of ADSs by holders outside Brazil are free of Brazilian foreign investment controls.
Transfer of Control
According to Brazilian law and our bylaws, the Brazilian government is required to own at least the majority of our voting shares. Therefore, any change in our control would require a change in the applicable legislation.
Disclosure of Shareholder Ownership
Brazilian regulations require that any person or group of persons representing the same interest that has directly or indirectly acquired or sold an interest corresponding to 5% of the total number of shares of any type or class must disclose its share ownership or divestment to the CVM and the São Paulo Stock Exchange. In addition, a statement containing the required information must be published in the newspapers. Any subsequent increase or decrease by 5% or more in ownership of shares of any type or class must be similarly disclosed.
Memorandum and Articles of Association of PIFCo
Register
PIFCo is an exempted company incorporated with limited liability in the Cayman Islands under the Companies Law (2004 Revision) with company registration number 76600. PIFCo registered and filed its Memorandum and Articles of Association with the Registrar of Companies on September 24, 1997. PIFCo was initially incorporated with the name Brasoil Finance Company, which name was changed by special resolution of PIFCo’s shareholders to Petrobras International Finance Company on September 25, 1997. There has been no subsequent amendment to PIFCo’s Memorandum and Articles of Association.
Objects and Purposes
PIFCo’s Memorandum and Articles of Association grants PIFCo full power and authority to carry out the business of petroleum marketing, sales, financing and transportation and any business incidental thereto. As a matter of Cayman Islands law, PIFCo cannot trade in the Cayman Islands except in furtherance of the business carried on outside the Cayman Islands.
Directors
Directors may vote on a proposal, arrangement or contract in which they are interested. However, interested directors must declare the nature of their interest at a directors’ meeting. If the interested directors declare their interest, their votes are counted and they are counted in the quorum of such meeting.
The directors may, in PIFCo’s name, exercise their powers to borrow money, issue debt securities and to mortgage or charge any of the undertaking or property of PIFCo and are generally responsible for its day-to-day management and administration.
Directors are not required to own shares.
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Rights and Obligations of Shareholders
Shareholders may declare dividends in a general meeting but the dividends cannot exceed the amount recommended by the directors. The directors may pay the shareholders interim dividends and may, before recommending any dividend, set aside reserves out of profits. The directors can invest these reserves in their discretion or employ them in PIFCo’s business.
Dividends may be paid in cash or in kind but may only be paid out of profits or, subject to certain restrictions of Cayman Islands law, a share premium account.
Votes may be cast at a general meeting by a show of hands or by a poll. On a vote by a show of hands, each shareholder or shareholder represented by proxy has one vote. On a vote by a poll, each shareholder or shareholder represented by proxy has one vote for each share owned.
Directors are elected by ordinary resolution by the shareholders at general meetings or by a board resolution of the directors. Shareholders are not entitled to vote at a general meeting unless calls or other amounts payable on their shares have been paid. In lieu of voting on a matter at a general meeting, the shareholders entitled to vote on that matter may adopt the matter by signing a written resolution.
Redemption
PIFCo may issue shares, which are redeemable by PIFCo or by its shareholders. The amount payable on each share in a redemption is its fair value as determined by the directors on the basis of a willing seller and a willing buyer.
Where PIFCo has agreed to purchase any share from a shareholder, PIFCo will give notice to the other shareholders, if any, specifying the number and class of shares to be purchased, the name and address of the seller, the price to be paid for the shares and the portion (if any) of that price which is being paid out of capital. The notice will also indicate a date on which the purchase is to be effected and will invite shareholders other than the seller, if any, to object to the purchase before that date. If any objection is received the redemption request will be refused by the directors or put to a general meeting of the shareholders.
Shareholder Rights Upon Liquidation
If PIFCo is liquidated, the liquidator may (in accordance with an ordinary shareholder resolution):
Shareholders will not be compelled to accept any securities on which there is a liability.
Calls on Shares
Directors may make calls on the shareholders with respect to any amounts unpaid on their shares. Each shareholder shall pay to the company the amounts called on such shares.
Change to Rights of Shareholders
Shareholders may change the rights of their class of shares by:
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There are no general limitations on the rights to own shares specified by the articles.
General Meetings
A general meeting may be convened:
Notice of a general meeting is given to all shareholders.
All business carried out at a general meeting is considered special business except:
Shareholder consent is required to carry out special business at a meeting unless notice of the special business is given in the notice of the meeting. A quorum of shareholders is required to be present at any meeting in order to carry out business. Any two shareholders or one shareholder holding a majority of the shares that are present in person or represented by proxy is a quorum.
There is no requirement under Cayman Islands law to convene an annual meeting or to convene any general meeting of the shareholders. The directors are permitted to designate any general meeting of shareholders as an annual general meeting.
Liability of Shareholders
In normal circumstances, the liability of any shareholder to PIFCo is limited to the amount, which such shareholder has agreed to pay in respect of the subscription of his shares.
Changes in Capital
PIFCo may increase its share capital by ordinary resolution. The new shares will be subject to all of the provisions to which the original shares are subject.
PIFCo may also by ordinary resolution:
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PIFCo may reduce its share capital and any capital redemption reserve by special resolution in accordance with relevant provision of Cayman Islands law.
Indemnity
PIFCo’s directors and officers are indemnified out of its assets and funds against all actions, losses, expenses and liabilities which they incur in the discharge of their respective duties, powers, authorities or discretions. Under PIFCo’s Memorandum of Association, directors and officers are excused from all liability to PIFCo, except for any losses, which arise as a result of such party’s, own dishonesty.
Accounts
Accounts relating to PIFCo’s affairs are kept in such manner as may be determined from time to time by the directors and may be audited in such manner as may be determined from time to time by PIFCo in a general meeting or failing any such determination by the directors. There is, however, no requirement as a matter of Cayman Islands law to have PIFCo’s accounts audited.
Transfer out of Jurisdiction
PIFCo may, by special resolution of the shareholders, transfer out of the Cayman Islands into any jurisdiction permitting such transfer.
Material Contracts
Concession Agreements with the ANP
As provided in the Oil Law, we were granted the exclusive right, for a period of 27 years from the declaration of commercial feasibility, to exploit the crude oil reserves in all fields where we had previously commenced production. Additionally, the Oil Law established a procedural framework for us to claim exclusive exploratory and, in case of drilling success, development 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.” To perfect our claim to explore and develop these areas, we had to demonstrate that we had the requisite financial capacity to carry out these activities, either alone or through cooperative arrangements.
On August 6, 1998, we signed concession contracts with the ANP relating to 397 areas, consisting of 231 production areas, 115 exploration areas and 51 development areas. In May 1999, we relinquished 26 exploratory areas out of the 115 initially granted to us by the ANP, and obtained an extension of our exclusive exploration period from three to five years with respect to 34 exploration areas aggregating 44.0 million acres (178,033 square kilometers) and from three to six years with respect to two exploration areas aggregating 7.3 million acres (29,415 square kilometers).
The areas of the concessions not awarded to us by the ANP have been, and will continue to be, awarded through public auctions conducted by the ANP. In the six auctions conducted thus far, we acquired concession rights that are formalized by 89 concession contracts. See Item 4. “Information on the Company—Exploration, Development and Production—Exploration Activities—Exploration Bidding Rounds.”
Under our concession agreements with the ANP we are required to pay the following:
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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 has to be paid upon the execution of the concession agreement. The rentals for the occupation and retention of the concession areas are also provided for in the related bidding rules and are payable annually. For a discussion of royalties, special participation tax and rentals, see Item 5. “Operating and Financial Review and Prospects—Effect of Taxes on Our Income.”
With respect to onshore fields, the Oil Law also requires us to pay 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.
For information concerning our other material contracts, see Item 4. “Information on the Company” and Item 5. “Operating and Financial Review and Prospects.”
For a description of PIFCo’s material agreements, see “—PIFCo Senior Notes,” “—PIFCo Global Notes” and “—Sale of Future Receivables.”
Statements contained in this annual report regarding the contents of any contract or other document are not necessarily complete, and, where the contract or other document is an exhibit to the annual report, each of these statements is qualified in all aspects by the provisions of the actual contract or other documents.
Exchange Controls
There are no restrictions on ownership of the common or preferred shares by individuals or legal entities domiciled outside Brazil.
The right to convert dividend payments and proceeds from the sale of shares into foreign currency and to remit such amounts outside Brazil may be subject to restrictions under foreign investment legislation which generally requires, among other things, that the relevant investments be registered with the Central Bank of Brazil. If any restrictions are imposed on the remittance of foreign capital abroad, they could hinder or prevent CBLC, as custodian for the common and preferred shares represented by the American Depositary Shares, or registered holders who have exchanged American Depositary Shares for common shares or preferred shares, from converting dividends, distributions or the proceeds from any sale of such common shares or preferred shares, as the case may be, into U.S. dollars and remitting the U.S. dollars abroad.
Foreign investors may register their investment under Law No. 4,131 of September 3, 1962 or Resolution No. 2,689. Registration under Resolution No. 2,689 affords favorable tax treatment to foreign investors who are not resident in a tax haven, as defined by Brazilian tax laws. See “—Brazilian Tax Considerations.”
Under Resolution No. 2,689, foreign investors may invest in almost all financial assets and engage in almost all transactions available in the Brazilian financial and capital markets, provided that certain requirements are fulfilled. In accordance with Resolution No. 2,689, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.
Under Resolution No. 2,689, a foreign investor must:
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Securities and other financial assets held by a Resolution No. 2,689 investor must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the Central Bank of Brazil or the CVM. In addition, any transfer of securities held under Resolution No. 2,689 must be carried out in the stock exchanges or through organized over-the-counter markets licensed by the CVM, except for transfers resulting from a corporate reorganization or occurring upon the death of an investor by operation of law or will.
Holders of American Depositary Shares who have not registered their investment with the Central Bank of Brazil could be adversely affected by delays in, or refusals to grant, any required government approval for conversions of payments made in Reais and remittances abroad of these converted amounts.
Annex V Regulations provide for the issuance of depositary receipts in foreign markets with respect to shares of Brazilian issuers. The depositary of the ADSs has obtained from the Central Bank of Brazil an electronic certificate of registration with respect to our existing ADR program. Pursuant to the registration, the custodian and the depositary will be able to convert dividends and other distributions with respect to the relevant shares represented by ADSs into foreign currency and to remit the proceeds outside Brazil. Following the closing of an international offering, the electronic certificate of registration will be amended by the depositary with respect to the ADSs sold in the international offering and will be maintained by the Brazilian custodian for the relevant shares on behalf of the depositary.
In the event that a holder of ADSs exchanges such ADSs for the underlying shares, the holder will be entitled to continue to rely on such electronic registration for five business days after the exchange. Thereafter, unless the relevant shares are held pursuant to Resolution No. 2,689 by a duly registered investor, or a holder of the relevant shares applies for and obtains a new certificate of registration from the Central Bank of Brazil, the holder may not be able to convert into foreign currency and to remit outside Brazil the proceeds from the disposition of, or distributions with respect to, the relevant shares, and the holder, if not registered under Resolution No. 2,689, will be subject to less favorable Brazilian tax treatment than a holder of ADSs. In addition, if the foreign investor resides in a “tax haven” jurisdiction, the investor will be also subject to less favorable tax treatment. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Equity and Debt Securities” and “—Brazilian Tax Considerations.”
There are:
Taxation relating to our ADSs and common and preferred shares
The following summary contains a description of material Brazilian and U.S. federal income tax considerations that may be relevant to the purchase, ownership and disposition of preferred or common shares or ADSs by a holder. This summary does not describe any tax consequences arising under the laws of any state, locality or taxing jurisdiction other than Brazil and the United States.
This summary is based upon the tax laws of Brazil and the United States as in effect on the date of this annual report, which are subject to change (possibly with retroactive effect). This summary is also based upon the representations of the depositary and on the assumption that the obligations in the deposit agreement and any related documents will be performed in accordance with their respective terms.
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This description is not a comprehensive description of all of the tax considerations that may be relevant to any particular investor, including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors. Prospective purchasers of common or preferred shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common or preferred shares or ADSs.
There is no reciprocal income tax treaty between the United States and Brazil. In recent years, the tax authorities of Brazil and the United States have held discussions that may culminate in such a treaty. We cannot predict, however, whether or when a treaty will enter into force or how it will affect the U.S. holders of common or preferred shares or ADSs.
Brazilian Tax Considerations
The following discussion summarizes the material Brazilian tax consequences of the acquisition, ownership and disposition of preferred or common shares or ADSs, as the case may be, by a holder that is not domiciled in Brazil, also called a non-Brazilian holder, for purposes of Brazilian taxation and, in the case of a holder of preferred or common shares, which has registered its investment in preferred or common shares at the Central Bank of Brazil as a U.S. dollar investment.
Under Brazilian law, investors may invest in the preferred or common shares under Resolution No. 2,689 or under Law No. 4,131 of September 3, 1962. Investments under Resolution No. 2,689 afford favorable tax treatment to foreign investors who are not resident in a tax haven jurisdiction. The rules of Resolution No. 2,689 allow foreign investors to invest in almost all instruments and to engage in almost all transactions available in the Brazilian financial and capital markets, provided that certain requirements are met. In accordance with Resolution No. 2,689, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.
Pursuant to this rule, foreign investors must: (1) appoint at least one representative in Brazil with powers to perform actions relating to the foreign investment; (2) complete the appropriate foreign investor registration form; (3) register as a foreign investor with the CVM; and (4) register the foreign investment with the Central Bank of Brazil.
Securities and other financial assets held by foreign investors pursuant to Resolution No. 2,689 must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the Central Bank of Brazil or the CVM. In addition, securities trading is restricted to transactions carried out in the stock exchanges or organized over-the-counter markets licensed by the CVM.
Taxation of Dividends
Dividends paid by us, including stock dividends and other dividends paid in property to the depositary in respect of the ADSs, or to a non-Brazilian holder in respect of the preferred or common shares, are currently not subject to withholding tax in Brazil.
We must pay to our shareholders (including holders of common or preferred shares or ADSs) interest on the amount of dividends payable to them, at the SELIC rate (the interest rate applicable to certain Brazilian government securities), from the end of each fiscal year through the date of effective payment of those dividends. These interest payments are considered as fixed-yield income and are subject to withholding income tax at varying rates depending on the length of period of interest accrual. The tax rate ranges from 15%, in case of interest accrued for a period greater than 720 days, to 22.5%, in case of interest accrued for a period up to 180 days. However, holders of ADSs and holders of common or preferred shares not resident or domiciled in tax haven jurisdictions (see “—Beneficiaries Residing or Domiciled in Tax Havens or Low Tax Jurisdictions”) investing under Resolution No. 2,689 are subject to such withholding tax at a reduced rate, currently at 15%.
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Taxation on Interest on Shareholders’ Equity
Any payment of interest on shareholders’ equity (see “—Memorandum and Articles of Incorporation of Petrobras—Payment of Dividends and Interest on Shareholders’ Equity”) to holders of ADSs or preferred or common shares, whether or not they are Brazilian residents, is subject to Brazilian withholding income tax at the rate of 15% at the time we record such liability, whether or not the effective payment is made at that time. In the case of non-Brazilian residents that are resident in a tax haven jurisdiction, the applicable withholding income tax rate is 25% (see “—Beneficiaries Residing or Domiciled in Tax Havens or Low Tax Jurisdictions”). The payment of interest at the SELIC rate that is applicable to payments of dividends applies equally to payments of interest on shareholders’ equity. The determination of whether or not we will make distributions in the form of interest on shareholders’ equity or in the form of dividends is made by our board of directors at the time distributions are to be made. We cannot determine how our board of directors will make these determinations in connection with future distributions.
Taxation of Gains
For purposes of Brazilian taxation, there are two types of non-Brazilian holders of ADSs or preferred or common shares: (1) non-Brazilian holders that are not resident or domiciled in a tax haven jurisdiction (see “—Beneficiaries Residing or Domiciled in Tax Havens or Low Tax Jurisdictions”), and that, in the case of holders of preferred or common shares, are registered before the Central Bank of Brazil and the CVM to invest in Brazil in accordance with Resolution No. 2,689; and (2) other non-Brazilian holders, which include any and all non-residents of Brazil who invest in equity securities of Brazilian companies through any other means (including under Law No. 4,131 of 1962) and all types of investors that are located in tax haven jurisdictions. The investors identified in clause (1) above are subject to favorable tax treatment in Brazil, as described below.
According to Law nº 10,833, dated December 29, 2003, capital gains realized on the disposition of assets located in Brazil, by non-Brazilian residents, whether or not to other non-residents and whether made outside or within Brazil, are subject to taxation in Brazil at a rate of 15% (a rate of 25% is applicable if realized by investors resident in a tax haven jurisdiction, i.e. a country that does not impose any income tax or that imposes tax at a maximum rate of less than 20%). We understand the ADSs do not fall within the definition of assets located in Brazil for the purposes of this law, but there is still no pronunciation from tax authorities nor judicial court rulings in this respect. Therefore, we are unable to predict whether such understanding will prevail in the courts of Brazil.
The deposit of preferred or common shares in exchange for ADSs may be subject to Brazilian capital gains at the rate of 15% if the amount previously registered with the Central Bank of Brazil as a foreign investment in the preferred or common shares is lower than:
(1) the average price per preferred or common share on a Brazilian stock exchange on which the greatest number of such shares were sold on the day of deposit; or
(2) if no preferred or common shares were sold on that day, the average price on the Brazilian stock exchange on which the greatest number of preferred or common shares were sold in the 15 trading sessions immediately preceding such deposit. In such a case, the difference between the amount previously registered and the average price of the preferred or common shares calculated as above, will be considered a capital gain. Investors registered under Resolution No. 2,689 and not located in a tax haven jurisdiction are exempt from this type of taxation. The withdrawal of ADSs in exchange for preferred or common shares is not subject to Brazilian tax. On receipt of the underlying preferred or common shares, the non-Brazilian holder registered under Resolution No. 2,689 will be entitled to register the U.S. dollar value of such shares with the Central Bank of Brazil as described below in “Registered Capital.”
Non-Brazilian holders are not subject to tax in Brazil on gains realized on sales of preferred or common shares that occur abroad to non-Brazilian holders.
Non-Brazilian holders which are not located in a tax haven jurisdiction are subject to income tax imposed at a rate of 15% on gains realized on sales or exchanges of the preferred or common shares that occur in Brazil or with a resident of Brazil, other than in connection with transactions on the Brazilian stock, future or commodities exchanges. With respect to proceeds of a redemption or of a liquidating distribution with respect to the preferred or common shares, the difference between the amount effectively received by the shareholder and the amount of foreign currency registered with the Central Bank of Brazil, accounted for in Reais at the commercial market rate on the date of the redemption or liquidating distribution, will be also subject to income tax at a rate of 15% given that
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such transactions are treated as a sale or exchange not carried out on the Brazilian stock, future and commodities exchanges.
Gains realized arising from transactions on the Brazilian stock, future or commodities exchanges by an investor registered under Resolution No. 2,689 who is not located in a tax haven jurisdiction are exempt from Brazilian income tax. Otherwise, gains realized on transactions related to the Brazilian stock, future or commodities exchanges are subject to income tax at a rate of 20%.
Therefore, non-Brazilian holders are subject to income tax imposed at a rate of 20% on gains realized on sales or exchanges of preferred or common shares that occur on the stock exchange unless such a sale is made by a non-Brazilian holder who is not resident in a tax haven jurisdiction and:
(1) such sale is made within five business days of the withdrawal of such preferred or common shares in exchange for ADSs and the proceeds thereof are remitted abroad within such five-day period; or
(2) such sale is made under Resolution No. 2,689 by registered non-Brazilian holders who obtain registration with the CVM.
In these two cases, the transaction will not be subject to taxation in Brazil. The “gain realized” is for tax purposes the difference between the amount in Reais realized on the sale or exchange and the acquisition cost measured in Reais, without any adjustment to account for inflation of the shares sold. The “gain realized” as a result of a transaction that occurs other than on the stock exchange will be the positive difference between the amount realized on the sale or exchange and the acquisition cost of the preferred or common shares, both such values to be taken into account in Reais. There are reasonable grounds, however, to hold that the “gain realized” should be calculated based on the foreign currency amount registered with the Central Bank of Brazil, such foreign currency amount to be translated into Reais at the commercial market rate on the date of such sale or exchange.
Any exercise of preemptive rights relating to the preferred or common shares will not be subject to Brazilian taxation. Any gain on the sale or assignment of preemptive rights relating to the preferred or common shares by the depositary on behalf of holders of the ADSs will be subject to Brazilian income taxation according to the same rules applicable to the sale or disposition of preferred or common shares, unless such sale or assignment is performed on the stock exchange by an investor under Resolution No. 2,689 who is not resident in a tax haven jurisdiction, in which case the gains are exempt from income tax.
There is no assurance that the current preferential treatment for holders of the ADSs and some non-Brazilian holders of the preferred or common shares under Resolution No. 2,689 will continue in the future.
Taxation of Foreign Exchange Transactions (“IOF/Câmbio”)
Under Decree No. 4,494 of December 3, 2002, the conversion into Brazilian currency of proceeds received by a Brazilian entity from a foreign investment in the Brazilian securities market (including those in connection with an investment in preferred or common shares or the ADSs and those under Resolution No. 2, 689) and the conversion into foreign currency of proceeds received by a non-Brazilian holder is subject to a tax on exchange transactions known as IOF/Câmbio, which is currently applicable at a zero percent rate in most transactions. However, according to Law No. 8,894 of June 21, 1994, the IOF/Câmbio rate may be increased at any time to a maximum of 25% by a decision of the Minister of Finance, but only in relation to exchange transactions carried out after the increase of the applicable rate.
Taxation on Bonds and Securities Transactions (“IOF/Títulos”)
Law No. 8,894 created the Tax on Bonds and Securities Transactions, or IOF/Títulos, which may be imposed on any transactions involving bonds and securities carried out in Brazil, even if these transactions are performed on the Brazilian stock, futures or commodities exchange. As a general rule, the rate of this tax is currently zero but the Brazilian government may increase such rate up to 1.5% per day, but only in relation to transactions carried out after the increase of the applicable rate.
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Other Brazilian Taxes
There are no Brazilian inheritance, gift or succession taxes applicable to the ownership, transfer or disposition of preferred or common shares or ADSs by a non-Brazilian holder, except for gift and inheritance taxes which are levied by some states of Brazil on gifts made or inheritances bestowed by individuals or entities not resident or domiciled in Brazil to individuals or entities resident or domiciled within such states in Brazil. There are no Brazilian stamp, issue, registration, or similar taxes or duties payable by holders of preferred or common shares or ADSs.
Tax on Bank Account Transactions (“CPMF”)
The Contribuição Provisória sobre Movimentação Financeira (Tax on Bank Account Transactions, or CPMF), is imposed on any debit to bank accounts. As a result, transactions by the depositary or by holders of preferred or common shares, which involve the transfer of Brazilian currency through Brazilian financial institutions, are subject to the CPMF tax at a rate of 0.38%. These transactions include situations where a non-Brazilian holder transfers the proceeds from the sale or assignment of preferred or common shares by an exchange transaction, in which case the CPMF tax will be levied on the amount to be remitted abroad in Reais. If we have to perform any exchange transaction in connection with ADSs or preferred or common shares, we will also be subject to the CPMF tax. The financial institution that carries out the relevant financial transaction will be responsible for collecting the applicable CPMF tax.
Beneficiaries Resident or Domiciled in Tax Havens or Low Tax Jurisdictions
Law No. 9,779 of January 1, 1999 states that, except for limited prescribed circumstances, income derived from transactions by a beneficiary, resident or domiciliary of a country considered a tax haven is subject to withholding income tax at the rate of 25%. Tax havens are considered to be countries which do not impose any income tax or which impose such tax at a maximum rate of less than 20%. Accordingly, if the distribution of interest attributed to shareholders’ equity is made to a beneficiary resident or domiciled in a tax haven jurisdiction, the applicable income tax rate will be 25% instead of 15%. Capital gains are not subject to this 25% tax, even if the beneficiary is resident in a tax haven jurisdiction. See “—Taxation of Gains.”
Registered Capital
The amount of an investment in preferred or common shares held by a non-Brazilian holder who obtains registration under Resolution No. 2,689, or by the depositary representing such holder, is eligible for registration with the Central Bank of Brazil; such registration (the amount so registered being called registered capital) allows the remittance outside Brazil of foreign currency, converted at the commercial market rate, acquired with the proceeds of distributions on, and amounts realized with respect to dispositions of, such preferred or common shares. The registered capital for each preferred or common share purchased as part of the international offering or purchased in Brazil after the date hereof, and deposited with the depositary will be equal to its purchase price (in U.S. dollars). The registered capital for a preferred or common share that is withdrawn upon surrender of an ADS will be the U.S. dollar equivalent of:
The U.S. dollar value of the average price of preferred or common shares is determined on the basis of the average of the U.S. dollar/Real commercial market rates quoted by the Central Bank of Brazil information system on that date (or, if the average price of preferred or common shares is determined under the second option above, the average of such average quoted rates on the same 15 dates used to determine the average price of preferred or common shares).
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A non-Brazilian holder of preferred or common shares may experience delays in effecting such registration, which may delay remittances abroad. Such a delay may adversely affect the amount, in U.S. dollars, received by the non-Brazilian holder. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Equity and Debt Securities.”
U.S. Federal Income Tax Considerations
The statements regarding U.S. tax law set forth below are based on U.S. law as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein. This summary describes the principal tax consequences of the ownership and disposition of common or preferred shares or ADSs, but it does not purport to be a comprehensive description of all of the tax consequences that may be relevant to a decision to hold or dispose of common or preferred shares or ADSs. This summary applies only to purchasers of common or preferred shares or ADSs who will hold the common or preferred shares or ADSs as capital assets and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements), tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common or preferred shares or ADSs on a mark-to-market basis, and persons holding common or preferred shares or ADSs in a hedging transaction or as part of a straddle or conversion transaction.
Each holder should consult such holder’s own tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common or preferred shares or ADSs.
Shares of our preferred stock will be treated as equity for U.S. federal income tax purposes. In general, for purposes of the U.S. Internal Revenue Code of 1986 (the “Code”) a holder of an ADS will be treated as the holder of the shares of common or preferred stock represented by those ADSs, and no gain or loss will be recognized if you exchange an ADS for the shares of common or preferred stock represented by that ADS.
In this discussion, references to ADSs refer to ADSs with respect to both common and preferred shares, and references to a “U.S. holder” are to a holder of an ADS that:
Taxation of Distributions
A U.S. holder will recognize ordinary dividend income for U.S. federal income tax purposes in an amount equal to the amount of any cash and the value of any property we distribute as a dividend to the extent that such distribution is paid out of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, when such distribution is received by the custodian, or by the U.S. holder in the case of a holder of common or preferred shares. The amount of any distribution will include the amount of Brazilian tax withheld on the amount distributed, and the amount of a distribution paid in Reais will be measured by reference to the exchange rate for converting Reais into U.S. dollars in effect on the date the distribution is received by the custodian, or by a U.S. holder in the case of a holder of common or preferred shares. If the custodian, or U.S. holder in the case of a holder of common or preferred shares, does not convert such Reais into U.S. dollars on the date it receives them, it is possible that the U.S. holder will recognize foreign currency loss or gain, which would be ordinary loss or gain, when the Reais are converted into U.S. dollars. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.
Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by an individual prior to January 1, 2009 with respect to the ADSs will be subject to taxation at a maximum rate of 15% if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if
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(i) the ADSs are readily tradable on an established securities market in the United States and (ii) the Company was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, (a) a passive foreign investment company (“PFIC”) or (b) for dividends paid prior to the 2005 tax year, a foreign personal holding company (“FPHC”) or foreign investment company (“FIC”). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on the Company’s audited financial statements and relevant market and shareholder data, the Company believes that it was not treated as a PFIC, FPHC or FIC for U.S. federal income tax purposes with respect to its 2003 or 2004 taxable year. In addition, based on the Company’s audited financial statements and its current expectations regarding the value and nature of its assets, the sources and nature of its income, and relevant market and shareholder data, the Company does not anticipate becoming a PFIC, FPHC or FIC for its 2005 taxable year. Based on existing guidance, it is not clear whether dividends received with respect to the shares will be treated as qualified dividends, because the shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs and intermediaries though whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes. Because such procedures have not yet been issued, it is not clear whether the Company will be able to comply with the procedures.
Distributions out of earnings and profits with respect to the shares or ADSs generally will be treated as dividend income from sources outside of the United States and generally will “passive income” for foreign tax credit purposes. Subject to certain limitations, Brazilian income tax withheld in connection with any distribution with respect to the shares or ADSs may be claimed as a credit against the U.S. federal income tax liability of a U.S. holder if such U.S. holder elects for that year to credit all foreign income taxes. Alternatively, such Brazilian withholding tax may be taken as a deduction against taxable income. Foreign tax credits may not be allowed for withholding taxes imposed in respect of certain short-term or hedged positions in securities or in respect of arrangements in which a U.S. holder’s expected economic profit is insubstantial. U.S. holders should consult their own tax advisors concerning the implications of these rules in light of their particular circumstances.
