SECURITIES AND EXCHANGE COMMISSION
FORM 20-F
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934for the fiscal year ended December 31, 2002
Commission File Number 1-15106
PETRÓLEO BRASILEIRO S.A. – PETROBRAS
Securities registered or to be registered pursuant to Section 12(b) of the Act:
*Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stockas of the close of the period covered by this Annual Report:
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.
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TABLE OF CONTENTS(continued)
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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:
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.
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.
The audited consolidated financial statements of Petrobras and our consolidated subsidiaries as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, 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 publish financial statements in Brazil in Reais in accordance with the accounting principles required by Brazilian corporate law and the regulations promulgated by theComissão de Valores Mobiliários (Brazilian Securities Commission, or the CVM)(“Brazilian GAAP”), which differs in significant respects from U.S. GAAP.
PricewaterhouseCoopers Auditores Independentes has audited our financial statements as of and for the years ending December 31, 2002, 2001, 2000, 1999 and 1998. We are required by Brazilian Corporate Law to change auditors every five years and to solicit public bids for selecting auditors. Beginning in June 2003 and through 2005, Ernst & Young Auditores Independentes S/C will serve as our independent auditors.
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 the 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. Accordingly, U.S. dollar amounts presented in this annual report that were derived from the audited consolidated financial statements as of dates or for periods ending subsequent to December 31, 1997 have been translated from Reais at the period-end exchange rate for balance sheet items or the average exchange rate prevailing during the period for income statement and cash flow items.
Unless the context otherwise indicates,
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The December 31, 2002 exchange rate represented a 52.3% depreciation of the Real against the U.S. dollar since December 31, 2001, and the December 31, 2001 exchange rate represented an 18.7% depreciation of the Real against the U.S. dollar since December 31, 2000. The use of a different Real/U.S. dollar exchange rate would substantially change the remeasured amounts.
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.
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ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
ITEM 3. KEY INFORMATION
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, 2002 have been derived from our audited consolidated financial statements, which were audited by PricewaterhouseCoopers Auditores Independentes. The information below should be read in conjunction with, and is qualified in its entirety by reference to, the audited consolidated financial statements and the accompanying notes and Item 5 “Operating and Financial Review and Prospects.”
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BALANCE SHEET DATA
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INCOME STATEMENT DATA
Exchange Rates
There are two principal foreign exchange markets in Brazil, the commercial rate exchange market and the floating rate exchange market.
On January 13, 1999, the Brazilian government announced the unification of the exchange positions of the Brazilian financial institutions in the commercial rate exchange market and floating rate exchange market, which led to a convergence in the pricing and liquidity of both markets. However,
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complete unification has not yet occurred and each market continues to be subject to specific regulation. The Brazilian government also allowed an increase in the exchange positions of institutions authorized to trade foreign currency to provide further liquidity to the foreign exchange markets. Most trade and financial transactions are carried out on the commercial rate exchange market. These transactions include 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 are generally carried out on the floating rate exchange market. Foreign currencies may only be purchased through Brazilian financial institutions authorized to operate in these markets. In both markets, rates are freely negotiated but may be influenced by the intervention of the Central Bank of Brazil.
From 1995 through January 1999, the Central Bank of Brazil allowed the gradual devaluation of the Real against the U.S. dollar by introducing new exchange rate policies that established a band within which the Real/U.S. dollar exchange rate could fluctuate (faixa de flutuação, or fluctuation band), and by agreeing to buy or sell, as applicable, U.S. dollars whenever the rate approached the upper or the lower limit of the band. Responding to pressure on the Real, on January 13, 1999, the Central Bank of Brazil widened the foreign exchange rate band. Because the pressure did not ease, on January 15, 1999, the Central Bank of Brazil allowed the Real to float freely. Since 1999, the Central Bank of Brazil has continued to allow the Real to float freely.
The Real devalued 9.3% in 2000, 18.7% in 2001, and 52.3% in 2002 against the U.S. dollar. As of June 13, 2003, the Real has appreciated to R$2.857 per U.S.$1.00, representing an appreciation of approximately 24.0% in 2003. The Real may depreciate or appreciate substantially in the future. See “—Risk Factors—Risks Relating to Brazil.”
The following table sets forth the commercial selling rate for U.S. dollars for the periods and dates indicated. The average exchange rates represent the average of the month-end exchange rates (R$/U.S.$) during the relevant period.
COMMERCIAL SELLING RATE FOR U.S. DOLLARS
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.”
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Risk Factors
Risks Relating to Our Operations
Our operations are affected by the volatility of prices for crude oil and oil products.
Until January 2, 2002, the prices we were allowed to charge for crude oil and oil products (and, as a result, our recorded prices for the calculation of net operating revenues) were determined on the basis of a pricing formula established by the Brazilian government designed to reflect changes in the Real/U.S. Dollar exchange rate and international market prices for relevant benchmark products. However, as of January 2, 2002, the crude oil and oil products markets in Brazil were deregulated in their entirety.
Historically, international prices for crude oil and oil products have fluctuated widely as a result of many factors. We do not, and will not, have control over the factors affecting international prices for crude oil and oil products. These factors include:
The average prices of Brent crude, an international benchmark oil, were approximately U.S.$25.02 per barrel for the year ended December 31, 2002, U.S.$24.44 per barrel for the year ended December 31, 2001 and U.S.$28.50 per barrel for the year ended December 31, 2000.
Changes in crude oil prices typically result in changes to prices for oil products. Lower crude oil prices have various effects on us, including decreasing our net operating revenues, net income and cash flows. In comparison, higher crude oil prices generally lead to increases in our net operating revenues, net income and cash flows.
We expect continued volatility and uncertainty in international prices for crude oil and oil products. Declines in international crude oil prices may adversely affect our business, results of operations and financial condition and the value of our proved reserves.
Prices remain regulated for natural gas, electricity and certain petrochemicals. These controls could have an adverse effect on revenues from these business activities.
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Because of changes in government regulations, we face increased competition and may lose market share.
Substantial changes have been occurring in the oil and gas industry in Brazil as a result of the continuing process of deregulation by the Brazilian government. As part of this deregulation, the Brazilian government eliminated all price controls on crude oil and oil products in early 2002. Prices remain regulated, however, for natural gas, electricity and certain petrochemicals. The changes in government regulation have enabled multi-national and regional oil companies to enter the Brazilian energy market. We expect that competition in our downstream and upstream activities will increase further, as existing and new participants expand their activities as a result of these regulatory changes.
Although our prices for crude oil and oil products are based on international prices, in periods of high international prices or sharp devaluations of the Real, we may not be able to adjust our prices in Reais sufficiently to maintain parity with international prices.
Since the Brazilian government’s elimination of all price controls on crude oil and oil products in January 2002, there have been periods of high international prices or sharp devaluations of the Real when we have been unable to increase prices in Reais sufficiently to maintain parity with international prices. While we do not have an obligation to supply the Brazilian market, during periods when the local prices of crude oil and oil products were below prevailing international prices, our competitors were unwilling to supply the local market. In order to ensure adequate supply of crude oil and oil products in Brazil, we sold crude oil and oil products below prevailing international prices.
As a result of deregulation of the Brazilian market, and the elimination of import tariffs in particular, our competitors can sell products in the Brazilian market at parity with international prices. In light of this increased competition, we have less flexibility to maintain local prices above international prices to compensate for revenues not realized in periods in which we sold crude oil and oil products below prevailing international market prices.
We may be required to sell some of our refining capacity in Brazil.
We presently own 98.6% of the existing refining capacity in Brazil. We plan to upgrade our present refineries and we may build new refineries in Brazil, sell participation interests in our present refineries to new partners or engage in asset swaps, as we did through our business combination in 2001 involving assets of Repsol-YPF S.A. Although we are not presently subject to any requirement to divest any assets, and the Brazilian government has not made any proposal in that respect, it is possible that we will be required to divest a portion of our refining capacity or other assets in the future. Any such divestiture could have a material adverse effect on our financial condition and results of operations.
Our ability to achieve growth is dependent upon our finding or acquiring additional reserves, as well as successfully developing current reserves, and risks associated with drilling may cause drilling operations to be delayed or cancelled.
Our ability to achieve our growth objectives is highly dependent upon our level of success in finding, acquiring or gaining access to additional reserves, as well as successfully developing current reserves. In general, the volume of production from crude oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. 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.
Our exploration and development activities expose us to the inherent risks of drilling, including the risk that no economically productive crude oil or natural gas reserves will be discovered. The costs of
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drilling, completing and operating wells are often uncertain and numerous factors beyond our control may cause drilling operations to be curtailed, delayed or cancelled. Our future drilling, exploration and acquisition activities may not be successful and, if unsuccessful, could harm our future results of operations and financial condition.
Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time.
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 numerous uncertainties inherent in estimating quantities of proved reserves. The reliability of proved reserve estimates depends on:
Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect. The results of our future drilling, testing and production activity may lead us to make significant revisions to our reserve estimates.
Our equipment, facilities and operations are subject to numerous environmental and health regulations which may become more stringent in the future and may result in increased liabilities and increased capital expenditures.
Our facilities 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. We could be exposed to civil penalties, criminal sanctions 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. Current and past waste disposal and emissions practices 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 dos Recursos Naturais Renováveis (Brazilian Institute of the Environment and Renewable Natural Resources), or IBAMA, has been investigating our oil platforms in the Campos Basin, and may impose fines, restrictions on operations or other sanctions in connection with its investigations.
We spent approximately U.S.$466 million in 2002, U.S.$473 million in 2001 and U.S.$356 million in 2000 to comply with environmental laws. However, since environmental laws are becoming more stringent in Brazil and in other jurisdictions where we operate, it is likely that our environmental capital expenditures and costs for environmental compliance will increase, perhaps substantially, in the future. In addition, due to the possibility of unanticipated regulatory or other developments, the amount and timing of future environmental expenditures may vary widely from those currently anticipated. The amount of investments we make in any given year is subject to limitations by the Brazilian government. Accordingly, expenditures required for compliance with environmental
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regulation could result in reductions in other strategic investments that we have planned, with a resulting decrease to our profits, and future environmental costs may harm our results of operations or financial condition.
In the past, significant oil spills have occurred and we have incurred, and may continue to incur, liabilities in connection with oil spills, including clean up costs, government fines, and potential lawsuits.
From time to time, oil spills occur in connection with our operations. Since January 1, 2000, we have experienced 11 significant oil spills. In each of these, we undertook cleanup efforts as promptly as possible. Nevertheless, in some situations, we were fined by various state and federal environmental agencies, became the defendant in several civil and criminal suits, and remain subject to several investigations and potential civil and criminal liabilities as a result of past oil spills. These or any future oil spills may have a material adverse effect on our financial condition or results of operations. Accordingly, if one or more of the potential liabilities resulting from these oil spills were to result in an actual fine or civil or criminal liability, our operations and financial condition could be negatively affected.
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. We are also pursuing discussions with various government authorities and with Repsol-YPF over our licenses, including our right to operate certain platforms, in connection with the 2001 Repsol-YPF asset swap. These claims involve a wide range of issues and seek substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us. Our audited financial statements as of December 31, 2002 include reserves totaling U.S.$50 million as of that date, for probable and reasonably estimable losses and expenses we may incur in connection with all of our pending litigation and a separate provision of U.S.$105 million related to various tax assessments received from the Instituto Nacional de Seguridade Social (National Security Institute, or INSS), as further described in Item 8 “Financial Information – Legal Proceedings”.
In the event that a number of the claims that we consider to represent remote or reasonably possible risks of loss were to be decided against us, or in the event that the losses estimated turn out to be higher than the reserves 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, including matters involving our platforms and asset swaps, could result in restrictions on our operations and have a material adverse effect on certain of our businesses.
Proposed legislative changes to the ICMS tax imposed by the State of Rio de Janeiro may have a material adverse effect on our results of operation and financial condition.
The governor of the State of Rio de Janeiro is considering signing a bill into law that would increase the amount of Imposto sobre Circulação de Mercadorias e Serviços (state value-added tax, or ICMS) that we are required to pay by approximately R$5.4 billion (U.S.$1.9 billion) per year. The proposed new law would change the point of collection of part of the ICMS from the refinery level to the wellhead level of production in the State of Rio de Janeiro. If it becomes effective, we may be unable to utilize part of the taxes imposed at the wellhead level in Rio de Janeiro to offset taxes that are imposed at the refinery level in other states, and therefore would be paying taxes on the same oil products at both the production and refining level. We believe that the proposed new law would be an unconstitutional form of taxation,
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and intend to challenge the law if it becomes effective. If the law becomes effective, it would significantly increase the amount of taxes we pay, and such increase could have a material adverse effect on our level of investments and, therefore, on our results of operation and financial condition.
Labor disputes, strikes, work stoppages and protests could lead to increased operating costs.
All of our employees, other than our maritime employees, are subject to a collective bargaining agreement with the Oil Workers’ Unified Federation, which was signed on December 4, 2002, retroactive to September 1, 2002. This collective bargaining agreement will expire on October 31, 2003. On December 27, 2002, we signed a separate collective bargaining agreement with the maritime employees’ union retroactive to November 1, 2002, which will expire on October 31, 2003.
From time to time, we have been subject to strikes and work stoppages. In 2001, our oil workers began a five-day strike. While this strike was settled, it did result in a decrease in crude oil production. 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. As a result, our financial condition and results of operations could be adversely affected by future strikes, work stoppages, protests or similar activities.
Our expansion into the domestic power market is relatively recent and has generated losses, and the regulatory environment remains uncertain.
Consistent with the global trend of other major oil and gas companies and to secure demand for our natural gas, we are currently expanding our business into 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 by private investors has been slow to progress. We currently invest in 16 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 Termoelectricidade (Thermoelectric Priority Program, or PPT). We invest in some of these plants with partners, many of whom may have power purchase agreements with the plants. We have had contractual disputes in connection with these investments and other disputes may occur. Depending on the outcome of any such disputes, they could have an adverse economic impact on us, including on the profitability of our investments.
We have a limited history of investing in thermoelectric plants, and thermoelectric plants have not previously operated in a competitive environment in Brazil. Thermoelectric plants have faced difficulties passing on to electricity offtakers foreign currency financing costs of developing new generating capacity, and have had to contend with the reluctance of many distribution companies to sign power purchase agreements due mainly to their existing initial contracts, which provide for a guaranteed price from 1998 to 2002, which is phased out over the following four years. In addition, demand for thermoelectric power in Brazil has been lower than expected. In 2002, Congress passed a law increasing government intervention in the market, and the current administration is studying the implementation of changes that could be material to the natural gas and power sector. It is not clear that thermoelectric power generation will remain a priority for the country. In addition, the energy policy of the new administration remains uncertain.
During 2002, we experienced significant losses relating to our investments in thermoelectric power generation. As a result, in 2002 we created a U.S.$205 million provision for losses related to our commitments to off-take electricity from certain thermoelectric power plants. We increased this provision in the first quarter of 2003 by a further U.S.$205 million. After deducting the losses incurred in the first quarter of 2003, which amounted to U.S.$111 million, the balance of the provision totaled U.S.$316
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million as of March 31, 2003. We have limited our investments in this area, but our participation in the domestic power market may never become profitable. As a result, our participation in this market may adversely affect our operating results and financial condition.
We are in the process of implementing a new Strategic Plan, which may have a material adverse effect on our competitive position or ability to expand our operations.
On April 17, 2003, we announced the adoption of revisions to our Strategic Plan for the period 2003-2007. The new Strategic Plan maintains our core strategies and objectives, but reduces our overall budgeted capital expenditures for the year 2003. The revisions for 2003 reflect an environment of decreased access to financial markets and increased volatility in foreign exchange rates and crude oil prices. The changes to our Strategic Plan, particularly the decrease in overall budgeted capital expenditures, could affect our ability to achieve certain of our strategic goals, and in particular, could negatively impact our competitive position or ability to expand our operations.
We may not be able to obtain financing for all of our planned investments.
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. We are endeavoring to obtain financing that does not require Brazilian government approval, such as structured financings, but there can be no assurance that we will succeed. As a result, 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 future operating results and financial condition may be adversely affected. In addition, failure to make our planned investments in Brazil could hurt our competitive position in the Brazilian oil and gas sector, particularly as other companies enter the market.
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 86% 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 the year ended December 31, 2002, we imported U.S.$5.2 billion of crude oil and oil products, the prices of which were all denominated in U.S. Dollars.
As a result of downward pressure on the Real, on January 15, 1999, the Central Bank of Brazil allowed the Real to float freely. The Real depreciated 9.3% in 2000, 18.7% in 2001 and 52.3% in 2002 against the U.S. Dollar. As of June 13, 2003, the exchange rate of the Real to the U.S. Dollar was R$2.857 per U.S.$1.00, representing an appreciation of approximately 24.0% in 2003 year-to-date. There is no assurance that this trend will continue, and the Real may depreciate further in the future. We cannot predict the impact on our operations of any future substantial devaluation of the Real, which could adversely affect our operating cash flows and our ability to meet our foreign currency-denominated obligations. You should consider this risk in light of past devaluations of the Real caused by inflationary and other pressures.
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We are exposed to increases in prevailing market interest rates.
As of December 31, 2002, approximately 45% of our total indebtedness consisted of floating rate debt. Although we are changing our risk management practices, we have not yet 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.
In the aftermath of the U.S. military action in Iraq there may be changes to the international oil markets, some of which could have an adverse effect on us.
Following the U.S. military action in Iraq, the United Nations eliminated sanctions that had limited Iraq’s ability to participate in the international oil markets. As a result, it is expected that in the future, Iraq will substantially increase its production and export sales of crude oil and oil products. Given the uncertainty surrounding the circumstances under which Iraq’s oil industry will be managed over the next few years, it is impossible to predict the economic or political goals which the United States government or any other party controlling such industry will seek to achieve. The changes to the international oil markets that could result from Iraq’s re-entry into such markets could have a material adverse effect on our financial condition and results of operations.
Our ability to obtain affordable insurance coverage may be adversely affected by changes in the insurance markets, our recent history of claims under our insurance policies and changes in the insurance markets following the September 11, 2001 terrorist attacks.
The insurance premiums charged for some or all of the coverage historically maintained by us and our subsidiaries has increased significantly in the past as a result of changes in the insurance markets and claims under our insurance policies. Following the March 15, 2001 explosion that sank Platform P-36, our insurance costs increased substantially, from U.S.$36.0 million in 2001 to U.S.$46.4 million in 2002. For 2003, these costs have decreased to U.S.$30.5 million. Our insurance costs may increase, or coverage may be unavailable, in the future. The premiums for war risk and terrorism insurance have also increased substantially in the past, and in some cases, such insurance is not available. Following the September 11, 2001 terrorist attacks, insurance underwriters have issued general notices of cancellations to their customers for war risk and terrorism insurance in respect of a wide variety of insurance coverage, including, but not limited to, liability coverage. We do not know whether underwriters will offer to reinstate some or all of these types of coverage and, if reinstatement is offered, the extent to which premiums may be increased. The failure to obtain insurance against risks inherent in our business may expose us to catastrophic losses that may materially affect our results of operations.
We may not achieve the anticipated timing, efficiencies and benefits of integrating Perez Companc into our business
On October 17, 2002, we agreed to acquire 58.62% of the capital stock of Perez Companc, the second largest Argentine energy company, from the Perez Companc family and the Perez Companc Foundation for approximately U.S.$1.03 billion. The completion of the Perez Companc acquisition was contingent upon antitrust approval from the Argentine government’s Comisión Nacional de Defensa de la Competencia (the “National Council for the Defense of Competition” or the “CNDC”). The CNDC approved the transaction on May 13, 2003. Upon approval of the transaction, Perez Companc agreed to divest itself of its equity interest in Transener S.A., which operates most of Argentina’s high-tension electricity lines. This divestiture is in line with Perez Companc’s strategic plan and does not affect our strategic plan in Latin America.
It is possible that we may not achieve the anticipated timing, efficiencies and benefits of integrating Perez Companc into our business. Differing corporate cultures, legal and regulatory
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environments, personalities, languages and other factors may pose challenges to the success of the acquisition. Failure to achieve the anticipated timing, efficiencies and benefits of integrating Perez Companc into our business may negatively impact us and our ability to implement our strategic objectives in South America.
Perez Companc is subject to substantial risks relating to its business and operations in Argentina and other South American countries.
Perez Companc is an Argentine sociedad anonima with approximately 59.6% of its total crude oil and natural gas production and 45.6% of its proved crude oil and natural gas reserves located in Argentina at December 31, 2002. As a result, Perez Companc’s financial condition and results of operation may be adversely affected by Argentine political instability, fluctuations in the Argentine economy and governmental actions concerning the economy, including:
Perez Companc is also active in Venezuela, Ecuador, Bolivia, Peru and Brazil. Production from Venezuela accounted for approximately 28.7% of Perez Companc’s total average production in barrels of oil equivalent in 2002, constituting the largest operation outside Argentina. Accordingly, Perez Companc’s operations may be negatively affected by:
If one or more of the risks described above were to materialize, we may not be able to realize the benefits that we currently intend to realize from the Perez Companc acquisition, and that development might negatively impact us and our ability to implement our strategic objectives in South America.
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Risks Relating to the Relationship between us and the Brazilian Government
The interests of the Brazilian government, as our controlling shareholder, may conflict with the interests of our other shareholders and creditors.
The Brazilian government, as our controlling shareholder, has pursued, and could continue to pursue, certain of its macroeconomic and social objectives through us. These initiatives have not always been in our best interests or the best interests of our other shareholders and creditors. 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 Brazilian government’s agenda 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 continue to make investments, incur costs and engage in sales on terms that are not necessarily in our best interests or in the best interests of our shareholders and creditors.
Luiz Inácio Lula da Silva was elected President of Brazil in October 2002 and took office on January 1, 2003. As a result, there have been significant changes in our board of directors and senior management in recent months. The reconstituted board of directors and new senior management may pursue a strategy or conduct operations in a manner that diverges significantly from the strategy and operations pursued by our previous management. Changes in government or government policy could have a material adverse effect on us and our business, results of operations, financial condition or prospects.
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, 2002 was U.S.$182 million. Effective January 2, 2002, all price controls for crude oil and oil products ended, and while no price controls were imposed in 2002, 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.
Brazilian political and economic conditions may have a material adverse effect on us.
The Brazilian economy has been characterized by significant involvement by the Brazilian government, which often changes monetary, credit and other policies to influence Brazil’s economy. The Brazilian government’s actions to control inflation and other economic policies have often involved wage and price controls, modifications to the Central Bank’s base interest rates, and other measures, such as the freezing of bank accounts, which occurred in 1990.
The Brazilian government’s economic policies may have important effects on Brazilian corporations and other entities, including us, and on market conditions and prices of Brazilian securities. Our financial condition and results of operations may be adversely affected by the following factors and the Brazilian government’s response to these factors:
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In addition, we cannot predict the effect that the policies of the new Brazilian administration may have on Brazilian economic conditions or on our financial condition and results of operations.
The current Argentine economic, political and social crisis could adversely affect the financial condition and results of operation of Perez Companc and our other Argentine operations.
Since 1999, the Argentine economy has been in a recession marked by reduced levels of consumption and investment, increased unemployment, declining gross domestic product and capital flight.
