SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2003
Commission File Number 1-15106
PETRÓLEO BRASILEIRO S.A. - PETROBRAS
(Exact name of registrant as specified in its charter)
Avenida República do Chile, 65
20035-900 - Rio de Janeiro - RJ
Brazil
(Address of principal executive offices)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class:
Name of each exchange on which registered:
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 stock
as of the close of the period covered by this Annual Report:
At December 31, 2003, there were outstanding:
634,168,418 Common Shares, without par value
462,369,507 Preferred Shares, without par value
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ¨ Item 18 x
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
CERTAIN TERMS AND CONVENTIONS
PRESENTATION OF FINANCIAL INFORMATION
ITEM 1.IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
ITEM 2.OFFER STATISTICS AND EXPECTED TIMETABLE
ITEM 3.KEY INFORMATION
ITEM 4.INFORMATION ON THE COMPANY
ITEM 5.OPERATING AND FINANCIAL REVIEW AND PROSPECTS
ITEM 6.DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
ITEM 7.MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
ITEM 8.FINANCIAL INFORMATION
ITEM 9.THE OFFER AND LISTING
ITEM 10.ADDITIONAL INFORMATION
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ITEM 11.QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 12.DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
ITEM 13.DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
ITEM 14.MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
ITEM 15.CONTROLS AND PROCEDURES
ITEM 16A.AUDIT COMMITTEE FINANCIAL EXPERT
ITEM 16B.CODE OF ETHICS
ITEM 16C.PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 17.FINANCIAL STATEMENTS
ITEM 18.FINANCIAL STATEMENTS
ITEM 19.EXHIBITS
GLOSSARY OF PETROLEUM INDUSTRY TERMS
ABBREVIATIONS
CONVERSION TABLE
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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.
Unless the context otherwise requires, the terms “Petrobras,” “we,” “us,” and “our” refer to Petróleo Brasileiro S.A.-Petrobras and its consolidated subsidiaries.
A glossary of petroleum industry terms, a table of abbreviations and a conversion table are presented beginning on page 116.
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, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, and the accompanying notes, contained in this annual report have been presented in U.S. dollars and prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP). See Item 5 “Operating and Financial Review and Prospects” and Note 2(a) to our audited consolidated financial statements. We also publish financial statements in Brazil in Reais in accordance with the accounting principles required by Brazilian Corporation Law and the regulations promulgated by the Comissão de Valores Mobiliários (Brazilian Securities Commission, or the CVM) “Brazilian GAAP,” which differs in significant respects from U.S. GAAP.
We are required by Brazilian Corporation Law to change auditors every five years and to select auditors through a bidding process. Since June 2003, Ernst & Young Auditores Independentes S/S has served as our independent auditors and audited our financial statements for the year ending December 31, 2003. PricewaterhouseCoopers Auditores Independentes audited our financial statements for each of the years ending December 31, 2002, 2001, 2000 and 1999.
Our functional currency is the Brazilian Real. As described more fully in Note 2(a) to our audited consolidated financial statements, the U.S. dollar amounts as of the dates and for the periods presented in our audited consolidated financial statements have been remeasured or translated from the Real amounts in accordance with the criteria set forth in Statement of Financial Accounting Standards No. 52 of the U.S. Financial Accounting Standards Board, or SFAS 52. U.S. dollar amounts presented in this annual report have been translated from Reais at the period-end exchange rate for balance sheet items and the average exchange rate prevailing during the period for income statement and cash flow items.
Unless the context otherwise indicates,
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.
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, 2003 have been derived from our audited consolidated financial statements, which were audited by Ernst & Young Auditores Independentes S/S for the year ended December 31, 2003 and by PricewaterhouseCoopers Auditores Independentes for each of the years ending December 31, 2002, 2001, 2000 and 1999. The information below should be read in conjunction with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and Item 5 “Operating and Financial Review and Prospects.”
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BALANCE SHEET DATA
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories
Recoverable taxes
Advances to suppliers
Other current assets
Total current assets
Property, plant and equipment, net
Investments in non-consolidated companies and other investments
Other assets:
Accounts receivables, net
Petroleum and Alcohol Account-Receivable from Federal Government
Government securities
Unrecognized pension obligation
Restricted deposits for legal proceedings and guarantees
Investments PEPSA and PELSA
Goodwill in PEPSA and PELSA
Prepaid expenses
Marketable securities
Others
Total other assets
Total assets
Liabilities and Shareholders’ equity
Current liabilities:
Trade accounts payable
Taxes payable
Short-term debt
Current portion of long-term debt
Current portion of project financings
Current portion of capital lease obligations
Dividends and interest on capital payable
Payroll and related charges
Advances from customers
Employee benefits obligations – Pension
Other current liabilities
Total current liabilities
Long-term liabilities:
Long-term debt
Project financings
Employee benefits obligation – Health Care
Capital lease obligations
Deferred income tax
Thermoelectric liabilities
Provision for abandonment of wells
Other liabilities
Total long-term liabilities
Minority interest
Shareholders’ equity
Shares authorized and issued:
Preferred stock
Common stock
Capital reserve and other comprehensive income
Total Shareholders’ equity
Total liabilities and Shareholders’ equity
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INCOME STATEMENT DATA
Sales of products and services
Value-added and other taxes on sales and services
CIDE(8)
Specific parcel price – PPE
Net operating revenues
Cost of sales(1)
Depreciation, depletion and amortization(2)
Exploration, including exploratory dry holes(2)
Selling, general and administrative expenses
Other operating expense(3)
Total costs and expenses
Financial income
Financial expense
Monetary and exchange variation on monetary assets and liabilities, net
Employee benefit expense
Other non-operating income (expense), net(4)
Income before income taxes, minority interest and accounting change
Income tax (expense) benefit:
Current
Deferred
Total income tax expense
Minority interest in results of consolidated subsidiaries
Income before effect of change in accounting principle
Cumulative effect of change in accounting principle, net of taxes(2)
Net income for the year
Weighted average number of shares outstanding:(5)
Common/ADS
Preferred/ADS
Basic and diluted earnings per share:
Common/ADS(6)
Preferred/ADS(6)
Cash dividends per share(7):
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, complete unification has not yet occurred and each market continues to be subject to specific regulation. 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. Since 1999, the Central Bank of Brazil has allowed the Real to float freely.
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The Real depreciated 18.7% in 2001 and 52.3% in 2002 against the U.S. dollar, before appreciating 18.2% in 2003. As of June 15, 2004, the Real has depreciated to R$3.138 per U.S.$1.00, representing a depreciation of approximately 6.7% in 2004 year-to-date. The Real may depreciate or appreciate substantially in the future. See “-Risk Factors-Risks Relating to Brazil.”
The following table sets forth the commercial selling rate for U.S. dollars for the periods and dates indicated. The average exchange rates represent the average of the month-end exchange rates (R$/U.S.$) during the relevant period.
COMMERCIAL SELLING RATE FOR U.S. DOLLARS
2003
2002
2001
2000
1999
December
2004
January
February
March
April
May
June (through June 15)
Source: Central Bank of Brazil
Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or serious reasons to foresee such an imbalance, temporary restrictions on remittances from Brazil may be imposed by the Brazilian government. These types of measures may be taken by the Brazilian government in the future, including measures relating to remittances related to our preferred or common shares or ADSs. See “Risk Factors-Risks Relating to Brazil.”
Risk Factors
Risks Relating to Our Operations
Substantial or extended declines in the prices of crude oil and oil products may have a material adverse effect on us.
We do not, and will not, have control over the factors affecting international prices for crude oil and oil products. The average prices of Brent crude, an international benchmark oil, were approximately U.S.$28.84 per barrel for 2003, U.S.$25.02 per barrel for 2002 and U.S.$24.44 per barrel for 2001.
Changes in crude oil prices typically result in changes in 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. However, even during periods of high crude oil prices, depending on the behavior of demand, it may not be possible to pass through higher prices to consumers.
Historically, international prices for crude oil and oil products have fluctuated widely as a result of many factors. These factors include:
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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. As of January 2, 2002, the crude oil and oil products markets in Brazil were deregulated in their entirety.
We expect continued volatility and uncertainty in international prices for crude oil and oil products. Substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition and the value of our proved reserves.
Because of changes in government regulations, we face increased competition and may lose market share.
The Brazilian government eliminated all price controls on crude oil and oil products in early 2002. Prices remain regulated, however, for natural gas and electricity. These controls could have an adverse effect on revenues from these business activities.
The changes in government regulation have enabled multinational and regional oil companies to enter the Brazilian energy market. Competition in our upstream and downstream activities has increased and will increase further, as existing and new participants expand their activities as a result of these regulatory changes.
Although our prices for 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 oil products were below prevailing international prices, our competitors were unwilling to supply the local market. In order to ensure adequate supply of oil products in Brazil, we sold 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 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 our growth objectives depends on our ability to gain access to additional reserves.
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.
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Exploratory drilling involves numerous risks, including the risk that we will not discover commercially productive oil or natural gas reserves.
Our exploration and development activities expose us to the inherent risks of drilling, including the risk that we will not discover commercially productive crude oil or natural gas reserves. The costs of drilling, completing and operating wells are often uncertain and numerous factors beyond our control (such as unexpected drilling conditions, equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment) may cause drilling operations to be curtailed, delayed or cancelled. 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. Although 91% of our domestic reserves are independently certified, there are uncertainties in estimating quantities of proved reserves related to prevailing crude oil and natural gas prices applicable to our production, which may lead us to make revisions to our reserve estimates.
Our equipment, facilities and operations are subject to numerous environmental and health regulations which have become more stringent in the recent past and may result in increased liabilities and increased capital expenditures.
Our activities are subject to a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment, both in Brazil and in other jurisdictions in which we operate. In Brazil, we could be exposed to 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. Waste disposal and emissions regulations may require us to clean up or retrofit our facilities at substantial cost and could result in substantial liabilities. The Instituto Brasileiro do Meio Ambiente dos Recursos Naturais Renováveis(Brazilian Institute of the Environment and Renewable Natural Resources, or IBAMA) routinely inspects our oil platforms in the Campos Basin, and may impose fines, restrictions on operations or other sanctions in connection with its inspections.
We spent approximately U.S.$750 million in 2003, U.S.$466 million in 2002 and U.S.$473 million in 2001 to comply with environmental laws and to implement improvements in our environmental practices. Because environmental regulations have become more stringent in Brazil and in other jurisdictions where we operate, it is probable that our capital expenditures for compliance with environmental regulations and to effect improvements in our health, safety and environmental practices will increase substantially in the future. 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 regulation could result in reductions in other strategic investments that we have planned, and any such reduction may have a material adverse effect on 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. In 2003, we experienced spills totaling 73,000 gallons of crude oil, as compared to 52,000 gallons in 2002 and 691,000 gallons in 2001. As a result of certain of our spills, we were fined by various state and federal environmental agencies, named the defendant in several civil and criminal suits and remain subject to several investigations and potential civil and criminal liabilities. 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. These claims involve substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us. Our audited financial statements as of December 31, 2003 include reserves totaling U.S.$260 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 an additional provision of U.S.$95 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
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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.
If a State of Rio de Janeiro law imposing ICMS on oil upstream activities is applied to us, our results of operations and financial condition may be adversely affected.
In June 2003, the State of Rio de Janeiro enacted a law imposing the Imposto sobre Circulação de Mercadorias e Serviços (state sales tax, or ICMS) on upstream activities. Although the law is technically in force, the government of the State of Rio de Janeiro has yet to apply it. Currently, the ICMS is assessed at the point of sale from refineries to distributors but not at the wellhead level. 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 State of Rio de Janeiro applies the law to us, it would change the point of collection of a portion of the ICMS from the refinery level to the wellhead level of production in the State of Rio de Janeiro. As a result, we would 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 have paid taxes on the same oil products at both production and refining levels. The attorney general has filed a lawsuit with the Brazilian Supreme Court challenging the constitutionality of the ICMS legislation. If the law is declared constitutional and the State of Rio de Janeiro applies the law to us, the amount of ICMS that we would be required to pay to the State of Rio de Janeiro could increase by approximately R$5.4 billion (U.S.$1.9 billion) per year. This increase could have a material adverse effect on our results of operations and financial condition.
A final judicial ruling upholding the view of the Brazilian Revenue Service of Rio de Janeiro that drilling and production platforms may no longer be classified as sea-going vessels will increase the amount of taxes we pay, and such an increase may have a material adverse effect on our results of operations and financial condition.
The Rio de Janeiro branch of the Brazilian Revenue Service (Secretaria de Receita Federal) has asserted that, under Brazilian law, drilling and production platforms may not be classified as sea-going vessels and therefore should not be chartered but leased. Based on this interpretation of Brazilian law, overseas remittances for charter payments would be reclassified as lease payments, and would be subject to withholding tax at the rate of 15%.
The Brazilian Revenue Service has filed two tax assessments against us in connection with the withholding tax (IRRF) on foreign remittances of payments related to the charter of vessels of movable platform types. On February 17, 2003, the Brazilian Revenue Service served us with a tax assessment notice for R$93 million (U.S.$32 million) covering disputed taxes for 1998. On June 27, 2003, the Brazilian Revenue Service served us with a tax assessment notice for R$3,064 million (U.S.$1,066 million) covering disputed taxes for the period from 1999 to 2002. We recently received two unfavorable rulings from the Brazilian Revenue Service with respect to these tax assessments, and have appealed these rulings to a higher administrative court.
We believe that Brazilian law supports our view that drilling and production platforms may be classified as sea-going vessels. However, in the event that a final judicial ruling supports the Brazilian Revenue Service’s position, the taxes we pay in connection with our drilling and production platforms would significantly increase, and such an increase could have a material adverse effect on our level of investments and, therefore, on our results of operations 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 November 4, 2003, and is retroactive to September 1, 2003. This collective bargaining agreement will expire on August 31, 2004. We negotiated a separate collective bargaining agreement with the maritime employees’ union. The agreement was signed on January 30, 2004, is retroactive to November 1, 2003 and will expire on October 31, 2004.
From time to time, we have been subject to strikes and work stoppages. In 2001, our oil workers began a five-day strike, which led to a decrease in crude oil production of four million barrels of oil equivalent per day. 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 participation in the domestic power market has generated losses, and the Brazilian regulatory environment for the energy sector remains uncertain.
Consistent with the global trend of other major oil and gas companies and to secure demand for our natural gas, we participate in the domestic power market. Despite a number of incentives introduced by the former Brazilian government to promote the development of thermoelectric power plants, development of such plants by private investors has been slow to progress. We have
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invested in 11 (5 in operation and 6 under construction or development) of the 39 gas-fired power generation plants being built or proposed to be built in Brazil under the program to promote the development of thermoelectric plants, known as the Programa Prioritário de Termoeletricidade (Thermoelectric Priority Program, or PPT). 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.
In 2002, the Brazilian Congress passed a law increasing government intervention in the domestic power market, and in 2003 the current administration proposed a new regulatory model for the energy sector. The New Industry Model Law was enacted on March 16, 2004, but because the new law remains subject to the enactment of decrees of the Brazilian government and implementing resolutions of the National Electric Energy Agency (ANEEL), many aspects of the regulatory environment for thermoelectric power remain uncertain, and it is not clear that thermoelectric power will remain a priority for the country.
We have limited our investments in the domestic power market, but our participation in this market may never become profitable and may continue to adversely affect our operating results and financial condition.
We may not be able to obtain financing for all of our planned investments.
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 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 83% 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 2003, we imported U.S.$5.7 billion of crude oil and oil products, the prices of which were all denominated in U.S. dollars.
The Real depreciated 18.7% in 2001 and 52.3% in 2002 against the U.S. dollar, before appreciating 18.2% in 2003 against the U.S. dollar. As of June 15, 2004, the exchange rate of the Real to the U.S. dollar was R$3.138 per U.S.$1.00, representing a depreciation of approximately 6.7% in 2004 year-to-date. The value of the Real in relation to the U.S. dollar may continue to fluctuate and may include a significant depreciation of the Real against the U.S. dollar as occurred in 2002. Any future substantial devaluation of the Real may adversely affect our operating cash flows and our ability to meet our foreign currency-denominated obligations. You should consider this risk in light of past devaluations of the Real caused by inflationary and other pressures.
We are exposed to increases in prevailing market interest rates.
As of December 31, 2003, approximately 57% 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 formal declaration of the end of hostilities 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 full re-entry into such markets could have a material adverse effect on our financial condition and results of operations.
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We are not insured against business interruption for our Brazilian operations and most of our assets are not insured against war and terrorism.
We do not maintain coverage for business interruption for our Brazilian operations and do not insure most of our assets against war and terrorism. A terrorist attack or an operational incident could therefore have a material adverse effect on our financial condition or results of operations.
We are subject to substantial risks relating to our operations in Argentina and other South American countries.
We operate in Argentina through our subsidiary, Petrobras Energia Participaciones S.A. (PEPSA). Approximately 5.9% of our total crude oil and natural gas production and 3.5% of our proved crude oil and natural gas reserves were located in Argentina at December 31, 2003. As a result, PEPSA’s results of operations and financial condition, and consequently, our results of operations and financial condition, may be adversely affected by fluctuations in the Argentine economy, Argentine political instability, and governmental actions concerning the economy, including:
We are also active in Venezuela, Ecuador, Colombia, Bolivia and Peru. Our operations in Venezuela and Bolivia are our most significant international operations outside of Argentina. Our operations in Venezula represented 2.1% of our total production in barrels of oil equivalent in 2003 and 2.6% of our proved crude oil and natural gas reserves at December 31, 2003. Our operations in Bolivia represented 1.5% of our total production in barrels of oil equivalent in 2003 and 2.9% of our proved crude oil and natural gas reserves at December 31, 2003. Accordingly, our operations may be negatively affected by:
If one or more of the risks described above were to materialize, we may not achieve our strategic objectives in South America, resulting in a material adverse effect on our results of operations and financial condition.
The current Argentine economic, political, energy and social crisis could adversely affect our Argentine operations.
From the last quarter of 1998 until 2003, the Argentine economy was in a recession marked by reduced levels of consumption and investment, increased unemployment, declining gross domestic product, capital flight and a suspension of payments on its approximately U.S.$95 billion of sovereign debt owed to private creditors. Argentina’s GDP contracted by 4.4% in 2001 and 10.9% in 2002.
On December 1, 2001, the Argentine government led by President Fernando de la Rúa effectively froze bank deposits and introduced exchange controls restricting capital outflows. The measures were perceived as further paralyzing the economy for the
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benefit of the banking sector and caused a sharp rise in social discontent, ultimately triggering public protests, outbreaks of violence and the looting of stores throughout Argentina. 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 undertook a number of far-reaching initiatives, including:
On May 25, 2003, a new president, Néstor Kirchner, took office. His current term will expire on December 10, 2007. There remains 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 ongoing renegotiation of the country’s public debt.
During 2003, some economic indicators of the Argentine economy began to stabilize. In 2003, GDP grew by approximately 8.7%, inflation remained below 4%, consumption and investment increased and the peso appreciated significantly against the U.S. dollar. Nevertheless, this return to growth and partial stabilization are recent developments and may not be sustainable. These developments must be viewed against the significant declines preceding 2003 and against the substantial continuing uncertainties in Argentina’s economic and legal environment, including the renegotiation of the country’s external public debt and public utility contracts, restructuring of the financial system and redesigning of the federal fiscal regime. We cannot be certain that the economy will not suffer additional shocks.
Over the last few years, Argentina has also been afflicted by an energy crisis. In May 2002, the Argentine government declared a state of emergency in the supply of hydrocarbons in Argentina. Subsequently, in March 2004, Argentina’s Secretary of Energy issued a resolution pursuant to which limits on natural gas exports may be imposed and, in fact, some limits have already been imposed. Further Argentine political instability, volatility in Argentina’s energy industry, fluctuations in the Argentine economy and governmental actions concerning the economy could adversely affect our operations in Argentina and may have a material adverse impact on our results of operations and financial condition.
Risks Relating to the Relationship between us and the Brazilian Government
The Brazilian government, as our controlling shareholder, may cause us to pursue certain macroeconomic and social objectives that may have an adverse effect on our results of operations and financial condition.
The Brazilian government, as our controlling shareholder, has pursued, and may pursue in the future, certain of its macroeconomic and social objectives through us. Brazilian law requires the Brazilian government to own a majority of our voting stock, and so long as it does, the Brazilian government will have the power to elect a majority of the members of our board of directors and, through them, a majority of the executive officers who are responsible for our day-to-day management. As a result, we may engage in activities that give preference to the objectives of the Brazilian government rather than to our own economic and business objectives. In particular, we continue to assist the Brazilian government to ensure that the supply of crude oil and oil products in Brazil meets Brazilian consumption requirements. Accordingly, we may continue to make investments, incur costs and engage in sales on terms that may have an adverse effect on our results of operations and financial condition.
If the Brazilian government reinstates controls over the prices we can charge for crude oil and oil products, such price controls could affect our financial condition and results of operations.
In the past, the Brazilian government set prices for crude oil and oil products in Brazil, often below prevailing prices on the world oil markets. These prices involved elements of cross-subsidy among different oil products sold in various regions in Brazil. The cumulative impact of this price regulation system on us is recorded as an asset on our balance sheet under the line item “Petroleum and Alcohol Account-Receivable from the Brazilian government.” The balance of the account at December 31, 2003
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was U.S.$239 million. Effective January 2, 2002, all price controls for crude oil and oil products ended, and while no price controls were imposed on crude oil and oil products in 2002 or 2003, 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.
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 based on fluctuations in exchange rates and international market prices for relevant benchmark products.
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.
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 in other countries. Under Brazilian law, the Brazilian government owns all crude oil and natural gas reserves in Brazil. We possess the exclusive right to develop our reserves pursuant to concession agreements awarded to us by the Brazilian government, but if the Brazilian government were to restrict or prevent us from exploiting these crude oil and natural gas reserves, our ability to generate income would be adversely affected.
Risks Relating to Brazil
The Brazilian government has historically exercised, and continues to exercise, significant influence over the Brazilian economy. Brazilian political and economic conditions have a direct impact on our business and may have a material adverse effect on 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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Inflation and government measures to curb inflation may contribute significantly to economic uncertainty in Brazil and to heightened volatility in the Brazilian securities markets and, consequently, may adversely affect the market value of our securities, financial condition and results of operations.
Our principal market is Brazil, which has, in the past, periodically experienced extremely high rates of inflation. Inflation, along with recent governmental measures to combat inflation and public speculation about possible future measures, has had significant negative effects on the Brazilian economy. The annual rates of inflation, as measured by the National Consumer Price Index (Índice Nacional de Preços ao Consumidor), have decreased from 2,489.1% in 1993 to 929.3% in 1994, 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, before decreasing to 10.4% in 2003.
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.
Fluctuations in the value of the Real against the U.S. dollar may result in uncertainty in the Brazilian economy and the Brazilian securities market and could negatively impact our business and lower the value of our securities.
Over the last three fiscal years, approximately 83% 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, 2003, we imported approximately U.S.$5.7 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. Throughout 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 18.7% in 2001 and by 52.3% in 2002, before appreciating 18.2% against the U.S. dollar in 2003.
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. Policies pursued by the Brazilian government, and investors’ reactions to actual or potential governmental policies, may contribute to economic uncertainty in Brazil and adversely affect our financial condition and results of operations.
Access to international capital markets for Brazilian companies is influenced by the perception of risk in Brazil and other emerging economies, which may hurt our ability to finance our operations.
International investors generally consider Brazil to be an emerging market. As a result, economic and market conditions in other emerging market countries, especially those in Latin America, influence the market for securities issued by Brazilian companies. As a result of economic problems in various emerging market countries in recent years (such as the Asian financial crisis of 1997, the Russian financial crisis in 1998 and the Argentine financial crisis which began in 2001 and is continuing), investors have viewed investments in emerging markets with heightened caution. These crises produced a significant outflow of U.S. dollars from Brazil, causing Brazilian companies to face higher costs for raising funds, both domestically and abroad, and impeding access to international capital markets. We cannot assure you that international capital markets will remain open to Brazilian companies or that prevailing interest rates in these markets will be advantageous to us. In addition, future financial crises in emerging market countries may have a negative impact on the Brazilian markets, which could adversely affect our share price.
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Risks Relating to our Equity and Debt Securities
The Brazilian securities markets are smaller, more volatile and less liquid than the major U.S. and European securities markets and therefore you may not be able 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.”
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 currently 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 forfeiting Brazilian tax advantages.
The Brazilian custodian for our common or preferred shares underlying our ADSs must obtain a certificate of registration from the Central Bank of Brazil to be entitled to remit U.S. dollars abroad for payments of dividends and other distributions relating to our preferred and common shares or upon the disposition of the common or preferred shares. If you decide to exchange your ADSs for the underlying common or preferred shares, you will be entitled to continue to rely, for five Brazilian business days from the date of exchange, on the custodian’s certificate of registration. After that period, you may not be able to obtain and remit U.S. dollars abroad upon the disposition of the common or preferred shares, or distributions relating to the common or preferred shares, unless you obtain your own certificate of registration or register under Resolution No. 2,689, of January 26, 2000, of the Conselho Monetário Nacional (National Monetary Council), which entitles registered foreign investors to buy and sell on the São Paulo Stock Exchange. If you do not obtain a certificate of registration or register under Resolution No. 2,689, you may be subject to less favorable tax treatment on gains with respect to the common or preferred shares.
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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 Corporation Law, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States, such as the States of Delaware or New York, or in other jurisdictions outside Brazil. In addition, your rights as an ADS holder or the rights of holders of the common or preferred shares under Brazilian Corporation Law to protect their interests against 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 represents our preferred shares. Under Brazilian law and our bylaws, holders of preferred shares generally do not have the right to vote in meetings of our stockholders. This means, among other things, that holders of ADSs representing preferred shares are not entitled to vote on important corporate transactions or decisions. See Item 10 “Additional Information-Memorandum and Articles of Incorporation-Voting Rights” for a discussion of the limited voting rights of our preferred shares.
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 relatively recent political and economic crisis in Argentina, 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
We are a mixed-capital company created pursuant to Law No. 2,004 (effective as of October 3, 1953). A mixed-capital company is a Brazilian corporation created by special law of which a majority of the voting capital must be owned by the Brazilian federal government, a state or a municipality. We are controlled by the Brazilian federal government, but our common and preferred shares are also publicly traded. Our principal executive office is 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 natural gas production and refining activities in Brazil. On November 9, 1995, the Brazilian Constitution was amended to authorize the Brazilian government to contract with any state or privately owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. This amendment eliminated our legal monopoly.
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The crude oil and natural gas industry in Brazil has experienced significant reforms since the enactment of Law No. 9,478, or the Oil Law, on August 6, 1997, which established competition in Brazilian markets for crude oil, oil products and natural gas in order to benefit end-users. Effective January 2, 2002, the Brazilian government deregulated prices for crude oil and oil products. See “-Regulation of the Oil and Gas Industry in Brazil-Price Regulation.” The gradual transformation of the oil and gas industry since 1997 has led to increased participation by international companies in Brazil across all segments of our business, both as our competitors and partners.
Based upon our 2003 consolidated revenues, we are the largest corporation in Brazil and one of the largest oil and gas companies in Latin America. In 2003, we had sales of products and services of U.S.$42,690 million, net operating revenues of U.S.$30,797 million and net income of U.S.$6,559 million.
We engage in a broad range of oil and gas activities, which cover the following segments of our operations:
Our Competitive Strengths
We have a number of key strengths, including:
Our dominant market position in the production, refining and transportation of crude oil and oil products in Brazil
Our legacy as Brazil’s former sole supplier of crude oil and oil products has provided us with a fully developed operational infrastructure throughout Brazil and a large proved reserve base. Our long history, resources and established presence in Brazil permit us to compete effectively with other market participants and new entrants now that the Brazilian oil and gas industry has been deregulated. We operate all major development fields in Brazil and operate approximately 98.6% of the country’s refining capacity. Our average domestic daily production of crude oil and NGLs increased 2.7% in 2003, 12.3% in 2002 and 10.2% in 2001.
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Our reserve base and comparatively long reserve life
As of December 31, 2003, we had estimated proved developed and undeveloped reserves of approximately 11.6 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, 2003, 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 9,842 feet (3,000 meters).
Our deepwater development and production expertise has allowed us to achieve high production volumes and relatively low lifting costs (excluding royalties, special government participation and rental of areas, which we refer to as “government take”). Our aggregate average lifting cost for crude oil and natural gas products in Brazil for 2003, excluding government take, increased to U.S.$3.48 per barrel of oil equivalent, as compared to U.S.$3.04 per barrel of oil equivalent for 2002. Including government take, our lifting costs increased to U.S.$8.62 per barrel of oil equivalent for 2003, as compared to U.S.$7.04 per barrel of oil equivalent for 2002.
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 energy company. In line with our Strategic Plan and to further these goals, we intend to:
Expand production while increasing reserves
We seek to generate production growth from the continued development of our proved undeveloped reserve base of 6.04 billion barrels of oil equivalent at December 31, 2003, which represents approximately 58.1% of our total proved reserves. Our 2004-2010 budget contemplates capital expenditures of approximately U.S.$53.6 billion in development activities for this seven-year period, including U.S.$5.9 billion to be financed through project financings. The majority of these capital expenditures, U.S.$32.1 billion, will be directed towards exploration and production activities, of which U.S.$26.2 billion will be directed towards domestic exploration and production activities. We intend to increase our effort in production to produce lighter crude oil from our newly discovered reserves.
At the same time that we seek to expand production, we intend to increase our proved reserves principally through an exploration program focused on deepwater exploration in Brazil. We have net exploration, development and production rights in 21 million acres (85,082 square kilometers) in Brazil. We expect to continue to participate selectively with major regional and international oil and gas companies in bidding for new concessions and in developing our large offshore fields.
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We also intend to pursue international exploration and production opportunities with industry participants primarily in South America, the Gulf of Mexico and the west coast of Africa. As a result of this strategy, we participate in joint ventures, which have resulted in discoveries in Agbami and Akpo (off the coast of Nigeria) and in a deepwater field in the Gulf of Mexico (Cascade Project). We are also exploring opportunities in new areas for our international activities, such as in the Middle East. In 2003, we participated in a tender for exploration blocks in Iran. At December 2003, we had exploration, development and production rights in 19.2 million gross and 9.7 million net acres (78,000 gross and 39,000 net square kilometers) outside Brazil.
Upgrade our refineries to increase their ability to process heavier domestic crude production while at the same time fulfilling a growing percentage of the current demands of the Brazilian market
Our refineries were originally constructed to process light imported crude oil, whereas our current reserves and production increasingly consist of heavier crude oil. We plan to improve and adapt our refineries to better process our domestic production of heavier crude oil by continuing to:
Expand international operations through internal growth and by participating selectively in new partnerships in core areas where we have competitive advantages.
In the near term, we expect to expand internationally by using our existing asset base or participating in selective partnerships in core activities where we have a competitive advantage. We consider our core activities to be integrated oil and gas operations throughout South America and deepwater exploration and development off the U.S. Gulf Coast and West Africa. During 2003 we acquired interests in exploration blocks in Argentina, Bolivia, Colombia and the Gulf of Mexico.
Develop and improve systematic, company-wide initiatives to address health, safety and environmental concerns and ensure compliance with environmental regulations
The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated oil, gas and energy company. In order to address and prioritize health, safety and environmental concerns and ensure compliance with environmental regulations, we have taken several measures, of which the most extensive is the Programa de Excelência em Gestão Ambiental e Segurança Operacional (Program for Excellence in Environmental and Operational Safety Management, or PEGASO). Through the program, we seek to improve technology, upgrade our pipelines, reduce emissions and wastes, improve our emergency response readiness and prevent environmental accidents. Another important initiative is the Programa de Segurança de Processo (Process Safety Program) that aims to strengthen our corporate commitment to safety through the implementation of standardized, company-wide health, safety and environmental guidelines. See “Health, Safety and Environmental Matters.”
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.
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Operate successfully and transparently in a deregulated market
Since the beginning of market liberalization in 1997 and price deregulation in 2002, 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 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:
As a foreign private issuer, we are exempt from many of the corporate governance standards the New York Stock Exchange (the “NYSE”) applies to U.S. domestic issuers listed on the NYSE. In accordance with Section 303A.11 of the NYSE Listed Company Manual, we have posted a summary of significant differences between the NYSE standards and our corporate governance practice on our website, www.petrobras.com.br.
Meet targeted operating costs and return on capital, while being socially and environmentally responsible and contributing to the development of Brazil and other countries where we operate.
We are undertaking a number of initiatives to control our operating costs. We are targeting a reduction in the aggregate average lifting costs in Brazil for crude oil and natural gas in order to achieve lifting costs of U.S.$3.00 per barrel of oil equivalent in 2010 (excluding government take) as compared to U.S.$3.48 per barrel of oil equivalent in 2003. We will seek to reduce our operating costs per barrel by a number of means, including:
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Overview by Business Segment
Exploration, Development and Production
Summary and Strategy
Our exploration and production segment includes exploration, development and production activities in Brazil. We began domestic production in 1954 and international production in 1972. As of December 31, 2003, our estimated net proved crude oil and natural gas reserves in Brazil were approximately 10.4 billion barrels of oil equivalent. Crude oil represented 87% and natural gas represented 13% of these reserves. Our proved reserves are located principally in the Campos Basin.
During 2003, our average daily domestic production was 1.5 million barrels per day of crude oil and NGLs and 1.5 billion cubic feet of natural gas per day. Our aggregate average lifting costs for crude oil and natural gas in 2003 were U.S.$3.48 per barrel of oil equivalent in Brazil (excluding government take).
We conduct our exploration, development and production activities in Brazil through concession contracts. Under the terms of the Oil Law, in 1998 we were granted the concession rights to areas where we were already producing or could demonstrate we could explore or develop within a certain time frame (“Round O”). In a number of our concessions, we have agreed with foreign partners to jointly explore and develop the concessions. In conjunction with the majority of these arrangements, we received a carried interest for capital expenditures made during the exploration phase, with our partners incurring all capital expenditures until the development of a commercial discovery commences.
At December 31, 2003, we held 326 areas, representing 21 million acres (85,082 square kilometers). We currently have joint venture agreements for exploration and production in Brazil with approximately 26 foreign and domestic companies. We are also active in exploration and production activities outside Brazil. For a full description of our international activities, see “-International-Exploration and Production.” In addition, we have added to our 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:
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Principal Domestic Oil and Gas Producing Regions
Our annual daily production in Brazil has grown over the years. 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 1,540 Mbpd in 2003.
Campos Basin
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 this area 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 oil production volume in the region has steadily increased for the past ten years and reached 1,252 Mbpd in 2003, which accounted for approximately 81.3% of Brazilian oil production.
At December 31, 2003, we produced crude oil from 33 fields in the Campos Basin and our proved crude oil reserves were 8.09 billion barrels, representing 89.4% of our total proved crude oil reserves. In 2003, the crude oil we produced in the Campos Basin had an average API gravity of 23.5° and an average water cut of 1.6%. We currently have 24 floating production systems, 13 fixed platforms and 4,225 kilometers of pipeline operating in 33 fields at water depths of 262 to 6,188 feet (80 - 1,886 meters) in the Campos Basin.
Santos Basin
The Santos Basin represents one of our most active and promising exploration areas. We currently have exploration rights to 15 blocks in the Santos Basin, with a combined acreage of 34.3 thousand square kilometers (as compared to 9 thousand square kilometers under concession in the Campos Basin). Current production of oil and natural gas is 8.2 Mboe per day in the Coral and Merluza fields. In 2003, we discovered significant quantities of natural gas and light crude oil in this region.
Espírito Santo Basin
In partnership with Shell and Chevron Texaco, we have made several discoveries of heavy crude oil in the Espírito Santo Basin. During 2003, we produced 52.2 Mboe per day of oil and natural gas in the Espírito Santo Basin (33.0 Mboe onshore and 19.2 Mboe offshore). In 2003, we discovered crude oil with an API gravity of 40° to 41° in Block BES-100.
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 2003, we produced 104.6 Mboe per day of oil and natural gas in the Solimões Basin.
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Properties
The following table sets forth our developed and undeveloped acreage by oil region and associated crude oil and natural gas production:
Production
Acreage as of
December 31, 2003
Average Oil andNatural GasProduction for
the Year
Ended December 31,2003(1)(3)
Ended December 31,2002(1)(3)
Brazil(1)
Offshore
Other offshore
Total offshore
Onshore
Total Brazil
International
Total
Deepwater Expertise
We are a leader in deepwater drilling, with recognized expertise in deepwater exploration, development and production. We have developed our expertise over many years and have achieved significant milestones, including the following:
Because many of Brazil’s richest oil fields are located offshore in deep waters, we intend to continue to focus on our deepwater production technology to increase our proved reserves and future domestic production. See Item 5 “Operating and Financial Review and Prospects-Research and Development.” Our main exploration and development efforts involve offshore fields neighboring our existing fields and production infrastructure, where higher drilling costs have been offset by higher drilling success ratios and relatively higher production. On a per-well basis, the exploration, development and production costs of an offshore well are generally higher than those costs for an onshore well. We believe, however, that offshore production is cost-effective, because historically:
We currently extract hydrocarbons from offshore wells in waters with depths of up to 6,188 feet (1,886 meters), and we have been developing technology to permit production from wells at water depths of up to 9,843 feet (3,000 meters). Set forth below is the distribution, by water depth, of offshore oil production in 2003 and 2002.
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OFFSHORE PRODUCTION BY WATER DEPTH
Depth
0-400 meters (0-1,312 feet)
400-1,000 meters (1,312 feet-3,281 feet)
More than 1,000 meters (3,281 feet)
Exploration Activities
Our Concessions in Brazil
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).
At December 31, 2003, we had 326 areas, consisting of 235 production areas, 54 exploration areas and 37 development areas, for a total area aggregating 21 million net acres (85 thousand square kilometers). This total area represents 1.4% 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.