Holders of ADSs that are foreign corporations or nonresident alien individuals (“non-U.S. holders”) generally will not be subject to U.S. federal income tax or withholding tax on distributions with respect to shares or ADSs that are treated as dividend income for U.S. federal income tax purposes unless such dividends are effectively connected with the conduct by the holder of a trade or business in the United States.
Holders of shares and ADSs should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.
Taxation of Capital Gains
Upon the sale or other disposition of a share or an ADS, a U.S. holder will generally recognize gain or loss for U.S. federal income tax purposes. The amount of the gain or loss will be equal to the difference between the amount realized in consideration for the disposition of the share or the ADS and the U.S. holder’s tax basis in the share or the ADS. Such gain or loss generally will be subject to U.S. federal income tax and will be treated as capital gain or loss. The net amount of long-term capital gain recognized by an individual holder before January 1, 2009 generally is subject to taxation at a maximum rate of 15%. Capital losses may be deducted from taxable income, subject to certain limitations.
A non-U.S. holder will not be subject to U.S. federal income tax or withholding tax on gain realized on the sale or other disposition of a share or an ADS unless:
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Backup Withholding and Information Reporting
Dividends paid on, and proceeds from the sale or other disposition of, the ADSs or common or preferred shares to a U.S. holder generally may be subject to the information reporting requirements of the Code and may be subject to backup withholding unless the U.S. holder provides an accurate taxpayer identification number or otherwise establishes an exemption. The amount of any backup withholding collected from a payment to a U.S. holder will be allowed as a credit against the U.S. holder’s U.S. federal income tax liability and may entitle the U.S. holder to a refund, provided that certain required information is furnished to the Internal Revenue Service.
A non-U.S. holder generally will be exempt from these information reporting requirements and backup withholding tax, but may be required to comply with certain certification and identification procedures in order to establish its eligibility for such exemption.
Taxation relating to PIFCo’s notes
The following summary contains a description of material Cayman Islands, Brazilian and U.S. federal income tax considerations that may be relevant to the purchase, ownership, and disposition of PIFCo’s debt securities. This summary does not describe any tax consequences arising under the laws of any state, locality or taxing jurisdiction other than the Cayman Islands, Brazil and the United States.
This summary is based on the tax laws of the Cayman Islands, Brazil and the United States as in effect on the date of this annual report, which are subject to change (possibly with retroactive effect). This description is not a comprehensive description of all of the tax considerations that may be relevant to any particular investor, including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors. Prospective purchasers of notes should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of notes.
There is no reciprocal tax treaty between the Cayman Islands and the United States, the Cayman Islands and Brazil or Brazil and the United States. In recent years, the tax authorities of Brazil and the United States have held discussions that may culminate in such a treaty. We cannot predict, however, whether or when a treaty will enter into force or how it will affect the U.S. holders of notes.
Cayman Islands Taxation
Under current law, PIFCo is not subject to income, capital, transfer, sales or other taxes in the Cayman Islands.
PIFCo was incorporated as an exempted company under the laws of the Cayman Islands on September 24, 1997. PIFCo has received an Undertaking as to Tax Concessions pursuant to Section 6 of the Tax Concessions Law (1999 Revision) which provides that, for a period of twenty years from the date thereof no law hereafter enacted in the Cayman Islands imposing any tax or duty to be levied on income or on capital assets, gains or appreciation will apply to any of PIFCo’s income or property and which is deemed to provide that no tax is to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable or in respect of shares, debentures or other of PIFCo’s obligations, or by way of withholding of any part of a payment of principal due under a debenture or other of PIFCo’s obligations.
No Cayman Islands withholding tax applies to distributions by PIFCo in respect of the notes. Noteholders are not subject to any income, capital, transfer, sales or other taxes in the Cayman Islands in respect of their purchase, holding or disposition of the notes.
Noteholders whose notes are brought into or issued in the Cayman Islands will be liable to pay stamp duty of up to C.I.$250 on each note.
Brazil Taxation
The following discussion is a summary of the Brazilian tax considerations relating to an investment in the notes by a non-resident of Brazil. The discussion is based on the tax laws of Brazil as in effect on the date hereof and is
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subject to any change in Brazilian law that may come into effect after such date. The information set forth below is intended to be a general discussion only and does not address all possible consequences relating to an investment in the notes.
PROSPECTIVE INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISERS AS TO THE CONSEQUENCES OF PURCHASING THE NOTES, INCLUDING, WITHOUT LIMITATION, THE CONSEQUENCES OF THE RECEIPT OF INTEREST AND THE SALE, REDEMPTION OR REPAYMENT OF THE NOTES OR COUPONS.
Generally, an individual, entity, trust or organization domiciled for tax purposes outside Brazil (a “Non-resident”) is taxed in Brazil only when income is derived from Brazilian sources. Therefore, any gains or income paid by PIFCo in respect of the notes issued by it in favor of Non-resident noteholders are not subject to Brazilian taxes.
Interest (including OID), fees, commissions, expenses and any other income payable by a Brazilian resident to a Non-resident are generally subject to income tax withheld at source. Currently, the rate of withholding tax is 15% or such other lower rate as provided for in an applicable tax treaty between Brazil and another country. If the recipient of the payment is domiciled in a tax haven jurisdiction, as defined by Brazilian tax regulations, the rate will be 25%.
If the payments with respect to the notes are made by a Brazilian source, the noteholders will be indemnified so that, after payment of all applicable Brazilian taxes collectable by withholding, deduction or otherwise, with respect to principal, interest (including the OID) and additional amounts payable with respect to the notes (plus any interest and penalties thereon), a noteholder will retain an amount equal to the amounts that such noteholder would have retained had no such Brazilian taxes (plus interest and penalties thereon) been payable. The Brazilian obligor will, subject to certain exceptions, pay additional amounts in respect of such withholding or deduction so that the holder receives the net amount due.
Gains on the sale or other disposition of the notes made outside Brazil by a Non-resident, other than a branch or a subsidiary of Brazilian resident, to another Non-resident are not subject to Brazilian taxes. Gains made by a Brazilian Non-resident from the sale or other disposition of notes to a Brazilian resident, subject to certain assumptions and conditions, are not subject to Brazilian taxes.
Generally, there are no inheritance, gift, succession, stamp, or other similar taxes in Brazil with respect to the ownership, transfer, assignment or any other disposition of the notes by a Non-resident, except for gift and inheritance taxes imposed by some Brazilian states on gifts or bequests by individuals or entities not domiciled or residing in Brazil to individuals or entities not domiciled or residing within such states.
U.S. Federal Income Taxation
The following summary sets forth certain United States federal income tax considerations that may be relevant to a holder of a note that is, for U.S. federal income purposes, a citizen or resident of the United States or a domestic corporation or that otherwise is subject to Untied States federal income tax on a net income basis in respect of the notes (a “U.S. holder”). This summary is based upon the Code, its legislative history, existing and proposed U.S. Treasury regulations promulgated thereunder, published rulings by the U.S. Internal Revenue Service, or the IRS, and court decisions, all in effect as of the date hereof, all of which authorities are subject to change or differing interpretations, which changes or differing interpretations could apply retroactively. This summary does not purport to discuss all aspects of United States federal income taxation which may be relevant to particular investors, such as financial institutions, insurance companies, dealers or traders in securities or currencies, regulated investment companies, tax-exempt organizations, certain short-term holders of notes, persons that hedge their exposure in the notes or hold notes as part of a position in a “straddle” or as part of a hedging transaction or “conversion transaction” for U.S. federal tax purposes, persons that enter into a “constructive sale” transaction with respect to the notes or U.S. Holder whose functional currency as defined in Section 985 of the code is not the U.S. dollar. U.S. holders should be aware that the U.S. federal income tax consequences of holding the notes may be materially different for investors described in the prior sentence.
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In addition, this summary does not discuss any foreign, state or local tax considerations. This summary only applies to original purchasers of notes who purchase notes at the original issue price and hold the notes as “capital assets” (generally, property held for investment) within the meaning of Section 1221 of the Code.
PROSPECTIVE INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE TAX CONSEQUENCES OF INVESTING IN THE NOTES, INCLUDING THE EFFECTS OF FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX LAWS.
Payments of interest
Payments of “qualified stated interest” (as defined below) on a note (including additional amounts, if any) generally will be taxable to a U.S. holder as ordinary interest income when such interest is accrued or received, in accordance with the U.S. holder’s regular method of tax accounting. In general, if the “issue price” of a note is less than the “stated redemption price at maturity” by more than a de minimis amount, such note will be considered to have “original issue discount” (“OID”). The issue price of a note is the first price at which a substantial amount of such notes are sold to investors. The stated redemption price at maturity of a note generally includes all payments other than payments of qualified stated interest (as defined below).
In general, each U.S. holder of a note, whether such holder uses the cash or the accrual method of tax accounting, will be required to include in gross income as ordinary interest income the sum of the “daily portions” of OID on the note for all days during the taxable year that the US holder owns the note. The daily portions of OID on a note are determined by allocating to each day in any accrual period a ratable portion of the OID allocable to that accrual period. In general, in the case of an initial holder, the amount of OID on a note allocable to each accrual period is determined by (a) multiplying the “adjusted issue price,” as defined below, of the note at the beginning of the accrual period by the yield to maturity of the note, and (b) subtracting from that product the amount of qualified stated interest allocable to that accrual period. U.S. holders should be aware that they generally must include OID in gross income as ordinary interest income for U.S. federal income tax purposes as it accrues, in advance of the receipt of cash attributable to that income. The “adjusted issue price” of a note at the beginning of any accrual period will generally be the sum of its issue price (generally including accrued interest, if any) and the amount of OID allocable to all prior accrual periods, reduced by the amount of all payments other than payments of qualified stated interest (if any) made with respect to such note in all prior accrual periods. The term “qualified stated interest” generally means stated interest that is unconditionally payable in cash or property (other than debt instruments of the issuer) at least annually during the entire term of a note at a single fixed rate of interest, or subject to certain conditions, based on one or more interest indices.
Interest income, including OID, in respect of the notes will constitute foreign source income for United sates federal income tax purposes and, with certain exceptions, will be treated separately, together with other items of “passive income” for purposes of computing the foreign tax credit allowable under the United states federal income tax laws. The calculation of foreign tax credits, involves the application complex of rules that depend on a U.S. holder’s particular circumstances. U.S. holders should consult their own tax advisors regarding the availability of foreign tax credits and the treatment of additional amounts.
Sale or disposition of notes
A U.S. holder generally will recognize capital gain or loss upon the sale, exchange, retirement or other disposition of a note in an amount equal to the difference between the amount realized upon such sale, exchange, retirement or other disposition (other than amounts attributable to accrued qualified stated interest, which will be taxed as such) and such U.S. holder’s adjusted tax basis in the note. A U.S. Holder’s adjusted tax basis in the note generally will equal the U.S. holder’s cost for the note increased by any amounts included in gross income by such U.S. holder as OID and reduced by any payments other than payments of qualified stated interest on that note. Gain or loss realized by a U.S. Holder on the sale, exchange, retirement or other disposition of a note generally will be United States source gain or loss for United States federal income tax purposes unless it is attributable to an office or other fixed place of business outside the United States and certain other conditions are met. The gain or loss realized by a U.S. holder will be capital gain or loss, and will be long-term capital gain or loss if the notes were held for more than one year. The net amount of long-term capital gain recognized by an individual holder before January 1, 2009 generally is subject to taxation at a maximum rate of 15%.
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A U.S. holder may, under certain circumstances, be subject to “backup withholding” with respect to certain payments to that U.S. holder, unless the holder (i) is a corporation or comes within certain other exempt categories, and demonstrates this fact when so required, or (ii) provides a correct taxpayer identification number, certifies that it is not subject to backup withholding otherwise complies with applicable requirements of the backup withholding rules. Any amount withheld under these rules generally will be creditable against the U.S. holder’s U.S. federal income tax liability. While Non-U.S. holders generally are except from backup withholding, a Non-U.S. holder may, in certain circumstances, be required to comply with certain information and identification procedures in order to prove entitlement to this exemption.
Non-U.S. Holder
A holder or beneficial owner of a note that is not a U.S. holder (a “non-U.S. holder”) generally will not be subject to U.S. federal income or withholding tax on interest received on the notes. In addition, a non-U.S. holder will not be subject to U.S. federal income or withholding tax on gain realized on the sale of notes unless, in the case of gain realized by an individual non-U.S. holder, the non-U.S. holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met.
Documents on Display
Statements contained in this annual report regarding the contents of any contract or other document are not necessarily complete, and, where the contract or other document is an exhibit to the annual report, each of these statements is qualified in all respects by the provisions of the actual contract or other documents.
We are subject to the information requirements of the Securities Exchange Act of 1934, as amended, applicable to a foreign private issuer, and accordingly, we file or furnish reports, information statements and other information with the SEC. These reports and other information filed by us can be inspected at, and subject to the payment of any required fees, copies may be obtained from, the public Reference Section of the SEC, 450 Fifth Street, N.W., room 1024, Washington, D.C. 20549. As a foreign private issuer, we were not required to make filings with the SEC by electronic means prior to November 4, 2002, although we were permitted to do so. Any filings we make electronically will be available to the public over the internet at the SEC’s website at http://www.sec.gov.
Reports and other information may also be inspected and copied at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. As a foreign private issuer, however, we are exempt from the proxy requirements of Section 14 of the Exchange Act and from the short-swing profit recovery rules of Section 16 of the Exchange Act, although the rules of the New York Stock Exchange may require us to solicit proxies from our shareholders under some circumstances. Our website is located at http://www.petrobras.com.br. The information on our website is not part of this annual report.
PIFCo Senior Notes
PIFCo has issued three series of Senior Notes in the aggregate amount of U.S.$1,550.0 million. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources.” The terms of each of these series of Senior Notes, and the material agreements, which set forth, their terms, are substantially similar and are summarized below.
Indentures
PIFCo issued each series of Senior Notes pursuant to an indenture between PIFCo, as the issuer, and The Bank of New York, as trustee. The terms of the indentures require PIFCo and its subsidiaries, among other things, to:
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In addition, the terms of the indenture restrict PIFCo’s ability and the ability of its subsidiaries, among other things, to:
These covenants are subject to a number of terms, conditions and further qualifications.
The indenture also contains certain events of default, consisting of the following:
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Standby Purchase Agreements
PIFCo’s Senior Notes have the benefit of credit support from us in the form of standby purchase agreements under which we are obligated to make certain payments to the trustee in the event PIFCo fails to make required payments of principal, interest and other amounts due under the Senior Notes and the indenture. Subject to certain limitations, we are required to purchase from the holders of the PIFCo notes and pay to the trustee amounts in respect of the noteholders’ right to receive:
PIFCo will have the right to defer making payments under the Senior Notes indentures for up to 18 months, if an event of inconvertibility, untransferability or expropriation occurs that prevents us from making required payments under the standby purchase agreement.
Obligations under the standby purchase agreement constitute direct and general senior unsecured and unsubordinated obligations of ours and rank pari passu with other senior, unsecured obligations of ours that are not, by their terms, expressly subordinated in right of payment to our obligations under the standby purchase agreement.
Letters of Credit/Political Risk Insurance
Pursuant to the indentures, PIFCo established and maintained reserve accounts with the trustee on behalf of the holders of the Senior Notes. PIFCo was also required to issue an irrevocable standby letter of credit in favor of the trustee or provide political risk insurance for the trustee, in aggregate amounts set forth in the terms of the Senior Notes. The required coverage amount varies for each series of Senior Notes. The funds in the reserve account may
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be returned to PIFCo, and the required coverage amount may be reduced, under certain circumstances. PIFCo has paid all premiums on its insurance policies and/or has funded and issued standby irrevocable letters of credit, which will be replaced by other standby letters of credit or by funds in its reserve accounts.
Amounts may be withdrawn from the reserve account and drawings may be made under the letter of credit or the political risk insurance policy to make scheduled interest payments on the Senior Notes for up to 18 months, if an event of inconvertibility, untransferability or expropriation occurs.
PIFCo Global Notes
On March 31, 2003, PIFCo issued U.S.$400 million of Global Step-Up Notes due 2008, which bear interest from March 31, 2003 at the rate of 9.00% per year until April 1, 2006 and at a rate of 12.375% thereafter. On July 2, 2003, PIFCo issued U.S.$500 million of 9.125% Global Notes. On September 18, 2003, PIFCo issued an additional U.S.$250 million in 9.125% Global Notes, which form a single fungible series with the U.S.$500 million Global Notes due July 2013. On December 10, 2003, PIFCo issued U.S.$750 million of 8.375% Global Notes due 2018. On September 15, 2004, PIFCo issued U.S.$600 million of 7.75% Global Notes due 2014.
PIFCo issued these notes pursuant to our and PIFCo’s U.S.$8 billion shelf registration statement on Form F-3, which was filed with the SEC on July 2, 2002. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources.”
The terms of these notes are summarized below.
Indenture
PIFCo issued the Global Notes pursuant to an indenture between PIFCo, as the issuer, and JP Morgan Chase Bank, as trustee, dated as of July 19, 2002. The U.S.$400 million Global Step-Up Notes due 2008 were supplemented by the first supplemental indenture dated as of March 31, 2003, among PIFCo, us and the trustee. The U.S.$500 million 9.125% Global Notes issued on July 2, 2003 due 2013 were supplemented by the second supplemental indenture dated as of July 2, 2003, among PIFCo, us and the trustee. The U.S.$250 million 9.125% Global Notes issued on September 18, 2003 due 2013 were supplemented by the amended and restated second supplemental indenture dated as of September 18, 2003, among PIFCo, us and the trustee. The U.S.$750 million 8.375% Global Notes due 2018 were supplemented by the third supplemental indenture dated as of December 10, 2003, among PIFCo, us and the trustee. The U.S.$600 million 7.75% Global Notes due 2014 were supplemented by the fourth supplemental indenture dated as of September 15, 2004, among PIFCo, us and the trustee. When we refer to the indenture in this section, we are referring to the indenture as supplemented by the first, second, amended and restated second, third and fourth supplemental indentures.
The terms of the indenture require PIFCo, among other things, to
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Standby Purchase Agreement
PIFCo’s Global Notes have the benefit of credit support from us in the form of a standby purchase agreement under which we are obligated to make certain payments to the trustee in the event PIFCo fails to make required payments of principal, interest and other amounts due under the senior Global Notes and the indenture. Subject to certain limitations, we are required to purchase from the holders of the notes and pay to the trustee amounts in respect of the noteholders’ right to receive:
The Global Notes did not include a letter of credit or political risk insurance.
Sale of Future Receivables
In connection with our exports prepayment program, PFL has received senior and junior trust certificates in the aggregate amount of U.S.$1,800.0 million. 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. See Item 4. “Information on the Company—Incorporation of PIFCo—PIFCo Business Overview—Export Prepayment Program.”
The Prepayment Agreement
Pursuant to a prepayment agreement entered into by us and PFL, we undertook to deliver, for as long as any Senior and Junior Trust Certificates remain outstanding, in each quarterly period, a quantity of Eligible Products having a market value equal to any scheduled payments of interest on and principal of the Senior and Junior Trust Certificates.
The Master Export Contract
As long as any Senior Trust Certificates or any amounts payable to the insurers remain outstanding, we will deliver, in each quarterly period, a quantity of Eligible Products having a value equal to any scheduled payments of interest, principal or other amounts due under the Senior Trust Certificates. Under the Master Export Contract, we export and sell Eligible Products to PFL during each quarterly period:
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We also agree that our average daily gross exports of fuel oil and bunker fuel for any rolling twelve-month period will be equal to at least 70,000 barrels of fuel oil and bunker fuel. We are not relieved of our obligations to deliver Eligible Products under the Master Export Contract or the Prepayment Agreement, for any reason, including, without limitation, as a result of force majeure or on non-payment by PFL.
Risk of Loss
We fulfill our delivery obligations to PFL by delivering the Eligible Products directly to buyers on behalf of PFL. Title and risk of loss remain with us until the Eligible Products are delivered to the buyers, at which time both title and risk of loss pass to PFL and simultaneously to the buyers.
Taxes and Expenses
We are obligated to indemnify PFL against all costs, expenses, liabilities, damages and other similar obligations which may be imposed upon, incurred or suffered by PFL in respect of any present or future taxes of any nature assessed against PFL by Brazil, the Cayman Islands, the United States or any other taxing jurisdiction.
Indemnification
We are obligated to indemnify and hold harmless PFL, its affiliates, and their respective officers, directors, employees and agents from all suits, direct damages or other losses arising from or out of the transactions contemplated by the principal agreements, including: any negligence or willful misconduct of ours, breach of representations or warranties, claims for payment (whether in cash or kind) by any and all third parties in respect of taxes or similar charges upon the distribution, sale and transportation of any Eligible Products prior to its export, claims for payment by any and all third parties who purport to be entitled to receive any portion of the proceeds from, or any payment relating to, the sale of the Eligible Products to PFL, amounts payable by PFL in respect of any indemnification provided to other persons, and all expenses arising from or out of any tax which may be levied and assessed upon PFL in respect of any delivery, sale or resale of Eligible Products to PFL.
Negative Pledge
So long as any senior trust certificate remains outstanding or any amount payable to an Enhancer under any of the insurance documents remains outstanding, we will not create or permit any Lien, other than a Petrobras Permitted Lien, on any of our assets or any of our subsidiaries’ assets to secure (i) any of our indebtedness, (ii) any of our subsidiaries’ indebtedness or (iii) the indebtedness of any other person, unless we contemporaneously create or permit such Lien to secure equally and ratably our obligations under the Master Export Contract and the other transaction documents to which we are a party or we provide other security for our obligations under the Master Export Contract and the other transaction documents to which we are a party as is duly approved by a resolution of the senior certificate holders in accordance with the trust deed.
Sales Agreements
PFL sells Eligible Products purchased from us or our affiliates though the following agreements:
Offtake Contracts with Citibank, N.A, as Offtaker, pursuant to which PFL agreed to deliver and sell, and Citibank N.A. agreed to accept and purchase, during each quarterly delivery period, Eligible Products with a value equal to at least 1.1 times the amounts scheduled to be paid in respect of the Series 2001 and 2003
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Senior Trust Certificates on the payment date immediately following the end of such quarterly delivery period.
The Receivables Purchase Agreement
Pursuant to a Receivables Purchase Agreement, PFL sells to the Trustee the rights to a specified amount of designated receivables to be generated from the sale of Eligible Products by PFL. In exchange, the Trustee issued to PFL the Senior and Junior Trust Certificates. The rights to the purchased receivables acquired by the Trust on the closing date consists of:
The Insurance and Reimbursement Agreements
Each of the 2001 series and the 2003 B series of Senior Trust Certificates features credit enhancement by means of a financial guaranty insurance policy. See Item 4. “Information on the Company—PIFCo Business Overview—Exports Prepayment Programs.”
The parties also entered into Insurance and Reimbursement Agreements pursuant to which, among other things, the Trustee has agreed to reimburse, with interest, MBIA, Ambac and XL Capital Assurance Inc., as applicable, for amounts paid pursuant to claims made under their respective financial guaranty insurance policies.
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We are exposed to a number of market risks arising from our normal business activities. Such market risks principally involve the possibility that changes in commodity prices, currency exchange rates or interest rates will adversely affect the value of our financial assets and liabilities or future cash flows and earnings.
Although we currently produce approximately 80% of our crude oil requirements in Brazil, we import a substantial amount of crude oil, as well as smaller quantities of diesel, liquefied petroleum gas, naphtha and other oil products. We also export crude oil, bunker fuel, fuel oil and gasoline. Virtually all of the prices for these imports and exports are payable in U.S. dollars even though substantially all our revenues are collected in Reais (despite the fact these prices are partly based on international prices). In addition, a substantial portion of our indebtedness and some of our operating expenses are, and we expect them to continue to be, denominated in or indexed to U.S. dollars or other foreign currencies. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil” for the manner in which the Brazilian government has controlled the prices we charge.
The principal market for our products is Brazil and substantially all of our revenues are denominated in Reais. We have described above under Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation” the manner in which the Brazilian government has regulated the prices we charge.
Risk Management
The market risks we face consist principally of commodity price risk, and to a lesser extent, interest rate risk and exchange rate risk.
Our management of risk exposures is evolving under the policies of our executive officers, acting as a group, most of whom have been in office since February 2003. In 2004, we created a Risk Management Committee comprised of members of all our business areas to promote an integrated management of our risk exposures and to establish the main guidelines to be adopted by us to handle risks related to our activities. As described below, we enter into contracts, such as energy futures, forwards, puts, swaps and options, designed to hedge against the risk of price changes relating to our imports and exports. Such derivative commodity instruments are used only to offset market exposures resulting from these imports and exports, and are not used for trading purposes. The results of our derivative activities are reviewed by senior management from time to time to permit the goals and strategies of the program to be periodically adjusted in response to market conditions. The derivative instruments contracted by us for purposes of risk management do not qualify for hedge accounting under SFAS 133. See Notes 22 and 23 to our audited consolidated financial statements.
By using derivative instruments, we expose ourselves to credit and market risk. Credit risk is the failure of a counter party to perform under the terms of the derivative contract. Market risk is the adverse effect on the value of a financial instrument that results from a favorable change in interest rates, currency exchange rates or commodity prices. We address credit risk by restricting the counterparties to such derivative financial instrument to major financial institutions. Our executive officers manage market risk.
PESA also uses derivative instruments such as options, swaps and others, mainly to mitigate the impact of changes in crude oil prices, interest rates and future exchange rates. Such derivative instruments are designed to mitigate specific exposures, and are assessed periodically to assure high correlation of the derivative instrument to the risk exposure identified and to assure that the derivative is highly effective in offsetting changes in cash flows inherent in the covered risk. PESA qualifies for hedge accounting treatment for its crude oil derivative instruments and its interest rate swap derivative instruments.
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Commodity Price Risk
Our sales of crude oil and oil products are based on international prices, thus exposing us to price fluctuations in the international markets.
In order to mitigate the impact of such fluctuations, we have entered into derivative transactions, primarily futures contracts, options and swaps. Our futures contracts provide economic hedges for anticipated crude oil purchases and sales, generally forecast to occur within a 30- to 360-day period. Our exposure on these contracts is limited to the difference between contract value and market value on the volumes hedged.
For 2004, we carried out derivative transactions on 33.1% of our total trade volume, as compared to 40.5% of our total trade volume for 2003 and 42.0% of our total trade volume for 2002. This decrease in our derivative transactions is a result of normal fluctuations in our operations. The open positions on the futures market, compared to spot market value, resulted in recognized losses of U.S.$2 million in 2004, U.S.$2 million in 2003 and U.S.$4 million in 2002.
In January of 2001, we sold put options for 52 million barrels of West Texas Intermediate oil over a period from 2004 to 2007. We executed the transaction in order to protect the quantity of oil from price fluctuations and provide the institutions financing the Barracuda/Caratinga project with a minimum guaranteed margin to cover debt servicing. The puts were structured to guarantee a minimum return on investment for the institutions financing the project. The value of our position with respect to this put option resulted in no gain or losses at December 31, 2004, a recognized net gain of U.S.$7 million at December 31, 2003 and U.S.$8 million at December 31, 2002.
In connection with the long-term contract to buy gas ( the “Gas Supply Agreement” or “GSA”) to supply thermoelectric plants and for other uses in Brazil, we entered into a contract, effective October 2002, with a gas producer that constituted a derivative financial instrument under SFAS No. 133. This contract, the Natural Gas Price Volatility Reduction Contract (the “PVRC”), with maturity in 2019, was executed with the purpose to reduce the volatility of price under the GSA. The counterparty to the PVRC is one of the gas producers that sell to the supplier under the GSA contract. Therefore, the PVRC refers to the same volumes of natural gas sold by the counterparty to the supplier under the GSA, and uses the same pricing index as the GSA contract and thus works as an economic hedge. The volume covered by the PVRC represents approximately 43% of the anticipated volume under the GSA.
The terms of the PVRC include a straight fixed for floating price swap for the period between inception and 2004, and for the period from 2005 to 2019, a collar with us receiving cash payments when the calculated price is over the established ceiling and we making cash payments when the price is below the established floor, with no cash payments being made when the price is between the ceiling and the floor.
The PVRC is being accounted for under SFAS No. 133 as a derivative instrument, since we did not satisfy the documentation required for hedge accounting, and is being marked to its calculated fair value with changes in such value recognized in income. At inception, the PVRC had a positive value to us of $169 million, which is deemed a deferred purchase incentive and is being amortized into income on the basis of the volumes anticipated under the PVRC. The liability was US$153 million at December 31, 2004 and generated a gain in the amount of US$11 million, net of deferred tax effect of US$5 million.