On December 20, 2001, President Fernando de la Rúa resigned, and since then, Argentina has had several presidents, including President Eduardo Duhalde, who held office from January 2002 to May 2003. During his term, President Duhalde and his government underook a number of far-reaching initiatives, including:
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The rapid and radical nature of recent changes in the Argentine social, political, economic and legal environment created an atmosphere of great uncertainty in the banking system. As a result, commercial and financial activities were virtually paralyzed during 2002, further aggravating the economic recession which precipitated the current crisis. Moreover, due to the depth of the social and political crisis that affected Argentina in 2002, Argentina continues to face risks, including: (i) civil unrest, rioting, looting, nation-wide protests, widespread social unrest and strikes, (ii) expropriation, nationalization and forced renegotiation or modification of existing contracts and (iii) changes in taxation policies, including royalty and tax increases and retroactive tax claims.
On May 25, 2003, a new president, Néstor Kirchner, took office. There is uncertainty as to the nature and scope of the measures to be adopted by Mr. Kirchner’s government to address many of the country’s unresolved economic problems, including the renegotiation of its external debt. We cannot predict the policies the new Kirchner administration may adopt or the effect that those policies could have on Argentine economic conditions and our investments in Argentina.
We have acquired a majority interest in several entities with operations in Argentina, including Perez Companc. The financial condition and results of operation of Perez Companc and other acquisitions may be adversely affected by Argentine political instability, fluctuations in the Argentine economy and governmental actions concerning the economy, which could result in our failure to realize the benefits we currently expect to realize from those acquisitions.
Historical Brazilian government control of our sales prices and regulation of our operating revenues mean that our results of operations cannot be easily compared from year to year.
One of the tools available to the Brazilian government to control inflation and pursue other economic and social objectives has been the regulation of oil product prices. The method by which the Brazilian government has controlled our prices has varied from year to year. Until December 31, 2001, the Brazilian government regulated the prices at which we were permitted to sell our oil products. The Brazilian government also established freight subsidies to ensure uniform oil product prices throughout Brazil, but these subsidies have since been phased out. Beginning in July 1998, and until the institution of price deregulation on January 2, 2002, the Brazilian government established a new methodology for calculating our net operating revenues.
Because of this government price control and the change in methodology:
Additionally, from time to time, the Brazilian government may impose specific taxes or other special payment obligations on our operations that may affect our results of operations.
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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. As a result, many oil and gas companies own crude oil and natural gas reserves. 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.
The Brazilian government is no longer contingently liable for our liabilities in the event of our insolvency.
On March 1, 2002, an amended Brazilian corporate law became effective. Among other changes, the amended law provides for the termination of the contingent liability of the Brazilian government for the liabilities and obligations of mixed capital companies, such as us and, as a consequence, for the termination of mixed capital companies’ immunity from bankruptcy legal proceedings. Accordingly, the Brazilian government will not be contingently liable, as it was in the past, for any of our obligations incurred after the enactment of this law.
Risks Relating to Brazil
The Brazilian government’s actions to maintain economic stability, as well as public speculation about possible future actions, may contribute significantly to economic uncertainty in Brazil and to heightened volatility in the Brazilian securities markets.
Our principal market is Brazil, which has 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, to 8.4% in 1999 and to 5.3% in 2000. The same index increased to 9.4% during 2001 and to 14.7% in 2002.
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.
Over the last three fiscal years, approximately 86% of our revenues have been denominated in Reais, although prices for crude oil and oil products have been based on international prices. 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 the U.S. Dollar and other foreign currencies. In addition, during the year ended December 31, 2002, we imported approximately U.S.$5.2 billion of crude oil and oil products, the prices of which were all denominated in U.S. Dollars.
As a result of inflationary pressures, the Real and its predecessor currencies have been devalued periodically during the last four decades. Through this period, the Brazilian government has implemented various economic plans and utilized a number of exchange rate policies, including sudden devaluations, periodic mini-devaluations during which the frequency of adjustments has ranged from daily to monthly, floating exchange rate systems, exchange controls and dual exchange rate markets. From time to time, there have been significant fluctuations in the exchange rates between the Real and the U.S. Dollar and other currencies. For example, the Real declined in value against the U.S. Dollar by 9.3% in 2000, 18.7% in 2001 and 52.3% in 2002.
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Devaluation of the Real relative to the U.S. Dollar could create additional inflationary pressures in Brazil by generally increasing the price of imported products and requiring recessionary governmental policies to curb aggregate demand. On the other hand, appreciation of the Real against the U.S. Dollar may lead to a deterioration of the country’s current account and the balance of payments, as well as dampen export-driven growth. The potential impact of the floating exchange rate and of measures by the Brazilian government aimed at stabilizing the Real is uncertain. In addition, a substantial increase in inflation may weaken investor confidence in Brazil. Future devaluation of the Real could adversely affect our results of operations and financial condition.
The current crisis in Argentina could adversely affect the Brazilian economy, adversely affecting our ability to finance our operations and our investments in Argentina.
In the past, the Brazilian economy and the securities of Brazilian companies have been, to varying degrees, influenced by economic and market conditions in other emerging market countries, particularly in Latin America, as well as by investors’ responses to those conditions.
Any further deterioration of the Argentine economy and further devaluation of the Argentine Peso could adversely affect the Brazilian economy, as Argentina is one of Brazil’s principal trading partners, accounting for 26% of Brazil’s exports in 2002. Adverse developments in the Brazilian economy could, in turn, negatively impact our business and results of operations.
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 may limit your ability to sell 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.
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—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. Although our ADSs are already traded on the New York Stock Exchange, we cannot predict whether an active liquid public trading market for our ADSs will be sustained. 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. Although ADS holders are entitled to withdraw the common or preferred shares underlying the ADSs from the depositary at any time, 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.
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 our subsidiary, Petrobras International Finance Company (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 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 Brazilian Stock Exchange. If you do not obtain a certificate of registration or register under Resolution
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No. 2,689, you will generally 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, or 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.
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 corporate 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 or the rights of holders of the common or preferred shares under Brazilian corporate law to protect interests relative to actions by our board of directors may be fewer and less well-defined 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 regarding 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 more difficulties in protecting your interests in the case of 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 represent 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—Voting Rights” for a discussion of the limited voting rights of our preferred shares.
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Developments in other emerging market countries may affect the trading values of our securities.
Securities of Brazilian companies have been influenced by economic and market conditions in other emerging market countries to varying degrees. Although economic conditions are different in each country, investors’ reactions to developments in one country may affect the securities of issuers in other countries, including Brazil. Between the fourth quarter of 1997 and the first quarter of 1999, the international financial markets experienced significant volatility, and a large number of market indices, including those in Brazil, declined significantly. The 1997 Asian economic crisis, the 1998 Russian debt moratorium and devaluation of the Russian currency, and the recent uncertainty caused by Argentina’s economic crisis, for example, resulted in increased volatility in securities markets in Latin America and in other emerging market countries.
ITEM 4. INFORMATION ON THE COMPANY
History and Development of the Company
Petróleo Brasileiro S.A.—PETROBRAS is 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 publicly traded. Our principal executive office is located at Avenida República do Chile, 65, 20035-900 — Rio de Janeiro — RJ, Brazil and our telephone number is (55-21) 2534-4477.
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 gas production, refining and distribution 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.
Based upon our 2002 consolidated revenues, we are the largest corporation in Brazil and the third largest industrial corporation in Latin America. For the year ended December 31, 2002, we had sales of products and services of U.S.$32,987 million, net operating revenues of U.S.$22,612 million and net income of U.S.$2,311 million.
We engage in a broad range of oil and gas activities, which cover the following segments of our operations:
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For a breakdown of total revenues by category of activity for each of the last three financial years, see Item 5 “Operating and Financial Review and Prospects—Business Segments.”
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.
In conjunction with the reforms in the Brazilian energy industry in 2001, we completed a reorganization designed to ensure our competitiveness and improved profitability in the evolving Brazilian energy markets. This reorganization included:
Overview by Business Segment
Exploration, Development and Production
We participate in exploration, development and production activities throughout Brazil and, as of December 31, 2002, in 8 other countries (Angola, Argentina, Bolivia, Colombia, United States, Nigeria, Trinidad & Tobago and Equatorial Guinea), excluding Perez Companc’s activities. Our reserves are primarily located in the offshore Campos Basin, which represents Brazil’s largest oil region and one of the most prolific oil and gas producing areas in South America. As of December 31, 2002, we had estimated proved developed and undeveloped reserves of approximately 10.5 billion barrels of oil equivalent, compared to 9.3 billion barrels of oil equivalent as of December 31, 2001, which were composed of 9.0 billion barrels of crude oil and condensate and 9.5 trillion cubic feet of natural gas, making us the sixth largest publicly traded oil and gas company in the world based upon total proved reserves.
Our reserve base has grown over the last five years. Our worldwide proved reserves have increased at an annual average growth rate of 2.7%, primarily as a result of our deepwater exploration and development success. Over the last five years, our average daily production has grown at an average annual growth rate of 10.9% to 1.54 million barrels per day of crude oil and natural gas liquids, or NGLs, and 1.65 billion cubic feet of natural gas per day for the year ended December 31, 2002.
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Refining, Transportation and Marketing
We own and operate 11 refineries in Brazil with a gross aggregate capacity of 1.93 million barrels of crude oil per day. In the year ended December 31, 2002, we processed 591 million barrels of crude oil, or 1.62 million barrels per day. We produced 1.64 million barrels of oil products per day in 2002, composed of 36% diesel fuel, 19% gasoline, 17% fuel oil, 13% naphtha and jet fuel and 15% other oil products. Our average refinery utilization of such oil products was 84% over the past three years, with the same installed capacity of 1.93 million barrels of crude oil per day since 2000.
In addition, we own interests in 2 refineries in Bolivia and 1 in Argentina (the operating results of which are accounted for in our international business segment), resulting in a total refining capacity in South America (excluding Brazil) of 0.09 million barrels per day. In the year ended December 31, 2002, we processed 0.06 million barrels per day in Bolivia and Argentina.
We operate an extensive storage network, with an aggregate capacity of 63 million barrels as of December 31, 2002, which enables us to supply oil products throughout Brazil. In addition, we operate a pipeline network for crude oil and oil products of approximately 3,915 miles (6,300 kilometers) of which approximately 72% is typically devoted to crude oil deliveries. We are currently reorganizing our crude oil transportation capabilities to better serve our vertically integrated operations.
Distribution
Our sales network for retail distribution of oil products, fuel alcohol and natural gas consisted of 7,119 service stations in Brazil as of December 31, 2002 (as compared to 7,031 as of December 31, 2001), of which 602 are owned by BR, our subsidiary. BR’s owned and franchised service station network represents approximately 25% of all of the service stations in Brazil, with approximately 42% of this network located in the populous and industrial Southeast region of the country.
BR also sells directly to commercial and industrial end-users. For the year ended December 31, 2002, BR had net operating revenues of U.S.$ 6,562 million, of which 47.9% were generated from commercial and industrial sales and 52.1% from retail sales. In 2002, BR was the largest distributor of refined oil products and fuel alcohol in Brazil with a 32.9% market share (by volume of sales), which it achieved by leveraging its extensive sales network and BR’s strong brand image. For the year ended December 31, 2002, 53.4% of BR’s net operating revenues were generated from sales of diesel and fuel oil, which are traditionally sold to industrial customers, transportation companies and the Brazilian government.
Additionally, we maintain a distribution network consisting of 722 service stations in Argentina and 76 service stations in Bolivia. The results of these service stations are reflected in our international business segment.
Natural Gas and Power
Natural gas exploration and production, marketing and distribution is becoming an increasingly important part of our business as Brazil’s energy needs grow. The Brazilian government has estimated that natural gas will represent 10% of primary energy consumption by 2005 and 12% by 2010. We intend to serve this potential growing demand primarily through:
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We currently own interests in 17 natural gas distribution companies. These companies have an effective monopoly in the geographic areas in which they operate and further our plan to vertically integrate our natural gas operations.
Our most significant natural gas project, amounting to approximately U.S.$1,785 million in capital expenditures at December 31, 2002, is the Bolivia-Brazil pipeline, which connects Bolivia and Brazil’s system of natural gas transportation pipelines and is designed to facilitate increased importation activities.
Investments in the power industry continue to be an important part of our business, although we have reduced our exposure to this sector, in light of decreased consumer demand for energy in Brazil. We have interests in 16 of the 39 gas-fired thermoelectric plants proposed or being built in Brazil under the PPT. We have (or have agreed to acquire) minority interests ranging from approximately 10% to 50% in 12 of these plants and majority interests in the remaining 4 plants.
During 2002, our total investments in thermoelectric power activities, including capital expenditures and capital commitments, totaled U.S.$906 million.
International
The international segment of our business includes all of our activities outside of Brazil, including exploration and production, transportation, refining, distribution, natural gas and power. In 2002, approximately 2.7% of our net operating revenues were generated from international sales.
We began our international exploration and development activities in 1972, and we made our earliest discoveries onshore in Colombia in that year. We currently conduct significant oil and gas exploration activities in eight countries and production activities in five other countries, principally in South America, the Gulf of Mexico and West Africa. As of December 31, 2002, our capital expenditures for international exploration and development were U.S.$224 million.
In 2002, we expanded our international operations through the acquisition of 58.62% of Perez Companc, 39.67% of Petrolera Perez Companc and 100% of Petrolera Santa Fe.
With the purchase of Perez Companc, we acquired participation interests in five refineries abroad, three of which are located in Argentina (Refisan, Refinor and Bahia Blanca) and two in Bolivia (one in Cochabamba and one in Santa Cruz). We also acquired 722 service stations in Argentina and 76 in Bolivia.
Our Competitive Strengths
We have a number of key strengths, including:
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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 permits 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 operate approximately 98.6% of the country’s refining capacity. Our average domestic daily production of crude oil and NGL increased 12.3% in 2002, 10.2% in 2001 and 12.1% in 2000.
Our reserve base and comparatively long reserve life
As of December 31, 2002, we had estimated proved developed and undeveloped reserves of approximately 10.5 billion barrels of crude 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, 2002, our proved reserves to production ratio was 17 years, as compared to an international industry average of 13 years.
We believe that our proved reserves will provide us with significant opportunities for:
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 9842 feet (3,000 meters).
Our deepwater development and production expertise has allowed us to achieve high production volumes and reduced lifting costs (excluding government taxes and imports). Our aggregate average lifting cost for crude oil and natural gas products in Brazil for the year ended December 31, 2002 increased to U.S.$ 7.0 per barrel of oil equivalent including government take from U.S.$6.55 per barrel of oil equivalent including government take for the year ended December 31, 2001. Excluding government take, our lifting costs decreased to U.S.$3.00 per barrel of oil equivalent for the year ended December 31, 2002, as compared to U.S.$3.26 per barrel of oil equivalent for the year ended December 31, 2001.
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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. 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 oil and gas 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 5.5 billion barrels of oil equivalent as of December 31, 2002, which represents approximately 53% of our total proved reserves. Our 2003-2007 budget contemplates capital expenditures of approximately R$77 billion (U.S.$22.4 billion) in development activities for this five-year period, including R$5.6 billion (U.S.$1.6 billion) to be financed through project financings. The majority of these capital expenditures, R$62 billion (U.S.$18 billion) will be directed towards domestic exploration and production activities.
At the same time that we seek to expand production, we intend to increase our proved reserves principally through an exploration program focused on deepwater exploration in Brazil. We have net exploration, development and production rights in 35.4 million acres (143,343 square kilometers) in
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Brazil. We expect to continue to participate selectively with major regional and international oil and gas companies in bidding for new concessions and in developing our large offshore fields.
We also intend to pursue international exploration and production opportunities with industry participants primarily in the west coast of Africa, the Gulf of Mexico and South America. 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). We have exploration, development and production rights in 12.7 million (gross) and 5.0 million (net) acres (58,000 (gross) and 21,000 (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
Our refineries were originally constructed to process light imported crude oil, whereas our current reserves and production increasingly consists of heavier crude oil. We plan to improve and adapt our refineries to better process our domestic production by continuing to:
Expand international operations through internal growth and by participating selectively in new partnerships in core areas where we have competitive advantages.
On October 17, 2002, we acquired a controlling interest in Perez Companc, and indirectly in its subsidiary Petrolera Perez Companc. With the Perez Companc acquisition, we have achieved our immediate targets with respect to international acquisitions. As a result, no further material acquisitions are planned during 2003. In the near term, we expect to expand internally 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.
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 and safety concerns and ensure compliance with environmental regulations, we have taken several measures, the most extensive of which is the Programa de Excelência em Gestão Ambiental e Segurança Operacional (Environmental, Management and Operational Safety Excellence Program, or PEGASO), which has enabled us to achieve a new standard with respect to issues of safety and respect for the environment. See “—Health, Safety and Environmental Matters.”
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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 the proportion of our 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 and price deregulation in 1997, we have been taking steps to prepare 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 agility, transparency and accountability to shareholders. In March 2002, we amended our bylaws to comply with changes to the Brazilian Corporation Law and improve our corporate governance. 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:
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We had hoped that these significant corporate governance initiatives would permit us to qualify for a higher level listing (Level 2) on the principal Brazilian stock exchange (Bovespa). Level 2 is a status reserved for companies that adhere to Bovespa’s corporate governance measures and certain other requirements. One of the requirements for qualification for Level 2 listing is that we, our controlling shareholder and our directors and executive officers sign a contract with Bovespa pursuant to which they would agree to cause an amendment to our bylaws in order to entitle our preferred shareholders to vote on certain matters, such as conversions into other corporate forms, mergers, split-offs or split-ups and approvals of transactions between us and other companies in our corporate group. In this process, the Finance Ministry represents the Brazilian government, our controlling shareholder. The Attorney General of the Finance Ministry has refused to recommend that the Minister of Finance sign the contract with Bovespa on behalf of the Brazilian government, because he believes that such an amendment to our bylaws would negatively affect the power of the Brazilian government to control us and that, therefore, the Brazilian government is prohibited by law from consenting to such an amendment. As a result, the Minister of Finance did not sign the contract with Bovespa on behalf of the Brazilian government, and consequently Bovespa refused to grant us a higher listing. We remain committed to resolving these legal issues in order to eventually achieve a Level 2 listing on Bovespa.
Meet targeted operating costs and return on capital
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.$2.80 per barrel of oil equivalent in 2005 (excluding government take) as compared to U.S.$3.0 per barrel of oil equivalent in 2002. We will seek to reduce our operating costs per barrel by a number of means, including:
Summary and Strategy
We participate in exploration, development and production activities throughout Brazil and, as of December 31, 2002, in 8 other countries (Angola, Argentina, Bolivia, Colombia, United States, Nigeria, Trinidad & Tobago and Equatorial Guinea), excluding Perez Companc’s activities. We began domestic production in 1954 and international production in 1972. As of December 31, 2002, our estimated worldwide net proved crude oil and natural gas reserves were approximately 10.5 billion barrels of oil
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equivalent. Crude oil represented 85% and natural gas represented 15% of these reserves. Our proved reserves are located principally in Brazil, in the Campos Basin.
During 2002, our average daily domestic production was 1.5 million barrels per day of oil and NGLs and 1.5 billion cubic feet of natural gas per day, compared to an average daily international production of approximately 35 thousand barrels per day of crude oil and NGLs and 138 million cubic feet of natural gas per day. Our aggregate average lifting costs for crude oil and natural gas in 2002 were U.S.$ 3.0 per barrel of oil equivalent in Brazil (excluding government take) and U.S.$ 2.08 per barrel of oil equivalent abroad.
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. 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.
As of December 31, 2002, we held 327 areas, representing 35.4 million acres (143,259 square kilometers). We currently have joint venture agreements for exploration and production in Brazil with approximately 20 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 the Agência Nacional de Petróleo(the National Petroleum Agency, or the ANP) since 1999.
Our main strategies in exploration, development and production in Brazil are to:
Our exploration, development and production results are reflected in the “Exploration and Production” segment in our audited consolidated financial statements.
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Principal Domestic Oil and Gas Producing Regions
The earliest discoveries of hydrocarbons in Brazil were made in the State of Bahia by the Conselho Nacional do Petróleo (Brazilian Oil Council, or CNP), between 1939 and 1954. Following the discoveries by CNP, we were created and began domestic exploration and production in 1954. Our first discoveries were made onshore in the States of Bahia, Alagoas and Sergipe in the 1950s and 1960s. In the 1970s, we made major offshore discoveries in shallow waters off the coast of the States of Rio Grande do Norte, Ceará and Rio de Janeiro. In the mid-1980s, we discovered the deepwater reservoirs in the Campos Basin off the coast of the State of Rio de Janeiro, and further exploration culminated with the deepwater discovery of the Roncador field in 1996.
Our progress can be seen in the growth of our annual daily production. In 1970, we produced 167 Mbpd of crude oil, condensate and natural gas liquids in Brazil. We increased production to 188 Mbpd in 1980, 654 Mbpd in 1990, 1,271 Mbpd in 2000 and 1,336 Mbpd in 2001. New platforms, along with high production efficiency of our platforms in the Campos Basin, enabled us to attain average production of 1,500 Mbpd in 2002. In February 2003, we achieved a new record in the monthly output of crude oil and NGL in Brazil, producing an average of 1,597 thousand barrels per day.
Campos Basin
The successful discovery and development of the oil fields in the Campos Basin marked a critical breakthrough in our history and that of the Brazilian oil and gas industry. The Campos Basin is our largest oil and gas producing region, and covers approximately 28.4 million acres (115 thousand square kilometers). Since exploration activities in the Campos Basin began in 1968, over 40 hydrocarbon reservoirs have been discovered in this region, 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
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oil production volume in the region has steadily increased for the past ten years and reached 1,218 thousand barrels per day in 2002, which accounted for approximately 81% of Brazilian oil production.
As of December 31, 2002, we produced crude oil from 35 fields in the Campos Basin. As of December 31, 2002, our proved crude oil reserves in the Campos Basin were 7.8 billion barrels, representing 89% of our total proved crude oil reserves. In 2002, the crude oil we produced in the Campos Basin had an average API gravity of 22.8° and an average water cut of 32%. We currently have 24 floating production systems, 13 fixed platforms and 4,225 kilometers of pipeline operating in 35 fields at water depths of 262 to 6,106 feet (80 – 1,861 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 14 blocks in the Santos Basin, with a combined acreage of 43.8 thousand square kilometers (as compared to 29.8 thousand square kilometers under concession in the Campos Basin). Current production is 2.5 Mboe per day of crude oil in the Caravelas and Merluza fields.
Espírito Santo Basin
In partnership with Shell and Chevron Texaco, we made several discoveries of heavy crude oil in the Espírito Santo Basin, but it is still unclear whether this crude oil is commercially recoverable. During 2002, we produced 24.9 Mboe per day of crude oil in the Espírito Santo Basin (mostly onshore).
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 2002, we produced 55.7 Mboe per day of crude oil in the Solimões Basin.
Properties
The following table sets forth our developed and undeveloped acreage by oil region and associated crude oil and natural gas production:
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Deepwater Expertise
We are a leader in deepwater drilling, with recognized expertise in deepwater exploration, development and production. In recognition of our deepwater drilling achievements, the Offshore Technology Conference awarded us the OTC Prize in 2001. We have developed our expertise over many years and have achieved significant milestones, including the following:
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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 6,165 feet (1,879 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 2002 and 2001.
OFFSHORE PRODUCTION BY WATER DEPTH
Exploration Activities
Our Concessions in Brazil
Prior to 1998, 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 (458,532 square kilometers).