The following chart summarizes our success in the exploration bidding rounds conducted by the ANP, as described above:
Event
Areas requested (October 13, 1997)
Concessions granted (August 6, 1998), Round 0
Areas redefined
Areas held (December 31, 1998)
Areas relinquished (May 11, 1999)
Areas won on Bid, Round 1
New concessions (July 1, 1999)
Areas held (December 31, 1999)
Areas relinquished on January 26, 2000
Areas won on Bid, Round 2
Areas held (December 31, 2000)
New concession (March 21, 2001) (Angico)
Areas sold (May 10 and May 11, 2001)
Areas won on Bid, Round 3
New concession (August 1, 2001) (Curió)
New concession (August 2, 2001) (Beija-Flor)
Areas relinquished (August 6, 2001)
Areas relinquished (October 5, 2001) (BC-8)
New concession (August 1,2001) (Cardeal)
Areas relinquished (November 5, 2001)
Areas redefined (August 6, 2001) (Pojuca Norte)
Areas held (December 31, 2001)
Areas relinquished (May 2002) (BA-1)
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Areas won on Bid, Round 4
Areas relinquished (August 6, 2002) (BM-CAL-1 and BM-C-6)
Areas relinquished (August 2002) (BS-2)
Areas relinquished (September 2002) (BES-2)
New concession (February 6,2002) (Siri)
New concession (August 27, 2002) (Asa Branca)
New concession (November 22, 2002) (Manati)
New concession (December 11,2002) (Jubarte)
New concession (December 27,2002) (Cachalote)
Areas relinquished (March 13, April 24, 2002)
Areas redefined (April 26, May 10, August 6, August 10, October 9 and December 12, 2002)
Areas relinquished (Caraúna - PETROBRAS not operator)
Areas held (December 31,2002)
Areas redefined (July 2003) (BCAM-40)
Areas relinquished (August 6, 2003)
Areas won on Bid, Round 5
New concession (January 29, 2003) (Guajá)
New concession (August 4, 2003) (Cavalo-Marinho)
Areas redefined (February 3, 2003) (Coral)
Areas redefined (July 15, 2003) (Beija-Flor)
Joint concession COG to CCN (1)
Joint concession CDL to MP (2)
Areas relinquished (BAS-104)
Areas relinquished (Arraia)
Total areas held (as of December 31, 2003)
Net land area held in million acres (as of December 31, 2003)
Joint Ventures
As of December 31, 2003, we had 47 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 30 of the 47 agreements, we are principally responsible for conducting the exploration and development activities. During 2003, we entered into 3 partnership projects relating to exploration activities. As of December 31, 2003, we had partnerships with 26 foreign and domestic companies.
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.
Drilling Activities
During 2003, we drilled a total of 305 development wells and 79 exploratory wells. Of those wells, 40 development wells and 37 exploratory wells were located in our principal Campos Basin fields. Of those development wells, 20% were drilled in the Marlim Sul field, with the remainder concentrated in the Roncador (12.5%), Barracuda (12.5%), Marlim (10%), Albacora Leste (10%), Caratinga Bicudo (10%), Pampo (5%), Albacora (2.5%), Linguado (2.5%) and Voador (2.5%) fields. An additional 54 of the 364 new development wells we plan to drill during 2004 will be drilled in the Albacora Leste, Roncador, Marlim Sul, Pampo, Marlim and Marlim Leste fields.
We plan to expand our exploration and development activities in 2004 by:
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The following table sets forth the number of wells we drilled, or in which we participated, and the results achieved, for the periods indicated:
EXPLORATORY AND DEVELOPMENT WELLS
Period
The following table sets forth our total fleet of drilling rig units. We will use these owned and leased rigs to support our future exploration, production and development activities. Most of the offshore rigs are operated in the Campos Basin.
DRILLING UNITS
Land rigs for onshore exploration and development
Owned
Leased
Semi-submersible rigs
Drill ships
Jack-up rigs
Moduled rigs for offshore exploration and development
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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 five years, we have concentrated our development investments in the deepwater fields located in the Campos Basin, where most of our proved reserves are located. We develop our fields in stages of production, which we refer to as modules.
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 2003 was 532.1 Mbpd, or more than 42% of total production in the Campos Basin. We have developed the Marlim field in five modules. We currently have seven floating production systems with a total capacity of 690 Mbpd operating in the Marlim field. We have a total of 82 production wells and 46 injection wells, and expect to drill another 4 wells in 2004. 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 unit (FPSO Brazil) with a capacity of 90 Mbpd. First oil from this unit was attained on December 8, 2002. A total of eight wells, which were previously attached to P-36, are currently being attached to the new FPSO unit. A second platform (P-52) with a 180 Mbpd capacity is under construction. First oil from the unit is expected in 2007. A total of 20 production wells are planned in this first module, including the eight which were completed before the sinking of P-36.
The contracts for a third production unit, with production capacity of 190 Mbpd, were signed on June 17, 2004. The production unit consists of an FPSO (P-54). A total of ten production wells and six injection wells are planned.
Marlim Sul (South Marlim). The Marlim Sul field is located at water depths between 2,789 and 7,874 feet (850 - 2,400 meters). Production of crude oil began on December 17, 2001. In 2003, the average production for Marlim Sul was 170 Mbpd. We plan to develop the Marlim Sul field in two modules. The first module includes a production system consisting of a semi-submersible platform (P-40) and an FPSO unit and has a total capacity of 255 Mbpd. Nine wells are currently producing through P-40, out of a total of 16 planned production wells and ten injection wells. Production from the Marlim Sul FPSO unit began on June 7, 2004 and is currently producing 33,000 boe per day.
The contracts for a second module, with a production capacity of 180 Mbpd, were signed on June 17, 2004. The production system consists of a semi-submersible unit (P-51), which is currently under contracting phase. 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 through two FPSO units (P-43, which was constructed in Singapore and moved to Brazil for completion and which will be installed in the Barracuda field and P-48, which is being constructed in Brazil and which will be installed in the Caratinga field). Each FPSO unit has a capacity of 150 Mbpd. A total of 32 production wells and 21 injection wells are planned for the two fields.
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Albacora Leste (East Albacora). Albacora Leste is located at water depths between 3,609 and 4,921 feet (1,100 - 1,500 meters). First oil is expected in the end of 2005. An FPSO unit (P-50) with a capacity of 180 Mbpd is currently being converted in 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: (1) the Jubarte field, already producing through a pilot system, that consists of an FPSO unit (Seillean) with a capacity of 20 Mbpd that will, in phase I of the field development, be replaced by another FPSO (P-34) with 60 Mbpd capacity in the end of 2005, (2) the Frade field, which we are developing in partnership with Chevron Texaco and (3) the Marlim Leste field, that will have an FPSO unit (P-53) with a 180 Mbpd capacity, currently in the bidding phase. The contract to increase the production capacity of P-34 to 60 Mbpd was signed on June 17, 2004.
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.”
Participation by Brazilian Companies
Our Strategic Plan for 2004 to 2010 contemplates greater domestic content in our construction activities and other projects. We estimate that of the U.S.$46.1 billion in domestic capital expenditures for 2004 to 2010, at least U.S.$31.7 billion (69%) will be utilized to pay for equipment and services provided by Brazilian contractors, suppliers and other service providers.
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 eight other countries: Angola, Argentina, Bolivia, Colombia, Ecuador, Peru, the United States and Venezuela. See “-International.”
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The following table sets forth our average daily crude oil and natural gas production, our average sales price and our average lifting costs for each of 2003, 2002 and 2001:
Crude Oil and NGL Production (in Mbpd)
Brazil (2)
Other
Total crude oil and NGL production
Crude Oil and NGL Average Sales Price (U.S. dollars per Bbl)
Natural Gas Production (in Mmcfpd)
Brazil(3)
Total natural gas production
Natural Gas Average Sales Price (U.S. dollars per Mcf)
Aggregate Average Lifting Costs (oil and natural gas) (U.S. dollars per boe)
Brazil(4)
International(5)
Our increased offshore production over the three years ended December 31, 2003 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 2003 increased 2.7% relative to 2002, reaching 1.54 million barrels per day, principally as a result of:
Reserves
Our estimated worldwide proved reserves of crude oil and natural gas as of December 31, 2003 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, 2003, our domestic proved developed crude oil reserves represented 40.1% of our total domestic proved developed and undeveloped crude oil reserves. Our domestic proved developed natural gas reserves represented 54.2% of our total domestic proved developed and undeveloped natural gas reserves. Total domestic proved hydrocarbon reserves on a barrel of oil equivalent basis increased at a compounded annual growth rate of 2.7% from the end of 1997 to 10.4 billion barrels of oil
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equivalent at the end of 2003. Natural gas as a percentage of total domestic proved hydrocarbon reserves increased 40.3% over the same period, representing an increase in volume from 5,782 billion cubic feet in 1997 to 8,111 billion cubic feet at the end of 2003, increasing at a compounded annual growth rate of 6.7% from the end of 1997 to 2003.
DeGolyer and MacNaughton, or D&M, reviewed and certified 91% of our gross domestic reserve estimates as of December 31, 2003. The estimates for the certification were performed in accordance with Rule 410 of Reg S-X of the SEC.
The following table sets forth our estimated net proved developed and undeveloped reserves and net proved developed reserves of crude oil and natural gas as of December 31, 2003, 2002 and 2001:
WORLDWIDE ESTIMATED NET PROVED RESERVES
Net Proved Developed and Undeveloped Reserves:
Reserves as of December 31, 2000
Revisions of previous estimates
Extensions, discoveries and improved recovery
Sales of reserves in place
Production for the year
Reserves as of December 31, 2001
Purchase of reserves in place
Reserves as of December 31, 2002
Reserves as of December 31, 2003
Net Proved Developed Reserves:
As of December 31, 2000
As of December 31, 2001
As of December 31, 2002
As of December 31, 2003
The following tables set forth our crude oil and natural gas proved reserves by region, as of December 31, 2003, 2002 and 2001:
CRUDE OIL NET PROVED RESERVES BY REGION
Proved
Developed and
Undeveloped
Developed
Other South America(1)
West Coast of Africa
Gulf of Mexico
Total international
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NATURAL GAS NET PROVED RESERVES BY REGION
and
Please see “Supplementary Information on Oil and Gas Producing Activities” in our audited consolidated financial statements for further details on our proved reserves.
Refining, Transportation and Marketing
Our refining, transportation and marketing business segment encompasses the refining, transportation and marketing of crude oil, oil products and fuel alcohol, including investments in petrochemicals.
We own and operate 11 refineries in Brazil, with a total processing capacity of 1.97 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 (which we also process in our refineries) and oil products. We also export some oil products. 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 the sole supplier of oil products to the Brazilian market. Now that the market is deregulated and we are no longer the sole supplier of oil products to the Brazilian market, we intend to reevaluate our import strategy and may reduce imports to the extent such reductions improve our profitability. We also export, to the extent our production of oil products exceeds Brazilian demand or our refineries are unable to process our growing domestic crude oil production.
We transport oil products and crude oil to domestic wholesale and export markets through a coordinated network of marketing centers, storage facilities, pipelines and shipping vessels. As the monopoly supplier for almost fifty years of a country that ranks as the 11th largest consuming nation in the world, according to the June 2003 issue of Statistical Review of the World, we have developed a large and complex infrastructure. Our refineries are generally located near Brazil’s population and industrial centers and near our production areas, which we believe creates logistical efficiencies in our operations.
In accordance with the requirements of the Oil Law, we have placed our shipping assets into a separate subsidiary, Petrobras Transporte S.A., or Transpetro. This subsidiary leases storage and pipeline facilities and provides open access to these assets to all market participants. Our petrochemicals business is now also included in the refining, transportation and marketing segment.
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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
At December 31, 2003, we had total installed capacity of approximately 2.10 million barrels per day, which, according to Petroleum Intelligence Weekly, made us the seventh largest refiner of oil products in the world among publicly traded companies in 2002. Worldwide, we processed an average of 1.70 million barrels of oil per day in 2003, which represents a utilization rate of 81% for the year, calculated on total capacity. This compares with 83% average utilization rates in 2002 and 83% average utilization rates in 2001.
Our domestic production in 2003 supplied approximately 80% of the crude oil feedstock for our refinery operations in Brazil, as compared to 79% in 2002 and 76% in 2001. 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 2003, we processed, in Brazil, 588 million barrels of crude oil or 1.61 million barrels per day. Our average refining costs (consisting of variable costs and excluding depreciation and amortization) in Brazil were U.S.$1.17 per barrel in 2003, U.S.$0.91 per barrel in 2002 and U.S.$0.95 per barrel in 2001. Our production in Brazil supplied approximately 80% of this crude oil. Due to the heavier crude characteristic of many Brazilian fields, we have invested in equipment and machinery that allows us to convert heavy crude oil to lighter products. The majority of our heavy crude conversion capacity is located in our largest refineries located near our heavy crude oil reserves in the Campos Basin: Landulpho Alves, Duque de Caxias, Paulínia, Presidente Bernardes, Gabriel Passos and Henrique Lage.
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The following table describes the installed capacity, refining throughput and utilization of our refineries for each of 2003, 2002 and 2001:
REFINING STATISTICS
Refineries
Capacity
(Mbpd)
Throughput
Utilization
(%)
Paulínia
Landulpho Alves
Duque de Caxias
Henrique Lage
Alberto Pasqualini(1)
Pres. Getúlio Vargas
Pres. Bernardes
Gabriel Passos
Manaus
Capuava
Fortaleza
Total Brazilian
Gualberto Villarroel(2)
Ricardo Eliçabe(3)(4)
Guillermo Elder Bell(2)
San Lorenzo (5)
Del Norte (6)
Total International
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 2003, 2002 and 2001:
DOMESTIC PRODUCTION VOLUME OF OIL PRODUCTS
Product
Diesel
Gasoline
Fuel oil
Naphtha and jet fuel
Refinery Investments and Improvements
In recent years, we have made investments in our refinery assets in order to improve our yields of middle and lighter distillates, which typically generate higher margin sales and reduce the need to import such products. Our principal strategy with respect to our refinery operations is to maximize throughput of domestic crude oil. Since our heavy domestic crude oil produces a higher proportion of fuel oil for each barrel of crude oil processed, production 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:
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Major Refinery Projects
Included in our Strategic Plan are a number of upgrades to our key refineries. Our major investments are generally (1) coking units to further break down our heavy oil into middle distillates or (2) hydro treatment units that reduce sulfur to produce products that meet international standards. We believe our hydro-treatment units will make it possible to offer diesel fuel containing a maximum sulfur content of 0.05% to metropolitan regions around Brazil, thus meeting stricter environmental standards being implemented under Brazilian law. The principal refineries and planned investments are as follows:
Refinery
Objective
Alberto Pasqualini (REFAP)
Presidente Getúlio Vargas Refinery (REPAR)
Henrique Lage (REVAP)
Paulínia Refinery (REPLAN) (two units)
Landulpho Alves (RLAM)
Duque de Caxias Refinery (REDUC)
Imports
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 sold to the retail market in Brazil through distributors, including our subsidiary BR.
As our production has increased and our refineries have become capable of processing larger quantities of our own crude oil, the average daily volume of our imports of crude oil has decreased to 320,600 barrels per day in 2003, as compared to 337,000 barrels per day in 2002 and 399,000 barrels per day in 2001. The following table sets forth the percentage of crude oil that we imported during each of 2003, 2002 and 2001 by region.
IMPORTS OF CRUDE OIL BY REGION
Region
Africa
Middle East
Central and South America/Caribbean
Oceania
Europe
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In 2003, our total costs of imports of crude oil from all these regions was U.S.$3,541 million, as compared to U.S.$3,162 million in 2002 and U.S.$3,635 million in 2001.
We purchased approximately 23% of our 2003 crude oil imports and 33% of our 2002 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, 2003, we had one long-term contract providing for the supply of crude oil to us in Brazil, with suppliers from Saudi Arabia. This contract was renewed in February 2003 under identical terms, and will now expire in January 2005. 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 121,827 barrels per day in 2003, as compared to 215,121 barrels per day in 2002 and 328,100 barrels per day in 2001, 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 2003, 2002 and 2001:
IMPORTS OF OIL PRODUCTS
Oil Product
LPG
Distillates(1)
Naphtha
Others(2)
In 2003, our total costs of oil product imports, measured on a cost-insurance-and-freight basis, was U.S.$1,542 million, as compared to U.S.$2,086 million in 2002 and U.S.$3,103 million in 2001. For a discussion of import purchase volumes and prices, see Item 5 “Operating and Financial Review and Prospects-Sales Volumes and Prices-Import Purchase Volumes and Prices.”
Exports
We also export that portion of oil products processed by our refineries that exceed Brazilian demand. In addition, we export domestic crude oil that we are unable to process in our refineries because of limited conversion capacity. The following table sets forth the volumes of oil products we exported during each of 2003, 2002 and 2001:
EXPORTS OF OIL AND OIL PRODUCTS(1)
Crude oil
Fuel oil (including bunker fuel)
The total value of our crude oil and oil products exports, measured on a free-on-board basis, was U.S.$5,335 million in 2003, U.S.$4,610 million in 2002 and U.S.$2,707 million in 2001.
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 retain the right of preference for its shipments, based on the historical level of transportation assessed for each pipeline, formally assigned by the ANP. The excess capacity is offered to third parties on a non-discriminatory basis and under equal terms and conditions.
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Prior to the enactment of the Oil Law, we were the only company authorized to ship oil products to and from Brazil and to own and operate Brazilian pipelines. Additionally, only vessels flying the Brazilian flag were entitled to carry shipments to and from Brazil. Pursuant to the Oil Law, the ANP now has the power to authorize any company or consortium organized under Brazilian law to transport crude oil, oil products and natural gas for use in the Brazilian market or in connection with import or export activities, and to build facilities for use in any of these activities. The Oil Law has also provided the basis for open competition in the construction and operation of pipeline facilities.
Pipelines and Terminals
We own, operate and maintain an extensive network of crude oil and natural gas pipelines connecting our terminals to our refineries and other points of primary distribution throughout Brazil. At December 31, 2003, our onshore and offshore crude oil and oil products pipelines aggregated 5,130 miles (8,262 kilometers) in length and our natural gas pipelines aggregated approximately 4,763 miles (7,669 kilometers) in length, including the Brazilian side (1,609 miles, or 2,589 kilometers) of the Bolivia-Brazil pipeline.
NATURAL GAS PIPELINES
Up to December 2003, we had the intention to develop a project, which we refer to as PDET, for the 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.
At the end of 2003, the government of Rio de Janeiro enacted a law creating severe obstacles to the economic feasibility of the original concept of the onshore portion of PDET. After three months of ultimately unsuccessful negotiations with the Rio de Janeiro State government, we announced the cancellation of the onshore portion of the PDET project and a revision to the project’s original design.
Under the revised project, the original offshore fixed platform (PRA-1) will be connected to six offshore production platforms through pipelines and will transfer the crude oil to a floating, storage and offloading platform (FSO) and two monobuoys, which will in turn facilitate the transfer of the crude oil to shuttle tankers or the export of the crude oil to other countries. The shuttle tankers will transport the oil to the Southeast terminals where it will be pumped to existing onshore pipelines connected to refineries in Rio de Janeiro, Minas Gerais and São Paulo. This project will cost approximately U.S.$700 million and is expected to start its commercial operation in January 2007.
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Transpetro also operates 43 storage terminals with aggregate capacity of 63.3 million barrels of oil equivalent. At December 31, 2003, tankage capacity at these terminals consisted of 34.1 million barrels of crude oil, 26.7 million barrels of oil products and fuel alcohol and 2.5 million barrels of LPG.
Transpetro is currently evaluating alternatives to improve the efficiency of its transportation system, including evaluating improvements to the monitoring and control of the crude oil and natural gas pipeline network through the gradual implementation of a supervisory control and data acquisition system, which, when completed, will monitor the pipelines and storage facilities located throughout the country. Transpetro has already implemented the first phase of the project and inaugurated a centralized control and operating center in June 2002, in its headquarters in Rio de Janeiro. Currently, there are a national back-up master station and two regional master stations connected through satellite communication. Tank-farms and pump stations are equipped with mini stations connected to the regional master stations. Transpetro’s goal is to be able to operate all of its domestic pipelines remotely, initially via the regional stations, and ultimately via the centralized control and operating center located in its headquarters in Rio de Janeiro.
Shipping
At December 31, 2003, our fleet consisted of the following 54 vessels (50 owned and 4 bareboat chartered), 36 of which are single hulled and 18 of which are double hulled, with aggregate deadweight tonnage of 2.71 million:
OWNED/BAREBOAT CHARTERED VESSELS
Type of Vessel
Tankers
Ore/Oil vessels
Liquefied petroleum gas tankers
AHTS Anchor Handling Tug Supply
FSO Floating, Storage and Offloading
These vessels are currently operated by Transpetro and their activities are mainly concentrated in the Brazilian coastline, South America (Venezuela and Argentina), Mediterranean Sea, Caribbean Sea, Gulf of Mexico, West Africa and the Persian Gulf. Our shipping operations support the transportation of crude oil from offshore production systems, our import and export of crude oil and oil products and our coastal trade. Our Strategic Plan calls for an investment of U.S.$1.2 billion from 2004-2010 to renew our fleet, including orders for an additional 53 vessels. The table below sets forth the types of products and quantities of such products we transported during each of the years indicated.
PRODUCTS AND QUANTITIES TRANSPORTED
Oil Products
Fuel Alcohol
Percentage transported by our owned/bareboat chartered fleet
Coastal transport as a percentage of total tonnage
The average monthly-chartered tonnage in 2003 amounted to 4.0 million deadweight tons, as compared to 3.9 million deadweight tons in 2002 and 3.6 million deadweight tons in 2001. 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.$537 million in 2003, U.S.$431 million in 2002 and U.S.$707 million in 2001.
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Marketing
We sell 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 2003, we sold 167.2 million barrels of oil products to wholesale customers, with gasoline and diesel fuel representing approximately 84.5% of these sales. Of our total sales in 2003, 133.6 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 2003, 2002 and 2001:
OIL PRODUCT SALES
Customer
Wholesalers
Total wholesalers
Retail distributors
BR
Third parties
Total retail distributors
Total customers
Petrochemicals
We conduct our petrochemical activities through our subsidiary, Petrobras Química S.A., or Petroquisa, with the exception of naphtha sales. Petroquisa is a holding company 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 utilities. At December 31, 2003, our ownership percentage of the total capital of these affiliates ranged from 11.09% to 59.92% and our ownership percentage of the voting capital of these affiliates ranged from 7.78% to 50%. The total book value of these investments is U.S.$463 million.
The basic supply feedstock used in Brazil’s petrochemical industry is naphtha, an oil based product. Until 2001, we were the sole supplier of naphtha to Brazil’s petrochemical industry. Following deregulation of the product in 2002, the petrochemical industry began importing naphtha directly. In 2003, the industry imported approximately 30% of its naphtha needs, and we supply the remainder from our refining operations.
Our petrochemicals business, based on the equity in results of affiliate companies, accounted for U.S.$27 million in 2003. We currently expect to maintain a presence in the petrochemicals industry principally by participating in projects integrated with our refineries. We expect that our selective investments in petrochemicals will solidify our involvement in the entire value chain, integrating refining and basic and derivative products. Although we have divested of certain interests in the petrochemical segment in the past, we plan on increasing the current level of our investments, as part of our downstream strategy.
In line with our strategy of stimulating demand for natural gas products, we also continue to invest in Rio Polímeros S.A., which is located next to our Duque de Caxias refinery (REDUC). Other investors include BNDES (the Brazilian federal development bank) 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.$74 million. At December 31, 2003, we had spent approximately U.S.$54 million of this total. We expect Rio Polímeros to be operational by mid-2005 and to produce 540,000 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 have started negotiating with BASF, a 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 material for production, we would use the propylene derived from LPG refined at our Henrique Lage refinery (REVAP). In June 2003, BASF and we decided to delay the creation of 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. This decision was a
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result of the lower than expected market demand for acrylic monomers and SAP. BASF and we will monitor market developments and continue discussions, but have not undertaken any commitments with respect to feedstock supply or the creation of a joint venture.
Distribution
Through BR, 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 6.5 million boe, at 71 storage facilities and 105 aviation product depots at airports throughout Brazil.
Our main strategies in distribution and marketing are to:
On June 25, 2004 we announced that our board of directors, and the board of directors of our subsidiary BR, approved the final terms and conditions negotiated by BR in order to acquire from ENI S.p.A. its Brazilian subsidiary Agip do Brasil S.A. for approximately U.S.$450 million, subject to adjustments based on the closing balance sheet. Agip do Brasil S.A. is a liquefied petroleum gas (LPG), fuel and lubricant distributor operating in Brazil under the Liquigás, Novogás and Tropigás brands for LPG distribution and the Agip, Companhia São Paulo de Petróleo and Ipê brands for fuel distribution. This acquisition should enable us to increase BR’s share of the LPG distribution market as well as consolidate its presence in the automotive fuel distribution market.
Retail
As of December 31, 2003, our sales network in Brazil included 7,000 active and non-active retail service stations compared to 7,119 as of December 31, 2002, and comprised approximately 21.3% 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 170 million reside. Of these 7,000 service stations, 5,095 were active stations and BR owned 631. As required under Brazilian law, BR subcontracts the operation of all its service stations to third parties. The other 6,369 service stations were owned and operated by dealers, who use the BR brand name under license with BR facilities as their exclusive suppliers. BR provides technical support, training and advertising for its network of service stations.
In 2003, 204 of our service stations also sold vehicular natural gas, compared to 170 in 2002 and 119 in 2001. The sales from these stations consisted of 14,554 million cubic feet (412 million cubic meters) in 2003, representing 31.2% of Brazilian market share, 13,245 million cubic feet (375 million cubic meters) in 2002, representing 60.6% of Brazilian market share and 9,893 million cubic feet (280 million cubic meters) in 2001, representing 61.4% of the Brazilian market share.
The table below sets forth market share (based on volume) for retail sales of different products in Brazil for each of 2003, 2002 and 2001:
DISTRIBUTION MARKET SHARE
Fuel alcohol
Source: Petrobras - based on figures provided by Sindicato
dos Distribuidores de Combustíveis-Sindicom
Prices to retailers have generally tended to remain consistent between competing distributors, particularly due to the low margin usually provided. Therefore, competition among distributors continues to be primarily based on product quality, service and image.
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.$23.4 million during 2003, as compared to U.S.$43.6 million in 2002 and U.S.$24.5 million in 2001.
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During 2003, approximately 21.3% 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 3,707 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:
We also participate in the retail sector in Argentina, where we currently own 681 retail service stations that operate under a number of brand names, including Petrobras, Eg3 and San Lorenzo.
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 31.5%, which has remained relatively constant over the past several years.
Set forth below are commercial and industrial sales statistics for each of 2003, 2002 and 2001:
COMMERCIAL AND INDUSTRIAL SALES BY PRODUCT
For the Year Ended
December 31,
Jet fuels
Lubricants
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. Prior to the share swap, we owned 73.6% of BR’s shares. We conducted the share swap and acquired an additional 25.6% of BR’s shares to bring our total to 99.2% of BR’s shares. We then incorporated BR as a wholly-owned subsidiary and effected the delisting of BR’s public shares, which were publicly traded in Brazil. 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 U.S.$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 U.S.$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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Natural Gas and Power
Our natural gas and power segment encompasses the purchase, sale and transportation of natural gas produced in or imported into Brazil. Additionally, this segment includes our domestic electric energy commercialization activities as well as investments in domestic natural gas transportation companies, state-owned natural gas distributors and thermal electric companies.
The natural gas market in Brazil has been growing steadily. In 2003, we estimate that natural gas consumption represented approximately 6.5-7.0% of Brazil’s primary energy consumption, as compared to 5.5-6.0% in 2002 and 4.7% in 2001. 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 75% while vehicular consumption has grown by approximately 70%.
To capitalize on these growth opportunities, we have adopted a vertically integrated strategy. As a result of our petroleum exploration and production activities in Brazil, we produce significant amounts of associated natural gas as a by-product. We have also invested heavily in production facilities and pipeline capacity to import natural gas from Bolivia, where we, and other oil companies, have discovered substantial non-associated reserves. To secure a market for our natural gas, we have been investing in domestic gas distribution companies, as well as in thermoelectric plants, with the intention to further develop the market for our natural gas.
Our main strategies in the natural gas and power segment are to:
Our natural gas and power results are reflected in the “Gas and Energy” segment in our audited consolidated financial statements.
Natural Gas
Pipelines
Our main pipeline investment has been the development and construction of the Bolivia-Brazil natural gas pipeline, which has a total capacity of 1,060 MMscfd (30 MMcmd). The pipeline is 1,969 miles (3,150 kilometers) in length, representing 40% of the existing Brazilian onshore gas pipelines, and running from Rio Grande in Bolivia to Porto Alegre in Southern Brazil. The Bolivia-Brazil pipeline connects to our domestic pipeline system that transports natural gas from the Campos and Santos Basins. We are a significant investor in the Bolivia-Brazil natural gas pipeline, holding an 11% interest in GTB - Gas TransBoliviano S.A., or GTB, the corporate entity owning the Bolivian portion of the pipeline, and a 51% interest in TBG - Transportadora Brasileira do Gasoduto Bolívia-Brasil S.A., or TBG, the corporate entity owning the Brazilian portion of the pipeline.
Our investment in the Bolivia-Brazil gas pipeline was the result of a 1996 gas supply agreement (the “GSA”) for the purchase of natural gas between the Bolivian state oil company, Yacimientos Petrolíferos Fiscales Bolivianos—YPFB, and us. The GSA requires us to purchase from YPFB, 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 three major domestic natural gas projects: Cabiúnas, the Southeast Gas Pipeline Network and the Northeast Gas Pipeline Network.
The Cabiúnas project comprises transportation and processing facilities of natural gas from the offshore oil fields in the Campos Basin to the State of Rio de Janeiro, and includes the construction of an undersea facility for storage of natural gas during declines in consumption. We expect this project to be fully operational by the beginning of 2005 and to increase transportation capacity from the current 290 million cubic
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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 2003, the average daily volume of natural gas flared on the offshore platforms of the Campos Basin was 7,346,300 million cubic feet (208,024 million cubic meters).
We are currently developing the Southeast and the Northeast Gas Pipeline Networks (Malha Sudeste and Malha Nordeste) jointly with private capital investors (the Malhas Project). These projects will create additional transportation capacity by expanding the existing natural gas infrastructure, delivering natural gas to markets in the Northeast and Southeast regions of Brazil, and includes the construction of an approximately 890-mile (1,423 kilometers) pipeline, which is expected to start operations in 2005, at a total cost of approximately U.S.$1,000 million.
We are also conducting feasibility studies for projects to deliver natural gas to the states of Amazonas and Rondônia in Northern Brazil (Urucu—Porto Velho and Urucu—Manaus Gas Pipelines). An additional feasibility study is being conducted for the Southeast-Northeast Gas Pipeline. This pipeline, with a length of 1,280 kilometers, will connect the Southeast and Northeast gas pipeline networks, linking more gas supply sources to demand and increasing the existing gas pipeline network’s overall reliability. The Southeast-Northeast Gas Pipeline will enable gas imported from Bolivia to reach demand centers located in Northeastern Brazil.
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 one state, Espírito Santo, we have the exclusive rights to distribute natural gas through BR.
Our capital expenditures in these natural gas distribution companies as of December 31, 2003 totaled U.S.$36 million, as compared to U.S.$35 million as of December 31, 2002 and U.S.$32 million as of December 31, 2001. Our business plan includes total budgeted capital expenditures in the gas distribution business of approximately U.S.$370 million from 2004 through 2010. 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).
The following table sets forth our domestic sales of natural gas to affiliated and non-affiliated local distribution companies for each of 2003, 2002 and 2001:
DOMESTIC SALES OF NATURAL GAS TO LOCAL DISTRIBUTION COMPANIES
Total sales annual average
Annual sales growth
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 that varies with the price of fuel oil. We have purchased and paid in 2001, 2002 and 2003, approximately U.S.$194 million, U.S.$279 million and U.S.$288 million, respectively. Set forth below are the minimum volumes we have agreed to under these contracts, together with an estimate of the amounts we are obligated to pay for such minimum volumes:
NATURAL GAS TAKE-OR-PAY COMMITMENTS
Yearly Average
after 2008(1)
Volume Obligation (Mmcmpd)
Volume Obligation (Mmcfd)
Estimated Payments (U.S.$ million)(2)
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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 Bolivia-Brazil gas pipeline. The total estimated project cost was U.S.$1.9 billion. We have purchased and paid in 2001, 2002 and 2003, approximately U.S.$189 million, U.S.$232 million and U.S.$623 million, respectively. Set forth below are the minimum volumes we have agreed to under the ship-or-pay arrangements, together with an estimate (assuming certain changes in the U.S. Consumer Price Index (CPI)) of the amounts we are obligated to pay for such minimum volumes:
NATURAL GAS SHIP-OR-PAY COMMITMENTS
Volume Commitment (Mmcmpd)
Volume Commitment (Mmcfpd)
Estimated Payments (U.S.$ million)(1)
Additionally, PEPSA has a 15-year ship or pay agreement for 80,000 barrels per day through the OCP pipeline in Ecuador. Estimated payments respective to the commitment are approximately U.S.$1,118 million.
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 sales for 2001, 2002 and 2003, were approximately U.S.$574 million, U.S.$897 million and U.S.$1,320 million, respectively. The table below sets forth our commitments by local gas distribution companies and by thermal power plants to us for the firm purchase of volumes of natural gas beginning in 2004, together with an estimate of the amounts obligated to be paid for such volumes:
NATURAL GAS SALES CONTRACTS(1)
after 2008(2)
To Local Gas Distribution Companies
Affiliated
Unaffiliated
To Power Generation Plants
Unaffiliated(3)
Estimated Contract Payments (U.S.$ million)(4)
Pricing. On June 1, 2001, the Brazilian government instituted a mechanism which allows a U.S. dollar indexed component of the natural gas pricing mechanism to be passed through to the thermoelectric plants for a period of 12 years, pursuant to Portaria No. 176 (a joint regulatory act issued by the Ministry of Mines and Energy and the Ministry of Finance), which was updated by Portaria No. 234 issued on July 22, 2002. See “-Regulations of the Oil and Gas Industry in Brazil-Price Regulation-Natural Gas.” This mechanism has enabled us to sell natural gas to a number of thermoelectric plants that were unwilling to purchase natural gas under the prior gas price regulation because it requires the buyer to take the intra-year exchange rate risk. Under the new formula, exchange rate variations are reflected in gas prices annually, while we will be remunerated at market based interest rates for any resulting delay in gas price adjustments.
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Renegotiation of the GSA
As a result of lower-than-anticipated Brazilian market demand for natural gas, we have experienced losses on our commitments to purchase natural gas from YPFB. In accordance with a provision of the GSA that allows either party to request a renegotiation of certain terms of the agreement in the event of significant changes in market conditions, we had initiated a renegotiation with YPFB to achieve reductions in the volume and price of natural gas we are required to purchase under the GSA. The governments of Bolivia and Brazil decided to take over the renegotiation process and have conducted it since. The negotiations have taken longer than anticipated, however, as a result of the changes in the Brazilian government and the political instability in Bolivia in 2003.
In the event we do not agree to reductions in volumes and prices with YPFB, we estimate that, based on current forecasts of Brazilian natural gas consumption, we will incur losses of U.S.$40 million in 2004 and U.S.$20 million in 2005 with respect to our take-or-pay commitments.
Since November 2002, we have disputed the amounts charged by YPFB under our take-or-pay commitments. After the start of the renegotiation of the GSA, in January 2003, we indicated to YPFB that the resolution of disputed amounts should be treated as part of the overall renegotiation of the GSA. However, in March 2004, by request of the Brazilian government and as a goodwill gesture to YPFB and gas producers in Bolivia, we paid U.S.$64.2 million, corresponding to part of the disputed amounts under our take-or-pay commitments for the years 2002 and 2003, which YPFB claims amount to U.S.$220.5 million. We also have claims against YPFB for unpaid amounts under their delivery-or-pay commitments for 2001, 2002 and 2003 amounting to U.S.$37.2 million.
Incentives to Distribution Companies. In order to accelerate the expansion of the natural gas market in Brazil, increase consumption and ultimately reduce the financial exposure from our ship-or-pay commitments, we announced in December 2003 a new program of discounts for natural gas distributors in certain regions of Brazil. Distributors in the states of São Paulo, Minas Gerais, Paraná, Santa Catarina, Rio Grande do Sul, and Mato Grosso do Sul will pay a discounted price for volumes sold in addition to contracted amounts. If actual amounts sold exceed 40% of contracted amounts, we will reduce the base price according to a progressive schedule.
Power
Brazil currently has an installed electricity generation capacity of approximately 80,000 MW. More than 97% of this capacity is interconnected to form one single integrated system, with approximately 86% of the electricity supplied to that system coming from hydroelectric sources. Annual consumption of electricity grew annually at a rate of 4.5% during the 1990s. As a result of the rapid growth in electricity demand, combined with the limited investment in the sector during the last two decades and a high dependency on hydroelectric power (and consequently susceptibility to a prolonged drought), we believe substantial additional generation capacity needs to be developed in Brazil. In recognition of the need for such capacity and in order to promote the development of thermoelectric plants, the Brazilian government established the Thermoelectric Priority Program (PPT).
History of the PPT
The PPT, as originally envisioned in February 2000, prioritized the development of 49 new thermoelectric plants to meet Brazil’s growing electricity demand requirements. These PPT thermoelectric plants were to have increased Brazil’s generation capacity by approximately 17,000 MW by 2003. Despite a number of incentives introduced by the Brazilian government to promote the PPT, those thermoelectric power plants under development have been slow to progress. Developers have faced numerous difficulties, including inability to pass on financial and operating costs in U.S. dollars following a devaluation of the Brazilian Real in each of 2001 and 2002, the reluctance of many distribution companies to sign power purchase agreements because of existing supply contracts and lower consumer demand for thermoelectric power as a result of excess supply of hydroelectric power. In light of these difficulties, the Brazilian government reviewed the PPT and reduced the program to 39 projects, representing a planned 13,500 MW of additional capacity.
In line with our strategies in this segment, we decided to participate in the PPT either as a minority shareholder, offtaker or both, in a number of strategically important thermoelectric plants. Initially, we were planning to participate in 26 of the PPT projects, with total capacity of approximately 10,500 MW, of which 4,500 MW corresponds to our purchase commitments at that time.
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Current Status of PPT
Due to decreased rainfall in 2000 and 2001 in Brazil and the subsequent shortfall of hydroelectric power to meet Brazilian demand, the Brazilian government implemented a rationing program from the beginning of June of 2001 until the end of February 2002. This created a permanent reduction in demand of approximately 7%, according to recent Brazilian government estimates, resulting from the more rational use of electricity achieved during this period. Additionally, since the end of the rationing program, heavy rains have filled the main reservoirs of the country. As a result, in the short term, existing hydroelectric capacity is sufficient to meet the energy needs of the 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.
At the end of 2003, the Lula administration announced a new regulatory model for the power sector. The New Industry Model Law was enacted on March 16, 2004, but because the new law remains subject to the enactment of decrees of the Brazilian government and implementing resolutions of ANEEL, many aspects of the regulatory environment for thermoelectric power remain uncertain.
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 have suspended all investment in thermoelectric power, except for the 11 plants under construction or operation. We do not intend to continue developing the thermoelectric plants still in the planning stage, or expand existing thermoelectric plants until the content and implications of the proposed new regulatory model for the Brazilian power sector become clearer. Although our Strategic Plan calls for an increase in capacity, our plans will ultimately depend upon the level of demand for electricity in general and the success of our electricity marketing efforts.
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)
after 2007
NE Contingent Capacity Payments
NE Tolling Arrangements
Total Northeast Region
S/SE Contingent Capacity Payments
S/SE Tolling Arrangements(2)
Total South and Southeast Region
Total Commitments
The total amount of electricity in respect of which we have tolling or capacity commitments, based upon commitments of projects under construction or in operation, is 3,645 MW as of the end of 2005, of which 2,215 MW come from firm tolling agreements and 1,430 MW from contingent capacity payments.