As of December 31, 2004, we recorded a derivative asset based on the fair value calculation in the amount of $635 million, and a mark-to-market (or “MTM”) gain in the amount of US$365 million, net of deferred tax effect of US$188 million. Such MTM gains represent the increased value of the derivative from inception to December 31, 2004. The derivative gains are recorded as a component of financial income. The effects of the PVRC were not recognized from inception but the impact was immaterial and has been cumulatively recognized in 2004.
Considering that there are no market quotations for natural gas for such a long duration as that of the PVRC, the fair value was calculated based on simulation using a mean reversion model developed by us. The most significant model assumptions at December 31, 2004 include starting prices of crude oil of $39.53 per barrel, an average fuel oil basket (i.e., the price index of the GSA) of $23.58 per barrel and a volatility of crude oil of 25% a.a. Other parameters of the model, including the long run average of crude oil, fuel oil spread to crude, correlations and inflation indexes were estimated based on historical averages.
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A $1 per barrel increase in the market price of fuel oil under the PVRC would result in a $24 million increase in the fair value of the derivative at December 31, 2004.
As indicated above, the accounting impacts recognized are in accordance with SFAS No. 133, whereas the economic impact and cash flow results of the transaction are to fix the price paid for natural gas supplied within a range and to receive or pay cash for price fluctuations under the GSA beyond those capped amounts. Such ceiling and floor amounts in the PVRC allow the purchase of natural gas at a price level appropriate to us, which then sells the gas in the local market to distributors at a price level that will allow the sustained development of the natural gas market in Brazil.
The following table sets forth a sensitivity analysis demonstrating the net change in fair value of 10% adverse change for the PVRC.
Derivative maturing 2005-2019
Gas price Collar
International hedging activities in 2004 represented an average of 310,000 barrels of oil equivalent per day of physical movements, of which 12.9% was related to fuel oil, 13.4% was related to diesel, 13.7% was related to gasoline and 60.0% was related to crude oil, as compared to our international hedging activities in 2003 which represented an average of 564,000 barrels of oil equivalent per day of physical movements, of which 20.0% was related to fuel oil, 21.2% was related to gasoline, 20.8% was related to diesel and 38.0% was related to crude oil. This decrease in our international derivative transactions was a result of normal fluctuations in our operations. Of our total hedging activities in 2004, 80% were carried out by Petrobras, 11% by PIFCo and 9% by PAI.
The following table sets forth a sensitivity analysis demonstrating the net change in fair value of a 10% adverse change in the price of the underlying commodity as of December 31, 2004, which is a 10% increase in the price of the underlying commodity for Options, Futures and Swaps and a 10% decrease for Options maturing 2005-2008.
Maturing in 2005
Options
Buy contracts
Sell contracts
Futures
Swaps
Receive variable/pay fixed
Receive fixed/pay variable
Options maturing 2005-2007(2)
Interest Rate and Exchange Rate Risk
The interest rate risk to which we are exposed is a function of our long-term debt and, to a lesser extent, our short-term debt. Our long-term debt consists principally of notes and borrowings incurred primarily in connection with capital expenditures and investments in exploration and development projects and loans to affiliated companies. Approximately 89% of our long-term debt is denominated in currencies other than Reais, principally U.S. dollars, and to a lesser extent, Japanese Yen and euro-linked European currencies. Our short-term debt consists principally of U.S. dollar denominated import and export financing and working capital borrowings from commercial banks. In general, our foreign currency floating rate debt is principally subject to fluctuations in
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LIBOR. Our floating rate debt denominated in Reais is principally subject to fluctuations in the Taxa de Juros de Longo Prazo (Brazilian long-term interest rate, or TJLP), as fixed by the National Monetary Council. See Note 12 to our audited consolidated financial statements.
We currently do not utilize derivative instruments to manage our exposure to interest rate fluctuation. We have been considering various forms of derivatives to reduce our exposure to interest rate fluctuations and may utilize these financial instruments in the future.
The exchange rate risk to which we are exposed is limited to the balance sheet and derives principally from the incidence of non-Real denominated obligations in our debt portfolio. In the event of a devaluation of the Real against the foreign currency in which our debt is denominated, we will incur a monetary loss with respect to such debt. However, a considerable part of our operating revenue is linked to the U.S. dollar since our oil product prices are based on international prices, while some expenses are not. See Item 5. “Operating and Financial Review and Prospects—General.”
The table below provides summary information regarding our exposure to interest rate and exchange rate risk in our total debt portfolio for 2004 and 2003. Total debt portfolio includes long-term debt, capital leases, project financings, and current portions thereof, and short-term debt.
Real denominated
o/w fixed rate
o/w floating rate
Dollar denominated
o/w floating rate (includes short-term debt)
Other currencies (primarily Yen)
Floating Rate Debt
Foreign Currency Denominated
Fixed Rated Debt
U.S. dollars
Euro
Japanese Yen
British Pounds
Brazilian Reais
Argentine Pesos
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The table below provides information about our total debt obligations as of December 31, 2004, which are sensitive to changes in interest rates and exchange rates. This table presents, by expected maturity dates and currency, the principal cash flows and related average interest rates of these obligations. Variable interest rates are based on the applicable reference rate, LIBOR, TJLP, IGP-M, CDI (Certificado de Depósito Interbancário, or Interbank Deposit Certificate) as of December 31, 2004:
Debt in EURO:
Fixed rate debt
Average interest rate
Variable rate debt
Debt in Japanese Yen:
Debt in U.S. dollars:
Debt in Brazilian Reais:
Debt in Argentine Pesos:
Total debt
obligations
In 2000, we entered into three zero-cost foreign exchange collars (combined put and call options) to reduce our exposure to variations with a notional amount of approximately U.S.$470 million between the U.S. dollar and the Japanese Yen exchange rate, and between the U.S. dollar and Euro exchange rate. These collars establish a ceiling and a floor for the associated exchange rates. If the exchange rate falls below the defined floor, the counterparty will pay to us the difference between the actual rate and the floor rate on the notional amount. Conversely, if the exchange rate increases above the defined ceiling, we will pay to the counterparty the difference between the actual rate and the ceiling rate on the notional amount. We do not account for these derivative contracts as hedge derivative instruments.
The Yen zero-cost collar contracts expired on September 8, 2003, and were settled by a cash payment of U.S.$68 million. One of our Euro (Austrian Schilling) zero-cost collar expired on December 29, 2004 and was settled by a cash payment to us of U.S.$18 million.
The table below provides information about our remaining zero-cost foreign exchange collars. The table presents the notional amount of the related debt obligation, the floor and ceiling rates, the fair values of the put and call options and the expiration date of the contract.
Italian
Lira
Notional amount of debt (U.S.$ in millions)
Contractual rates(1)
Interest payments
Floor
Ceiling
Final principal payments
Fair value as of December 31, 2004 (U.S.$ in millions)
Put Option
Call Option
Expiration date
PIFCo makes limited use of derivatives, which are contracted by Petrobras on behalf of PIFCo. PIFCo does not hold derivative instruments for trading purposes or for leverage.
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In the normal course of business, PIFCo faces market risks, including interest rate risk and oil and oil products price risk. Neither we nor PIFCo have entered into derivative contracts or made other arrangements to hedge against interest rate risk. 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 are considering methods of continuing this practice in the future, we cannot assure you that this practice will continue.
PIFCo’s borrowings are derived mainly from commercial banks and include trade lines of credit and commercial paper, which are primarily intended for the purchase of crude oil and oil products, and with interest rates ranging from 2.86% to 6.01%. The weighted average annual interest rate for PIFCo’s short-term debt at December 31, 2004 was 4.25%, compared to 3.85% at December 31, 2003.
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The table below sets forth the amounts and related weighted average annual interest rates by expected maturity dates for PIFCo’s long-term debt obligations at December 31, 2004:
CALENDAR YEAR OF EXPECTED MATURITY DATE FOR DEBT
(in thousands of U.S. dollars, except for percentages)
December 31, 2004
Debt Obligations
Debt in U.S. Dollars:
Total debt obligations
Total Debt Portfolio
December 31,
U.S. Dollars:
Floating rate debt
At December 31, 2004, 15.5% of PIFCo’s debt was dollar-denominated floating rate debt and 84.5% of PIFCo’s debt was dollar-denominated fixed rate debt. Since all of PIFCo’s debt is dollar denominated, it is not subject to material foreign exchange rate risk.
Not Applicable.
None.
Both PIFCo and we carried out an evaluation under the supervision and with the participation of our respective management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our respective disclosure controls and procedures as of December 31, 2004. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our respective evaluations, our respective Chief Executive Officer and Chief Financial Officer concluded that our respective disclosure controls and procedures as of December 31, 2004 were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required.
There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
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We failed to properly identify a contract as a derivative instrument and account for it under the rules of FAS 133, which could be classified as a significant deficiency in our internal controls. We do not believe that additional errors may result from any significant deficiency, as the contract identified was unique in nature and entered to address a specific long-term price risk exposure. We have made an extensive internal search and determined there to be no similar contracts existing within the company. We are currently working to address any significant deficiencyin the context of our preparation for reporting on evaluation of internal controls design and effectiveness under Section 404 and expect to remedy any significant deficiency prior to having to make such a Section 404 evaluation.
On June 17, 2005 our Board of Directors approved the appointment of an audit committee for purposes of the Sarbanes-Oxley Act of 2002. Our Board of Directors has determined that Fabio Colletti Barbosa is the audit committee financial expert.
PIFCo’s board of directors currently serves as its audit committee for purposes of the Sarbanes-Oxley Act of 2002. PIFCo’s board of directors has determined that Almir Guilherme Barbassa is an “audit committee financial expert” within the meaning of this Item 16A.
We have adopted a Code of Ethics applicable to our employees and executive officers and a Code of Good Practices applicable to our directors and executive officers, both of which are also applicable to PIFCo. No waivers of the provisions of the Code of Ethics or Code of Good Practices are permitted. Both documents are available on Petrobras’ website: www.petrobras.com.br/investor relations/corporate governance.
Principal Accountant Fees
Audit and Non-Audit Fees
The following table sets forth the fees billed to us by our independent auditors, Pricewaterhouse Coopers Auditores Independentes from January to March of 2003, and Ernst & Young Auditores Independentes S/S from March 2003 until December 31, 2003 and during the fiscal year ended December 31, 2004:
Audit fees
Audit-related fees
Tax fees
Other fees
Total fees
Audit fees in the above table are the aggregate fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S in connection with the audit of our annual financial statements (U.S. GAAP and Brazilian GAAP), interim reviews (U.S. GAAP and Brazilian GAAP), subsidiary audits (U.S. GAAP and Brazilian GAAP, among others) and review of periodic documents filed with the SEC.
Audit-related fees in the above table are the aggregate fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S for assurance and related services with due diligence, our shelf registration with the SEC and attest services that are not required by statute or regulation.
Tax fees in the above table are fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S for services related to tax compliance.
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Other fees in the above table paid to Pricewaterhouse Coopers Auditores Independentes in 2003 primarily related to services rendered with respect to environmental liabilities, the PEGASO program, the Pipeline Integrity Program, and to a lesser degree, our Strategic Plan, organizational structure and data processing services.
Other fees in the above table paid to Ernst & Young Auditores Independentes S/S primarily in 2004 primarily related to services rendered with respect to the review of our 2004 annual report for investors.
The following table sets forth the fees billed to PIFCo by its independent auditors, Pricewaterhouse Coopers Auditores Independentes from January to March of 2003, and Ernst & Young Auditores Independentes S/S from March 2003 until December 31, 2003 and during the fiscal years ended December 31, 2003 and 2004:
Audit Fees
Audit-Related Fees
Total Fees
“Audit Fees” are the aggregate fees billed by Ernst & Young Auditores Independentes S/S and Pricewaterhouse Coopers Auditores Independentes for the audit of PIFCo’s consolidated and annual financial statements, reviews of interim financial statements and attestation services that are provided in connection with statutory and regulatory filings or engagements. Fees disclosed under the category “Audit-Related Fees” are mainly related to services provided in connection with the issuance of PIFCo’s notes in the international capital markets and its exports prepayment program.
Audit Committee Approval Policies and Procedures
Our audit committee has the authority to recommend pre-approval policies and procedures to our Board of Directors for the engagement of our or PIFCo’s independent auditor for services. At present, our Board of Directors has not established such pre-approval policies and procedures. Our Board of Directors expressly approves on a case-by-case basis any engagement of our independent auditors for all services provided to our subsidiaries or to us. Our bylaws prohibit our independent auditor from providing any consulting services to our subsidiaries or to us during the term of such auditor’s contract.
During the fiscal year ended December 31, 2004, neither any “affiliated purchaser,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act, nor we have purchased any of our equity securities.
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See pages F-2 through F-168, incorporated herein by reference.
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Description
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185
186
187
188
189
GLOSSARY OF PETROLEUM INDUSTRY TERMS
Unless the context indicates otherwise, the following terms have the meanings shown below:
“cmpd”
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Bbl
Bcf
Boe
Bpd
Cf
Km
Km2
Mbbl
Mboe
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191
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant hereby certifies that it meets all the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Rio de Janeiro, on June 29, 2005.
/s/ JOSÉ EDUARDO DE BARROS DUTRA
Name:
José Eduardo De Barros Dutra
Title:
/s/ JOSÉ SÉRGIO GABRIELLI DE AZEVEDO
José Sérgio Gabrielli de Azevedo
192
Petrobras International Finance Company - PIFCo
/s/ ALMIR GUILHERME BARBASSA
/s/ DANIEL LIMA DE OLIVEIRA
193
PETRÓLEO BRASILEIRO S.A.– PETROBRAS AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
Contents
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Shareholders’ Equity
Notes to the Consolidated Financial Statements
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Supplementary Information on Oil and Gas Exploration and Production
PETROBRAS INTERNATIONAL FINANCE COMPANY
AND SUBSIDIARIES
(A wholly-owned subsidiary of PETRÓLEO BRASILEIRO S.A. - PETROBRAS)
FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002
Audited Financial Statements
Consolidated Statements of Operations
Consolidated Statements of Changes in Stockholder’s Equity
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PETRÓLEO BRASILEIRO S.A. – PETROBRAS
We have audited the accompanying consolidated balance sheets of PETRÓLEO BRASILEIRO S.A. – PETROBRAS and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in shareholders’ equity and cash flows, for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PETRÓLEO BRASILEIRO S.A. – PETROBRAS and its subsidiaries as of December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
F-2
As discussed in Note 3, the Company made the following accounting changes: Effective December 31, 2004 the Company adopted a new actuarial methodology respective to the calculation of the Accumulated Benefit Obligation under FAS 87. Effective January 1, 2003, the Company adopted SFAS No. 143 – Accounting for Asset Retirement Obligation (“SFAS 143”). Additionally, at December 31, 2003 the Company adopted FIN 46 “Consolidation of Variable Interest Entities”.
ERNST & YOUNG
Auditores Independentes S/S
Paulo José Machado
Partner
Rio de Janeiro, Brazil
May 13, 2005
F-3
Report of Independent Registered
Public Accounting Firm
To the Board of Directors and Stockholders
In our opinion, the accompanying consolidated statement of income, of cash flows and of changes in stockholders’ equity for the year ended December 31, 2002 present fairly, in all material respects, the results of operations and cash flows of Petróleo Brasileiro S.A.—PETROBRAS and its subsidiaries for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
February 13, 2003
PricewaterhouseCoopers
Auditores Independentes
F-4
PETRÓLEO BRASILEIRO S.A. - PETROBRAS
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2003
Expressed in Millions of United States Dollars
Current assets
Cash and cash equivalents (Note 5)
Marketable securities (Note 6)
Accounts receivable, net (Note 7)
Inventories (Note 8)
Deferred income tax (Note 4)
Recoverable taxes (Note 9)
Property, plant and equipment, net (Note 10)
Investments in non-consolidated companies and other investments (Note 11)
Other assets
Petroleum and Alcohol account – Receivable from Federal Government (Note 12)
Restricted deposits for legal proceedings and guarantees (Note 21 (a))
Goodwill (Note 20)
Fair value asset of gas hedge (Note 23)
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Liabilities and shareholders’ equity
Current liabilities
Income tax
Taxes payable, other than income taxes
Short-term debt (Note 13)
Current portion of long-term debt (Note 13)
Current portion of project financings (Note 15)
Current portion of capital lease obligations (Note 1 6)
Accrued interest
Dividends and interest on capital payable (Note 19)
Contingencies (Note 21)
Employees’ postretirement benefits obligation - Pension (Note 18)
Other payables and accruals
Long-term debt (Note 13)
Project financings (Note 15)
Employees’ postretirement benefits obligation - Pension (Note 1 8)
Employees’ postretirement benefits obligation - Health care (Note 18)
Capital lease obligations (Note 16)
Provision for abandonment of wells (Note 3 (a))
Thermoelectric liabilities (Note 3 (b))
Deferred purchase incentive (Note 23)
Shares authorized and issued (Note 19)
Preferred share - 2004 and 2003 – 462,369,507 shares
Common share - 2004 and 2003 – 634,168 ,418 shares
Capital reserve (Note 19)
Retained earnings
Appropriated (Note 19)
Unappropriated
Accumulated other comprehensive income
Cumulative translation adjustments
Amounts not recognized as net periodic pension cost, net of tax (Note 18)
Unrealized gains (losses) on securities, net of tax
Total liabilities and shareholders’ equity
F-6
CONSOLIDATED STATEMENTS OF INCOME
Expressed in Millions of United States Dollars (except number of shares and earnings per share)
Less:
Contribution of intervention in the economic domain charge - CIDE
Impairment (Note 10 (b))
Equity in results of non-consolidated companies (Note 11)
Financial income (Note 14)
Financial expenses (Note 14)
Monetary and exchange variation on monetary assets and liabilities, net (Note 14)
Income before income taxes, minority interest and accounting change
F-7
CONSOLIDATED STATEMENTS OF INCOME (Continued)
Income tax expense (Note 4)
Minority interest in results of consolidated subsidiaries
Cumulative effect of change in accounting principle, net of taxes (Note 3 (a))
Net income applicable to each class of shares
Basic and diluted earnings per share (Note 19 (c))
Common/ADS and Preferred/ADS
Before effect of change in accounting principle
After effect of change in accounting principle
Weighted average number of shares outstanding
F-8
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
Cash flows from operating activities
Adjustments to reconcile net income to net cash provided by operating activities
Dry hole costs
Loss on property, plant and equipment
Minority interest in loss (income) of subsidiaries
Amortization of deferred purchase incentive
Deferred income taxes
Foreign exchange and monetary loss (gain)
Accretion expense – asset retirement obligation
Provision for uncollectible accounts
Cumulative effect of change in accounting principle, net of
taxes
Equity in the results of non-consolidated companies
Financial income on mark to market of gas hedge
Decrease (increase) in assets
Petroleum and Alcohol account
Interest receivable on government securities
Increase (decrease) in liabilities
Income taxes payable
Employee postretirement benefits, net of unrecognized
pension obligation
Contingencies
Abandonment
Net cash provided by operating activities
F-9
Cash flows from investing activities
Additions to property, plant and equipment
Investment in Perez Companc S.A. – PEPSA
Investments in thermoelectric plants
Investment in non-consolidated companies
Liquigás Distribuidora S.A. acquisition (Note 20)
Dividends received from non-consolidated companies
Restricted deposits for legal proceedings
Effect on cash from merger with PEPSA
Effect on cash of FIN 46 adoption
Net cash used in investing activities
Cash flows from financing activities
Short-term debt, net issuances and repayments
Proceeds from issuance of long-term debt
Principal payments of long-term debt
Proceeds from project financings
Payments of project financings
Payment of financings lease obligations
Net cash provided by (used) in financing activities
Increase (decrease) in cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplemental cash flow information:
Cash paid during the year for
Interest, net of amount capitalized
Income taxes
Withholding income tax on financial investments
Non-cash investing and financing transactions during the year
Project financings expenditures funded by special purpose companies
Transfer of Government securities to PETROS
Consolidation of merchant type thermoelectrics
Exchange of BR shares for PETROBRAS preferred shares
Recognition of asset retirement obligation – FAS 143
Consummation of gas hedge asset with deferred purchase incentive liability
F-10
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Expressed in Millions of United States Dollars (except per-share amounts)
Preferred shares
Balance at January 1
Capital increase with issue of preferred shares
Capital increase with undistributed earnings reserve
Balance at December 31
Common shares
Capital reserve – fiscal incentive
Transfer from (to) unappropriated retained earnings
Change in the year
Amounts not recognized as net periodic pension cost
(Increase) decrease in additional minimum liability
Tax effect on above
F-11
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (Continued)
Unrecognized gains (losses) on securities
Unrealized gains (losses)
Appropriated retained earnings
Legal reserve
Transfer from (to) unappropriated retained earnings, net of gain or loss on translation
Undistributed earnings reserve
Capital increase
Transfer from unappropriated retained earnings, net of gain or loss on translation
F-12
Statutory reserve
Total appropriated retained earnings
Unappropriated retained earnings
Dividends reclasification (Note 19 b)
Dividends (per share: 2004 - US $1.68 to common and preferred shares; 2003 - US $1.49 to common and preferred shares; 2002 - US $1.19 to common and preferred shares)
Appropriation (to) from fiscal incentive reserve
Appropriation to reserves
Total shareholders’ equity
Comprehensive income (loss) is comprised as follows:
Unrealized gain on available-for-sale securities
Total comprehensive income (loss)
F-13
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(except when specifically indicated)
PETRÓLEO BRASILEIRO S.A. - PETROBRAS is Brazil’s national oil company and, directly or through its subsidiaries (collectively, “PETROBRAS” or the “Company”), is engaged in the exploration, exploitation and production of oil from reservoir wells, shale and other rocks, and in the refining, processing, trade and transport of oil and oil derivatives, natural gas and other fluid hydrocarbons, in addition to other energy related activities. Additionally, PETROBRAS may promote the research, development, production, transport, distribution and marketing of all sectors of energy, as well as other related or similar activities.
PETROBRAS was incorporated under Law No. 2,004 on October 3, 1953. Until November of 1995, PETROBRAS was the exclusive agent of the Brazilian Federal Government (the “Federal Government”) for purposes of exploiting the Federal Government’s constitutional and statutory control over activities involving exploration, production, refining, distribution, import, export, marketing and transportation of hydrocarbons and oil products in Brazil and its continental waters. When adopted in 1953, the relevant provisions of the Brazilian constitution and statutory law gave the Federal Government a monopoly in these areas subject only to the right of companies then engaged in oil refining and the distribution of oil and oil products to continue those activities in Brazil. Therefore, except for limited competition from those companies in their grandfathered activities, PETROBRAS had a monopoly over its businesses for approximately 42 years. As a result of a change in the Brazilian constitution in November of 1995, and the subsequent and ongoing implementation of that change, PETROBRAS has ceased to be the Federal Government’s exclusive agent in Brazil’s hydrocarbons sector and up to 2001 had been operating in an environment of gradual deregulation and increasing competition.
In accordance with Law No. 9,478 (“Petroleum Law”) and Law No. 9,990, dated August 6, 1997 and July 21, 2000, respectively, the fuel market in Brazil was totally liberalized beginning January 1, 2002 permitting other companies to produce and sell on the domestic market, and also to import and export oil products.
The Company also has oil and gas operations in international locations, with the most significant international operations being in other Latin American countries.
F-14
In preparing these consolidated financial statements, the Company has followed accounting policies that are in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these financial statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto.
Estimates adopted by management include: oil and gas reserves, pension and health care liabilities, environmental obligations, depreciation, depletion and amortization, abandonment costs, contingencies and income taxes. While the Company uses its best estimates and judgments, actual results could differ from those estimates as future confirming events occur.
The accompanying consolidated financial statements of PETRÓLEO BRASILEIRO S.A. - PETROBRAS (the Company) have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) and the rules and regulations of the Securities and Exchange Commission (SEC). U.S. GAAP differs in certain respects from Brazilian accounting practice as applied by PETROBRAS in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the Brazilian Securities Commission (CVM).
The U.S. dollar amounts for the years presented have been translated from the Brazilian Real amounts in accordance with Statement of Financial Accounting Standards SFAS No. 52 - Foreign Currency Translation (“SFAS 52”) as applicable to entities operating in non-hyperinflationary economies. Transactions occurring in foreign currencies are first remeasured to the Brazilian Real and then translated to the U.S. dollar, with remeasurement gains and losses being recognized in the statements of income. While PETROBRAS has selected the U.S. Dollar as its reporting currency, the functional currency of PETROBRAS and all Brazilian subsidiaries is the Brazilian Real. The functional currency of PIFCo and certain of the special purpose companies is the U.S. dollar, and the functional currency of PEPSA is the Argentine Peso.
F-15
The Company has translated all assets and liabilities into U.S. dollars at the current exchange rate (R $2.6544 and R $2.8892 to US $1.00 at December 31, 2004 and 2003, respectively), and all accounts in the statements of income and cash flows (including amounts relative to local currency indexation and exchange variances on assets and liabilities denominated in foreign currency) at the average rates prevailing during the year. The net translation gain/ (loss) in the amount of US $1,911 in 2004 (2003 - US $2,856 and 2002 - US $(5,452)) resulting from this remeasurement process was excluded from income and presented as a cumulative translation adjustment (“CTA”) within Other Comprehensive Income in the statement of changes in shareholders’ equity.
The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries in which (a) the Company directly or indirectly has either a majority of the equity of the subsidiary or otherwise has management control, or (b) the Company has determined itself to be the primary beneficiary of a variable interest entity in accordance with FIN 46 (Note 3(b)). Intercompany accounts and transactions are eliminated.
F-16
The following majority-owned subsidiaries and variable interest entities are consolidated:
Subsidiary companies
Activity
F-17
Cash equivalents consist of highly liquid investments that are readily convertible into cash and have an original maturity of three months or less at date of acquisition.
(d) Marketable securities
Marketable securities are accounted for under SFAS No. 115 - Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”) and have been classified by the Company as available for sale or trading based upon intended strategies with respect to such securities. The marketable securities classified as trading are short term in nature as the investments are expected to be liquidated, sold, or used for current cash requirements. The marketable securities classified as available for sale are long term in nature as the investments are not expected to be sold or otherwise liquidated in the next twelve months.
F-18
Trading securities are marked to market through current period earnings, available for sale securities are marked to market through other comprehensive income, and held to maturity securities are recorded at historical cost.
The Company has maintained junior trust notes received in connection with the structured finance program as held to maturity, and additionally has certain available for sale investments in companies with publicly traded shares. The Company also has available for sale and trading securities arising from its consolidation of investments in an exclusive fund.
Accounts receivable is stated at estimated realizable values. An allowance for doubtful accounts is provided in an amount considered by management to be sufficient to meet probable future losses related to uncollectible accounts.
Inventories are stated as follows:
The Company uses the equity method of accounting for all long-term investments for which it owns between 20% and 50% of the investee’s outstanding voting stock or has the ability to exercise significant influence over operating and financial policies of the investee. The equity method requires periodic adjustments to the investment account to recognize the Company’s proportionate share in the investee’s results, reduced by receipt of investee’s dividends.
F-19
The Company holds National Treasury Bonds “Series B” (NTN-B) issued by the Federal Government which are accounted for as available-for-sale securities in accordance with SFAS 115.
The costs incurred in connection with the exploration, development and production of oil and gas are recorded in accordance with the “successful efforts” method. This method requires that costs the Company incurs in connection with the drilling of developmental wells and facilities in proved reserve production areas and successful exploratory wells be capitalized. In addition, costs the Company incurs in connection with geological and geophysical activities are charged to the results of operations in the period incurred, and the costs relating to exploratory dry wells on unproven reserve properties are charged to the results of operations when determined as dry or uneconomical.
The capitalized costs are depreciated based on the unit-of-production method using proved developed reserves. These reserves are estimated by the Company’s geologists and petroleum engineers in accordance with international industry standards and are reviewed annually, or more frequently when there are indications of significant changes in the Company’s reserves.
Costs of acquiring developed or undeveloped leaseholds including lease bonus, brokerage, and other fees are capitalized. The costs of undeveloped properties that become productive are transferred to a producing property account.
F-20
Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to assure that commercial quantities of reserves have been found or that additional exploration work is underway or planned. Exploratory costs related to areas where commercial quantities have been found are capitalized, and exploratory costs where additional work is underway or planned continue to be capitalized pending final evaluation. Exploratory well costs not meeting either of these tests are charged to expense. All other exploratory costs (including geological and geophysical costs) are expensed as incurred. Exploratory dry holes are expensed.
Costs of development wells including dry holes, platforms, well equipment and attendant production facilities are capitalized.
Costs incurred with producing wells are expensed as incurred.
Through December 31, 2002, the Company recorded abandonment costs in accordance with SFAS No. 19 - Financial Accounting and Reporting by Oil and Gas Production Companies (“SFAS 19”). Under SFAS 19, the estimated costs of dismantlement and removal of oil and gas related facilities are accrued over the properties’ production lives using the unit-of-production method and recognized as accumulated depreciation, depletion and amortization as the expense is recorded. Effective January 1, 2003, the Company adopted SFAS No. 143 - Accounting for Asset Retirement Obligations (“SFAS 143”) for abandonment costs (see Note 3(a) for information related to the new accounting policy for abandonment costs commencing from January 1, 2003).