As of December 31, 2002, we had 327 areas, consisting of 235 production areas, 58 exploration areas and 34 development areas, for a total area aggregating 35.4 million net acres (143.3 thousand square kilometers). This total area represents 2.3% of the Brazilian sedimentary basins.
Exploration bidding rounds
Since 1998, 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.
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We have participated in the first, second, third and fourth auctions for exploration rights conducted by the ANP.
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The following chart summarizes our success in the exploration bidding rounds conducted by the ANP, as described above:
Joint Ventures
As of December 31, 2002, we had 43 exploration and development agreements with respect to our concessions with numerous oil and gas companies. Our percentage participation ranges from 20% to 85%, and in 22 of the 43 agreements, we are principally responsible for conducting the exploration and development activities. During 2002, we entered into 5 partnership projects relating to exploration activities. As of December 31, 2002, we had partnerships with 20 foreign and domestic companies.
We have sought to maximize our exploratory acreage and reduce our costs and risks of exploration and development activities. In conjunction with the majority of these arrangements, we receive 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.
Recent Exploration Activities
Our exploration activities during the period from 1999 through 2002 led to many discoveries. The most important were:
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Drilling Activities
During 2002, we drilled a total of 277 development wells and 56 exploratory wells. Of those wells, 20 development wells and 19 exploratory wells were located in our principal Campos Basin fields. Of those development wells, 40% were drilled in the Marlim field, with the remainder concentrated in the Roncador, Barracuda, Albacora, Espadarte, Voador, Marimbá and Marlim Sul fields. An additional 99 of the 319 new development wells we plan to drill during 2003 will be drilled in the Campos Basin, primarily in the Roncador, Marlim, Barracuda, Espadarte, Voador, Marimbá and Marlim Sul fields.
We plan to expand our exploration and development activities in 2003 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
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
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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 four 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.
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 2002 was 602 Mbpd, or more than 49% 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 817 Mbpd operating in the Marlim field. We have a total of 83 production wells and 45 injection wells, and expect to drill another four wells in 2003. Peak production of 602 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). 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 (FPSO) unit 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, are currently being attached to the new FPSO unit.
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A new permanent unit to replace P-36 is being planned, with production of first oil from the unit expected in 2006. Planned capacity is 180 Mbpd. The production unit consists of an FPSO, P-54. A total of 20 production wells are planned in this first module, including the eight which were completed before the sinking of P-36.
A second production unit is also being planned, with production of first oil also expected in 2006. Planned capacity is 190 Mbpd. The production unit consists of an FPSO (P-54). A total of ten production 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 2002, the average production for Marlim Sul was 152 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 Mpbd. Nine wells are currently producing through P-40, out of a total of 16 planned production wells and ten injection wells.
A second module is also being planned, with production of first oil expected in 2006. Planned capacity is 180 Mbpd. The production system consists of an FPSO unit and is currently under evaluation. A total of 14 production wells and ten injection wells are planned.
Barracuda and Caratinga. The Barracuda and Caratinga fields are located at water depths between 2,274 and 3,899 feet (700 – 1,200 meters). Production of first oil is expected by the end of 2004. Two FPSO units are currently being constructed, one in Singapore (P-43, which will be installed in the Barracuda field) and one in Brazil (P-48, which will be installed in the Caratinga field). 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 2004. An FPSO unit (P-50) with a capacity of 180 Mbpd is currently being converted in Singapore. A total of 18 horizontal wells and 11 injection wells are planned. We are the operator and Repsol–YPF is a partner with a 10% interest.
Other Planned Developments
Other developments include the Frade field, which is being developed in partnership with Chevron Texaco and the Bijupirá Salema field, which is being developed by Shell.
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 and Off Balance Sheet Arrangements—Project Finance.”
Platforms P-51 and P-52
We are planning to construct two new semi-submersible platforms, P-51 and P-52, with an expected total capacity of 360 Mpbd, which will be installed in the Campos Basin.
On February 25, 2003, our executive board approved a revision to the bidding and contractual requirements of the invitations to bid for the construction of the P-51 and P-52 platforms, in order to include a minimum required level of participation by Brazilian companies. The new requirements provide, among other things, that:
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Our Strategic Plan for 2003 to 2007 contemplates greater participation by Brazilian companies in our domestic construction activities and other projects. We estimate that of the U.S.$29.2 billion in domestic capital expenditures contemplated in our Strategic Plan for 2003 to 2007, at least U.S.$18.9 billion (65%) will be utilized to pay for equipment and services provided by Brazilian contractors, suppliers and other similar service providers.
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 seven Brazilian states. We are also producing crude oil and natural gas in five other countries: Angola, Argentina, Bolivia, Colombia and the United States. 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 the years ended December 31, 2002, 2001 and 2000:
Our increased offshore production over the three years ended December 31, 2002 was primarily attributable to our discovery and development of fields on the continental shelf off the coast of Rio de Janeiro in the Campos Basin. Increased average daily natural gas production was principally attributable to growth in the volume of associated gas recovered from the same fields.
Average Brazilian production of crude oil and NGL for the year ended December 31, 2002 increased 12% relative to 2001, reaching 1.5 million barrels per day, principally as a result of:
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Reserves
Our estimated worldwide proved reserves of crude oil and natural gas as of December 31, 2002 totaled approximately:
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 chiefly 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 which may prove to be incorrect over time.
As of December 31, 2002, our proved developed crude oil reserves represented 47% of our total proved crude oil reserves. Our proved developed natural gas reserves represented 63% of our total proved developed natural gas reserves. Total proved hydrocarbon reserves on a barrel of oil equivalent basis increased at a compounded annual growth rate of 2.7% from the end of 1997 to 10.5 billion barrels of oil equivalent at the end of 2002. Natural gas as a percentage of total proved hydrocarbon reserves increased from 12% to 15% over the same period, representing an increase in volume from 8,440 billion cubic feet in 2000 to 9,473 billion cubic feet at the end of 2002.
In 2002, our reserves increased to 10.5 billion barrels of oil equivalent from 9.3 billion barrels of oil equivalent in 2001. This increase was a result of:
Ninety percent of our gross domestic reserves estimates as of December 31, 2002 were reviewed and certified by DeGolyer and MacNaughton, or D&M. The estimates for the certification were performed in accordance with the rules and regulations of the SEC.
D&M’s estimate of our gross domestic reserves for 2002 was approximately 3% lower than our estimate, even though D&M used the same technical criteria for the analysis of the reserves that we use. The main reason for the difference between these estimates is the differing interpretations of technical data. D&M has informed us that it is of the view that although it found both positive and negative differences in reserve estimates for individual properties in 2002, overall differences between our estimates and the estimates of D&M, when compared on the basis of gross domestic reserves, are not material.
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The following table sets forth our own estimated net proved developed and undeveloped reserves and net proved developed reserves of crude oil and natural gas as of December 31, 2002, 2001 and 2000 and as of January 1, 2000.
WORLDWIDE ESTIMATED NET PROVED RESERVES
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The following tables set forth our crude oil and natural gas proved reserves by region, as of December 31, 2002, 2001 and 2000:
CRUDE OIL NET PROVED RESERVES BY REGION
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NATURAL GAS NET PROVED RESERVES BY REGION
We own and operate 11 refineries in Brazil, with a total processing capacity of 1.93 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 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 and oil products, some of which is also processed in our refineries. As our own domestic production increases and refinery upgrades enable us to process more throughput, we expect to import proportionately less crude oil and oil products. Until January of 2002, we were charged with the responsibility of being 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.
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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 monopoly supplier for almost fifty years of a country that ranks as the 11th largest consuming nation in 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.
We recently restructured our fleet of shipping vessels into a more efficient integrated system. 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
As of December 31, 2002, we had total installed capacity of approximately 2.02 million barrels per day, which makes us the fifth largest refiner of oil products in the world among publicly traded companies. Worldwide, we processed an average of 1.7 million barrels of oil per day in 2002, which represents a utilization rate of 83% for the year, calculated on total capacity. This compares with 84% average utilization rates in 2001 and 82% average utilization rates in 2000.
Our domestic production in 2002 supplied approximately 79% of the crude oil feedstock for our refinery operations in Brazil, as compared to 76% in 2001 and 75% in 2000. 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 the year ended December 31, 2002, we processed 591 million barrels of crude oil or 1.62 million barrels per day. In November 2002, our catalytic cracking units set a new daily processing record of 526 thousand barrels per day. Our average refining costs (consisting of variable costs and excluding
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depreciation and amortization) in Brazil were U.S.$ 0.91 per barrel in 2002, U.S.$ 0.95 per barrel in 2001 and U.S.$1.14 per barrel in 2000. Our exploration and production operations in Brazil supplied approximately 79% of this crude oil, and we purchased the remainder, principally supplies of lighter crude oil used by us to achieve our oil density objectives, from third parties. 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.
The following table describes the installed capacity, refining throughput and utilization of our refineries for each of the three years ended December 31, 2002, 2001 and 2000:
REFINING STATISTICS
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. As we operate our refineries to maximize the output of diesel fuel, we produce volumes of gasoline and fuel oil which 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 the three years ended December 31, 2002 and 2001 and 2000:
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DOMESTIC PRODUCTION VOLUME OF OIL PRODUCTS
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. 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 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 Recent Projects
To pursue our objectives for the refining segment, during the course of the last six years our board of directors has approved the construction of diesel hydro-treatment units for the following refineries:
We believe these 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. Capital expenditures for these units are projected to be U.S.$798 million and completion is expected by the middle of 2004.
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Our executive board has also approved within our projected capital expenditures the construction of additional coking units within our existing refineries. These units will allow us to more easily convert our domestically produced heavy fuel oil into middle distillate fuels such as diesel.
Imports
Prior to January 2002, we were effectively responsible under Brazilian Law for ensuring that the supply of crude oil and oil products in Brazil met the country’s consumption requirements. To the extent necessary, we were required to import crude oil and oil products to fulfill this responsibility. Although our domestic production is increasing, we continue to import crude oil and refined 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 to import lighter crude oils to improve the mix of oils to be refined, and to create certain oil products for which there is demand in the market but that would be too costly for us to produce.
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 mainly sold to the retail market in Brazil through BR.
As our domestic crude oil production has increased and our refineries have become capable of processing larger quantities of crude oil, the average daily volume of our imports of crude oil has decreased to 337,000 barrels per day in 2002, as compared to 399,000 barrels per day in 2001 and 394,000 barrels per day in 2000. The following table sets forth the percentage of crude oil that we imported during each of the three years ended December 31, 2002, 2001 and 2000 by region.
IMPORTS OF CRUDE OIL BY REGION
In 2002, our total costs of imports of crude oil from all these regions was U.S.$2,953 million, as compared to U.S.$3,211 million in 2001 and U.S.$3,110 million in 2000.
We purchased approximately 33% of our 2002 crude oil imports and 37% of our 2001 crude oil imports pursuant to one-year term contracts, which are considered to be long-term contracts within the industry standard practice. At December 31, 2002, we had two long-term contracts providing for the supply of crude oil to us in Brazil, with suppliers from Saudi Arabia and Argentina. The contract with suppliers from Saudi Arabia was renewed in February 2003 under identical terms, and will now expire in January 2004. Our contracts with suppliers from Argentina expired in February and April 2003 and were not renewed. 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 215,121 barrels per day in 2002, as compared to 328,100 barrels per day in 2001 and 383,861 barrels per day in 2000, primarily as a result of the reduction in the import of petrochemical naphtha and diesel, and growing domestic refinery production. The following table sets forth the volume of oil products that we imported during each of the three years ended December 31, 2002, 2001 and 2000:
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IMPORTS OF OIL PRODUCTS
In 2002, our total costs of oil product imports, measured on a cost-insurance-and-freight basis, was U.S.$2,055 million, as compared to U.S.$3,425 million in 2001 and U.S.$4,545 million in 2000. For a discussion of import purchase volumes and prices, see Item 5 “Operating and Financial Review and Prospects––Sales Volumes and Prices—Import Purchase Volumes and Prices.”
Exports
We also export oil products processed by our refineries, but not required to satisfy Brazilian demand. In addition, we export domestic crude oil that we are unable to process in our refineries because of limited conversion capacity. The following table sets forth the volumes of oil products we exported during each of the three years ended December 31, 2002, 2001 and 2000:
EXPORTS OF OIL AND OIL PRODUCTS(1)
The total value of our crude oil and oil products exports, measured on a free-on-board basis, was U.S.$4,760 million in 2002, U.S.$2,763 million in 2001 and U.S.$2,555 million in 2000.
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. Therefore, in 1998, we created a wholly-owned subsidiary, Transpetro, 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 keep 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
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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. As of December 31, 2002, our onshore and offshore crude oil and oil products pipelines aggregated 2,826 miles (4,548 kilometers) in length and our natural gas pipelines aggregated approximately 4,819 miles (7,755 kilometers) in length, including the Brazilian side (1,609 miles, or 2,589 kilometers) of the Bolivia-Brazil pipeline. During the second half of 2003, we plan to begin the construction of additional crude oil pipelines totaling approximately 435 miles (700 kilometers) in order to increase throughput capacity and extend our distribution network. Our plans for future crude oil pipeline development are likely to involve joint ventures.
We are currently developing an enhancement of 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. The project, which we refer to as PDET, will involve the construction of an approximately 70 mile (115 kilometers) offshore pipeline and related assets extending from the Campos Basin to Barra do Furado in the state of Rio de Janeiro and an approximately 375 mile (603 kilometers) onshore pipeline and related assets extending from Barra do Furado in the state of Rio de Janeiro to Guararema Terminal in the state of São Paulo. The project will cost approximately U.S.$1,312 million.
NATURAL GAS PIPELINES
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Transpetro also operates 43 storage terminals with aggregate capacity of 63 million barrels of oil equivalent. As of December 31, 2002, tankage capacity at these terminals consisted of 33.5 million barrels for crude oil, 25.4 million barrels for oil products and fuel alcohol and 2.4 million barrels for LPG.
We are currently evaluating alternatives to improve the efficiency of our transportation system, including evaluating improvements to the monitoring and control of our crude oil and natural gas 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. We have already implemented the first phase of the project and inaugurated a centralized control and operating center in June 2002, in our headquarters in Rio de Janeiro. Currently, we have 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. Our goal is to be able to operate all of our domestic pipelines remotely, initially via the regional stations, and ultimately via the centralized control and operating center located in our headquarters in Rio de Janeiro.
Shipping
As of December 31, 2002, our fleet consisted of the following 59 owned vessels, 55 of which are single hulled and four of which are double hulled, with aggregate deadweight tonnage of 3,050.5 million:
OWNED VESSELS
Fifty-six of 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. Our shipping operations support the transportation of crude oil from offshore production systems, our import and export activities and coastal trade.
PRODUCTS AND QUANTITIES TRANSPORTED
In 2002, our shipping activity increased 3.5% compared to 2001, as a result of an increase in offshore domestic oil production, which reflected an increase of 4.6% in coastal trade and of 23.8% in crude oil transportation related to import and exports during the year.
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The average monthly-chartered tonnage in 2002 amounted to 3.9 million deadweight tons, as compared to 3.6 million deadweight tons in 2001 and 3.2 million deadweight tons in 2000. 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.$431 million in 2002, U.S.$707 million in 2001 and U.S.$471 million in 2000.
Marketing
Our supply segment sells oil products to various wholesale customers and retail distributors in Brazil, including our subsidiary BR and other retailers such as Shell Brasileira de Petróleo S.A., Esso Brasileira de Petróleo S.A., Companhia de Petróleo Ipiranga S.A. and Texaco do Brasil S.A. In the year ended December 31, 2002, we sold 189.6 million barrels of oil products to wholesale customers, with gasoline and diesel fuel representing approximately 82.9% of these sales. Of our total sales in 2002, 158.0 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 the three years ended December 31, 2002, 2001 and 2000:
OIL PRODUCT SALES
Prior to the implementation of the Oil Law, we were required to be Brazil’s principal wholesale supplier of oil products and it was therefore necessary to establish significant marketing operations and infrastructure in numerous geographic areas to ensure supply throughout the country. As a result of this system, we often had to establish and maintain distribution outlets in geographic areas that were not economically viable.
Petrochemicals
We conduct our petrochemical activities through our subsidiary, Petrobras Química S.A., or Petroquisa. Petroquisa is a holding company which holds minority voting interests in nine operational petrochemical affiliated companies involved in the production and sale of basic petrochemical products, derivative petrochemical products and fertilizers. As of December 31, 2002, our ownership percentage of the total capital of these affiliates ranged from 13.5% to 62.4% and our ownership percentage of the voting capital of these affiliates ranged from 8.1% to 50.0%. The total book value of these investments is U.S.$167.5 million.
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The basic supply feedstock used in Brazil’s petrochemical industry is naphtha, an oil product. Until 2001, we were the sole supplier of naphtha to Brazil’s petrochemical industry. In 2002, the petrochemical industry imported approximately 28% of its naphtha needs, and we supply the remainder from our refining operations.
Our petrochemicals business, based on the equity in results of non-consolidated companies, accounted for U.S.$10.8 million in 2002. We currently expect to maintain a presence in the petrochemicals industry principally by participating in projects located adjacent to our refineries. We expect that our selective investment in petrochemicals will solidify our involvement in the entire energy value chain, integrating refining and primary and secondary products. Although we have divested of certain interests in the petrochemical segment in the past, we plan on increasing the current level of our investments, unless such investments cease to be profitable.
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). Other investors include BNDES 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.$1.0 billion budgeted construction cost over the next three years, 60% is being provided by long-term loans from or guaranteed by U.S. Ex-Im Bank, BNDES and SACE (the Italian Export Credit Agency), and 40% is expected to be funded by equity investments, of which our portion is approximately U.S.$67 million. As of December 31, 2002, we had spent approximately U.S.$28 million of this total. We expect Rio Polímeros to be operational by mid-2005 and to produce 515,000 tons per year of polyethylene and 60,000 tons per year of propylene, from ethane and propane extracted from natural gas originated in the Campos Basin.
We also intend to market products derived from our refining processes. We are currently negotiating with BASF, the German chemicals company, to create a joint venture in order to produce 90,000 tons per year of Acrylic Acid and 60,000 tons per year of Super Absorbent Polymer -SAP. As raw materials for production, we will use the propylene derived from LPG refined at our Henrique Lage refinery (REVAP). The estimated total investment is US$148 million, and it is expected that the return on investment will be consistent with our Strategic Plan for the Petrochemical area (minimum of 15% per year). We expect start-up of operations in 2007.
Through BR, we distribute oil products, fuel alcohol and natural gas to retail, commercial and industrial customers throughout Brazil. Our oil products, fuel alcohol and vehicular natural gas are sold to service stations under exclusive supply agreements. Besides providing the products, we also provide to those service stations, identified with our trademark “BR”, managerial and technical support to ensure quality and consistency in our operations and establish control procedures. We own only 602 of the 7,119 service stations that sell our products, but all of them are required to be identified by our BR trademark. We also sell non-fuel products through oil lubrication centers.
Our main strategies in distribution and marketing are to:
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Our distribution results are reflected in the “Distribution” segment in our audited consolidated financial statements.
General
We distribute oil products, fuel alcohol and natural gas to retail, commercial and industrial customers throughout Brazil. Our operations are supported by tankage capacity of approximately 9,465 barrels of oil equivalent, at 78 storage facilities and 99 aviation product depots at airports throughout Brazil.
Retail
As of December 31, 2002, our sales network in Brazil included 7,119 retail service stations compared to 7,031 as of December 31, 2001, and comprised approximately 25% of the total number of service stations in Brazil, all under the brand name “BR”. Over 65% of these BR stations are located in the South and Southeast regions of Brazil, where over 59% of Brazil’s total population of 165 million reside. Of these 7,119 service stations, BR owned 602. As required under Brazilian law, BR subcontracts the operation of all its service stations to third parties. The other 6,517 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.
We sell oil products to service stations under exclusive supply agreements which are typically for a term of seven years. Under these agreements, we also provide managerial and technical support to ensure quality and consistency in our operations and establish control procedures.
In 2002, 170 of our service stations also sold vehicular natural gas, compared to 119 in 2001 and 58 in 2000. The sales from these stations consisted of 13,245 million cubic feet (375 million cubic meters) in 2002, representing 60.6% of Brazilian market share, 9,893 million cubic feet (280 million cubic meters) in 2001, representing 61.4 % of Brazilian market share and 5,090 million cubic feet (144 million cubic meters) in 2000, representing 57.3% of the Brazilian market share in that year.
The table below sets forth market share (based on volume) for retail sales of different products in Brazil for each of the years ended December 31, 2002, 2001 and 2000:
DISTRIBUTION MARKET SHARE
Source: Petrobras – based on figures provided by Sindicato dos Distribuidores de Combustíveis-Sindicom
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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.
BR provides financing to certain of its service station operators to improve their competitiveness, the terms of which may vary in accordance with the provisions of each financing agreement. These agreements are of two types: unconditional and conditional. The unconditional agreements must be paid in full and bear interest at market rates. The conditional agreements are contingent upon the service station operators’ purchases of minimum volumes of oil products as set forth in each financing agreement, in which case the total amount of the conditional agreement is forgiven by BR. These costs amounted to approximately U.S.$43.6 million during 2002, compared to U.S.$24.5 million during 2001 and U.S.$29.5 million during 2000.
During 2002, approximately 25% 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 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 3,797 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. Currently, we plan to take the following actions through 2005:
The transfers of the rights to supply products to gas stations to Repsol-YPF under the swap transaction with that company represented less than 1.2% of BR’s market share by volume. Through this swap transaction, we acquired a refinery with a production capacity of 30,500 barrels per day and 735 service stations in Argentina, which represented approximately 12% of the Argentine retail fuel market. See “—International—Argentine Activities—Repsol Asset Swap.”
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 45%, which has remained relatively constant over the past several years.
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Set forth below are commercial and industrial sales statistics for each of the three years ended December 31, 2002, 2001 and 2000:
COMMERCIAL AND INDUSTRIAL SALES BY PRODUCT
Delisting of BR
On November 7, 2002, our board of directors approved a public tender offer for all the outstanding shares of BR through a swap of BR shares for preferred shares to be issued by us. We conducted the share swap to acquire the 99.2% of BR shares we did not own in order to incorporate BR as a wholly-owned subsidiary and effect the delisting of BR’s public shares, which were publicly traded in Brazil. The public tender offer will allow us to advance the interests of our shareholders by:
An independent appraisal determined the fair value of BR stock to be R$45.40 (U.S.$11.66) for each 1,000-share lot of BR stock. A similar independent appraisal established the fair value of our preferred shares to be issued at R$64.90 (U.S.$16.68) per share. The exchange ratio was initially set at 0.7 shares of our preferred stock for every thousand-share block of BR stock, augmented by an additional U.S.$0.9427 per share paid to BR shareholders as an incentive for them to accept the public offer. In order to account for dividends paid to our and BR’s shareholders three months after the date of the public auction for BR shares, this exchange ratio was subsequently adjusted to 0.9626 shares of our preferred stock for every thousand-share block of BR stock.
A public tender auction was held on January 29, 2003 and our board of directors approved the issue of 9,866,828 preferred shares at an issue price of US$12.76 per share, under the terms of the capital increase approved during the meeting of our board of directors held on November 7, 2002. As a result, our capital increased by US$122 million. After verifying that all of the conditions for delisting BR’s shares were met, on February 5, 2003, the CVM effected the delisting of BR shares.