We expect that the electricity we purchase under tolling agreements will be partly used for consumption in our facilities, estimated to be approximately 300 MW per year, equally allocated between the Northeast and South/Southeast regions of Brazil, as well as firm power sales contracts to third party distributors and industrial consumers. Currently, we do not expect to enter into tolling or capacity arrangements with respect to future thermoelectric plants. Our strategy is to sell all of the other energy in respect of which we have purchase commitments through medium and long-term Power Purchase Agreements, or PPAs. However, as a result of current price levels, we have also negotiated certain shorter-term contracts. As of May 2004, PPAs included offtake commitments totaling 1,850 average MW for 2004, 2,370 average MW for 2005 and 1,630 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.
We continue to have contractual commitments related to our energy operations which would be payable to third parties. These contractual commitments include the purchase of energy, supply of natural gas and reimbursement of operating expenses of thermoelectric power plants. These commitments were incurred in connection with the PPT. Our energy commitments include the following:
Employing a discount rate of 12.0% per year, the net present value of the maximum financial exposure of the energy segment is approximately U.S.$1,419 million at December 31, 2003.
In January 2003, Companhia Paranaense de Energia - COPEL ceased making its monthly capacity payments to UEG Araucária Ltda. - UEGA (an independent power producer that initiated operations in September 2002 and which is 60% owned by El Paso, 20% by Copel and 20% by us). In April 2003, UEGA initiated arbitration proceedings before the ICC International Court of Arbitration to recover damages from COPEL’s default under the PPA entered into between the two parties. As of December 2003, the capacity payments would have totaled approximately U.S.$72 million if the PPA had remained in effect.
TermoRio S.A. in as an independent power producer under construction. We own 50% of TermoRio S.A., as does NRG. In April 2002, NRG exercised a put option requesting us to buy its shares and credits in TermoRio S.A. In May 2002, a court granted an injunction against NRG suspending the effects of the put option pending a final award by an arbitral tribunal. The final award was granted on March 8, 2004, holding that the amount that we must pay to NRG for its shares and credits in TermoRio S.A. totaled approximately U.S.$80 million. We are taking the necessary steps to implement the arbitral award in conjunction with NRG.
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In 2003, approximately 6.8% 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 internationally. 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.$6.1 billion in capital expenditures for the period 2004-2008 for all of our international investments.
Our main strategies in the international segment are to:
Our international results are reflected in the “International” segment in our audited consolidated financial statements.
Exploration and Production
During 2003 we conducted significant international exploration activities in Angola, Argentina, Bolivia, Colombia, Nigeria, the United States and Trinidad & Tobago and Venezuela. In addition, we are currently performing studies to evaluate blocks where we hold interests in Angola, Argentina, Colombia, Mexico, Nigeria and the United States. Production activities were conducted in Angola, Argentina, Bolivia, Colombia, Ecuador, Peru, the United States and Venezuela. Collectively, these activities represented approximately 6.5% of our total capital expenditures for crude oil and natural gas exploration and production. Our capital expenditures for international exploration and development were U.S.$428 million for 2003, U.S.$224 million for 2002 and U.S.$318 million for 2001. The following table provides information about the allocation of such expenditures for each of 2003, 2002 and 2001:
DISTRIBUTION OF INTERNATIONAL EXPLORATION ACTIVITIES
Argentina
Bolivia
Colombia
PESA(1)
South America
North Sea(2)
Development
Over the past three years, we have participated in the development of a number of fields internationally, including three in Argentina (Aguarague, Campo Duran & El Tordillo), two in Bolivia (San Alberto and San Antonio), five in Colombia (Guando, Rio Ceiba, Yaguara, Venganza e Revancha), and one in the United States (GB 200).
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In 2003, our net production outside of Brazil averaged 160,864 barrels per day of crude oil and NGLs and 85,015 barrels of oil equivalent of natural gas per day at an average lifting cost of U.S.$2.46 per barrel. The following table provides information on the allocation of our international development activities for each of 2003, 2002 and 2001.
ALLOCATION OF INTERNATIONAL DEVELOPMENT ACTIVITIES
North Sea(1)
Argentine Activities
With our acquisition of PEPSA (formerly Perez Companc) in 2002, we reinforced our position as an exploration and production leader in South America, especially in Argentina, where we already maintained activities. As of December 31, 2003, our combined crude oil and natural gas proved reserves in Argentina were approximately 410.63 million barrels of oil equivalent, approximately 65.56% of which were proved developed reserves and approximately 34.44% of which were proved undeveloped reserves.
PEPSA’s production in the country is concentrated in the Neuquén and Austral Basins. PEPSA owns 579 thousand net acres under production concessions in the Neuquén Basin and 2,632 thousand net acres under production concessions in the Austral Basin. Our gross production acreage in Argentina amounted to 4,027 thousand acres (3,211 thousand net), and we have a total of 2,536 gross productive wells (1,498 thousand net). For the year ended December 31, 2003, our combined crude oil and natural gas production in Argentina averaged 121 thousand barrels per day.
We own a 34% participation in the MEGA project (representing a total investment of U.S.$728 million), a joint venture among us, Repsol-YPF and Dow Chemical to fractionate natural gas liquids. The project consists of a natural gas processing plant in Loma La Lata (Province of Neuquén), a 600 km extension pipeline and a separating plant in Bahía Blanca (Province of Buenos Aires).
We are obligated under an off-take contract to take minimum volumes of LPG and natural gasoline , if delivered, at market prices. The sponsors financed approximately 70% of the project costs with a U.S.$472 loan from commercial banks and other institutional lenders. The loan was structured to be non-recourse to the sponsors following the termination of sponsor completion guarantees to the lenders during the construction period for their respective shares in the project (Repsol-YPF 38%, Petrobras 34%, and Dow Chemical 28%). The guarantees were originally set to expire on December 31, 2001, but were subsequently extended to December 31, 2003.
While the MEGA project reached mechanical completion and met or exceeded the performance tests established for the release of the sponsors’ guarantees, the lenders maintained that other conditions required for the release were not met. The sponsors agreed in December of 2003 to extend their guarantees until December 31, 2005 and to permit all lenders the right to put their MEGA notes to the sponsors immediately prior to the guarantees’ expiration. In addition, the sponsors granted MEGA’s fixed rate noteholders the right to exercise their put immediately. On January 15, 2004, all fixed rate noteholders exercised this right. As a result of these events, we purchased our respective share of MEGA’s fixed rate notes (U.S.$58 million), and currently guarantee our share of MEGA’s floating rate notes (U.S.$76 million).
We are also a shareholder in TGS, which owns a 7,400 km extension pipeline with a transport capacity of 62 MMcmd and a gas processing plant located in Bahía Blanca, with a processing capacity of 42 million MMcmd.
Our electricity assets in Argentina cover the entire productive chain. We account for 6.5% of the country’s electricity generation through our ownership interests in three generation plants—two hydroelectric (Piedra Del Águila and Pichi Picún Leufú) and one thermoelectric (Genelba). We also have an interest in Transener, Argentina’s largest transmission company and owner of 95% of Argentina’s high-tension network through our subsidiary PESA. PESA also maintains an important presence in the central area of Buenos Aires, an area with more than 2.1 million customers, through Edesur, Argentina’s largest energy distribution company by volume.
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Bolivian Activities
As of December 31, 2003, our combined crude oil and natural gas proved reserves in Bolivia were approximately 339.42 million barrels of oil equivalent, approximately 96.36% of which were proved developed reserves and approximately 3.64% of which were proved undeveloped reserves. Approximately 89.58% of our proved developed reserves in Bolivia are natural gas reserves.
We have a 35% interest in the San Alberto and San Antonio gas fields (the other partners are Petrolífera Andina (50%) and Total Bolivia (15%)). For the year ended December 31, 2003, our combined crude oil and natural gas production in Bolivia averaged 31 thousand barrels per day.
We own 44.5% of the shares of Transierra S.A, the owner and operator of the Yacuiba-Rio Grande gas pipeline (GASYRG), a pipeline in Bolivia that connects the gas fields in the south of Bolivia to the Bolivia-Brazil pipeline. Presently the pipeline has a capacity of 17 MMcmd, and installation of another compression unit will increase the capacity to 23 MMcmd. Investment for this project totaled more than U.S.$375 million. We also provided all the capital for the San Marcos pipeline, which transports natural gas to the city of Puerto Suárez (Bolivia), on the Brazilian border.
We acquired an interest in a natural gas compression plant in Rio Grande, Bolivia, which has a capacity to compress up to 1,546 million cubic feet per day.
We have a 100% interest in Empresa Boliviana de Refino (EBR). EBR owns two Bolivian refineries located in Cochabamba and Santa Cruz de la Sierra, with an estimated maximum production capacity of 48,000 barrels of crude oil per day. EBR wholly owns Empresa Boliviana de Distribución, a company with a network of 72 gas stations.
Venezuelan Activities
PEPSA’s exploration and production rights in Venezuela are held under operating service contracts. In 1994 Petróleos de Venezuela S.A. (PDVSA) awarded our first contract at the Oritupano-Leona field. As of December 31, 2003, PEPSA’s combined crude oil and natural gas proved reserves in Venezuela were approximately 304.56 million barrels of oil equivalent, approximately 40.52 % of which were proved developed reserves and approximately 59.48 % of which were proved undeveloped reserves.
As of December of 2003, PEPSA had four productions fields in the country. PEPSA’s gross production acreage in Venezuela amounted to 585 thousand acres (379 thousand net), and PEPSA has a total of 667 gross productive wells (430 thousand net). For the year ended December 31, 2003, PEPSA’s combined crude oil and natural gas production in Venezuela averaged 43 thousand barrels per day.
Ecuadorian Activities
PEPSA owns a 70% interest in Block 18 situated in the Oriente Basin of Ecuador. Block 18 is a field covering 197 thousand acres with a significant potential for production of 28° to 33° API light crude oil reserves. The concession for production activities in Block 18 is for an initial 20-year term starting from October 2002. Once this term expires, the Ecuadorian hydrocarbons law provides for the possibility of an additional five-year extension.
Block 18 has eight productive wells, one of which is located at the Pata field and six of which are located at the Palo Azul field. In addition, the area has early production facilities which can handle a daily gross production of 20 thousand barrels of crude oil.
PEPSA also holds a 100% interest in Block 31. This block is located in a highly sensitive ecological area of the Amazon jungle in the central part of the eastern border of the upper Amazon basin and covers an area of 494 thousand net acres. For the development of the block, investments totaling approximately U.S.$800 million will be required, with initial investments in the amount of approximately U.S.$200 million.
In addition to conducting seismic work in Block 31, PEPSA has drilled four exploratory wells in Apaika, Obe, Nenke and Minta. All the wells were successful and led to the discovery of the Apaika, Obe, Nenke and Minta fields. According to the block’s production sharing agreement, Petroecuador is entitled to a crude oil production take of about 15% to 17%, depending on the field’s daily crude oil production ranges and crude oil gravity.
Future oil production in Block 31 will be shipped through a heavy crude oil pipeline known as OCP in which PEPSA currently has an 8.96% interest. PEPSA has entered into a 15-year ship-or-pay transportation contract under which OCP has committed to provide it with a shipping capacity of 80,000 barrels per day.
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Peruvian Activities
Through PEPSA, we have the rights to oil and gas production in Lote X, a 116 thousand acre block in Peru’s Talara Basin. As of December 2003, Lote X had 2,366 production wells. PEPSA has entered into a long-term sales contract under which Petroperú (the Peruvian state-owned company) is obligated to purchase all of the production from Lote X at market prices. The sales contract expires in 2006.
Colombian Activities
During 2003, we signed three new contracts in Colombia, acquiring interests in Espinal Profundo (50%), Boqueron Profundo (60%) and Rio Aipe (50%). We drilled one wildcat well, Espino-1, which is currently under evaluation.
In the Guando Field, we drilled 31 wells, 27 oil producers and four water injectors. We started to operate the main oil pipeline (Guando - Chicoral pipeline) that exports the oil produced in the field to the OAM pipeline.
African Activities
In December 2001, we entered into three joint ventures for crude oil exploration and production in deepwater blocks, two off the coast of Nigeria (resulting from the 2000 license bidding round) and one off the coast of Angola. In one of these blocks in Nigeria, in which we were awarded a 75% interest and are the operator, we farmed out in 2003 half of our interests (37.5%), in order to lower our overall risk. We are currently appraising Agbami and Akpo, two fields previously discovered in the Niger Delta Basin.
Our Angolan branch of our wholly-owned subsidiary, Petrobras International Braspetro B.V., has continued to perform as a non-operating partner in two licenses under petroleum sharing agreements.
Gulf of Mexico Activities
Petrobras America, Inc. (PAI), our wholly-owned subsidiary, continues to expand its activities in the Gulf of Mexico’s deep and ultra-deepwaters through “farm-in” agreements (by which PAI, rather than obtaining an interest directly from the relevant government authorities, acquires an interest from a party who has already obtained such interest), and participation in leases and sales conducted by the United States Minerals Management Service. As of December 31, 2003, PAI held participations in 115 offshore blocks in the Gulf of Mexico, of which about 94 were located in deep and ultra-deep waters.
In 2003, PAI participated in the drilling of three exploration wells which resulted in the discoveries of Coulomb, Chinook and St. Malo, with 33.3%, 30% and 25% of participation, respectively. Together with the previous Cascade discovery, these accumulations confirm the potential of the ultra deepwaters of the Gulf of Mexico. Additionally, PAI has obtained a participation in several other similar prospects, along the same geologic features, with similar potential, which will be drilled in 2004 and 2005.
Also, in 2003, as part of the bidding launched by Petróleos Mexicanos (PEMEX) for the operation of areas under multiple service contracts, contracts for the Cuervito and Fronterizo blocks were awarded to a joint venture composed of us (45% interest), the Japanese company Teikoku (40%) and the Mexican company Diavaz (15%). There are 12 gas discoveries in this block which will be developed with a total expenditures of U.S.$510 million.
Organizational Structure
All of our 14 direct subsidiaries are incorporated under the laws of Brazil, except PIFCo, Petrobras International Braspetro B.V. (PIB BV), Braspetro Oil Company (BOC), Braspetro Oil Services Company (Brasoil) and Petrobras Netherlands B.V. (PNBV), which are incorporated abroad. We own at least 99.9% of the common shares of those subsidiaries and at least 98% of the preferred shares of Petroquisa, Gaspetro and BR. PIFCo, Petrobras International Braspetro B.V. (PIB BV), Braspetro Oil Company (BOC), Braspetro Oil Services Company (Brasoil), Petrobras Netherlands B.V. (PNBV), Transpetro, Downstream Participações S.A., Petrobras Negócios Eletrônicos S.A. (E-Petro) Petrobras Energia Ltda., VTE Piratininga and Termor 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.
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The following diagram sets forth our significant consolidated subsidiaries:
Property, Plants and Equipment
Under Brazilian law, the Brazilian government owns all crude oil and natural gas reserves within Brazil, and we have certain rights to exploit those reserves pursuant to concessions. Substantially all of our property, consisting of refineries and storage, production, manufacturing and transportation facilities, is located in Brazil. See Item 4 “Information on the Company” for a description of our reserves, sources of crude oil and natural gas and material plans for expansion and improvements in our facilities.
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 U.S.$25 million to confirm its compliance with all HSE requirements.
We will continue to evaluate and develop initiatives to address HSE concerns and to reduce our exposure to HSE risks.
See below and Item 8 “Financial Information” and Item 5 “Environmental Proceedings and Liabilities” for additional information.
Environmental Liabilities
In the period between 2000 to 2003, we experienced several accidents, some of them leading to significant oil spills: 73,000 gallons in 2003, 52,000 gallons in 2002, 691,000 gallons in 2001 and 1,580,000 gallons in 2000. As a result of certain of these accidents, we remain subject to several administrative, civil and criminal investigations and proceedings. We cannot predict whether additional litigation will result from those accidents or whether any such additional proceedings would have a material adverse effect on us. See Note 22(d) to our audited consolidated financial statements.
On January 18, 2000, a pipeline connecting one of our terminals to a refinery in Guanabara Bay ruptured, causing a release of approximately 341,000 gallons of crude oil into the bay. We undertook action to control the spill in an effort to prevent the oil from threatening additional areas. We have spent approximately R$104 million in connection with the clean-up efforts and fines imposed by IBAMA in connection with this spill, and are subject to several proceedings as a result of this spill, including:
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:
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On February 16, 2001, our Araucária-Paranaguá pipeline ruptured as a result of an unusual movement of the soil and spilled approximately 15,059 gallons of fuel oil into several rivers located in the State of Paraná. On February 20, 2001, we finalized the cleaning of the river surfaces, recovering approximately 13,738 gallons of fuel oil. As a result of the accident:
On March 15, 2001, a gas explosion inside one of the columns of the P-36 production platform, located in the Roncador field (75 miles off the Brazilian coast) led to the death of 11 employees and eventual sinking of the platform. The accident also caused 396,300 gallons of oil to spill into the ocean. As a result of the accident:
On October 13, 2002, a power blackout in FPSO P-34, which is located in the Barracuda-Caratinga fields, affected the ship’s water balance system and caused water to move from storage tanks located in one side of the ship to the tanks located in the opposite side, causing the FPSO to roll up to an angle of 40 degrees. Four days later, the stability of the ship had been restored, without casualties or spill of oil into the sea. As a result of the investigation of this accident, several measures to prevent similar accidents were incorporated into our Programa de Excelência Operacional-PEO (Operational Excellence Program). In connection with the accident:
On January 15, 1986, the Public Ministry of the State of São Paulo and the União dos Defensores da Terra(Union for Defense of the Earth), filed a public civil action against us and 23 other companies in the State Court of São Paulo for alleged damages caused by pollution. This lawsuit is entering the discovery phase. Although the plaintiffs alleged damages of U.S.$89,500 in an initial pleading filed with the Court, the Public Ministry of the State of São Paulo has publicly stated that U.S.$800 million will be ultimately required to remedy the alleged environmental damage. The Court refused to assert joint and several liability of the defendants, and we believe that it will be difficult to determine the environmental damage attributable to each defendant.
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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, 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 Comissão de Valores Mobiliários (Brazilian Securities Commission, or 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 regulations, the Brazilian government:
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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 and electricity.
To permit the taxation of all imported crude oil, oil products and natural gas in conjunction with the opening of the market to all participants, the Brazilian government established an excise tax to be applied with respect to the sale and import of crude oil, oil products and natural gas products (Contribuição de Intervenção no Domínio Econômico, Contribution for Intervention in the Economic Sector, or CIDE). As of May 1, 2004, important changes were made regarding the taxation of oil products sales. The PIS/PASEP tax and the COFINS tax, previously ad valorem taxes, were converted into specific value taxes at the following rates:
Jet Fuel
Reais/m3 (except LPG/metric ton)
The specific tax rates for CIDE, and the amounts paid which could be used as credits against PIS/PASEP and COFINS amounts also changed and are now the following:
Fuel Oil
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.
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
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adjusted annually for changes in the United States producer price index and the U.S. dollar exchange rate with respect to the portion of the ceiling price relating to imported natural gas (set by the regulation at 80%) and for changes in the IGP-M with respect to the portion of the ceiling price relating to domestic natural gas (set by the regulation at 20%), reflecting the current mix of natural gas supplied to these qualifying thermoelectric plants. The annual adjustment in the ceiling price related to imported gas is based on the previous twelve-month period rate and the projected volume of natural gas to be sold to the qualifying thermoelectric plant during the succeeding twelve-month period. The price will be adjusted to reimburse the natural gas supplier, on a per invoice basis, for any shortfalls caused by a Real devaluation. Similarly, the qualifying thermoelectric plant will be reimbursed for overpayments, calculated on a per invoice basis, resulting from a Real appreciation during the period.
The applicable interest rate on the net shortfall or overpayment amount with respect to each qualifying thermoelectric plant will be the SELIC rate, the interest rate applicable to certain Brazilian government securities. In addition, interest projected to be accrued during the immediately succeeding twelve-month period on the net shortfall or overpayment amount will be added. Any portion of the shortfall or overpayment amount that is not reimbursed through these adjustments in the ceiling price will be included in the adjustment to the ceiling price for subsequent consecutive twelve-month periods until reimbursed in full.
The PPT allows qualifying thermoelectric plants to pass on to their customers any increases in pricing resulting from these adjustments.
The Petroleum and Alcohol Account
Prior to 2002, the Petroleum and Alcohol Account was a special account that reflected the impact on us of the Brazilian government’s regulatory policies for the Brazilian oil industry and its fuel alcohol program.
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).
From July 29, 1998 until December 31, 2001, the Petroleum and Alcohol Account was required to be adjusted by the PPE and certain fuel transportation and other reimbursable costs that had not been phased out. The net impact on us of our fuel alcohol activities was also recorded in the Petroleum and Alcohol Account.
Article 74 of the Oil Law required settlement of the Petroleum and Alcohol Account by the Brazilian government on or before full implementation of price deregulation was completed. This deregulation was phased in over several years and was implemented in full on January 2, 2002. To facilitate the required settlement, on June 30, 1998, the Brazilian government issued National Treasury Bonds-Series H 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 2004. 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 2004.
The value of the outstanding Series H bonds was U.S.$59 million as of December 31, 2003, U.S.$46 million as of December 31, 2002 and U.S.$92 million as of December 31, 2001.
Certification of the Petroleum and Alcohol Account
The changes in the Petroleum and Alcohol Account in the period from July 1, 1998 to December 20, 2002 are subject to audits by the ANP. The results of the audit will be the basis for settlement of the account with the Brazilian government. The term for settlement of the Petroleum and Alcohol Account has been extended to June 30, 2004, thereby extending the term for certification of the outstanding balance in the Petroleum and Alcohol Account.
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 2003, 2002 and 2001:
Opening balance
Advances (Collections)-PPE
Reimbursements to third parties:
Subsidies paid to fuel alcohol producers
Total reimbursements to third parties
Reimbursements to Petrobras:
Transport of oil products
Net result of fuel alcohol
commercialization activities(1)
Total reimbursements to Petrobras
Total reimbursements
Results of certification/audit process
conducted by the Brazilian government(2)
Translation gain (loss)(3)
Ending balance
The U.S.$57 million increase in the balance of the Petroleum and Alcohol Account during 2003 was primarily a result of the effect of the 18.2% appreciation of the Real against the U.S. dollar during the year.
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:
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:
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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 Ambiente (National Council for the Environment), which issues operating or drilling licenses. Maintenance of the licenses requires the submission of reports, including safety and pollution monitoring reports (IOPP) to IBAMA. Onshore environmental, health and safety conditions are controlled at the state rather than federal level. Law No. 6,938 of August 31, 1981, and subsequent regulations and decrees established strict liability for environmental damage, mechanisms for enforcement of environmental standards and licensing requirements for polluting activities.
CONAMA’s Resolution No. 23 of 1994 requires us to conduct environmental impact studies in connection with certain of our activities. We must eliminate, mitigate, or compensate the relevant parties for, the adverse environmental effects identified through these studies.
On December 27, 2000, Law No. 10,165, modifying Law No. 6,938, created the Taxa de Controle e Fiscalização Ambiental(Environmental and Fiscalization Control Tax, or TCFA). The law empowers IBAMA to collect, on a quarterly basis, certain fees from us and other companies that meet a minimum revenue threshold, are engaged in potentially environmentally damaging activities and/or are exploiting natural resources within Brazil. At present, we do not consider this fee imposed by IBAMA to be material. The Confederação Nacional da Indústria (Brazilian Industry Confederation, or CNI), is currently contesting these fees as unconstitutional.
Brazilian environmental laws and regulations provide for restrictions and prohibitions on spills and releases or emissions of various hazardous substances produced in association with our operations. Brazilian environmental laws and regulations also govern the operation, maintenance, abandonment and reclamation of wells, refineries, terminals, service stations and other facilities. Compliance with these laws and regulations can require significant expenditures, and violations may result in fines and penalties, some of which may be material. In addition, operations and undertakings that have a significant environmental impact, especially the drilling of new wells and expansion of refineries, require us to apply for environmental impact assessments in accordance with federal and state licensing procedures. In accordance with Brazilian environmental laws, we have proposed the execution of, or we have entered into, environmental commitment agreements with the environmental protection agencies and/or the federal or state public ministries, in which we agree to undertake certain measures in order to complete the environmental licensing for several of our operating facilities.
Under Law No. 9,605 of February 12, 1998, individuals or entities whose conduct or activities cause harm to the environment are subject to criminal and administrative sanctions, as well as any costs to repair the actual damages resulting from such harm. Individuals or legal entities that commit a crime against the environment are subject to penalties and sanctions that range from fines to imprisonment, for individuals, or, for legal entities, suspension or interruption of activities or prohibition to enter into any contracts with governmental bodies for up to ten years. The government environmental protection agencies may also impose administrative sanctions on those who do not comply with the environmental laws and regulations, including, among others:
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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.
In 2003, we invested approximately U.S.$750 million in environmental projects as compared to approximately U.S.$466 million in 2002. These investments were primarily directed at reducing emissions and wastes resulting from industrial processes, obtaining oil collectors for our environmental protection centers and other new equipment to improve our response to emergency situations, implementing new environmental technologies and upgrading our pipelines.
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, some participants have already begun importing refined oil products, which will compete with oil products from our Brazilian refineries, as well as the oil products we currently import. We now have to compete with global imports at international prices. We expect that this additional competition may affect the prices we can charge for our oil products, which in turn will affect the profit we can make.
We 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.
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 BBB+ or higher by Standard & Poor’s rating agency or B++ or higher by A.M. Best. 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 the entire value of our pipelines, we have insurance against damage or loss resulting from specific incidents, as well as oil spills from our pipelines.
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The premiums we paid in 2003 were distributed as follows: 29.0% to coverage of our offshore assets, 25.8% to coverage of our onshore assets, 9.9% to coverage of third-party liability, 2.2% to coverage of risks associated with transportation, 4.5% to hull and machinery risk coverage and 24.1% to coverage for other risks. Over 16.0% 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 2003, 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 our international activities, 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 2004 was U.S.$23.1 million, net of taxes. This represented a decrease of 21% over the preceding 12-month period. The decrease was primarily due to changes in the way we buy insurance, our risk management, our health, safety and environmental policies and market conditions.
Following the sinking of Platform P-36 and the September 11, 2001 terrorist attacks in the United States 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 our assets in Brazil that are the subject of our project financings, when required by the terms of those agreements.
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.
Overview
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 2003 totaled approximately 923,481 million barrels of crude oil equivalent, representing U.S.$30,797 million in net operating revenues, as compared to approximately 911,817 million barrels of crude oil equivalent and U.S.$22,612 million in net operating revenues in 2002 and approximately 862,009 million barrels of crude oil equivalent and U.S.$24,549 million in net operating revenues in 2001.
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.$28.84 per barrel for 2003, U.S.$25.02 per barrel for 2002 and U.S.$24.44 per barrel for 2001. For December 2003, Brent crude oil prices averaged U.S.$29.87 barrel, but during 2004 (through June 15), Brent crude oil prices have increased, averaging U.S.$33.63 per barrel. This increase in average crude oil prices also affected international prices for oil products.
Domestic Sales Volumes and Prices
During 2003, approximately 73.9% of our net operating revenues were derived from sales of crude oil and oil products in Brazil, as compared to 76.0% in 2002 and 84.3% in 2001. As export volumes of crude oil and oil products have increased, domestic sales as a percentage of net operating revenues have declined.
Our revenues are principally derived from sales in Brazil. The following table sets forth our domestic sales by volume of oil products, natural gas and fuel alcohol for each of 2003, 2002 and 2001:
Net
Average
Price
Operating
Revenues
Energy products:
Automotive gasoline
Liquid petroleum gas
Total energy products
Non-energy products:
Petrochemical naphtha
Total non-energy products
Natural gas (BOE)
Sub-total
Distribution net sales
Intercompany net sales
Total domestic market
Export net sales
International net sales
Sub-Total
Services
Consolidated net sales
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On June 15, 2004, we announced an increase in gasoline and diesel prices due to the elevated prices of crude oil on the international market. The price increase in the chart below reflect the increases in billing at Petrobras refineries, without ICMS:
The increase returns gasoline and diesel prices at the Petrobras refineries to the nominal values that were in effect during the entire first quarter of 2003 and up to April 30, 2003.
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.” Our export volumes of crude oil and oil products totaled 192,545 million barrels of crude oil equivalent in 2003, as compared to 202,003 million barrels of crude oil equivalent in 2002 and 125,261 million barrels of crude oil equivalent in 2001. 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 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 2003 was U.S.$5,335 million, as compared to U.S.$4,610 million in 2002 and U.S.$2,707 million in 2001. See Item 4 “Information on the Company-Refining, Transportation and Marketing-Exports.”
International Volumes and Prices
We produce, refine, transport, distribute and market crude oil and natural gas internationally. Sales from production outside Brazil to sources outside Brazil were U.S.$1,974 million in 2003, U.S.$588 million in 2002 and U.S.$1,034 million in 2001. 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
In spite of the growth in our domestic production, we continue to import lighter crude oil for blending in our own refineries, as well as smaller quantities of diesel, liquefied petroleum gas, naphtha and other oil products, 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 116.1 million barrels of crude oil in 2003, as compared to 117.6 million barrels of crude oil in 2002 and 128.8 million barrels of crude oil in 2001.
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 44.5 million barrels of oil products in 2003, as compared to 78.5 million barrels in 2002 and 119.8 million barrels in 2001. See Item 4 “Information on the Company-Refining, Transportation and Marketing-Imports.”
Effect of Taxes on our Income
General
In addition to collecting sales and value-added taxes, such as the Imposto sobre Circulação de Mercadorias e Serviços, or ICMS, on behalf of federal and state governments, we pay three principal taxes on our oil producing activities in Brazil:
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offshore), water depth and number of years that the field has been in production. In 2003, the tax was charged on 13 of our fields, including Marlim, Albacora, Roncador, Leste do Urucu, Rio Urucu, Canto do Amaro, Marimbá, Rio Urucu, Canto do Amaro and Barracuda. The tax is based on net revenues of a field, which consists of gross revenues less royalties paid, investments in exploration, operational costs and depreciation adjustments and applicable taxes. The Special Participation Tax uses as a reference international oil prices converted to Reais at the current exchange rate.
These taxes imposed by the Brazilian government are included in our cost of goods sold, and therefore have a significant effect on our total lifting costs. Additionally, we are subject to tax on our income at an effective rate of 25% and a social contribution tax at an effective rate of 9%, the standard corporate tax rate in Brazil. See Note 4 to our audited consolidated financial statements.
Potential Change in ICMS Legislation
In June 2003, the governor of the State of Rio de Janeiro enacted a law that would have increased the amount of ICMS that we are required to pay by approximately R$5.4 billion (U.S.$1.9 billion) per year. Although the law is technically in force, the government of the State of Rio de Janeiro has yet to apply it. Currently, the ICMS is assessed at the refinery level at the point of sale of refined products, but not at the wellhead level. 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). The new law changes the point of collection of a portion of the ICMS from the refinery level to the wellhead level of production in the State of Rio de Janeiro. As a result, we would 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 have paid taxes on the same oil products at both production and refining levels.
On February 3, 2004, the governor of Rio de Janeiro issued a decree implementing the collection of the ICMS tax under the guidelines of the new law. However, that decree was revoked the following day by a subsequent decree. Nevertheless, the State of Rio de Janeiro may choose to enforce the law at any time.
The attorney general has filed a lawsuit with the Brazilian Supreme Court challenging the constitutionality of the ICMS legislation. We believe that the law is in fact unconstitutional and are awaiting a judicial ruling on the issue.
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.$602 million in 2003, U.S.$1,142 million in 2002 and U.S.$1,375 million in 2001.
We incur financial expenses from short and long-term debt denominated in U.S. dollars, Reais and other currencies. Our financial expenses were U.S.$1,247 million in 2003, U.S.$774 million in 2002 and U.S.$808 million in 2001. In addition, we capitalized U.S.$188 million in interest in 2003, as compared to U.S.$139 million in 2002 and U.S.$123 million in 2001.
Inflation and Exchange Rate Variation
Inflation
Since the introduction of the Real as the new Brazilian currency in July 1994, inflation in Brazil has remained relatively limited, although it increased markedly in 2002. Inflation was 7.7% in 2003, 26.4% in 2002 and 10.4% in 2001, as measured by the IGP-DI, a general price index. Inflation has had, and may continue to have, effects on our financial condition and results of operations. A large percentage of our total costs are in Reais, and our suppliers and service providers generally attempt to increase their prices to reflect Brazilian inflation. These increases are counteracted by an appreciation of the U.S. dollar against the Real.
Exchange Rate Variation
Since we adopted the Real as our functional currency in 1998, fluctuations in the value of the Real against the U.S. dollar, particularly devaluations of the Real, have had, and will continue to have, multiple effects on our results of operations. Our reporting currency for all periods is the U.S. dollar. We maintain our financial records in Reais, and translate our statements of operations into U.S. dollars at the average rate for the period. The amounts reported in our statements of operations in any given period will be reduced at the same rate as the Real has devalued in relation to the U.S. dollar during that period. During 2003, there was a 18.2% appreciation of the Real against the U.S. dollar, as compared to a 52.3% devaluation in 2002 and a 18.7% devaluation in 2001.
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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. Prior to 2003, our Reais-denominated costs increased at a rate slower than the devaluation. Accordingly, the effect was to decrease costs of locally supplied products and services when reported in U.S. dollars.
In recent periods, the exchange rate variation has had the following additional effects, among others, on our financial condition and results of operations:
Foreign currency translation adjustments reflecting a devaluation have the greatest impact on the balance sheet of a company such as ours, whose assets are primarily denominated in Reais, but whose liabilities are primarily denominated in foreign currencies. The reductions in our asset values charged to shareholders’ equity, however, do not necessarily affect our cash flows, since our revenues and cash earnings are to a large degree linked to the U.S. dollar, and a portion of our operating expenses are linked to the Real.
The exchange rate variation also impacts the amount of retained earnings available for distribution by us when measured in U.S. dollars. Amounts reported as available for distribution in our statutory accounting records prepared in accordance with Brazilian accounting principles decrease or increase when measured in U.S. dollars as the Real depreciates or appreciates against the U.S. dollar. In addition, the exchange rate variation creates foreign exchange gains and losses that are included in our results of operations determined in accordance with Brazilian accounting principles and that affect the amount of our unretained earnings available for distribution.
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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:
Crude Oil and NGL Production (Mbpd)
Total Crude Oil and NGL Production
Change in Crude Oil and NGL Production
Average Sales Price for Crude (bpd in U.S.$)
Natural Gas Production (Mmcfpd)
Total Natural Gas
Change in Natural Gas Production (sold only)
Average Sales Price for Natural Gas (Mcf in U.S.$)
Year End Exchange Rate
Appreciation (Devaluation) during the year
Inflation Rate (IGP-DI)
Results of Operations for the year ended December 31, 2003 (“2003”) compared to the year ended December 31, 2002 (“2002”).
The comparison between our results of operations has been impacted by the Real’s devaluation against the U.S. dollar, due to the fact that the average Real/U.S. dollar exchange rate for 2003 was 5.2% higher than the average exchange rate for 2002.
Net operating revenues increased 36.2% to U.S.$30,797 million for 2003, as compared to net operating revenues of U.S.$22,612 million for 2002. This increase was primarily attributable to the alignment of prices of certain oil products in the Brazilian market with international prices of such products at the end of 2002. The increase in net operating revenues was also attributable, to a lesser extent, to an increase in sales volume outside Brazil (international sales), which includes sales conducted by PEPSA and PELSA. This increase was partially offset by a 4.4% reduction in sales volume in the domestic market, primarily due to a decrease in Brazilian consumer demand. See “-Sales Volumes and Prices-Domestic Sales Volumes and Prices.”
Our consolidated sales of products and services increased 29.4% to U.S.$42,690 million for 2003, as compared to U.S.$32,987 million for 2002.
Included in sales of products and services are the following amounts which we collected on behalf of the federal or state governments:
Cost of sales
Cost of sales for 2003 increased 34.0% to U.S$15,416 million, as compared to U.S.$11,506 million for 2002. This increase was principally a result of:
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additional charge payable in the event of high production and/or profitability from our fields), which increased to U.S.$1,625 million in 2003, as compared to U.S.$917 million in 2002, as a result of our increased production of crude oil during 2003, the inclusion of the Canto do Amaro and Roncador fields as fields subject to the special participation tax and the increase in domestic reference prices for domestic crude oil;
These increases were partially offset by:
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 decreased 7.5% to U.S.$1,785 million for 2003, as compared to U.S.$1,930 million for 2002. This decrease was primarily attributable to the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002, and to the effect of the adoption of SFAS 143 in 2003. In 2002, U.S. $ 284 million in abandonment costs were recognized as depreciation, depletion and amortization in accordance with SFAS 19. In 2003, as a result of the adoption of SFAS 143, depreciation on the asset retirement obligation was recorded under depreciation, depletion and amortization, while accretion expense was recorded under exploration, including exploratory dry holes. See “-Impact of New Accounting Standards-SFAS 143.” This change resulted in U.S.$21 million in abandonment costs being recognized as depreciation, depletion and amortization in 2003. The decrease in depreciation, depletion and amortization, was partially offset by an increase of depreciation, depletion and amortization expenses of approximately U.S.$182 million incurred in connection with the activities of PEPSA and PELSA.
Exploration, including exploratory dry holes
Exploration costs, including exploratory dry holes increased 17.7% to U.S.$512 million for 2003 as compared to U.S.$435 million for 2002. This increase was primarily attributable to the increase of approximately U.S.$49 million in exploration costs, including exploratory dry holes in connection with the consolidation of PEPSA and PELSA and U.S.$43 million in abandonment costs recognized. The increase in exploration costs, including exploratory dry holes, was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
Impairment of oil and gas properties
For 2003, we recorded an impairment charge of U.S.$70 million, as compared to an impairment charge of U.S.$75 million for 2002. In 2003, the impairment charge was related to certain of our oil and gas producing properties in Brazil, Colombia and Angola. In 2002, the impairment charge was related to certain of our oil and gas producing properties in Brazil and Angola. These charges were recorded based upon our annual assessment of our fields using prices consistent with those used in our overall strategic plan and discounted at a rate of 13%.
Selling, general and administrative expenses increased 20.1% to U.S.$2,091 million for 2003, as compared to U.S.$1,741 million for 2002.
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Research and development expenses
Research and development expenses increased 36.7% to U.S.$201 million for 2003, as compared to U.S.$147 million for 2002. This increase was primarily related to our additional investments in programs for environmental safety, deepwater and refining technologies of approximately U.S.$62 million, and was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
Equity in results of non-consolidated companies
Equity in results of non-consolidated companies registered a gain of U.S.$141 million for 2003, as compared to a loss of U.S.$178 million for 2002. This increase was primarily attributable to:
We derive financial income from several sources, including:
Financial income decreased 47.3% to U.S.$602 million for 2003, as compared to U.S.$1,142 million for 2002. This decrease was primarily attributable to a reduction in financial interest income from short-term investments, which declined 79.4% to U.S.$163 million for 2003, as compared to U.S.$793 million for 2002. The reduction in financial income was also attributable to the 5.2% decrease in the value of the Real against the U.S. dollar for 2003, as compared to 2002. This decrease was partially offset by an increase of financial income of approximately U.S.$80 million resulting from the consolidation of PEPSA and PELSA in our 2003 financial results.