F-21
In 2004, the Company reviewed and revised its 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 US $196 with a gain recognized in net income, and recorded in the line titled exploratory costs for oil and gas exploration.
Depreciation, depletion and amortization of leasehold costs of producing properties are recorded using the unit-of-production method applied on a field by field basis as a ratio of proved reserves produced. Leased production platforms are depreciated on a straight-line basis over the estimated useful lives of the platforms. Depreciation, depletion and amortization of all other capitalized costs (both tangible and intangible) of proved oil and gas producing properties are recorded using the unit-of-production method applied on a field by field basis as a ratio of proved developed reserves produced. Prior to January 1, 2003, estimated dismantlement, restoration and abandonment costs and estimated salvage values were taken into account in determining amortization and depreciation provisions.
Other plant and equipment are depreciated on a straight-line basis over the following estimated useful lives:
Building and improvements
Equipment and other assets
Platforms
F-22
In accordance with SFAS No. 144 - Impairment of Long-Lived Assets (“SFAS 144”), management reviews long-lived assets, primarily property, plant and equipment to be used in the business and capitalized costs relating to oil and gas producing activities, whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable on the bases of undiscounted future cash flows. The reviews are carried out at the lowest level of assets to which the Company is able to attribute identifiable future cash flows. The net book value of the underlying assets is adjusted to their fair value using a discounted future cash flows model, if the sum of the expected undiscounted future cash flows is less than the book value. Maintenance and repairs
The actual costs of major maintenance, including turnarounds at refineries and vessels, as well as other expenditures for maintenance and repairs, are expensed as incurred.
Interest is capitalized in accordance with SFAS No. 34 - Capitalization of Interest Cost (“SFAS 34”). Interest is capitalized on specific projects when a construction process involves considerable time and involves major capital expenditures. Capitalized interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. Interest is capitalized at the Company’s weighted average cost of borrowings.
Revenues from sales of crude oil and oil products, petrochemical products and others are recognized on an accrual basis when the title is transferred to the customer. Revenues from sales of natural gas are accounted for when the natural gas is transferred to the customer. Subsequent adjustments to revenues based on production sharing agreements or volumetric delivery differences are not significant. Costs and expenses are accounted for on an accrual basis.
F-23
The Company accounts for income taxes in accordance with SFAS No. 109 - Accounting for Income Taxes (“SFAS 109”), which requires an asset and liability approach to recording current and deferred taxes. The effects of differences between the tax bases of assets and liabilities and the amounts recognized in the financial statements have been treated as temporary differences for the purpose of recording deferred income taxes.
The Company records the tax benefit of all net operating losses as a deferred tax asset and recognizes a valuation allowance for any part of this benefit which management believes will not be recovered against future taxable income using a “more likely than not” criterion.
The Company sponsors a contributory defined-benefit pension plan covering substantially all of its employees, which is accounted for by the Company in accordance with SFAS No. 87 - Employers’ Accounting for Pensions (“SFAS 87”).
In addition, the Company provides certain health care benefits for retired employees and their dependents. The cost of such benefits is recognized in accordance with SFAS No. 106 - Postretirement Benefits Other Than Pensions (“SFAS 106”).
On December 23, 2003 the Financial Accounting Standards Board released revised FASB Statement No. 132-R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“SFAS No. 132-R”). The revised standard provides additional required disclosures for pensions and other postretirement benefit plans and is designed to improve disclosure transparency in financial statements. The revised standard replaces existing pension disclosure requirements. The requirements of the standard are effective for public entities for fiscal years ending after December 15, 2003. The adoption of SFAS No. 132-R did not have a material impact on the Company’s consolidated financial statements.
F-24
The Company also contributes to the national pension, social security and redundancy plans at rates based on payroll, and such contributions are expensed as incurred. Further indemnities may be payable upon involuntary severance of employees but, based on current operating plans, management does not believe that any amounts payable under this plan will be significant.
PEPSA sponsors a defined contribution plan, the funding of which is recognized in accordance with the accrual method of accounting. PEPSA’s defined contribution plan is presently suspended. PEPSA also sponsors a defined benefit plan in which the employees’ benefit is based on the last computable salary in the years of service of the employee. For purposes of determining the estimated cost of benefit pension plans granted to employees, the Company has used actuarial calculation methods, making estimates with respect to the applicable demographic and financial variables.
Environmental and remediation costs relating to current operations are expensed or capitalized, as appropriate, depending on whether such costs are expected to provide future economic benefits. Liabilities are recognized when the costs are considered probable and can be reasonably estimated.
F-25
As provided in the Petroleum Law, the fuel market in Brazil was totally liberalized as of January 1, 2002 permitting other companies to produce and sell on the domestic market and, also, import and export oil products. Additionally, as from January 1, 2002, PETROBRAS is no longer required to charge the prices established by the Federal 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 from January 1, 2002, the Petroleum and Alcohol Account will no longer be used to reimburse expenses related to the supply of oil products and fuel alcohol to PETROBRAS 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 (“ANP”) with no impact on the income statement and (ii) adjustments resulting from the audit of the account by the ANP.
The impact of Federal Government regulation on the Company’s balance sheet and operating structure has been recorded in the Petroleum and Alcohol Account as of, and for the years ended, December 31, 2004 and 2003 (see Note 12).
The Contribuição de Intervenção no Domínio Econômico (Contribution of Intervention in the Economic Domain Charge - CIDE) on the importation and sale of fuels was established by Law No. 10,336 dated December 19, 2001.
The CIDE is a per-transaction payment to the Brazilian Government required to be made 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.
F-26
The liability for future compensation of employees for vacations is accrued as earned.
Earnings per share are computed using the two-class method, which is an earnings allocation formula that determines earnings per share for both preferred shares, which are participating securities and common shares. The preferred shares participate in dividends and undistributed earnings with the common shares at a predetermined formula. Such formula allocates the net income, as if all of the net income for each year had been distributed, first to the preferred shares in an amount equal to the preferred shares’ priority minimum annual dividend of the higher of 3% of their shareholders equity or 5% of their paid-in capital as stated in the statutory accounting records, then to common shares in an amount equal to the preferred shares’ priority dividend on a per share basis and any remaining net income is allocated equally to the common and preferred shares. Each American Depositary Share (ADS) for common shares represents one share of the Company’s common shares or one share of the Company’s preferred shares and, in each case, is presented together with earnings per share.
Research and development costs are charged to expense when incurred.
The Company adopted SFAS No. 133 – Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), as amended by SFAS No. 138 – Accounting for Certain Derivative Instruments and Certain Hedging Activities (“SFAS 138”). SFAS 133 requires that all derivative instruments be recorded in the balance sheet of the Company as either an asset or a liability measured at fair value. SFAS 133 requires that changes in the derivative’s fair value be recognized in earnings/losses unless specific hedge accounting criteria is met. For derivatives accounted for as hedges, fair value adjustments are recorded to earnings/losses or other comprehensive income, a component of shareholders’ equity, depending upon the type of hedge and the degree of hedge effectiveness.
F-27
The Company may use derivative financial instruments to mitigate the risk of unfavorable price movements on crude oil purchases. These instruments are marked-to-market on a current basis and associated gains and losses are recognized currently in the financial income/ expense line items.
The Company may also use derivative financial instruments to mitigate the risk of unfavorable exchange-rate movements affecting its foreign currency-denominated indebtedness. Gains and losses from changes in the fair value of these contracts are recognized as financial income or financial expense.
PEPSA also uses derivative instruments such as swaps, options, futures, and other instruments, principally to mitigate the impact of changes in crude oil prices, exchange rates and interest rates. PEPSA’s crude oil derivative instruments and interest rate swap instruments are designed to mitigate specific exposures and thus qualify as cash flow hedges under SFAS 133.
As cash flow hedges, the gains and losses associated with the derivative instruments are deferred and recorded in other comprehensive income until the underlying hedge transaction impacts earnings, with the exception of any ineffective portions. Derivative instruments not qualifying for hedge accounting are marked-to-market through earning on a current basis.
FASB has recently issued (i) SFAS No. 151, “Inventory Costs, an amendment of ARB Nº 43, Chapter 4”, “Inventory Pricing”, (“SFAS 151”) in November of 2004, (ii) FASB Statement No. m123R, “Share-Based Payment” (“SFAS 123R”) in December of 2004, (iii) FASB Statement No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29” (“SFAS 153”) in December of 2004 and (iv) FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, in March of 2005.
F-28
SFAS 151 will be effective for the Company on January 1, 2006. The standard amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, the standard requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The Company is currently evaluating the impact of this standard.
SFAS 123R requires that compensation costs relating to share-based payments be recognized in the Company’s financial statements. Petrobras Energia S.A.-PEPSA, member of PETROBRAS’ System currently accounts for those payments under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company is preparing to implement this standard effective on July 1, 2005. Although the transition method to be used to adopt the standard has not been selected, such adoption is expected to have a minimal impact on the Company’s results of operations, financial position and liquidity.
SFAS 153 will be effective for the Company for asset-exchange transactions beginning on July 1, 2005. Under APB No. 29, assets received in certain types of non-monetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by SFAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, the Company has not engaged in a large number of non-monetary asset exchanges for significant amounts, and thus does not expect a material impact upon adoption.
FIN 47 clarifies the term “conditional asset retirement obligation” as used SFAS 143 in order to avoid diversity in accounting practice with respect to the effect of uncertainties about the timing and (or) method of settlement that are conditional on a future event, when recognizing the fair value of a liability for an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company does not expect that the adoption of FIN 47 will have a material effect on the Company’s financial position or results from operations when it becomes effective on December 31, 2005.
The FASB has also adopted on April 4, 2005, the FASB Staff Position (FSP SFAS 19-1) (that amends SFAS 19 to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves that justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the viability of the project. The guidance in FSP SFAS 19-1 shall be applied prospectively in the third quarter of 2005 and the Company does not expect that it will have a material effect on the Company’s financial position or results from operations (see Note 27 for information related to the accounting policy currently practiced by the Company with respect to suspended exploratory wells).
F-29
During the first quarter of 2005, the Securities and Exchange Commission (SEC) requested Oil & Gas registrants to disclosure certain information related to the accounting for buy/sell contracts in their filings that include financial reports covering periods ending on or after December 15, 2004. These transactions, which are not part of PETROBRAS’ operations, typically involve contractual arrangements that establish the terms of the buy and sell agreements either jointly, in a single contract, or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single counterparty. The topic is under deliberation by the Emerging Issues Task Force (EITF) of the FASB as Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”.
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.
As of January 1, 2003, PETROBRAS adopted SFAS No. 143 - Accounting for Asset Retirement Obligations (“SFAS 143”). The primary impact of SFAS 143 is to change the method of accruing for upstream site restoration costs.
Under SFAS 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the related assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations and depreciated over the related useful lives of such assets. Over time, the amounts recognized as liabilities will be accreted for the change in their present value until the related assets are retired or sold.
F-30
The cumulative adjustment for the change in accounting principle reported in the first quarter of 2003 was an after-tax income of US $697 (net of US $359 deferred income tax effects). The effect of this accounting change on the balance sheet, was a US $1,056 reduction to the abandonment provision, and a US $359 increase in deferred income tax liabilities, see Note 4. Additionally, the change in accounting principle resulted in a US $16 increase to property, plant and equipment at original asset acquisition date, with accumulated depreciation through January 1, 2003 of US $9 on proved developed properties. Further, on January 1, 2003, PETROBRAS established an abandonment liability with respect to proved undeveloped reserves in the amount of US $44.
This adjustment is due to the difference in the method of accruing site restoration costs under SFAS 143 compared with the method required by SFAS 19. Under SFAS 19, site restoration costs are accrued on a unit-of-production basis of accounting as the oil and gas are produced. The SFAS 19 method matches the accruals with the revenues generated from production and results in most of the costs being accrued in early field life, when production is at the highest level. Because SFAS 143 requires accretion of the liability as a result of the passage of time using an effective interest method of allocation, a significant portion of costs will be accrued towards the end of field life, when production is at the lowest level. The cumulative income adjustment described above results from reversing the higher liability accumulated under SFAS 19 in order to adjust it to the lower present value amount resulting from transition to SFAS 143. This amount being reversed in transition, which was previously charged to operating earnings under SFAS 19, will again be charged to earnings under SFAS 143 in future years.
Measurement of assets retirement obligations is based on currently enacted laws and regulations, existing technology and site-specific costs. There are no assets legally restricted to be used in the settlement of asset retirement obligations.
F-31
A summary of the annual changes in the abandonment provision is presented as follows:
Balance as of December 31, 2002
Reversion of provision
Assets related to proved developed property
Accumulated depreciation
Assets related to proved undeveloped property
Balance as of January 1, 2003
PEPSA acquisition
Depreciation and impairment
Accretion expenses
Liabilities incurred
Liabilities settled
Cumulative translation adjustment
Balance as of December 31, 2003
Revision of provision (Note 2 (i))
Balance as of December 31, 2004
F-32
The following unaudited pro-forma summary financial information presents the consolidated results of operations as if the adoption of SFAS 143 had occurred at the beginning of 2002.
Impairment
Income tax expense
Basic and diluted earnings per share
The Financial Accounting Standards Board (FASB) issued Interpretation No. 46 (FIN 46) - Consolidation of Variable Interest Entities in January of 2003. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities disclosed by enterprises that do not control them through a majority voting interest. Under FIN 46, entities are required to be consolidated by an enterprise that has a controlling financial interest in such entities when equity investors of that enterprise do not have significant capital risk, the obligation to absorb the majority of expected losses, or the right to receive the majority of expected returns from such entities. Entities identified with these characteristics are called variable interest entities and the interest that enterprises have in these entities are called variable interests. These interests may derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards to the enterprise with the controlling financing interest in such entities, irrespective of such enterprises’ voting interest in such entities.
F-33
The interpretation requires that if a business enterprise has a controlling financial interest in a variable entity, the assets, liabilities and results of the activities of the variable interest entity must be included in the consolidated financial statements with those of the business enterprise. This interpretation was applied immediately to variable interest entities created after January 31, 2003. For variable interests in special purpose entities created before February 1, 2003, FIN 46 was adopted at December 31, 2003. For variable interest in operating entities, FIN 46 was required to be adopted in the first quarter of 2004.
The Company adopted FIN 46 in its December 31, 2003 annual financial statements. Such adoption resulted in the consolidation of a number of special purpose entities related to project financings arrangements in which the Company has an interest, and which were deemed to be variable interest entities for which the Company was the primary beneficiary. These entities are detailed above in Note 2 (b). Prior to adoption of FIN 46, a significant portion of the Company’s share of commitments and debt obligations, as well as fixed asset contributions, were already included in the consolidated financial statements as the project financings transactions qualified as capital leases.
Thus, adoption of FIN 46 related to the special purpose companies formed in connection with project financings arrangements did not have a significant impact on the Company’s financial condition. While PETROBRAS does not have specific assets set aside and established as collateral for these special purpose entities, the Company does have certain contractual obligations relating to the debt of the special purpose entities.
Three thermoelectric plants were also consolidated at December 31, 2003 as a result of the adoption of FIN 46. However, as these thermoelectric plants had previously been accounted for as capital leases, their consolidation did not have a material impact on the Company’s financial condition.
F-34
Furthermore, PETROBRAS has determined that it is the primary beneficiary of three additional plants for which it has certain contractual obligations to bear energy market risk. The effect of the consolidation of these three thermoelectrics was an increase in fixed assets of US $1,095 as of December 31, 2004 (US $1,142 as of December 31, 2003) and an increase in liabilities US $1,095 as of December 31, 2004 (US $1,142 as of December 31, 2003). Results of operations for these companies were consolidated beginning January 1, 2004, and generated a net loss during the year ended December 31, 2004 in the amount of US $490. See also Note 15 and Note 17.
PETROBRAS has also indentified two exclusive investment funds which require consolidation. See additional discussion at Note 6.
The Company has determined that it has no variable interests in operating entities and thus has not consolidated additional entities as variable interests in 2004.
On December 31, 2004 the Company adopted a new actuarial methodology regarding the calculation of Accumulated Benefit Obligation (ABO), by excluding the effects of long term inflation. In the past, the Company had applied a terminal methodology in the calculation of its ABO, an approach permitted under EITF 88-1, but at December 31, 2004 elected a change in methodology to a going concern calculation of the ABO, a more preferable application of principle per EITF 88-1. The change in accounting principle application did not effect net income, and while the ABO increased from 2003 to 2004, the change in methodology resulted in a reduction of the ABO in the approximate amount of US $1,142 over that which would have been calculated under the former methodology and effected both the liability balance and amount not recognized in the shareholders equity. There was no income statement impact of this change in accounting principle.
F-35
Income taxes in Brazil comprise federal income tax and social contribution, which is an additional federal income tax. The statutorily enacted tax rates have been 25% and 9%, respectively for the years ended December 31, 2004, 2003 and 2002.
Substantially all of the Company’s taxable income is generated in Brazil and is therefore subject to the Brazilian statutory tax rate. The following table reconciles the tax calculated based upon statutory tax rates to the income tax expense recorded in these consolidated financial statements.
Income before income taxes, minority interest and accounting changes
Tax expense at statutory rates
Adjustments to derive effective tax rate:
Non-deductible postretirement health-benefits
Change in valuation allowance
Tax benefit on interest on shareholders’ equity
Income taxes regarding abandonment liabilities adjustments related to the year ended December 31, 2002
Income tax expense per consolidated statement of income
TBG, a subsidiary of GASPETRO, has accumulated tax loss and negative income tax and social contribution carryforwards amounting to US $450 as of December 31, 2004 (US $469 in 2003), which could be offset against future taxable income to a limit of 30% of annual income, based on Law No. 9,249/95, which in the opinion of the TBG management, will occur within the useful life of the Bolivia-Brazil Gas Pipeline project.
F-36
However, considering the long estimated term for utilization, these tax credits, totaling US $153 (US $159 - 2003), were provided for in a valuation allowance in the consolidated financial statements for December 31, 2004 and 2003. The accounting recognition of these credits is reviewed annually.
PEPSA also has tax credits amounting to US $551 as of December 31, 2004 (US $590 in 2003), which could be offset against future taxable income and, for which a valuation allowance is recognized in the consolidated financial statements for December 31, 2004 and 2003. These tax losses carryforward have been generated mainly due to operating losses occurred during the Argentinean crisis on 2001 and 2002 and the valuation allowance recognized is related to uncertainties regarding the recovery of the Argentinean economy and its impact on the financial instruments transacted by PEPSA. The recoverability of the above mentioned tax credits is assessed annually by PEPSA’s management in light of the business plan elaborated for the year.
F-37
The major components of the deferred income tax accounts in the consolidated balance sheet are as follows:
Current Assets
Lease obligations
Provision for profit sharing
Property, plant and equipment
Derivatives
PETROS
Other temporary differences
Current Liabilities
Net current deferred tax assets
Non-current
Employees’ postretirement benefits, net of unrecognized pension obligation
Interest on shareholder’s equity
Deferred assets
Tax loss carryforwards
Investments
Inventory revaluation
Allowance for doubtful accounts
Provision for contingencies
Provision for notification from INSS
Other temporary differences, not significant individually
Valuation allowance
Capitalized exploration and development costs
Tax effect on unrealized loss on investments available-for-sale
Net long-term deferred tax liabilities
F-38
As of December 31, 2003, the “Tax loss carryforwards” amounted US $69, net of valuation allowance amounting US $695. As of December 31, 2004 the Company reclassified this amount and elected to present both the line item “Tax loss carryforwards” and the line item “Valuation Allowance” on a gross basis.
Although realization of net deferred tax assets is not assured, management believes that, except where a valuation allowance has been provided, such realization is more likely than not to occur. The amount of the deferred tax asset considered realizable could, however, be reduced if estimates of future taxable income are reduced. Tax loss carryforwards do not expire and are available for offset against future taxable income, limited to 30% of taxable income in any individual year for Brazilian companies. PEPSA tax loss carryforward principally expire in years beyond 2008, and may be offset against future taxable income without limitation. The following presents the changes in the valuation allowance for the years ended December 31, 2004, 2003 and 2002:
Year ended December 31, -%
Balance at January 1,
Reductions (additions)
Acquisition of Perez Companc S.A. – PEPSA
Balance at December 31,
Cash
Investments - Brazilian reais
Investments - U.S. dollars
F-39
Cash and cash equivalents include US $858 at December 31, 2004 (US $1,049 in 2003), as a result of incorporation of certain special purpose entities pursuant to the FIN 46 consolidation. See Note 15 relating to Project financings. See Note 6 respective to reclasses related to 2003 from cash equivalents to marketable securities.
Marketable security classification:
Available for sale
Trading
Held-to-maturity
Less: Current portion of marketable securities
Long-term portion of marketable securities
Marketable securities are comprised primarily of amounts the Company has invested in the exclusive fund, absent the Company’s own securities, which are considered repurchased. The exclusive fund is consolidated, and the equity and debt securities within the portfolio are classified as trading or available for sale under SFAS 115 based on management’s intent. Trading securities are principally Brazil bonds, which are bought and sold frequently with the objective of making margins on market price changes. Available for sale securities are principally, LCN (Credit Liquid Note) agreements and certain other bonds which the Company does not have current expectations to trade actively. The trading securities are presented as current assets, as they are expected to be used in the near term for cash funding requirements; available for sale securities are presented as other assets, as they are not expected to be sold or liquidated in the next twelve months. Amounts related to 2003, have been reclassified from cash and cash equivalents, as the exclusive funds are subject to consolidation per the requirements of FIN 46.
F-40
Accounts receivable, net consisted of the following:
Trade
Related parties (Note 26)
Less: Allowance for uncollectible accounts
Less: Long-term accounts receivable, net
Current accounts receivable, net
Allowance for uncollectible accounts
Additions
Write-offs
Allowance on short-term receivables
Allowance on long-term receivables
F-41
At December 31, 2004 and 2003, long-term receivables include US $590 and US $581 respectively relating to payments made by the Company to suppliers and subcontractors on behalf of certain contractors. These contractors had been hired by the subsidiary BRASOIL for the construction/conversion of vessels into FPSO (“Floating Production, Storage and Offloading”) and FSO (“Floating, Storage and Offloading”) and failed to make the payments to their suppliers and subcontractors. The Company made the payments to avoid further delays in the construction/conversion of the vessels and consequent losses to BRASOIL.
Based on opinions from the legal advisers of BRASOIL, these payments can be reimbursed, since they represent a right of BRASOIL with respect to the contractors, for which reason judicial action was filed with international courts to seek financial reimbursement. However, as a result of the uncertainties with regards to the probability of receiving all the amounts disbursed, the Company recorded a provision for uncollectible accounts for all credits that are not backed by collateral. The balances of this provision amounted US $518 and US $509 as of December 31, 2004 and 2003, respectively.
Products
Oil products
Raw materials, mainly crude oil
Materials and supplies
At December 31, 2004 and 2003, there were no inventories requiring an obsolescence provision.
F-42
Recoverable taxes consisted of the following:
Local:
Domestic value-added tax (ICMS)
Income tax and social contribution
PASEP/COFINS (1)
Foreign value-added tax (IVA)
Other recoverable taxes
Less: Long-term recoverable taxes
Current recoverable taxes
These contributions and the domestic value-added tax (ICMS) are not cumulative and amounts paid related to these taxes in the acquisition of products and/or services can be offset when these products and services are sold, which means a tax credit is generated when the purchase is made and such credit is then offset upon sale to final customer.
The income tax and social contribution recoverable will be offset against future taxable income.
PETROBRAS plans to fully recover these taxes, and as such, no allowance has been provided.
F-43
Property, plant and equipment, at cost, are summarized as follows:
Buildings and improvements
Oil and gas assets
Capital lease – platforms and vessels
Rights and concessions
Land
Materials
Expansion projects -
Construction and installations in progress:
F-44
During 2004, the Company capitalized US $267 of interest cost (2003 - US $184; 2002 - US $139). See Note 14.
The property, plant and equipment account at December 31, 2004 and 2003, respectively, includes US $347 and US $678 of assets under construction that are intended to be sold or transferred into structured financing deals. These assets include natural gas pipelines and other oil and gas projects at 2004 and 2003. Additionally, the property, plant and equipment account at December 31, 2004 and 2003, respectively, includes US $844 and US $978 of assets under agreements with investors.
For the years ended December 31, 2004, 2003 and 2002, the Company recorded impairment charges of US $65, US $70 and US $75, respectively. During 2004, the impairment charge was related to producing properties in Brazil, principle amounts were related to the Company’s Cioba’s off-shore field (US $30). The impairment expenses recorded in 2004 were primarily due to capital expenditures made in 2004 to producing fields with only marginal reserves. During 2003, US $65 of the impairment charge was related to producing properties in Brazil, principle amounts were related to the Company’s Fazenda Belem on-shore field (US $15) in Rio Grande do Norte, and the Lamarão on-shore field (US $4) in Bahia. During 2002, US $75 of the impairment charge was related to producing properties in Brazil, primarily recorded in the Company’s Voador field (US $42) in the Campos basin, Caravelas field (US $15) in the Santos basin and Massape field (US $4) in the Reconcavo basin. These charges were recorded based upon the Company’s annual assessment of the fields using pricing and other assumptions consistent with those used in the Company’s overall strategic plan.
F-45
During 2004, the Company returned to the National Petroleum Agency - ANP the rights associated with one exploratory concession – BM-ES-9 (fully returned) and 15 exploratory concessions referring to the completion of the first exploration phase (partially returned) as established in the agreements, all in connection with “BID 3”. Of the total sixteen concessions and exploratory areas, the Company had exclusive rights over 9 (nine) concessions, and the other 7 (seven) were operated in partnership with other companies.
The rights to POT-T-655 Block, referring to BT-POT-22 Exploratory Block, “BID 5”, in which the Company was the sole concession holder, were fully returned to ANP.
Three areas - BM-C-14/BM-S-14/BM-S-22 - - explored by the Company in partnership with other companies, the concession of which was not operated by the Company, were partially returned to ANP.
The area relating to 1-RJS-144 well, originating in BC-200 block, maintained in connection with the assessment of the related discovery was returned. Considering that the Company was not interested in declaring its marketability, the area was fully returned.
Thus, total concessions returned are as follows:
F-46
In August 2004, PETROBRAS acquired 107 (one hundred and seven) new exploratory blocks out of the 154 (one hundred and fifty four) blocks included in the 6th bidding process conducted by the National Petroleum Agency - ANP. To date, the Agency offered a total of 913 blocks, of which 294 were onshore and 619 were offshore.
PETROBRAS acquired 55 blocks with exclusive rights and acquired another 52 blocks in consortium with other companies; PETROBRAS serves as operator of 32 of these blocks.
The total leasehold bonus expenditures made by PETROBRAS totaled US $165 (R $437 million). The concession agreements related to the 6th bidding round were signed on November 24, 2004.
PETROBRAS conducts portions of its business through investments in companies accounted for using the equity and cost methods. These non-consolidated companies are primarily engaged in the petrochemicals and products transportation businesses.
Equity method
20% -50%(1)
Investments available-for-sale
8% -17%
Investments at cost
F-47
At December 31, 2004 and 2003, the Company had investments in companies with publicly traded shares: BRASKEM S.A., Petroquímica União S.A. - PQU and Companhia Petroquímica do Sul S.A. - COPESUL. The Company’s investments in these companies with publicly traded shares amounts to less than 20% of the investee’s total voting shares, are classified as available for sale and have been recorded at market value. The Company has recorded unrealized gains (losses) for the difference between the fair value and the cost of the investment on these investments of US $657 and US $207 as of December 31, 2004 and 2003, respectively. These holding (losses) gains are reflected as a component of shareholder’s equity, net of tax, with changes in the unrealized balance recorded as a component of comprehensive income.
The Company also has investments in companies for the purpose of developing, constructing, operating, maintaining and exploring thermoelectric plants included in the federal government’s Priority Thermoelectric Energy Program, with equity interests of between 10% and 50%. The balance of these investments as of December 31, 2004 and 2003 includes US $119 and US $72 respectively, and are included as equity method investments due to the Company’s ability to exercise significant influence over such operations.
The Company’s investments in equity of non-consolidated companies generated equity earnings (losses) in results of non-consolidated companies of US $172 for the year ended December 31, 2004 (2003 - US $141; 2002 - US $(178)).
On August 25, 2004, PETROBRAS, through its subsidiary PETROBRAS GÁS S.A. – GASPETRO, agreed to the acquisition of 40% interest of the capital of Companhia de Gás de Minas Gerais – GASMIG, according to the Association Agreement with Companhia Energética de Minas Gerais – CEMIG, dated August 11, 2004, in order to promote natural gas consumption in the Minas Gerais State. The acquisition was approved by the Minas Gerais State Legislature through Law No. 15.404/2004, dated December 3, 2004. The operation was concluded on December 15, 2004 by GASPETRO and its subsidiary TSS Participações S.A., for US $58.