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The natural gas market in Brazil has been rapidly growing. In 2002, we estimate that natural gas consumption represented approximately 5.5-6.0% of Brazil’s primary energy consumption, as compared to 4.7% in 2001 and 3.8% in 2000. The Brazilian government has estimated that natural gas will represent 10% of primary energy consumption by 2005 and 12% by 2010. We expect that a large portion of this growth will come from the development of natural gas-fired thermoelectric plants in Brazil, increased industrial demand, as well as from the Brazilian government’s environmental policies encouraging the replacement of traditional industrial fuels with cleaner energy sources. During the last three years, we estimate that industrial consumption of natural gas has grown by 17% while vehicular consumption has grown by approximately 67%.
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
In the course of developing and producing crude oil, we produce significant volumes of associated natural gas. In addition, we have also made significant investments to facilitate the importation of natural gas from Bolivia.
Pipelines
Our main pipeline investment was 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. The construction of the pipeline was divided into two phases. We completed the first phase, linking Bolivia to São Paulo, in February 1999 and commenced operations in July 1999. We completed the second phase, linking São Paulo to Porto Alegre, in March 2000 and commenced operations in April
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2000. 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.
Our investment in the Bolivia-Brazil gas pipeline was the result of a 1996 commercial agreement for the purchase of natural gas between the Bolivian state oil company, Yacimientos Petrolíferos Fiscales Bolivianos – YPFB, and us. The gas purchase contract signed by us requires us to purchase from YPFB on a take-or-pay basis specified quantities of natural gas transported through the pipeline over a 20-year term.
We are also investing in two major domestic natural gas projects: Cabiúnas and Southeast-Northeast Gas Pipeline Network.
The Cabiúnas project comprises transportation and processing facilities of associated 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 fully operational by mid-2004 and to increase transportation capacity from the current 290 million cubic feet (8.2 million cubic meters) per day to a total of 494 million cubic feet (14 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 2002, the average daily volume of natural gas flared on the offshore platforms of the Campos Basin was 185 million cubic feet (5.2 million cubic meters).
We are currently developing the Southeast-Northeast Gas Pipeline Network (Malha Sudeste-Nordeste) jointly with private capital investors (the Malha project). This project will create additional transportation capacity by integrating new natural gas markets in the Northeast and Southeast regions of Brazil. It involves the construction of an approximately 700 mile (1,120 kilometers) pipeline, which is expected to start operations in 2005, at a total cost approximately U.S.$750 million.
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 17 of these natural gas distribution companies, 12 of which are in operation. 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 Espírito Santo State, we have the exclusive rights to distribute natural gas through BR.
Our capital expenditures in these natural gas distribution companies as of December 31, 2002 totaled U.S.$35 million, as compared to U.S.$32 million as of December 31, 2001 and U.S.$31 million as of December 31, 2000. Our business plan includes total budgeted capital expenditures in the gas distribution business of approximately US$10.2 million from 2003 through 2007. 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 take-or-pay obligations (in the case of contracts relating to Brazilian gas), and ship-or-pay and take-or-pay obligations (in the case of contracts relating to Bolivian gas or with thermoelectric power producers).
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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 the three years ended December 31, 2002, 2001 and 2000:
DOMESTIC SALES OF NATURAL GAS TO LOCAL DISTRIBUTION COMPANIES
Commitments and Sales Contracts
Take-or-pay 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 which varies with the price of fuel oil. Set forth below are actual amounts we purchased and paid in 2000, 2001 and 2002, and the minimum volumes we have agreed to thereafter, together with an estimate (assuming a Brent crude oil price of U.S.$15.00 per barrel) of the amounts we are obligated to pay for such minimum volumes:
NATURAL GAS TAKE-OR-PAY COMMITMENTS
Ship-or-pay commitments. In order to support the financing for the Bolivia-Brazil pipeline, TBG’s portion of which is consolidated in our balance sheet, 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. Our volume obligations under the ship-or-pay arrangements are generally designed to meet the take-or-pay 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 Boliva-Brazil gas pipeline. The total estimated project cost was U.S.$1.9 billion, which has already been invested as of December 31, 2002. Set forth below are the actual amounts we purchased and paid in 2000, 2001 and 2002, and the minimum volumes we have agreed to thereafter, 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:
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NATURAL GAS SHIP-OR-PAY COMMITMENTS
Natural gas sales contracts. In light of these take-or-pay and ship-or-pay obligations, we have entered into or negotiated firm take-or-pay 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. The table below sets forth our actual sales for 2000, 2001 and 2002, and commitments by local gas distribution companies and by thermal power plants to us for the firm purchase of volumes of natural gas thereafter, together with an estimate (assuming a Brent crude oil price of U.S.$15.00 per barrel) of the amounts obligated to be paid for such volumes:
NATURAL GAS SALES CONTRACTS(1)
Pricing. On June 1, 2001, the Brazilian government instituted a new mechanism which allows a U.S. dollar indexed component of the natural gas pricing mechanism to be passed through to the thermoelectric plants for a period of 12 years, pursuant to Portaria No. 176 (a joint regulatory act issued
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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”. We expect that this mechanism will enable 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-annum exchange rate risk. Under the new formula, exchange rate variations are reflected in gas prices annually, while we will be remunerated at market based interest rates for any resulting delay in gas price adjustments.
Power
Brazil currently has an installed electricity generation capacity of approximately 80,000 MW. More than 97% of this capacity is interconnected to form one single integrated system, with approximately 88% 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 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, and 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 by 2004.
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
The rationing program instituted by the Brazilian government from the beginning of June of 2001 until the end of February 2002, 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, heavy rains have filled the reservoirs to approximately 70% of their maximum capacity. As a result, in the short term, existing hydroelectric capacity is sufficient to meet the energy needs of the 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. However, in the medium term, we believe that expected growth in electricity demand combined with limited spare hydroelectric capacity available will create the need for some thermoelectric capacity in Brazil. In addition, electricity costs of thermoelectric plants are expected to be relatively competitive with projected incremental hydroelectric capacity.
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Currently, the new administration of the Brazilian government is reviewing the power sector and developing a comprehensive set of new regulations to govern the entire power sector in the future.
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:
In light of the uncertainties surrounding thermoelectric power, we are limiting our investments in the power sector. With an aim to reducing our exposure, we now plan to invest in 16 thermoelectric plants, with total capacity of approximately 6,700 MW, including six co-generation plants. Of these 16 thermoelectric plants, ten are already under construction or operation. With the exception of four plants in which we have a majority stake, we anticipate that our investments in the thermoelectric plants will be as a minority shareholder. These thermoelectric plants are located primarily in the Southeast and Northeast regions of Brazil. Some of them also have connections with other natural gas projects involving the construction of pipelines, which facilitates our distribution activities.
We currently have halted all investment in thermoelectric power, except for the ten plants under construction or operation. We have acquired turbines for future projects that have been delayed, although we have negotiated postponements in the delivery of such turbines as well as the related payments. We do not intend to continue developing the thermoelectric plants still in the planning stage, or expand existing thermoelectric plants until we are satisfied with new government regulations being formulated to govern thermoelectric power. Our plans will also depend upon the level of demand for electricity in general and the success of our electricity marketing efforts.
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. Our obligations under these agreements are either structured as:
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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)
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 3,685 MW as of the end of 2005, of which 2,255 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 the consumption in our facilities, estimated to be approximately 300 MW per year, equally allocated between the Northeast and South/Southeast regions of Brazil, 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 May 2003, PPAs included offtake commitments totaling 1,530 average MW for 2004, 1,700 average MW for 2005 and 1,400 average MW for 2006, 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.
On April 16, 2002, the Brazilian Congress approved Provisional Measure 14, which permits us to include in our corporate purpose “activities related to energy”. This regulation was signed into Law 10,438, on April 26 2002, and we amended our bylaws, in June 2002, to incorporate energy as part of our corporate purpose. In addition, we have established a new subsidiary, Petrobras Energia Ltda., to negotiate sales and purchases of electricity.
In 2002, we created a U.S.$205 million provision for reasonably probable losses from our investments in thermoelectric power plants. On May 7, 2003, our executive board authorized an increase in this accounting provision in the first quarter of 2003 by a further US$205 million, equivalent to 94% of the maximum expected loss for 2003, in consideration of the fact that the expected sales of energy available through our PPAs in 2003 and the level of dispatch from the thermoelectric power plants initially anticipated were not realized. After deducting the losses incurred in the first quarter of 2003, which amounted to US$111 million, the balance of the provision totaled US$316 as of March 31, 2003, to
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cover probable reasonably probable losses related to our investments in the energy sector in the 2003 fiscal year.
The provisions are related to:
Assuming a discount rate of 12% per year, we estimate that the net present value of our maximum financial exposure from our investments in the energy sector as of March 31, 2003, is approximately U.S.$1,700 million.
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). As of June 2003, such unpaid capacity payments totaled approximately U.S.$23 million. 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.
In 2002, approximately 2.68% of our net revenues were generated outside Brazil. 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 oil and gas company. 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 natural gas production 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.$5.1 billion in capital expenditures for the period 2003-2007 for all of our international investments. These budgeted capital expenditures are subject to government approval.
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
We began our international exploration and production activities in 1972, and made our earliest discoveries onshore in Colombia in that year. We currently conduct significant international exploration activities in Angola, Argentina, Bolivia, Colombia, Nigeria, the United States and Trinidad & Tobago. In addition, we are currently performing studies to evaluate blocks where we hold interests in Angola, Argentina, Colombia, Nigeria and the United States. As of December 31, 2002, we participated in crude oil and natural gas exploration activities in eight other countries and production activities in five countries, which collectively represented approximately 4.6% of our total capital expenditures for crude oil and natural gas exploration and production activities. Our capital expenditures for international exploration and development were U.S.$224 million for the year ended December 31, 2002, U.S.$318 million for the year ended December 31, 2001 and U.S.$236 million for the year ended December 31, 2000. The following table provides information about the allocation of such expenditures for each of the three years ended December 31, 2002, 2001 and 2000:
DISTRIBUTION OF INTERNATIONAL EXPLORATION ACTIVITIES
Development
Over the past three years, we have participated in the development of a number of fields internationally, including three in Argentina, two in Bolivia, ten in Colombia, and three in the United States.
In 2002, our net production outside of Brazil averaged 35,224 barrels per day of crude oil and NGLs and 22,947 barrels of oil equivalent of natural gas per day at an average lifting cost of U.S.$2.08 per barrel. In comparison with 2001, net production decreased approximately 14.9% in terms of barrels of crude oil equivalent due to the sale in 2001 of all of our production assets in the United Kingdom and eight of our production assets in the United States, as well as the normal decline in production of our mature fields in Angola. The following table provides information on the allocation of our international development activities for the three years ended December 31, 2002, 2001 and 2000.
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ALLOCATION OF INTERNATIONAL DEVELOPMENT ACTIVITIES
Bolivian Activities
In January 2001, we inaugurated our first natural gas producing field in Bolivia, the Sábalo gas field, where Petrobras Bolivia is the operator and has a 35% equity stake (the other partners are Petrolífera Andina (50%) and Total Bolivia (15%)). In 2002, we drilled two additional appraisal wells in the Sábalo field.
At the end of 2001, we began construction of the Yacuiba-Rio Grande gas pipeline (GASYRG), a pipeline in Bolivia that connects the gas fields in the south of Brazil to the Bolivia-Brazil pipeline. We completed construction of the pipeline in the beginning of 2003. The pipeline, along with the construction of two compression stations, is expected to increase the current flow of natural gas from the San Antonio and Sábalo fields into the Bolivia-Brazil gas pipeline to 815 million cubic feet per day.
We also entered into several 20-year agreements for the importation of natural gas from Bolivia to be sold to natural gas distribution companies in Brazil.
As part of the Bolivian gas transport infrastructure, we acquired an interest in a natural gas compression plant in Rio Grande, Bolivia, which has a capacity to compress up to 840 million cubic feet per day. As a result of certain improvements to this plant, we expect that this capacity will increase to up to 1,200 million cubic feet per day by the middle of 2003 (1,590 million cubic feet per day, including stand-by capacity.
The Bolivian refining and distribution market are regulated by the Bolivian government. On January 25, 2003, the government issued a decree which reduced refining margins. We are working with the Bolivian government and crude oil suppliers to attempt to convince the Bolivian government to restore our refining margins.
African Activities
For the first time, as a result of the 2000 license bid round in Nigeria, we will act as operator in the deepwater Niger Delta block in Nigeria. In addition, in December 2001, we entered into three joint ventures for oil exploration and production in deepwater blocks off the coast of Nigeria. In one of these blocks, we have a 75% interest and we are the operator. We are currently appraising Agbami and Akpo, two fields previously discovered in the Niger Delta Basin.
Gulf of Mexico Activities
Our wholly-owned Subsidiary, Petrobras America, Inc. (PAI) continues to expand its activities in the Gulf of Mexico 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
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Management Service. As of December 31, 2002, PAI held participation in 110 offshore blocks in the Gulf of Mexico, of which 90 are located in deep and ultra-deep waters.
PAI holds a 25% working interest in the Cascade discovery well drilled in the Walker Ridge area, Block WR-206, which is operated by BHP Billiton. PAI also holds a 33% interest in the Jedi block, which is operated by Kerr-McGee. In 2002, PAI also successfully drilled and brought into production an exploratory well in Block GB-201 in the Garden Banks area.
Argentine Activities
Perez Companc
Terms of Acquisition
On October 17, 2002, we agreed to acquire 58.62% of the capital stock of Perez Companc S.A., the second largest Argentine energy company, from the Perez Companc family and the Perez Companc Foundation. We paid the Perez Companc family and the Perez Companc Foundation a total of approximately U.S.$1.03 billion, consisting of U.S.$689.2 million in cash and U.S.$338.4 million in debt securities issued by our wholly-owned subsidiary, PIFCo, and which will pay a 4.75% annual coupon and mature on October 4, 2007. We also agreed to acquire from the Perez Companc family 39.67% of the capital stock of Petrolera Perez Companc S.A, a company engaged in hydrocarbons production in Argentina’s Neuquén basin, for U.S.$49.8 million in cash.
The completion of the Perez Companc acquisition was contingent upon antitrust approval from the Argentine Government’s Comisión Nacional de Defensa de la Competencia (the “National Council for the Defense of Competition” or the “CNDC”). We received approval from the CNDC on May 13, 2003. Upon approval, Perez Companc agreed to divest itself of its aggregate equity interest in Transener S.A., which operates most of Argentina’s high-tension electricity lines. This divestiture is in line with Perez Companc’s strategic plan and does not affect our strategic plan in Latin America.
Because the transaction had not received final approval from the CNDC at December 31, 2002, we did not consolidate Perez Companc’s 2002 financial statements into our 2002 consolidated financial statements. We expect to consolidate Perez Companc’s financial statements into our consolidated financial statements by June 30, 2003.
On April 4, 2003, the shareholders of Perez Companc and Pecom Energía approved the change of Perez Companc S.A.’s corporate name to Petrobras Energía Participaciones S.A. and Pecom Energía S.A.’s corporate name to Petrobras Energía S.A.
Perez Companc — Selected Financial Information
Perez Companc is an integrated energy company engaged in oil and gas exploration and production, refining, petrochemicals, electricity generation, transmission and distribution and hydrocarbons marketing and transportation activities. It conducts operations in Argentina, Bolivia, Brazil, Ecuador, Peru and Venezuela.
Approximately 59.6% of Perez Companc’s total crude oil and natural gas production and 45.6% of its proved crude oil and natural gas reserves were located in Argentina at December 31, 2002. Production from Venezuela accounted for approximately 28.7% of Perez Companc’s total average production in barrels of oil equivalent in 2002, constituting the largest operation outside Argentina.
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Perez Companc prepares its financial statements in accordance with generally accepted accounting principles in Argentina (“Argentine GAAP”), which differ in significant respects with U.S. GAAP. Perez Companc also presents its results of operation in Argentine Pesos. The following table sets forth, for the periods indicated, the high, low, average and period-end exchange rates for the purchase of U.S. dollars, expressed in nominal pesos per U.S. dollar:
EXCHANGE RATE OF PESOS PER U.S. $1.00
As of December 31, 2002, Perez Companc had total consolidated assets of P$13.6 billion, total consolidated outstanding indebtedness of P$8.7 billion and shareholders’ equity of P$4.8 billion. The company registered a net loss of P$1.2 billion for the fiscal year ended December 31, 2002, principally as a result of the devaluation of the Argentine Peso, the worsening of the economic and financial crisis in Argentina and the political and economic instability in Venezuela.
The table below presents selected consolidated financial information from the income statement of Perez Companc for the year ended December 31, 2002:
The table below presents selected consolidated financial information from the balance sheet of Perez Companc as of December 31, 2002:
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Business Outlook
During the year ended December 31, 2002, Perez Companc’s business was adversely affected by the severe economic and financial crises in Argentina, and in particular:
As a result of the Argentine economic crisis and its effect on Perez Companc, the company could not obtain investor financing and relied exclusively on its cash generation, which led to significant cuts in capital expenditures during the year ended December 31, 2002. Faced with significant liquidity constraints, the company completed a U.S.$1,694 million renegotiation of its indebtedness in order to bring principal payments in line with cash flow provided by operations and establish a more manageable debt maturity schedule.
Perez Companc’s business was also negatively affected during the fourth quarter of 2002 by the political and economic crisis in Venezuela, which resulted in decreased oil production and cash flow.
Oil and Gas Exploration and Production
As of December 31, 2002, Perez Companc had proved reserves of 593,878 thousand barrels of crude oil and natural gas liquids, and 1,313,244 million cubic feet (37,187 million cubic meters) of natural gas. Total production for the year ended December 31, 2002 was 172.4 thousand barrels of oil equivalent per day (crude oil production totaled 118.9 thousand barrels per day and natural gas production totaled 321.3 million cubic feet or 9.09 million cubic meters per day). Perez Companc’s reserves to production ratio was 13.2 years, as of December 31, 2002.
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Santa Fe Acquisition
On October 24, 2002, we acquired Petrolera Santa Fe, an Argentine oil company and subsidiary of Devon Energy Corporation, for U.S.$89.6 million. Petrolera Santa Fe produces approximately 6,040 barrels of crude oil per day and approximately 22,672,016 cubic feet (642,000 cubic meters) of natural gas per day. As of December 31, 2002, Petrolera Santa Fe had estimated proved reserves of 81.3 Mmboe, estimated in accordance with the criteria established by the Society of Petroleum Engineers (SPE).
Repsol Asset Swap
On December 17, 2001, we entered into an exchange of equally-valued assets with Repsol-YPF, Europe’s sixth largest crude oil company. We exchanged some of our operating assets in Brazil for some of YPF’s operating assets in Argentina. The transaction closed on December 26, 2001. As a result of this transaction, we increased our downstream activities in the Southern Cone region of South America and acquired over 99% of the total capital stock of Eg3 S.A., the fourth-largest oil product marketing company in Argentina. In 2002 , Eg3 S.A. accounted for approximately 10.4% of Argentina’s automotive fuels market, with total sales of approximately 0.7 million gallons per day, through approximately 618 service stations and a refinery with a production capacity of 30,500 barrels per day. In exchange, Repsol-YPF received a 30% stake in our Alberto Pasqualini refinery in the State of Rio Grande do Sul, with a refining capacity of 189,000 barrels per day, and which both companies expect to be the target of sizeable additional joint strategic investments. Repsol-YPF also acquired from us the right to resell fuels at 234 service stations in the Midwest, South and Southeast regions of Brazil, with aggregate sales of approximately 8,386 barrels per day. In addition, Repsol-YPF acquired a 10% stake, or the equivalent of approximately 5.2 million barrels of proved crude oil reserves and 2.2 billion cubic feet of proved natural gas reserves, in our Albacora Leste offshore oil field in the Campos Basin.
No cash was exchanged in the deal because the transaction consisted of an exchange of equally-valued assets. Under the terms of the agreement, the value of the assets that we acquired has been protected under the structure for a period of eight years so as to minimize, for both parties, the foreign currency risk resulting from the present economic situation in Argentina.
For the year ended December 31, 2002, we sold approximately 81 million cubic feet per day of gas in Argentina. As a result of the devaluation of the Peso in Argentina, our revenues from these sales have decreased as reflected in U.S. dollars.
Others
The MEGA project is a joint venture among us, Repsol-YPF and Dow Chemical to fractionate natural gas liquids. We are obligated under an off-take contract to take minimum volumes of LPG and natural gas, if delivered, at market prices. The sponsors provided a completion guarantee for their respective shares in the project (Repsol-YPF 38%; Petrobras 34% and Dow Chemical 28%) until June 30, 2003. In 2002, two bank loans in the aggregate amount of U.S.$48 million were replaced by intercompany loans from sponsors.
The MEGA project has been adversely affected by the crisis in Argentina, particularly the peso devaluation, which affected the ability of Compañia Mega to service its debt. As a result, we are in the process of negotiating new pricing arrangements and sponsor guarantees. We asked sponsors to extend their corporate guarantees so that Argentina’s declaration of a moratorium on its sovereign debt would not be considered an event of default with respect to Compañia Mega’s debt obligations. Dollar denominated bank loans (U.S.$48 million) were replaced by subordinated debt from shareholders in order to take advantage of the lower exchange rate. In addition, sponsors decided to renegotiate prices of natural gas and ethane and to address unfair price advantages among sponsors.
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Organizational Structure
The following diagram sets forth our 12 direct subsidiaries:
All of our 12 direct subsidiaries are incorporated under the laws of Brazil, except PIFCo, Petrobras International Braspetro B.V. (PIB BV), Brapetro Oil Company (BOC), Braspetro Oil Services Company (Brasoil) and Petrobras Netherlands B.V. (PNBV), which were incorporated abroad. We own at least 99.99% of the common shares of those subsidiaries and at least 98% of the preferred shares of Petroquisa, Gaspetro and BR. PIFCo, Transpetro, Downstream Participações S.A. and Petrobras Negócios Eletrônicos S.A. (E-Petro) do not have preferred shares. In May 2002, we created Petrobras Energia Ltda., a wholly owned subsidiary, which will act as a power trader and conduct various activities related to Petrobras’ investments in the Brazilian power sector.
Restructuring of International Business Segment
In order to increase operational efficiency, we are in the process of restructuring our international operations. At an extraordinary general shareholders’ meeting held on September 30, 2002, our shareholders approved the absorption by us of Braspetro, a subsidiary which formerly managed all of our international operations, and which operated through the following direct subsidiaries:
As part of this restructuring, which we initiated in September 2002 and expect to complete at the end of 2003, we directly control or will directly control the following entities:
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Property, Plant 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.
Health, Safety and Environmental Matters
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 and safety concerns and ensure compliance with environmental regulations, we have:
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In addition, we conduct environmental impact studies for new projects as required by Brazilian environmental legislation, and our HSE department evaluates each and every project with a budget exceeding US$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.
See below and Item 8 “Financial Information” and Item 5 “Environmental Proceedings and Liabilities” for additional information.
Environmental Liabilities
Since January 1, 2000, we have experienced several accidents, including 11 significant oil spills causing the release of approximately 1.9 million gallons of crude oil and 0.1 million gallons of naphtha into various waterways. Due to those accidents, we are currently subject to several administrative, civil and criminal investigations and proceedings. We cannot predict whether additional litigation will result from those accidents and whether any such additional proceedings will have a material adverse effect on us. We have made provisions of US$50 million to meet probable and reasonably probable losses in the event of unfavorable rulings against us, including the matters described in Item 8 “Financial Information—Legal Proceedings.”