Financial expense increased 61.1% to U.S.$1,247 million for 2003, as compared to U.S.$774 million for 2002. This increase was primarily attributable to our additional debt and an increase of approximately U.S.$194 million in financial expenses resulting from the consolidation of PEPSA and PELSA in our 2003 financial results.
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Monetary and exchange variation on monetary assets and liabilities, net registered a gain of U.S.$ 509 million for 2003, as compared to a loss of U.S.$ 2,068 million for 2002. Approximately 90% of our long-term indebtedness was denominated in foreign currencies during each of 2003 and 2002. The fluctuation in monetary and exchange variation on monetary assets and liabilities, net was primarily attributable to the effect of the 18.2% appreciation of the Real against the U.S. dollar during 2003, as compared to a 52.3% depreciation of the Real against the U.S. dollar during 2002.
Employee benefits expense
Employee benefit expense consists of financial costs associated with pension and health care budgets. Our employee benefit expense increased 31.9% to U.S.$595 million for 2003, as compared to U.S.$451 million for 2002. This rise in costs was attributable to an increase of U.S.$166 million from the annual actuarial calculation of our pension and health care plan liability. The increase was partially offset by the effect of the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002.
Other taxes
Other taxes, consisting of miscellaneous value-added, transaction and sales taxes, decreased 7.5% to U.S.$333 million for 2003, as compared to U.S.$360 million for 2002. This decrease was primarily attributable to the 5.2% decrease in the value of the Real against the U.S. dollar in 2003, as compared to 2002, and the decrease of U.S.$61 million in the PASEP/COFINS taxes payable in respect of foreign exchange gains on assets, resulting from transactions with affiliates with assets denominated in foreign currencies.
Other expenses, net
Other expenses, net are primarily composed of gains and losses recorded on sales of fixed assets, general advertising and marketing expenses and certain nonrecurring charges. Other expenses, net for 2003 increased to an expense of U.S.$1,026 million, as compared to an expense of U.S.$857 million for 2002. The most significant charges were:
The most significant charges for 2002 were:
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Income tax (expense) benefit
Income before income taxes, minority interest and accounting changes increased from U.S.$ 8,773 million for 2003 to U.S.$ 3,232 million for 2002. As a result, we recorded an income tax expense of U.S.$ 2,663 million for 2003, as compared to an expense of U.S.$ 1,153 million for 2002.
The reconciliation between the tax calculated based upon statutory tax rates to income tax expense and effective rates is discussed in Note 4 to our consolidated financial statements as of December 31, 2003.
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 for 2002 and 2001 was significantly impacted by the Real’s devaluation against the U.S. dollar, due to the fact that the average Real/U.S. dollar exchange rate for 2002 was 24.2% higher than the average exchange rate for 2001.
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 was 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 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.
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 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 12.3% 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 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.
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 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 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 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 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:
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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 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.
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 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 for 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 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 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 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:
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Business Segments
Set forth below is selected financial data by segment for 2003, 2002 and 2001:
SELECTED FINANCIAL DATA BY SEGMENT
Exploration, Development and Production (Exploration and Development Segment)
Net revenues to third parties(1)
Intersegment net revenues
Total net operating revenues
Net income
Capital expenditures
Refining, Transportation and Marketing (Supply Segment)
Distribution (Distribution Segment)
Natural Gas and Power (Gas and Energy Segment)
Net revenues to third parties(2)
Net loss
International (International Segment)(2)
Liquidity and Capital Resources
Our principal uses of funds are for capital expenditures, dividend payments and repayment of debt. We have historically met these requirements with internally generated funds, short-term debt, long-term debt, project financings and sale and lease back agreements. We believe these sources of funds, together with our strong cash and cash equivalents on hand, will continue to allow us to meet our currently anticipated capital requirements. In 2004, our major cash needs include announced capital expenditures of U.S.$8,262 million, announced dividends of U.S.$1,955 million and payments of U.S.$1,145 million on our long-term debt obligations.
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Financing Strategy
The objective of our financing strategy is to help us achieve the targets set forth in our Strategic Plan, which provides for capital expenditures of U.S.$53.6 billion from 2004 to 2010. We plan to meet our budgeted capital expenditures primarily through internally generated cash and issuances in the international capital markets.
Our internally generated cash flows are sensitive to a number of factors, including international oil prices, domestic oil product prices and the Real/U.S. dollar exchange rate. Fluctuations in these factors can cause material variations between actual and projected annual cash flows. Our financing strategy is designed to maintain adequate liquidity to meet our debt obligations and to fulfill our capital spending plans, notwithstanding any unexpected decreases in our cash flows. To maintain liquidity, we exercise a series of precautions, including:
We also aim to increase the average life of our debt portfolio and reduce our cost of capital through a variety of medium and long-term financing arrangements, including supplier financing, project financing, bank financing, securitizations and the issuances of debt and equity securities. To that end, we took advantage of market conditions in 2003 to extend our maturity profile and capture decreased financing costs. We went from issuing a 5-year note bearing an interest rate of 9.0% in the beginning of the year to issuing a 15-year note with a 8.375% coupon on December 10, 2003. At the time of the issuance, the 15-year maturity was a record for Brazilian corporations.
Government Regulation
The Ministry of Planning, Budget and Management controls the total amount of medium and long-term debt that Petrobras and its Brazilian subsidiaries are allowed to incur through the annual budget approval process (Plano de Dispêndio Global, or PDG). Before issuing medium and long-term debt, 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 our 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 of debt that Petrobras and its Brazilian subsidiaries could incur was set at U.S.$932 million. The maximum level was set at U.S.$824 million for 2002 and U.S.$1,211 million for 2001.
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.
Sources of Funds
Our Cash Flow
At December 31, 2003, we had cash and cash equivalents of U.S.$9,610 million compared to U.S.$3,301 million at December 31, 2002. This increase in cash was primarily a result of:
Operating activities provided net cash flows of U.S.$8,569 million in 2003, as compared to U.S.$6,287 million in 2002. This increase was due primarily to a 36.2% increase in net operating revenues.
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Financing activities provided net cash flows of U.S.$2,376 million for 2003, as compared to U.S.$1,614 million in net cash used in 2002. This increase was due primarily to net issuances of short and long-term debt, which was partially offset by an increase in our repayments of short and long-term debt.
Net cash used in investing activities decreased to U.S.$5,519 million in 2003, as compared to U.S.$6,656 million in 2002. This decrease was due primarily to our adoption of FIN 46, which required us to consolidate certain special purpose entities in which we have investment interests.
Short-Term Debt
Our outstanding short-term debt serves mainly to support our imports of crude oil and oil products, and is provided almost completely by international banks and under our commercial paper program. At December 31, 2003, our short-term debt (excluding current portions of long-term obligations) increased to U.S.$1,329 million as compared to U.S.$671 million at December 31, 2002. This increase was due to the inclusion of PEPSA’s short term debt in our consolidated balance sheets and our increased use of short-term credit facilities. Our short-term debt is denominated principally in U.S. dollars.
Long-Term Debt
Our total outstanding consolidated long-term debt consists primarily of the 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.$13,033 million at December 31, 2003, as compared to U.S.$7,714 million at December 31, 2002. Included in these figures at December 31, 2003 are the following international debt issues:
Notes
9.00% Notes due 2004(1)
10.00% Notes due 2006
6.625% Step Down Notes due 2007(1)
9.125% Notes due 2007(2)
9.875% Notes due 2008(2)
6.750% Senior Trust Certificates due 2010(3)
Floating Rate Senior Trust Certificates due 2010(3)
9.750% Notes due 2011(2)
6.600% Senior Trust Certificates due 2011(3)
Floating Rate Senior Trust Certificates due 2013(3)
4.750% Senior Exchangeable Notes due 2007(4)
Global Step-up Notes due 2008(5)
9.125% Global Notes due 2013(6)
8.375% Global Notes due 2018(6)
3.748% Senior Trust Certificates due 2013(3)
6.436% Senior Trust Certificates due 2015(3)
9.375% Notes due 2013(7)
On March 31, 2003, PIFCo 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 registration statement filed with the SEC in July 2002.
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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 exports prepayment program. On July 2, 2003, PIFCo issued Global Notes in an aggregate principal amount of U.S.$500 million due July 2013. The notes bear interest at the rate of 9.125% per annum, payable semiannually. On September 18, 2003, PIFCo issued an additional U.S.$250 million in Global Notes, which form a single fungible series with its U.S.$500 million Global Notes due July 2013. On December 10, 2003 PIFCo issued U.S.$750 million of 8.375% Global notes due 2018.
We describe the average interest rates on our long-term debt in Note 12 to our consolidated financial statements.
In addition to issuing foreign currency denominated debt in the international capital markets, we have historically issued Real denominated debentures in the local capital markets. These debentures are floating-rate obligations, and the coupon is based on an index plus a fixed spread.
We did not issue any Real-denominated debentures in 2003. In 2002, we issued R$1,525 million (U.S.$432 million) in Real-denominated debentures. Outstanding debentures totaled U.S.$928 million at December 31, 2003, as compared to U.S.$688 million at December 31, 2002.
Project Finance
Since 1997, we have utilized project financings to provide capital for our large exploration and production and related projects, including some natural gas processing and transportation systems. All of these projects, and their related debt obligations, are on-balance sheet and accounted for under the line item “Project Financings” until December 31, 2002. At December 31, 2003, the special purpose companies related to these project financings are consolidated in accordance with FIN 46 on a line-by-line basis. Under the contractual arrangements, we are responsible for completing the development of the 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 fully fund the special purpose companies’ debt and return on equity payments. At the end of each financing project, we have the option to purchase the project assets from the special purpose company or, in some cases, acquire control over the special purpose company itself.
During 2003, we made capital expenditures of U.S.$1,316 million (20.1% of our total capital expenditures) in connection with exploration and development projects in the Campos Basin, a number of which are being financed through project financings.
Of the U.S.$1,034 million projected amount of expenditures for project financings in 2004, we expect that approximately U.S.$537 million will be used by our Exploration and Production segment (U.S.$340 million of which will be used in our Barracuda-Caratinga field), U.S.$384 million by our Gas and Energy segment and U.S.$113 million by our other segments.
At December 31, 2003, the long-term portion of project financings becomes due in the following years:
2005
2006
2007
2008
2009 and thereafter
Off Balance Sheet Arrangements
As noted above, all of our project financings are on-balance sheet. At December 31, 2003, we had no off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Uses of Funds
In 2003, we continued to prioritize capital expenditures for the development of crude oil and natural gas production projects through internal investments and through structured undertakings with partners. We invested a total of U.S.$6,551 million in 2003, a 33.4% increase from our investments in 2002. Our increased capital expenditures in 2003 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, including investments in thermoelectric power plants. We spent U.S.$3,658 million (55.8%) in 2003 in our domestic exploration and production activities, which includes our exploration and production segment and our project financings.
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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 2003, 2002 and 2001:
Supply
Gas and Energy
Corporate
On May 14, 2004, we announced our Strategic Plan Petrobras 2015, which contemplates total budgeted capital expenditures of U.S.$53.6 billion in the period from 2004 through 2010, approximately U.S.$46.1 billion of which will be directed towards our activities in Brazil, while U.S.$7.5 billion will be directed to our activities abroad. We expect that the majority of our capital expenditures from 2004 through 2010, approximately U.S.$32.1 billion, will be directed towards exploration and production, of which U.S.$26.2 billion is slated for our activities in Brazil.
Our capital expenditures budget for the year 2004, including our project financings, is U.S.$ 9.4 billion, allocated among each of our business segments as follows: (i) Exploration and Production: U.S.$ 5.0 billion; (ii) Downstream: U.S.$ 1.4 billion; (iii) International: U.S.$ 1.0 billion; (iv) Gas and Energy: U.S.$ 1.1 billion; (v) Distribution: U.S.$ 0.6 billion; and (vi) Corporate: U.S.$ 0.3 billion.
We plan to meet our budgeted capital expenditures primarily through internally generated cash and issuances in the international capital markets. Our actual capital expenditures may vary substantially from the projected numbers set forth above as a result of market conditions and the cost and availability of the necessary funds.
Dividends
On March 29, 2004, our shareholders approved a distribution of dividends of approximately U.S.$1,955 million (U.S.$1.78 per share) based on our financial results and cash available for distribution. The U.S.$1,127 million already distributed to shareholders on February 13, 2004 in the form of interest on capital will be deducted from this amount. The proposed dividend includes an additional U.S.$436 million of interest on capital.
Contractual obligations
The following table summarizes our outstanding contractual obligations at December 31, 2003, excluding employee postretirement benefits, deferred income tax and trade accounts payable.
Payments due by period
(in millions of U.S. dollars)
Contractual Obligations
Long-Term Debt Obligations(1)
Capital (Finance) Lease Obligations(2)
Project Finance Obligations
Operating Lease Obligations
Contract Services Obligations
Purchase Obligations
Risk Management Activities
We are exposed to a number of market risks arising in the normal course of business. We may use derivative and non-derivative instruments to manage these risks. For a description of our risk management activities, see Item 11 “Qualitative and Quantitative Disclosures About Market Risk.”
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Critical Accounting Policies and Estimates
The following discussion describes those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting estimates we make in these contexts require us to make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
The discussion addresses only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are used to help make investment decisions about oil and gas properties. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less then reasonable certainty of recoverability and are classified as either probable or possible. Probable reserves are reserves that are more likely to be recovered than not and possible reserves are less likely to be recovered than not.
The estimation of proved reserves is an ongoing process that takes into account engineering and geological information such as well logs, pressure data and fluid sample core data. Proved reserves can also be divided in two categories: developed and undeveloped. Developed proved reserves are expected to be recovered from existing wells including reserves behind pipe, or when the costs necessary to put them in production are relatively low. For undeveloped proved reserves, significant investments are necessary, including drilling new wells and installing production or transportation facilities.
We use the “successful efforts” method to account for our exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to ensure that commercial quantities of reserves have been found or that additional exploration work is under way or planned in a timeframe reasonable to the Petrobras development cycle and with consideration to ANP timing requirements. Exploratory well costs not meeting either of these tests are charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method because it provides a more timely accounting of the success or failure of our exploration and production activities.
Impact of Oil and Gas Reserves on Depreciation and Depletion
The calculation of unit-of-production depreciation and depletion is a critical accounting estimate that measures the depreciation and depletion of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) asset cost. Proved undeveloped reserves are considered in the amortization of leasehold acquisition costs. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability they are based on estimates that are subject to some variability. This variability may result in net upward or downward revisions of proved reserves in existing fields, as more information becomes available through research and production. We revised our proved reserves in the last three years, decreasing our proved reserves by 665.5 million barrels of oil equivalent in 2003, increasing our proved reserves by 917.4 million barrels of oil equivalent in 2002 and decreasing our proved reserves by 880.8 million barrels of oil equivalent in 2001. 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; such percentage of probables incorporated to cash flows do not exceed past success ratios.
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.
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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
The determination of the expense and liability relating to our pension plan involves the use of judgment in the determination of actuarial assumptions, including future mortality, withdrawal, changes in compensation and discount rate to reflect the time value of money as well as the rate of return on plan assets. These assumptions are reviewed at least annually and may differ materially from actual results due to changing market and economic conditions, regulatory events, judicial rulings, higher or lower withdrawal rates or longer or shorter life spans of plan participants. As of December 31, 2002, we decided to change the assumptions related to the estimate of future mortality, adopting a new mortality table (GAM-71) that more accurately reflects the average life expectancy of our retired employees.
With the assistance of our actuarial consultants, we recently reviewed the basis for estimating the assumed discount rate for our actuarial obligations in light of the recent development of a secondary bond market in Brazil for high-grade long-term government securities. SFAS 87 and subsequent interpretations require that the discount rate reflect the price at which actuarial obligations 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. Applying the precepts of SFAS 87 in historically inflationary environments such as Brazil creates certain issues as the ability for a company to settle a pension obligation at a future point in time may not exist as long-term financial instruments of suitable grade may not exist locally as they do in the United States.
Although Brazilian market interest rates have been stable in recent years, it is not yet prudent to conclude that market interest rates will remain stable. Although SFAS 87 offers limited guidance, we consider it appropriate to use actuarial assumptions which include an estimate of long-term inflation; i.e. nominal rates. Considering the rate of return offered on high-grade long-term government securities (a nominal rate of approximately 9.2% at December 31, 2003) we have decided not to change the discount interest rate that has been used historically, as we believe that this rate is consistent with the requirements of SFAS 87 and subsequent interpretations for measurement of defined benefit obligations. We may adopt different assumptions in the future, however, and any such changes may have a significant impact on the amount of our pension liability and expense.
Litigation, Tax Assessments and Other Contingencies
Claims for substantial amounts have been made against us arising in the normal course of business. We are sometimes held liable for spills and releases of oil products and chemicals from our operating assets. In accordance with the guidance provided by U.S. GAAP, we accrue for these costs when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. 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.
Asset retirement Obligations and Environmental Remediation
Under various contracts, permits and regulations, we have material legal obligations to remove equipment and restore the land or seabed at the end of operations at production sites. Our most significant asset removal obligations involve removal and disposal of offshore oil and gas production facilities worldwide. We accrue the estimated discounted costs of dismantling and removing these facilities at the time of installation of the assets. We also estimate costs for future environmental clean-up and remediation activities based on current information on costs and expected plans for remediation. Estimating asset retirement, removal and environmental remediation costs requires performing complex calculations that necessarily involve significant judgment because our obligations are many years in the future, the contracts and regulations have vague descriptions of what removal and remediation practices and criteria will have to be met when the removal and remediation events actually occur and asset removal technologies and costs are constantly changing, along with political, environmental, safety and public relations considerations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty.
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Impact of New Accounting Standards
SFAS 143
As of January 1, 2003, we adopted SFAS No. 143 - Accounting for Asset Retirement Obligations (“SFAS 143”). The primary impact of SFAS 143 was to change the method of accruing for upstream site restoration costs. These costs were previously accrued ratably over the productive lives of the assets in accordance with SFAS No. 19 – Financial Accounting and Reporting by Oil and Gas Producing Companies (“SFAS 19”). At the end of 2002, the cumulative amount accrued under SFAS 19 was U.S.$1,166 million.
Our provision for abandonment was recognized as a component of accumulated depreciation, depletion and amortization as of December 31, 2002, with no separate provision for abandonment liability being disclosed on the face of the financial statements. Under SFAS 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the related assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations and depreciated over the related useful lives of such assets. Over time, the amounts recognized as liabilities will be accreted for the change in their present value until the related assets are retired or sold.
The cumulative adjustment for the change in accounting principle reported in the first quarter of 2003 was an after-tax income of U.S.$697 million (net of U.S.$359 million deferred income tax effects). The effect of this accounting change on the 2003 balance sheet was a U.S.$1,056 million reduction to the abandonment provision and a U.S.$359 million increase in deferred income tax liabilities. Additionally, the change in accounting principle resulted in a U.S.$16 million increase to property, plant and equipment at original asset acquisition date, with accumulated depreciation through January 1, 2003 of U.S.$9 million on proved developed properties. Further, on January 1, 2003, we established an abandonment liability with respect to proved undeveloped reserves in the amount of U.S.$44 million.
These adjustments are due to the difference in the method of accruing site restoration costs under SFAS 143 compared with the method required by SFAS 19. Under SFAS 19, site restoration costs are accrued on a unit-of-production basis of accounting as the oil and gas are produced. The SFAS 19 method matches the accruals with the revenues generated from production and results in most of the costs being accrued in early field life, when production is at the highest level. Because SFAS 143 requires accretion of the liability as a result of the passage of time using an effective interest method of allocation, a significant portion of costs will be accrued towards the end of field life, when production is at the lowest level. The cumulative income adjustment described above results from reversing the higher liability accumulated under SFAS 19 in order to adjust it to the lower present value amount resulting from transition to SFAS 143. This amount being reversed in transition, which was previously charged to operating earnings under SFAS 19, will again be charged to earnings under SFAS 143 in future years.
For a more detailed description of the impact of the adoption of SFAS 143, see Note 3 to our audited consolidated financial statements.
FIN 46
In January 2003, the FASB issued Interpretation No. 46 (FIN 46) - Consolidation of Variable Interest Entities. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities disclosed by enterprises that do not control them through a majority voting interest. Under FIN 46, entities are required to be consolidated by an enterprise that has a controlling financial interest in such entities when equity investors of that enterprise have significant capital risk, the obligation to absorb the majority of expected losses, or the right to receive the majority of expected returns from such entities. Entities identified with these characteristics are called variable interest entities and the interest that enterprises have in these entities are called variable interests. These interests may derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards to the enterprise with the controlling financing interest in such entities, irrespective of such enterprises’ voting interest in such entities.
We adopted FIN 46 in our 2003 financial statements. Such adoption resulted in the consolidation of a number of special purpose entities related to project financing arrangements in which we had an interest, and which were deemed to be variable interest entities for which we were the primary beneficiary. Prior to adoption of FIN 46, a significant portion of our share of commitments and debt obligations, as well as fixed asset contributions, were related to project financings and already included in the consolidated financial statements as the project financing transactions qualified as capital leases. As a result, adoption of FIN 46 related to the special purpose companies formed in connection with project finance arrangements did not have a significant impact on our financial condition or operating results. While we do not have specific assets set aside and established as collateral for these special purpose entities, we do have certain contractual obligations relating to the debt of the special purpose entities.
We also consolidated three thermoelectric power plants at December 31, 2003 as a result of the adoption of FIN 46. However, as these thermoelectric plants had previously been accounted for as capital leases, their consolidation did not have a material impact on our financial condition or operating results. We also determined that we are the primary beneficiary of three additional thermoelectric plants for which we have certain contractual obligations to bear energy market risk. The effect of the consolidation of these three thermoelectric power plants was an increase in fixed assets of U.S.$ 1,142 million and an increase in liabilities of U.S.$ 1,142 million. Results of operations for these companies will only be consolidated in 2004.
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Research and Development
Since 1966, we have maintained a dedicated research and development facility in Rio de Janeiro, Brazil. As of December 31, 2003, we had 1465 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.$28.5 million in 2003 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, 2003, we had 23 floating production systems in operation (13 semi-submersibles, 8 FPSO and 2 FSO), 18 of which we engineered. We have obtained 85 patents in Brazil and 224 abroad for a significant number of the technologies produced through research and development activities during the three-year period ended December 31, 2003.
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 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).
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. 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.
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.
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Furthermore, our bylaws enable each of (i) minority preferred shareholders that together hold at least 10% of the total capital stock (excluding the controlling shareholders); and (ii) minority common shareholders, to elect one member to our board of directors. Additionally, according to Law No. 10,683 of May 28, 2003, one of the members of the board of directors is appointed by the Minister of Budget and Management. Our bylaws provide that, independently from the exercise of the rights above granted to minority shareholders, the federal government always has the right to appoint the majority of our directors. The maximum term for a director is one year, but re-election is permitted. In accordance with the Brazilian Corporation Law, the shareholders may remove any director from office at any time with or without cause at an extraordinary meeting of shareholders. Following an election of board members under the cumulative vote procedure, the removal of any board member by an extraordinary meeting of shareholders will result in the removal of all the other members, after which new elections shall be held.
We currently have nine directors. The following table sets forth certain information with respect to these directors:
BOARD OF DIRECTORS
Name
Position
Expiration of
Current Term
Business Address
Dilma Vana Rousseff (1)
Esplanada dos
Ministérios, Bloco U, sala 801
70065-900 - Brasília – DF
Jaques Wagner (1)
Antonio Palocci Filho (1)
José Eduardo de Barros Dutra (1)
Gleuber Vieira (1)
Arthur Antonio Sendas (1)
Claudio Luiz da Silva Haddad (1)
Fabio Colletti Barbosa (2)
Jorge Gerdau Johannpeter (3)
Av. Farrapos, 1811
90220-005 - Porto Alegre - RS
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. On January 1, 2003, Mr. Wagner was named Minister of Labor by President Luiz Ignacio Lula da Silva, leaving this position on January 26, 2004, to become Special Secretary to the Council of Economic and Social Development of the Presidency of the Republic. He has also served as: Representative before the Brazilian House of Representatives (1990-2002) and founder and director of the Sindicato dos Trabalhadores na Indústria Química do Estado da Bahia(State of Bahia Chemical Industry Workers’ Union, 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.
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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 Ribeirão Preto (1989-1990). Mr. Palocci has also served as President of the Partido dos Trabalhadores (Workers’ Party) for the State of São Paulo (1997-1998).
José Eduardo de Barros Dutra - Mr. Dutra has been a member of our board of directors since January 3, 2003 and is also a member of the boards of directors of BR, Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. In January 2003, the President of Brazil appointed him our president. He has also served as: Senator of the Republic of Brazil from the State of Sergipe (1995-2003) and President of the Sindicato dos Mineiros do Estado de Sergipe (State of Sergipe Miners Union, 1989-1994). Mr. Dutra has also served as leader of the Workers’ Party (1996-1997) and member of the Workers’ Party National Executive Committee, and has worked as a geologist on various projects.
Gleuber Vieira - Mr. Vieira has been a member of our board of directors since January 3, 2003 and is also a member of the board of directors of BR. Since 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).
Arthur Antonio Sendas - President of the Sendas Group which ranks as the leader among the largest wholly Brazilian-owned companies in the retail sector in the state of Rio de Janeiro. Mr. Sendas is vice-president of the Advisory Council of the Brazilian Supermarkets Association - Abras and for five years represented the private sector on the National Monetary Council; he is president of the Board of Directors and the Executive Board of Sendas S/A., president of Sendas Empreendimentos e Participações Ltda., president of Sendas Agropecuária S/A., president of the Executive Board of Sendas Comércio Exterior S/A., president of the Executive Board of Casa Show S/A., president of the Board of Directors of Sendas Distribuidora S/A. He also sits on the Board of Directors of Cia. Brasileira de Distribuição – Pão de Açúcar and is a member Catholic University of Rio de Janeiro’s Development Council and president of the Board of Directors of the City of Rio de Janeiro Development Agency - Agência Rio. He is a member of the Board of Directors of Petrobras and Petrobras Distribuidora S/A., to which he was elected on March 29 2004.
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 the Federação 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 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
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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
Date of Birth
José Eduardo de Barros Dutra
J. S. Gabrielli de Azevedo
Renato de Souza Duque
Guilherme de Oliveira Estrella
Paulo Roberto Costa
Ildo Luís Sauer
Nestor Cuñat Cerveró
José Eduardo de Barros Dutra - Mr. Dutra has been President of our company since January 3, 2003 and has been a member of our board of directors since January 3, 2003. For biographical information regarding Mr. Dutra, see “-Directors and Senior Management-Our Board of Directors.”
J. S. Gabrielli de Azevedo - Mr. Gabrielli has been our Chief Financial Officer and Investor Relations Officer since January 31, 2003. Currently, Mr. Gabrielli is also a member of the boards of directors of Petrobras Energia Participaciones S.A. and of Petrobras Energia S.A. He holds a Ph.D. in economics from Boston University. He served as dean of the Economic Sciences School of the Federal University of Bahia and superintendent of the Fundação de Apoio a Pesquisa e Extensão (Foundation for Support of Research and Extension - Fapex). He was also a visiting researcher at the London School of Economics and Political Science in 2000 and 2001.
Renato de Souza Duque - Mr. Duque has been our Manager of Corporate Services since January 31, 2003. Currently, Mr. Duque is also a member of the boards of directors of Petrobras Energia Participaciones S.A., Petrobras Energia S.A. and Petrobras Gás S.A. - GASPETRO and Chief Executive Officer of Petrobras Negócios Eletrônicos S.A. He has been at our company since 1978, as a Petroleum Engineer, where he has held several positions, including: Manager of Human Resources for all of our operational units in the Exploration and Production area; Manager of Drilling Operations in the Campos Basin; and Manager of our owned platforms.
Guilherme de Oliveira Estrella - Mr. Estrella has been our Managing Director of Exploration and Production since January 31, 2003. Currently, Mr. Estrella is also a member of the boards of directors and executive boards of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A., and also serves as Chairman of the Board of the Instituto Brasileiro de Petróleo e Gás (Brazilian Oil and Gas Institute). He worked at our company from 1965 until 1994, when he retired as a geologist of our Exploration Department. Before his retirement, he held several other positions, including: General Superintendent (1989-1993); Superintendent of Research and Development for exploration, drilling and production (1985-1989); Head of the Exploration Division (1981-1985); Head of the Organic Geochemistry Sector (1981); Head of the Brazilian East Coast Basin Interpretation Sector of our Exploration Department - DEPEX/RJ (1978-1981); and Exploration Manager of Petrobras Internacional S.A. - BRASPETRO for Iraq (1976-1978). Mr. Estrella has also served as director of the Instituto Brasileiro de Petróleo e Gás.
Paulo Roberto Costa – Mr. Paulo Roberto has been our Director of Refining, Transportation and Marketing since May 14, 2004. Mr. Paulo Roberto graduated in Mechanical Engineering from the Federal University of Paraná in 1976 and specialized in Off-shore Engineering at Petrobras. From 1979 to 1994 he worked on platform installation and production development at the Campos basin in the areas of Engineering, Support Management and as Superintendent of the Southeastern Production Region. In 1995 he was promoted to General Manager of E&P Sul (Southern Brazil Exploration and Production), with responsibility for the Santos and Pelotas basins. In 1996 he became general manager for Logistics in the E&P area. From May 1997 to 1999 he headed up the Gas Segment, responsible for commercialization of natural gas. He was Director of Petrobras Gas S.A.-Gaspetro from May 1999 to December 2000. From January 2001 to April 2003, he was General Manager for Logistics at Petrobras of Natural Gas Segment. He has been Managing Director of TBG-Transportadora Brasileira Gasoduto Bolívia Brasil since April 2003. In May 14, 2004 he was appointed Downstream Director of Petróleo Brasileiro S.A. – Petrobras.
Ildo Luis Sauer - Dr. Sauer has been our Director for Gas and Energy since January 31, 2003. Currently, Dr. Sauer is also a member of the board of Petrobras Energia Participaciones S.A. and Petrobras Energia S.A. He holds a Ph.D. in nuclear engineering from the Massachusetts Institute of Technology. He also holds a MSc degree from COPPE - Federal University of Rio de Janeiro in Energy Planning/Nuclear Power. He is Professor at the Instituto de Eletrotécnica e Energia da Universidade de São Paulo (Electrotechnical and Energy Institute of the University of São Paulo), on leave, where he has published more than 100 technical papers and supervised more than 40 doctoral and master theses in the field. Previously, he has worked as a consultant at TecSauer Consultoria Ltda. and as manager of the nuclear reactor project for the Brazilian Navy.
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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 the Presidência daComercializadora Brasileira de Energia Emergencial (Presidency of the Brazilian Supplier of Emergencial Energy - CBEE) of the Ministry of Mines and Energy.
Compensation
For 2003, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was approximately U.S.$1.2 million.
In addition, the members of the board and the executive officers receive certain additional benefits generally provided to our employees and their families, such as medical assistance, educational expenses and supplementary social security benefits.
We have no service contracts with our directors providing for benefits upon termination of employment. We do have a compensation and succession committee in the form of an advisory committee. See “-Advisory Committees.”
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 May 31, 2004, 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 12 common shares and 510 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.
Fiscal Council
We have established a permanent conselho fiscal, fiscal council, in accordance with applicable provisions of the Brazilian Corporation Law, composed of up to five members. As required by the Brazilian Corporation Law our fiscal council is independent of our management and external auditors. The fiscal council’s responsibilities include, among others: (i) monitoring management’s activities and (ii) reviewing our annual report and financial statements. The members and their respective alternates are elected by the shareholders at the annual general shareholder’s meeting. Holders of preferred shares without voting rights and minority common shareholders are each entitled to elect one member and his respective alternate to the fiscal council. The Brazilian government has the right to appoint the majority of the members of the fiscal council and their alternates. One of these members and his respective alternate are appointed by the Minister of Finance representing the Brazilian Treasury.
The following table lists the current members of the fiscal council:
FISCAL COUNCIL
Year of First Appointment
Eduardo Coutinho Guerra
Denise Maria Ayres de Abreu
Túlio Luiz Zamin
Nelson Rocha Augusto
Maria Lúcia de Oliveira Falcón
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The following table lists the alternate members of the fiscal council:
Claudia Rebello Massa
Osvaldo Peterson Filho
Edison Freitas de Oliveira
Maria Auxiliadora Alves da Silva
Celso Barreto Neto
Because we are not required to satisfy the audit committee requirements of Rule 10A-3 under the Exchange Act until July 31, 2005, the entire board of directors is currently serving as our audit committee for purposes of the Sarbanes-Oxley Act of 2002. As permitted by Rule 10A-3(c)(3) under the Exchange Act, we are considering whether to adopt the fiscal council as an alternative organ to the audit committee for purposes of Rule 10A-3.
Advisory Committees
We also have three advisory committees to our board of directors as follows: Comitê de Auditoria, the audit committee, Comitê de Remuneração e Sucessão, the compensation and succession committee, andComitê de Meio Ambiente, the environmental committee. The committee members are composed exclusively of members of our board of directors.
The audit committee is responsible for, among other things: (1) monitoring and evaluating the activities of the internal and external auditors; (2) supervising the process for preparation of our financial statements; and (3) ensuring that the financial statements comply with applicable legal requirements.
The compensation and succession committee is responsible for, among other things: (1) proposing remuneration packages for members of the board of directors and the executive board; (2) proposing performance targets for members of the executive boards; and (3) evaluating the effectiveness of procedures designed to retain talented employees.
The environmental committee is responsible for, among other things: (1) overseeing and managing environmental and work safety issues affecting us; (2) establishing measurable environmental targets and ensuring compliance; and (3) recommending changes in environmental, health and safety policy, if necessary, to our board of directors.
Employees and Labor Relations
We had 48,798 employees at December 31, 2003, compared to 40,848 at December 31, 2002 and 38,483 at December 31, 2001. The increase in the number of our employees in 2003 is primarily a result of expanding our hiring practices as well as the consolidation of some of our subsidiaries and foreign affiliates, primarily PEPSA. Expenses relating to employees of the parent company amounted to approximately R$3,612 million (U.S.$1,175 million) in 2003, R$3,019 million (U.S.$1,033 million) in 2002 and R$2,966 million (U.S.$1,260 million) in 2001. During 2003, these expenses represented 70% of our consolidated employee expenses. Of the 36,363 employees of the parent company, as of December 31, 2003, 35,339, 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.
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 November 4, 2003, retroactive to September 1, 2003. This collective bargaining agreement will expire on August 31, 2004. A separate collective bargaining agreement was negotiated with the maritime employees’ union in order to replace the last agreement that expired on December 30, 2003. The new agreement was signed on January 30, 2004, retroactive to November 1, 2003, and will expire on October 31, 2004.
Our collective bargaining agreements are subject to renewal on an annual basis. Under the terms of these agreements, we agreed to, among other things:
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.
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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 R$141,256,000 (U.S.$46 million) on employee training in 2003, as compared to U.S.$30 million in 2002. We intend to spend R$170,131,000 (U.S.$59 million) on employee training in 2004.
With the enactment of the Oil Law and the emergence of competitors in the Brazilian oil sector, we have developed a strategic plan to provide incentives to attract new employees and to retain existing ones. We have also implemented a management improvement plan, which will focus on training our management-level employees to enable them to develop the skills necessary to operate in a free-market economy. As part of our employee incentives, we have 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.
Our profit sharing distributions to our employees within the entire Petrobras Group were R$894 million (U.S.$291 million) for 2003, R$444 million (U.S.$152 million) for 2002 and R$416 million (U.S.$168 million) for 2001. At the annual general shareholders’ meeting held on March 29, 2004 our shareholders approved a profit sharing distribution to Petrobras employees (excluding subsidiaries) of R$777 million (U.S.$253 million) for 2003. In January 2004, 40% of this distribution was paid to our employees. The form and timing of the remaining portion is currently being negotiated with representatives of our employees. Our subsidiaries approved profit sharing distributions to their employees of R$117 million (U.S.$38 million) at their annual general shareholders’ meeting in March 2004.
Our Pension and Health Care Plans
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. Employees that participate make mandatory monthly contributions. Our historical funding policy has been to make annual contributions to the plan in the amount determined by actuarial appraisals. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. We made contributions of U.S.$402 million in 2003, as compared to contributions of U.S.$311 million in 2002. We recorded a liability of U.S.$2,055 million in 2003, U.S.$1,452 million in 2002 and U.S.$2,088 million in 2001 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 17 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 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.
On November 23, 2001, the Oil Workers Federation, which represents approximately 96.7% of our workers, filed a lawsuit against the Supplemental Pension Plan Secretariat, seeking to prevent the approval of Petrobras VIDA. An initial judicial decision by a lower court annulled the plan, but that decision will be automatically reviewed by an appeals court. Although some employees had already opted to migrate to the plan, an injunction was granted on January 10, 2002, which resulted in the suspension of the plan and which prevented us from including any employees under this plan. 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.
In 2003, we established a working group to evaluate our current pension system and formulate recommendations for change. The working group is recommending the adoption of a new plan that will be offered to current participants in PETROS and all new employees. The plan is still subject to negotiation with our unionized workers, approval by our board of directors and approval by the Supplemental Pension Plan Secretariat.
We maintain a health care benefit plan (AMS), which offers defined benefits and covers all employees (active and inactive) together with their dependents. We manage the plan, with the employees contributing fixed amounts to cover principal risks and a portion of the costs relating to other types of coverage in accordance with participation tables defined by certain parameters, including salary levels.
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Our commitment related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The health care plan is not funded or otherwise collateralized by assets. Instead, we make benefit payments based on annual costs incurred by plan participants.
The actuarial gains and losses arising from the differences between the actuarial assumptions and the costs effectively incurred are respectively included or excluded when defining the net actuarial liability. These gains and losses are amortized over the average remaining service period of the active employees.
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. At December 31, 2003, there were 634,168,418 outstanding common shares and 462,369,507 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 May 31, 2004 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.
Shareholder
Brazilian government
BNDES Participações S.A.-BNDESPAR
Other Brazilian public sector entities
All directors and executive officers as a Group (15 persons)
In August 2000, the Brazilian government sold 180,609,768 of our common shares, reducing its percentage of ownership of our common shares from 84% to the current 55.7%. In July 2001, BNDES sold 41,381,826 of our preferred shares, which constituted its entire holdings of our shares.
On March 29, 2004 our shareholders approved an increase in our authorized capital from R$30 billion (U.S.$10.2 billion) to R$60 billion (U.S.$20.4 billion).
As of April 30, 2004, approximately 38.9% of our preferred shares and approximately 26.7% of our common shares were held of record in the United States. As of April 30, 2004, we had approximately 179,836,427 record holders of preferred shares, or American Depositary Shares representing preferred shares, and approximately 169,736,554 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
We engage in numerous transactions in the ordinary course of business with our controlling shareholder, the Brazilian government, and with other companies controlled by it.