The acquisition of GASMIG was recorded using the equity method of accounting.
F-48
On October 4, 2004, through its subsidiary PETROBRAS GÁS S.A. – GASPETRO, PETROBRAS exercised the option of purchasing shares of CEG-RIO, agreed with the company GÁS NATURAL SGD, comprising 65,580 thousand common shares (9.86% of total common shares) and 181,920 thousand preferred shares (13.68% of total preferred shares), in the total amount of approximately US $16.5.
As a result of this operation, GASPETRO has increased its interest in CEG-RIO, and now holds 26.19% of its total common shares and 43.01% of its total preferred shares.
The acquisition of CEG RIO was recorded using the equity method of accounting.
In accordance with the Petroleum Law and subsequent legislation, the fuel market in Brazil was deregulated in its entirety as of January 1, 2002. Therefore, as of that date, the Petroleum and Alcohol account would no longer be used to reimburse expenses in connection with the Federal Government’s regulation of the prices of oil products and fuel alcohol. Accordingly, the Petroleum and Alcohol account will only include changes in amounts with triggering events having occurred before December 31, 2001, in accordance with Law No. 10,453, of May 13, 2002, and ANP regulations. See additional discussion at Note 2(n) respective to market regulation in Brazil.
F-49
The following summarizes the changes in the Petroleum and Alcohol account for the years ended December 31, 2004 and 2003:
Reimbursements to PETROBRAS
Reimbursements to third parties: principally subsidies paid to fuel alcohol producers
Financial income (Note 26)
Result of audit conducted by the Federal Government
Translation gain
The Federal Government certified the balance of the Petroleum and Alcohol account as of June 30, 1998.
The ANP/STN Integrated Audit Committee submitted, on June 23, 2004, its final report certifying and approving the balance of the Petroleum and Alcohol accounts for the period from July 1, 1998 to December 31, 2001, together with monetary restatement through that date. The conclusion of this audit process for the Petroleum and Alcohol account and the parties concurrence as to final amount establishes the basis for concluding the settlement process between the Federal Government and PETROBRAS.
F-50
The Company and the Federal Government reached an agreement whereby the Federal Government issued National Treasury Bonds - H (NTN-H) into a federal depositary on behalf of the Company to support the balance of the Petroleum and Alcohol account.
As of June 30, 2004, there were 138,791 National Treasury Notes – series H (NTN-H), in the amount of US $56, at which time the balance of the Petroleum and Alcohol account was US $241. On July 2, 2004, the Federal Government deposited US $56 in favor of the NTNs-H which expired on June 30, 2004, as a partial guarantee to the balance of the Petroleum and Alcohol account. Of the total amount, US $3 was made available to PETROBRAS and the remaining US $53 was deposited in an account in the Company’s name, however, such amount is restricted from use by order of 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.
As defined by Provisional Measure No. 123 dated June 26, 2003, made into Law No. 10,742 dated October 6, 2003, the settlement of accounts should have been completed by June 30, 2004. After having provided all information required by the National Treasury Secretariat (STN), PETROBRAS has been in contact with the Ministry of Energy and Mines (MME), in order to resolve remaining issues between the parties necessary to conclude the settlement process as established by Provisional Measure No. 2,181-45, of August 24, 2001.
The remaining balance of the Petroleum and Alcohol account may be paid as follows:
F-51
The Company’s short-term borrowings are principally sourced from commercial banks and include import and export financing denominated in United States dollars, as follows:
Import - oil and equipment
Working capital
The weighted average annual interest rates on outstanding short-term borrowings were 4.43% and 3.79% at December 31, 2004 and 2003, respectively.
F-52
Foreign currency
Financial institutions
Suppliers’ credits
Sale of future receivables
Assets related to export program to be offset against sales of future receivables (1)
Repurchased securities (2)
Local currency
Debentures
National Economic and Social Development Bank - BNDES (state-owned company, see Note 26)
Debentures (state-owned company, see Note 26)
F-53
Currencies
United States dollars
The long-term portion at December 31, 2004 becomes due in the following years:
2010
2011 and thereafter
As of December 31, 2004, US $1,904 was related to PEPSA’s debt (US $368 – recorded as current portion of long term debt and US $1,536 – as long term debt).
F-54
Interest rates on long-term debt were as follows:
6% or less
Over 6% to 8%
Over 8% to 10%
Over 10% to 15%
On September 15, 2004, the subsidiary PETROBRAS INTERNATIONAL FINANCE COMPANY (“PIFCo”) concluded placement in the international capital market of “Global Notes” amounting to US $600 for 98.638% of their face value, with coupon of 7.75% per year, and maturity in 2014. The Company used the proceeds from this issuance principally to repay trade-related debt.
On December 10, 2003, the Company issued Global Notes in an aggregate principal amount of US $750 due December of 2018. The notes will bear interest at the rate of 8.375% per annum, payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt.
On October 24, 2003, Petrobras Energía S.A. issued US $100 notes - Series R, with a 9.375% annual coupon payable semiannually, and a 9.5% annual yield to maturity, and due date of 2013.
F-55
On July 2, 2003, the Company issued Global Notes in an aggregate principal amount of US $500 due July of 2013. The notes will bear interest at the rate of 9.125% per annum, payable semiannually. On September 18, 2003, the Company issued an additional US $250 in Global Notes, which form a single fungible series with the Company’s US $500 Global Notes due July of 2013. The Company used the proceeds from these issuances principally to repay trade-related debt.
On March 31, 2003, the Company issued Global Step-up Notes in an aggregate principal amount of US $400 due April of 2008. The notes will bear interest from March 31, 2003 at a rate of 9.00% per annum until April 1, 2006 and at a rate of 12.375% per annum thereafter, with interest payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt.
Respective to the Senior and Junior Notes issued pursuant to the structured finance program, PETROBRAS and Petrobras Finance Ltd. - PFL have certain contracts (Master Export Contract and Prepayment Agreement) between themselves and special purpose entity not related to PETROBRAS, PF Export Receivables Master Trust (“PF Export”), relating to the prepayment of export receivables to be generated by PFL by means of sales on the international market of fuel oil and other products acquired from PETROBRAS.
F-56
As stipulated in the contracts, PFL assigned the rights to future receivables in the amount of US $1,800 (1st and 2nd tranches) to PF Export, which, in turn, issued and delivered to PFL the following securities, also in the amount of US $1,800:
The assignment of rights to future export receivables represents a liability of PFL, which will be settled by the transfer of the receivables to PF Export as and when they are generated. This liability will bear interest on the same basis as the Senior and Junior Trust Certificates, as described above.
In May of 2003, the PF Export Trust issued to the Company additional US $750 in Senior Trust Certificates and US $150 in Junior Trust Certificates. The Senior Trust Certificates consist of Series 2003-A of US $550 bearing annual interest of 6.436% and due in June of 2015 and Series 2003-B of US $200 bearing annual interest due of 5.548% due in June of 2013. The Junior Trust Certificates were issued with complementary terms as the new Senior Trust Certificates as they form a 20% guarantee to the senior trust certificates and expire ratably. These two new issuances complement the initial structured finance export prepayment program commenced in December of 2001.
F-57
Financial institutions abroad do not require guarantees from the Company. The financing granted by BNDES - National Bank for Social and Economic Development is guaranteed by a lien on the assets being financed (vessels).
At December 31, 2004 and 2003, GASPETRO had secured certain debentures issued to finance the purchase of the transportation rights in the Bolivia/Brazil pipeline with 3,000 shares of its interest in TBG, a subsidiary of GASPETRO responsible for the operation of the pipeline.
The Company’s debt agreements contain affirmative covenants regarding, among other things, provision of information; financial reporting; conduct of business; maintenance of corporate existence; maintenance of government approvals; compliance with applicable laws; maintenance of books and records; maintenance of insurance; payment of taxes and claims; and notice of certain events. The Company’s debt agreements also contain negative covenants, including, without limitation, limitations on the incurrence of indebtedness; limitations on the incurrence of liens; limitations on transactions with affiliates; limitations on the disposition of assets; limitation on consolidations, mergers, sales and/or conveyances; negative pledge restrictions; change in ownership limitations; ranking; use of proceeds limitations; and required receivables coverages.
The Federal Government guarantees TBG’s Multilateral Credit Agency debt, which had an outstanding balance of US $437 and US $463 at December 31, 2004 and 2003, respectively. During 2000, the Federal Government, the Company, TBG, PETROQUISA and Banco do Brasil S.A. entered into an agreement whereby the revenues of TBG will serve as a counter-guarantee to this debt until the debt has been extinguished.
PETROBRAS entered into standby purchase agreements in support of the obligations of its wholly-owned subsidiary under the note issuances in 2001, 2002 and 2003 and their respective indentures. PETROBRAS has the obligation to purchase from the noteholders any unpaid amounts of principal, interest or other amounts due under the notes and the indenture applies, subject to certain limitations, irrespective of whether any such amounts are due at maturity of the notes or otherwise.
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At December 31, 2004 and 2003, the Company had fully utilized all available lines of credit for the purchase of imports. Outstanding lines of credit at December 31, 2004 and 2003 were US $1,167 and US $1,689, respectively. Lines of credit are included in short-term debt and long-term debt.
Financial expenses, financial income and monetary and exchange variation on monetary assets and liabilities, net, allocated to income for the years ended at December 31, 2004, 2003 and 2002 are shown as follows:
Financial expenses
Loans and financings
Capitalized interest
Leasing
Losses on Derivative instruments
Repurchased securities losses
Government Securities
Gain on fair value hedge
Monetary and exchange variation
Monetary and exchange variation on monetary assets
Monetary and exchange variation on monetary liabilities
F-59
Since 1997, the Company has utilized project financings to provide capital for the continued development of the Company’s exploration and production and related projects.
Prior to December 31, 2003, the Company’s arrangements with respect to these projects were considered as capital leasing transactions for accounting purposes. Effective December 31, 2003, the Company adopted FIN 46 and the project financings special purpose entities were consolidated on a line by line basis. Thus, at December 31, 2004 and 2003, the project financings obligation represents the debt of the consolidated SPE with the third-party lender.
The Company’s responsibility under these contracts is to complete the development of the oil and gas fields, operate the fields, pay for all operating expenses related to the projects and remit a portion of the net proceeds generated from the fields to fund the special purpose companies’ debt and return on equity payments. At the conclusion of the term of each financing project, the Company will have the option to purchase the leased or transferred assets from the consolidated special purpose company.
The following summarizes the liabilities related to the projects that were in progress at December 31, 2004 and 2003:
Barracuda/Caratinga
Cabiúnas
Espadarte/Voador/Marimbá (EVM)
Nova Marlim
Albacora
Pargo, Carapeba, Garoupa and Cherne (PCGC)
Nova Transportadora do Sudeste
Nova Transportadora do Nordeste
Companhia Locadora de Equipamentos Petrolíferos – CLEP(1)
PDET S.A.
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PETROBRAS has received certain advances in the amount of US $587 which are recorded as project financings obligations and are related to assets under agreements with investors, which are included to the property, plant and equipment balance; see Note 10. Such asset and obligation amounts are presented gross as the obligation can only be settled through delivery of the fully constructed asset.
As of December 31, 2004, the amounts of cash outlay commitments assumed related to consolidated structured project financings are presented as follows:
Nova Transportadora do Sudeste - NTS
Nova Transportadora do Nordeste - NTN
On June 23, 2000 the Company completed its project financings negotiations with the Barracuda Caratinga Leasing Company B. V. (BCLC), a special purpose entity formed by a group of international financial institutions for the sole purpose of raising US $2,500 for the development of the Barracuda and Caratinga oil and gas fields located in the Campos basin. Permanent funding for this project has been raised from two governmental institutions (Japan’s Bank of International Cooperation - JBIC and the BNDES) and from a syndicate of commercial banks. In conjunction with this project, the Company will contribute US $1,035 of drilling services through a drilling services contract signed with the Halliburton Company.
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Barracuda/Caratinga (Continued)
Under an EPC turnkey contract, BCLC retained Kellog Brown & Root (KBR), a Halliburton Group company, as the prime contractor with singular responsibility for all work necessary to construct the Barracuda/Caratinga Project assets, including drilling activities, for which PETROBRAS has been subcontracted.
From early 2003, KBR has been announcing to the market its intention to file a Chapter 11 case with the U.S. courts, specifically limited to its asbestos business; such filing was completed in the second half of December 2003. As informed by KBR in its official announcements to the market, the bankruptcy protection proceedings would not directly impact the remaining businesses, including its obligations under the Barracuda/Caratinga Project EPC contract. On January 3, 2005, KBR announced the end of its Chapter 11 proceedings and exited from bankruptcy.
In the capacity as “Owner’s Representative” under the project, at June 17, 2003, PETROBRAS, on behalf of BCLC, finalized negotiations with KBR involving claims made by KBR for time extensions and project cost increases. After formal approval from the project sponsors, as contractually defined, such negotiations resulted in an amendment to the original agreement, as approved on November 7, 2003. The objectives of such amendment are to mitigate the risks involved, especially the risk related to the bankruptcy protection filed by KBR, and ensures asset construction completion in the shortest period. The original package of guarantees has been maintained and new guarantees are expected to be provided by KBR.
Pursuant to the first round of negotiations, as previously described, after the required approval was obtained from the project’s sponsors, a Term Sheet was generated which detailed various contractual amendments, which were signed by all parties on December 6, 2004. Thus, upon execution of this new amendment, the parties consider all outstanding items and disputes in connection with any and all claims to be resolved, as well as other issues relating to delays in construction work, fines, liquidated damages, responsibilities for pending services and other outstanding issues relating to the project. Execution of the amendments to the contract did not generate any financial impact.
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Respective to physical project works status, one FPSO, the P-43 was, installed in the Barracuda field, with testing operations and first volumes on December 21, 2004. The other FPSO, P-48, installed in the Caratinga field, was shipped from the Brasfels shipyard in Angra dos Reis on December 13, 2004 to its final location in Campos basin, and started production on February 28, 2005.
On March 1, 2000, the Company completed a project financing with the Cayman Cabiúnas Investment Co. Ltd. (CCIC), a special purpose company established by the Mitsui and Sumitomo trading companies for the sole purpose of raising US $850 for the expansion of the Cabiúnas Complex located in Macaé, in the state of Rio de Janeiro. Permanent financings were provided by JBIC, a syndicate of commercial banks led by the Bank of Tokyo-Mitsubishi and the special purpose company’s equity investors. Currently the works are being concluded. Lease payments from the Company to the CCIC commenced in March of 2003 and will continue through September of 2009.
On June 23, 2000, the Company closed a project financings arrangement with the EVM Leasing Corporation (EVMLC), a special purpose company established by a group of international financial institutions that raised funds by way of shareholders capital and debt for the sole purpose of raising US $1,600 for the development of the Espadarte, Voador and Marimbá oil and gas fields located in the Campos basin. The funding for the EVM project was provided by a syndicate of international financial institutions, Japanese trading companies, JBIC and BNDES. On the closing of the agreement, the Company sold previously identified oil and gas assets to EVM, who leased them back to the Company.
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On December 14, 1998, the Company entered into a consortium agreement with Companhia Petrolífera Marlim (CPM), a single purpose entity formed in November of 1998 by a group of international financial institutions for the sole purpose of raising US $1,500 for the expansion and continued development of the Marlim oil field. With this funds that were raised through the issuance of debt in the international and domestic markets and shareholders capital, CPM acquired assets from the Company and leased them back to the Company through the consortium. The revenue from the Marlim oil field is shared between the CPM and the Company, with CPM being entitled to a share that varies from 2% to 30%. The shareholders of CPM and the Company have entered into a Stock Option Agreement and granting to the Company a call option on the assets at the end of the consortium agreement and granting to the shareholders of CPM a put option to be exercised on the Company in the case of default.
On December 6, 2001, the Company entered into a consortium agreement with Nova Marlim Petróleo S.A. (NovaMarlim), a special purpose entity established by a group of financial institutions for the sole purpose of raising US $933 for the complementary development and production optimization of the Marlim oil field. The shareholders of NovaMarlim and the Company have entered into a Stock Option Agreement granting to the Company a call option over the leased assets at the end of the consortium and to the shareholders of NovaMarlim a put option to be exercised on the Company in the case of default.
During 2000, the Company structured two separate project financings for the development of the Albacora oil field located in the Campos basin. On November 28, 2000, the Company completed the financial arrangement with the Albacora Japan Petroleum Limited Company (AJPL), a special purpose company established for the sole purpose of providing financing for the continued development of the Albacora oil field. AJPL’s operations started in December of 2000 with the purchase of certain oil and gas assets from the Company. AJPL makes these assets available exclusively to the Company in return for AJPL’s share in the revenue generated from the field’s production.
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Albacora (Continued)
Funds in the amount of US $170 were raised by AJPL by way of shareholder capital from Sojitz (former Nissho Iwai Corp.) and Indonesia Petroleum Corporation (INPEX) and permanent financing by JBIC and commercial banks.
In December of 2000, the Company closed the second project financing with PETROS, the Company’s pension fund, and the deal provided additional US $240 for the continued development of the Albacora oil field.
Pargo, Carapeba, Garoupa, Cherne and Congro (PCGC)
The Companhia de Recuperação Secundária (CRSec) PCGC is a special purpose company established with the purpose of developing the Pargo, Carapeba, Garoupa, Cherne and Congro (PCGC) offshore fields project. The project is a secondary extraction project using water-injection technology to reestablish the appropriate level of pressure in the reservoirs to maximize the recovery of oil and gas in these fields. In addition, the PCGC project includes equipment for new oil reserves in the Congro field. To develop the PCGC project Management estimates total costs of the PCGC project to be US $134.
Malhas Project
In order to implement a pipeline network for the transportation of gas in the Southeast and Northeast regions (MALHAS Project), the Company, through its subsidiaries GASPETRO and TRANSPETRO, entered into a consortium with the special purpose companies Nova Transportadora do Sudeste (NTS) and Nova Transportadora do Nordeste (NTN). NTS and NTN will participate in the consortium by the construction and acquisition of assets related to the transportation of natural gas (gas pipelines, citygates and accessories), in the amount of up to US $1,000 to be integrated in the existing gas pipelines network of PETROBRAS. Funds allocated to the project by NTS and NTN will be derived from shareholders capital (10%) and from financing operations obtained from Japan Bank of International Cooperation and from a group of commercial banks led by Bank of Tokyo-Mitsubishi, and also financing from BNDES.
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Malhas Project (Continued)
In addition to NTS and NTN, the MALHAS consortium also includes the wholly-owned subsidiary of the Company, Transportadora Nordeste Sudeste (TNS), to whom the existing gas transportation assets belong, and by TRANSPETRO, which is responsible for the activities involved in the operation and maintenance of the consortium assets. Upon commencement of operations, the consortium will transport the natural gas and the Company will pay the consortium a fee for the services provided. Revenues arising from this project will be shared among the consortium members in accordance with pre-defined contractual terms, and NTS and NTN will receive funds in an amount necessary to fulfill their financial obligations. The Company is committed to making prepayments for transportation capacity to cover any cash shortfalls of the consortium, so that it may transfer to NTS and NTN the funds necessary for the fulfillment of their financial obligations under the agreement. The MALHAS consortium was not operational as of December 31, 2004 and, accordingly, the Company did not make any payments for gas transportation services.
CLEP Project (former Langstrand Project)
Through a financing structure that involves the SPC Companhia Locadora de Equipamentos Petrolíferos – CLEP, former Langstrand Holdings S.A., the Company will sell to this company assets related to the production of oil, located in the Campos basin, and subsequently will lease such assets back through a leasing agreement. The funds necessary for CLEP to acquire the assets from PETROBRAS has been provided by shareholders’ capital and from debt raised in the international financial markets through the issuance of Medium Term Notes backed by CLEP receivables (lease payments to be made by PETROBRAS). As of December 31, 2004, CLEP had obtained financings in the amount of US $1,700.
CLEP revenues will arise solely from the semi-annual lease payments to be made by PETROBRAS for the use of the assets. PETROBRAS also ensures the payment of additional lease payments in the event that CLEP revenues are not sufficient to cover its financial obligations related to the project. In an event of default, PETROBRAS is committed to acquire the SPC for the remaining balance of its obligations.
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PDET Offshore
The main objective of PDET Project is to enhance the oil transportation facilities of Campos Basin to the Brazilian refineries and for exportation. The Project consists of a fixed central platform (PRA-1), 2 monobuyos interconnected to it by subsea lines and other auxiliary equipments. The oil will flow through these equipments and will fill tankers that will take petroleum produced from platforms P-51, P-52, P-53, P-55 e RO-4 to Petrobras` coastal terminals that are connected to the onshore pipelines.
Bridge financing was provided for the Project on November 2004 by Mitsubishi Corporation and Mizuho Corporate Bank. On March 30, 2005, PDET Offshore S.A. received the first disbursement, in the total amount of US $183.
PDET Onshore
PDET ONSHORE S/A is a special purpose company that was established in November 2002 to be part of the onshore portion of the PDET Project. The main objective of the onshore portion was to construct and own an approximately 375- mile (603 kilometers) onshore pipeline and related assets from Barra do Furado in the state of Rio de Janeiro to Guararema Terminal in the state of São Paulo. The onshore portion of the PDET Project was cancelled in the first quarter of 2004 and the scope of the PDET Project has been revised.
F-67
The Company leased certain offshore platforms and vessels, which are accounted for as capital leases. At December 31, 2004, assets under capital leases had a net book value of US $1,518 (US $1,749 at December 31, 2003).
The following is a schedule by year of the future minimum lease payments at December 31, 2004:
2005
Estimated future lease payments
Less amount representing interest at 6.2% to 12.0% annual
Less amount representing executory costs
Present value of minimum lease payments
Less current portion of capital lease obligations
Long-term portion of capital lease obligations
F-68
As a result of adoption of FIN 46 at December 31, 2003, the Company consolidates six thermoelectric plants. Previously, three of these thermoelectric plants were accounted for as capital leases, and therefore, their consolidation did not have a material impact on the Company’s financial condition. For the other three thermoelectric plants, the Company was deemed the primary beneficiary because of contractual obligations concerning third-party interests, with amounts equal to the contingent payments required under the contracts recognized to the extent the related payments are deemed probable and can be estimated in accordance with the provisions of SFAS 5.
At December 31, 2003 as a result of adoption of FIN 46, the Company has consolidated the thermoelectric plants and recognized a corresponding liability. Thus, it is no longer necessary to recognize any additional liability for future payments expected to be made under the agreements with the sponsors of the thermoelectric plants. The Company will recognize any losses from operations of the plants if and when incurred.
On August 13, 2004, the Board of Directors of PETROBRAS approved the initial financial terms for the acquisition of a 100% interest in the Eletrobolt Thermoelectric plant. This plant is one of the three plants discussed above that the Company was deemed to be the primary beneficiary of because of contractual obligations concerning third-party interests, and thus has been consolidated from December 31, 2003. On December 17, 2004, the Board of Directors of PETROBRAS approved the final terms and conditions for the completion of the acquisition of Sociedade Fluminense de Energia – SFE, owner of Termoelétrica Eletrobolt’s assets, for US $164 to be paid in one lump sum. The transaction is pending due diligence to finalize any purchase price adjustments and the related documentation is expected to be signed in early 2005, at which time SFE’s quotas will be transferred to PETROBRAS and the related payment will be made. The purchase of Electrobolt will be accounted for as a purchase business combination under the accounting rules of FAS 141, once the transaction is finalized and ownership has transferred and the purchase price will be allocated based on the fair value of assets acquired and liabilities assumed at the acquisition date. As the ultimate purchase price inclusive of adjustment is expected to closely approximate the book value of assets recorded in Electrobolt and presently consolidated under FIN 46, this transaction is expected to have an immaterial impact to the financial statements.
F-69
The balances related to Employees’ Postretirement Benefits are represented as follows:
Employees’ postretirement benefits obligations
Tax effect
Net balance recorded in shareholders’ equity
The Fundação Petrobras de Seguridade Social (PETROS) and the current benefits plan (the PETROS Plan)
The Fundação Petrobras de Seguridade Social (PETROS) was established by PETROBRAS as a private, legally separate nonprofit pension entity with administrative and financial autonomy. As such, PETROS has the following principle objectives:
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The Fundação Petrobras de Seguridade Social (PETROS) and the current benefits plan (the PETROS Plan) (Continued)
The PETROS plan is a contributory defined-benefit pension plan introduced by PETROBRAS in July of 1970, to supplement the social security pension benefits of employees of PETROBRAS and its Brazilian subsidiaries and affiliated companies. In order to fund its objectives, PETROS receives monthly contributions from the sponsoring companies of the PETROS Plan amounting to 12.93% of the salaries of participants in the plan. Additionally PETROS is funded by income resulting from the investment of these contributions. The Company’s funding policy is to contribute to the plan annually the amount determined by actuarial calculations. In the calendar 2004 year, contributions paid totaled US $435 (US $402 in 2003), and was deducted from the balance of the provision for benefit obligation established at December 31, 2004. In the 2004 and 2003 financial years, these contributions were included in the cost of operations.
The Company’s liability related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The assets that guarantee the pension plan are presented as a reduction to the net actuarial liabilities.
The accumulated benefit obligation less the fair value of plan assets is recognized as an increase or decrease in the additional minimum liability and respectively recorded to “amounts not recognized as net periodic pension cost”, in shareholders’ equity. Actuarial gains and losses are amortized during the average remaining service period of the active employees of approximately 10 years at December 31, 2004, in accordance with the procedure established by SFAS 87.
F-71
The relation between contributions by the sponsors and participants of the PETROS Plan, considering only those attributable to the Company and subsidiaries in the 2004 financial year, was 1.00 (1.01 in 2003). The Company’s best estimate of contributions expected to be paid in 2005 respective to the pension plan approximates US $135, with total pension benefit payments in 2005 expected to be US $587.
According to Constitutional Amendment No. 20, the computation of any deficit in the defined-benefit plan in accordance with the actuarial method of the current plan (which differs from the method defined in SFAS 87), must be equally shared between the sponsor and the participants.
Therefore, in the event that the deficit computed for December 31, 2004 in accordance with the projected credit unit method (SFAS 87), is reflected as a technical deficit in the funding methods adopted by the PETROS Plan, and results in additional financial contributions, these additional required contributions shall be divided equally between the Company and the participants.
Plan assets
Plan assets are invested primarily in government securities, investment funds, equity instruments and properties.
The table below describes the types of plan assets:
Investments funds
Equity instruments
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Plan assets (Continued)
Plan assets include the following securities of related parties:
PETROBRAS common shares
PETROBRAS preferred shares
Government controlled companies
Securities of other related parties
PETROS provided certain financing for the continued development of the Albacora oil and gas field located in the Campos basin, that is classified as securities of other related parties. (See Note 15).
The Company uses 6% as the expected long-term rate of return over inflation on PETROS’ assets. The PETROS’ portfolio of investments as of December 31, 2004 was comprised of 71% securities, 49% of which were held-to-maturity government securities that earn interest at 6% annually plus the IPCA (Consumer Price Index) variation and 22% of which were Investments Funds that earn interest approximate to the CDI (Certificado de Depósito Interbancário, or Interbank Deposit Certificate), which has been yielding more than 6% annually. Thus, the Company considers a 6% long term interest rate appropriate to calculate the expected return on assets, as such aligns with the composition of the PETROS’ asset portfolio.
PETROS intends to change its investment strategy for the 2005-2008 years to reflect the evolution of and opportunities expected in the Brazilian economy for 2005 and beyond. PETROS will continue to maintain plan assets in various sectors, but percentages by asset type are expected to differ depending on yield’s achievable in the market while minimizing risk exposure.
PETROS has a significant volume of investments in government securities, mainly NTN-B bonds, which by an agreement with the Supplementary Social Security Department will be held-to-maturity. Thus, the percentage of assets allocated in this investment will remain the same over the short term.
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New benefits plan
In May of 2001, the Board of Directors of PETROBRAS approved the creation of a mixed social security plan, for current and new employees, based on defined contribution formula for programmable benefits and a defined benefit formula for risk benefits. However, the migration of participants and beneficiaries of the previous plan (PETROS) to the new plan was suspended, pursuant to a Federal Judicial ruling arising from an injunction filed by the employee union. A court order in 2004 granted the injunction ruling against the new plan and invalidating any changes to the PETROS plan premised upon intended migration to a new plan. This court decision is under appeal.
The impact of joining the new plan and the cost of the benefits stipulated in the new plan will be valued according to the standards established in SFAS 87 and will only be computed and recognized in the accounts when the litigation has been resolved.
Pursuant to closure of the PETROS Plan, PETROBRAS contracted a group life insurance policy to cover employees commencing employment with the Company subsequent to closure of the PETROS plan; this policy will remain in effect until a new private pension plan is implemented.
In 2003 PETROBRAS formed a task force with representatives of the National Union of Oil Workers (FUP), unions and PETROS, among others, in order to evaluate alternatives to a new model for the Company’s supplementary pension plan, including analyses of negotiated arrangements for the settlement of actuarial deficits. There have been no formal decisions by the committee as of December 31, 2004.