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. We are also subject to several investigations and civil and criminal proceedings as a result of this spill, including:
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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:
On November 4, 2000, the Cypriot flag vessel Vergina II chartered by us collided with a pier at our terminal in São Sebastião Ilhabela, causing the release of approximately 22,719 gallons of crude oil into the São Sebastião canal. We concluded the clean up of the spill on November 8, 2000. As a result of the accident, the environmental agency of the State of São Paulo imposed a fine of R$7 million and the environmental agency of Ilhabela imposed a fine of R$46 million. We are currently contesting these fines on the basis that the Cypriot company was responsible for the navigation of the ship into the terminal.
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 the Sagrado, Meio, Neves and Nhundiaquara rivers located in the State of Paraná. We finalized the cleaning of the river surfaces on February 20, 2001, recovering approximately 13,738 gallons of fuel oil. Environmental teams are still assessing the environmental impact of the spill. As a result of the accident:
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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) caused the loss of 11 employees and led to flooding of the column and part of the pontoon, which resulted in the capsizing and sinking of the platform on March 20, 2001. The accident also caused 396,300 gallons of oil to spill into the ocean. The spill was controlled through oil recovery in a first phase and with chemical and mechanical dispersion in a second phase. As a result of the accident:
On May 30, 2001, there was a rupture in a pipeline which transported crude oil from Barueri to the Paulínia Refinery, in São Paulo, causing the leak of 52,826 gallons of crude oil. We assumed responsibility for the accident and began repair work immediately, which we completed in August 2001.
On October 18, 2001, the ship Norma collided with a rock in the Paranaguá Port causing a leak of 103,158 gallons of naphtha. In response to this spill, the Port Authority fined Transpetro R$50,000 and IBAMA fined Transpetro R$5 million. Transpetro has already paid the Port Authority fine and is contesting the fine imposed by IBAMA. The Federal Public Ministry has also initiated a criminal complaint related to this accident.
On May 13, 2002, Transpetro’s ship Brotas released approximately 4,000 gallons of crude oil into the Ilha Grande Bay. As a result of the accident,Comissão Estadual de Controle Ambiental (State Environmental Control Commission, or CECA) fined us approximately R$7 million, and the municipalities of Angra dos Reis and Mangaratiba fined us approximately R$10 million each. We are contesting both fines.
On September 14, 2002, a fire in the Ilha Grande Bay Terminal caused the release of approximately 300 gallons of crude oil into the Ilha Grande Bay. As a result of the accident, Comissão Estadual de Controle Ambiental (State Environmental Control Commission, or CECA) fined us approximately R$1 million. We are contesting this fine.
On October 13, 2002, a power blackout in FPSO P-34, which is located in the Barracuda-Caratinga fields, and the failure of back-up generators 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). We estimate that total lost production
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resulting from the interruption of P-34’s operations represented 0.44% of our average daily production in 2002. As a result of the accident:
In November 2002, a failure in the operational system of the Henrique Lage Refinery (REVAP), in São José dos Campos caused the release of smoke from LPG and gasoline into the atmosphere. As a result of the accident, Companhia de Tecnologia de Saneamento Ambiental (Environmental Sanitation Technology Company, or CETESB) fined us approximately R$0.2 million. We have already paid this fine.
Also in 2002, we paid several fines to CETESB totaling approximately R$3.8 million, mostly for emissions from the Paulínia (REPLAN) and Presidente Bernardes – Cubatão (RPBC) refineries.
On May 12, 2003, there was a rupture in an oilfield gathering pipeline located in the Fazenda Belém Field, in Ceará, causing the leak of 1,850 gallons of crude oil. As a result of the accident, Superintendência de Meio Ambiente do Estado do Ceará (Environmental Secretariat of the State Ceará, or SEMACE) fined us R$0.1 million. On May 29, 2003, we and SEMACE executed a Termo de Compromisso, an agreement pursuant to which we will take the steps necessary to prevent future accidents, collect and properly dispose of the crude oil and residues released and present to SEMACE a plan of environmental recovery for the area affected by the accident. SEMACE in turn agreed to consider a reduction of up to 90% in the amount of the fine.
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On June 3, 2003, the tanker Nordic Marita released approximately 6,600 gallons of crude oil into the São Sebastião Canal. As a result of the accident, IBAMA fined us R$0.5 million. We are currently reviewing the matter in order to decide how to proceed.
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—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 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,
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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.
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 are traded on the São Paulo Stock Exchange, we are also regulated by the CVM.
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
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. Following the implementation of the Oil Law through December 31, 2001, the Brazilian oil and gas sector was significantly deregulated and the Brazilian government changed its price regulation policies. Under these new regulations the Brazilian government:
As set forth below, pursuant to Law No. 9,990, on January 2, 2002, 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, electricity and certain petrochemicals. On August 19, 2002, the ANP directed us to reduce prices of LPG for residential use by 12.4%, and we effected such reduction. The ANP eliminated this price control on October 31, 2002.
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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, pursuant to Constitutional Amendment No. 33, as of December 11, 2001, enacted Law No. 10,336, dated December 19, 2001, establishing a tax of a fixed amount 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), amended by Decree No. 4,066, dated December 27, 2001 and No. 4,565, dated January 1, 2003. On December 30, 2002, the Brazilian government enacted Law No. 10,636, amended by Decree No. 4,565, dated January 1, 2003, which increased the fixed amount of CIDE.
Crude Oil and Refined Oil Products
Until enactment of the Oil Law, the Brazilian government regulated all aspects of the pricing of crude oil and oil products in Brazil, from the cost of crude oil imported for use in our refineries, to the price of refined oil products charged to the consumer. The regulation of oil product prices was one of the tools available to the Brazilian government for controlling inflation. Prior to the enactment of the Oil Law, we regularly requested price adjustments in Reais to maintain prices at or above domestic inflation, and to cover the cost of importing crude oil and oil products at prevailing international prices. During periods of high inflation, the Brazilian government frequently did not increase prices in order to keep them at international levels. From July 29, 1998 until December 31, 2002, the decision to increase prices rested with the Minister of Mines and Energy, after he had consulted with the Minister of Finance.
The deregulation process occurred over time, with the prices of the following products being deregulated prior to January 2, 2002:
From July 29, 1998 until December 2001, we were required to calculate our net operating revenues based on the preço de realização (realization price, or PR), for oil products we sold. PR was determined on the basis of a pricing formula established by the Brazilian government that, with a lag of approximately one month, reflected changes in the Real/U.S. dollar exchange rate, international market prices for the relevant benchmark products and applicable import tariffs. Net operating revenues is the sum of the products obtained by multiplying the realization price for each oil product by the volume of each such oil product sold. The amount obtained from subtracting net operating revenues from sales of products and services (net of value-added and other taxes on sales and services) was recorded as the Parcela de Preços Específica (Specific Price Portion, or PPE), which was presented as an adjustment to sales of products and services. The amount of PPE for any period increased or decreased the balance of
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the Petroleum and Alcohol Account, and this process resulted in a decrease or increase in our net available cash.
The Brazilian government continued to reimburse certain fuel transportation and other eligible costs to us and distributors (including BR), until December 2001. Thereafter, we received the right to reimbursement for coastal and pipeline transportation costs of fuel oil and LPG, and distributors (including BR) continued to receive reimbursement for transportation costs of aviation fuel, diesel, LPG and fuel oil to certain municipalities in the Northern and Midwestern regions of Brazil. The impact of our role as administrator of these subsidies was reflected in the Petroleum and Alcohol Account (described below) on our balance sheet and in increases or decreases in that account on our statement of cash flows. The funds we and BR were entitled to receive as reimbursement for transportation costs under these subsidies reduced the amounts we recorded in selling, general and administrative expenses in respect of transportation costs, thus increasing the Petroleum and Alcohol Account.
On January 4, 2001, the Ministry of Mines and Energy and the Ministry of Finance adopted a new methodology for establishing the prices we were required to charge for diesel, gasoline and LPG. Under this methodology, the prices for these oil products were adjusted by an index (Indice de Reajuste, or IR), on a quarterly basis, calculated on the basis of a formula that reflects changes in the Real/U.S. dollar exchange rate and the prevailing international prices of Brent crude during the preceding quarter. If the IR was positive, the Brazilian government had discretion to establish an increase in price for any of these oil products lower than that which would result from application of the readjustment factor. If the IR was negative, the Brazilian government had discretion to establish a smaller price decrease for a product that would result from application of the readjustment factor if the average PPE for the product during the preceding quarter was negative.
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:
We continue to comply with a number of rules relating to the natural gas industry, 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) and Portaria 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
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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.
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 bonds issued by the Brazilian government. 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.
Hydrated Alcohol
Until December 31, 2002, we occasionally purchased and sold hydrated alcohol at the direction of the Brazilian government through government auctions and recorded the net effect of our fuel alcohol commercialization activities as an increase or decrease to the Petroleum and Alcohol Account, with an offsetting adjustment to cost of sales. The ANP, pursuant to Administrative Rule 301, dated December 18, 2001, authorized us to export, either in its natural state, or mixed with gasoline, the portions of inventory of fuel alcohol in our possession that were not purchased in connection with the Conselho Interministerial do Açúcar e do Álcool (Interministerial Council of Sugar and Alcohol, or CIMA). In addition, the Brazilian government is considering ways to facilitate our disposition of fuel alcohol inventories acquired by us through December 31, 2002.
The Petroleum and Alcohol Account
Prior to 2002, the Petroleum and Alcohol Account was a special account maintained to reflect the impact on us of the Brazilian government’s regulatory policies for the Brazilian oil industry and its fuel alcohol program.
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). The excess of the amounts we paid under the FUP/FUPA programs over the amount of FUP/FUPA we collected in any month increased the Petroleum and Alcohol Account. Conversely, the excess of the amounts we collected under the FUP/FUPA programs over the amounts we paid under the FUP/FUPA programs in any month decreased the Petroleum and Alcohol Account. In connection with the settlement of the Petroleum and Alcohol Account, the Brazilian government has been certifying the balance of the Petroleum and Alcohol Account since March 31, 1992.
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
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phased out. If recorded net operating revenues for any period were less than the amount recorded in sales of products and services (net of value-added and other taxes on sales and services) for such period, PPE was a positive amount and the balance of the Petroleum and Alcohol Account decreased. Conversely, if net operating revenues for any period exceeded the amount recorded in sales of products and services (net of value-added and other taxes on sales and services) for such period, the balance of the Petroleum and Alcohol Account increased. In addition, during this period, the net impact on us of our fuel alcohol commercialization activities was also recorded in the Petroleum and Alcohol Account. Finally, we were also required to fund the administrative expenses of the ANP. These funding payments were made after determination by the Brazilian government and were recorded as an increase in the Petroleum and Alcohol Account and did not impact our income statement.
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 in our name, which were placed with a federal depositary to support the balance of this account. These bonds are not tradable and are redeemable only at their maturity in 2003. The Series H bonds have been cancelled from time to time by the depositary, pursuant to our authorization, as the balance of the Petroleum and Alcohol Account decreased. We have no other rights to use, withdraw or transfer the Series H bonds before maturity in 2003.
From the issuance of the Series H bonds until September 30, 1999, the balance of the Petroleum and Alcohol Account decreased by U.S.$3,999 million as a result of the collection of the PPE, net of transportation subsidies. The collection of PPE was positive due to relatively low international oil product prices as compared to the sales prices established by the Brazilian government for our oil products. Accordingly, a corresponding amount of Series H bonds was cancelled.
From October 1, 1999 until December 31, 2000, our net operating revenues generally exceeded the amount recorded in sales of products and services, net of value-added and other taxes on sales and services, due to high international prices for oil products that were not fully reflected in the sales prices we were allowed to charge for our oil products during such period. As a result, PPE was negative during this period and the balance of the Petroleum and Alcohol Account increased.
During 2001, the balance of the Petroleum and Alcohol Account decreased by U.S.$1,428 million, mainly as a result of the positive collection of the PPE and a reduction of U.S.$405 million in connection with the certification of the balance of the account by the interministerial working group, as discussed below.
During 2002, the balance of the Petroleum and Alcohol Account increased by U.S.$101 million, mainly as a result of a provision of U.S.$259 million relating to expenses incurred in connection with Article 7 of Law No. 10,453, of May 13, 2002, which includes the Sugar Cane Cost Equalization Program in the Northeast Region as well as the receipt of credits and settlement of debts relating to events prior to December 31, 2001, as established by ANP.
The value of the outstanding Series H bonds was U.S.$46 million as of December 31, 2002, U.S.$92 million as of December 31, 2001 and U.S.$ 1,062 million as of December 31, 2000. The balance of the Petroleum and Alcohol Account was U.S.$182 million as of December 31, 2002, U.S.$81 million as of December 31, 2001 and U.S.$1,509 million as of December 31, 2000.
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Certification of the Petroleum and Alcohol Account
In September 1999, the Ministers of Finance, Agriculture, Internal Supply and Mines and Energy created a working group to certify the balance of the Petroleum and Alcohol Account for the period from April 1, 1992 to June 30, 1998. In December 2000, the working group concluded its certification process on a portion of the activity for this period, and we agreed to reduce the balance of the Petroleum and Alcohol Account by U.S.$106 million. The adjustments we accepted primarily related to differences in the calculation of the FUP/FUPA and the procedures used to determine the difference between our actual and the regulated cost of imported crude oil and oil products, both of which were eliminated with the implementation of new regulations on July 29, 1998. In December 2001, we received the final report on the audit by the interministerial working group for the 1992-1998 period. In addition to the U.S.$106 million adjustment arising from the certification completed in December 2000, the interministerial working group report included new recommendations to deduct U.S.$405 million from the Petroleum and Alcohol Account. In response to these recommendations, we agreed to reduce the balance of the Petroleum and Alcohol Account by the following adjustments:
On April 19, 2002, the ANP Director adopted Portaria No. 50, which established a commission to audit the activity recorded in the Petroleum and Alcohol Account for the period from July 1, 1998 through December 31, 2001. This audit proceeding started on May 27, 2002, the results of which will be the basis for the required settlement of the balance of the account with the Brazilian government. The changes in the Petroleum and Alcohol Account in the period July 1, 1998 to December 20, 2002 are subject to audits by the ANP, and in November 2002, the ANP recommended, and we agreed, to reduce the balance of the Petroleum and Alcohol Account by U.S.$29 million. The settlement of accounts with the Federal Government should have been completed by December 31, 2002, according to the provisions of Law No. 10453 of May 13, 2002, amended by Decree No. 4491 of November 29, 2002. As of the date of this annual report, settlement has not been effected. We are in constant contact with the ANP and the Secretaria do Tesouro Nacional (the National Treasury, or STN) in order to effect settlement of the account.
Since we have implemented all recommendations made by the interministerial working group, we do not expect significant additional adjustments to be necessary as a result of the audit by the ANP.
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:
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The following table summarizes the changes in the Petroleum and Alcohol Account for the years ended December 31, 2002, 2001 and 2000:
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.
With the effectiveness of the Oil Law and the regulations promulgated by the ANP thereunder, concessionaires were required to pay the government 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 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 of the Brazilian Institute for the Environment and Renewable Natural Resources, or IBAMA, and to the regulatory authority of the Conselho Nacional do Meio
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Ambiente (National Council for the Environment). 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. 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 new 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. Any other fees imposed by IBAMA in the future, however, may have a material adverse effect on us.
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:
As a result of our spill in the Guanabara Bay, on January 27, 2000, the National Council for the Environment enacted Resolution No. 265 of the Brazilian National Council for the Environment imposing an obligation on IBAMA and the state environmental agencies, 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 crude oil and oil products in Brazil within 240 days from the enactment of the resolution. Resolution No. 265 also required us to perform, within a six-month
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period, an independent environmental audit in all of our industrial installations located in the State of Rio de Janeiro. Finally, Resolution No. 265 required all companies with activities related to the production of crude oil and oil products in Brazil to submit to the National Council for the Environment, within 180 days, a plan and schedule for the implementation of independent environmental audits in all of their respective plants located in Brazil. On August 8, 2000, we filed our plan and schedule for the implementation of independent environmental audits with the National Council for the Environment for our plants in Brazil. In November 2001, all of our operating units had concluded their environmental audits as required by Resolution No. 265, except for BR, which due to the large number of its installations is scheduled to conclude its environmental audits by December 2003.
Under Law No. 9,966 of 2000, entities operating organized ports and port installations and owners or operators of platforms and its support installations must perform independent environmental audits every two years, with a view to evaluating the environmental management and control systems in their units. We are in full compliance with this law.
Law No. 9,985 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.
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.
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 transport and distribute products in Brazil. As a result, we expect these participants to begin importing refined oil products, which will compete with oil products from our Brazilian refineries, as well as the oil products we currently import. We will 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 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.
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.
In our international segment, we are planning to expand 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.
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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 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 A or higher by Standard & Poor’s rating agency. Other assets, such as small auxiliary boats, certain storage facilities, and some administrative installations, are self-insured. We do not maintain coverage for business interruption. Since November 2000, we maintain coverage for operational third-party liability with respect to our onshore and offshore activities, including oil spills. Although we do not insure our pipelines, we have insurance against damage or loss resulting from oil spills from our pipelines.
The premiums we paid in 2002 were distributed as follows: 48.6 % to coverage of our offshore assets, 31.1% to coverage of our onshore assets, 7.9 % to coverage of third-party liability, 3.8 % to coverage of risks associated with transportation, 2.8 % to hull and machinery risk coverage and 5.8 % to coverage for other risks. Over 30.5% of our annual insurance coverage relates to the domestic and international transportation of crude oil, products and materials. 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.
In November 2002, we signed a one-year general risk insurance contract that covers environmental risk. The insurance policy covers any damage resulting from either our or our affiliates’ activities, with the exception of Petrobras Internacional S.A., or Braspetro, which has its own insurance and is therefore not included in this policy. Under our insurance policy, the total covered amount of onshore and offshore risk is up to U.S.$250 million per incident and in the aggregate. This insurance policy, however, does not cover any fines that may be imposed on us or our affiliates. Although we believe that we are currently in compliance in all material respects with all applicable environmental laws, regulations and requirements, future environmental costs, including those related to past operations, may have a material adverse effect on our financial condition or results of operations.
The premium for renewing our general risk insurance policy for a 12-month period commencing June 2003 was U.S.$30.5 million, net of taxes. This represented a decrease of 34.4% over the preceding 12-month period. The decrease was primarily due to changes to our risk management and health, safety and environmental policies.
Following the sinking of Platform P-36, and as a result of the risks inherent in our operations, deductibles have increased and may increase up to U.S.$20 million per accident for our platforms and refineries.
Following the terrorist attacks in the United States, the insurance premiums charged for war risk and terrorism coverage increased significantly and may increase further prior to renewal, or the coverage may be unavailable in the future. We received a notice of cancellation of our war risk and terrorism insurance in December 2001. We subsequently were able to purchase war risk and terrorism insurance covering important assets in Brazil that we consider more susceptible to war and terrorism risk.
In October 2002, the Brazilian Supreme Court declared unconstitutional a bill that had been approved by Congress that provided for the privatization ofIRB-Brasil Resseguros S.A., or IRB, and which would have deregulated the Brazilian re-insurance market. We cannot predict if and when Congress will approve a new bill on the matter. Therefore, we do not expect that our insurance costs will be reduced by the opening of the Brazilian re-insurance market to competition in the near term.
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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
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.
We are one of the world’s largest integrated oil and gas companies. As of December 31, 2002, our estimated worldwide net proved crude oil and natural gas reserves were approximately 10.5 billion barrels of crude oil equivalent. During 2002, our average domestic production was 1.5 million barrels per day of crude oil and NGLs and 1.7 billion cubic feet per day of natural gas, and our average international production was approximately 35,224 barrels per day of crude oil and NGLs and 138 million cubic feet per day of natural gas. Our domestic refining capacity totals 1.93 million barrels per day of crude oil, which constitutes 98.6% of the Brazilian refining capacity. In 2002, approximately 79% of the crude oil feedstock for our refinery operations was supplied by our domestic production. During 2002, our consolidated net sales totaled approximately 911,817 million barrels of crude oil equivalent, generating net operating revenues of U.S.$22,612 million. See “—Sales Volumes and Prices.” In our efforts to become a fully integrated natural gas and power company, we are capitalizing on our natural gas assets and have positioned ourselves to be a significant participant in Brazil’s thermoelectric power industry.
We earn income from:
Our operating expenses include:
Year to year fluctuations in our income are the result of a combination of factors, including:
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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 2002 totaled approximately 911,817 million barrels of crude oil equivalent, representing U.S.$22,612 million in net operating revenues, as compared to approximately 862,009 million barrels of crude oil equivalent and U.S.$24,549 million in net operating revenues in 2001 and approximately 817,992 million barrels of crude oil equivalent and U.S.$ 26,955 million in net operating revenues in 2000.
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.$25.02 per barrel for 2002, U.S.$24.44 per barrel for 2001 and U.S.$28.50 per barrel for 2000. For December 2002, Brent crude oil prices averaged U.S.$28.67 per barrel, but during 2003 (through May), Brent crude oil prices have increased, averaging U.S.$29.85 per barrel. This increase in average crude oil prices also affected international prices for oil products.
Domestic Sales Volumes and Prices
During 2002, approximately 76.0% of our net operating revenues were derived from sales of crude oil and oil products in Brazil, as compared to 84.3% in 2001 and 87.0% in 2000. As export volumes of crude oil and oil products have increased, domestic sales as a percentage of net operating revenues have declined.
Until January 2, 2002, the Brazilian government established prices at which we were allowed to sell our oil products in Brazil. From July 1998 through 2001, our net operating revenues for domestic sales were determined based on a realization price, calculated pursuant to a pricing formula established by the Brazilian government. This formula was designed to reflect the international prices in U.S. dollars for relevant benchmark products, as adjusted for exchange rate variations for the prior month and transportation differentials to Brazil. The pricing formula was intended to transition the Brazilian market to international price levels for oil products in anticipation of the full price deregulation that occurred on January 2, 2002. See Item 4 “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”
The difference between the actual gross sales prices we charged (net of taxes and charges) and the net operating revenues based on realization prices, the PPE, was applied to reduce or increase the balance the Brazilian government owed to us on the Petroleum and Alcohol Account. In 1999 and 2001, our actual sales price exceeded the formula price which was established by the Brazilian government. This
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excess was not accounted for as an increase in our revenues, but was instead accompanied by an equivalent reduction of our assets on our balance sheet under the line item “Petroleum and Alcohol Account—Receivable from the Brazilian government.” The amount of the Petroleum and Alcohol Account receivable at December 31, 2002 was U.S.$182 million, a substantial decrease from a high of U.S.$7,414 million at December 31, 1996. As of January 2, 2002, we have been free to set our prices, subject to market conditions.
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 the three years ended December 31, 2002, 2001 and 2000:
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 increased 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.” As a result, our export volumes of crude oil and oil products have increased to 209,504 million barrels of crude oil equivalent in 2002, as compared to 127,829 million barrels of crude oil equivalent in 2001 and 88,661 million barrels of crude oil equivalent in 2000. 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 our increased volume of exports, as well as to a lesser degree an increase in average prices for export sales of crude oil and oil products, the total value of our crude oil and oil product exports (measured on a free-on-board basis) in 2002 was U.S.$4,760 million, as compared to U.S.$2,763 million in 2001 and U.S.$2,555 million in 2000. See Item 4 “Information on the Company—Refining, Transportation and Marketing—Exports.”