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As of December 31, 2003, we had a receivable (the Petroleum and Alcohol Account) from the Brazilian government, our controlling shareholder, of U.S.$239 million secured by U.S.$59 million of National Treasury Bonds-Series H issued by the Brazilian government. See Item 4 “Regulation of the Oil and Gas Industry in Brazil-The Petroleum and Alcohol Account.”
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.
At December 31, 2003, PETROS had provided us with U.S.$134 million in project financing loans for the development of the Albacora field.
As of December 31, 2003, we had assets deposited with Banco do Brasil S.A. in the amount of U.S.$6,164 million, of which U.S.$5,973 million corresponded to cash and cash equivalents in Brazil (U.S.$4,340 million) and abroad (U.S.$1,633 million).
For additional information regarding our principal transactions with related parties, see Note 26 to our audited consolidated financial statements.
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. 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, including the proceedings described in Item 4 “Information on the Company-Environmental Liabilities.” See Note 22 to our audited consolidated financial statements. The table below sets forth our recorded financial provisions by type of claim:
PROVISIONS BY TYPE OF CLAIM(1)
Labor claims
Tax claims
Civil claims
Commercial claims and other contingencies
Claims against Petrobras, the parent company, which as of December 31, 2003, corresponded to approximately 25.3% 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.$58.5 million. As of December 31, 2003, 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.$8.1 billion.
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The most significant claims are described below:
On November 23, 1992, Porto Seguro Imóveis Ltda., a minority shareholder of Petroquisa, filed a lawsuit against us in a State Court of Rio de Janeiro for alleged losses suffered as a result of the sale of the share participation held by Petroquisa in various petrochemical companies included in the National Privatization Program (Programa Nacional de Desestatização). The plaintiff in the lawsuit requests that we, as controlling shareholder of Petroquisa, be compelled to reinstate the damages made to Petroquisa’s equity, as a consequence of the corporate acts that approved the minimum sales price attributed to its share participation in the capital of the privatized companies. An initial decision on January 14, 1997 held us liable to Petroquisa for damages in an amount equivalent to U.S.$3.406 billion. Additionally, we were required to pay the plaintiff 5% of the indemnification amount as a premium as well as lawyers’ fees of 20% over that amount. However, since the amount due shall be payable to Petroquisa, and we own 99.0% of Petroquisa’s share capital, the actual disbursement, in case the decision is not dismissed, shall be restricted to 25% of the damages amount, or U.S.$851 million. We appealed and prevailed in canceling the judgment, but a subsequent appellate decision on March 30, 2004 found us liable for U.S.$2.37 billion, plus a 5% premium and 20% of attorney’s fees, all payable to Petroquisa. We will now file appeals to both the Superior Justice Tribunal and to the Federal Supreme Court.
On May 28, 1981, Kallium Mineração S.A. brought an action against Petromisa, our former subsidiary, in the Federal Court of the State of Rio de Janeiro alleging damages of R$1,044 million relating to the rescission of a contract to develop a potassium salt mine. On August 10, 1999, the trial judge dismissed most of the plaintiff’s claims and ordered us to indemnify the plaintiff only with respect to the preliminary research expenses it had incurred. Both parties have appealed the decision. If Kallium prevails on appeal, we would be required to pay an additional amount of 10% of any judgment to cover attorneys’ fees.
Several individuals have filed a lawsuit (an ação popular) against us, Repsol-YPF and the Brazilian government seeking to unwind the 2001 exchange of certain of our operating assets in Brazil for some of YPF’s operating assets in Argentina. The plaintiffs maintain that the assets exchanged were not properly valued and that, therefore, the transaction was not in our best interests. On September 5, 2002, the Fourth Chamber of the Brazilian Federal Court of Appeals for the Fourth Region granted an injunction to the plaintiffs. The Superior Court of Justice of Brazil suspended the injunction, stressing that the transaction had already been approved by the Brazilian antitrust authorities, the ANP and the Brazilian Federal Audit Court. We are awaiting a final disposition on the merits.
We are a defendant in four labor lawsuits filed with two different state labor courts related to our alleged failure to index salaries in accordance with the official inflation rates published by the Brazilian government during the years 1987, 1989 and 1990. The lawsuits are each at different stages of the litigation process.
Certain independent distributors located throughout Brazil have brought civil claims against us. Collectively, these claims total approximately R$821.48 million (U.S.$394 million) and aim at the restitution of the ICMS retained from such distributors and collected by us in favor of many states, plus damages. We believe these taxes were properly collected and represent valid state value-added tax credits. However, in connection with these claims, approximately R$76 million (U.S.$32 million) in injunctive relief was declared against us in various local courts and seized from our accounts in several jurisdictions in anticipation of favorable judgments for the distributors. Upon appeal, these rulings were subsequently overruled, but we are awaiting a final disposition on the merits of these cases.
We received several tax assessments from the INSS alleging irregular presentation of documentation by construction companies and other service providers under contract with us with regard to their INSS contributions. The INSS seeks to hold us jointly and severally liable for contributions not made by these providers. We are analyzing each of the INSS’s assessments in order to attempt to recover payments that we made to the INSS with respect to these tax assessments. In addition, we intend to take action against service providers in order to recover any amounts paid and not recovered from the INSS. Because it is unlikely that we will successfully obtain a reversal of the INSS’s decision through the agency’s administrative procedures, at December 31, 2003, we had a balance of U.S.$95 million in our provision to cover future payments to the INSS.
Federal tax authorities (Delegacia da Receita Federal) have served us with a tax assessment of approximately R$566 million related to a withholding tax (IRRF) that they believe should have been applied in connection with remittances we made abroad between 1999 and 2002. The remittances were related to the purchase of imported oil by Petrobras. According to the federal tax authorities, such remittances corresponded to interest payments, which they believe would give rise to the tax levy they claim. However, the importation documents do not make reference to the alleged interest payments. Petrobras is currently challenging the tax assessment.
On behalf of the special purpose company involved in the U.S.$2.5 billion Barracuda/Caratinga project financing, we had been party to a legal dispute with Halliburton and its subsidiary, Kellogg Brown & Root, Inc., KBR, relating to project construction delays and cost overruns. The total amount of the KBR claims against the project company was approximately U.S.$375 million
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and the total amount of claims that we and the project company had against Halliburton and KBR, in addition to liquidated damages, was approximately U.S.$380 million. In April 2004, we reached a preliminary, non-binding agreement with Halliburton and KBR for settlement of these claims. The agreement, which is still subject to the project lenders’ approval, will release all parties from these claims and would terminate an arbitration proceeding that had been instituted in New York. Additionally, we agreed to extend certain construction deadlines and reduce the scope of the works to be performed by KBR after the oil platforms to be delivered in connection with the project depart their docks.
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 description of existing environmental lawsuits, see Item 4 “Information on the Company-Environmental Liabilities.”
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 Plan.”
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:
Common Shares
Preferred Shares
Common ADSs
Preferred ADSs
We are currently applying for listing of our shares on the Buenos Aires Stock Exchange, but we cannot predict when or whether our application will be approved.
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.
Reais per
Common Share
U.S. dollars per
Average Numberof Common Shares
Traded per Day
1997
1998
2002:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2003:
2004:
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Average Number ofPreferred Shares
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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.
Average Number
of Common Shares
2000:
2001:
of Preferred Shares
Markets
Brazilian securities are traded only on the São Paulo Stock Exchange, with the exception of electronically traded public debt securities. Privatization auctions are conducted on the Rio de Janeiro Stock Exchange.
If you were to trade in our common or preferred shares on the São Paulo Stock Exchange, your trade would settle in three business days after the trade without adjustment of the purchase price for inflation. The seller is ordinarily required to deliver the shares to the exchange on the second business day following the trade date. Delivery of and payment for shares are made through the facilities of the clearinghouse, or Companhia Brasileira de Liquidação e Custódia, known as CBLC.
The São Paulo Stock Exchange is a nonprofit entity owned by its member brokerage firms. Trading on each exchange is limited to member brokerage firms and a number of authorized nonmembers. The São Paulo Stock Exchange has two open outcry trading sessions each day from 11:00 a.m. to 1:30 p.m. and from 2:30 p.m. to 6:00 p.m. Brazil local time, except during daylight savings time in the United States. During daylight savings time in the United States, the sessions are from 10:00 a.m. to 1:00 p.m. and from 2:00 p.m. to 5:00 p.m. Brazil local time, to closely mirror New York Stock Exchange trading hours. Trading is also conducted between 11:00 a.m. and 6:00 p.m., or between 10:00 a.m. and 5:00 p.m. during daylight savings time in the United States on an automated system known as the Sistema de Negociação Assistida por Computador (Computer Assisted Trading System) on the São Paulo Stock Exchange. The São Paulo Stock Exchange also permits trading from 6:30 p.m. to 7:30 p.m. (or
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from 5:45 p.m. to 7:00 p.m. during daylight savings time in the United States) on an online system connected to traditional and internet brokers called the “After Market.” Trading on the After Market is subject to regulatory limits on price volatility and on the volume of shares transacted through internet brokers. There are no specialists or officially recognized market makers for our shares.
In order to better control volatility, the São Paulo Stock Exchange adopted a “circuit breaker” system pursuant to which trading sessions may be suspended for a period of thirty minutes or one hour whenever the indices of these stock exchanges fall below the limits of 10% or 15%, respectively, in relation to the index registered in the previous trading session.
The São Paulo Stock Exchange is less liquid than the New York Stock Exchange or other major exchanges in the world. At December 31, 2003, the aggregate market capitalization of the 412 companies listed on the São Paulo Stock Exchange was approximately U.S.$234.2 billion and the ten largest companies represented approximately 49.4% 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 governmental entities or by one principal shareholder.
Trading on the São Paulo Stock Exchange by a holder not deemed to be domiciled in Brazil for Brazilian tax and regulatory purposes (a “non-Brazilian holder”) is subject to certain limitations under Brazilian foreign investment legislation. With limited exceptions, non-Brazilian holders may only trade on the São Paulo Stock Exchange in accordance with the requirements of Resolution No. 2,689 of January 26, 2000 of the National Monetary Council. Resolution No. 2,689 requires that securities held by non-Brazilian holders be maintained in the custody of, or in deposit accounts with, financial institutions duly authorized by the Central Bank of Brazil and the CVM. In addition, Resolution No. 2,689 requires non-Brazilian holders to restrict their securities trading to transactions on Brazilian stock exchanges or qualified over-the-counter markets. With limited exceptions, non-Brazilian holders may not transfer the ownership of investments made under Resolution No. 2,689 to other non-Brazilian holders through a private transaction. 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 and preferred shares are listed and traded on the São Paulo Stock Exchange and may also be traded privately, subject to some limitations.
To be listed on the São Paulo Stock Exchange, a company must apply for registration with the CVM and the São Paulo Stock Exchange.
We have the option to ask that trading in our securities on the São Paulo Stock Exchange be suspended in anticipation of a material announcement. Trading may also be suspended on the initiative of the São Paulo Stock Exchange or the CVM, among other reasons, based on or due to a belief that a company has provided inadequate information regarding a material event or has provided inadequate responses to the inquiries by the CVM or the São Paulo Stock Exchange.
The Brazilian over-the-counter market consists of direct trades between individuals in which a financial institution registered with the CVM serves as intermediary. No special application, other than registration with the CVM, is necessary for securities of a public company to be traded in this market. The CVM requires that it be given notice of all trades carried out in the Brazilian over-the-counter market by the intermediaries.
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 and preferred shares underlying the ADSs must, on behalf of the depositary for the ADSs, register with the Central Bank of Brazil to remit U.S. dollars abroad for payments of dividends, any other cash distributions or upon the disposition of the shares and sales proceeds. In the event that a holder of ADSs exchanges ADSs for common or preferred shares, the holder will be entitled to continue to rely on the custodian’s registration for
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five business days after the exchange. Thereafter, the holder may not be able to obtain and remit U.S. dollars abroad upon the disposition of the common or preferred shares or distributions relating to the common shares, unless the holder obtains a new registration. See Item 10 “Additional Information-Exchange Controls.”
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 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:
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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 ours, 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.
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 to our shareholders are subject to financial charges at the SELIC rate (an interest rate applicable to certain Brazilian government securities) from the end of each fiscal year through the date we actually pay such dividends. Shareholders have a three-year period from the dividend payment date to claim dividends or interest payments with respect to their shares, after which the amount of the unclaimed dividends reverts to us.
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 and Valor Econômico. The notice must be published no fewer than three times, beginning at least
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15 calendar days prior to the scheduled meeting date. The notice must contain the meeting’s agenda and, in the case of a proposed amendment to the bylaws, an indication of the subject matter. For ADS holders, we are required to provide notice to the ADS depositary at least 30 calendar days prior to a shareholders’ meeting.
The board of directors or, in some specific situations set forth in the Brazilian Corporation Law, the shareholders, call our general shareholders’ meetings. A shareholder may be represented at a general shareholders’ meeting by an attorney-in-fact, so long as the attorney-in-fact was appointed within a year of the meeting. The attorney-in-fact must be a shareholder, a member of our management, a lawyer or a financial institution. The attorney-in-fact’s power of attorney must comply with certain formalities set forth by Brazilian law.
In order for a valid action to be taken at a shareholders’ meeting, shareholders representing at least one quarter of our issued and outstanding common shares must be present at the meeting. However, in the case of a general meeting to amend our bylaws, shareholders representing at least two-thirds of our issued and outstanding common shares must be present. If no such quorum is present, the board may call a second meeting giving at least eight calendar days notice prior to the scheduled meeting in accordance with the rules of publication described above. The quorum requirements will not apply to the second meeting, subject to the voting requirements for certain matters described below.
Voting Rights
Pursuant to the Brazilian Corporation Law and our bylaws, each of our common shares carries the right to vote at a general meeting of shareholders. 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:
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 fiscal council. Preferred shareholders are not entitled to vote on any other matter.
Under Brazilian Corporation Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates. Furthermore, minority common shareholders holding at least 10% of our voting capital also have the right to appoint or dismiss one member to or from our fiscal council.
Preferred shareholders holding, individually or as a group, 10% of our total capital have the right to appoint and/or dismiss one member to or from our board of directors. Preferred shareholders have the right to separately appoint and/or dismiss one member to or from our 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.
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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.
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:
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.
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Any redemption of shares arising out of the exercise of such withdrawal rights would be made based on the book value per share, determined on the basis of the last balance sheet approved by our shareholders. However, if a shareholders’ meeting giving rise to redemption rights occurred more than 60 days after the date of the last approved balance sheet, a shareholder would be entitled to demand that his or her shares be valued on the basis of a new balance sheet dated within 60 days of such shareholders’ meeting. The right of withdrawal lapses 30 days after publication of the minutes of the shareholders’ meeting that approved the corporate actions described above. We would be entitled to reconsider any action giving rise to withdrawal rights within 10 days following the expiration of such rights if the withdrawal of shares of dissenting shareholders would jeopardize our financial stability.
Other Shareholders’ Rights
According to the Brazilian Corporation Law, neither a company’s bylaws nor actions taken at a general meeting of shareholders may deprive a shareholder of some specific rights, such as:
Liquidation
In the event of a liquidation, holders of preferred shares are entitled to receive, prior to any distribution to holders of common shares, an amount equal to the paid-in capital with respect to the preferred shares.
Conversion Rights
According to our bylaws, our common shares are not convertible into preferred shares, nor are preferred shares convertible into common shares.
Liability of Our Shareholders for Further Capital Calls
Neither Brazilian law nor our bylaws provide for capital calls. Our shareholders’ liability for capital calls is limited to the payment of the issue price of the shares subscribed or acquired.
Form and Transfer
Our shares are registered in book-entry form and we have hired Banco 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 fiscal council members and involving the provisions of the Brazilian Corporation Law, our bylaws, the rules of the National Monetary Council, the Central Bank of Brazil and the CVM or any other capital markets legislation, including the provisions of any agreement entered into by us with any stock exchange or over-the-counter entity registered with the CVM, relating to adoption of differentiated corporate governance practices.
However, decisions of the Brazilian government, as exercised through voting in any general shareholders’ meeting, are not subject to this arbitration proceeding, in accordance with Article 238 of the Brazilian Corporation Law.
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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 securities on the São Paulo Stock Exchange without obtaining a separate certificate of registration for each transaction.
In addition, Annex V to Resolution No. 1,289 of the National Monetary Council, as amended, known as Annex V Regulations, allows Brazilian companies to issue depositary receipts in foreign exchange markets. We currently have an ADR program for our common and preferred shares duly registered with the CVM and the Central Bank of Brazil. The proceeds from the sale of ADSs by holders outside Brazil are free of Brazilian foreign investment controls.
Transfer of Control
According to Brazilian law and our bylaws, the Brazilian government is required to own at least the majority of our voting shares. Therefore, any change in our control would require a change in the applicable legislation.
Disclosure of Shareholder Ownership
Brazilian regulations require that any person or group of persons representing the same interest that has directly or indirectly acquired or sold an interest corresponding to 5% of the total number of shares of any type or class must disclose its share ownership or divestment to the CVM and the São Paulo Stock Exchange. In addition, a statement containing the required information must be published in the newspapers. Any subsequent increase or decrease by 5% or more in ownership of shares of any type or class must be similarly disclosed.
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 five auctions conducted thus far, we acquired interests in 56 exploration areas (88 exploration cells were transformed by ANP into 17 exploration blocks in the fifth round of auctions held in 2003). 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.
Exchange Controls
There are no restrictions on ownership of the common or preferred shares by individuals or legal entities domiciled outside Brazil.
The right to convert dividend payments and proceeds from the sale of shares into foreign currency and to remit such amounts outside Brazil may be subject to restrictions under foreign investment legislation which generally requires, among other things, that the relevant investments be registered with the Central Bank of Brazil. If any restrictions are imposed on the remittance of foreign capital abroad, they could hinder or prevent CBLC, as custodian for the common and preferred shares represented by the American Depositary Shares, or registered holders who have exchanged American Depositary Shares for common shares or preferred shares, from converting dividends, distributions or the proceeds from any sale of such common shares or preferred shares, as the case may be, into U.S. dollars and remitting the U.S. dollars abroad.
Foreign investors may register their investment under Law No. 4,131 of September 3, 1962 or Resolution No. 2,689. Registration under Resolution No. 2,689 affords favorable tax treatment to foreign investors who are not resident in a tax haven, as defined by Brazilian tax laws. See “-Brazilian Tax Considerations.”
Under Resolution No. 2,689, foreign investors may invest in almost all financial assets and engage in almost all transactions available in the Brazilian financial and capital markets, provided that certain requirements are fulfilled. In accordance with Resolution No. 2,689, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.
Under Resolution No. 2,689, a foreign investor must:
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.
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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.”
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 securities), from the end of each fiscal year through the date of effective payment of those dividends. These interest payments are considered as fixed-yield income and are subject to withholding income tax at 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
(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
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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, unless such sale or assignment is performed on the stock exchange by an investor under Resolution No. 2,689 who is not resident in a tax haven jurisdiction, in which case the gains are exempt from income tax.
There is no assurance that the current preferential treatment for holders of the ADSs and some non-Brazilian holders of the preferred or common shares under Resolution No. 2,689 will continue in the future.
Taxation of Foreign Exchange Transactions (“IOF/Câmbio”)
Under Decree No. 4,494 of December 3, 2002, the conversion into Brazilian currency of proceeds received by a Brazilian entity from a foreign investment in the Brazilian securities market (including those in connection with an investment in preferred or common shares or the ADSs and those under Resolution No. 2, 689) and the conversion into foreign currency of proceeds received by a non-Brazilian holder is subject to a tax on exchange transactions known as IOF/Câmbio, which is currently applicable at a zero percent rate in most transactions. However, according to Law No. 8,894 of June 21, 1994, the IOF/Câmbio rate may be increased at any time to a maximum of 25% by a decision of the Minister of Finance, but only in relation to exchange transactions carried out after the increase of the applicable rate.
Taxation on Bonds and Securities Transactions (“IOF/Títulos”)
Law No. 8,894 created the Tax on Bonds and Securities Transactions, or IOF/Títulos, which may be imposed on any transactions involving bonds and securities carried out in Brazil, even if these transactions are performed on the Brazilian stock, futures or commodities exchange. As a general rule, the rate of this tax is currently zero but the 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.
Tax on Bank Account Transactions (“CPMF”)
The Contribuição Provisória sobre Movimentação Financeira (Tax on Bank Account Transactions, or CPMF), is imposed on any debit to bank accounts. As a result, transactions by the depositary or by holders of preferred or common shares which involve
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the transfer of Brazilian currency through Brazilian financial institutions are subject to the CPMF tax at a rate of 0.38%. These transactions include situations where a non-Brazilian holder transfers the proceeds from the sale or assignment of preferred or common shares by an exchange transaction, in which case the CPMF tax will be levied on the amount to be remitted abroad in Reais. If we have to perform any exchange transaction in connection with ADSs or preferred or common shares, we will also be subject to the CPMF tax. The financial institution that carries out the relevant financial transaction will be responsible for collecting the applicable CPMF tax.
Beneficiaries Resident or Domiciled in Tax Havens or Low Tax Jurisdictions
Law No. 9,779 of January 1, 1999 states that, except for limited prescribed circumstances, income derived from transactions by a beneficiary, resident or domiciliary of a country considered a tax haven is subject to withholding income tax at the rate of 25%. Tax havens are considered to be countries which do not impose any income tax or which impose such tax at a maximum rate of less than 20%. Accordingly, if the distribution of interest attributed to shareholders’ equity is made to a beneficiary resident or domiciled in a tax haven jurisdiction, the applicable income tax rate will be 25% instead of 15%. Capital gains are not subject to this 25% tax, even if the beneficiary is resident in a tax haven jurisdiction. See “-Taxation of Gains.”
Registered Capital
The amount of an investment in preferred or common shares held by a non-Brazilian holder who obtains registration under Resolution No. 2,689, or by the depositary representing such holder, is eligible for registration with the Central Bank of Brazil; such registration (the amount so registered being called registered capital) allows the remittance outside Brazil of foreign currency, converted at the commercial market rate, acquired with the proceeds of distributions on, and amounts realized with respect to dispositions of, such preferred or common shares. The registered capital for each preferred or common share purchased as part of the international offering or purchased in Brazil after the date hereof, and deposited with the depositary will be equal to its purchase price (in U.S. dollars). The registered capital for a preferred or common share that is withdrawn upon surrender of an ADS will be the U.S. dollar equivalent of:
The U.S. dollar value of the average price of preferred or common shares is determined on the basis of the average of the U.S. dollar/Real commercial market rates quoted by the Central Bank of Brazil information system on that date (or, if the average price of preferred or common shares is determined under the second option above, the average of such average quoted rates on the same 15 dates used to determine the average price of preferred or common shares).
A non-Brazilian holder of preferred or common shares may experience delays in effecting such registration, which may delay remittances abroad. Such a delay may adversely affect the amount, in U.S. dollars, received by the non-Brazilian holder. See Item 3 “Key Information-Risk Factors-Risks Relating to our Equity and Debt Securities.”
U.S. Federal Income Tax Considerations
The statements regarding U.S. tax law set forth below are based on U.S. law as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein. This summary describes the principal tax consequences of the ownership and disposition of common or preferred shares or ADSs, but it does not purport to be a comprehensive description of all of the tax consequences that may be relevant to a decision to hold or dispose of common or preferred shares or ADSs. This summary applies only to purchasers of common or preferred shares or ADSs who will hold the common or preferred shares or ADSs as capital assets and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements), tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common or preferred shares or ADSs on a mark-to-market basis, and persons holding common or preferred shares or ADSs in a hedging transaction or as part of a straddle or conversion transaction.
Each holder should consult such holder’s own tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common or preferred shares or ADSs.
Shares of our preferred stock will be treated as equity for U.S. federal income tax purposes. In general, for purposes of the U.S. Internal Revenue Code of 1986 (the “Code”) a holder of an ADS will be treated as the holder of the shares of common or preferred stock represented by those ADSs, and no gain or loss will be recognized if you exchange an ADS for the shares of common or preferred stock represented by that ADS.
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In this discussion, references to ADSs refer to ADSs with respect to both common and preferred shares, and references to a “U.S. holder” are to a holder of an ADS that:
Taxation of Distributions
A U.S. holder will recognize ordinary dividend income for U.S. federal income tax purposes in an amount equal to the amount of any cash and the value of any property we distribute as a dividend to the extent that such distribution is paid out of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, when such distribution is received by the custodian, or by the U.S. holder in the case of a holder of common or preferred shares. The amount of any distribution will include the amount of Brazilian tax withheld on the amount distributed, and the amount of a distribution paid in Reais will be measured by reference to the exchange rate for converting Reais into U.S. dollars in effect on the date the distribution is received by the custodian, or by a U.S. holder in the case of a holder of common or preferred shares. If the custodian, or U.S. holder in the case of a holder of common or preferred shares, does not convert such Reais into U.S. dollars on the date it receives them, it is possible that the U.S. holder will recognize foreign currency loss or gain, which would be ordinary loss or gain, when the Reais are converted into U.S. dollars. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code. Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by an individual in respect of the shares or ADSs 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 shares or 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 shares or ADSs may be claimed as a credit against the U.S. federal income tax liability of a U.S. holder if such U.S. holder elects for that year to credit all foreign income taxes. Alternatively, such Brazilian withholding tax may be taken as a deduction against taxable income. Foreign tax credits may not be allowed for withholding taxes imposed in respect of certain short-term or hedged positions in securities or in respect of arrangements in which a U.S. holder’s expected economic profit is insubstantial. U.S. holders should consult their own tax advisors concerning the implications of these rules in light of their particular circumstances.
Distributions of additional shares to holders with respect to their shares or 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 shares or ADSs that are treated as dividend income for U.S. federal income tax purposes unless such dividends are effectively connected with the conduct by the holder of a trade or business in the United States.
Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by an individual prior to January 1, 2009 with respect to the ADSs will be subject to taxation at a maximum rate of 15% if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) the Company was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”), foreign personal holding company (“FPHC”) or foreign investment company (“FIC”). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on the Company’s audited financial statements and relevant market and shareholder data, the Company believes that it was not treated as a PFIC, FPHC or FIC for U.S. federal income tax purposes with respect to its 2003 taxable year. In addition, based on the Company’s audited financial statements and its current expectations regarding the value and nature of its assets, the sources and nature of its income, and relevant market and shareholder data, the Company does not anticipate becoming a PFIC, FPHC or FIC for its 2004 taxable year. Based on existing guidance, it is not clear whether dividends received with respect to the shares will be treated as qualified dividends, because the shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs and intermediaries though whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes. Because such procedures have not yet been issued, it is not clear whether the Company will be able to comply with the procedures. Holders of shares and ADSs should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.
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Taxation of Capital Gains
Upon the sale or other disposition of a share or an ADS, a U.S. holder will generally recognize gain or loss for U.S. federal income tax purposes. The amount of the gain or loss will be equal to the difference between the amount realized in consideration for the disposition of the share or the ADS and the U.S. holder’s tax basis in the share or the ADS. Such gain or loss generally will be subject to U.S. federal income tax and will be treated as capital gain or loss. The net amount of long-term capital gain recognized by an individual holder before January 1, 2009 generally is subject to taxation at a maximum rate of 15%. Capital losses may be deducted from taxable income, subject to certain limitations.
A non-U.S. holder will not be subject to U.S. federal income tax or withholding tax on gain realized on the sale or other disposition of a share or an ADS unless:
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 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.
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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 80% of our crude oil requirements in Brazil, we import a substantial amount of crude oil, as well as smaller quantities of diesel, liquefied petroleum gas, naphtha and other oil products. We also export crude oil, bunker fuel, fuel oil and gasoline. Virtually all of the prices for these imports and exports are payable in U.S. dollars even though substantially all our revenues are collected in Reais (despite the fact these prices are partly based on international prices). In addition, a substantial portion of our indebtedness and some of our operating expenses are, and we expect them to continue to be, denominated in or indexed to U.S. dollars or other foreign currencies. See Item 4 “Information on the Company-Regulation of the Oil and Gas Industry in Brazil” for the manner in which the Brazilian government has controlled the prices we charge.
The principal market for our products is Brazil and substantially all of our revenues are denominated in Reais. We have described above under Item 4 “Information on the Company-Regulation of the Oil and Gas Industry in Brazil-Price Regulation” the manner in which the Brazilian government has regulated the prices we charge.
Risk Management
The market risks we face consist principally of commodity price risk, and to a lesser extent, interest rate risk and exchange rate risk.
Our management of risk exposures is evolving under the policies of our executive officers, acting as a group, most of whom have been in office since February 2003. As described below, we enter into contracts, such as energy futures, forwards, puts, swaps and options, designed to hedge against the risk of price changes relating to our imports and exports. Such derivative commodity instruments are used only to offset market exposures resulting from these imports and exports, and are not used for trading purposes. 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 22 our audited consolidated financial statements.
By using derivative instruments, we expose ourselves to credit and market risk. Credit risk is the failure of a counterparty to perform under the terms of the derivative contract. Market risk is the adverse effect on the value of a financial instrument that results from a favorable change in interest rates, currency exchange rates or commodity prices. We address credit risk by restricting the counterparties to such derivative financial instrument to major financial institutions. Our executive officers manage market risk.
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.
PEPSA also uses derivative instruments such as options, swaps and others, mainly to mitigate the impact of changes in crude oil prices, interest rates and future exchange rates. Such derivative instruments are designed to mitigate specific exposures, and are assessed periodically to assure high correlation of the derivative instrument to the risk exposure identified and to assure that the derivative is highly effective in offsetting changes in cash flows inherent in the covered risk. PEPSA qualifies for hedge accounting treatment for its crude oil derivative instruments and its interest rate swap derivative instruments.
Commodity Price Risk
Our sales of crude oil and oil products are based on international prices, thus exposing us to price fluctuations in the international markets.
In order to mitigate the impact of such fluctuations, we have entered into derivative transactions, primarily futures contracts, options and swaps. Our futures contracts provide economic hedges for anticipated crude oil purchases and sales, generally forecast to occur within a 30- to 360-day period. Our exposure on these contracts is limited to the difference between contract value and market value on the volumes hedged.
For 2003, we carried out derivative transactions on 72.5% of our total trade volume, as compared to 42.0% of our total trade volume for 2002 and 21.2% of our total trade volume for 2001. This increase in our derivative transactions is a result of normal fluctuations in our operations. The open positions on the futures market, compared to spot market value, resulted in recognized losses of U.S.$2 million in 2003, U.S.$4 million in 2002 and U.S.$6 million in 2001.
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In January of 2001, we sold put options for 52 million barrels of West Texas Intermediate oil over a period from 2004 to 2007. We executed the transaction in order to protect the quantity of oil from price fluctuations and provide the institutions financing the Barracuda/Caratinga project with a minimum guaranteed margin to cover debt servicing. The puts were structured to guarantee a minimum return on investment for the institutions financing the project. The value of our position with respect to this put option resulted in recognized net gain of U.S.$7 million at December 31, 2003, U.S.$8 million at December 31, 2002 and U.S.$5 million at December 31, 2001.
International hedging activities in 2003 represented an average of 564,000 barrels of oil equivalent per day of physical movements, of which 20.0% was related to fuel oil, 20.8% was related to diesel, 21.2% was related to gasoline and 38.0% was related to crude oil, as compared to our international hedging activities in 2002 which represented an average of 379,000 barrels of oil equivalent per day of physical movements, of which 43.5% was related to fuel oil, 13.3% was related to gasoline, 28.0% was related to diesel and 7.3% was related to crude oil. This increase in our international derivative transactions was a result of normal fluctuations in our operations.
PEPSA consummated commodity derivative transactions, referenced to WTI, for 40% of its total sales volume (corresponding to 11,963 thousand boe) at December 31, 2003. The operations settled in the year generated a loss in the approximate amount of U.S.$67 million. At December 31, 2003, the open positions on the futures market, when compared to their market value, represented a negative result of approximately U.S.$187 million, if liquidated on that date. These transactions were accounted for as cash flow hedges in accordance with SFAS No. 133—Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”).
Interest Rate and Exchange Rate Risk
The interest rate risk to which we are exposed is a function of our long-term debt and, to a lesser extent, our short-term debt. Our long-term debt consists principally of notes and borrowings incurred primarily in connection with capital expenditures and investments in exploration and development projects and loans to affiliated companies. Approximately 90% 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 12 to our audited consolidated financial statements.
We currently do not utilize derivative instruments to manage our exposure to interest rate fluctuation. We have been considering various forms of derivatives to reduce our exposure to interest rate fluctuations and may utilize these financial instruments in the future.
PEPSA holds an interest rate contract to manage the volatility of the LIBOR rate implied in a Class C negotiable instrument, establishing the respective interest rate at 7.93% annually. If this instrument were to be liquidated, considering the rates used at the date, a net loss of approximately U.S.$6 million would be recorded. This contract qualifies for hedge accounting in accordance with SFAS 133.
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 2003 and 2002. Total debt portfolio includes long-term debt, capital leases, project financings, and current portions thereof, and short-term debt.
Real denominated
o/w fixed rate
o/w floating rate
Dollar denominated
o/w floating rate (includes short-term debt)
Other currencies (primarily Yen)
Floating Rate Debt
Foreign Currency Denominated
Fixed Rated Debt
111
U.S. dollars
Euro
Japanese Yen
British Pounds
Brazilian Reais
Argentine Pesos
The table below provides information about our total debt obligations as of December 31, 2003, 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, 2003:
Fair Value
as of
Debt in British Pounds:
Variable rate debt
Average interest rate
Debt in EURO:
Fixed rate debt
Debt in Japanese Yen:
Debt in U.S. dollars:
Debt in Brazilian Reais:
Debt in Argentine Pesos:
Total debt obligations
In 2000, we entered into three zero-cost foreign exchange collars (combined put and call options) to reduce our exposure to variations with a notional amount of approximately U.S.$470 million between the U.S. dollar and the Japanese Yen exchange rate, and between the U.S. dollar and Euro exchange rate. These collars establish a ceiling and a floor for the associated exchange rates. If the exchange rate falls below the defined floor, the counterparty will pay to us the difference between the actual rate and the floor rate on the notional amount. Conversely, if the exchange rate increases above the defined ceiling, we will pay to the counterparty the difference between the actual rate and the ceiling rate on the notional amount. We do not account for these derivative contracts as hedge derivative instruments.
The Yen zero-cost collar contracts expired on September 8, 2003, and were settled by a cash payment of U.S.$68 million.
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The table below provides information about our zero-cost foreign exchange collars by contract. The table presents the notional amount of the related debt obligation, the floor and ceiling rates, the fair values of the put and call options and the expiration date of each contract.
Austrian
Schilling
Italian
Lira
Notional amount of debt (U.S.$ in millions)
Contractual rates(1)
Interest payments
Floor
Ceiling
Final principal payments
Fair value as of December 31, 2003 (U.S.$ in millions)
Put Option
Call Option
Expiration date
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, and increased to 2.0% in 2002. During 2003, the average monthly rate of inflation decreased to 0.6%. 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 before decreasing to 7.7% in 2003.
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
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 as of December 31, 2003. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures as of December 31, 2003 were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required.
There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT
Our board of directors currently serves as our audit committee for purposes of the Sarbanes-Oxley Act of 2002. Our board of directors has reviewed the qualifications and backgrounds of its members and determined that board members Fabio Colleti Barbosa and Dilma Vana Rousseff are audit committee financial experts within the meaning of this Item 16A.
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ITEM 16B. CODE OF ETHICS
We have adopted a Code of Ethics applicable to our employees and a Code of Good Practices applicable to our directors and executive officers. No waivers of the provisions of the Code of Ethics or Code of Good Practices are permitted. Both documents are available on Petrobras’ website: www.petrobras.com.br/investor relations/corporate governance.
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Principal Accountant Fees
Audit and Non-Audit Fees
The following table sets forth the fees billed to us by our independent auditors, Pricewaterhouse Coopers Auditores Independentes in 2002 and from January to March of 2003, and Ernst & Young Auditores Independentes S/S from March 2003 until December 31, 2003, during the fiscal years ended December 31, 2002 and 2003:
Audit fees
Audit-related fees
Tax fees
Other fees
Total fees
Audit fees in the above table are the aggregate fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S in connection with the audit of our annual financial statements (U.S. GAAP and Brazilian GAAP), interim reviews (U.S. GAAP and Brazilian GAAP), subsidiary audits (U.S. GAAP and Brazilian GAAP, among others) and review of periodic documents filed with the SEC.
Audit-related fees in the above table are the aggregate fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S for assurance and related services with due diligence, our shelf registration with the SEC and attest services that are not required by statute or regulation.
Tax fees in the above table are fees billed by Pricewaterhouse Coopers Auditores Independentes and Ernst & Young Auditores Independentes S/S for services related to tax planning and tax advice.
Other fees in the above table are fees billed by Pricewaterhouse Coopers Auditores Independentes primarily related to services rendered with respect to environmental liabilities, the PEGASO program, the Pipeline Integrity Program, and to a lesser degree, our Strategic Plan, organizational structure and data processing services.
Audit Committee Approval Policies and Procedures
Since we do not have an audit committee, our board of directors performs those functions. Our board of directors has not established pre-approval policies and procedures for the engagement of our independent auditors for services. Our board of directors expressly approves on a case-by-case basis any engagement of our independent auditors for all services provided to our subsidiaries or to us. Our bylaws prohibit our independent auditors from providing any consulting services to our subsidiaries or to us.
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
Description
Amended and Restated Second Supplemental Indenture, initially dated as of July 2, 2003, as amended and restated as of September 18, 2003, between Petrobras International Finance Company (PIFCo) and JPMorgan Chase Bank, as Trustee, relating to the 9.125% Global Notes due 2013.
Third Supplemental Indenture, dated as of December 10, 2003, between Petrobras International Finance Company (PIFCo) and JPMorgan Chase Bank, as Trustee, relating to the 8.375% Global Notes due 2018.
The amount of long-term debt securities of Petrobras authorized under any given instrument does not exceed 10% of its total assets on a consolidated basis. Petrobras hereby agrees to furnish to the SEC, upon its request, a copy of any instrument defining the rights of holders of its long-term debt or of its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed.
115
Unless the context indicates otherwise, the following terms have the meanings shown below:
116
Bbl
Bcf
Boe
Bpd
Cf
Km
Km2
Mbbl
Mboe
Mbpd
Mcf
MMbbl
MMboe
MMcf
MMcmd
MMcfpd
MMscfd
m3
1 barrel
1 domestic barrel of oil equivalent
1 international barrel of oil equivalent
1 cubic meter of natural gas
1 Km
1 Km2
1 ton of crude oil
1 meter
117
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 30, 2004.