TRANSPETRO
TRANSPETRO maintains a defined-contribution private pension scheme with PETROS called Plano TRANSPETRO, which receives monthly contributions equivalent to 5.32% of the payroll of the members and is equal to the contributions made by the participants.
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PETROBRAS ENERGIA – PEPSA
Defined contribution plan
Petrobras Energia sponsors a defined contribution plan applicable to all of its employees with salaries above a specified level. Through this plan, Petrobras Energia provides additional matching funds at amounts equivalent to contributions made by employees which are in excess of legally required amounts. These funds are recognized in accordance with the accrual method of accounting. Due to significant changes in the macroeconomic scenario in 2002 and the uncertainties with regard to the Argentine economic conditions, PEPSA has temporarily suspended this benefit as from January of 2002. This benefit will be reinstated when a provisional savings means considered adequate to this end is identified.
Defined benefit pension plan
All employees joining PEPSA prior to May 31, 1995 that have participated in the defined contribution plan without interruption and that have worked for a required number of years are entitled to be participants in the defined benefit pension plan. The benefit is based on the last salary amount paid to the employees that participate in the plan, considering years of service.
The defined benefit pension plan is of a supplemental nature, with the benefit received by the employee corresponding to an amount defined in conformity with the plan’s provisions, after deducting the benefits payable in accordance with the contribution plan and the government-sponsored pension system, such that the aggregate amount of benefits granted to each employee under the three plans is equivalent to that defined in the plan. As from retirement, the employees are entitled to a fixed monthly payment.
The plan requires contributions to a fund, payable exclusively by PEPSA and without any contribution by the employees, who must contribute to the social security system based on their total salary. The fund’s assets have been transferred to a trust and invested mainly in bonds, notes, mutual investment funds and fixed term deposits. The Bank of New York is the trustee and Watson Wyatt is the managing agent. PEPSA determines the liability relating to this plan using actuarial calculation methods.
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PETROBRAS and its Brazilian subsidiaries maintain a health care benefit plan (AMS), which offers defined benefits and covers all employees (active and inactive) together with their dependents. The plan is managed by the Company, with the employees contributing fixed amounts to cover principal risks and a portion of the costs relating to other types of coverage in accordance with participation tables defined by certain parameters including salary levels.
The Company’s commitment related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The health care plan is not funded or otherwise collateralized by assets. Instead, the Company makes benefit payments based on annual costs incurred by plan participants.
The actuarial gains and losses arising from the differences between the actuarial assumptions and the costs effectively incurred are respectively included or excluded when defining the net actuarial liability. These gains and losses are amortized over the average remaining service period of the active employees.
For measurement purposes, a 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed upon adoption of SFAS 106. The annual rate was assumed to decrease to 7.5% after 4 years.
Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Effect on total of services and interest cost component
Effect on postretirement benefit obligation
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LIQUIGÁS DISTRIBUIDORA S.A. (former Sophia do Brasil S.A. and Agip do Brasil S.A.)
On August 9, 2004, the Company acquired Liquigás Distribuidora S.A. (see Note 20). Liquigás maintains a health care benefit plan, which offers defined benefits and covers LPG employees. At December 31, 2004, Liquigás recorded liabilities in connection with future post-retirement health care benefit costs, in the amount of US $12, directly charged to profit and loss accounts for the year. The liability related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method, according to SFAS 106 and SFAS 132 – Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106 (“SFAS 132”).
F-77
The funded status of the plans at December 31, 2004 and 2003, based on the report of the independent actuary, and amounts recognized in the Company’s balance sheets at those dates, are as follows:
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits paid
Acquisitions/Mergers
Gain (loss) on translation
Benefit obligation at end of year (1)
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Company contributions
Employee contributions
Gain on translation
Fair value of plan assets at end of year
Reconciliation:
Funded status
Unrecognized actuarial loss
Net amount recognized
Amounts recognized in the balance sheet consist of:
Employees’ postretirement benefits
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Net periodic benefit cost includes the following components:
Service cost-benefits earned during the year
Interest cost on projected benefit obligation
Expected return on plan assets
Amortization of initial transitory obligation
Recognized actuarial loss
Net periodic benefit cost
The main assumptions adopted in 2004 and 2003 for the actuarial calculation are summarized as follows:
Discount rates
Rates of increase in compensation levels
Expected long-term rate of return on assets
Mortality table
Petrobras has aggregated information for all defined benefit pension plans. The domestic benefit plans of Petrobras, BR Distribudora, Petroquisa, and Refap contain similar assumptions and the benefit obligation related to PEPSA, the international plan, is not significant to the total obligation and thus has also been aggregated. All Petrobras group pension plans have accumulated benefit obligation in excess of plan assets.
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The determination of the expense and liability relating to the Company’s pension plan involves the use of judgment in the determination of actuarial assumptions. These include estimates of future mortality, withdrawal, changes in compensation and discount rate to reflect the time value of money as well as the rate of return on plan assets. These assumptions are reviewed at least annually and may differ materially from actual results due to changing market and economic conditions, regulatory events, judicial rulings, higher or lower withdrawal rates or longer or shorter life spans of participants.
Although the Brazilian market has been demonstrating signs of stabilization under the present economic model, as reflected in market interest rates, it is not yet prudent to conclude that market interest rates will be stable. Although SFAS 87 offers limited guidance, the Company considers it appropriate to use actuarial assumptions which include an estimate of long-term inflation; i.e. nominal rates.
The Executive Board of PETROBRAS approved a change to a new mortality table of the actuarial assumptions of the pension and healthcare plans in Brazil; this new mortality table reflects updated assumptions and changes relative to the profile of employees, retirees and pensioners, based on longevity, age of invalidity and invalid mortality tables.
As discussed in Note 3(c), on December 31, 2004 the Company adopted a new actuarial methodology regarding the calculation of Accumulated Benefit Obligation.
F-80
The Accumulated Benefit Obligation at December 31, 2004 and 2003, respectively, is US $10,186 and US $7,646
F-81
In 2004, the Company contributed US $118 to its pension plans. In 2005, the Company expects contributions to be approximately US $135. Actual contribution amounts are dependent upon investment returns, changes in pension obligations and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
The following benefit payments, which include estimated future service, are expected to be paid by the Company in the next 10 years:
Subsequent five years
The Company’s subscribed and fully paid-in capital at December 31, 2004 and 2003 consisted of 634,168,418 common shares and 462,369,507 preferred shares. The preferred shares do not have any voting rights and are not convertible into common shares and vice-versa. Preferred shares have priority in the receipt of dividends and return of capital.
On January 29, 2003, the Board of Directors of the Company, approved the issuance of 9,866,828 preferred shares of the Company in connection with the public offer by the Company to acquire publicly traded shares of Petrobras Distribuidora - BR, at an issue price of US $12.38 (R $45.08) per share, under the terms of the capital increase approved during the meeting of the Board of Directors of the Company held on November 7, 2002. As a result, the capital of the Company increased by US $122. This minority interest acquisition, accounted for as a purchase business combination under SFAS No. 141 – Business Combinations (“SFAS 141”), did not have a material impact to the financial statements.
F-82
The Extraordinary Shareholders’ Meeting, held jointly with the General Shareholders’ Meeting on March 27, 2003, approved an increase in the Company’s capital by capitalizing revenue reserves accrued during previous years, to the amount of US $912, without issuing new shares, in accordance with Art. 169, paragraph 1 of Law No. 6,404/76.
On May 9, 2003, the Board of Directors of the Company approved the issue of 567,010 preferred shares of the Company in connection with the public offer by the Company to acquire publicly traded shares of Petrobras Distribuidora - BR, at an issue price of R $45.08 per share. As a result, the capital of the Company increased by US $8.
The General Extraordinary Meeting, held together with the General Ordinary meeting on March 29, 2004, increased the Company’s capital to US $11,701, through the capitalization of revenue reserves accrued during previous financial years, in the amount of US $4,439, and without the issuance of new shares, in accordance with article 169, paragraph 1, Law No. 6,404/76. This capitalization was made in order to bring the Company’s capital in line with the investment requirements of an oil company given intensive use of capital and extended operating cycles.
The Extraordinary General Meeting held on March 29, 2004 also approved an increase in the Company’s authorized capital (paragraph 1, article 4, of the Company’s by-laws) from R $30.000 million to R $60.000 million, through the issuance of up to 200,000,000 (two hundred million) preferred shares for payment in cash, assets and credit capitalization.
On May 13, 2005, PETROBRAS management approved the proposed share split and the related amendment to article 4 of the Company’s by-laws. These issues will be discussed by the shareholders at the Extraordinary General Meeting (EGM) to be held on June 15, 2005.
Current Brazilian law requires that the Federal Government retain ownership of 50% plus one share of the Company’s voting shares.
F-83
In accordance with the Company’s by-laws, holders of preferred and common shares are entitled to a minimum dividend of 25% of annual net income as adjusted under Brazilian Corporate Law. In addition, the preferred shareholders have priority in the receipt of an annual dividend of at least 3% of the book value of the shares or 5% of the paid-in capital in respect of the preferred shares as stated in the statutory accounting records. As of January 1, 1996 amounts attributed to shareholders as interest (see below) can be deducted from the minimum dividend computation. Dividends are paid in Brazilian reais. The Company paid US $366 in dividends during the year ended December 31, 2004 (2003 - US $212 - 2002 - US $602).
Brazilian corporations are permitted to attribute interest on shareholders’ equity, which may either be paid in cash or be used to increase capital stock. The calculation is based on shareholders’ equity amounts as stated in the statutory accounting records and the interest rate applied may not exceed the Taxa de Juros de Longo Prazo (long-term interest rate or the “TJLP”) as determined by the Brazilian Central Bank. Such interest may not exceed the greatest of 50% of net income or 50% of retained earnings plus revenue reserves. Interest on shareholders’ equity, is subject to withholding tax at the rate of 15%, except for untaxed or exempt shareholders, as established by Law No. 9,249/95. The Company paid US $1,443 in interest on shareholders’ equity during the year ended December 31, 2004 (2003 - US $731 - 2002 - US $416).
The General Shareholders’ Meeting held on March 29, 2004 approved the proposed dividends for the 2003 financial year amounting to US $1,955. Such amount includes the portion of interest on shareholders’ equity approved by the Board of Directors on November 13, 2003, amounting to US $1,139, and also includes the portion of interest on equity approved by the Board of Directors on February 13, 2004, amounting to US $436, that was made available based on the shareholders of record as of March 29, 2004. These amounts, paid in Brazilian reais, were monetarily restated as from December 31, 2003 up to the date of payment.
F-84
The dividends for the year 2004, as approved at the Annual General Meeting (AGM) of Stockholders held March 31, 2005, amounting to US $1,900, corresponding to R $4.60 per share (US $1.73 per share calculated by year-end exchange rate), include the portion of interest on shareholders’ equity approved by the Board of Directors on September 17, 2004 and paid to the shareholders on February 15, 2005, amounting to US $1,239, corresponding to R $3.00 per share (US $1.13 per share calculated by year-end exchange rate). The balance of dividends (US $248) and the portion of the interest on shareholders’ equity (US $413) will be made available to stockholders by May 17, 2005, the deadline stipulated pursuant to Articles 132, item II, and 205, paragraph 3, of the Brazilian Corporation Law (No. 6.404/76).
Brazilian law permits the payment of dividends only from retained earnings as stated in the statutory accounting records. At December 31, 2004, the Company had appropriated all such retained earnings.
In addition, at December 31, 2004, the undistributed reserve in appropriated retained earnings, amounting to US $9,688, may be used for dividend distribution purposes, if so approved by the shareholders, however, the Company’s stated intent is to use such reserve to fund working capital and capital expenditures.
A withholding tax of 15% was payable on distributions of dividends earned from January 1, 1994 through December 31, 1995. No withholding tax is payable on distributions of dividends earned since January 1, 1996.
As of December 31, 2004, US $816 from the financials statements as of December 31, 2003 were reclassified from the line item “Unappropriated retained earnings” to the Current liabilities section and presented in the Dividend and interest on capital payable line item. This amount includes dividends (US $380) and interest on shareholders’ equity (US $436). The total dividend paid in 2003 was equal to 29% of net income, sufficient to cover the minimum dividend required under the Company’s by-laws, which is set at 25% of net income.
F-85
Basic and diluted earnings per share amounts have been calculated as follows:
Cumulative effect of change in accounting principle, net of taxes
Net income for the period
Less priority preferred share dividends
Less common shares dividends, up to the priority preferred Shares dividends on a per-share basis
Remaining net income to be equally allocated to common and preferred shares
Common and Preferred
Relates to the Merchant Marine (AFRMM) freight surcharges levied in accordance with relevant legislation. These funds are used to purchase, enlarge or repair vessels of the Company’s transport fleet.
This reserve consists of investments in tax incentives in the Northeast Investment Fund (FINOR), arising from allocations of part of the Company’s income tax.
F-86
Brazilian Law and the Company’s by-laws require that certain appropriations be made from retained earnings to reserve accounts annually. The purpose and basis of appropriation to such reserves are as follows:
This reserve is a requirement for all Brazilian corporations and represents the annual appropriation of 5% of net income as stated in the statutory accounting records up to a limit of 20% of capital stock. The reserve may be used to increase capital or to compensate for losses, but may not be distributed as cash dividends.
This reserve is established in accordance with Article 196 of Law No. 6,404/76 to fund the Company’s annual investment program. For the year ended December 31, 2003, the Company’s management retained US $4,603 of which US $3,773 relates to net income for that year and US $830 to the remaining balance of retained earnings, to fund the Company’s capital expenditure budget for 2004. This proposal was approved at the General Shareholders’ Meeting held on March 29, 2004.
The proposal for appropriation of income for the year ended December 31, 2004 includes a retention of earnings in the amount of US $4,396, of which US $4,392 relates to net income for the year and US $4 to the remaining balance of retained earnings, approved by the General Shareholders’ Meeting held on March 31, 2005. This proposal is intended to cover partially the annual investment program established in the capital budget for 2005.
This reserve is provided through an amount equivalent to a minimum of 0.5% of subscribed and fully paid in capital at year-end. The reserve is used to fund the costs incurred with research and technological development programs. The accumulated balance of this reserve cannot exceed 5% of the capital stock, according to Article 55 of the Company’s by-laws.
F-87
On August 9, 2004, the Company’s subsidiary, Petrobras Distribuidora S.A. – BR, acquired from ENI B.V. 100% of the capital of its Brazilian subsidiary Liquigás Distribuidora S.A. (former Sophia do Brasil S.A. and Agip do Brasil S.A.), assuming its control from that date.
The purchase price paid for Liquigás Distribuidora S.A. was based on an economic valuation model of expected future earnings of Liquigás Distribuidora S.A., which considered relevant factors, including the potential effects of the economic situation of Brazil. The acquisition of Liquigás Distribuidora S.A. totaled US $511. The Company paid US $225 in cash, and settled a debt of US $225 that the former Agip do Brasil had with ENI BV. An additional amount of US $61 related to subsequent purchase price adjustments was paid on December 10, 2004.
The acquisition of Liquigás Distribuidora S.A. was recorded using the purchase method of accounting and the financial statements of Liquigás Distribuidora S.A. were included in the consolidated PETROBRAS financial statements, beginning in August of 2004. The purchase price allocation was based on the fair market value of the assets acquired and the liabilities assumed as of the acquisition date as determined by independent appraisers.
Liquigás Distribuidora S.A. is a liquefied petroleum gas (LPG), fuel and lubricant distributor, and has 21.5% share in the LPG market in Brazil, 3.8% of total fuel distribution domestic market with a network of more than 1,500 service stations and 3% share in the Brazilian lubricant distribution market.
The acquisition of Liquigás Distribuidora S.A. contributes toward achieving the objectives established in PETROBRAS’ Strategic Planning for its subsidiary BR of expanding its share in the LPG distribution segment, and also of consolidating its penetration in the automotive fuel distribution market in certain regions of the country.
F-88
The following unaudited pro forma summary financial information presents the consolidated results of operations as if the acquisition of Liquigás Distribuidora S.A. had occurred at the beginning of the years presented.
The Company’s subsidiary, Petrobras Química S.A. – PETROQUISA decided to exercise its preemptive right in the acquisition of shares held by PRIMERA Indústria e Comércio Ltda. in the capital of Petroquímica Triunfo S.A. (Triunfo) in response to the put option.
After exercise of its preemptive right on May 14, 2004, PETROQUISA, which had previously held 45.22% of voting capital and 59.92% of capital stock of Petroquímica Triunfo increased its interest to 70.45% of voting capital and 85.04% of its capital stock. The results of Triunfo have been included to the Petrobras Consolidated Financial Statements since May of 2004. Due to immateriality, the Company has not prepared pro forma information respective to this business combination.
The acquisition was consummated principally to expand PETROBRAS’ petrochemical activities according to the Strategic Plan approved in May 14, 2004.
The Company paid US $32 (R $101 million) in cash and this purchase price was based on an economic valuation model of expected future earnings of Petroquímica Triunfo S.A.
Petroquímica Triunfo S.A. produces low-density polyethylene and has an installed capacity of 160,000 tons per year. Triunfo’s activities are exclusively in Brazil.
F-89
On December 17, 2004, PETROBRAS informed the market of the approval, from its Executive Board, of the acquisition of all of the shares held by EDP Brasil S.A. in the thermoelectric power plant FAFEN Energia S.A., located in the city of Camaçari, state of Bahia, with an installed capacity of 133 MW for electricity generation and 42 ton/hour for steam generation. PETROBRAS already owned a 20% interest in the capital of FAFEN Energia. PETROBRAS will pay EDP Brasil US $36 for the acquired 80% interest in the plant, payable as follows: 50% 30 days after the closing of the operation, 25% one year thereafter and the remaining 25% two years thereafter.
The acquisition of FAFEN was recorded using the purchase method of accounting and was consumated on December 27, 2004 with the assets and liabilities of such being included in the consolidated PETROBRAS financial statements as of December 31, 2004. Results of operations will be included in the consolidated PETROBRAS financial statements beginning on January 2005.
The purchase price for FAFEN was allocated based on the fair market value of the assets acquired and the liabilities assumed as of the acquisition date as determined by independent appraisers. Due to immateriality, the Company has not prepared pro-forma information respective to this business combination.
The first module of the power plant has been operating since September 2001, supplying 22 MW and 42 ton/hour of steam to PETROBRAS’ Fertilizer Plant, in the Camaçari complex. Construction and testing have been recently concluded, the plant will supply, beginning in 2005, 100 MW energy to Bandeirantes Energia, under a previously already signed contract.
F-90
On October 17, 2002, the Company signed the Final Share Acquisition Agreement completing the acquisition of a controlling interest PEPSA and PELSA.
On May 13, 2003, the Argentine antitrust agency approved the purchase of 58.62% of the capital stock of PEPSA and 39.67% of the capital stock of PELSA. As a result of the purchase of a 39.67% interest in the capital stock of PELSA, together with the purchase of 58.62% of PEPSA’s interest in the capital stock of PELSA, the Company has a controlling interest in PELSA equal to 50.73% and thus has consolidated the entity.
The purchase price to be paid for PEPSA and PELSA was based on an economic valuation model of expected future earnings of those companies, which considered relevant factors, including the potential effects of the economic situation of Argentina. The Company paid US $739 in cash and US $338 in bonds to the Perez Companc family for the shares of PEPSA and PELSA.
The acquisition was consummated principally to expand PETROBRAS operations into geographical markets where the Company had little activity. Through the acquisition of PEPSA and PELSA, PETROBRAS was able to gain immediate access to the Argentine market and brand recognition. The goodwill of US $183 generated by the transaction is attributed principally to downstream activities.
The acquisition of PEPSA and PELSA was recorded using the purchase method of accounting and the financial statements of PEPSA and PELSA were included in the consolidated PETROBRAS financial statements, beginning on May 13, 2003. The purchase price for PEPSA and PELSA was allocated based on the fair market value of the assets acquired and the liabilities assumed as of the acquisition date as determined by independent appraisers.
F-91
PEPSA operates principally in the areas of oil field exploration and production, refining, transport and commercialization, electricity generation, transmission and distribution, and petrochemicals. Its activities are primarily based in Argentina, but PEPSA also operates in Bolivia, Brazil, Ecuador, Peru and Venezuela. PELSA operates primarily in the oil and gas exploration and production industry in Argentina.
The following unaudited pro forma summary financial information presents the consolidated results of operations as if the acquisition of PEPSA and PELSA had occurred at the beginning of the periods presented.
Consolidated income statements data for the year ended December 31, 2003 and 2002.
Costs and expenses
Financial expenses, net
Cumulative effect of change in accounting principles, net of taxes
F-92
PETROBRAS is subject to a number of commitments and contingencies arising in the normal course of its business. Additionally, the operations and earnings of the Company have been, and may be in the future, affected from time to time in varying degrees by political developments and laws and regulations, such as the Federal Government’s continuing role as the controlling shareholder of the Company, the status of the Brazilian economy, forced divestiture of assets, tax increases and retroactive tax claims, and environmental regulations. The likelihood of such occurrences and their overall effect upon the Company are not predictable.
The Company currently has several contracts to purchase crude oil, diesel fuel and other oil products, which require the Company to purchase a minimum of approximately 57,400 barrels per day at respective current market prices.
PETROBRAS provided guarantees to the ANP for the minimum exploration program defined in the concession contracts for exploration areas, totaling US $1,661 (US $907 in 2003). Out of this total, US $1,311 (US $704 in 2003) represents a pledge on the oil to be extracted from previously identified fields already in production, for areas in which the Company had already made commercial discoveries or investments at the time where Law No. 9,478 of August 6, 1997 came into force. For areas whose concessions were obtained by bidding from the ANP, PETROBRAS has given bank guarantees totaling US $350 through December 31, 2004 (US $203 in 2003).
PETROBRAS has guaranteed that it will purchase specified volumes of natural gas that run through TBG pipeline.
In 1993, the Company signed a contract with Yacimentos Petrolíferos Fiscales Bolivianos, the Bolivian state oil company for the purchase of natural gas. Under this contract, the Company is required to purchase 80% of the natural gas transported through the Bolivia/Brazil natural gas pipeline over a 20 year term at contract prices ranging from US $1.07 per MMBTU to US $1.17 MMBTU, based upon throughput. The pipeline achieved an average throughput of 19.9 million cubic meters per day during 2004.
The Company has exclusive supply contracts with certain service stations. These contracts are typically for seven years and require the Company to sell product at market prices.
F-93
The Company is a defendant in numerous legal actions involving civil, tax, labor, corporate and environment issues arising in the normal course of its business. Based on the advice of its internal legal counsel and management’s best judgment, the Company has recorded accruals in amounts sufficient to provide for losses that are considered probable and reasonably estimable. At December 31, 2004 and 2003, the respective claims by type are as follows:
Commercials claims and other contingencies
Contingencies for joint liability
Current Contingencies
Long-term Contingencies
As of December 31, 2004 and 2003, in accordance with Brazilian law, the Company had paid US $699 and US $543, respectively, into federal depositories to provide collateral for these and other claims until they are settled. These amounts are reflected in the balance sheet as restricted deposits for legal proceedings and guarantees.
The Company is a party to several contracts related to the acquisition and upgrade of production Platform P-36, which was lost in its entirety in 2001. Pursuant to those contracts, the Company had an obligation to pay the insurance proceeds to a Security Agent for distribution according to specified clauses established in the contracts. The Company contends that it is entitled to the insurance proceeds under the contractual arrangements, and other parties contend that they are also entitled to such proceeds. The issue is subject to international proceedings in a British court. Pending determination of the issue by the international court, the Company committed to deposit cash collateral in the amount of US $175, in order to facilitate the issuance of a guarantee by a Security Agent, for the payment of creditors. At December 31, 2004, this amount was included in the balance sheet as restricted deposits for legal proceedings and guarantees.
F-94
On May 28, 1981, Kallium Mineração S.A. brought an action against Petromisa, a former subsidiary of PETROBRAS, in the Federal Court of the State of Rio de Janeiro alleging damages of approximately US $450 relating to the rescission of a contract to develop a potassium salt mine. On August 10,1999, a decision was handed down that considered most of the plaintiff’s petitions to be without grounds (losses, damages and loss of profit), requiring only the Company to reimburse “all expenses incurred as a result of the prospecting research” carried out, in accordance with amounts to be calculated in the final award. No award for loss of profit was established in the decision. In September of 1999 both parties filed appeals with the appeals court in the state of Rio de Janeiro. Based on the opinion of its legal advisers, management does not expect an unfavorable outcome in this case and considers the risk of loss with respect to this lawsuit to be remote.
On November 23, 1992, PORTO SEGURO IMÓVEIS LTDA., a minority shareholder of PETROQUISA, filed a suit against PETROBRAS in the State Court of Rio de Janeiro related to alleged losses resulting from the sale of a minority holding by PETROQUISA in various petrochemical companies included in the National Privatization Program introduced by Law No. 8,031/90
In this suit, the plaintiff claims that PETROBRAS, as the majority shareholder in PETROQUISA, should be obliged to reinstate the “loss” caused to the net worth of PETROQUISA, as a result of the acts that approved the minimum sale price of its holding in the capital of privatized companies. A decision was handed down on January 14, 1997 that considered PETROBRAS liable with respect to PETROQUISA for losses and damages in an amount equivalent to US $3,406.
F-95
In addition to this amount, PETROBRAS was required to pay the plaintiff 5% of the value of the compensation as a premium (see art. 246, paragraph 2 of Law No. 6,404/76), in addition to attorneys’ fees of approximately 20% of the same amount. However, since the award would be payable to PETROQUISA and PETROBRAS holds 99.0% of its capital, the effective disbursement if the ruling is not reversed will be restricted to 25% of the total award. PETROBRAS filed an appeal with the State Court of Rio de Janeiro, and received a favorable decision from the Third Civil Court on February 11, 2003, which, by a majority vote, accepted PETROBRAS’ appeal to reverse the judgment and ruled the plaintiff’s case to be without grounds, the revising judge’s decision that held the case to be partially with grounds to reduce the amount of compensation to US $1,538 being overruled. Against this decision, Porto Seguro filed another appeal (motion to reverse or annul) with the State Court of Rio de Janeiro, and the Fourth Civil Court handed down a unanimous decision on March 30, 2004 requiring PETROBRAS to indemnify PETROQUISA and Porto Seguro the amounts of US $2,359 and US $590 respectively (the latter representing 5% in premium and 20% in attorney’s fees). In view of this decision, PETROBRAS filed special and extraordinary appeals with the Superior Court of Justice and the Supreme Court respectively.
On December 10, 2004, the Official Newspaper of the State of Rio de Janeiro published a decision by the State Court of Rio de Janeiro which ruled against the special and extraordinary appeals filed by PETROBRAS and against the request to forward the case to a higher Court. PETROBRAS now intends to file directly with the Supreme Court. Based on the opinion of its legal advisers, the Company does not expect to obtain an unfavorable ruling in this case. The expectation of loss in this case has been assessed as possible.
F-96
The Fisherman’s Federation of the State of Rio de Janeiro (FEPERJ) filed a civil suit against the Company with the Rio de Janeiro State Court for compensation of miscellaneous damages amounting to US $224, which it is claiming in the name of its members, as a result of the oil spill in Guanabara Bay on January 18, 2000. A decision was handed down on February 7, 2002 which ruled the claim partially without grounds, rejecting pain and suffering, and requiring the Company to pay compensation for material damages and loss of profit to be calculated at the award phase. The ruling expressly declares that it is not reasonable to consider an award based on the amount claimed, since it was without economic base.
Based on its legal counsels opinion, the Company’s Administration believes it is possible that the Company will not prevail in this case, but that any possible negative judgment would be in an amount far below the originally filed complaint. As such, the Company assesses the risk of loss related to this case as possible.
The São Paulo tax authorities filed a tax suit against the Company, alleging that the Company did not pay ICMS levied on interstate sales of naphtha. However, during the period in which according to the State of São Paulo, the Company should have paid the ICMS, the Company was subject to a different tax regime (federal) on these sales, and for this reason enjoyed a tax holiday. The value of the matter in controversy is US $60. There is no guarantee that the final result of the legal case will be favorable to PETROBRAS, but even in the case of an unfavorable ruling, management does not believe that the award could have a material negative impact on the financial position of PETROBRAS. The Company assesses its risk of loss in the matter as possible.
PETROBRAS is a defendant in five labor claims filed by the UNIONS OF PETROLEUM WORKERS of three federal states (Rio de Janeiro, São Paulo and Sergipe), alleging that official inflation rates for 1987, 1989 and 1990 (understatement of the official inflation rate - Bresser, Summer and Collor Plans) were not fully included in the workers’ salaries.
F-97
The lawsuits are at different stages. Based on past favorable decisions in similar cases and on a final understanding of the TST, management does not expect an unfavorable decision in these suits. Three identical cases have been decided in favor of PETROBRAS. Management assesses risk of loss to be remote.