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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.$607 million in 2002, U.S.$1,034 million in 2001 and U.S.$902 million in 2000. 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
Although we currently produce approximately 80% of our crude oil requirements in Brazil, we continue to import lighter crude oil for use in our own refineries, as well as smaller quantities of diesel, liquefied petroleum gas, naphtha and other oil products, which are sold in the Brazilian retail market. As we have produced more domestic crude oil capable of being processed in our Brazilian refineries and have upgraded our refineries to handle heavier crude oil, we have reduced our purchases of imported crude oil and oil products. 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. As we further upgrade our refineries to handle larger quantities of our heavy crude oil, we expect our level of imports to continue to decrease. We imported a total of 117.6 million barrels of crude oil in 2002, as compared to 128.8 million barrels of crude oil in 2001 and 106.0 million barrels of crude oil in 2000.
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 supply the market, we continue to reevaluate our import strategy and may further reduce our level of imports to the extent profitable. We imported a total of 78.5 million barrels of oil products in 2002, as compared to 119.8 million barrels in 2001 and 140.1 million barrels in 2000. See Item 4 “Information on the Company—Refining, Transportation and Marketing—Imports.”
Effect of Taxes on our Income
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 3 to our audited consolidated financial statements.
Proposed Change in ICMS Legislation
The governor of the State of Rio de Janeiro is considering signing a bill into law that would increase the amount of ICMS that we are required to pay by approximately R$5.4 billion (U.S.$1.9 billion) per year. Currently, the ICMS is assessed at the refinery level at the point of sale of refined products, but not at the wellhead. As a result, the tax is mainly collected in the eight states where our refineries are located (Rio de Janeiro, São Paulo, Rio Grande do Sul, Paraná, Minas Gerais, Amazonas, Ceará and Bahia). If the new law becomes effective, it will change the point of collection of part of the ICMS from the refinery level to the wellhead level of production in the State of Rio de Janeiro. In that event, we may be unable to utilize part of the taxes imposed at the wellhead level in Rio de Janeiro to offset taxes that are imposed at the refinery level in other states, and therefore would be paying taxes on the same oil products at both the production and refining level. We believe that the proposed new law would be an unconstitutional form of taxation and intend to challenge the law if it becomes effective. If the law becomes effective, it would significantly increase the amount of taxes we pay, and such increase could have a material adverse effect on our income.
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.$1,142 million in 2002, U.S.$1,375 million in 2001 and U.S.$ 1,113 million in 2000. See “—Results of Operations—Results of operations for the year ended December 31, 2002 (“2002”) compared to the year ended December 31, 2001 (“2001”)—Financial Income” and “—Results of Operations—Results of operations for the year ended December 31, 2001 (“2001”) compared to the year ended December 31, 2000 (“2000”)—Financial Income.”
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.$774 million in 2002, U.S.$808 million in 2001 and U.S.$909 million in 2000. In addition, we capitalized U.S.$139 million in interest in 2002, as compared to U.S.$123 million in 2001 and U.S.$223 million in 2000. See “—Results of Operations—Results of operations for the year ended December 31, 2002 (“2002”) compared to the year ended December 31, 2001 (“2001”)—Financial Expense” and “—Results of Operations—Results of operations for the year ended December 31, 2001 (“2001”) compared to the year ended December 2000 (“2000”)—Financial Expense.”
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 has increased since the devaluation of the Real in January 1999. Inflation was 26.4% in 2002, 10.4% in 2001 and 9.9% in 2000, as measured by the IGP-DI, a general price index. Inflation has had, and may continue to have, effects on our financial condition and
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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. As expressed in U.S. dollars, however, these increases have been generally offset during the last four years by the effect of the appreciation of the U.S. dollar against the Real.
Exchange Rate Variation
Since we adopted the Real as our functional currency in 1998, the devaluation of the Real has 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 2002, there was a 52.3% devaluation of the Real, as compared to an 18.7% devaluation in 2001 and a 9.3% devaluation in 2000.
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. 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. In periods of sharp devaluations or high international prices, however, we may not be able to adjust our prices in Reais sufficiently to maintain parity with international prices, and may therefore not realize the higher operating revenues in Reais that result from an increase in prices.
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. During the last several years, our Reais-denominated costs have been increasing at a rate slower than the devaluation. Accordingly, the effect has been to decrease costs of locally supplied products and services when reported in U.S. dollars.
In recent periods, a devaluation of the Real has had the following additional effects, among others, on our financial condition and results of operations:
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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 devaluation of the Real 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, a devaluation of the Real 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 our unappropriated earnings available for distribution.
Business Segments
We participate in all aspects of the oil and gas business, from finding and extracting crude oil and natural gas from our reservoirs, refining crude oil and delivering the resulting oil products to the retail market. We have chosen to report our income related to the distribution and commercialization of our natural gas separately from crude oil, because of the growing importance of natural gas to our results. Due to the limited nature of our petrochemical operations, we include these results within our supply segment, rather than in a separate segment. We conduct approximately 96% of our oil and gas production in Brazil, and the remainder internationally, primarily in the rest of South America, West Africa and the Gulf of Mexico.
We report our results by market segment to reflect our organizational structure as follows:
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The segment information included in this annual report was prepared based on the same accounting policies reflected in our audited consolidated financial statements. Intersegment net revenues related to transfers of crude oil were recorded at estimated market prices based upon our internal model which considers a netback pricing methodology primarily based upon monthly prices for Brent crude, giving effect to product quality and transportation considerations as well as taxes paid. Until January 2002, intersegment sales and transfers related to oil products were recorded at the realization prices established by the Brazilian government for purposes of calculating our net operating revenues. Since January 2, 2002, when prices were deregulated, we have been free to record intersegment sales and transfers related to oil products based on prevailing market prices.
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The following table sets forth by segment selected financial data reflecting our domestic and international activities for the three years ended December 31, 2002, 2001 and 2000:
SELECTED FINANCIAL DATA BY SEGMENT(1)
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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 and oil products, 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:
Results of Operations for the year ended December 31, 2002 (“2002”) compared to the year ended December 31, 2001 (“2001”).
The comparison between our results of operations has been significantly impacted by the Real’s devaluation against the U.S. dollar, due to the fact that the average exchange rate for 2002 was 24.2% higher than the average exchange rate for 2001.
Revenues
Net operating revenues decreased 7.9% to U.S.$22,612 million for 2002, as compared to net operating revenues of U.S.$24,549 million for 2001. This decrease is primarily attributable to the 52.3% devaluation of the Real against the U.S. dollar in 2002, as we were unable to increase prices for oil products in the domestic market sufficiently to offset the effect of the devaluation. To a lesser extent, this
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decrease was a result of a 3.0% decrease in the domestic sales volumes. This decrease in net operating revenues was partially offset by an increase of 42.1% in sales volumes outside Brazil during 2002.
Our consolidated sales of products and services decreased 3.4% to U.S.$32,987 million for 2002, as compared to U.S.$34,145 million for 2001.
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
Cost of sales for 2002 decreased 10.2% to U.S$11,506 million, as compared to U.S.$12,807 million for 2001. This decrease was principally a result of:
These decreases were partially offset by:
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Depreciation, depletion and amortization
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 increased 11.6% to U.S.$1,930 million for 2002, as compared to U.S.$1,729 million for 2001. This increase was primarily attributable to a 12% increase in production of crude oil, NGL and natural gas, primarily in the Campos Basin, and an increase in abandonment costs as a result of increased production and a revision in our estimates of abandonment costs. These increases were partially offset by the effect of the devaluation of the Real against the U.S. dollar in 2002.
Exploration, including exploratory dry holes
Exploration costs, including costs related to exploratory dry holes increased 7.7% to U.S.$435 million for 2002, as compared to U.S.$404 million for 2001.
This increase was primarily attributable to an increase of approximately U.S.$38 million in dry holes expenses and U.S.$58 million in geological and geophysical expenses, and was partially offset by the effect of the devaluation of the Real against the U.S. dollar.
Impairment of oil and gas properties
For 2002, we recorded an impairment charge of U.S.$75 million, as compared to an impairment charge of U.S.$145 million for 2001. In 2002, the impairment charge was related to certain of our producing oil and gas properties in Brazil and Angola. In 2001, the impairment charge was related to certain of our producing oil and gas properties in Brazil, Colombia and the United States. 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 10%.
Selling, general and administrative expenses
Selling, general and administrative expenses decreased 0.6% to U.S.$1,741 million for 2002, as compared to U.S.$1,751 million for 2001.
Selling expenses increased 0.5% to U.S.$966 million for 2002, as compared to U.S.$961 million for 2001. Although largely offset by the effect of the devaluation of the Real on these expenses when expressed in U.S. dollars, this increase was primarily attributable to the following:
General and administrative expenses decreased 1.9% to U.S.$775 million for 2002, as compared to U.S.$790 million for 2001. This decrease was primarily attributable to the effect of the 52.3% devaluation of the Real against the U.S. dollar, and was partially offset by an increase of U.S.$62 million
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in expenses related to technical consulting services in connection with our increased outsourcing of selected non-core general and administrative activities.
Research and development expenses
Research and development expenses increased 11.4% to U.S.$147 million for 2002, as compared to U.S.$132 million for 2001. This increase was primarily related to our additional investments in programs for environmental safety and deepwater and refining technologies of approximately U.S.$41 million, and was partially offset by the effect of the devaluation of the Real against the U.S. dollar.
Equity in results of non-consolidated companies
Equity in results of non-consolidated companies decreased to a loss of U.S.$178 million for 2002, as compared to a loss of U.S.$8 million for 2001. This decrease was mainly attributable to:
Financial income
We derive financial income from several sources, including interest on cash and cash equivalents, long-term Brazilian government securities and government receivables, primarily the Petroleum and Alcohol Account.
Financial income decreased 16.9% to U.S.$1,142 million for 2002, as compared to U.S.$1,375 million for 2001. This decrease was primarily attributable to:
Financial expense
Financial expense decreased 4.2% to U.S.$774 million for 2002, as compared to U.S.$808 million for 2001. This decrease was primarily attributable to a reduction in LIBOR and our replacing of current maturities of long-term debt with newly contracted long-term obligations at lower interest rates.
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Monetary and exchange variation on monetary assets and liabilities, net
Monetary and exchange variation on monetary assets and liabilities, net increased 126% to an expense of U.S.$2,068 million for 2002, as compared to an expense of U.S.$915 million for 2001. Approximately 87% of our indebtedness was denominated in foreign currencies during each of 2002 and 2001. The expense increase is therefore primarily related to the effect of the 52.3% devaluation of the Real against the U.S. dollar during 2002 as compared to a 18.7% devaluation of the Real against the U.S. dollar during 2001.
Employee benefits expense
Employee benefits expense consists of financial costs relating to pension and other post-retirement benefits. Employee benefits expense decreased 24.1% to U.S.$451 million for 2002, as compared to U.S.$594 million for 2001.
This decrease was primarily attributable to a decrease in the provision of U.S.$78 million due to the annual actuarial calculation of the pension plan liability and by the effect of the devaluation of the Real against the U.S. dollar.
The decreases were partially offset by an expense of U.S.$34 million related to the migration process to our new pension plan and administrative fees in the amount of U.S.$16 million charged by PETROS in respect of the transfer of Series B Bonds to PETROS.
Other taxes
Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, increased 22% to U.S.$360 million for 2002, as compared to U.S.$295 million for 2001. This increase is primarily attributable to an increase of U.S.$79 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, and was partially offset by the effect of the 18.7% devaluation of the Real against the U.S. dollar.
Other expenses, net
Other expenses, net are primarily comprised of gains and losses recorded on sales of fixed assets, general advertising and marketing expenses and certain other non-recurring charges. Other expenses, net for 2002 increased 92.6% to U.S.$857 million, as compared to an expense of U.S.$445 million for 2001. The most significant non-recurring charges for 2002 were:
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The most significant non-recurring charges for 2001 were:
The losses for the year ending December 31, 2001 were partially offset by:
Income tax (expense) benefit
Income before income taxes and minority interest decreased 32.6% to U.S.$3,232 million for 2002, as compared to U.S.$4,792 million for 2001. As a result, we recorded an income tax expense of U.S.$1,153 million for 2002, a 17.0% decrease from an expense of U.S.$1,389 million recorded for 2001. The most significant factors that influenced this decrease were:
The reconciliation between the tax calculated based upon statutory tax rates to income tax expense and effective rates is shown in Note 3 to our audited consolidated financial statements as of December 31, 2002.
Results of operations for the year ended December 31, 2001(“2001”) compared to the year ended December 31, 2000 (“2000”)
Net operating revenues decreased 8.9% to U.S.$24,549 million for 2001, as compared to net operating revenues of U.S.$26,955 million for 2000. This decrease is primarily attributable to a decrease in international oil product prices from December 31, 2000 through December 31, 2001, which is
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reflected in the realization price we were allowed to charge for oil products. This decrease was partially offset by the increase in the volume of sales outside Brazil, which includes both international sales and exports.
Our consolidated sales of products and services decreased 3.8% to U.S.$34,145 million for 2001, as compared to U.S.$35,496 million for 2000. This decrease is primarily attributable to the effect of the 18.7% devaluation of the Real on our sales of products and services as expressed in U.S. dollars, which to a large degree was offset by increases granted by the Brazilian government in the prices we were allowed to charge for our basic oil products in Brazil during 2001, including aggregate increases of 9.1% in the price of gasoline, 8.6% in the price of diesel, 10.4% in the price of aviation fuel and 4.8% in the price of fuel oil. The net result of both of these effects was a net decrease of approximately U.S.$1,618 million in sales of products and services within Brazil, because the price increases granted were less than the effect of the devaluation, as a result of the decline in international prices for oil products. Slightly lower domestic sales of crude oil and oil products also contributed to the decrease.
This decrease was partially offset by an increase in revenues from sales outside Brazil of approximately U.S.$267 million, primarily attributable to an increase in our sales volume in the international market, which was offset in part by a decrease in international sales prices for oil products.
Cost of sales for 2001 decreased 4.8% to U.S.$12,807 million, as compared to U.S.$13,449 million for 2000. The principal items that contributed to the decrease in our cost of sales were:
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Depreciation, depletion and amortization expenses decreased 14.5% to U.S.$1,729 million for 2001, as compared to U.S.$2,022 million for 2000. The 18.7% devaluation of the Real was primarily responsible for the decrease in our depreciation, depletion and amortization expenses. These decreases were partially offset by the increase of approximately U.S.$193 million related to depreciation expenses on projects under development that were not active during all of fiscal year 2000.
Costs for exploration, including exploratory dry holes decreased 8.2% to U.S.$404 million for 2001, as compared to U.S.$440 million for 2000. This decrease was primarily attributable to the effect of the 18.7% devaluation of the Real on costs for exploration when expressed in U.S. dollars and a decrease of approximately U.S.$24 million in dry holes expenses. These decreases were partially offset by the increase of approximately U.S.$76 million related to geological and geophysical expenses.
For 2001, we recorded an increase in impairment charges of U.S.$145 million, as compared to U.S.$37 million for 2000. In 2001, we recorded an impairment charge with respect to some of our producing oil and gas properties in Brazil, Colombia and the United States. In 2000, the impairment charge was related to some of our producing properties in Brazil and Colombia. These charges were recorded based upon our annual assessment of the fields using prices consistent with those used in our overall Strategic Plan, discounted at a rate of 10%. See Note 8 to our audited consolidated financial statements.
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Selling, general and administrative expenses increased 20.8% to U.S.$1,751 million for 2001, as compared to U.S.$1,450 million for 2000.
Selling expenses increased 19.4% to U.S.$961 million for 2001, as compared to U.S.$805 million for 2000. Although partially offset by the effect of the 18.7% devaluation of the Real on these expenses when expressed in U.S. dollars, this increase was primarily attributable to the following:
General and administrative expenses increased 22.5% to U.S.$790 million for 2001, as compared to U.S.$645 million for 2000. Although partially offset by the effect of the 18.7% devaluation of the Real on these expenses when expressed in U.S. dollars, this increase was primarily attributable to the following:
Research and development expenses decreased 13.2% to U.S.$132 million for 2001, as compared to U.S.$152 million for 2000. This decrease was primarily attributable to the effect of the 18.7% devaluation of the Real on these expenses when expressed in U.S. dollars, although partially offset by increased investments in programs for environmental safety and deepwater and refining technologies.
Financial income increased 23.5% to U.S.$1,375 million for 2001, as compared to U.S.$1,113 million for 2000. The increase is primarily attributable to an increase in interest income from cash and cash equivalents, which amounted to U.S.$886 million for 2001, as compared to U.S.$607 million for 2000, primarily as a result of the increase in our average balance of cash and cash equivalents from U.S.$4,421 million for 2000 to U.S.$6,593 million for 2001. U.S.$243 million of our financial income is derived from our holding of NTN-P government securities which accrued all interest-in-kind.
Financial expense decreased 11.1% to U.S.$808 million for 2001, as compared to U.S.$909 million for 2000. This decrease was primarily attributable to a decrease in the LIBOR and U.S. Treasury
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rates, a reduction in the spread that we paid on the indebtedness that we incurred in 2001 and our replacement of maturing indebtedness with newly contracted indebtedness at lower rates. These lower rates were partially offset by a higher indebtedness balance on average of approximately U.S.$12,348 million. In addition, we capitalized U.S.$123 million in interest in 2001, compared to U.S$223 million in interest in 2000.
Monetary and exchange variation on assets and liabilities denominated in currencies other than Reais increased 59.1% to an expense of U.S.$915 million for 2001, as compared to an expense of U.S.$575 million for 2000. Approximately 87% of our indebtedness was denominated in currencies other than the Real during each of 2001 and 2000. The increase is primarily attributable to the effect of the 18.7% devaluation of the Real against the U.S. dollar during 2001, as compared to a 9.3% devaluation of the Real against the U.S. dollar during 2000.
Additionally, we realized a loss of U.S.$77 million in respect of our hedge contracts, due to the devaluation of the Japanese Yen against the U.S. dollar during 2001.
Employee benefits expenses consist of financial costs relating to pension and other post-retirement benefits. Employee benefits expenses increased 60.5% to U.S.$594 million for 2001, as compared to U.S.$370 million for 2000. The increase is primarily attributable to an administrative fee of 6% charged by PETROS in respect of the transfer of Series B Bonds by us to PETROS, amounting to an expense of U.S.$128 million, and an expense of U.S.$38 million related to the migration process to our new pension plan.
Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, increased 20.4% to U.S.$295 million for 2001, as compared to U.S.$245 million for 2000. This increase was due primarily to increases in value-added taxes payable with respect to interest income from short-term investments, and an increase in the CPMF payable on financial transactions during 2001. This was partially offset by the effect of the 18.7% devaluation of the Real against the U.S. dollar during 2001.
Loss on government securities
Loss on government securities was previously reported as a component of other expenses, net. Loss on government securities increased to U.S.$1,099 million for 2001, as compared to U.S.$192 million for 2000. In 2001, we exchanged our NTN-P bonds for NTN-B bonds. The NTN-P bonds could not be traded on the secondary market, nor had we intended to sell them, so we recorded them at face value. When we exchanged the NTN-P notes for the NTN-B bonds, we were required to mark them to the lower of cost or market value, and in marking them to market value, we recognized a loss. Subsequently, these NTN-B bonds were transferred to our pension plan, PETROS, in order to decrease our liability to PETROS. In 2000, our loss on government securities was attributable to marking to market SIBR and ELET government securities, which we transferred to PETROS in 2000.
Other expenses, net for 2001 decreased 1.1% to U.S.$445 million, as compared to U.S.$450 million for 2000. Other expenses, net are primarily comprised of gains and losses recorded on sales of
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fixed assets, certain other non-recurring charges and general advertising and marketing expenses. The most significant nonrecurring charges for 2001 were:
These losses were partially offset by:
The most significant non-recurring charges for 2000 were:
These expenses were partially offset by the U.S.$133 million received during 2000 as consideration under contracts we entered into with leading oil and gas companies for exploration, development and production ventures. Under the terms of these contracts, we sold a partial interest in each of these fields and recorded the proceeds received as a gain, since we had no carrying costs on them.
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Income tax expense decreased 45.0% to U.S.$1,389 million for 2001, as compared to an expense of U.S.$2,523 million for 2000. This difference is primarily attributable to a decrease in income before income taxes and minority interest from U.S.$7,803 million during 2000 to U.S.$4,792 million during 2001. See Note 3 to our audited consolidated financial statements.
Liquidity and Capital Resources
Capital expenditures
Total consolidated capital expenditures were U.S.$4,911 million in 2002, U.S.$4,254 million in 2001 and U.S.$3,583 million in 2000, reflecting increases of 15.4% in 2002 as compared to 2001 and of 18.7% in 2001 as compared to 2000. This increase in capital expenditures in 2002 was primarily a result of increased expenditures on our exploration and production activities and improvements in our refinery facilities. Of the capital expenditures incurred during 2002, U.S.$3,156 million (64%) were directed to domestic exploration and production activities, which includes our exploration and production segment, our project financings and our investments in thermoelectric power plants.
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 2002, 2001 and 2000:
Our capital expenditures in 2002, 2001 and 2000 were primarily directed towards increasing our production capabilities in the Campos Basin, modernizing our refineries, expanding our pipeline transportation and distribution systems and to a lesser extent, investing in energy and gas related activities, such as investments in natural and thermoelectric power plants.
In 2002, we spent U.S.$1,167 million on acquisitions. Some of the companies we have acquired may require additional financing for capital expenditures or for debt reduction. See Item 4. “Information on the Company—International—Argentine Activities.”
On April 17, 2003, we announced the adoption of revisions to our Strategic Plan for the period from 2003 through 2007. The new Strategic Plan maintains our main strategies and objectives, but reduces our overall budgeted capital expenditures for the year 2003. The revisions for 2003 reflect an environment of decreased access to financial markets and increased volatility in foreign exchange rates and crude oil prices.
Our capital expenditures budget for the year 2003, including our project financings, is U.S.$7.2 billion, allocated among each of our business segments as follows: (i) Exploration and Production:
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U.S.$3.8 billion; (ii) Supply: U.S.$1.4 billion; (iii) International: U.S.$0.8 billion; (iv) Gas and Energy: U.S.$0.8 billion; (v) Distribution: U.S.$0.3 billion; and (vi) Corporate: U.S.$0.1 billion.
Our Strategic Plan contemplates total budgeted capital expenditures of U.S.$34.3 billion in the period from 2003 through 2007, approximately U.S.$29.2 billion of which will be directed towards our activities in Brazil, while U.S.$5.1 billion will be directed to our activities abroad. We expect that the majority of our capital expenditures from 2003 through 2007, approximately U.S.$22.4 billion, will be directed towards our Exploration and Production business segment. Our average budgeted capital expenditures for the years 2003-2007 are consistent with net cash provided by operating activities during the last four years and with our future expected cash flows. We plan to meet our budgeted capital expenditures primarily through internally generated cash, while replacing maturing debt during this period with newly contracted financing and capital increases, if necessary.
Financing
We fund our investments and working capital with internally generated funds, short-term debt, long-term debt, project financings, sale and lease back agreements and bonds issued in the capital markets.