Petróleo Brasileiro S.A. - PETROBRAS
By:
/s/ JOSÉ EDUARDO DE BARROS DUTRA
Name:
José Eduardo De Barros Dutra
Title:
Chief Executive Officer
/s/ JOSÉ SÉRGIO GABRIELLI DE AZEVEDO
José Sérgio Gabrielli de Azevedo
Chief Financial Officer
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INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statement of Income for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2003, 2002 and 2001
Notes to the Consolidated Financial Statements
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CONSOLIDATED FINANCIAL STATEMENTS
PETRÓLEO BRASILEIRO
S.A. - PETROBRAS AND
SUBSIDIARIES
December 31, 2003, 2002 and 2001, together
With Report of Independent Registered Public Accounting Firm
PETRÓLEO BRASILEIRO S.A. – PETROBRAS
AND SUBSIDIARIES
Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PETRÓLEO BRASILEIRO S.A. - PETROBRAS:
We have audited the accompanying consolidated balance sheet of PETRÓLEO BRASILEIRO S.A. - PETROBRAS and subsidiaries as of December 31, 2003, and the related consolidated statements of income, shareholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PETRÓLEO BRASILEIRO S.A. - PETROBRAS and subsidiaries at December 31, 2003, and the consolidated results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
Effective January 1, 2003, the Company adopted SFAS No. 143 - Accounting for Asset Retirement Obligations (“SFAS 143”). Additionally, at December 31, 2003 the Company adopted FIN 46 “Consolidation of Variable Interest Entities” as discussed in Note 3.
ERNST & YOUNG
Auditores Independentes S/S
Paulo José Machado
Partner
Rio de Janeiro, Brazil
February 13, 2004
F-1
CONSOLIDATED BALANCE SHEETS
December 31, 2003, and 2002
Expressed in Millions of United States Dollars
Current assets
Cash and cash equivalents (Note 5)
Accounts receivable, net (Note 7)
Inventories (Note 8)
Deferred income tax (Note 4)
Property, plant and equipment, net (Note 9)
Investments in non-consolidated companies and other investments (Note 10)
Other assets
Petroleum and alcohol account – receivable from Federal Government (Note 11)
Government securities (Note 6)
Unrecognized pension obligation (Note 17)
Restricted deposits for legal proceedings and guarantees (Note 22 (a))
Goodwill in PEPSA and PELSA (Note 19)
Investment in PEPSA and PELSA (Note 19)
F-2
Liabilities and shareholders’ equity
Current liabilities
Income tax
Taxes payable, other than income taxes
Short-term debt (Note 12)
Current portion of long-term debt (Note 12)
Current portion of project financings (Note 14)
Current portion of capital lease obligations (Note 15)
Accrued interest
Dividends and interest on capital payable (Note 18)
Contingencies (Note 22)
Ventures under consortium agreements
Employee benefits obligation - Pension (Note 17)
Other payables and accruals
Long-term liabilities
Long-term debt (Note 12)
Project financings (Note 14)
Employee benefits obligation - Health care (Note 17)
Capital lease obligations (Note 15)
Provision for abandonment of wells (Note 3 (a))
Thermoelectric liabilities (Note 3 (b))
Shares authorized and issued (Note 18)
Preferred share - 2003 - 462,369,507 shares (2002 - 451,935,669 shares)
Common share - 2003 and 2002 - 634,168,418 shares
Capital reserve (Note 18)
Retained earnings
Appropriated (Note 18)
Unappropriated
Accumulated other comprehensive income
Cumulative translation adjustments
Amounts not recognized as net periodic pension cost, net of tax (Note 17)
Unrealized gains (losses) on securities, net of tax
Total liabilities and shareholders’ equity
F-3
CONSOLIDATED STATEMENTS OF INCOME
December 31, 2003, 2002 and 2001
Expressed in Millions of United States Dollars (except number of shares and earnings per share)
Less:
Contribution of intervention in the economic domain charge - CIDE
Specific parcel price - PPE
Impairment (Note 9 (b))
Equity in results of non-consolidated companies (Note 10)
Financial income (Note 13)
Financial expense (Note 13)
Monetary and exchange variation on monetary assets and liabilities, net (Note 13)
Loss on government securities (Note 6)
Income before income taxes and minority interest and accounting change
F-4
Income tax expense (Note 4)
Cumulative effect of change in accounting principle, net of taxes
Net income applicable to each class of shares
Basic and diluted earnings per share (Note 18 (b))
Common/ADS and Preferred/ADS
Before effect of change in accounting principle
After effect of change in accounting principle
Weighted average number of shares outstanding
F-5
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities
Adjustments to reconcile net income to net cash provided by operating activities
Dry hole costs
Loss on property, plant and equipment
Loss on government securities
Minority interest in loss (income) of subsidiaries
Deferred income taxes
Foreign exchange and monetary loss (gain)
Accretion expense – asset retirement obligation
Provision for uncollectible accounts
Gain on exchange of businesses with Repsol-YPF
Equity in the results of non-consolidated companies
Decrease (increase) in assets
Petroleum and Alcohol Account
Interest receivable on government securities
Increase (decrease) in liabilities
Employee postretirement benefits, net of unrecognized pension obligation
Risk management activities
Contingencies
Abandonment
Net cash provided by operating activities
F-6
Cash flows from investing activities
Additions to property, plant and equipment
Investment in Perez Companc S.A - PEPSA
Investments in thermoelectric plants
Investment in non-consolidated companies
Dividends received from non-consolidated companies
Restricted deposits for legal proceedings
Effect on cash from merger with subsidiaries and affiliates
Effect on cash of FIN 46 adoption
Net cash used in investing activities
Cash flows from financing activities
Short-term debt, net issuances and repayments
Proceeds from issuance of long-term debt
Principal payments on long-term debt
Project financing funding (payments)
Payment of finance lease obligations
Dividends paid to shareholders
Dividends paid to minority interests
Net cash provided by (used) in financing activities
Increase (decrease) in cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplemental cash flow information:
Cash paid during the year for
Interest
Income taxes
Withholding income tax on financial investments
Non-cash investing and financing transactions during the year
Project finance expenditures funded by special purpose companies
Net assets acquired in purchased business combination with Repsol-YPF
Transfer of Government securities to PETROS
Consolidation of merchant type thermoelectrics
Exchange of BR shares for PETROBRAS preferred shares
Recognition of asset retirement obligation – FAS 143
F-7
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Expressed in Millions of United States Dollars (except per-share amounts)
Balance at January 1
Capital increase with issue of preferred shares
Capital increase with undistributed earnings reserve
Balance at December 31
Transfer from (to) unappropriated retained earnings
Change in the year
(Increase) decrease in additional minimum liability
Tax effect on above
F-8
Unrealized gains (losses)
Legal reserve
Transfer from (to) unappropriated retained earnings, net of gain or loss on translation
Unrealized income reserve
Undistributed earnings reserve
Capital increase
Transfer from unappropriated retained earnings, net of gain or loss on translation
F-9
Statutory reserve
Total appropriated retained earnings
Dividends (per share: 2003 - US$ 1.49 to common and preferred shares; 2002 - US$ 1.19 to common and preferred shares; 2001 - US$ 1.62 to common and preferred shares)
Appropriation (to) from fiscal incentive reserve
Appropriation to reserves
Total shareholders’ equity
Amounts not recognized as net periodic pension cost
Unrealized gain on available-for-sale securities
Total comprehensive income (loss)
F-10
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(except when specifically indicated)
1. The Company and its operations
PETRÓLEO BRASILEIRO S.A. - PETROBRAS is Brazil’s national oil company and, directly or through its subsidiaries (collectively, “PETROBRAS” or the “Company”), is engaged in the exploration, exploitation and production of oil from reservoir wells, shale and other rocks, and in the refining, processing, trade and transport of oil and oil derivatives, natural gas and other fluid hydrocarbons, in addition to other energy related activities. Additionally, PETROBRAS may promote the research, development, production, transport, distribution and marketing of all sectors of energy, as well as other related or similar activities.
PETROBRAS was incorporated under Law No. 2,004 on October 3, 1953. Until November of 1995, PETROBRAS was the exclusive agent of the Brazilian Federal Government (the “Federal Government”) for purposes of exploiting the Federal Government’s constitutional and statutory control over activities involving exploration, production, refining, distribution, import, export, marketing and transportation of hydrocarbons and oil products in Brazil and its continental waters. When adopted in 1953, the relevant provisions of the Brazilian constitution and statutory law gave the Federal Government a monopoly in these areas subject only to the right of companies then engaged in oil refining and the distribution of oil and oil products to continue those activities in Brazil. Therefore, except for limited competition from those companies in their grandfathered activities, PETROBRAS had a monopoly over its businesses for approximately 42 years. As a result of a change in the Brazilian constitution in November of 1995, and the subsequent and ongoing implementation of that change, PETROBRAS has ceased to be the Federal Government’s exclusive agent in Brazil’s hydrocarbons sector and up to 2001 had been operating in an environment of gradual deregulation and increasing competition.
In accordance with Law No. 9,478 (“Petroleum Law”) and Law No. 9,990, dated August 6, 1997 and July 21, 2000, respectively, the fuel market in Brazil was totally liberalized beginning January 1, 2002 permitting other companies to produce and sell on the domestic market, and also to import and export oil products.
The Company also has oil and gas operations in international locations, with the most significant international operations being in other Latin American countries.
F-11
2. Summary of significant accounting policies
In preparing these consolidated financial statements, the Company has followed accounting policies that are in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The preparation of these financial statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto.
Estimates adopted by management include: oil and gas reserves, pension and health care liabilities, environmental obligations, depreciation, depletion and amortization, abandonment costs, contingencies and income taxes. While the Company uses its best estimates and judgments, actual results could differ from those estimates as future confirming events occur.
The accompanying consolidated financial statements of PETRÓLEO BRASILEIRO S.A. - PETROBRAS (the Company) have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) and the rules and regulations of the Securities and Exchange Commission (SEC). U.S. GAAP differs in certain respects from Brazilian accounting practice as applied by PETROBRAS in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the Brazilian Securities Commission (CVM).
The U.S. dollar amounts for the years presented have been translated from the Brazilian Real amounts in accordance with Statement of Financial Accounting Standards SFAS No. 52 - Foreign Currency Translation (“SFAS 52”) as applicable to entities operating in non-hyperinflationary economies. Transactions occurring in foreign currencies are first remeasured to the Brazilian Real and then translated to the U.S. dollar, with remeasurement gains and losses being recognized in the statements of income. While PETROBRAS has selected the U.S. Dollar as its reporting currency, the functional currency of PETROBRAS is the Brazilian Real.
F-12
2. Summary of significant accounting policies—Continued
The Company has translated all assets and liabilities into U.S. dollars at the current exchange rate (R$ 2.8892 and R$ 3.5333 to US$ 1.00 at December 31, 2003 and 2002, respectively), and all accounts in the statements of income and cash flows (including amounts relative to local currency indexation and exchange variances on assets and liabilities denominated in foreign currency) at the average rates prevailing during the year. The net translation gain/ (loss) in the amount of US$ 2,856 in 2003 (2002 - US$ (5,452) and 2001 - US$ (2,695)) resulting from this remeasurement process was excluded from income and presented as a cumulative translation adjustment (“CTA”) within Other Comprehensive Income in the statement of changes in shareholders’ equity.
The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries in which (a) the Company directly or indirectly has either a majority of the equity of the subsidiary or otherwise has management control, or (b) the Company has determined itself to be the primary beneficiary of a variable interest entity in accordance with FIN 46 (Note 3(b)). Intercompany accounts and transactions are eliminated.
F-13
The following majority-owned subsidiaries and variable interest entities are consolidated:
Subsidiary companies
Activity
Petrobras Química S.A. - PETROQUISA
Petrochemical
Petrobras Distribuidora S.A. - BR
BRASPETRO Oil Services Company - BRASOIL
International operations
BRASPETRO Oil Company - BOC
PIB - Petrobras Internacional - BRASPETRO B.V. (1)
Petrobras Energia Ltda.
Energy
Petrobras Negócios Eletrônicos S.A.
Petrobras Gás S.A. - GASPETRO
Gas transportation
Petrobras International Finance Company - PIFCO
Petrobras Transporte S.A. - TRANSPETRO
Downstream Participações S.A.
Refining and distribution
Petrobras Netherlands BV
Explorations and Production
UTE Nova Piratininga Ltda.
TERMOR Participações S.A.
TERMORIO S. A. (3)
TERMOBAHIA Ltda. (3)
Ibiritermo S. A. (3)
EVM Leasing Co. (2)
Companhia Petrolifera Marlim (2)
NovaMarlim Petroleo S.A. (2)
Nova Transportadora do Sudeste S.A.(2)
Nova Transportadora do Nordeste S.A.(2)
Barracuda e Caratinga Holding Company B.V. (2)
Cayman Cabiunas Investments Co. Ltda. (2)
Langstrand Holdings S.A.(2)
Albacora Japan Petroleum Limited Company (2)
Companhia de Recuperação Secundaria (2)
PDET ONSHORE S.A. (2)
MPX Termoceará Ltda. (4)
SFE - Sociedade Fluminense de Energia Ltda. (4)
Consórcio Macaé Merchant (4)
F-14
Cash equivalents consist of highly liquid investments that are readily convertible into cash and have an original maturity of three months or less at date of acquisition.
Accounts receivable is stated at estimated realizable values. An allowance for doubtful accounts is provided in an amount considered by management to be sufficient to meet probable future losses related to uncollectible accounts.
Inventories are stated as follows:
F-15
NOTES TO THE CONSOLIDATED FINANCIAL INFORMATION
F-16
The Company uses the equity method of accounting for all long-term investments for which it owns between 20% and 50% of the investee’s outstanding voting stock or has the ability to exercise significant influence over operating and financial policies of the investee. The equity method requires periodic adjustments to the investment account to recognize the Company’s proportionate share in the investee’s results, reduced by receipt of investee’s dividends.
The Company holds National Treasury Bonds “Series B” (NTN-B) issued by the Federal Government which are accounted for as available-for-sale securities in accordance with SFAS No. 115 - Accounting for Certain Investments in Debt and Equity Securities (“SFAS 115”). The Company has maintained junior trust notes received in connection with the structured finance program as held-to-maturity, and additionally has certain available-for-sale investments in companies with publically traded shares.
The successful efforts method of accounting is used for oil and gas exploration, development and production activities.
Costs of acquiring developed or undeveloped leaseholds including lease bonus, brokerage, and other fees are capitalized. The costs of undeveloped properties that become productive are transferred to a producing property account.
F-17
Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to assure that commercial quantities of reserves have been found or that additional exploration work is underway or planned. Exploratory costs related to areas where commercial quantities have been found are capitalized, and exploratory costs where additional work is underway or planned continue to be capitalized pending final evaluation. Exploratory well costs not meeting either of these tests are charged to expense. All other exploratory costs (including geological and geophysical costs) are expensed as incurred. Exploratory dry holes are expensed.
Costs of development wells including dry holes, platforms, well equipment and attendant production facilities are capitalized.
Costs incurred with producing wells are expensed as incurred.
Through December 31, 2002, the Company recorded abandonment costs in accordance with SFAS No. 19 - Financial Accounting and Reporting by Oil and Gas Production Companies (“SFAS 19”). Under SFAS 19, the estimated costs of dismantlement and removal of oil and gas related facilities are accrued over the properties’ production lives using the unit-of-production method and recognized as accumulated depreciation, depletion and amortization as the expense is recorded. Effective January 1, 2003, the Company adopted SFAS 143 for abandonment costs (see Note 3(a) for information related to the new accounting policy for abandonment costs commencing from January 1, 2003).
F-18
Depreciation, depletion and amortization of leasehold costs of producing properties are recorded using the unit-of-production method applied on a field by field basis as a ratio of proved reserves produced. Leased production platforms are depreciated on a straight-line basis over the estimated useful lives of the platforms. Depreciation, depletion and amortization of all other capitalized costs (both tangible and intangible) of proved oil and gas producing properties are recorded using the unit-of-production method applied on a field by field basis as a ratio of proved developed reserves produced. Prior to January 1, 2003, estimated dismantlement, restoration and abandonment costs and estimated salvage values are taken into account in determining amortization and depreciation provisions.
Other plant and equipment are depreciated on a straight-line basis over the following estimated useful lives:
Building and improvements
Equipment and other assets
Platforms
In accordance with SFAS No. 144 - Impairment of Long-Lived Assets (“SFAS 144”), management reviews long-lived assets, primarily property, plant and equipment to be used in the business and capitalized costs relating to oil and gas producing activities, whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable on the bases of undiscounted future cash flows. The reviews are carried out at the lowest level of assets to which the Company is able to attribute identifiable future cash flows. The net book value of the underlying assets is adjusted to their fair value using a discounted future cash flows model, if the sum of the expected undiscounted future cash flows is less than the book value.
F-19
F-20
The actual costs of major maintenance, including turnarounds at refineries and vessels, as well as other expenditures for maintenance and repairs, are expensed as incurred.
Interest is capitalized in accordance with SFAS No. 34 - Capitalization of Interest Cost (“SFAS 34”). Interest is capitalized on specific projects when a construction process involves considerable time and involves major capital expenditures. Capitalized interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. Interest is capitalized at the Company’s weighted average cost of borrowings.
Revenues from sales of crude oil and oil products, petrochemical products and others are recognized on an accrual basis when the title is transferred to the customer. Revenues from sales of natural gas are accounted for when the natural gas is transferred to the customer. Subsequent adjustments to revenue based on production sharing agreements or volumetric delivery differences are not significant. Costs and expenses are accounted for on an accrual basis.
The Company accounts for income taxes in accordance with SFAS No. 109 - Accounting for Income Taxes (“SFAS 109”), which requires an asset and liability approach to recording current and deferred taxes. The effects of differences between the tax bases of assets and liabilities and the amounts recognized in the financial statements have been treated as temporary differences for the purpose of recording deferred income taxes.
F-21
PETROBRAS records the tax benefit of all net operating losses as a deferred tax asset and recognizes a valuation allowance for any part of this benefit which management believes that will not be recovered against future taxable income using a “more likely than not” criterion.
The Company sponsors a contributory defined-benefit pension plan covering substantially all of its employees, which is accounted for by the Company in accordance with SFAS No. 87 - Employers’ Accounting for Pensions (“SFAS 87”).
In addition, the Company provides certain health care benefits for retired employees and its dependents. The cost of such benefits is recognized in accordance with SFAS No. 106 - Postretirement Benefits Other Than Pensions (“SFAS 106”).
The Company also contributes to the national pension, social security and redundancy plans at rates based on payroll, and such contributions are expensed as incurred. Further indemnities may be payable upon involuntary severance of employees but, based on current operating plans, management does not believe that any amounts payable under this plan will be significant.
Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether such costs are expected to provide future economic benefits. Liabilities are recognized when the costs are considered probable and can be reasonably estimated.
F-22
As provided in the Petroleum Law, the fuel market in Brazil was totally liberalized as of January 1, 2002 permitting other companies to produce and sell on the domestic market and, also, import and export oil products. Additionally, as of January 1, 2002, PETROBRAS is no longer required to charge the prices established by the Federal Government on the sale of oil products, and the realization price is no longer established by a formula adjusted to the international market. Therefore the specific parcial price (Parcela de Preço Específico - PPE) is no longer collected.
Considering the liberation of the market and current legislation, as from January 1, 2002, the Petroleum and Alcohol Account will no longer be used to reimburse expenses related to the supply of oil products and fuel alcohol to PETROBRAS and third parties. The movements in the account during 2002 relate only to (i) payments and adjustments mandated by the Agência Nacional do Petróleo - ANP (“ANP”) with no impact on the income statement and (ii) adjustments resulting from the audit of the account by the ANP.
The impact of Federal Government regulation on the Company’s balance sheet and operating structure has been recorded in the Petroleum and Alcohol Account as of, and for the years ended, December 31, 2003, 2002 and 2001 (see Note 11). The impact of this regulation is recorded in the income statement to correspond with underlying transactions when compliance with applicable law has occurred and collection is reasonably assured.
The Contribuição de Intervenção no Dominio Econômico (Contribution of Intervention in the Economic Domain Charge - CIDE) on the importation and sale of fuels was established by Law No. 10,336 dated December 19, 2001.
F-23
The CIDE is a per-transaction payment to the Brazilian Government required to be made by producers, blenders and importers upon sales and purchases of specified oil and fuel products at a set amount for different products based on the unit of measurement typically used for such products.
The Company’s income statement for the year ended December 31, 2001 were impacted by Federal Government regulation in the amount of US$ 1,066.
The liability for future compensation of employees for vacations is accrued as earned.
Earnings per share are computed using the two-class method, which is an earnings allocation formula that determines earnings per share for both preferred shares, which are participating securities and common shares. The preferred shares participate in dividends and undistributed earnings with the common shares at a predetermined formula. Such formula allocates the net income, as if all of the net income for each year had been distributed, first to the preferred shares in an amount equal to the preferred shares’ priority minimum annual dividend of the higher of 3% of their shareholders equity or 5% of their paid-in capital as stated in the statutory accounting records, then to common shares in an amount equal to the preferred shares’ priority dividend on a per share basis and any remaining net income is allocated equally to the common and preferred shares. Each American Depositary Share (ADS) for common shares represent one share of the Company’s common shares or one share of the Company’s preferred shares and, in each case, is presented together with earnings per share.
Research and development costs are charged to expense when incurred.
F-24
The Company adopted SFAS No. 133 – Accounting for Derivative Instruments and Headging Activities (“SFAS 133”), as amended by SFAS No. 137 – Accounting for Derivative Instruments and Headging Activities – Deferral of the Efective Date of SFAS No. 133 (“SFAS 137”) and SFAS No. 138 – Accounting for Certain Derivative Instruments and Certain Headging Activities (“SFAS 138”), on January 1, 2001. SFAS 133 requires that all derivative instruments be recorded in the balance sheet of the Company as either an asset or a liability measured at fair value. SFAS 133 requires that changes in the derivative’s fair value be recognized in earnings/losses unless specific hedge accounting criteria is met. For derivatives accounted for as hedges, fair value adjustments are recorded to earnings/losses or other comprehensive income, a component of shareholders’ equity, depending upon the type of hedge and the degree of hedge effectiveness. The Company has determined that none of its derivative financial instruments that had been previously treated as hedges qualified for hedge accounting under the new standard. The net-of-tax cumulative-effect recorded on January 1, 2001 to recognize the Company’s derivative financial instruments were not significant.
The Company may use derivative financial instruments to mitigate the risk of unfavorable price movements on crude oil purchases. These instruments are marked-to-market on a current basis and associated gains and losses are recognized currently in the income statement.
The Company may also use derivative financial instruments to mitigate the risk of unfavorable exchange-rate movements affecting its foreign currency-denominated indebtedness. Gains and losses from changes in the fair value of these contracts are recognized in income currently, in the same line item as foreign exchange gains and losses arising on the Company’s outstanding debt balance.
F-25
PEPSA also uses derivative instruments such as swaps, options, futures, and other instruments, principally to mitigate the impact of changes in crude oil prices, exchange rates and interest rates. PEPSA’s crude oil derivative instruments and interest rate swap instruments are designed to mitigate specific exposures and thus qualify as cash flow hedges under SFAS 133. As cash flow hedges, the gains and losses associated with the derivative instrument are deferred and recorded in other comprehensive income until the underlying hedge transaction impacts earnings, with the exception of any ineffective portions. Derivative instruments not qualifying for hedge accounting are marked-to-market through earning on a current basis.
EITF Issue 86-12, “Accounting by Insureds for Claims-Made Insurance Policies”, EITF Issue 03-3, “Accounting for Claims-Made Insurance Policies by the Insured Entity”, and EITF Abstracts Topic D-79, “Accounting for Retroactive Insurance Contracts Purchased by Entities Other than Insurance Enterprises”, address various aspects of the accounting for retroactive insurance contracts and claims-made insurance policies by the insured entity. EITF Issue 03-8 finished discussion in November of 2003 and has the purpose to codify the guidance set forth in the aforementioned pronouncements. The Company contracts claims made insurance policies on a prospective basis only and records provisions, as applicable, for all probable losses that may result under SFAS No. 5 - Accounting for Contingencies (“SFAS 5”).
Certain prior years’ amounts have been reclassified to conform with the current year’s presentation. These reclassifications had no impact on the Company’s net income or shareholders’ equity.
F-26
3. Accounting change
As of January 1, 2003, PETROBRAS adopted SFAS No. 143 - Accounting for Asset Retirement Obligations (“SFAS 143”). The primary impact of SFAS 143 is to change the method of accruing for upstream site restoration costs. These costs were previously accrued ratably over the productive lives of the assets in accordance with SFAS No. 19 - Financial Accounting and Reporting by Oil and Gas Producing Companies (“SFAS 19”). At the end of 2002, the cumulative amount accrued under SFAS 19 was US$ 1,166.
This provision for abandonment was recognized as a component of accumulated depreciation, depletion and amortization as of December 31, 2002, with no separate provision for abandonment liability being disclosed on the face of the financial statements. Under SFAS 143, the fair value of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the related assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations and depreciated over the related useful lives of such assets. Over time, the amounts recognized as liabilities will be accreted for the change in their present value until the related assets are retired or sold.
The cumulative adjustment for the change in accounting principle reported in the first quarter of 2003 was an after-tax income of US$ 697 (net of US$ 359 deferred income tax effects). The effect of this accounting change on the balance sheet, was a US$ 1,056 reduction to the abandonment provision, and a US$ 359 increase in deferred income tax liabilities, see Note 4. Additionally, the change in accounting principle resulted in a US$ 16 increase to property, plant and equipment at original asset acquisition date, with accumulated depreciation through January 1, 2003 of US$ 9 on proved developed properties. Further, on January 1, 2003, PETROBRAS established an abandonment liability with respect to proved undeveloped reserves in the amount of US$ 44.
F-27
3. Accounting change—Continued
This adjustment is due to the difference in the method of accruing site restoration costs under SFAS 143 compared with the method required by SFAS 19. Under SFAS 19, site restoration costs are accrued on a unit-of-production basis of accounting as the oil and gas are produced. The SFAS 19 method matches the accruals with the revenues generated from production and results in most of the costs being accrued in early field life, when production is at the highest level. Because SFAS 143 requires accretion of the liability as a result of the passage of time using an effective interest method of allocation, a significant portion of costs will be accrued towards the end of field life, when production is at the lowest level. The cumulative income adjustment described above results from reversing the higher liability accumulated under SFAS 19 in order to adjust it to the lower present value amount resulting from transition to SFAS 143. This amount being reversed in transition, which was previously charged to operating earnings under SFAS 19, will again be charged to earnings under SFAS 143 in future years.
Measurement of assets retirement obligations is based on currently enacted laws and regulations, existing technology and site-specific costs. There are no assets legally restricted to be used in the settlement of asset retirement obligations.
A summary of the annual changes in the abandonement provision are presented as follows:
Balance as of December 31, 2002
Reversion of provision
Assets related to proved developed property
Accumulated depreciation
Assets related to proved undeveloped property
Balance as of January 1, 2003
PEPSA acquisition
Depreciation and impairment
Accretion expenses
Liabilities incurred
Liabilities settled
Cumulative translation adjustment
Balance as of December 31, 2003
F-28
The following unaudited pro-forma financial information presents the asset retirement obligation as if FAS 143 adoption had occurred at January 1, 2001 using current rates and assumptions.
Beginning balance as of January 1, 2001
Reversal of provision
Asset retirement obligation balances at January 1, 2001
Depreciation
Actualization of provision, at net present value
Cummulative translation adjustment
Balance as of December 31, 2001
The following unaudited pro-forma summary financial information presents the consolidated results of operations as if the adoption of FAS 143 had occurred at the beginning of the periods presented.
Impairment
Income tax expense
Cummulative effect of change in accounting principle, net of tax
Basic and diluted earnings per share
F-29
The Financial Accounting Standards Board (FASB) issued Interpretation No. 46 (FIN 46) - Consolidation of Variable Interest Entities in January of 2003. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities disclosed by enterprises that do not control them through a majority voting interest. Under FIN 46, entities are required to be consolidated by an enterprise that has a controlling financial interest in such entities when equity investors of that enterprise do not have significant capital risk, the obligation to absorb the majority of expected losses, or the right to receive the majority of expected returns from such entities. Entities identified with these characteristics are called variable interest entities and the interest that enterprises have in these entities are called variable interests. These interests may derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards to the enterprise with the controlling financing interest in such entities, irrespective of such enterprises’ voting interest in such entities.
The interpretation requires that if a business enterprise has a controlling financial interest in a variable entity, the assets, liabilities and results of the activities of the variable interest entity must be included in the consolidated financial statements with those of the business enterprise. This interpretation applies immediately to variable interest entities created after January 31, 2003. For variable interest entities created before February 1, 2003, FIN 46 must be adopted in the first reporting period ending after December 15, 2003.
The Company adopted FIN 46 in its December 31, 2003 annual financial statements. Such adoption resulted in the consolidation of a number of special purpose entities related to project financing arrangements in which the Company has an interest, and which were deemed to be variable interest entities for which the Company was the primary beneficiary. These entities are detailed above in Note 2 (b). Prior to adoption of FIN 46, a significant portion of the Company’s share of commitments and debt obligations, as well as fixed asset contributions, were already included in the consolidated financial statements as the project financing transactions qualified as capital leases.
F-30
Thus, adoption of FIN 46 related to the special purpose companies formed in connection with project finance arrangements did not have a significant impact on the Company’s financial condition. While PETROBRAS does not have specific assets set aside and established as collateral for these special purpose entities, the Company does have certain contractual obligations relating to the debt of the special purpose entities.
Three thermoelectric plants were also consolidated at December 31, 2003 as a result of the adoption of FIN 46. However, as these thermoelectric plants had previously been accounted for as capital leases, their consolidation did not have a material impact on the Company’s financial condition.
Furthermore, PETROBRAS has determined that it is the primary beneficiary of three additional plants for which it has certain contractual obligations to bear energy market risk. The effect of the consolidation of these three thermoelectrics was an increase in fixed assets of US$ 1,142 and an increase in liabilities of US$ 1,142. Results of operations for these companies will only be consolidated in 2004.
EITF 01-08 “Determining Whether an Arrangement Contains a Lease,” expands former guidance respective to determination of whether an arrangement contains a lease that is within the scope of SFAS No. 13 - Accounting for Leases, (“SFAS 13”) and offers specific guidance related to transportation and other energy contracts that may qualify as leases. Adoption of this EITF in 2003 did not have a significant impact on the Company’s accounting for its energy and transportation contracts.
PETROBRAS has adopted the presentation outlined in EITF 02-6 - Classification in the Statement of Cash Flows of Payments made to Settle an Asset Retirement Obligation within the Scope of SFAS 143, with immaterial changes to prior classification of such costs as investment activities.
F-31
4. Income taxes
Income taxes in Brazil comprise federal income tax and social contribution, which is an additional federal income tax. The statutorily enacted tax rates applicable in the years are presented as follows:
Federal income tax rate
Social contribution
Composite tax rate
During 2001, the Company recognized a benefit in the amount of US$ 111, relating to the reversal of a tax provision established in previous years in connection with the privatization of certain affiliates of PETROQUISA included in the National Privatization Program (PND) due to expiration of the statute of limitations.
Also during 2001, certain changes were introduced in the Brazilian tax legislation, including a requirement that earnings from foreign subsidiaries be included in the determination of current taxes payable in Brazil. As a result, the Company recorded a provision of US$ 100 relating to income taxes on its foreign subsidiaries undistributed taxable income generated since 1996.
F-32
4. Income taxes—Continued
Substantially all of the Company’s taxable income is generated in Brazil and is therefore subject to the Brazilian statutory tax rate. The following table reconciles the tax calculated based upon statutory tax rates to the income tax expense recorded in this consolidated financial statements.
Income before income taxes, minority interest and accounting changes
Tax expense at statutory rates
Adjustments to derive effective tax rate:
Reversal of income tax
Non-deductible postretirement health-benefits
Tax on unremitted earnings of foreign subsidiaries
Foreign income subject to different tax rates
Change in valuation allowance
Tax benefit on interest on shareholders’ equity
Income taxes regarding abandonment liabilities adjustments related to the year ended December 31, 2002
Income tax expense per consolidated statement of income
TBG, a subsidiary of GASPETRO, has accumulated tax loss and negative income tax and social contribution carryforwards amounting to US$ 469 (US$ 768 in 2002) as of December 31, 2003, which could be offset against future taxable income to a limit of 30% of annual income, based on Law No. 9,249/95, which in the opinion of the TBG management, will occur within the useful life of the Bolivia-Brazil Gas Pipeline project.
However, considering the long estimated term for utilization, these tax credits, totaling US$ 159 (US$ 239 - 2002), were provided for in a valuation allowance in the consolidated financial statements for December 31, 2003 and 2002. The accounting recognition of these credits is reviewed annually.
F-33
The major components of the deferred income tax accounts in the consolidated balance sheet are as follows:
Lease obligations
Provision for profit sharing
Provision for loss on Energy
Provision for INSS
Other temporary differences
Employees’ post-retirement benefits, net of unrecognized pension obligation
Deferred assets
Tax loss carryforwards
Investments
Project financing
Provision for notification from INSS
Valuation allowance
Capitalized exploration and development costs
Property, plant and equipment
Net long-term deferred tax liabilities
As a result of the NTN-P swap transaction in 2001, described in Note 6, the income tax on interest on government securities held-to-maturity, which payment had been deferred, became payable and the corresponding provision for income tax and social contribution was transferred to current liabilities on December 28, 2001.
F-34
Although realization of net deferred tax assets is not assured, management believes that, except where a valuation allowance has been provided, such realization is more likely than not to occur. The amount of the deferred tax asset considered realizable could, however, be reduced if estimates of future taxable income are reduced. Tax loss carryforwards do not expire and are available for offset against future taxable income, limited to 30% of taxable income in any individual year. The following presents the changes in the valuation allowance for the years ended December 31, 2003, 2002 and 2001:
Balance at January 1,
Reductions (additions)
Balance at December 31,
5. Cash and cash equivalents
Cash
Investments - local currency
Investments - U.S. dollars
Cash includes US$ 1,049 at December 31, 2003, as a result of incorporation of certain special purpose entities pursuant to the FIN 46 consolidation. See Note 12 relating to repurchased securities held in an exclusive fund.
F-35
6. Government securities
On December 28, 2001, PETROBRAS entered into a contract with the Federal Government to exchange the restricted National Treasury Bonds “Series P” (NTN-P) for unrestricted National Treasury Notes - Series B (NTN-B) with a face value of US$ 3,239. The NTN-P had previously been accounted for as held-to-maturity securities. The NTN-B were created on July 4, 2001 by means of Federal Decree No. 3,859. The exchange was accounted for at fair value and a loss of US$ 1,099 was recorded in the results of operations for 2001. The NTN-B were classified as available-for-sale, and on December 28, 2001, the Company transferred NTN-B notes with a fair value of US$ 1,475 to PETROS, the Company’s current pension plan for employees (see Note 17) to increase pension assets.
On December 30, 2002, the Company effectively transferred a portion of the NTN-B with a fair value of US$ 388 to PETROS to further increase plan assets.
The Company has retained title to NTN-B amounting to US$ 283 as of December 31, 2003 (US$ 176 as of December 31, 2002). These bonds have been advanced to PETROS and the Company intends to utilize them to provide incentives for participants to migrate from the PETROS Plan to the PETROBRAS VIDA, the Company’s new pension plan for employees (see Note 17). Accordingly, as the Company still has the risks and rewards relating to the bonds, they are accounted for as securities available-for-sale and their corresponding earnings will be recorded on an amortized cost basis, with changes in fair value presented in the statement of shareholders’ equity as a component of other comprehensive income.
The NTN - B are denominated in reais, earn interest at 6% annually plus the variation of the IPCA (Consumer Price Index - Adjusted) and mature in 2031.
F-36
7. Accounts receivable, net
Accounts receivable consisted of the following:
Trade
Related parties (Note 26)
Less: allowance for uncollectible accounts
Less: long-term accounts receivable, net
Current accounts receivable, net
Allowance for uncollectible accounts
Additions
Write-offs
Allowance on short-term receivables
Allowance on long-term receivables
F-37
7. Accounts receivable, net—Continued
At December 31, 2003 and 2002, long-term receivables include US$ 581 and US$ 569 respectively relating to payments made by the Company to suppliers and subcontractors on behalf of certain contractors. These contractors had been hired by the subsidiary BRASOIL for the construction/conversion of vessels into FPSO (“Floating Production, Storage and Offloading”) and FSO (“Floating, Storage and Offloading”) and failed to make the payments to their suppliers and subcontractors. The Company made the payments to avoid further delays in the construction/conversion of the vessels and consequent losses to BRASOIL.
Based on opinions from the legal advisers of BRASOIL, these payments can be reimbursed, since they represent a right of BRASOIL with respect to the contractors, for which reason judicial action was filed with international courts to seek financial reimbursement. However, as a result of the uncertainties with regards to the probability of receiving all the amounts disbursed, the Company recorded a provision for uncollectible accounts for all credits that are not backed by collateral. The balances of this provision amounted US$ 509 and US$ 497 as of December 31, 2003 and 2002.
The Company prevailed in the lawsuit filed with an American court by the insurance companies Fidelity & Guaranty Company and American Home Assurance Company, which had attempted to obtain, since 1997, a legal ruling in the United States to exempt the insurance companies from the obligation to pay the sum insured for the construction of platforms P-19 and P-31. As a result of a court decision by the first level of the Federal District Court of the Southern District of New York, the Company was entitled to receive losses and damages in the amount of US$ 237, plus interest and reimbursement of legal expenses through the settlement date. This decision is pending appeal to the Appeals Court of the State of New York, and therefore the Company has not recognized this amount in the financial statements.
F-38
8. Inventories
Products
Oil products
Raw materials, mainly crude oil
Materials and supplies
At December 31, 2003 and 2002, there were no inventories requiring an obsolescence provision.
9. Property, plant and equipment, net
(a) Composition of balance
Property, plant and equipment, at cost, are summarized as follows:
Accumulated
depreciation
Buildings and improvements
Oil and gas assets
Capital lease – platforms, vessels and thermoeletric plants
Rights and concessions
Land
Materials
Expansion projects -
Construction and installations in progress:
Exploration and production
During 2003, the Company capitalized US$ 184 of interest cost (2002 - US$ 139; 2001 - US$ 123).
F-39
F-40
9. Property, plant and equipment—Continued
The property, plant and equipment account at December 31, 2003 and 2002, respectively, includes US$ 678 and US$ 292 of assets under construction that are intended to be sold or transferred into structured financing deals. These assets include natural gas pipelines and other oil and gas projects at 2003, and thermoelectric plants, natural gas pipelines and other oil and gas projects at 2002. Additionally, the property, plant and equipment account at December 31, 2003 and 2002, respectively, includes US$ 978 and US$ 653 of assets under agreements with investors.
The property, plant and equipment balance at December 31, 2003, includes US$ 5,775 of assets consolidated as a result of the adoption of FIN 46. Of this amount, US$ 3,718 was previously included in the property, plant and equipment balance at December 31, 2002 for special purpose project financing entities and certain thermoelectric plants accounted for as capital leases. The increase to property, plant and equipment resulting from the adoption of FIN 46 is related to the consolidation of three thermoelectric plants which were previously only recognized as guarantees; see Note 16.