The Company was sued in court by certain small oil distribution companies under the allegation that it does not pass on to state governments the State Value-Added Tax (ICMS) collected according to the legislation upon fuel sales. These suits were filed in the states of Goiás, Tocantins, Bahia, Pará, Maranhão and in the Federal District.
Of the total amount related to in legal actions approximately US $337 up to December 31, 2004, US $28 were placed in escrow to satisfy judicial order.
The Company, with the support of the state and federal authorities, has succeeded in stopping the execution of other withdrawals, and is making all possible efforts to obtain reimbursement of the amounts that were previously withdrawn from its accounts.
The Company received various tax assessments related to social security amounts payable as a result of irregularities in presentation of documentation required by the INSS, to eliminate its joint liability in contracting civil construction and other services, stipulated in paragraphs 5 and 6 of article 219 and paragraphs 2 and 3 of article 220 of Decree No. 3,048/99.
F-98
The Company made a provision for this contingency in the amount of US $105 at December 31, 2002, as it considers the chance of success in a defense filed against the INSS to be remote.
On September 29, 2003, the Company received additional INSS tax assessments related to the joint liability for irregularities in presentation of contractors’ documentation related to periods subsequent to past notifications. During 2004, the Company set up a new provision for contingencies related to the joint liability referring to a period after that to which the assessments referred. PETROBRAS had disbursed during 2004 US $137 (US $103 in 2003), referring to administrative suits filed by the INSS claiming the Company’s joint liability.
At December 31, 2004 the balance of contingencies associated with this joint liability was US $107 (US $95 at December 31, 2003).
Internally, procedures were revised to improve the inspection of contracts and require the presentation of documents, as stipulated in the legislation, to substantiate the payment of INSS amounts due by contractors. PETROBRAS continues to analyze each tax assessment received in order to recover amounts, as permitted through administrative processes of the INSS.
The Internal Revenue Service of Rio de Janeiro filed two Tax Assessments against the Company in connection with Withholding Tax (IRRF) on foreign remittances of payments related to charter of vessels of movable platform types for the years 1998 through 2002.
The Internal Revenue Service, based on Law No. 9,537/97, Article 2, considers that drilling and production platforms cannot be classified as sea-going vessels and therefore should not be chartered but leased. Based on this interpretation, overseas remittances for servicing chartering agreements would be subject to withholding tax at the rate of 15% or 25%.
F-99
The Company disagrees with the Internal Revenue Service’s interpretation as to charter contracts, given that the Federal Supreme Court has already ruled that, in the context of its judgment with respect to the IPI (Federal VAT) tax, offshore platforms are to be classified as sea-going vessels. Additionally, the 1994 and 1999 Income Tax Regulations support the “non-taxation” (RIR/1994) and the “zero tax rate” (RIR/1999) for the remittances in question.
On June 27, 2003, the Internal Revenue Service served a tax assessment notice on the Company amounting to R $3,064 million (US $1,066) covering the period from 1999 to 2002. Using the same arguments, on February 17, 2003, another tax assessment notice had already been issued for R $93 million (US $32) with respect to 1998, against which, on March 20, 2003, the Company filed an appeal. According to the fiscal authorities, the Company should have withheld that tax, incident on remittances made to abroad for payment of the hiring of vessels of the mobile platform type, used in oil exploration and production.
PETROBRAS has defended itself against these tax assessments: i) the smaller in value has been confirmed by the first administrative level, and the corresponding appeal has been already filed by the Company, and waits judgment; ii) no first level decision has been issued so far with regard to the other one, with greater value. Based on its legal counsels advice, the Company’s Administration does not expect to obtain an unfavorable decision in this case, and thus has assessed risk of loss to be possible.
The Company is subject to various environmental laws and regulations. These laws regulate the discharge of oil, gas or other materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of such materials at various sites.
F-100
During 2000 the Company implemented an environmental excellence and operational safety program - PEGASO - (Programa de Excelência em Getão Ambiental e Segurança Operacional). The Company made expenditures of approximately US $2,974 from 2000 to December 31, 2004 under this program. During the years ended December 31, 2004 and 2003 the Company made expenditures of approximately US $594 and US $766 respectively. The Company believes that future payments related to environmental clean-up activities resulting from these incidents, if any, will not be material.
On January 18, 2000, a pipeline from one of the Company’s terminals to a refinery in the Guanabara Bay ruptured, causing a release of crude oil into the bay. On January 19, 2001, the Rio de Janeiro State Prosecutor filed a criminal lawsuit against the Company. The Company is contesting the legal basis for the criminal lawsuit. Additionally, the Federal Prosecutor has filed criminal lawsuits against the former president of the Company (that finished) and 9 other employees. The Company cannot predict if the outcome of these proceedings will have a material adverse effect on the financial condition, results of operations or cash flows of the Company.
The local federal tribunal dismissed the complaint against the Company’s former president, and this dismissal is not subject to appeal.
On April 30, 2002, the judge determined that the Company could not appear as a defendant in this criminal proceeding as a result of an injunction the Company obtained from the court, although the decision is still subject to appeal.
On October of 2003 the judge determined that in regard to one of the employees the suit will be suspended for the period of 2 years, under certain conditions that defendant will have to observe.
In addition, as a result of the spill, on January 27, 2000, the National Council for the Environment enacted a resolution that obligated the IBAMA (Brazilian Institute for the Environment and Renewable Resources), state environmental agencies and local environmental agencies and non-governmental agencies to evaluate the control and prevention measures and environmental licensing status of all industrial facilities for the production of oil and oil products in Brazil. This resolution also mandated that the Company perform an independent environmental audit of all of its industrial installations located in the State of Rio de Janeiro.
F-101
Since 2000, the Company implemented independent environmental audits in all of the Company’s plants located in Brazil that was concluded during December of 2003. The Company implemented 80% of the auditors’ recommendations and intends to implement the remaining 20% during 2004.
On July 16, 2000, an oil spill occurred at the Presidente Getúlio Vargas refinery releasing crude oil in the surrounding area. The Federal and State of Paraná Prosecutors have filed a civil lawsuit against the Company seeking US $1,176 in damages, which have already been contested by the Company. Additionally, there are two other actions pending, one by the Instituto Ambiental do Paraná (Paraná Environmental Institute) and by another civil association called AMAR that have already been contested by the Company. The Company cannot predict whether these proceedings will have a material adverse effect on the financial condition, results of operations or cash flow of the Company.
On November 4, 2000, the Cypriot flag vessel Vergina II chartered by PETROBRAS collided with the south pier at the Company’s Almirante Barroso terminal in São Sebastião and spilled oil in the São Sebastião canal. As a result of the accident, the Company was fined approximately US $30 by various local environmental agencies. The Company is currently contesting these fines.
On February 16, 2001, the Company’s Araucária-Paranaguá pipeline ruptured and as a result fuel oil was spilled into the Sagrado, Meio, Neves and Nhundiaquara Rivers located in the state of Paraná. As a result of the accident, the Company was fined approximately US $80 by the Instituto Ambiental do Paraná (Paraná Environmental Institute), which was contested by the Company through administrative proceeding but the appeal was rejected.
On March 15, 2001, a spill resulting from the accident involving the P-36 platform occurred, causing a release of diesel fuel and crude oil. The Company was fined by the IBAMA US $3 in April of 2001 for the spill and improper use of chemicals to disperse the oil. The Company is currently contesting these fines.
F-102
On May 12, 2003, the rupture of a connection socket on a production line at well FZB-71, on the Belém Farm field, in the city of Aracati-CE, resulted in the spill of approximately 7 (seven) thousand liters of oil at an area located far from any communities or water sources. The Company’s Contingency Plan was immediately activated and cleaning work for the area was carried out. PETROBRAS was charged with a penalty of US $0.04 by the Environment Superintendence of the State of Ceará (Semace) and up to 90% of this amount can be reduced by compliance with a Commitment Term entered into with the referred environmental entity.
On June 3, 2003, a fault in the connection of one of the unloading arms of vessel Nordic Marita, anchored at the Maritime Terminal Almirante Barroso (Tebar), in São Sebastião, on the North coast of São Paulo, caused a spill of approximately 27 thousand liters of oil from Campos basin. As a result of this accident, PETROBRAS was charged with a penalty of US $0.17 by the IBAMA and of US $0.12 by Basic Sanitation, Technology and Environment Protection Agency of the State of São Paulo (CETESB). An appeal was filed against both charges based on the understanding that the Company acted in the most efficient possible manner in order to minimize possible impacts on the environment.
On August 26, 2003, the rupture of a pipeline between Transpetro’s terminal in Cabiúnas (Macaé) and Duque de Caxias Refinery caused the spill of 20 (twenty) liters of oil in an area of the city of Cachoeiras de Macacu. The Company immediately determined that the oil located in the service area of the pipeline should be removed, and took preventive measures to protect a creek, near to the Soarinhos River, with checks and oil-absorbing materials. In spite of the effective procedures adopted by PETROBRAS and the non-existence of environmental damages, the Company received a fine from IBAMA in the amount of US $0.69, but filed an administrative proceeding with this entity.
The Company’s management considers that any expenses incurred to correct or mitigate possible environmental impacts should not have a significant effect on operations or cash flows.
F-103
The Company is committed to make the following minimum payments related to operating leases as of December 31, 2004:
Minimum operating lease payment commitments
The Company paid US $1,247, US $1,205, and US $1,355 in rental expense on operating leases at December 31, 2004, 2003 and 2002, respectively.
On November 25, 2004, the Board of directors of PETROBRAS approved the execution of a contract in the amount of up to US $378.5 between the National Bank for Economic and Social Development (BNDES) and the wholly-owned subsidiary PETROBRAS NETHERLANDS B.V. – PNBV for the financing of Brazilian assets and services to be used in the construction of the P-52 production platform, the construction contract for which was signed on December 19, 2003 with FSTP Pte. Ltd. (Consortium FelsSetal/Technip).
The amount will be provided by BNDES within the BNDES-Exim post-shipment program, under the buyer credit standards. The financing will be amortized over a 10-year period after conclusion of the platform construction work, expected for 2006. The interest rate will be the 36-month LIBOR plus 2% during the grace period and the 60-month LIBOR plus 2% thereafter. Other credit lines are also being negotiated with Banco BNP Paribas, the agent bank of the financing obtained from the BNDES, and with European and North-American export credit agencies, for the financing of imported platform assets. However, no other credit lines have been finalized as to amount of terms. The loan contract was signed on November 26, 2004 and no cash was received under such loan as of December 31, 2004.
F-104
PETRÓLEO BRASILEIRO S.A. -PETROBRAS
The Company is exposed to a number of market risks arising from the normal course of business. Such market risks principally involve the possibility that changes in interest rates, currency exchange rates or commodity prices will adversely affect the value of the Company’s financial assets and liabilities or future cash flows and earnings. The Company maintains an overall risk management policy that is developed under the direction of the Company’s executive officers.
The Company may use derivative and non-derivative instruments to implement its overall risk management strategy. However, by using derivative instruments, the Company exposes itself to credit and market risk. Credit risk is the failure of a counterparty to perform under the terms of the derivative contract. Market risk is the adverse effect on the value of a financial instrument that results from a favorable change in interest rates, currency exchange rates, or commodity prices. The Company addresses credit risk by restricting the counterparties to such derivative financial instruments to major financial institutions. Market risk is managed by the Company’s executive officers. The Company does not hold or issue financial instruments for trading purposes.
In 2004, PETROBRAS Executive Board organized a Risk Management Committee comprising executive managers of all business areas and of several corporate areas for the purpose of ensuring an integrated management of risk exposures and formalizing the main guidelines adopted by the Company to handle uncertainties regarding its activities. The Risk Management Committee has been created with a view to concentrating risk management information and discussions, facilitating communications with the Board of Directors and the Executive Board concerning corporate governance best practices.
The Company’s foreign currency risk management strategy may involve the use of derivative instruments to protect against foreign exchange rate volatility, which may impair the value of certain of the Company’s obligations. The Company currently uses zero cost foreign exchange collars to implement this strategy.
F-105
During 2000, the Company entered into three zero cost foreign exchange collars to reduce its exposure to variations between the U.S. Dollar and the Japanese Yen, and between the U.S. Dollar and EURO relative to long-term debt denominated in foreign currencies with a notional amount of approximately US $470. The Company does not use hedge accounting for these derivative instruments.
These collars establish a ceiling and a floor for the associated exchange rates. If the exchange rate falls below the defined floor, the counterparties will pay to the Company the difference between the actual rate and the floor rate on the notional amount. Conversely, if the exchange rate increases above the defined ceiling, the Company will pay to the counterparties the difference between the actual rate and the ceiling rate on the notional amount. The contracts expire upon the maturity date of each note.
The Yen zero cost collar contracts were settled on September 8, 2003, with a cash payment of US $68 and one of the Euro zero cost collars was settled on December 31, 2004, with cash reception of US $18.
The call and put portion of the Company’s zero cost foreign exchange collars at December 31, 2004 have a fair value of US $18 and US $3, respectively (US $31 and US $5 at December 31, 2003).
Petroleum and oil products
The Company is exposed to commodity price risks as a result of the fluctuation of crude oil and oil product prices. The Company’s commodity risk management activities primarily consist of futures contracts traded on stock exchanges and options and swaps entered into with major financial institutions. The futures contracts provide economic hedges to anticipated crude oil purchases and sales, generally forecast to occur within a 30 to 360 day period, and reduce the Company’s exposure to volatile commodity prices.
F-106
Petroleum and oil products (Continued)
The Company’s exposure on these contracts is limited to the difference between contract value and market value on the volumes hedged. Crude oil future contracts are marked to market and related gains and losses are recognized currently into earnings, irrespective of when physical crude sales occur. For the years ended December 31, 2004, 2003 and 2002, the Company consummated commodity derivative transaction activities on 33.06%, 40.52% and 42.01%, respectively, of its total import and export traded volumes.
The open positions on the futures market, compared to spot market value, resulted in recognized losses of US $2, US $2 and US $4 during the years ended December 31, 2004, 2003 and 2002, respectively.
A long-term position was executed in January 2001 by the sale of put options for 52 million barrels of West Texas Intermediate (WTI) oil over a period extending from 2004 to 2007, with the objective to obtain price protection for this quantity of oil and to provide the funding institutions of the Barracuda/Caratinga project with a minimum guaranteed margin to cover the debt servicing. The puts were structured to ensure that the financial institutions participating in the financing of the development of the fields receive the price required to generate the minimum required return on investment. The Company accounts for the put options on a mark to market basis. During 2003 and 2002, the Company realized a net gain and US $7 and US $8, respectively. During 2004 the Company realized no gain or losses.
The Company’s interest rate risk is a function of the Company’s long-term debt and, to a lesser extent, short-term debt. The Company’s foreign currency floating rate debt is principally subject to fluctuations in LIBOR and the Company’s floating rate debt denominated in Reais is principally subject to fluctuations in the Brazilian long-term interest rate (TJLP), as fixed by the Brazilian Central Bank. The Company currently does not utilize derivative financial instruments to manage its exposure to fluctuations in interest rates. However, the Company has been studying various forms of derivatives to reduce exposure to interest rate fluctuations and may use these financial instruments in the future.
F-107
PEPSA also uses derivative instruments such as options, swaps and others, mainly to mitigate the impact of changes in crude oil prices, interest rates and future exchange rates. Such derivative instruments are designed to mitigate specific exposures, and are assessed periodically to assure high correlation of the derivative instrument to the risk exposure identified and to assure that the derivative is highly effective in offsetting changes in cash flows inherent in the covered risk. PEPSA qualifies for hedge accounting treatment for its crude oil derivative instruments and its interest rate swap derivative instruments.
As of December 31, 2004, PEPSA did not have commodity derivative transactions that qualify for hedge accounting purposes in accordance with SFAS No. 133 – Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). PEPSA accounted for a loss of US $233 for the year ended December 31, 2004, due to derivative financial instruments that do not qualify for hedge accounting.
Additionally, PEPSA holds an interest rate contract to manage the volatility of the LIBOR rate implied in a Class C negotiable instrument, establishing the respective interest rate at 7.93% annually. If these instruments were to be liquidated, considering the rates used at the date, a net loss of approximately US $1 would be recorded. This contract qualifies for hedge accounting in accordance with SFAS 133.
F-108
In connection with the long-term contract to buy gas (“The Gas Supply Agreement” or “GSA”) to supply thermoelectric plants and for other uses in Brazil, the Company entered into a contract, effective October 2002, with a gas producer that constituted a derivative financial instrument under SFAS 133. This contract, the Natural Gas Price Volatility Reduction Contract (the “PVRC”), with maturity in 2019, was executed with the purpose to reduce the volatility of price under the GSA. The counterparty to the PVRC is one of the gas producers that sell to the supplier under the GSA contract. Therefore, the PVRC refers to the same volumes of natural gas sold by the counterparty to the supplier under the GSA, and uses the same pricing index as the GSA contract and thus works as an economic hedge. The volume covered by the PVRC represents approximately 43% of the anticipated volume under the GSA.
The terms of the PVRC include a straight fixed for floating price swap for the period between inception and 2004, and for the period from 2005 to 2019, a collar with Petrobras receiving cash payments when the calculated price is over the established ceiling and Petrobras making cash payments when the price is below the established floor, with no cash payments being made when the price is between the ceiling and the floor.
The PVRC is being accounted for under SFAS 133 as a derivative instrument, since the Company did not satisfy the documentation required for hedge accounting, and is being marked to its calculated fair value with changes in such value recognized in income. At inception, the PVRC had a positive value to Petrobras of US $169, which is deemed a deferred purchase incentive and is being amortized into income on the basis of the volumes anticipated under the PVRC. The liability was US $153 at December 31, 2004 and generated a gain in the amount of US $11, net of deferred tax effect of US $5.
As of December 31, 2004, the Company recorded a derivative asset based on the fair value calculation in the amount of US $635, and a mark-to-market (or “MTM”) gain in the amount of US $365, net of deferred tax effect of US $188. Such MTM gains represent the increased value of the derivative from inception to December 31, 2004. The derivative gains are recorded as a component of financial income. The effects of the PVRC were not recognized from inception but the impact was immaterial and has been cumulatively recognized in 2004.
F-109
Considering that there are no market quotations for natural gas for such a long duration as that of the PVRC, the fair value was calculated based on simulation using a mean reversion model developed by Petrobras. The most significant model assumptions at December 31, 2004 include starting prices of crude oil of US $39.53 per barrel, an average fuel oil basket (i.e., the price index of the GSA) of US $23.58 per barrel and a volatility of crude oil of 25% a.a. Other parameters of the model, including the long run average of crude oil, fule oil spread to crude, correlations and inflation indexes were estimated based on historical averages.
A US $1 per barrel increase in the market price of crude under the PVRC would result in a US $24 million increase in the fair value of the derivative at December 31, 2004.
As indicated above, the accounting impacts recognized are in accordance with SFAS 133, whereas the economic impact and cash flow results of the transaction are to fix the price paid for natural gas imports within a range and to receive or pay cash for price fluctuations under the GSA beyond those capped amounts. Such ceiling and floor amounts in the PVRC allow the purchase of natural gas at a price level appropriate to Petrobras, which then sells the gas in local market to distributors at a price level that will allow the sustained development of the natural gas market in Brazil.
In the normal course of its business, the Company uses various types of financial instruments. These instruments include recorded assets and liabilities, and also items such as derivatives, which principally involve off-balance sheet risk.
Substantial portions of the Company’s assets including financial instruments are located in Brazil and substantially all of the Company’s revenues and net income are generated in Brazil. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, government securities, the Petroleum and Alcohol account, trade receivables and future contracts.
F-110
The Company takes several measures to reduce its credit risk to acceptable levels. All cash equivalents in Brazil are maintained with major banks. Time deposits in U.S. dollars are placed with creditworthy institutions in the United States. Additionally, all of the Company’s available for sale securities and derivative contracts are either exchange traded or maintained with creditworthy financial institutions. The Company monitors its credit risk associated with trade receivables by routinely assessing the creditworthiness of its customers. At December 31, 2004 and December 31, 2003, the Company’s trade receivables were primarily maintained with large distributors.
Fair values are derived either from quoted market prices where available, or, in their absence, the present value of expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year end. Fair values of cash and cash equivalents, trade receivables, the Petroleum and Alcohol account, short-term debt and trade payables approximate their carrying values. The fair value for the Company’s available for sale government securities equals their carrying value.
The fair values of other long-term receivables and payables do not differ materially from their carrying values.
The Company’s debt included US $12,145 at December 31, 2004 and US $11,888 at December 31, 2003 and had estimated fair values of US $12,725 and US $12,690, respectively. The Company’s project financings obligation, resulting from FIN 46 consolidation was US $4,399 at December 31, 2004 and US $5,066 at December 31, 2003, and had an estimated fair value of US $4,470 and US $5,115, respectively.
F-111
The following segment information has been prepared in accordance with SFAS No. 131 - Disclosure about Segments of an Enterprise and Related information (“SFAS 131”). The Company operates under the following segments, which are described as follows:
The items that cannot be attributed to the other areas are allocated to the group of corporate entities, especially those linked with corporate financial management, overhead related with central administration and other expenses, including actuarial expenses related with the pension and health-care plans.
F-112
The accounting information by business area was prepared based on the assumption of controllability, for the purpose of attribution to the business areas only items over which these areas have effective control.
The main criteria used to record the results and assets by business segments are summarized as follows:
F-113
NOTES TO THE CONSOLIDATED FINANCIAL INFORMATION
The following presents the Company’s assets by segment:
Non current assets
F-114
F-115
F-116
F-117
Revenues and net income by segment are as follows:
Net operating revenues to third parties
Inter-segment net operating revenues
Exploration, including exploratory dry holes and impairment
Financial income (expenses), net
Income (loss) before income taxes and minority interest
Income tax benefits (expense)
F-118
F-119
Income (loss) before income taxes and minority interest and accounting change
Net operating revenues and Costs of sales relative to 2003 were reclassified between the International segment and Supply segment in relation to offshore operations that were being allocated to the international segment. There was no significant impact on the results reported for these segments.
F-120
F-121
F-122
F-123
Capital expenditures incurred by segment for the years ended December 31, 2004, 2003 and 2002 are as follows:
The Company’s gross sales, classified by geographic destination, are as follows:
The total amounts sold of products and services to the two major customers in 2004 were US $4,269 and US $3,108 (US $3,498 and US $2,688 in 2003; and US $2,693 and US $2,549 in 2002).
F-124
PETROLEO BRASILEIRO S.A. - PETROBRAS
The Company is controlled by the Federal Government and has numerous transactions with other state-owned companies in the ordinary course of its business.
Transactions with major related parties resulted in the following balances:
PETROS (Pension fund)
Banco do Brasil S.A.
BNDES (Note 13 (b))
Federal Government
Restricted deposits for legal Proceedings
Petroleum and Alcohol account - Receivable from Federal Government (Note 12)
F-125
These balances are included in the following balance sheet classifications:
Accounts receivable (Note 7)
Petroleum and Alcohol account - receivable from Federal Government (Note 12)
Pension Fund
F-126
NOTES TO THE CONSOLIDATED FINANCIAL INFORMATION (Continued)
The principal amounts of business and financial operations carried out with related parties are as follows:
BRASKEM S.A.
Centrais Elet. do Norte do Brasil
S.A. – Eletronorte
COPESUL S.A.
Manaus Energia S.A.
Petroquímica União S.A.
Petroleum and Alcohol account - Receivable from Federal
Government (Note 12)
The Company’s accounting for exploratory drilling costs is governed by Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (SFAS No. 19). On April 4, 2005, the Financial Accounting Standards Board (FASB) adopted FASB Staff Position (FSP SFAS 19-A) that amended SFAS No. 19 with respect to the deferral of exploratory drilling costs.
Costs the Company has incurred to drill exploratory wells that find commercial quantities of oil and gas are carried as assets on its balance sheet under the classification “unproved oil and gas properties.” Each year, the Company writes off the costs of these wells unless (1) the well is in an area requiring major capital expenditure before production can begin and (2) additional exploratory drilling is under way or firmly planned to determine whether the capital expenditure is justified.
F-127
As of December 31, 2004, the total amount of unproved oil and gas properties was US $1,684, and of that amount US $840 (US $779 of which related to projects in Brazil) represented costs that had been capitalized for more than one year, which generally are a result of (1) extended exploratory activities associated with offshore production and (2) the transitory effects of deregulation in the Brazilian oil and gas industry, as described below.
In 1998, the Company’s government-granted monopoly ended and the Company signed concession contracts with the Agência Nacional de Petróleo (National Petroleum Agency, or ANP) for all of the areas the Company had been exploring and developing prior to 1998, which consisted of 397 concession blocks. Since 1998, the ANP has conducted competitive bidding rounds for exploration rights, which has allowed the Company to acquire additional concession blocks. After a concession block is found to contain a successful exploratory well, we must submit an “Evaluation Plan” to the ANP for approval. This Evaluation Plan details the drilling plans for additional exploratory wells. An Evaluation Plan is only submitted for those concession areas where technical and economic feasibility analyses on existing exploration wells evidence justification for completion of such wells. Until the ANP approves the Evaluation Plan, the drilling of additional exploratory wells cannot commence. If companies do not find commercial quantities of oil and gas within a specific time period, generally 4-6 years depending on the characteristics of the exploration area, then the concession block must be relinquished and returned to the ANP. Because the Company was forced to assess a large volume of concession blocks in a limited time frame even when an exploratory well has found sufficient reserves to justify completion and additional wells are firmly planned, finite resources and expiring time frames in other concession blocks have dictated the timing of the planned additional drilling.
F-128
The following table shows the net changes in capitalized exploratory drilling costs during 2004, 2003 and 2002:
Unproved Oil and Gas Properties
Beginning balance at January 1
Acquisition of reserves
Write offs
Transfers to proved reserves
Cumulative Translation Adjustment
Ending balance at December 31
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of the drilling:
Aging of Capitalized Exploratory Well Costs
Capitalized exploratory well costs that have been capitalized for a period of one year or less
Capitalized exploratory well costs that have been capitalized for a period greater than one year
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
F-129
Of the US $840 for 40 projects that include wells suspended for more than one year since the completion of drilling, approximately US $766 are associated with 26 offshore projects. Activities associated with assessing the reserves and the projects’ economic viability include, but are not limited to: (a) US $224 – negotiations with potential customers of natural gas (three projects), (b) US $60 – discussions with operators for the joint development of two projects and (c) US $54 – negotiation of commercial terms with partner. Included in the US $840 of exploratory well costs that have been capitalized for a period of greater than one year since the completion of drilling is US $321.5 associated with 29 wells completed before 2002.
Additionally, for each of the 40 projects that include wells suspended for more than one year since the completion of drilling, we have submitted an “Evaluation Plan” to the ANP for approval. As described above, the submission of an Evaluation Plan indicates that the Company has found the wells to have economic feasibility.
The adoption of SFAS 19, as amended, will not have a material effect on its financial position or results of operations for any period.
On March 2, 2005, the Company completed the negotiations and executed the documents for raising permanent financing for the Project. The loan comprises a total of US $910, provided by Japan Bank for International Cooperation, a group of Commercial Banks, led by Mizuho Corporate Bank, and a consortium between Mitsubishi Corporation and Marubeni Corporation. The project finance structure utilizes a special purpose company named PDET Offshore S.A., which is the entity to borrow the funds, to own all Project assets and to rent such assets to Petrobras for 12 years, counted from the date of completion of the assets or March 2007, whichever happens first.
F-130
On March 24, 2005, a Term Sheet was signed with MPX, owner of the thermoelectric power plant Termoceará in the northeastern state of Ceará, containing terms and conditions for suspension of the arbitration proceedings and court lawsuits underway. After signature of the Term Sheet, a due diligence process was begun and a Consortium Agreement was signed, and the obligations of other related contracts were suspended for a period of 90 days. If the process for the due diligence and detailing of the acquisition operation occurs satisfactorily, the Participation Agreement is to be transformed into a Sale Agreement. The total price of the company, as agreed between the parties, is US$ 137 million, including settlement of debts. This thermoelectric plant is consolidated in the financial statements of 2003 and 2004 as a FIN 46 variable interest entity to which Petrobras is the primary beneficiary. Upon acquisition of a 100% equity interest in MPX, Petrobras will account for the transaction under FAS 141 as a purchase business combination.
The documentation pursuant to the acquisition of Sociedade Fluminense de Energia (SFE), the owner of Eletrobolt, was signed April 29, 2005, thus concluding the acquisition process. The agreed-upon price of its shares is US$ 65 million. With this acquisition, the Consortium Agreement has been terminated and all the obligations arising thereunder have ceased.