Our Indebtedness
Government Regulation
The total amount of medium and long-term debt that we are allowed to incur is controlled by the Ministry of Planning, Budget and Management, through the annual budget approval process (Plano de Dispêndio Global, or PDG). Before issuing medium and long-term debt, Petrobras and its 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 Petrobras’ and its Brazilian subsidiaries’ borrowings is subject to an annual maximum amount, exclusive of certain permitted commercial obligations, based on stockholders’ equity, debt service expense and other factors as of the prior year and subject to certain ongoing quarterly adjustments. For 2003, the maximum level has been initially set at U.S.$932 million. The maximum level was set at U.S.$824 million for 2002, U.S.$1,211 million for 2001 and U.S.$1,072 million for 2000.
All of the foreign currency denominated debt of Petrobras and its 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.
Total Indebtedness
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Our total debt (including short-term debt, long-term debt, project financing and sale and leaseback, including current portions) increased to U.S.$14,680 million as of December 31, 2002, from U.S.$14,010 million as of December 31, 2001. During that same period, our short-term debt (including current portions of long-term debt obligations) declined from U.S.$3,019 million as of December 31, 2001 to U.S.$1,986 million as of December 31, 2002.
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. During the last three years, we have succeeded in reducing short-term debt (excluding current portions of long-term debt obligations) to U.S.$671 million as of December 31, 2002, as compared to U.S.$1,101 million as of December 31, 2001 and U.S.$3,128 million as of December 31, 2000. Our short-term debt is denominated principally in U.S. dollars.
Long-Term Debt
Our total outstanding consolidated long-term debt consists primarily of issuance of securities in the international capital markets and debentures in the domestic capital markets and amounts outstanding under facilities guaranteed by export credit agencies and multilateral agencies, as well as financing from the Banco Nacional de Desenvolvimento Econômico e Social (the National Bank for Economic and Social Development, or BNDES) and other financial institutions. Outstanding long-term debt, plus the current portion of our long-term debt, totaled U.S.$7,714 million as of December 31, 2002, as compared to U.S.$6,848 million as of December 31, 2001 and U.S.$5,785 million as of December 31, 2000. Included in these figures as of December 31, 2002 are the following international debt issues:
If we had consolidated the financial statements of Perez Companc and Petrolera Perez Companc in our consolidated financial statements as of December 31, 2002, our total consolidated debt would have increased by U.S.$2,455 (18.6%). As of December 31, 2002, Perez Companc had total assets of P$13,579 million and total liabilities of P$8,677. When we begin consolidating Perez Companc, our balance sheet and cash flows will reflect Perez Companc’s financial position and cash flows. Our Strategic Plan takes this into account, and includes budgeted capital expenditures of Perez Companc in the contemplated capital expenditures of approximately U.S.$5.1 billion related to our international operations during the period from 2003 through 2007. We plan to manage the liquidity and funding requirements of Perez Companc independently of Petrobras, so that Perez Companc funds its own capital expenditures without funding or credit support from Petrobras.
During 2003, we have successfully completed three debt issuances in the capital markets. On March 31, 2003, we issued U.S.$400 million of 9.00% Global Step-Up Notes due 2008. These notes 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. This transaction represented our first issuance under our U.S.$8 billion universal shelf
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registration statement filed with the SEC in July 2002. On May 21, 2003, Petrobras Finance Ltd., a subsidiary of PIFCo, received U.S.$550 million in 6.436% Senior Trust Certificates due 2015, and U.S.$200 million in 3.748% Senior Trust Certificates due 2013 in connection with our asset receivables securitization program.
In addition to issuing foreign currency denominated debt in the international capital markets, we also issue 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. During 2002, we issued R$1,525 million (U.S.$432 million) in debentures, as set forth in the table below:
Project Finance and Off-Balance Sheet Arrangements
Project Finance
Since 1997, we have utilized project financings to provide capital for our continued financing of our large exploration and production and related projects. Our arrangements with respect to these projects are accounted for as capital leases and are on-balance sheet. Under the contractual arrangements, we are responsible for completing the development of the oil and gas fields, operating the fields, 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 leased or transferred assets from the special purpose company.
We continue to reflect the assets related to these projects on our balance sheet as a component of property, plant and equipment and the related debt obligations are on-balance sheet and accounted for under the line item Project Financings.
Many of our capital expenditures for 2002, 2001 and 2000 were made in connection with exploration and development projects in the Campos Basin, a number of which are being financed through project financings. Below are our material project finance expenditures by project for the years ended December 31, 2002 and December 31, 2001, as well as amounts representing future commitments under our contract obligations:
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Of the U.S.$1,433 million projected amount of expenditures for project financings in 2003, we expect that approximately U.S.$1,136 million will be used by our Exploration and Production segment (U.S.$756 million of which will be used in our Barracuda-Caratinga field), U.S.$228 million by our Gas and Energy segment and U.S.$69 million by our other segments.
Off Balance Sheet Arrangements
As noted above, all of our project financings are on-balance sheet. As of December 31, 2002, we had no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Our Cash Flow
Net cash provided by operating activities was U.S.$6,287 million for 2002, as compared to U.S.$8,743 million for 2001. This decrease was due primarily to a 7.9% decrease in net operating revenues.
Net cash used in financing activities amounted to U.S.$1,614 million for 2002, as compared to U.S.$1,754 million for 2001. This decrease was due primarily to dividends paid and net issuances and repayments of short-term debt, which was partially offset by an increase in payments related to project financings.
Financing Strategy
The objective of our financing strategy is to help us achieve the targets set forth in our Strategic Plan. We 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 financing, bank financing, securitizations and the issuances of debt and equity securities.
Contractual obligations
In the table below, we set forth our outstanding contractual obligations as of December 31, 2002, consisting of long-term debt including financial leases and operating leases, and the period in which the contractual obligations come due.
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We have certain operating leases related to computers and other equipment, but the total value of such leases is not material.
Critical Accounting Policies
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.
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.
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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, fluid sample core date and others. 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 is 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. 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. If the full cost method were used, all costs would be capitalized and depreciated on a field by-field basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.
Impact of Oil and Gas Reserves on Depreciation
The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation 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 the (3) asset cost. 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
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production. We revised our proved reserves in the last three years, increasing our proved reserves by 917.4 million barrels of oil equivalent in 2002, decreasing our proved reserves by 880.8 million barrels of oil equivalent in 2001 and increasing our proved reserves by 771.4 million barrels of oil equivalent in 2000. 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
Oil and gas producing properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future undiscounted 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 additional non-proved reserves will be developed and contribute to cash flows in the future.
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.
Pension and Other Post-Retirement Benefits
Determination of the projected benefit obligations for the company’s defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rate, rates of return on plan assets, future health care cost trends, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, the company engages outside actuarial firms to assist in the determination of these projected benefit obligations.
Each of these assumptions reflects estimates that are highly uncertain for a number of reasons, including uncertainty regarding long-term economic conditions in Brazil. Notwithstanding changes in inflation, interest rates and other economic variables, we have not
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changed the assumptions, because the uncertainty concerning long-term developments in the Brazilian economy makes it difficult to apply the principles set forth in U.S. GAAP and to agree on specific assumptions. We may change these assumptions in the future, and any such changes could have a material effect on reported liabilities and, to a lesser extent, on reported earnings.
In particular, we believe that the weighted average discount rate that we apply to determine the present value of our future obligations for pensions and other post-retirement obligations may be subject to revision to reflect changes in the Brazilian financial markets. U.S. GAAP require that the discount rate reflect the price at which the pension benefits could be effectively settled, and encourage the use of rates of return on high-quality fixed-income investments currently available and expected to be available in the market. In recent years, the Brazilian government has issued long-term inflation-indexed securities that are traded in an increasingly liquid market. We believe that the high rates of return on these securities suggest that it would be appropriate to increase the discount rate assumption, but there are interpretive problems under U.S. GAAP with this view and with increasing the spread between the discount rate assumption and the assumed rate of future increase in compensation. We are currently discussing these issues with our auditors and actuaries, and these discussions could result in a change in assumptions in the near future. Such a change could have a significant effect on the amount of our pension liability and expense.
Litigation and Other Contingencies
Claims for substantial amounts have been made against us. 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. 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 have a material adverse effect on our operations or cash flows.
Recent Accounting Pronouncements
The Financial Accounting Standards Board (“FASB”) has recently issued the following Statements of Financial Accounting Standards (“SFAS”):
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We are beginning to assess the impact of SFAS No. 145 and No. 146 and therefore, at this time cannot reasonably estimate the effect of these statements on our financial condition, result of operations and cash flows.
Research and Development
Since 1966, we have maintained a dedicated research and development facility in Rio de Janeiro, Brazil. As of April 30, 2003, we had 1,311 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.$23.0 million in 2002 on joint projects with Brazilian universities and technological institutions. 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, 2002, we had 27 floating production systems in operation (14 semi-submersibles, 12 FPSO and 1 FSO), 24 of which we engineered. We have obtained 80 patents in Brazil and abroad for a significant number of the technologies produced through research and development activities during the three-year period ended December 31, 2002.
Of the projects in which we are currently involved, three programs are key to our technological development activities. The first project, originally named PROCAP 2000, is our technological development program for deepwater production systems, which was established in 1993 with a budget of U.S.$52 million to develop additional deepwater and ultra deepwater technology. This program aimed to enhance recovery of oil and gas reserves and to extend the life of wells located at depths greater than 984 feet (300 meters). The program was extended for two additional years after the expiration of the initial term and was finalized in December 1999 through an increase of R$12.2 million (approximately U.S.$7 million) to the original PROCAP 2000 budget. In 2000, PROCAP 3000 was launched with a budget of U.S.$128 million over three to four years to provide technological solutions to produce and support the
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next phases of development of Marlim Sul, Roncador, Albacora Leste and Albacora in order to achieve production and extraction in water depths beyond 9,842 feet (3,000 meters) a reality.
The second project, the Advanced Oil Recovery Program — PRAVAP, is designed to increase our oil reserves and production through the improvement of our recovery factor from mature oil development areas. The program was established in 1993 to complete seven projects in five years with an estimated budget of U.S.$53 million. The program is now focused predominantly on reservoirs in the Campos Basin, where the greatest known reserves are located.
The third project, the Strategic Refining Technology Development Program — PROTER, was established in 1994 to assist our refineries in reducing costs, refining greater volumes of heavy oils, and meeting increased demand for higher quality products. The 2003 budget for this program is U.S.$0.5 million. Work done under this program has led to the development of technologies used by our fluid catalytic cracking (FCC) units, including a residue cracking process specifically developed for use with heavy and acidic types of Brazilian oils found in the Cabiúnas and Marlim fields.
Our research center is also involved in technology exchange and assistance projects in partnership with other oil companies such as: Royal Dutch/Shell (subsea completion, floating production systems, hydrates and paraffins); Texaco (deep water exploration and production); AGIP (pressure phase of the development of the vertical annular separation and pumping systems); BP/STATOIL (floating production systems, risers, deepwater drilling and subsea technology); and Chevron (pipeline transportation) as well as with a number of prominent international universities and other institutes.
Our total expenditures on research and development at our dedicated research and development facility were U.S.$147 million in 2002, U.S.$132 million in 2001 and U.S.$ 152 million in 2000.
Trend Information
For a description of trends that might affect our financial condition and results of operation, see Item 4 “Information on the Company—Competition”.
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
Directors and Senior Management
Our Board of Directors
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 and an alternate 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 Federal Government always has the right to appoint the
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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 shall be held.
We currently have nine directors. The following table sets forth certain information with respect to these directors:
BOARD OF DIRECTORS
Dilma Vana Rousseff - Ms. Rousseff has been a member of our board of directors since January 3, 2003 and was appointed chairman of the board of directors of our company and BR on January 3, 2003. Since January 1, 2003, she has held the post of Minister of Mines and Energy 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 in the Governmental Transition Team as Coordinator of the Infrastructure Group.
Jaques Wagner - Mr. Wagner has been a member of our board of directors since February 17, 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 Labor and Employment. 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, 1981-present). 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 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
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Ribeirão Preto (1989-1990). Mr. Palocci has also served as President of thePartido 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 1995, he has been a General of the Brazilian Army. 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).
Gerald Dinu Reiss - Mr. Reiss 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 is currently also a vice-president of Cevekol S.A. Indústria e Comércio de Produtos Químicos, a managing partner of Consemp Consultoria e Empreendimentos Industriais Ltda. and a member of the board of directors of several public and private sector companies. Mr. Reiss has also served as a member of the board of directors of Grow Jogos e Brinquedos S.A. (1972-1991) and Director of Planning and Development for Grupo Ultra (1980-1986).
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. Since March 1999, he has been President and partner of Ibmec Educacional S.A., a business and economics school in Brazil, and since January 2001, he has been the President of the board of directors of IBTS S.A., a professional information technology and telecommunications training entity. He has also served as: Chief Executive Officer of Banco de Investimentos Garantia S.A. (1992-1998); Partner and Director of Banco de Investimentos Garantia S.A., responsible for the Corporate Finance Division and subsequently for all the Investment Banking Division (1983-1992); and Director of the Central Bank of Brazil, responsible for public debt and open market operations (1980-1983).
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); 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 theFederação Brasileira das Associações de Bancos (Brazilian Bank Associations Federation – FEBRABAN) and of the Conselho de Desenvolvimento Econômico e Social do Governo Federal (Brazilian Government Social and Economic Development Council).
Jorge Gerdau Johannpeter - Mr. Johannpeter has been a member of our board of directors since October 19, 2001 and is also a member of the board of directors of BR. He also serves as: President of the board of directors of Gerdau Group, a steel company; coordinator of Ação Empresarial Brasileira (Brazilian Corporate Action), a non-governmental Brazilian organization addressing developmental issues; leader of Programa 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; President of Conselho do Prêmio Qualidade do Governo Federal(Brazilian Government Quality
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Prize Council); Director and Vice-President of Instituto Brasileiro de Siderurgia (the Brazilian Steel Institute, or the IBS); Chairman of the board of directors of Aço Minas Gerais—Açominas; President of Conselho Superior do Movimento Brasil Competitivo (Competitive Brazil Movement Superior Council, or MBC); member of the Brazilian Government Social and Economic Development Council.
Our Executive Officers
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 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
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—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 served as dean of the Economic Sciences School of the Federal University of Bahia and superintendent of the Fundação de Apoio a Pesquisa e Extenção (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, 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. Estrela 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
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(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 (Brazilian Oil and Gas Institute) of which he is now the Chairman of the Board.
Rogério Almeida Manso da Costa Reis – Mr. Reis has been our Director of Refining, Transportation and Marketing since September 10, 2001. Currently, Mr. Reis is also a member of the boards of directors of Petrobras Energia Participaciones S.A., Petrobras Energia S.A., Companhia Petroquímica do Sul (Copesul) and the Alberto Pasqualini Refinery and a director of Petrobras Internacional Finance Company (PIFCo). He joined our company in 1979 and has held several positions, including Marketing Director, Logistics and Supply Manager. He has also served as Sales Manager of the Commercial Office in New York which purchased and marketed oil refined by Petrobras (1986-1990).
Ildo Luís Sauer – Mr. Sauer has been our Manager of Natural Gas and Power since January 31, 2003. Currently, Mr. Sauer is also a member of the boards of directors of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. He is a Professor of the Instituto de Eletrotécnica e Energia da Universidade de São Paulo (Electrotechnical and Energy Institute of the University of São Paulo) since 1991 and has served as an analyst and policy formulator for the energy sector for the past ten years. Mr. Sauer has also worked as a consultant at TecSauer Consultoria Ltda., where he provided consulting services for several entities, and nuclear reactor development project manager at the Brazilian Navy (1986-1989).
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 thermoelectrical energy companies and acted as assistant to thePresidência da Comercializadora Brasileira de Energia Emergencial (Presidency of the Brazilian Supplier of Emergencial Energy — CBEE) of the Ministry of Mines and Energy.
Compensation
For the year ended December 31, 2002, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was approximately U.S.$921 thousand.
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, educational expenses and supplementary social security benefits.
We have no service contracts with our directors providing for benefits upon termination of employment. We do not have a compensation committee.
We currently sponsor a defined benefit plan known as PETROS and have established a new contributory benefit pension plan known as Petrobras VIDA, which is being legally challenged by the Oil Workers Federation and has not yet been implemented. For more information, see “—Employees and Labor Relations—Our Pension Fund.”
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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 incurred by us 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 April 30, 2003, the members of our board of directors, our executive officers, the members of our audit committee, and close members of their families, as a group, beneficially held a total of 1,512 common shares and 1,937 preferred shares of our company. Accordingly, on an individual basis, and as a group, our directors, executive officers, audit committee 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, audit committee 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, audit committee members, or close members of their families holds any options to purchase common shares or preferred shares, and there are no arrangements for involving our employees in the capital of our company.
Audit Committee
Brazilian corporation law requires us to establish a permanent audit committee. Accordingly, our bylaws provide for a permanent audit committee composed of up to five members. A person elected to serve on this committee must be a resident of Brazil and either be a university graduate or have been a company officer or audit committee member of a Brazilian company for at least three years prior to election to the committee. Under our bylaws, 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, other than the Brazilian government, are each entitled to elect one member and his respective alternate to the audit committee. Under our bylaws, one member and his respective alternate are appointed by the Minister of Finance representing the Treasury. The Federal Government has the right to appoint the majority of the members of the audit committee and their alternates. None of the members of our audit committee is a member of our board of directors.
The following table sets forth certain information with respect to our audit committee:
AUDIT COMMITTEE
Employees and Labor Relations
We had 40,848 employees as of December 31, 2002, compared to 38,483 as of December 31, 2001 and 38,908 as of December 31, 2000. The increase in the number of our employees in 2002 was
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due to normal hiring practices related to our business requirements. Expenses relating to employees of the parent company amounted to approximately R$3,019 million (U.S.$1,033 million) in 2002, R$2,966 million (U.S.$1,260 million) in 2001 and R$2,636 million (U.S.$1,441 million) in 2000. During 2002, these expenses represented 83% of our consolidated employee expenses. Of the 34,520 employees of the parent company, as of December 31, 2002, 33,503, or 97%, were classified as onshore employees and 3% were classified as offshore employees. Employees who work on ships are classified as offshore employees, while all others are considered onshore employees. We also subcontract certain services, such as data processing, security and cleaning.
All of our employees, except the maritime employees, are subject to a collective bargaining agreement with the Oil Workers’ Unified Federation, which we signed on December 4, 2002, retroactive to September 1, 2002, and which will expire on August 31, 2003. On December 27, 2002, we signed a collective bargaining agreement with the maritime employees’ union, retroactive to November 1, 2002, which will expire on October 31, 2003. Our collective bargaining agreements are subject to renewal on an annual basis. Under the terms of these agreements, we agreed to:
On October 19, 2001, our oil workers began a five-day strike. The cause of the strike was a dispute over wage increases during the negotiations of the collective bargaining agreement for 2001. This strike caused a decrease in oil production of four million barrels for the five-day period. On May 3, 2002, oil workers held a one-day strike, due to a dispute over our profit-sharing proposal, causing no material decrease in oil production. Neither of the strikes affected our average production targets for 2001 or 2002 or our level of oil imports. A labor strike has not caused a material decrease in production since 1995, when a 30-day strike by the oil workers was held 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.
We provide approximately three million hours of annual training to our employees at our training centers (Universidade Corporativa). Despite budget limitations, we have been able to maintain this total number of training hours as a result of improved training processes. We spent approximately U.S.$30 million on employee training in 2002, and we intend to spend U.S.$50 million on employee training 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 plan to include more flexible compensation packages, 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 will be determined by negotiation with the labor unions representing our 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.
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Our profit sharing distributions to our employees were R$444 million (U.S.$152 million) for 2002, R$416 million (U.S.$168 million) for 2001 and R$307 million (U.S.$159 million) for 2000. At the annual general shareholders’ meeting held on March 27, 2003, our shareholders approved a profit sharing distribution to our employees of R$380 million (U.S.$108 million) for the year ended December 31, 2002, which was distributed in May 2003, and our subsidiaries approved profit sharing distributions to their employees of R$64 million (U.S.$22 million) at their annual general shareholders’ meeting in March 2003.
Our Pension Fund
We sponsor a contributory defined benefit pension plan known as PETROS, which covers substantially all 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. 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 recorded a liability of U.S.$1,452 million in 2002, U.S.$ 2,088 million in 2001 and U.S.$ 3,308 million in 2000 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 14 to our audited consolidated financial statements.
On May 11, 2001, our board of directors approved the creation of a new mixed benefit plan for existing, active and inactive employees. The new plan, Petrobras VIDA, is 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.
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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. 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 new plan and prevented us from including any employees under this plan. 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.
If Petrobras VIDA becomes effective, our goal is to migrate existing participants in the PETROS plan to the new plan and permit new employees to participate in the new plan. The actual costs of closing participation in PETROS and migrating participants will depend on the level of migration. We expect that, if migration is allowed to resume, the new plan will be the principal employee benefit plan for our employees. We do not expect that the additional costs of implementing the new plan and migrating employees to the new plan will have a material adverse effect on our financial condition.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major Shareholders
Our capital stock is composed of common shares and preferred shares, all without par value. As of December 31, 2002, there were 634,168,418 outstanding common shares and 451,935,669 outstanding preferred shares as adjusted for the 1 for 100 reverse stock split approved by our board of directors on April 24, 2000 and effective as of May 23, 2000. 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.
The following table sets forth information concerning the ownership of our common shares and preferred shares as of April 30, 2003 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.
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 55.7%. In July 2001, BNDES sold 41,381,826 of our preferred shares, which constituted its entire holdings of our shares.
The extraordinary shareholders’ meeting held together with the general shareholders’ meeting on March 27, 2003, approved an increase our capital by capitalizing revenue reserves accrued during previous years, amounting to U.S.$912 million without issuing new shares, in accordance with Art. 169, paragraph 1 of Law No. 6404/76.
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As of April 30, 2003, approximately 40.0% of our preferred shares and approximately 25.2% of our common shares were held of record in the United States. As of April 30, 2003, we had approximately 185,343,824 record holders of preferred shares, or American Depositary Shares representing preferred shares, and approximately 179,716,640 record holders of common shares, or American Depositary Shares representing common shares, in the United States.
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 significant to our business during the current or the three immediately preceding financial years or during any earlier financial year which remains in any way outstanding or unperformed.
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
As of December 31, 2002, we had a receivable (the Petroleum and Alcohol Account) from the Brazilian government, our controlling shareholder, of U.S.$182 million secured by U.S.$46 million of National Treasury Bonds—Series H issued by the Brazilian government. In addition, between 1991 and 1996 we received privatization currencies and securities from the Brazilian government as consideration for the sale of our shareholdings in certain subsidiaries and affiliates of Petroquisa and Petrofértil.
On September 11, 1997, the privatization currencies were exchanged for National Treasury Bonds—Series P (Series P bonds) issued by the Brazilian government. Series P bonds are non-transferable, except with the consent of the Brazilian government.
On July 4, 2001, the Brazilian government created the National Treasury Bonds—Series B (Series B bonds). The Series B bonds are freely transferable and indexed to the IPCA with the terms and interest rate defined by the Finance Ministry.
On December 28, 2001, we exchanged the Series P bonds held by us for Series B bonds issued by the Brazilian government. The exchange was accounted for at fair value of U.S.$3,239 million, and we recorded a loss of U.S.$1,099 million in the results of our operations for the year. At such time, in accordance with a contract signed between us and PETROS, we transferred the rights on a substantial portion of the Series B bonds to PETROS to increase pension assets.