For the years ended December 31, 2003, 2002 and 2001, the Company recorded impairment charges of US$ 70, US$ 75 and US$ 145, respectively. During 2003, US$ 65 of the impairment charge was related to producing properties in Brazil, principle amounts were related to the Company’s Fazenda Belem on-shore field (US$ 15) in Rio Grande do Norte, and the Lamarão on-shore field (US$ 4) in Bahia. During 2002, US$ 75 of the impairment charge was related to producing properties in Brazil, primarily recorded in the Company’s Voador field (US$ 42) in the Campos basin, Caravelas field (US$ 15) in the Santos basin and Massape field (US$ 4) in the Reconcavo basin.
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During 2001, US$ 129 of the impairment charge was related to producing properties in Brazil and was primarily recorded in the Company’s Voador field (US$ 88) in the Campos basin and Caravelas field (US$ 30) in the Santos basin. The remaining US$ 16 were recorded in the international segment primarily in the Company’s Upia field (US$13) located in Colombia. These charges were recorded based upon the Company’s annual assessment of the fields using pricing and other assuptions consistent with those used in the Company’s overall strategic plan.
During 2003, PETROBRAS returned to the ANP the rights to over twenty two exploratory concessions where it had not made any oil or gas discoveries.
Thus, total concessions returned are as follows: 113 (one hundred and thirteen) of the 115 (one hundred and fifteen) concessions granted to the Company on August 6, 1998; 2 (two) of the 5 (five) exploratory concessions areas acquired under the “BID 1” in June of 1999; and 50% of the original areas related to 8 (eight) exploratory concession areas acquired under the “BID 2”, in June of 2000.
The Company acquired 88 (eighty-eight) new exploratory concessions of the 908 (nine hundred and eight) blocks offered by ANP in the 5th bid for exploratory blocks held in August of 2003. The Company has exclusive rights over 85 (eighty-five) of these concessions and the other 3 (three) were acquired under a consortium. The Company is not the operator of the consortium. The costs incurred by the Company in subscription bonus totaled US$ 7.
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10. Investments in non-consolidated companies and other investments
PETROBRAS conducts portions of its business through investments in companies accounted for using the equity and cost methods. These non-consolidated companies are primarily engaged in the petrochemicals and products transportation businesses.
Equity method
Investments available-for-sale
Investments at cost
During 2003, the Company acquired PEPSA and PELSA (see Note 19), that hold interests in other companies that are recorded according to equity method or at cost. The balance of those investments as of December 31, 2003 amounted to US$ 401 of which US$ 348 was recorded using the equity method. Those companies operate mainly in exploration and production, refining, transport and commercialization, electricity generation, transmission and distribution, and petrochemicals.
At December 31, 2003 and 2002, the Company had investments in companies with publicly traded shares: BRASKEM S.A., Petroquimica União S.A. - PQU and Companhia Petroquimica do Sul S.A. - COPESUL. The Company’s investments in these companies with publicly traded shares amounts to less than 20% of the investee’s total voting shares, are classified as available for sale and have been recorded at market value. The Company has recorded unrealized gains (losses) for the difference between the fair value and the cost of the investment on these investments of US$ 207 and US$ (16) as of December 31, 2003 and 2002, repectively. These holding (losses) gains are reflected as a component of shareholder’s equity, net of tax, with changes in the unrealized balance recorded as a component of comprehensive income.
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10. Investments in non-consolidated companies and other investments—Continued
The Company also has investments in companies for the purpose of developing, constructing, operating, maintaining and exploring thermoelectric plants included in the federal government’s Priority Thermoelectric Energy Program, with equity interests of between 10% and 50%. The balance of the investments as of December 31, 2003 and 2002 includes US$ 46 and US$ 38 respectively, and are included as equity method investments due to the Company’s ability to influence such operations.
The Company’s investment in equity of non-consolidated companies generated equity gains (losses) in results of non-consolidated companies of US$ 141 for the year ended December 31, 2003 (2002 - US$ (178); 2001 - US$ (8)).
11. Receivable from Federal Government
In accordance with the Petroleum Law and subsequent legislation, the fuel market in Brazil was deregulated in its entirety as of January 1, 2002. Therefore, as of that date, the Petroleum and Alcohol account would no longer be used to reimburse expenses in connection with the Federal Government’s regulation of the prices of oil products and fuel alcohol. Accordingly, the Petroleum and Alcohol account will only include changes in amounts with triggering events having occurred before December 31, 2001, in accordance with Law No. 10,453, of May 13, 2002, and ANP regulations. See additional discussion at Note 2 respective to market regulation in Brazil and the effect of such on the historical financial statements.
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11. Receivable from Federal Government—Continued
The following summarizes the changes in the Petroleum and Alcohol Account for the years ended December 31, 2003 and 2002:
Advances (collections) - PPE
Reimbursements to third parties: principally subsidies paid to fuel alcohol producers
Result of audit conducted by the Federal Government
Translation gain (loss)
The Federal Government certified the balance of the Petroleum and Alcohol Account as of June 30, 1998.
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. The results of the audit will be the basis for the settlement of the account with the Federal Government.
The settlement of the account with the Federal Government should have been completed by December 31, 2002, according to the provisions of Law No. 10,453 of May 13, 2002, amended by Decree No. 4,491 of November 29, 2002. On June 26, 2003 Provisional Measure 123, article 11, which was converted to Law No. 10,742 dated October 6, 2003, extended the term of settlement of accounts involving reciprocal debits and credits between PETROBRAS and the Federal Government to June 30, 2004, and in so doing, automatically extending the term for certification of the outstanding balance in the Petroleum and Alcohol Account.
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On June 30, 1998, the Company and the Federal Government reached an agreement whereby the Federal Government issued National Treasury Bonds - H (NTN-H) into a federal depositary on behalf of the Company to support the balance of the Petroleum and Alcohol account. On June 27, 2003, the National Treasury Secretary issued Administrative Instruction 348, authorizing the cancellation of 138,791 NTN-H, which expired on June 30, 2003 and were held in guarantee of payment of an outstanding balance in the Petroleum and Alcohol Account and the issue of new 138,791 NTN-H, with the same terms as the cancelled bonds but expiring on June 30, 2004. The value of the outstanding bonds at December 31, 2003 was US$ 59, at which time the balance of the Petroleum and Alcohol Account was US$ 239. The legal, valid, and binding nature of the account is not affected by any difference between the balance of the account and the value of the outstanding bonds.
The Brazilian Government, upon the Company’s consent, can effect the cancellation of all or a portion of the bonds’ outstanding balance. The NTN-H will mature on June 30, 2004 and currently PETROBRAS has no other rights on those bonds; withdrawal or transfers are not allowed.
12. Financings
The Company’s short-term borrowings are principally sourced from commercial banks and include import and export financing denominated in United States dollars, as follows:
Import - oil and equipment
Working capital
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12. Financings—Continued
The weighted average annual interest rates on outstanding short-term borrowings were 3.79 % and 3.86% at December 31, 2003 and 2002, respectively.
Foreign currency
Financial institutions
Sale of future receivables
Suppliers’ credits
Senior exchangeable notes
Repurchased securities (1)
Local currency
Debentures
National Economic and Social Development Bank - BNDES (state-owned company, see Note 26)
Debentures (state-owned company, see Note 26)
Total (2)
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Currencies
United States dollars
EURO
The long-term portion at December 31, 2003 becomes due in the following years:
As of December 31, 2003, US$ 1,923 was related to PEPSA’s.
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Interest rates on long-term debt were as follows:
6% or less
Over 6% to 8%
Over 8% to 10%
Over 10% to 15%
On March 31, 2003, the Company issued Global Step-up Notes in an aggregate principal amount of US$ 400 due April of 2008. The notes will bear interest from March 31, 2003 at a rate of 9.00% per annum until April 1, 2006 and at a rate of 12.375% per annum thereafter, with interest payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt.
On July 2, 2003, the Company issued Global Notes in an aggregate principal amount of US$ 500 due July of 2013. The notes will bear interest at the rate of 9.125% per annum, payable semiannually. On September 18, 2003, the Company issued an additional US$ 250 in Global Notes, which form a single fungible series with the Company’s US$ 500 Global Notes due July of 2013. The Company used the proceeds from these issuances principally to repay trade-related debt.
On December 10, 2003, the Company issued Global Notes in an aggregate principal amount of US$ 750 due December of 2018. The notes will bear interest at the rate of 8.375% per annum, payable semiannually. The Company used the proceeds from this issuance principally to repay trade-related debt.
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On October 24, 2003, Petrobras Energía S.A. issued US$ 100 notes - Series R, with a 9.375% annual coupon payable semiannually, and a 9.5% annual yield to maturity, and due date of 2013.
Respective to the Senior and Junior Notes issued pursuant to the structured finance program, PETROBRAS and Petrobras Finance Ltd. - PFL have certain contracts (Master Export Contract and Prepayment Agreement) between themselves and special purpose entity not related to PETROBRAS, PF Export Receivables Master Trust (“PF Export”), relating to the prepayment of export receivables to be generated by PFL by means of sales on the international market of fuel oil and other products acquired from PETROBRAS.
As stipulated in the contracts, PFL assigned the rights to future receivables in the amount of US$ 1,800 (1st and 2nd tranches) to PF Export, which, in turn, issued and delivered to PFL the following securities, also in the amount of US$ 1,800:
The assignment of rights to future export receivables represents a liability of PFL, which will be settled by the transfer of the receivables to PF Export as and when they are generated. This liability will bear interest on the same basis as the Senior and Junior Trust Certificates, as described above.
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In May of 2003, the PF Export Trust issued to the Company additional US$ 750 in Senior Trust Certificates and US$ 150 in Junior Trust Certificates. The Senior Trust Certificates consist of Series 2003-A of US$ 550 bearing annual interest of 6.436% and due in June of 2015 and Series 2003-B of US$ 200 bearing annual interest due of 5.548% due in June of 2013. The Junior Trust Certificates were issued with complementary terms as the new Senior Trust Certificates as they form a 20% guarantee to the senior trust certificates and expire ratably. These two new issuances complement the initial structured finance export prepayment program commenced in December of 2001.
During 2002, PETROBRAS issued the following book-entry, non-convertible debentures, without guarantee or preference, in a single issue:
Issue date
August 29
October 4 and 23
The proceeds of these issuances were used for general corporate purposes. There were no additional issuances in 2003 on non-convertible debentures.
Financial institutions abroad do not require guarantees from the Company. The financing granted by BNDES—National Bank for Social and Economic Development is guaranteed by a lien on the assets being financed (vessels).
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At December 31, 2003 and 2002, GASPETRO had secured certain debentures issued to finance the purchase of the transportation rights in the Bolivia/Brazil pipeline with 3,000 shares of its interest in TBG, a subsidiary of GASPETRO responsible for the operation of the pipeline.
The Company’s debt agreements contain affirmative covenants regarding, among other things, provision of information; financial reporting; conduct of business; maintenance of corporate existence; maintenance of government approvals; compliance with applicable laws; maintenance of books and records; maintenance of insurance; payment of taxes and claims; and notice of certain events. The Company’s debt agreements also contain negative covenants, including, without limitation, limitations on the incurrence of indebtedness; limitations on the incurrence of liens; limitations on transactions with affiliates; limitations on the disposition of assets; limitation on consolidations, mergers, sales and/or conveyances; negative pledge restrictions; change in ownership limitations; ranking; use of proceeds limitations; and required receivables coverages.
The Federal Government guarantees TBG’s Multilateral Credit Agency debt, which had an outstanding balance of US$ 463 and US$ 487 at December 31, 2003 and 2002, respectively. During 2000, the Federal Government, the Company, TBG, PETROQUISA and Banco do Brasil S.A. entered into an agreement whereby the revenues of TBG will serve as a counter-guarantee to this debt until the debt has been extinguished.
PETROBRAS entered into standby purchase agreements in support of the obligations of its wholly-owned subsidiary under the note issuances in 2001, 2002 and 2003 and their respective indentures. PETROBRAS has the obligation to purchase from the noteholders any unpaid amounts of principal, interest or other amounts due under the notes and the indenture applies, subject to certain limitations, irrespective of whether any such amounts are due at maturity of the notes or otherwise.
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At December 31, 2003 and 2002, the Company had fully utilized all available lines of credit for the purchase of imports. Outstanding lines of credit at December 31, 2003 and 2002 were US$ 1,689 and US$ 2,771, respectively. Lines of credit are included in short-term debt and in suppliers’ credits.
13. Financial income (expenses), net
Financial expenses, financial income and monetary and exchange variation on monetary assets and liabilities, net, allocated to income for the years ended December 2003, 2002 and 2001 are shown as follows:
Financial expenses
Loans and financings
Capitalized interest
Leasing
Government Securities
Monetary and exchange variation
Monetary and exchange variation on monetary assets
Monetary and exchange variation on monetary liabilities
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14. Project financings
Since 1997, the Company has utilized project financing to provide capital for the continued development of the Company’s exploration and production and related projects.
Through 2002 and the majority of 2003, the Company’s arrangements with respect to these projects were considered capital leasing transactions for accounting purposes. Effective December 31, 2003, the Company adopted FIN 46 and the project financing special purpose entities were consolidated on a line by line basis. Thus at year-end 2002, the project finance obligation represents the present value of the future value of capital lease commitments, while at December 31, 2003, the project finance obligation represents the debt of the consolidated SPE with the third party lender.
As the assets related to the project finance special purpose entities and the related capital lease obligations were already recorded in the accounts of the Company at December 31, 2003, the adoption of FIN 46 related to the project finance entities did not have a material impact on the financial statements.
The Company’s responsibility under these contracts is to complete the development of the oil and gas fields, operate the fields, pay for all operating expenses related to the projects and remit a portion of the net proceeds generated from the fields to fund the special purpose companies’ debt and return on equity payments. At the conclusion of the term of each financing project, the Company will have the option to purchase the leased or transferred assets from the consolidated special purpose company.
The following summarizes the liabilities related to the projects that were in progress at December 31, 2003 and 2002:
Barracuda/Caratinga
Cabiúnas
Espadarte/Voador/Marimbá (EVM)
Marlim
Nova Marlim
Albacora
Pargo, Carapeba, Garoupa and Cherne (PCGC)
Malhas project
Langstrand Holdings S.A.
PDET ONSHORE
Repurchased securities
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14. Project financings—Continued
PETROBRAS has received certain advances in the amount of US$ 593 which are recorded as project finance obligations and are related to assets under agreements with investors, which are included to the property, plant and equipment balance; see Note 9. Such asset and obligation amounts are presented gross as the obligation can only be settled through delivery of the fully constructed asset.
As of December 31, 2003, the amounts of cash outlay commitments assumed related to consolidated structured project financings are presented as follows:
Nova Transportadora do Sudeste - NTS
Nova Transportadora do Nordeste - NTN
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On June 23, 2000 the Company completed its project finance negotiations with the Barracuda Caratinga Leasing Company B. V. (BCLC), a special purpose entity formed by a group of international financial institutions for the sole purpose of raising US$ 2,500 for the development of the Barracuda and Caratinga oil and gas fields located in the Campos Basin. Permanent funding for this project has been raised from two governmental institutions (Japan’s Bank of International Cooperation - JBIC and the BNDES) and from a syndicate of commercial banks. In conjunction with this project, the Company will contribute US$ 1,035 of drilling services through a drilling services contract signed with the Halliburton Company.
From early 2003, KBR has been announcing to the market its intention to file a Chapter 11 case with the U.S. courts, specifically limited to its asbestos business; such filing was completed in the second half of December 2003. As informed by KBR in its official announcements to the market, the bankruptcy protection proceedings would not directly impact the remaining businesses, including its obligations under the Barracuda/Caratinga Project EPC contract.
In the capacity as “Owner’s Representative” under the project, at June 17, 2003, PETROBRAS, on behalf of BCLC, finalized negotiations with KBR involving claims made by KBR for time extensions and project cost increases. After formal approval from the project sponsors, as contractually defined, such negotiations resulted in an amendment to the original agreement, as approved on November 7, 2003. The objectives of such amendment are to mitigate the risks involved, especially the risk related to the bankruptcy protection filed by KBR, and ensures asset construction completion in the shortest period. The original package of guarantees has been maintained and new guarantees are expected to be provided by KBR.
On January 12, 2004, KBR officially announced that the judge responsible for its Chapter 11 filing accepted the position advanced by KBR whereby bankruptancy proceedings should be limited to its asbestos business, without prejudice to the development of other businesses of the company, including the Barracuda/Caratinga project.
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On March 1, 2000, the Company completed its project finance negotiations with the Cayman Cabiúnas Investment Co. Ltd., a special purpose entity formed by the Mitsui and Sumitomo banks for the sole purpose of raising US$ 850 for the expansion of the Cabíunas Complex located in Macaé, in the state of Rio de Janeiro. Permanent financing was provided by JBIC, a syndicate of commercial banks led by the Bank of Tokyo-Mitsubishi and the special purpose company’s equity investors.
On June 23, 2000, the Company completed its project finance negotiations with the EVM Leasing Corporation (EVMLC), a special purpose entity formed by a group of international financial institutions for the sole purpose of raising US$ 1,600 for the development of the Espadarte, Voador and Marimbá oil and gas fields located in the Campos Basin. Permanent funding for the EVM project was provided by a syndicate of international financial institutions, Japanese trading companies, JBIC and BNDES. Bridge financing in the amount of US$ 300 for this project was prepaid in December of 1999. Upon closing of the agreement, the Company sold previously identified oil and gas assets to EVM, who leased them back to the Company.
On December 14, 1998, the Company entered into a consortium agreement with Companhia Petrolífera Marlim (CPM), a single purpose entity formed in November of 1998 by a group of international financial institutions for the sole purpose of raising US$ 1,500 for the expansion and continued development of the Marlim oil field. In December of 1999, CPM raised US$ 200 through a medium term note program, and an additional US$ 300 in 2000. Upon closing of the consortium agreement, the Company sold certain assets to CPM, who leased them back to the Company. Effective June 30, 1999 PETROBRAS conveyed its remaining assets in the Marlim field to CPM, that also leased them back to the Company. Additionally, in June of 1999, the shareholders of CPM and the Company entered into a Stock Option Agreement granting to the Company a call option at the end of the lease and to the shareholders of CPM a put option to the Company in the case of default.
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On December 6, 2001, the Company entered into a consortium agreement with Nova Marlim Petróleo S.A., a special purpose entity formed by a group of international financial institutions for the sole purpose of raising US$ 933 for the complementary development and production optimization of the Marlim oil field.
During 2000, the Company finalized negotiations for two separate financing projects related to the Albacora oil field located in the Campos basin. On November 28, 2000, the Company completed its negotiations related to a project financing arrangement with the Albacora Japan Petroleum Limited Company (AJP), a special purpose corporation formed in December of 1998 for the sole purpose of providing financing for the continued development of the Albacora oil field. AJP’s operations commenced in December of 2000 with the purchase of certain oil and gas assets from the Company. AJP provided these assets exclusively to the Company in return for minimum proceeds of US$ 208 to be generated from the field’s production.
Permanent financing was provided by JBIC, the Japan National Oil Company (JNOC) and certain Japanese trading companies. In addition, in December of 2000, PETROS, the Company’s pension plan, agreed to provide funding for the development of this oil field. During 2000, PETROS advanced US$ 240 for the continued development of the field, and this amount has been classified together with the AJP financing transaction. AJP does not have any further funding needs.
Pargo, Carapeba, Garoupa, Cherne and Congro (PCGC)
The PCGC is an offshore development project in the Pargo, Carapeba, Garoupa, Cherne and Congro fields. The project is a secondary extraction project using water-injection technology to reestablish the appropriate level of pressure in the reservoirs to maximize the recovery of oil and gas in these fields. In addition, the PCGC project includes equipment for new oil reserves in the Congro field. Management estimates total costs of the PCGC project to be US$ 134.
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Malhas Project
In order to implement a pipeline network for the transportation of gas in the Southeast and Northeast regions (MALHAS Project), the Company, through its subsidiaries GASPETRO and TRANSPETRO, entered into a consortium with the SPCs Nova Transportadora do Sudeste (NTS) and Nova Transportadora do Nordeste (NTN). NTS and NTN will participate in the consortium by acquiring assets related to the transportation of natural gas (gas pipelines, citygates and accessories), in the amount of up to US$ 1,000, US$ 92 of which had already been allocated, to be integrated in the existing gas pipeline network of PETROBRAS. Funds to be allocated to the project by NTS and NTN will derive from own capital (10%) and from financing operations obtained in the financial market.
In addition to NTS and NTN, the MALHAS consortium also includes the wholly-owned subsidiary of the Company, Transportadora Nordeste Sudeste (TNS), to which existing gas transportation assets belong, and by TRANSPETRO, which is responsible for the activities involved in the operation and maintenance of the consortium assets. Upon commencement of operations, the consortium will transport the natural gas of PETROBRAS, which will pay the consortium a fee for the services provided. Revenues arising from this project will be shared among the consortium members in accordance with pre-defined contractual terms, and NTS and NTN will receive funds in an amount necessary to fulfill their financial obligations. The Company is committed to making prepayments for transportation capacity to cover any cash shortfalls of the consortium, so that it may transfer to NTS and NTN the funds necessary for the fulfillment of their financial obligations under the agreement. The MALHAS consortium was not operational as of December 31, 2003 and, accordingly, the Company did not make any payments for gas transportation services.
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Langstrand Project
Through a financing structure that involves the SPC Langstrand Holdings S.A., the Company will sell to this company assets related to the production of oil, located in the Campos Basin, and subsequently will lease such assets back through a leasing agreement. The funds necessary for Langstrand to acquire the assets from PETROBRAS will be provided by shareholders capital (equivalent to US$ 70) and from the financing operations obtained in the international financial markets through the issuance of Medium Term Notes backed by Langstrand receivables (lease payments to be made by PETROBRAS).
Lease payments are due on a semi-annual basis from June of 2004. Langstrand revenues will arise solely from the semi-annual lease payments to be made by PETROBRAS for the use of the assets and PETROBRAS also ensures the payment of additional lease payments in the event that Langstrand revenues are not sufficient to cover its financial obligations related to the project. In an event of default, PETROBRAS is committed to acquire the SPC for the remaining balance of its obligations.
15. Capital leases
In 2002, the Company leased certain offshore platforms, vessels and thermoelectric plants, which are accounted for as capital leases. At December 31, 2003, the Company continued to lease these offshore platforms and vessels, and continued to account for such as capital leases. However, pursuant to the adoption of FIN 46, three thermoelectric plants which were previously accounted for as capital leases have been consolidated by the Company. At December 31, 2003, assets under capital lease had a net book value of US$ 1,749 (US$ 2,499 at December 31, 2002, including thermolectrics).
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15. Capital leases—Continued
The following is a schedule by year of the future minimum lease payments at December 31, 2003:
Estimated future lease payments
Less amount representing interest at 6.2% to 12.0% annual
Less amount representing executory costs
Present value of minimum lease payments
Less current portion
Long-term portion
16. Thermoelectric plant obligations
As a result of adopting FIN 46 at December 31, 2003, the Company now consolidates six thermoelectric plants. Previously, three of these thermoelectric were accounted for as capital leases, while the other three were considered contractual obligations concerning third-party interests, with amounts equal to contingency payments required to be funded under the contracts recognized to the extent the related payments are deemed probable and can be estimated in accordance with the provisions of SFAS 5.
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16. Thermoelectric plant obligations—Continued
The consolidation of the three thermoelectrics formerly treated as capital leases resulted in US$ 375 being reclassified from capital lease obligations to long-term debt obligations (see Note 15). The impact of changing the obligations related to these three plants from the minimum value of future lease payments to the debt outstanding with third party lenders was immaterial. At December 31, 2003, the consolidation of the three thermoeletrics previously accounted for as contractual obligations concerning third party interests resulted in an increase to assets and long-term obligations of US$ 1,142.
At December 31, 2002, the Company had commitments with thermoelectric plants related to (a) the supply of natural gas for the production of energy and the purchase of all or a portion of the energy generated by these plants and (b) commitments to reimburse certain allocations as defined per the Consortium Agreements. At December 31, 2002 the provision for future losses on energy business recorded by the Company amounted to US$ 205. On May 7, 2003, the Executive Board authorized an increase in the above-mentioned accounting provision for US$ 205, in the first quarter of 2003 especially considering that the originally expected sales of energy available through Power Purchase Agreements (PPA’s) in 2003 and the technical supply level of thermopower plants were not confirmed, principally as a result of a retraction in demand following the energy rationing program and of the lack of a well defined regulatory framework for the energy sector. The provisions accrued at year-end 2002 and in the first quarter of 2003, respective to 2003 exposure was substantially utilized during the course of the year.
At December 31, 2003 as a result of adoption of FIN 46, the Company has consolidated the thermoelectric plants and recognized a corresponding liability. Thus, it is no longer necessary to recognize any additional liability for future payments expected to be made under the agreements with the sponsors of the thermoelectric plants. The Company will recognize any losses from operations of the plant if and when incurred.
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17. Employees’ postretirement benefits and other benefits
The balances related to Employees’ Postretirement Benefits are represented as follows:
Health
care
benefits
Employees’ postretirement benefits obligations
Tax effect
Net balance recorded in shareholders’ equity
Other assets: Unrecognized pension obligations
The Fundação Petrobras de Seguridade Social (PETROS) and the current benefits plan (the PETROS Plan)
The Fundação Petrobras de Seguridade Social (PETROS) was established by PETROBRAS as a private, legally separate nonprofit pension entity with administrative and financial autonomy. As such, PETROS has the following principle objectives:
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17. Employees’ postretirement benefits and other benefits—Continued
The Fundação Petrobras de Seguridade Social (PETROS) and the current benefits plan (the PETROS Plan)—Continued
The PETROS plan is a contributory defined-benefit pension plan introduced by PETROBRAS in July of 1970, to supplement the social security pension benefits of employees of PETROBRAS and its subsidiaries and affiliated companies. In order to fund its objectives, PETROS receives monthly contributions from the sponsoring companies of the PETROS Plan amounting to 12.93% of the salaries of participants in the plan. Additionally PETROS is funded by income resulting from the investment of these contributions. The Company’s funding policy is to contribute to the plan annually the amount determined by actuarial calculations. In the calendar 2003 year, contributions paid totaled US$ 402 (US$ 311 in 2002), and was deducted from the balance of the provision for benefit obligation established at December 31, 2003. In the 2003 and 2002 financial years, these contributions were included in the cost of operations.
The Company’s liability related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The assets that guarantee the pension plan are presented as a reduction to the net actuarial liabilities.
The actuarial gains and losses arising from the difference between the actuarial assumptions and the fair value of plan assets are respectively recorded as “amounts not recognized as net periodic pension cost”, in shareholders’ equity. These gains and losses are amortized during the average remaining service period of the active employees of approximately 15 years at December 31, 2003, in accordance with the procedure established by SFAS 87.
The relation between contributions by the sponsors and participants of the PETROS Plan, considering only those attributable to the Company and subsidiaries in the 2003 financial year, was 1.01 (0.94 in 2002). The Company’s best estimate of contributions expected to be paid in 2004 respective to the pension plan approximates US$ 122.
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According to Constitutional Amendment No. 20, the computation of any deficit in the defined-benefit plan in accordance with the actuarial method of the current plan (which differs from the method defined in SFAS 87), must be equally shared between the sponsor and the participants.
Therefore, in the event that the deficit computed for December 31, 2003 in accordance with the projected credit unit method (SFAS 87), is reflected as a technical deficit in the methods adopted by the PETROS Plan, and results in additional financial contributions, these additional required contributions shall be divided equally between the Company and the participants.
Plan assets
Plan assets are invested primarily in government securities, investment funds, equity instruments and properties.
The table below describes the types of plan assets:
Investments funds
Equity instruments
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Plan assets—Continued
Plan assets includes the following securities of related parties:
PETROBRAS common shares
PETROBRAS preferred shares
Government controlled companies
Securities of other related parties
In addition, PETROS has agreed to provide certain financing for the continued development of the Albacora oil and gas field located in the Campos Basin (see Note 14).
The Company uses 6% as the expected long-term rate of return on PETROS’ assets. The PETROS’ portfolio of investments as of December 31, 2003 was comprised of 71% securities, 50% of which were held-to-maturity government securities that earn interest at 6% annually plus the IPCA (Consumer Price Index) variation and 23% of which were Investments Funds that earn interest approximate to the CDI (Certificado de Depósito Interbancário, or Interbank Deposit Certificate), which has been yielding more than 6% annually. Thus, the Company considers a 6% long term interest rate appropriate to calculate the expected return on assets, as such aligns with the composition of the PETROS’ asset portfolio.
PETROS intends to change its investment strategy for the 2004-2008 years to reflect the evolution of and opportunities expected in the Brazilian economy for 2004 and beyond. PETROS will continue to maintain plan assets in various sectors, but percentages by asset type are expected to differ depending on yield’s achievable in the market while minimizing risk exposure.
PETROS has a significant volume of investments in government securities, mainly NTN-B bonds, which by an agreement with the Supplementary Social Security Department will be held-to-maturity. Thus, the percentage of assets allocated in this investment will remain the same over the short term.
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PETROBRAS VIDA plan
In May of 2001, the Board of Directors of PETROBRAS approved the creation of a mixed social security plan, for current and new employees, based on defined contribution formula for programmable benefits and a defined benefit formula for risk benefits.
The new plan, PETROBRAS VIDA, was approved by the Coordination and Control Department of State Companies (DEST) and by the Supplementary Social Security Department (SPC) in October of 2001, and ratified by PETROBRAS Board of Directors.
The migration process of participants in the current plan to PETROBRAS VIDA has been temporarily suspended pursuant to a Federal Justice ruling. Therefore the impact of migration to the new plan will only be computed and recognized in the Company’s financial statements in accordance with the requirements of SFAS No. 88 - Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (“SFAS 88”), when the issues being litigated have been resolved and the migration process finalized.
In August of 2002, pursuant to closure of the PETROS Plan, PETROBRAS took out a group life insurance policy to cover employees beginning employment with the Company subsequent to closure of the PETROS plan; this policy will remain in effect until a new private pension plan is implemented.
TRANSPETRO
TRANSPETRO maintains a defined-contribution private pension scheme with PETROS called Plano TRANSPETRO, which receives monthly contributions equivalent to 5.32% of the payroll of the members and is equal to the contributions made by the participants.
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PETROBRAS ENERGIA – PEPSA
Defined contribution plan
Petrobras Energia sponsors a defined contribution plan applicable to all of its employees with salaries above a specified level. Through this plan, Petrobras Energia provides additional funds at amounts equivalent to contributions made by employees which are in excess of legally required amounts. These funds are recognized in accordance with the accrual method of accounting. Due to significant changes in the macroeconomic scenario in 2002 and the uncertainties with regard to the Argentine economic conditions, PEPSA has temporarily suspended this benefit as from January of 2002. This benefit will be reinstated when a provisional savings means considered adequate to this end is identified.
All employees joining PEPSA prior to May 31, 1995 that have participated in the defined contribution plan without interruption and that have worked for a required number of years are entitled to this benefit. The benefit is based on the latest salary amount paid to the employees that participate in the plan, considering the number of years worked.
The plan is of a supplemental nature: the benefit received by the employee corresponds to an amount defined in conformity with the plan’s provisions, after deducting the benefits vested in accordance with the contribution plan and the government-sponsored pension scheme, so as the aggregate amount of benefits granted to each employee under the three plans is equivalent to that defined in the plan.
As from retirement, the employees are entitled to a fixed monthly payment.
The plan requires contributions to a fund, payable by PEPSA and not by the employees, who must contribute to the social security system based on their total salary. The fund’s assets have been transferred to a trust and invested mainly in bonds, notes, mutual investment funds and fixed term deposits. The Bank of New York is the trustee and Watson Wyatt is the managing agent. PEPSA determines the liability relating to this plan using actuarial calculation methods.
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PETROBRAS and its subsidiaries maintain a health care benefit plan (AMS), which offers defined benefits and covers all employees (active and inactive) together with their dependents. The plan is managed by the Company, with the employees contributing fixed amounts to cover principal risks and a portion of the costs relating to other types of coverage in accordance with participation tables defined by certain parameters including salary levels.
The Company’s commitment related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method. The health care plan is not funded or otherwise collateralized by assets. Instead, the Company makes benefit payments based on annual costs incurred by plan participants.
For measurement purposes, a 5.82% annual rate of increase in the per capita cost of covered health care benefits was assumed upon adoption of SFAS 106. The annual rate was assumed to decrease to 2.7% after 50 years.
Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement health care plans. A one-percentage-point change in assumed health care cost rates would have the following effects:
One percentage
point-increase
point-decrease
Effect on total of services and interest cost component
Effect on postretirement benefit obligation
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The funded status of the plans at December 31, 2003 and 2002, based on the report of the independent actuary, and amounts recognized in the Company’s balance sheets at those dates, are as follows:
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits paid
Acquisitions/Mergers - GASPETRO
Gain (loss) on translation
Benefit obligation at end of year (1)
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Company contributions
Employee contributions
Loss on translation
Fair value of plan assets at end of year
Reconciliation:
Funded status
Unrecognized actuarial loss
Unrecognized transition obligation
Net amount recognized
Amounts recognized in the balance sheet consist of:
Employees’ postretirement benefits
Unrecognized pension obligations
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As discussed in Note 6, on December 30, 2002, the Company transferred to PETROS NTN-B notes with a fair value of US$ 388.
Net periodic benefit cost includes the following components:
Pension
Care
HealthCare
Service cost-benefits earned during the year
Interest cost on projected benefit obligation
Expected return on plan assets
Amortization of initial transitory obligation
Recognized actuarial loss
Net periodic benefit cost
The main assumptions adopted in 2003 and 2002 for the actuarial calculation are summarized as follows:
Pension benefits
Health care benefits
Discount rates
Rates of increase in compensation levels
Expected long-term rate of return on assets
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The determination of the expense and liability relating to the Company’s pension plan involves the use of judgment in the determination of actuarial assumptions. These include estimates of future mortality, withdrawal, changes in compensation and discount rate to reflect the time value of money as well as the rate of return on plan assets. These assumptions are reviewed at least annually and may differ materially from actual results due to changing market and economic conditions, regulatory events, judicial rulings, higher or lower withdrawal rates or longer or shorter life spans of participants. As of December 31, 2002, the Company decided to change the assumptions related to the estimate of future mortality, adopting a new mortality table (GAM-71) more suitable for the evolution observed in the average life expectancy of the population made up of Company retired employees.
The Company and its actuarial consultants had been reviewing the basis for estimating the assumed discount rate for its actuarial obligations in light of the recent development of a secondary bond market in Brazil for high-grade long-term government securities. According to the requirements of SFAS 87, and subsequent interpretations, the discount rate should be based on current prices for settling the pension obligation. Applying the precepts of SFAS 87 in historically inflationary environments such as Brazil creates certain issues as the ability for a company to settle a pension obligation at a future point in time may not exist as long-term financial instruments of suitable grade may not exist locally as they do in the United States.
Although the Brazilian market has been demonstrating signs of stabilization under the present economic model, as reflected in market interest rates, it is not yet prudent to conclude that market interest rates will be stable. Although SFAS 87 offers limited guidance, the Company considers it appropriate to use actuarial assumptions which include an estimate of long-term inflation; i.e. nominal rates. Considering that the rate of return offered on high grade long-term government securities, a nominal rate of approximately 9.2% at December 31, 2003, the Company has decided not to change the discount interest rate that has been used historically, as it deems such to be consistent with the requirements of SFAS 87, and subsequent interpretations, for measurement of defined benefit obligations. The Company may adopt different assumptions in the future, which may have a significant impact on the amount of pension liability and expense.
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18. Shareholders’ equity
The Company’s subscribed and fully paid-in capital at December 31, 2003 consisted of 634,168,418 common shares and 462,369,507 preferred shares and, at December 31, 2002, consisted of 634,168,418 common shares and 451,935,669 preferred shares. The preferred shares do not have any voting rights and are not convertible into common shares and vice-versa. Preferred shares have priority in the receipt of dividends and return of capital.
The Extraordinary Shareholders’ Meeting, held jointly with the General Shareholders’ Meeting on March 22, 2002, approved the increase of the Company’s capital stock from US$ 4,834 to US$ 6,220 with the capitalization of the revenue reserve constituted in prior years, without issuing new shares.
During the same meeting, PETROBRAS shareholders approved a reform of the Company’s by-laws to adjust them to the modifications introduced by Law No. 10,303, of October 31, 2001. The principal change introduced by the new by-laws include an amendment that requires preferred shares to be given priority in the case of repayment of capital and the receipt of dividends, of at least 3% of the book value of the shares or 5% calculated on the portion of capital represented by this class of shares, whichever is larger, and participation on an equal footing with common shares in capital increases resulting from the incorporation of reserves and income.
On June 10, 2002 at an Extraordinary Shareholders Meeting, the Company’s shareholders approved an amendment to the Company’s by-laws, to adjust them to the modifications introduced by Law No. 10,438 of April 26, 2002. This amendment authorized a change in the corporate purpose of the Company, to include activities related with energy and its sale, in addition to providing more flexible means of borrowings. The Company is also authorized to increase capital, irrespective of an amendment to the by-laws, as a result of a resolution by the Board of Directors, up to R$ 30,000 million, by means of issuing up to 200 million shares, such that preferred shares do not exceed two-thirds of common shares.
In a Special Meeting of Preferred Shareholders held on June 10, 2002, the Company’s shareholders ratified a resolution taken by the Extraordinary Shareholders’ Meeting authorizing the issue of preferred shares, without maintaining proportion with common shares.
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18. Shareholders’ equity—Continued
On December 20, 2002, the Board of Directors approved the Company’s share buyback program, as facilitated by its by-laws, with the main purpose of, defending the price of its share at times when it is undervalued by the market. The definition and implementation of the share buyback program is not intended to jeopardize the investment program or replace the payment of dividends by the Company.
On January 29, 2003, the Board of Directors of the Company, approved the issuance of 9,866,828 preferred shares of the Company in connection with the public offer by the Company to acquire publicly traded shares of Petrobras Distribuidora - BR, at an issue price of US$ 12.38 (R$ 45.08) per share, under the terms of the capital increase approved during the meeting of the Board of Directors of the Company held on November 7, 2002. As a result, the capital of the Company increased by US$ 122. This minority interest acquisition, accounted for as a purchase business combination under SFAS No. 141 – Business Combinations (“SFAS 141”), did not have a material impact to the financial statements. See also Note 20.
The Extraordinary Shareholders’ Meeting, held jointly with the General Shareholders’ Meeting on March 27, 2003, approved an increase in the Company’s capital by capitalizing revenue reserves accrued during previous years, to the amount of US$ 912, without issuing new shares, in accordance with Art. 169, paragraph 1 of Law No. 6,404/76.
On May 9, 2003, the Board of Directors of the Company approved the issue of 567,010 preferred shares of the Company in connection with the public offer by the Company to acquire publicly traded shares of Petrobras Distribuidora - BR, at an issue price of R$ 45.08 per share. As a result, the capital of the Company increased by US$ 8.