On April 8, 2005, PETROBRAS received correspondence from the law firm Pinheiro Netos Advogados, attorneys for Alliance Capital Management L.P., a limited partnership organized and existing in accordance with the Laws of the State of Delaware, United States of America, with registered offices at 1345 Avenue of the Americas, in the City of New York, State of New York, U.S.A. (“ACMLP”), in its capacity as manager of funds and/or investments of discretionary clients domiciled overseas, communicating in the manner prescribed by Article 12, heading, of CVM Instruction No. 358/02, that they had acquired through stock market transactions carried out either directly or through American Depositary Receipts — ADR - the amount of 23.859.771 (twenty-three million, eight hundred and fifty-nine thousand, seven hundred and seventy-one) preferred shares issued by PETROBRAS, a portion that corresponds to 5,16% of the Company’s preferred stock. This operation involves a minority investment that does not alter either the Company’s ownership or administrative structure.
ACMLP does not aim to hold any quantity of shares issued by the Company and nor do any of its subsidiaries or associated companies hold securities issued by the Company.
There are no share-convertible debentures held either directly or indirectly by ACMLP or by any parties related to it, nor is there any agreement or contract regulating voting rights or the purchase and sale of securities issued by the Company to which ACMLP or any party related to it is a party.
On April 29, 2005, ODEBRECHT S.A., NORDESTE QUÍMICA S.A. - NORQUISA, ODBPAR INVESTIMENTOS S.A. and PETROBRAS QUÍMICA S.A. - PETROQUISA signed, with the agreement of their respective parent companies, BRASKEM S.A. and PETRÓLEO BRASILEIRO S.A. - PETROBRAS, a Second Addendum to the Stockholders Agreement of BRASKEM, which rescinds the First Addendum and upholds the terms of the memorandum agreement signed in July 03, 2001. The parties have decided to alter the terms and conditions for exercising the option to purchase common shares issued by BRASKEM, granting PETROQUISA the right to own up to 30% of the voting capital of BRASKEM. The Option to be exercised at the discretion of PETROQUISA is valid until December 31, 2005. If the Option is exercised, payment for the shares under the Option is to be made by PETROQUISA contributing to BRASKEM: (a) its equity stakes in petrochemical companies 1ocated at the Petrochemical Complex in Triunfo, State of Rio Grande do Sul, as well as (b) equity stakes in other petrochemical companies considered strategic by BRASKEM. The shares purchased pursuant to the Option shall be appraised based upon the economic value of BRASKEM, as calculated from a discounted cash flow criterion, without consideration of premium, and the value of the Assets to be contributed to BRASKEM by PETROQUISA shall likewise be appraised according to the economic value of the companies involved, obtained based on the discounted cash flow criterion, valued according to the same criteria and on the same base date, without consideration of premium. The Second Addendum took effect April 29, 2005 and will remain in effect until December 31, 2005.
In April 2005, the Venezuelan Ministry of Energy and Oil (MEP) ordered the company Petróleos de Venezuela S.A. (PDVSA) to review the 32 operating agreements signed by its subsidiaries with oil companies between 1992 and 1997, including the agreements entered into by Petrobras Energia Venezuela S.A., subsidiary of PESA which governs the exploration of the Oritupano Leona, La Concepción, Acema and Mata areas. According to the MEP, these operating agreements include clauses that are in direct conflict with the nature of a services agreement, as defined by the 1975 Organic Law of Venezuela which preserves the State’s absolute right to produce and sell hydrocarbons.
Pursuant to these new rulings, necessary measures to conform the agreements, currently in the form of variable capital companies, must be adopted within a 6-month period, and the federal government, through PDVSA, shall be required to hold an interest of more than 50%. In relation to the contracts previously executed, the MEP issued instructions to PDVSA that the total amount of the accumulated payments contracted during any one fiscal year may not exceed 66.67% of the value of the hydrocarbons produced under the corresponding arrangement. On April 15, 2005, PDVSA notified Petrobras Energia Venezuela S.A. of this situation and informed it that shortly the MEP would be setting the date to begin the relevant discussions.
Without express agreement as to the propriety of the claims and rulings asserted by MEP / PDVSA as to the legal standing of the operating arrangements, PESA indicated willingness to begin conversations with PDVSA and Corporacion Venesolana de Petróleo in order to make the required adaptations to the agreements with current validity effect, such that such agreements may continue.
Company management cannot predict either the future development of this contractual review process or the consequences of the results of operations or financial position of the Company in Venezuela.
In May of 2005, the NNPC (Nigerian National Petroleum Corporation) authorized the development of the Akpo offshore oil field, located in Block OML 130. PETROBRAS has a 16% participation in the field and contributed to the exploration and discovery of such in 2000. Respective to the Block, PETROBRAS acts in partnership with the French company, Total, which is the operator, and together with the NNPC and the South Atlantic Petroleum Ltd (Sapetro - a private Nigerian company).
The Akpo Field contains natural and condensed gas reserves and is located 200 km from the Nigerian city of Port Harcourt, in deep waters ranging from 1.100 to 1.700 meters. The Akpo development project encompasses the drilling of 22 production wells, 20 water-injection wells, and 2 gas-injection wells that will be connected to a Floating, Production, Storage and Offloading (FPSO) production unit, with capacity of 2 million barrels. Once operational, expected to occur at the end of 2008, Akpo anticipates a maximum production of 225 thousand barrels of oil equivalent per day, 80% of which will be high quality Light/condensed gas. Crude oil will be transported to vessels moored 2 km from the FPSO. The gas will reach the Bonny Island Liquid Natural Gas plant through a 150-km gas pipeline passing through the Amenan/Kpono platforms, located on the Nigerian continental shelf.
F-131
SUPPLEMENTARY INFORMATION ON OIL AND GAS EXPLORATION AND
PRODUCTION ACTIVITIES (UNAUDITED)
In accordance with SFAS 69 - Disclosures About Oil and Gas Producing Activities (“SFAS 69”), this section provides supplemental information on oil and gas exploration and producing activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations. The information included in items (iv) and (v) present information on PETROBRAS’ estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Beginning in 1995, the Federal Government of Brazil undertook a comprehensive reform of the country’s oil and gas regulatory system. On November 9, 1995, the Brazilian Constitution was amended to authorize the Federal 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 eliminated PETROBRAS’ effective monopoly. The amendment was implemented by the Petroleum Law, which liberated the fuel market in Brazil beginning January 1, 2002.
The Petroleum Law established a new regulatory framework ending PETROBRAS’ exclusive agency and enabling competition in all aspects of the oil and gas industry in Brazil. As provided in the Petroleum Law, PETROBRAS was granted the exclusive right for a period of 27 years to exploit the petroleum reserves in all fields where the Company had previously commenced production. However, the Petroleum Law established a procedural framework for PETROBRAS to claim exclusive exploratory (and, in case of success, development) rights for a period of up to three years with respect to areas where the Company could demonstrate that it had “established prospects.” To perfect its claim to explore and develop these areas, the Company had to demonstrate that it had the requisite financial capacity to carry out these activities, alone or through financing or partnering arrangements.
The “International” geographic includes activities in Angola, Argentina, Bolivia, Colombia, Ecuador, Mexico, Nigeria, Peru, The United States of America and Venezuela. The Company has immaterial non-consolidated companies involved in exploration and production activities; the amounts related to such are in the line item titled “Company’s share of unconsolidated affiliates”.
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PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
The following table summarizes capitalized costs for oil and gas exploration and production activities with the related accumulated depreciation, depletion and amortization, and asset retirement obligation assets:
Unproved oil and gas properties
Proved oil and gas properties
Support equipment
Gross capitalized costs
Depreciation and depletion
Construction and installations in progress
Net capitalized costs
Company’s share by unconsolidated affiliates
F-133
Costs incurred are summarized below and include both amounts expensed and capitalized:
Property acquisitions
Unproved
Exploration costs
Development costs
F-134
The Company’s results of operations from oil and gas producing activities for the years ending December 31, 2004, 2003 and 2002 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the supply segment in Brazil. The prices calculated by the Company’s model may not be indicative of the price the Company would have realized had this production been sold in an unregulated spot market. Additionally, the prices calculated by the Company’s model may not be indicative of the future prices to be realized by the Company after January 1, 2002, when full price deregulation began. Gas prices used are contracted prices to third parties.
Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including such costs as operating labor, materials, supplies, fuel consumed in operations and the costs of operating natural liquid gas plants. Production costs also include administrative expenses and depreciation and amortization of equipment associated with production activities.
Exploration expenses include the costs of geological and geophysical activities and non-productive exploratory wells. Depreciation and amortization expenses relate to assets employed in exploration and development activities. In accordance with SFAS 69, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.
F-135
Net operating revenues:
Sales to third parties (2)
Intersegment (2)
Production costs (3)
Exploration expenses
Depreciation, depletion, amortization
Results before income taxes
Results of operations (excluding corporate overhead and interest cost)
Sales to third parties
Intersegment
Production costs
Company’s share of unconsolidated affiliates
F-136
F-137
The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2004, 2003 and 2002 are shown in the following table. Proved reserves are estimated by the Company’s reservoir engineers in accordance with the reserve definitions prescribed by the Securities and Exchange Commission.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves do not include additional quantities recoverable beyond the term of the concession or contract, or that may result from extensions of currently proved areas, or from application of secondary or tertiary recovery processes not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes which are expected to be recovered as a result of future investments in drilling, re-equipping existing wells and installing facilities necessary to deliver the production from these reserves.
In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
F-138
A summary of the annual changes in the proved reserves of crude oil and natural gas follows:
Worldwide Net Proved Developed and Undeveloped Reserves
Reserves at December 31, 2001
Improved recovery
Extensions and discoveries
Reserves at December 31, 2002
Purchase of reserves in place - PEPSA
Reserves at December 31, 2003
Reserves at December 31, 2004
Net proved Developed Reserves
At January 1, 2001
At December 31, 2001
At December 31, 2002
At December 31, 2003
At December 31, 2004
F-139
The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of SFAS 69. Estimated future cash inflows from production in Brazil are computed by applying year-end prices based upon the Company’s internal pricing methodology for oil and gas to year-end quantities of estimated net proved reserves. Estimated future cash inflows from production related to the Company’s International segment are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indicators, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% midperiod discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.
The information provided does not represent management’s estimate of PETROBRAS’ expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations.
F-140
The arbitrary valuation prescribed under SFAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of PETROBRAS’ future cash flows or the value of its oil and gas reserves.
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Undiscounted future net cash flows
10 percent midyear annual discount for timing of estimated cash flows
Standardized measure of discounted future net cash flows
F-141
The following are the principal sources of change in the standardized measure of discounted net cash flows:
Sales and transfers of oil and gas, net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved, recovery less related costs
Revisions of previous quantity estimates
Net changes in prices and production costs
Changes in future development costs
Accretion of discount
Net change in income taxes
F-142
To the Executive Board and Stockholder of
We have audited the accompanying consolidated balance sheets of PETROBRAS INTERNATIONAL FINANCE COMPANY and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholder’s equity and cash flows, for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PETROBRAS INTERNATIONAL FINANCE COMPANY and its subsidiaries as of December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
February 14, 2005
F-143
Petrobras International Finance Company - PIFCO
(a wholly-owned subsidiary of Petróleo Brasileiro S.A. - PETROBRAS)
In our opinion, the accompanying consolidated statements of operations, of cash flows and of changes in stockholders’ equity for the year ended December 31, 2002 present fairly, in all material respects, the results of operations and cash flows of Petrobras International Finance Company - PIFCO and its subsidiaries for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
F-144
PETROBRAS INTERNATIONAL FINANCE COMPANY AND SUBSIDIARIES
As of December 31, 2004 and 2003
(In thousands of US dollars)
Notes receivable - related parties
Export prepayments – related parties
Restricted deposits for guarantees and others
Property and equipment
Assets related to export prepayments
Export prepayment – related parties
Restricted deposits for guarantees and prepaid expenses
The accompanying notes are an integral part of these financial statements.
F-145
(In thousands of US dollars, except for number of shares and per share amounts)
Liabilities and stockholders’ equity
Notes payable - related parties
Short-term financing
Current portion of long term debt
Unearned income - related parties
Stockholder’s equity
Shares authorized and issued
Common stock - 2004 and 2003 - 50,000 shares, par value US$ 1
Additional paid in capital
Accumulated deficit
Total liabilities and stockholder’s equity
F-146
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2004, 2003 and 2002
Sales of crude oil, oil products and services
Operating expenses:
Lease expense
Net (loss) for the year
F-147
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
Common stock
Capital contribution from PETROBRAS related to transfer of PNBV
Conversion of loans to capital
Balance at end of year
Total stockholder’s equity
F-148
CONSOLIDATED STATEMENTS OF CASH FLOWS
Adjustments to reconcile net (loss) to net cash used in operations
Depreciation and amortization
Net cash used in operating activities
Cash rendered in connection with transfer of subsidiary to PETROBRAS
Cash acquired in connection with transfer of subsidiary from BRASOIL
Marketable securities, net
Issuance of notes receivable – related parties
Collection of principal on notes receivable – related parties
Net investment in direct financing activities from related party
Short-term financing, net issuance and repayments
Principal payments of long - term debt
Proceeds from short term loans - related parties
Principal payments of short term loans – related parties
Proceeds from long term loans - related parties
Capital contribution
Net cash provided by financing activities
Increase in cash and cash equivalents
F-149
Supplemental disclosures of cash flow information:
Interest
Non cash investing and financing transactions
Book value of net assets exchanged for inter-company loan
Capital contribution from PETROBRAS from transfer of PNBV
Receipt of Junior Trust Certificates in exchange of receivables
Assets acquired through capital lease obligations
Increase of capital through conversion of loan payable
Receipt of notes receivable in exchange of Senior Exchangeable Notes issued
Cancellation of Senior Exchangeable Notes issued in exchange of PETROBRAS loans (Note 7(c))
F-150
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Petrobras International Finance Company - PIFCo was incorporated in the Cayman Islands on September 24, 1997 and operates as a wholly-owned subsidiary of PETROBRAS.
The primary objective of Petrobras International Finance Company and its subsidiaries (collectively, PIFCo or the Company) is to purchase crude oil and oil products from third parties and sell the products at a premium to PETROBRAS on a deferred payment basis. Accordingly, intercompany activities and transactions, and therefore the Company’s financial position and results of operations, are affected by decisions made by PETROBRAS. Additionally, to a more limited extent, the Company sells oil and oil products to third parties. PIFCo also engages in international capital market borrowings as a part of the PETROBRAS financial and operating strategy.
On January 2, 2003, the Company entered into a series of transactions as part of a larger corporate restructuring implemented by PETROBRAS. The restructuring included the transfer of PETROBRAS NETHERLANDS B. V. - PNBV to PETROBRAS and the transfer of BEAR INSURANCE COMPANY LIMITED - BEAR from BRASPETRO OIL SERVICES - BRASOIL to PIFCo.
PNBV was transferred to PETROBRAS through an intercompany loan of US$ 4,658, with PNBV’s existing cash balance being US$ 743. BEAR was transferred to the Company in exchange for an intercompany payable to BRASOIL of US$ 1,703, with BEAR’s existing cash balance being US$ 2,988. The restructuring was undertaken in order to group each business’ activities more closely with the corporate goals of the respective companies in the PETROBRAS group.
The corporate restructurings, which resulted in the transfer of PNBV from PIFCo and the transfer of BEAR to PIFCo, were accounted for under FAS 141. Due to the immaterial impact of BEAR on PIFCo’s consolidated financial statements, the financial statements of December 31, 2002 have not been restated to reflect this transfer among commonly controlled entities. Additionally, as PNBV’s operating result was immaterial, the PIFCo financial statements as of December 31, 2002 have similarly not been restated to reflect discontinued operations for disposal of this component.
F-151
In connection with the transfer of PNBV, the Company recognized US$ 39,135 as a capital contribution from PETROBRAS. This amount is equal to the unamortized portion of the deferred gain of the platform P-47 (US$ 37,271) and the deferred gain on other equipment (US$ 1,864) under similar transaction structures, which upon transfer of PNBV to PETROBRAS was treated as a capital transaction. This platform was acquired from BRASOIL in December 2001, for its book value of US$ 142,729. On the same date, the P-47 was sold to PB-47, an independent trust, for a market value of US$ 180,000. PB-47 subsequently entered into a charter agreement with PNBV, which in turn entered into a subcharter agreement with PETROBRAS.
The following is a brief description of each of the Company’s wholly-owned subsidiaries:
PETROBRAS FINANCE LIMITED
PETROBRAS FINANCE LIMITED (PFL), based in the Cayman Islands, in connection with the Company’s structured finance export prepayment program, whereby PFL purchases bunker and fuel oil from PETROBRAS and sells these products in the international market, including sells to designated customers, in order to generate receivables to cover the sale of future receivables.
In May 2003, PIFCo, upon receiving approval from the Board of Directors, contributed an additional US$ 15,000 of capital, bringing PFL’s total capital to US$ 30,000 divided into 30,000,000 quotas of US$ 1.00 each.
PETROBRAS EUROPE LIMITED
PETROBRAS EUROPE LIMITED (PEL), based in the United Kingdom, consolidates PETROBRAS’ European trade and finance activities. These activities consist of advising on and negotiating the terms and conditions for crude oil and oil products supplied to PIFCo and PETROBRAS, as well as marketing Brazilian crude oil and other derivative products exported to the geographic areas in which the Company operates. PEL plays an advisory role in connection with these activities and undertakes no commercial or financial risk.
BEAR INSURANCE COMPANY LIMITED
BEAR INSURANCE COMPANY LIMITED (BEAR), based in Bermuda, contracts insurance for PETROBRAS and its subsidiaries.
F-152
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (US GAAP).
The Company’s functional currency is the US dollar. All monetary assets and liabilities denominated in a currency other than the U.S. dollar are remeasured into the U.S. dollar using the current exchange rates. The effect of variations in the foreign currencies is recorded in the statement of operations as financial expense.
Cash equivalents consist of highly liquid investments that are readily convertible into cash and have an original maturity of three months or less at their date of acquisition.
For all third party and related party transactions, revenues are recognized in accordance with the U.S. SEC Staff Accounting Bulletion 104 – Revenue Recognition. Crude oil and oil products revenues are recognized on an accrual basis when persuasive evidence of our arrangement exists in the form of a valid contract, delivery has occurred or title has transferred, the price is fixed or determinable and collectability is reasonably assured. Costs are recognized when incurred. Income and expenses include financial interest and charges, at official rates or indexes, relating to current and non-current assets and liabilities and, when applicable, the effects arising from the adjustment of assets to market or realizable value.
The principle commercial transactions of the Company consist of:
Imports – the company buys from suppliers outside Brazil (mainly from third-parties) and sells to PETROBRAS and its Brazilian subsidiaries.
F-153
Exports – the Company buys from PETROBRAS and sells to customers outside Brazil (mainly to related-parties).
Off-shore – the Company buys and sells mainly outside of Brazil, in transactions with third-parties and related parties.
These are stated at their cost, which approximates net realizable values.
Inventories are stated at the lower of cost or market value.
Deferred financing costs associated with various debt issuances are recorded as prepaid expenses and are being amortized over the terms of the related debt, based on the amount of outstanding debt, using the effective interest method. The unamortized balance of deferred financing costs was US$ 79,748 and US$ 80,513 as of December 31, 2004 and 2003, respectively.
F-154
These are stated at known or estimated amounts including, when applicable, accrued interest.
Unearned income represents the unearned premium charged by the Company to PETROBRAS and ALBERTO PASQUALINI - REFAP S.A. (REFAP) to compensate for its financing costs. The premium is billed to PETROBRAS and REFAP at the same time the related product is sold, and is deferred and recognized into earnings as a component of financial income on a straight-line basis over the collection period, which ranges from 120 to 270 days
All of the Company’s derivative instruments are recorded on the balance sheet at their fair value. The changes in the market value of derivative instruments that do not qualify for hedge accounting are recognized in the statement of operations as financial income or expense each reporting period. The ineffective portion of all hedges is recognized in current period earnings.
PIFCo holds a purchased put option that allows the holder to sell a floating number of crude oil volumes at a minimum floor price of US$14/barrel. Such option serves as an economic hedge on related future sales of receivables under the structured finance export prepayment program, the intent of which is to assure that physical barrels delivered under the project finance agreement generate sufficient cash proceeds to repay related financial obligations. This option has no intrinsic value and immaterial time value at December 31, 2004, and therefore does not have a material effect on the Company’s results of operations or financial position.
F-155
The Company accounts for income taxes using an asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax liabilities and assets representing the future tax consequences of events that have been recognized in the Company’s financial statements. The measurement of current and deferred tax liabilities and assets are based on the provisions of the tax laws in the countries in which the Company and its subsidiaries operate (the United Kingdom, Bermuda and the Cayman Islands in 2004 an 2003 and the United Kingdom, Netherlands and the Cayman Islands in 2002). Deferred tax assets are reduced by the amount of any tax benefits when, based on the available evidence, such benefit may not be realized. The Cayman Islands and Bermuda have no corporate tax requirements, therefore the Company has no tax provision for the periods. There were no significant operations in the United Kingdom or the Netherlands that gave rise to taxable income in these countries that would have created temporary differences.
As of January 2, 2003, PNBV, the Company’s leasing subsidiary, was transferred to PETROBRAS. Due to this transaction, leasing activities are no longer included in the Company’s results of operations. Prior period financial statements have not been restated for the effect of discontinued leasing operations as amounts related to these transactions were immaterial to PIFCo operations.
Through December 31, 2002, the Company had capital leases on operating platforms and production equipment (see Note 9), and subsequently leased this equipment to related parties through charter agreements.
Income and expense on financing leases, consisting of interest income, was recognized over the lease term. Income and expense from operating leases was recognized ratably over the terms of the leases.
F-156
Certain immaterial reclassifications have been completed respective to prior period financial statements to conform to presentation standards adopted at December 31, 2004.
Cash and banks
Time deposits and short term investment funds
Security
Held to Maturity
Available for Sale
Less: Current balances
F-157
Marketable securities are comprised of amounts the Company has invested in the exclusive fund, absent the Company’s own securities, which are considered repurchased. The exclusive fund is consolidated by PETROBRAS, and the equity and debt securities within the portfolio are classified as held to maturity, trading or available for sale under SFAS 115 based on management’s intent. The trading securities are presented as current assets, as they are expected to be used in the near term for cash funding requirements; available for sale securities are presented as other long-term assets, as they are not expected to be sold or liquidated in the next twelve months. Amounts related to 2003, have been reclassified from cash and cash equivalents.
At December 31, 2004 and 2003, the exclusive fund held debt securities of PIFCo and PIFCo subsidiaries in the amount of US$ 149,227 and US$ 54,004, respectively. These amounts were offset against the related balances of current and non current liabilities.
F-158
PETRÓLEO
BRASILEIRO
S.A. -
INTERNATIONAL
BRASPETRO B.V.
-
PIB.B.V. and its
subsidiaries
DOWNSTREAM
PARTICIPAÇÕES
S.A.
and its
subsidiaries (iii)
BRASPETRO
OIL SERVICES -
BRASOIL
OIL COMPANY -
BOC
Accounts receivable, principally for sales (i)
Export prepayment
Notes payable (ii)
Notes payable (iii)
Statement of operations
Purchases (iv)
Lease income, net
Commercial operations between PIFCo and its subsidiaries and affiliated companies are carried out under normal market conditions and at commercial prices, except for the sales of oil and oil products to PETROBRAS, which have an extended settlement period consistent with PIFCo’s formation as a financing entity, and include finance charges incurred during the extended payment period.
The transactions were realized to support the financial and operational strategy of the Company’s Parent Company, PETRÓLEO BRASILEIRO S.A. - PETROBRAS.
F-159
GLP
PIFCo has deposits in guarantee, relating to contractual obligations in financing arrangements. The amount of US$ 70,861 classified in current assets, relates to a deposit made in connection with the issuance of global notes in the amount of US$ 500,000 (described in note 8 (f)) and is renewed annually. The amount classified in non-current assets is comprised of deposits of US$ 29,728 and US$ 38,637 related to issuances of senior notes in the total amount of US$ 450,000 and US$ 600,000, respectively (described in note 8 (a)). These guarantees will be maintained through maturity of the related financings.
F-160
Financial institutions (i)
Global notes
Global step-up notes
Assets related to export prepayment to be offset against sales of rights to future receivables (b)
Repurchased securities (e)
Financing
At December 31, 2004 and 2003, the Company had fully utilized all available lines of credit for purchase of imports.
F-161
Long term financing – additional information
Date of issuance
Interest rate
Senior Notes (a)
Senior Notes
Sale of Future Receivables (b)
Junior Trust Certificates
Serie 2001-A1
Serie 2001-A2
Serie 2001-B
Serie 2001-C
Serie 2003-B
Serie 2003-A
Assets related to export
prepayment to be offset against
sales of rights to future
receivables(b)
Senior Trust Certificates
Senior Exchangeable Notes (c)
Global Step-up Notes (d)
repurchased (e)
Global Notes (f)
F-162
Long term financing – additional information (Continued)
PETROBRAS entered into standby purchase agreements in support of the obligations of PIFCo under the issuances and their respective indentures. PETROBRAS has the obligation to purchase from the noteholders any unpaid amounts of principal, interest or other amounts due under the notes and the indenture. This purchase obligation exists, subject to certain limitations, irrespective of whether any such amounts are due at maturity of the notes or otherwise.
F-163
As stipulated in the contracts, PFL assigned the rights to future receivables in the amount of US$ 1,800,000 (1st and 2nd tranches) to PF Export, which, in turn, issued and delivered to PFL the following securities, also in the amount of US$ 1,800,000:
As long as any Senior Trust Certificates or amounts payable to the insurers that are guaranteeing the payments to the holders of the Senior Trust Certificates remain outstanding, PETROBRAS is required to export to the Company, during each quarterly delivery period, (a) at least 80% of the total volume of heavy fuel oil exported by Petrobras during such period and (b) certain oil products having an aggregate value (as determined by the net invoice amount at which such products are actually sold by PFL) equal to, at least, the debt service requirements of the Senior Trust Certificates multiplied by a coverage ratio. Moreover, certain additional receivables, as defined in the agreement documents, are to be generated by the sale of eligible products to other buyers, to make the aggregate amount of both exports and additional receivables equal to 1.2 times the debt service. PETROBRAS also agrees that its average daily gross exports of heavy fuel oil for any rolling 12-month period will be equal to at least 70,000 barrels.
F-164
PETROBRAS will not be relieved of its obligations to deliver the oil products under the export prepayment program in the amounts set forth for any reason, including, but not limited to force majeure or non-payment by PFL.
In May 2004, PFL and the PF Export Trust executed an amendment to the Trust Agreement allowing the Junior Trust Certificates to be set-off against the related Notes, rather than paid in full, after fulfillment of all obligations pursuant to the Senior Trust Certificates. The effect of this amendment is that amounts related to the Junior Trust Certificates are now presented net, rather than gross in these consolidated financial statements, and thus US$ 300,000 has been reduced from the long term financing respective to sales of rights to future receivables, with a similar reduction to the asset line item titled “assets related to export prepayments”.
F-165
On December 10, 2003, the Company issued Global Notes in an aggregate principal amount of US$ 750,000 due December 2018. The notes will bear interest at the rate of 8.375% per annum, payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt and inter-company loans.
On September 15, 2004, the Company issued Global Notes in an aggregate principal amount of US$ 600,000 due September 2014. The notes will bear interest at the rate of 7.75% per annum, payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt and inter-company loans.
F-166
Long-term maturities
Thereafter
Fair values are derived either from quoted market prices available, or, in their absence, the present value of expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year end. Fair values of cash and cash equivalents, trade receivables, short-term debt and trade payables approximate their carrying values. For 2003, fair value for long-term lines of credit approximates carrying value due to the nature of the transactions.
At December 31, 2003, the Company’s long-term debt was US$ 5,825,336, of which US$ 5,447,786 related to senior notes, sales of future receivables, senior exchangeable notes, global step-up notes and global notes, which had estimated fair values of US$ 5,898,000.
For 2004, long-term lines of credit had fair values immaterially different from their book values. At December 31, 2004 the Company’s long-term debt was US$ 6,151,802 and had an estimated fair value of approximately US$ 6,576,000.
The Company’s long-term asset related to the export prepayment program was US$ 1,261,820 and US$ 1,706,850 at December 31, 2004 and 2003, and had fair values of US$ 1,252,000 and US$ 1,717,000, respectively.
F-167
In an effort to ensure procurement of oil products for the Company’s customers, the Company currently has several short-term contracts which collectively obligate it to purchase a minimum of approximately 57,412 barrels of crude oil and oil products per day at market prices.
The Company has maintained the right to exercise the call option on the existing Subchartered Asset Option Agreements with PNBV, for the Platforms P-8, P-15, P-32 and P-47, after the expiration of the Charter terms with PNBV. Upon exercise of the call option, the Company will purchase all of the vessels for the greater of (i) the purchase price, any unpaid and accrued charter hire for all of the vessels, or any costs and expenses which PNBV has incurred or may incur by virtue of any such purchase, and the amount equal to the default amount set forth in each of the charters for all of the Vessels; and (ii) Ten (10) dollars from PNBV, representation or warranty of any kind or character, and assume and succeed to all rights, duties and obligations of PNBV under the charters.
PIFCo may designate any affiliate or subsidiary to perform its obligations under this agreement.
F-168