PETROS and BNDESPAR, among other investors, have subscribed to shares and debentures issued by special purpose vehicles created as part of the Marlim and Nova Marlim project financings. BNDESPAR, among other investors, has subscribed to shares issued by a special purpose vehicle created as part of the Pargo, Carapeba, Garoupa and Cherne project financing. PETROS also invests in special purpose vehicles created in connection with the Albacora-PETROS and Termobahia Project financings.
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At December 31, 2002, PETROS had lent us U.S.$107 million in project financing loans for the development of the Albacora field.
BNDES
In February 1998, we established an approximately U.S.$380 million program for the issuance of Brazilian debentures to BNDES, bearing interest at the Taxa de Juros de Longo Prazo, or TJLP interest rate, the Brazilian government’s long-term interest rate, plus a margin of 2.5%, due February 2015 and guaranteed by Petrobras Gás S.A. and secured by a pledge of assets of Gaspetro. On December 31, 2002, the balance of debentures issued was U.S. $194.2 million.
BNDES, in its role as an economic development bank, is involved with us as a lender and/or co-investor in a number of projects, and will probably continue to be involved in the future.
Current activities of BNDES related to us include:
ITEM 8. FINANCIAL INFORMATION
Consolidated Statements and Other Financial Information
See Item 18 “Financial Statements” and “Index to Financial Statements.”
Legal Proceedings
We are currently subject to numerous proceedings relating to civil, criminal, administrative, environmental, labor and tax claims, which involve a wide range of issues. Several individual disputes account for a significant part of the total amount of claims against 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. As of December 31, 2002, the accruals for contingencies was U.S.$50 million, which we believe to be sufficient to meet probable and reasonably probable losses in the event of unfavorable rulings relating to the legal proceedings in which we are a party, including the ones described in Item 4 “Information on the Company—Environmental Liabilities”. See Note 14 to our audited consolidated financial statements.
Claims against Petrobras, the parent company, which as of December 31, 2002, corresponded to approximately 93% of the total amount of claims against us, have decreased and the amounts paid by us in respect of legal claims in each of the last five years have never exceeded U.S.$27 million, having been consistently immaterial to our results of operations and financial condition. As of December 31, 2002, 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.$7.2 billion.
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On November 23, 1992, Porto Seguro, a minority shareholder of Petroquisa, brought a lawsuit against us in the State Court of Rio de Janeiro for alleged losses suffered by Petroquisa in connection with the sales of certain of its subsidiaries. On January 14, 1997 we were held liable to Petroquisa for damages in the amount of R$9,062 million. We appealed this decision and, on February 11, 2003, by a majority vote, the State Court of Appeals of Rio de Janeiro accepted our appeal and dismissed the plaintiff’s claim. We expect Porto Seguro to appeal this decision and, if Porto Seguro prevails on appeal, an additional amount equal to 5% of the award would be payable to Porto Seguro, as a minority shareholder premium, and an additional amount equal to 20% of the award would be payable to Porto Seguro’s attorneys. However, because the award would be payable to Petroquisa and we own 99% of the total capital of Petroquisa, we would only be liable for approximately 25% of the judgment amount. We consider the risk of loss with respect to this claim to be remote.
On January 15, 1986, the Public Ministry of the State of São Paulo and theUnião 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. Therefore, we consider the risk of any material loss with respect to this claim to be remote.
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 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. We consider the risk of loss with respect to this claim to be remote.
On March 18, 1999, Itasul Indústria e Comércio de Pescados S.A. brought a civil suit against BR in the state court of Santa Catarina requesting indemnification for alleged losses incurred as a result of BR’s reporting the plaintiff’s payment default to the government credit agency. The plaintiff maintains that BR’s actions prevented it from obtaining any financing to continue its business operations or to meet its contractual duties to third parties. The plaintiff claims losses in the amount of approximately R$1,462 million. The trial court is currently questioning the amount of damages claimed by the plaintiff. BR believes that the likelihood that it will be held liable for the alleged damages is remote and that, even in the event that BR is held liable, any judgment would be significantly lower than the amount claimed. This lawsuit is currently in the discovery phase.
Several individuals have filed a lawsuit (an ação popular) against us, Repsol-YPF and the Brazilian government seeking to unwind the transaction pursuant to which we exchanged some 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. At the request of the Brazilian government, Justice Nilson Naves, Chief Justice of the Superior Court of Justice of Brazil, suspended the injunction, stressing that the transaction had already been approved by the Brazilian antitrust authorities, the ANP and the Brazilian Federal Audit Court. We consider the risk of loss with respect to this claim to be remote. For a description of the asset swap transaction, see Item 4 “Information on the Company—International—Argentine Activities—Repsol Asset Swap”.
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We are a defendant in seven labor lawsuits filed 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. Labor unions in the States of Rio de Janeiro, São Paulo and Sergipe have alleged that the failure to apply this indexation to the salaries of certain employees reduced the income of the relevant employees and unjustly deprived them of amounts which would have accrued in relation to salaries earned during the relevant years. The lawsuits are each at different stages of the litigation process. Based upon our previous victories in similar actions and the position of the Brazilian Superior Court of Labor Law on the matter, we believe that the risk that any material judgment will be entered against us is remote.
Certain independent distributors located throughout Brazil have brought civil claims against us. Collectively, these claims total approximately R$1,271 million and aim at the restitution of the Imposto sobre Circulação de Mercadorias e Serviços (state value-added tax, or 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$79 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 to date only a small portion of that amount (approximately R$4 million) has been returned to us. We consider the risk of loss with respect to these claims to be remote, but we cannot give assurance that we will be able to effectively recover the remaining portion of the aforementioned amount.
The tax authority of the State of São Paulo filed legal proceedings against us alleging that we improperly claimed certain credits relating to the collection of the ICMS on interstate sales of naphtha. The approximate aggregate amount of these claims is R$212 million. We cannot give assurance that the final decision would be favorable to us, but even in the case we lose, we do not believe that an unfavorable ruling would have a material adverse effect on us.
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, in accordance with paragraphs 5 and 6 of Article 219 and paragraphs 2 and 3 of Article 220 of Decree 3048/99. 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, we have established a U.S.$105 million provision to cover future payments to the INSS.
In response to the INSS’s assessments, we have revised our internal procedures to improve the inspection of contracts and to ensure that contractors are presenting proper documents evidencing the payment of INSS contributions, in accordance with applicable legislation. In connection with service contracts requiring the employment of substantial numbers of workers, we directly discount 11% of the invoiced value of such service contracts and pay this amount directly to the INSS. Additionally, in January 2003, we established automated procedures for verifying that service contractors comply with their INSS obligations and ensuring that no payment is made to service providers until we have verified such compliance.
We have been the defendant in a number of civil, administrative and criminal proceedings related to alleged violations of environmental laws and regulations, including lack of licenses required to operate our platforms in the Campos Basin, and environmental damages caused by significant oil spills. For a
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description of existing environmental lawsuits, see Item 4 “Information on the Company—Environmental Liabilities.”
We are currently involved, on behalf of the special purpose company involved in the Barracuda/Caratinga project financing, in negotiations with Halliburton Company and its subsidiary Kellog Brown & Root, Inc., KBR, regarding certain claims relating to construction activities involved in the project. We have reached an agreement with Halliburton and KBR with respect to certain claims, subject to the project lenders’ approval, extending some construction milestones and increasing the costs related to the project. We have agreed with Halliburton and KBR to submit the remainder of the claims to arbitration in accordance with the terms of the project agreements. The total amount of the KBR claims against the project company is approximately U.S.$375 million and the total amount of claims that we and the project company have against Halliburton and KBR, in addition to liquidated damages, is approximately U.S.$380 million. An adverse determination with respect to either set of claims could adversely affect our operating results and financial condition.
On June 13, 2003, the governor of the State of Rio de Janeiro signed a bill into law that should increase the amount of ICMS that we are required to pay by approximately R$5.4 billion. We intend to challenge the new law as an unconstitutional form of taxation. For a more detailed description of this matter, see Item 5 “Operating and Financial Review and Prospects—Effect of Taxes on our Income—Change in ICMS Legislation”.
For a description of the lawsuit relating to the migration of employees from PETROS to the new pension plan, see Item 6 “Directors, Senior Management and Employees—Employees and Labor Relations—Our Pension Fund.”
Dividend Distribution
For our policy on mandatory dividend distribution see Item 10 “Additional Information—Memorandum and Articles of Incorporation—Payment of Dividends and Interest on Shareholders’ Equity.”
ITEM 9. THE OFFER AND LISTING
Trading Markets
Our shares and ADSs are listed or quoted on the following markets:
We are currently applying for listing of our shares on the Buenos Aires Stock Exchange.
Price Information
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 and for a description of the commercial market rate as compared to other rates.
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The tables below set forth the reported high and low closing sale prices per common and preferred share and the reported average daily trading volume in common and preferred shares on the New York Stock Exchange for the periods indicated.
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Markets
In 2000, the Brazilian stock exchanges entered into memoranda of understanding to reorganize themselves. Pursuant to the memoranda, all securities are now 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. In 2001, the São Paulo Stock Exchange accounted for 100% of the trading value of equity securities on all Brazilian stock exchanges.
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. As of April 30, 2002, the aggregate market capitalization of the 412 companies listed on the São Paulo Stock Exchange was approximately U.S.$189.4 billion and the ten largest companies listed on the São Paulo Stock Exchange represented approximately 47.2% 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 actually available for trading by the public. The remainder is held by small groups of controlling persons, by
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governmental entities or by one principal shareholder. As of April 30, 2002, we accounted for 13.8% of the market capitalization of all listed companies on the São Paulo Stock Exchange.
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. See Item 10 “Additional Information—Exchange Controls” and Item 10 “Additional Information—Brazilian Tax Considerations—Taxation of Gains” for a description of 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 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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Trading on the São Paulo Stock Exchange by non-residents of Brazil is subject to limitations under Brazilian foreign investment and tax legislation. The Brazilian custodian for the common 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 upon the disposition of the shares and sales proceeds. In the event that a holder of ADSs exchanges ADSs for common 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 shares or distributions relating to the common shares, unless the holder obtains a new registration. See Item 10 “Additional Information—Exchange Controls.”
ITEM 10. ADDITIONAL INFORMATION
Memorandum and Articles of Incorporation
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 resident 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.
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
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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.
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
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. 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 us, to suspend the mandatory distribution if the board of directors and the audit committee 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 rata variation of the TJLP interest rate, the Brazilian government’s long-term interest rate.
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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:
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 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 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.
Our preferred shares are entitled to priority in the distribution of the greater of a 5% minimal dividend, calculated over the part of our capital stock represented by the preferred shares, or 3% of the share 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 andValor 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.
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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. 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:
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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.
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:
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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. Preferred shareholders that hold a minimum number of shares have the right to appoint one member to our board of directors and to our audit committee. Preferred shareholders are not entitled to vote on any other matter.
Furthermore, according to our bylaws, common shareholders have the right to appoint and/or dismiss one member to or from our board of directors. 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 audit committee.
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 audit committee.
Our bylaws provide that, independently from the exercise of the rights above granted to minority shareholders, through cumulative voting process, the Federal 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 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.
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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 ten 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.
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.
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Form and Transfer
Our shares are registered in book-entry form and we have hired Banco Itaú to perform all the services of safe-keeping and transfer of shares. To make the transfer, Banco Itaú 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 auditing committee 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 audit committee 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 accordance with Resolution No. 2,689 may buy and sell
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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 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.
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 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 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 four auctions conducted thus far, we acquired interests in 37 exploration areas. See Item 4 “Information on the Company—Exploration, Development and Production—Exploration Activities—Exploration Bidding Rounds.”
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Under our concession agreements with the ANP we are required to pay the Brazilian 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 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 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.
Natural Gas Purchase and Sale Agreement
Pursuant to a 1996 commercial contract for the purchase of natural gas between us and the Bolivian state oil company, Yacimientos Petroliferos Fiscales Bolivianos, we are required to purchase from YPFB on a take-or-pay basis specified quantities of natural gas transported through the Bolivia-Brazil pipeline over a 20-year term. We also have a transportation capacity option valid for a 40-year term. The transportation capacity option was granted to us in exchange for our investment of approximately U.S.$379 million in the Bolivia-Brazil pipeline.
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.”
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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:
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.”
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Taxation
The following summary contains a description of certain Brazilian and U.S. federal income tax consequences of the purchase, ownership and disposition of preferred or common shares or ADSs by a holder.
The 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.
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 at present no income tax treaty between Brazil and the United States. In recent years, the tax authorities of the two countries 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.
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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 bonds traded in the Brazilian market), 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 a 20% rate. 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%.
Taxation on Interest on Shareholders’ Equity
Any payment of interest on shareholders’ equity (see “—Memorandum and Articles of Incorporation—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 additional amounts relating to interest at the SELIC rate 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.
Gains realized outside Brazil by a non-Brazilian holder on the disposition of ADSs to another non-Brazilian holder are not subject to Brazilian tax.
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
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(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 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,
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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. 2,219 of May 2, 1997, 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 Federal 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.
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.
Transactions on Bank Accounts (“CPMF”)
As a general rule, the Contribuição Provisória sobre Movimentação Financeira (Tax on Transactions on Bank Accounts, or CPMF), is imposed on any debit to bank accounts. Therefore, transactions by the depositary or by holders of preferred or common shares which involve the transfer of Brazilian currency through Brazilian financial institutions will be subject to the CPMF tax. 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 CPMF tax is imposed generally on bank account debits at the current rate of 0.38%, which will be applicable through December 31, 2003. During 2004, the CPMF tax rate will be 0.08%. The CPMF is set to expire on December 31, 2004. However, the President of Brazil has proposed a bill to the Brazilian Congress which, if approved, will convert the CPMF tax into a permanent tax. The financial institution that carries out the relevant financial transaction is responsible for collecting the applicable CPMF tax.
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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).
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
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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.
In this discussion, references to ADSs also refer to common or preferred shares, and references to a “U.S. holder” are to a holder of an ADS that:
For purposes of the U.S. Internal Revenue Code of 1986, as amended, (the “Code”) holders of ADSs will be treated as owners of the common or preferred shares represented by such ADSs.
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 in respect of the ADSs after December 31, 2002 and before January 1, 2009 is subject to taxation at a maximum rate of 15%. You should consult your own tax adviser regarding the availability of the reduced dividend tax rate in the light of your own particular circumstances.
Distributions out of earnings and profits with respect to the ADSs generally will be treated as dividend income from sources outside of the United States and generally will be treated separately along with other items of “passive” (or, in the case of certain U.S. holders, “financial services”) income for purposes of determining the credit for foreign income taxes allowed under the Code. Subject to certain limitations, Brazilian income tax withheld in connection with any distribution with respect to the 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
159
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.
Distributions of additional shares to holders with respect to their ADSs that are made as part of a pro rata distribution to all our shareholders generally will not be subject to U.S. federal income tax.
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 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.
Taxation of Capital Gains
Upon the sale or other disposition of 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 ADS and the U.S. holder’s tax basis in 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 after May 5, 2003 and before January 1, 2009 generally is subject to taxation at a maximum rate of 15%. The net long-term capital gain recognized by an individual holder before May 6, 2003 generally is subject to taxation at a maximum rate of 20%. 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 an ADS unless:
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.
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
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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.
ITEM 11. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
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 90% 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
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. 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
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to offset market exposures resulting from these imports and exports, and are not used for trading purposes. Our risk management activities follow transaction limits set by our executive officers as a group. 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. See Note 11 to our audited consolidated financial statements.
We manage risk related to interest rate changes, currency exchange rate changes and commodity price changes based on “Value at Risk” or “VAR” measures. VAR is a measure of the maximum potential change in the value of financial instruments and commodity positions and projected cash flows with a given probability over a set horizon, generally one month. The VAR approach we apply is the “Analytical Method” or “Variance/Covariance Method,” which assumes that the distribution of returns from assets and liabilities are normal. The model uses historical volatility and correlation data to predict how markets are likely to move in the future and is based on the premise that the total market risk of a financial position is a function of two factors: volatilities and correlations. To the extent that price movements of assets and liabilities are not perfectly correlated, there will be a diversification effect. The total market risk of the position will be less than the direct summation of individual components. The VAR measure can differ from actual results because financial return distribution curves reflect the possibility of extreme price movements, while normal distribution curves may not reflect the true frequency of such price fluctuations.
Commodity Price Risk
Our commodity risk management activities primarily consist of futures contracts, options and swaps. For the year ended December 31, 2002, we carried out derivative transactions on 42% of our total trade volume, as compared to 21.2% of our total trade volume for the year ended December 31, 2001 and 14.4% of our total trade volume for the year ended December 31, 2000. This increase in our derivative transactions is a result of normal fluctuations in our operations.
International hedging activities in 2002 represented an average of 379,000 barrels of oil equivalent per day of physical movements, of which 43.5% was related to fuel oil, 28.0% was related to diesel, 13.3% was related to gasoline and 7.3% was related to crude oil, as compared to our international hedging activities in 2001 which represented an average of 173,000 barrels of oil equivalent per day of physical movements, of which 36.0% was related to fuel oil, 31.0% was related to gasoline, 15.0% was related to diesel and 15.5% was related to crude oil. This increase in our international derivative transactions was a result of normal fluctuations in our operations.
Derivative transactions are generally entered into for short periods, usually not longer than six months. During 2002, our principal derivative transactions were as follows, and represented the following percentage of our total hedging operations coverage of barrels of oil equivalent for 2002:
The notional value of the contracts approximates fair value at December 31, 2002.
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
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primarily in connection with capital expenditures and investments in exploration and development projects and loans to affiliated companies. Approximately 87% 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 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 11 to our audited consolidated financial statements.
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 the years ended December 31, 2002 and 2001:
The table below provides information about our debt obligations as of December 31, 2002, 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, 2002:
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In 2000, we entered into three zero-cost foreign exchange collars, combined put and call options, which are treated as non-hedge derivative instruments relative to long-term debt denominated in foreign currencies to reduce our exposure to variations 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.
The table below provides information about our zero-cost foreign exchange collars by contract. 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 each contract.
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The inflation rate in Brazil has declined significantly in recent years. Average monthly inflation, as measured by the IGP, was 43.2% during the first half of 1994 and the monthly rate of inflation reached 46.6% in June 1994. During the second half of 1994, the average monthly rate of inflation declined to 2.7%. The average monthly rate of inflation continually declined until 1998, reaching 5.9% in 1994, 1.2% in 1995, 0.8% in 1996, 0.6% in 1997 and 0.1% in 1998. The average monthly rate of inflation rose to 1.5% in 1999, declined to 0.8% in 2000, and rose to 0.83% in 2001. During 2002, the average monthly rate of inflation increased to 2.0%. The annual inflation rate for 1998 was 1.7%, versus 7.5% in 1997, 9.3% in 1996, 14.8% in 1995 and 909.6% in 1994. However, the annual inflation rate rose to 20.0% in 1999 and was 9.8% in 2000, 10.4% in 2001, and 26.4% in 2002.
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Not Applicable.
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
None.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
ITEM 15. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. 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 and as of the date of our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures are 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.
ITEM 16. [RESERVED]
ITEM 17. FINANCIAL STATEMENTS
ITEM 18. FINANCIAL STATEMENTS
See pages F-2 through F-103, incorporated herein by reference.
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ITEM 19. EXHIBITS
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GLOSSARY OF PETROLEUM INDUSTRY TERMS
Unless the context indicates otherwise, the following terms have the meanings shown below:
168
169
ABBREVIATIONS
170
CONVERSION TABLE
171
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant, Petróleo Brasileiro S.A.—PETROBRAS, 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 18, 2003.
CERTIFICATION PURSUANT TO RULES 13a-15 and 15d-15 AS ADOPTED UNDERSECTION 302 OF THE SARBANES-OXLEY ACT
I, José Eduardo de Barros Dutra, certify that:
1. I have reviewed this annual report on Form 20-F of Petróleo Brasileiro S.A. – PETROBRAS.
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
(a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
(c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
I, José Sérgio Gabrielli de Azevedo, certify that:
INDEX TO FINANCIAL STATEMENTS
PETRÓLEO BRASILEIROS.A. - PETROBRAS and SubsidiariesConsolidated Financial Statementsat December 31, 2002 and 2001and Report of Independent Accountants
Report of Independent Accountants
To the Board of Directors and StockholdersPETRÓLEO BRASILEIRO S.A. - PETROBRAS
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of stockholders’ equity, present fairly, in all material respects, the financial position of PETRÓLEO BRASILEIRO S.A. - PETROBRAS and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period 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 audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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 audits provide a reasonable basis for our opinion.
As described in Notes 2(j) and 10, PETROBRAS has been subject to significant Brazilian Federal Government regulation and new regulations were implemented in July 1998 that significantly changed the regulation of the Brazilian oil and gas market.
PricewaterhouseCoopersAuditores IndependentesRio de Janeiro, Brazil
February 13, 2003.
COPY OF THE ORIGINAL
F-2
PETRÓLEO BRASILEIRO S.A. -PETROBRAS and Subsidiaries
Consolidated Balance Sheets(Expressed in Millions of United States Dollars
F-3
The accompanying notes are integral part of these consolidated financial statements.
F-4
Consolidated Statements of IncomeExpressed in millions of United States dollars, except number of shares and per-share amounts
F-5
The accompanying notes are an integral part of these consolidated financial statements.
F-6
F-7
F-8
The accompanying notes are an integral part of these consolidated finaical statements.
F-9
Consolidated Statements of Changes in Stockholders’ EquityExpressed in Millions of United States Dollars, Except number of shares and per-share amounts
F-10
F-11
F-12
Notes to the Consolidated Financial Statements(Expressed in millions of United States dollars,unless otherwise stated)
F-13
F-14
F-15
F-16
F-17
F-18
F-19
F-20
F-21
F-22
F-23
F-24
F-25
F-26
F-27
F-28
F-29
F-30
F-31
F-32
F-33
F-34
F-35
F-36
F-37
F-38
F-39
F-40
F-41
F-42
F-43
F-44
F-45
F-46
F-47
F-48
F-49
F-50
F-51
F-52
F-53
F-54
F-55
F-56
F-57
F-58
F-59
F-60
F-61
F-62
F-63
F-64
F-65
F-66
F-67
F-68
F-69
F-70
F-71
F-72
F-73
F-74
F-75
F-76
F-77
F-78
F-79
F-80
F-81
F-82
F-83
F-84
F-85
F-86
F-87
Capital expenditures were as follows:
F-88
F-89
F-90
F-91
PETRÓLEO BRASILEIRO S.A. -PETROBRAS and subsidiaries
Supplementary Information on Oil and GasExploration and Production Activities (Unaudited)(Expressed in Millions of United States Dollars,Unless Otherwise Stated)
F-92
F-93
PETRÓLEO BRASILEIRO S.A. -PETROBRAS and subsidiariesSupplementary Information on Oil and GasExploration and Production Activities (Unaudited)(Expressed in Millions of United States Dollars,Unless Otherwise Stated)
F-94
F-95
F-96
F-97
F-98
F-99
F-100
PETRÓLEO BRASILEIRO S.A. –PETROBRAS and subsidiaries
F-101
F-102
[Additional columns below]
[Continued from above table, first column(s) repeated]
F-103