The management of PETROBRAS will propose to the General Extraordinary Meeting, to be held together with the General Ordinary meeting on March 29, 2004, an increase in the Company’s capital to R$ 32,896,138 thousand, through the capitalization of revenue reserves accrued during previous financial years, in the amount of R$ 13,033,504 thousand, and without the issuance of new shares, in accordance with article 169, paragraph 1, Law No. 6,404/76. This capitalization will be made in order to bring the Company’s capital in line with the investment requirements of an oil company given intensive use of capital and extended operating cycles. Additionally, the Company’s management will propose an increase in authorized capital from R$ 30,000 million to R$ 60,000 million at the General Extraordinary Meeting.
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Current Brazilian law requires that the Federal Government retain ownership of 50% plus one share of the Company’s voting shares.
In accordance with the Company’s by-laws, holders of preferred and common shares are entitled to a minimum dividend of 25% of annual net income as adjusted under Brazilian Corporate Law. In addition, the preferred shareholders have priority in the receipt of an annual dividend of at least 3% of the book value of the shares or 5% of the paid-in capital in respect of the preferred shares as stated in the statutory accounting records. As of January 1, 1996 amounts attributed to shareholders as interest (see below) can be deducted from the minimum dividend computation. Dividends are paid in Brazilian reais. The Company paid US$ 212 in dividends during the year ended December 31, 2003 (2002 - US$ 602 - 2001 - US$ 424)
Brazilian corporations are permitted to attribute interest on shareholders’ equity, which may either be paid in cash or be used to increase capital stock. The calculation is based on shareholders’ equity amounts as stated in the statutory accounting records and the interest rate applied may not exceed the Taxa de Juros de Longo Prazo (long-term interest rate or the “TJLP”) as determined by the Brazilian Central Bank. Such interest may not exceed the greater of 50% of net income or 50% of retained earnings plus revenue reserves. Interest on shareholders’ equity, is subject to withholding tax at the rate of 15%, except for untaxed or exempt shareholders, as established by Law No. 9,249/95. The Company paid US$ 731 in interest on shareholders’ equity during the year ended December 31, 2003 (2002 - US$ 416 - 2001 - US$ 1,301).
On November 13, 2003, the PETROBRAS Board of Directors approved the distribution of remuneration to shareholders in the form of interest on shareholders’ equity amounting to R$ 3,290 million (US$ 1,139), in accordance with article 8 and 9, of the Company’s by-laws, article 9 of Law No. 9,249/95 and Decrees No. 2,673/98 and No. 3,381/00. This provision for interest on shareholders’ equity resulted in an income tax benefit in the amount of US$ 364.
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This remuneration was made available to shareholders at February 13, 2004, based on the shareholdings on November 25, 2003, corresponding to R$ 3.00 (US$ 1.03 calculated by the year-end exchange rate) per common and preferred share, and was deducted from the dividend calculated on adjusted net income for the 2003 financial year.
The General Shareholders’ Meeting held on March 27, 2003 approved the proposed dividends for the 2002 financial year amounting to US$ 781; such amount included US$ 307 which was accrued in the 2002 financials, and interest on shareholders’ equity approved by the Board of Directors on January 31, 2003, amounting to US$ 310, and the balance of dividends, amounting to US$ 164, both of which amount were reflected in the 2003 financial statements. These amounts, paid in Brazilian reais, were monetarily restated as from December 31, 2002 up to the date of payment.
The dividends proposal submitted by the Board of Directors for approval at the General Shareholders’ Meeting to be held on March 29, 2004, amounting to US$ 1,955, corresponding to R$ 5.15 per share (US$ 1.78 per share calculated by year-end exchange rate), include the portion of interest on shareholders’ equity approved by the Board of Directors on November 13, 2003, amounting to US$ 1,139, corresponding to R$ 3.00 per share (US$ 1.04 per share calculated by year-end exchange rate), and also includes the portion of interest on equity approved by the Board of Directors on February 13, 2004, amounting to US$ 436, corresponding to R$ 1.15 (US$ 0.40 calculated by the year-end exchange rate) per common and preferred share, to be made available based on the shareholders of record as of March 29, 2004, which is the intended date of the General Shareholders’ Meeting that will discuss this subject.
The balance of dividends (US$ 380) and the additional portion of the interest on shareholders’ equity (US$ 436) have been excluded from the US GAAP financials, but will be paid on a date to be established by the General Shareholders’ Meeting. These amounts are paid in Brazilian reais and will be monetarily restated as from December 31, 2003 up to the initial date of payment, according to the variation in the SELIC rate.
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Brazilian law permits the payment of dividends only from retained earnings as stated in the statutory accounting records. At December 31, 2003, the Company had appropriated all such retained earnings.
In addition, at December 31, 2003, the undistributed reserve in appropriated retained earnings, amounting to US$ 9,372, may be used for dividend distribution purposes, if so approved by the shareholders, however, the Company’s stated intent is to use such reserve to fund working capital and capital expenditures.
A withholding tax of 15% was payable on distributions dividends earned from January 1, 1994 through December 31, 1995. No withholding tax is payable on distributions of dividends earned since January 1, 1996.
Basic and diluted earnings per share amounts have been calculated as follows:
Net income for the period
Less priority preferred share dividends
Less common shares dividends, up to the priority preferred shares dividends on a per-share basis
Remaining net income to be equally allocated to common and preferred shares
Common and Preferred
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Relates to the Merchant Marine (AFRMM) freight surcharges levied in accordance with relevant legislation. These funds are used to purchase, enlarge or repair vessels of the Company’s transport fleet.
This reserve consists of investments in tax incentives in the Northeast Investment Fund (FINOR), arising from allocations of part of the Company’s income tax.
Brazilian Law and the Company’s by-laws require that certain appropriations be made from retained earnings to reserve accounts annually. The purpose and basis of appropriation to such reserves is as follows:
This reserve is a requirement for all Brazilian corporations and represents the annual appropriation of 5% of net income as stated in the statutory accounting records up to a limit of 20% of capital stock. The reserve may be used to increase capital or to compensate for losses, but may not be distributed as cash dividends.
This reserve is established in accordance with Article 196 of Law No. 6,404/76 to fund the Company’s annual investment program. For the year ended December 31, 2002, the Company’s management retained US$ 1,834 of which US$ 1,831 relates to net income for the year and US$ 3 to the remaining balance of retained earnings, to fund the Company’s capital expenditure budget for 2003. This proposal was approved at the General Shareholders’ Meeting held on March 27, 2003.
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The proposal for appropriation of income for the year ended December 31, 2003 includes a retention of earnings in the amount of US$ 4,603, of which US$ 3,773 relates to net income for the year and US$ 830 to the remaining balance of retained earnings, to be approved by the General Shareholders’ Meeting to be held on March 29, 2004. This proposal is intended to cover partially the annual investment program established in the capital budget for 2004.
This reserve is provided through an amount equivalent to a minimum of 0.5% of subscribed and fully paid in capital at year-end. The reserve is used to fund the costs incurred with research and technological development programs. The accumulated balance of this reserve cannot exceed 5% of the capital stock, according to Article 55 of the Company’s by-laws.
19. International acquisitions
On October 17, 2002, the Company signed the Final Share Acquisition Agreement with the Perez Companc family and the Fundación Perez Companc, completing the acquisition of a controlling interest of Perez Companc S.A. (currently known as Petrobras Energia Participaciones S.A – PEPSA), and Petrolera Perez Companc S.A. (currently known as Petrolera Entre Lomas S.A. - PELSA). In October of 2002, in accordance with Argentine legislation, the necessary documentation was submitted to the Argentine antitrust agency (CNDC - Comisión Nacional de Defensa de la Competencia) in order to obtain approval for the transaction.
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19. International acquisitions—Continued
On May 13, 2003, the Argentine antitrust agency (Comisión Nacional de Defensa de la Competencia), an agency reporting to the Argentine Secretariat of Competition, Deregulation and Consumer Protection (Secretaria de la Competencia, la Deregulación y la Defensa del Consumidor), approved the purchase of 58.62% of the capital stock of PEPSA and 39.67% of the capital stock of PELSA capital stock by PETROBRAS Participações S.L., a company controlled by PETROBRAS. As a result of the purchase of a 39.67% interest in the capital stock of PELSA, together with the purchase of 58.62% of PEPSA’s interest in the capital stock of PELSA, the Company has a controlling interest in PELSA equal to 50.73% and thus has consolidated the entity.
The purchase price to be paid for PEPSA and PELSA was based on an economic valuation model of expected future earnings of those companies, which considered relevant factors, including the potential effects of the economic situation of Argentina. The Company paid US$ 739 in cash and US$ 338 in bonds to the Perez Companc family for the shares of PEPSA and PELSA.
The acquisition was consummated principally to expand PETROBRAS operations into geographical markets where the Company had little activity. Through the acquisition of PEPSA and PELSA, PETROBRAS was able to gain immediate access to the Argentine market and brand recognition. The goodwill of US$ 183 generated by the transaction is attributed principally to downstream activities.
The acquisition of PEPSA and PELSA was recorded using the purchase method of accounting and the financial statements of PEPSA and PELSA were included in the consolidated PETROBRAS financial statements, beginning on May 13, 2003. The purchase price for PEPSA and PELSA was allocated based on the fair market value of the assets acquired and the liabilities assumed as of the acquisition date as determined by independent appraisers.
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PEPSA operates principally in the areas of oil field exploration and production, refining, transport and commercialization, electricity generation, transmission and distribution, and petrochemicals. Its activities are primarily based in Argentina, but PEPSA also operates in Bolivia, Brazil, Ecuador, Peru and Venezuela. PELSA operates primarily in the oil and gas exploration and production industry in Argentina.
The following unaudited pro forma summary financial information presents the consolidated results of operations as if the acquisition of PEPSA and PELSA had occurred at the beginning of the periods presented.
Consolidated income statements data for the year ended December 31.
Costs and expenses
Financial expenses, net
Cumulative effect of change in accounting principles, net of taxes
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On October 24, 2002, the Company completed the acquisition of 100% of Petrolera Santa Fe Southern Cone, Inc., a holding company incorporated in the British Virgin Islands, parent company of Petrolera Santa Fe S.R.L (Santa Fe), an Argentine oil and gas exploration company, for US$ 90, paid in cash on the same date. The purchase price was less than the estimated fair market value of the net assets acquired, resulting in a reduction in the acquisition value assigned to Santa Fe’s long-lived assets. In 2002, Santa Fe produced approximately 10.2 thousand barrels of oil equivalents per day. The acquisition did not have significant effects on results of operations on a pro-forma basis.
20. Petrobras Distribuidora - BR
On November 7, 2002, the Board of Directors of the Company approved a public offer by the Company to acquire the publicly traded shares of Petrobras Distribuidora S.A. - BR, to cancel its quoted company registration by means of an exchange for preferred share to be issued by the Company.
In addition the Board of Directors approved the valuation appraisal of BR that determined the value of R$ 45.40 (US$ 11.66) for each 1,000 share lot of BR stock, the valuation appraisal by the Company that established a value of R$ 64.90 (US$ 16.66) for each share issued by the Company together with the swap ratio of the Company and BR shares at the rate of 0.7 PETROBRAS shares for 1,000 BR shares, which will be agreed together with a premium, defined by the specific formula.
On January 29, 2003, a public auction was held in which implementation of the condition for canceling the registration of the quote company of BR was verified. On February 5, 2003, CVM cancelled the registration of the quoted company of BR.
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21. Accounts - temporary agreement on price stabilization in Argentina
In January 2003, pursuant to government actions seeking to stabilize the economic environment in Argentina, the hydrocarbon producing and refining companies signed a temporary agreement aimed at stabilizing the prices of crude oil, gasoline and diesel oil in the Argentine market. This agreement, considering renewals, extends to February 29, 2004. Under this agreement, deliveries of crude oil must be billed and paid based on a reference WTI (West Texas Intermediate) price of US$ 28.50 per barrel. Positive or negative differences between the actual WTI, up to the limit of US$ 36.00 per barrel, and the reference price are to be realized based on amounts generated in periods during which the actual WTI price is lower than US$ 28.50 per barrel. As long as average market WTI prices remain higher than the reference price, the refining companies will, otherwise, record a liability to be realized when the WTI price is lower than the reference price. At December 31, 2003, the amount payable by Argentine companies within the PETROBRAS system related to the price difference on the acquisition of crude oil, amounted to US$ 10.
22. Commitments and contingencies
PETROBRAS is subject to a number of commitments and contingencies arising in the normal course of its business. Additionally, the operations and earnings of the Company have been, and may be in the future, affected from time to time in varying degrees by political developments and laws and regulations, such as the Federal Government’s continuing role as the controlling shareholder of the Company, the status of the Brazilian economy, forced divestiture of assets, tax increases and retroactive tax claims, and environmental regulations. The likelihood of such occurrences and their overall effect upon the Company are not predictable.
The Company currently has several contracts to purchase crude oil, diesel fuel and other oil products, which require the Company to purchase a minimum of approximately 147,000 barrels per day at respective current market prices.
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22. Commitments and contingencies—Continued
PETROBRAS provided guarantees to the ANP for the minimum exploration program defined in the concession contracts for exploration areas, totaling US$ 907. Out of this total, US$ 704 represents a pledge on the oil to be extracted from previously identified fields already in production, for areas in which the Company had already made commercial discoveries or investments at the time where Law No. 9,478 of August 6, 1997 came into force. For areas whose concessions were obtained by bidding from the ANP, PETROBRAS has given bank guarantees totaling US$ 203 through December 31, 2003.
PETROBRAS has guaranteed that it will purchase specified volumes of natural gas that run through TBG pipeline.
In 1993, the Company signed a contract with Yacimentos Petrolíferos Fiscales Bolivianos, the Bolivian state oil company for the purchase of natural gas. Under this contract, the Company is required to purchase 80% of the natural gas transported through the Bolivia/Brazil natural gas pipeline over a 20 year term at contract prices ranging from US$ 1.07 per MMBTU to US$ 1.17 MMBTU, based upon throughput. The pipeline achieved an average throughput of 24.64 million cubic meters per day during 2003.
The Company has exclusive supply contracts with certain service stations. These contracts are typically for seven years and require the Company to sell product at market prices.
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The Company is a defendant in numerous legal actions involving civil, tax, labor, corporate and environment issues arising in the normal course of its business. Based on the advice of its internal legal counsel and management’s best judgment, the Company has recorded accruals in amounts sufficient to provide for losses that are considered probable and reasonably estimable. At December 31, 2003 and 2002, the respective claims by type are as follows:
Commercials claims and other contingencies
Contractual contingencies - thermoelectric plants (see Note 16)
Contingencies for joint liability
Current Contingencies
Long-term Contingencies
As of December 31, 2003 and 2002, in accordance with Brazilian law, the Company had paid US$ 543 and US$ 290, respectively, into federal depositories to provide collateral for these and other claims until they are settled. These amounts are reflected in the balance sheet as restricted deposits for legal proceedings and guarantees.
The Company is a party to several contracts related to the acquisition and upgrade of production Platform P-36, which was lost in its entirety in 2001. Pursuant to those contracts, the Company had an obligation to pay the insurance proceeds to a Security Agent for distribution according to specified clauses established in the contracts. The Company contends that it is entitled to the insurance proceeds under the contractual arrangements, and other parties contend that they are also entitled to such proceeds. The issue is subject to international proceedings in a British court. Pending determination of the issue by the international court, the Company committed to deposit cash collateral in the amount of US$ 175, in order to facilitate the issuance of a guarantee by a Security Agent, for the payment of creditors. At December 31, 2003, this amount was included in the balance sheet as restricted deposits for legal proceedings and guarantees.
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On May 28, 1981, Kallium Mineração S.A. brought an action against Petromisa, a former subsidiary of PETROBRAS, in the Federal Court of the State of Rio de Janeiro alleging damages of approximately US$ 450 relating to the rescission of a contract to develop a potassium salt mine. On August 10,1999, a decision was handed down that considered most of the plaintiff’s petitions to be without grounds (losses, damages and loss of profit), requiring only the Company to reimburse “all expenses incurred as a result of the prospecting research” carried out, in accordance with amounts to be calculated in the final award. No award for loss of profit was established in the decision. In September of 1999 both parties filed appeals with the appeals court in the state of Rio de Janeiro. Based on the opinion of its legal advisers, management does not expect an unfavorable outcome in this case and considers the risk of loss with respect to this lawsuit to be remote.
On August 8, 1993, Indústria Bahiana de Adubos, Importação e Exportação Ltda. filed a lawsuit against the Company in the State Court of Bahia claiming approximately US$ 129 in damages. The claim is based upon the Company’s refusal to sell fertilizers to the plaintiff due to the plaintiff’s payment default under prior contracts with the Company. The plaintiff claims that such refusal harmed its financial condition and, ultimately, caused its bankruptcy. On December 9, 1993, the trial court decided in favor of the plaintiff. However, the Company appealed and the decision was reversed by the State Court of Appeals. Subsequently, the plaintiff filed a special appeal, which was also found to be without grounds on June 25, 2002 by the 3rd Panel of the Appeals Court. This Court dismissed the case and the lawsuit was extinguished.
On November 23, 1992, PORTO SEGURO IMÓVEIS LTDA., a minority shareholder of PETROQUISA, filed a suit against PETROBRAS in the State Court of Rio de Janeiro related to alleged losses resulting from the sale of a minority holding by PETROQUISA in various petrochemical companies included in the National Privatization Program introduced by Law No. 8,031/90.
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In this suit, the plaintiff claims that PETROBRAS, as the majority shareholder in PETROQUISA, should be obliged to reinstate the “loss” caused to the net worth of PETROQUISA, as a result of the acts that approved the minimum sale price of its holding in the capital of privatized companies. A decision was handed down on January 14 of 1997 that considered PETROBRAS liable with respect to PETROQUISA for losses and damages in an amount equivalent to US$ 3,406.
In addition to this amount, PETROBRAS was required to pay the plaintiff 5% of the value of the compensation as a premium (see art. 246, paragraph 2 of Law No. 6,404/76), in addition to attorneys’ fees of approximately 20% of the same amount. However, since the award would be payable to PETROQUISA and PETROBRAS holds 99.0% of its capital, the effective disbursement if the ruling is not reversed will be restricted to 25% of the total award. PETROBRAS filed an appeal with the State Court of Rio de Janeiro, and received a favorable decision from the Third Civil Court on February 11, 2003, which, by a majority vote, accepted PETROBRAS’ appeal to reverse the judgment and ruled the plaintiff’s case to be without grounds, the revising judge’s decision that held the case to be partially with grounds to reduce the amount of compensation to US$ 1,538 being overruled. Based on its legal counsels advice, PETROBRAS’ Administration does not expect to obtain an unfavorable decision in the case and assesses the risk of loss to be remote.
The Fisherman’s Federation of the State of Rio de Janeiro (FEPERJ) filed a civil suit against the Company with the Rio de Janeiro State Court for compensation of miscellaneous damages amounting to US$ 224, which it is claiming in the name of its members, as a result of the oil spill in Guanabara Bay on January 18, 2000. A decision was handed down on February 7, 2002 which ruled the claim partially without grounds, rejecting pain and suffering, and requiring the Company to pay compensation for material damages and loss of profit to be calculated at the award phase. The ruling expressly declares that it is not reasonable to consider an award based on the amount claimed, since it was without economic base.
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Based on its legal counsels opinion, the Company´s Administration believes it is possible that the Company will not prevail in this case, but that any possible negative judgment would be in an amount far below the originally filed complaint. As such, the Company assesses the risk of loss related to this case as possible.
The São Paulo tax authorities filed a tax suit against the Company, alleging that the Company did not pay ICMS levied on interstate sales of naphtha. However, during the period in which according to the State of São Paulo, the Company should have paid the ICMS, the Company was subject to a different tax regime (federal) on these sales, and for this reason enjoyed a tax holiday. The value of the matter in controversy is US$ 60. There is no guarantee that the final result of the legal case will be favorable to PETROBRAS, but even in the case of an unfavorable ruling, management does not believe that the award could have a material negative impact on the financial position of PETROBRAS. The Company assesses its risk of loss in the matter as possible.
PETROBRAS is a defendant in four labor claims filed by the UNIONS OF PETROLEUM WORKERS of three federal states (Rio de Janeiro, São Paulo and Sergipe), alleging that official inflation rates for 1987, 1989 and 1990 (understatement of the official inflation rate - Bresser, Summer and Collor Plans) were not fully included in the workers’ salaries.
The law suits are at different stages. Based on past favorable decisions in similar cases and on a final understanding of the TST, management does not expect an unfavorable decision in these suits. Three identical cases have been decided in favor of PETROBRAS. Management assesses risk of loss to be remote.
The Company was sued in court by certain small oil distribution companies under the allegation that it does not pass on to state governments the State Value-Added Tax (ICMS) collected according to the legislation upon fuel sales. These suits were filed in the states of Goiás, Tocantins, Bahia, Pará, Maranhão and in the Federal District.
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Of the total amount related to in legal actions approximately US$ 394 up to December 31, 2003, US$ 32 were effectively withdrawn from the Company’s accounts as a result of judicial rulings of advance relief.
The Company, with the support of the state and federal authorities, has succeeded in stopping the execution of other withdrawals, and is making all efforts possible to obtain reimbursement of the amounts that were previously withdrawn from its accounts.
The Company received various tax assessments related to social security amounts payable as a result of irregularities in presentation of documentation required by the INSS, to eliminate its joint liability in contracting civil construction and other services, stipulated in paragraphs 5 and 6 of article 219 and paragraphs 2 and 3 of article 220 of Decree No. 3,048/99.
The Company made a provision for this contingency in the amount of US$ 105 at December 31, 2002, as it considers the chance of success in a defense filed against the INSS to be remote.
On September 29, 2003, the Company received additional INSS tax assessments related to the joint liability for irregularities in presentation of contractors’ documentation related to periods subsequent to past notifications. At December 31, 2003 the balance of contingencies associated with this joint liability was US$ 193.
Internally, procedures were revised to improve the inspection of contracts and require the presentation of documents, as stipulated in the legislation, to substantiate the payment of INSS amounts due by contractors. PETROBRAS continues to analyze each tax assessment received in order to recover amounts, as permitted through administrative processes of the INSS.
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The Internal Revenue Service of Rio de Janeiro filed two Tax Assessments against the Company in connection with Withholding Tax (IRRF) on foreign remittances of payments related to charter of vessels of movable platform types for the years 1998 through 2002.
The Internal Revenue Service, based on Law No. 9,537/97, Article 2, considers that drilling and production platforms cannot be classified as sea-going vessels and therefore should not be chartered but leased. Based on this interpretation, overseas remittances for servicing chartering agreements would be subject to withholding tax at the rate of 15% or 25%.
The Company disagrees with the Internal Revenue Service’s interpretation as to charter contracts, given that the Federal Supreme Court has already ruled that, in the context of its judgment with respect to the IPI (Federal VAT) tax, offshore platforms are to be classified as sea-going vessels. Additionally, the 1994 and 1999 Income Tax Regulations support the “non-taxation” (RIR/1994) and the “zero tax rate” (RIR/1999) for the remittances in question.
On June 27, 2003, the Internal Revenue Service served a tax assessment notice on the Company amounting to R$ 3,064 million (US$ 1,066) covering the period from 1999 to 2002. Using the same arguments, on February 17, 2003, another tax assessment notice had already been issued for R$ 93 million (US$ 32) with respect to 1998, against which, on March 20, 2003, the Company filed an appeal. According to the fiscal authorities, the Company should have withheld that tax, incident on remittances made to abroad for payment of the hiring of vessels of the mobile platform type, used in oil exploration and production.
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PETROBRAS has defended itself against these tax assessments: i) the smaller in value has been confirmed by the first administrative level, and the corresponding appeal has been already filed by the Company, and waits judgment; ii) no first level decision has been issued so far with regard to the other one, with greater value. Based on its legal counsels advice, the Company’s Administration does not expect to obtain an unfavorable decision in this case, and thus has assessed risk of loss to be remote.
The Company is subject to various environmental laws and regulations. These laws regulate the discharge of oil, gas or other materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of such materials at various sites.
During 2000 the Company implemented an environmental excellence and operational safety program -PEGASO - (Programa de Excelência em Getão Ambiental e Segurança Operacional). Scheduled to be concluded in December 2003, the Company made expenditures of approximately US$ 2,400 from 2000 to December 31, 2003 under this program.
During the years ended December 31, 2003 and 2002 the Company made expenditures of approximately US$ 766 and US$ 677 respectively, under this program, including US$ 225 and US$ 234 through the Programa de Integridade de Dutos (Pipeline Integrity Program) through which it conducts inspections of, and improvements to, the Company’s pipelines.
The Company believes that future payments related to environmental clean up activities resulting from these incidents, if any, will not be material.
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On January 18, 2000, a pipeline from one of the Company’s terminals to a refinery in the Guanabara Bay ruptured, causing a release of crude oil into the bay. On January 19, 2001, the Rio de Janeiro State Prosecutor filed a criminal lawsuit against the Company. The Company is contesting the legal basis for the criminal lawsuit. Additionally, the Federal Prosecutor has filed criminal lawsuits against the former president of the Company (that finished) and 9 other employees. The Company cannot predict if the outcome of these proceedings will have a material adverse effect on the financial condition, results of operations or cash flows of the Company.
In addition, as a result of the spill, on January 27, 2000, the National Council for the Environment enacted a resolution that obligated the Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis (IBAMA), state environmental agencies and local environmental agencies and non-governmental agencies to evaluate the control and prevention measures and environmental licensing status of all industrial facilities for the production of oil and oil products in Brazil. This resolution also mandated that the Company perform an independent environmental audit of all of our industrial installations located in the State of Rio de Janeiro.
Since 2000, the Company implemented independent environmental audits in all of the Company’s plants located in Brazil that was concluded during December of 2003. The Company implemented 80% of the auditors recommendations and intend to implement the remaining 20% during 2004.
On July 16, 2000, an oil spill occurred at the Presidente Getúlio Vargas refinery releasing crude oil in the surrounding area. The Federal and State of Paraná Prosecutors have filed a civil lawsuit against the Company seeking US$ 1,176 in damages, that have already been contested by the Company. Additionally, there are two other actions pending, one by the Instituto Ambiental do Paraná (Paraná Environmental Institute) and by another civil association called AMAR that have already been contested by the Company. The Company cannot predict whether these proceedings will have a material adverse effect on the financial condition, results of operations or cash flow of the Company.
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On November 4, 2000, the Cypriot flag vessel Vergina II chartered by PETROBRAS collided with the south pier at the Company’s Almirante Barroso terminal in São Sebastião and spilled oil in the São Sebastião canal. As a result of the accident, the Company was fined approximately US$ 30 by various local environmental agencies. The Company is currently contesting these fines.
On February 16, 2001, the Company’s Araucária-Paranaguá pipeline ruptured and as a result fuel oil was spilled into the Sagrado, Meio, Neves and Nhundiaquara Rivers located in the state of Paraná. As a result of the accident, the Company was fined approximately US$ 80 by the Instituto Ambiental do Paraná (Paraná Environmental Institute), which the Company is contesting through administrative proceedings.
On March 15, 2001, a spill resulting from the accident involving the P-36 platform occurred, causing a release of diesel fuel and crude oil. The Company was fined by the Brazilian Environmental Institute (IBAMA) US$ 3 in April of 2001 for the spill and improper use of chemicals to disperse the oil. The Company is currently contesting these fines.
On May 12, 2003, the rupture of a connection socket on a production line at well FZB-71, on the Belém Farm field, in the city of Aracati-CE, resulted in the spill of approximately 7 (seven) thousand liters of oil at an area located far from any communities or water sources. The Company’s Contingency Plan was immediately activated and cleaning work for the area was carried out. PETROBRAS was charged with a penalty of US$ 0.04 by the Environment Superintendency of the State of Ceará (Semace) and up to 90% of this amount can be reduced by compliance with a Commitment Term entered into with the referred environmental entity.
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On June 3, 2003, a fault in the connection of one of the unloading arms of vessel Nordic Marita, anchored at the Maritime Terminal Almirante Barroso (Tebar), in São Sebastião, on the North coast of São Paulo, caused a spill of approximately 27 thousand liters of oil from Campos Basin. As a result of this accident, PETROBRAS was charged with a penalty of US$ 0.17 by the Brazilian Institute for the Environment and Renewable Resources (IBAMA) and of US$ 0.12 by Basic Sanitation, Technology and Environment Protection Agency of the State of São Paulo (CETESB). An appeal was filed against both charges based on the understanding that the Company acted in the most efficient possible manner in order to minimize possible impacts on the environment.
On August 26, 2003, the rupture of a pipeline between Transpetro’s terminal in Cabiúnas (Macaé) and Duque de Caxias Refinery caused the spill of 20 (twenty) liters of oil in an area of the city of Cachoeiras de Macacu. The Company immediately determined that the oil located in the service area of the pipeline should be removed, and took preventive measures to protect a creek, near to the Soarinhos River, with checks and oil-absorbing materials. In spite of the effective procedures adopted by PETROBRAS and the non-absence of environmental damages, the Company received a fine from IBAMA in the amount of US$ 0.69, but filed an administrative proceeding with this entity.
The Company’s management considers that any expenses incurred to correct or mitigate possible environmental impacts should not have a significant effect on operations or cash flows.
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The Company is committed to make the following minimum payments related to operating leases as of December 31, 2003:
Minimum operating lease payment commitments
The Company paid US$ 1,205, US$ 1,355, and US$ 1,284 in rental expense on operating leases at December 31, 2003, 2002 and 2001, respectively.
Additionally, the company is committed to make the following minimum long-term payments related to services contracted as of December 31, 2003:
Minimum service contract payment commitments
23. Derivative instruments, hedging and risk management activities
The Company is exposed to a number of market risks arising from the normal course of business. Such market risks principally involve the possibility that changes in interest rates, currency exchange rates or commodity prices will adversely affect the value of the Company’s financial assets and liabilities or future cash flows and earnings. The Company maintains an overall risk management policy that is developed under the direction of the Company’s executive officers.
The Company may use derivative and non-derivative instruments to implement its overall risk management strategy. However, by using derivative instruments, the Company exposes itself to credit and market risk. Credit risk is the failure of a counterparty to perform under the terms of the derivative contract. Market risk is the adverse effect on the value of a financial instrument that results from a favorable change in interest rates, currency exchange rates, or commodity prices. The Company addresses credit risk by restricting the counterparties to such derivative financial instruments to major financial institutions. Market risk is managed by the Company’s executive officers. The Company does not hold or issue financial instruments for trading purposes.
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23. Derivative instruments, hedging and risk management activities—Continued
The Company’s foreign currency risk management strategy may involve the use of derivative instruments to protect against foreign exchange rate volatility, which may impair the value of certain of the Company’s obligations. The Company currently uses zero cost foreign exchange collars to implement this strategy.
During 2000, the Company entered into three zero cost foreign exchange collars to reduce its exposure to variations between the U.S. Dollar and the Japanese Yen, and between the U.S. Dollar and EURO relative to long-term debt denominated in foreign currencies with a notional amount of approximately US$ 470. The Company does not use hedge accounting for these derivative instruments.
These collars establish a ceiling and a floor for the associated exchange rates. If the exchange rate falls below the defined floor, the counterparties will pay to the Company the difference between the actual rate and the floor rate on the notional amount. Conversely, if the exchange rate increases above the defined ceiling, the Company will pay to the counterparties the difference between the actual rate and the ceiling rate on the notional amount. The contracts expire upon the maturity date of each note.
As of December 31, 2002 and 2001, the Company had a fair value obligation of US$ 80 and US$ 119, respectively, associated with its EURO and Japanese Yen zero cost collar contracts. The Yen zero cost collar contracts were settled on September 8, 2003, with a cash payment of US$ 68.
As of December 31, 2003 the Company had a fair value asset of US$ 26 associated with its Euro zero cost collar contracts.
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The Company is exposed to commodity price risks as a result of the fluctuation of crude oil and oil product prices. The Company’s commodity risk management activities primarily consist of futures contracts traded on stock exchanges and options and swaps entered into with major financial institutions. The futures contracts provide economic hedges to anticipated crude oil purchases and sales, generally forecast to occur within a 30 to 360 day period, and reduce the Company’s exposure to volatile commodity prices.
The Company’s exposure on these contracts is limited to the difference between contract value and market value on the volumes hedged. Crude oil future contracts are marked to market and related gains and losses are recognized currently into earnings, irrespective of when physical crude sales occur. For the years ended December 31, 2003, 2002 and 2001, the Company consummated commodity derivative transaction activities on 72.47%, 42.01% and 21.20%, respectively, of its total import and export traded volumes.
The open positions on the futures market, compared to spot market value, resulted in recognized losses of US$ 2, US$ 4 and US$ 6 during the years ended December 31, 2003, 2002 and 2001, respectively.
A long-term operation was executed on January of 2001 by the sale of put options for 52 million barrels of West Texas Intermediate (WTI) oil over a period extending from 2004 to 2007, with the objective to obtain price protection for this quantity of oil and to provide the funding institutions of the Barracuda/Caratinga project with a minimum guaranteed margin to cover the debt servicing. The puts were structured to ensure that the financial institutions participating in the financing of the development of the fields receive the price required to generate the minimum required return on investment. The Company accounts for the put options on a mark to market basis. During 2003, 2002 and 2001, the Company realized a net gain of US$ 7 and US$ 8 and US$ 5, respectively.
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The fair value of oil products is based on usual market conditions, at values prevailing at the closing of the period, considered relevant for underlying quotations. Option contracts are valued using the Black & Scholes model, considering parameters advised by financial institutions of international reputation.
The Company’s interest rate risk is a function of the Company’s long-term debt and, to a lesser extent, short-term debt. The Company’s foreign currency floating rate debt is principally subject to fluctuations in LIBOR and the Company’s floating rate debt denominated in Reais is principally subject to fluctuations in the Brazilian long-term interest rate (TJLP), as fixed by the Brazilian Central Bank. The Company currently does not utilize derivative financial instruments to manage its exposure to fluctuations in interest rates. However, the Company has been studying various forms of derivatives to reduce exposure to interest rate fluctuations and may use these financial instruments in the future.
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PEPSA consummated commodity derivative transactions, referenced to WTI, for 40% of its total sales volume (corresponding to 11,963 thousand boe) at December 31, 2003. The operations settled in the year generated a loss in the approximate amount of US$ 67. At December 31, 2003, the open positions on the futures market, when compared to their market value, represented a negative result of approximately US$ 187, if liquidated on that date. These transactions were accounted for as cash flow hedges in accordance with SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”).
Additionally, PEPSA holds an interest rate contract to manage the volatility of the LIBOR rate implied in a Class C negotiable instrument, establishing the respective interest rate at 7.93% annually. If this instruments were to be liquidated, considering the rates used at the date, a net loss of approximately US$ 6 would be recorded. This contract qualifies for hedge accounting in accordance with SFAS 133.
24. Financial instruments
In the normal course of its business, the Company uses various types of financial instruments. These instruments include recorded assets and liabilities, and also items such as derivatives, which principally involve off-balance sheet risk.
Substantial portions of the Company’s assets including financial instruments are located in Brazil and substantially all of the Company’s revenues and net income are generated in Brazil. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, government securities, the Petroleum and Alcohol Account, trade receivables and future contracts.
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24. Financial instruments—Continued
The Company takes several measures to reduce its credit risk to acceptable levels. All cash equivalents in Brazil are maintained with federal banks in accordance with federal law. Time deposits in U.S. dollars are placed with creditworthy institutions in the United States. Additionally, all of the Company’s available for sale securities and derivative contracts are either exchange traded or maintained with creditworthy financial institutions. The Company monitors its credit risk associated with trade receivables by routinely assessing the creditworthiness of its customers. At December 31, 2003 and December 31, 2002, the Company’s trade receivables were primarily maintained with large distributors.
As described in Note 11, the National Treasury Notes, NTN-H may be used in the settlement of the Petroleum and Alcohol Account.
Fair values are derived either from quoted market prices where available, or, in their absence, the present value of expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year end. Fair values of cash and cash equivalents, trade receivables, the Petroleum and Alcohol Account, short-term debt and trade payables approximate their carrying values. The fair value for the Company’s available for sale government securities equals their carrying value as disclosed in Note 6.
The fair values of other long-term receivables and payables do not differ materially from their carrying values.
The Company’s debt included US$ 11,888 and US$ 7,346 at December 31, 2003 and December 31, 2002 and had estimated fair values of US$ 12,690 and US$ 6,791, respectively. The Company’s project finance obligation, resulting from FIN 46 consolidation was US$ 5,066 at December 31, 2003, and had an estimated fair value of US$ 5,115.
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The call and put portion of the Company’s zero cost foreign exchange collars at December 31, 2003 have a fair value of US$ 31 and US$ 5, respectively (US$ 8 and US$ 88 at December 31, 2002).
25. Segment information
The following segment information has been prepared in accordance with SFAS No. 131 - Disclosure about Segments of an Enterprise and Related information (“SFAS 131”). The Company operates under the following segments, which are described as follows:
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25. Segment information—Continued
The items that cannot be attributed to the other areas are allocated to the group of corporate entities, especially those linked with corporate financial management, overhead related with central administration and other expenses, including actuarial expenses related with the pension and health-care plans.
The accounting information by business area was prepared based on the assumption of controllability, for the purpose of attribution to the business areas only items over which these areas have effective control.
The main criteria used to record the results and assets by business segments are summarized as follows:
In periods prior to January 1, 2002, revenue and net income from the gas and energy activities of the international segment were added to revenue and net income from the exploration and production activities of the international segment, as our management did not separate our gas and energy operations abroad. In addition, the changes in our accounting systems adopted in connection with our new business segment reporting does not permit the practicable separation of revenue and cost information for those prior periods. We do not believe this classification of the gas and energy revenue and net income information materially changes the overall segment presentation.
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The following presents the Company’s assets by segment:
Exploration
Gas and
(see separate
disclosure)
Non current assets
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Revenues and net income by segment are as follows:
Net operating revenues to third parties
Inter-segment net operating revenues
Exploration, including exploratory dry holes and impairment
Financial income (expenses), net
Income (loss) before income taxes and minority interest and accounting change
Income tax benefits (expense)
Net income (loss)
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Income (loss) before income taxes and minority interest
F-114
(see separatedisclosure)
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F-116
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Capital expenditures incurred by segment for the years ended December 31, 2003, 2002 and 2001 are as follows:
The Company’s gross sales, classified by geographic destination, are as follows:
The total amounts sold of products and services to the two major customers in 2003, 2002 and 2001 were US$ 3,498, US$ 2,693, US$ 2,907 and US$ 2,688, US$ 2,549, US$ 2,871, respectively.
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26. Related party transactions
The Company is controlled by the Federal Government and has numerous transactions with other state-owned companies in the ordinary course of business.
Transactions with major related parties resulted in the following balances:
PETROS (Pension fund)
Banco do Brasil S.A.
BNDES (Note 12 (b))
Federal Government
ANP
Petroleum and Alcohol Account - Receivable from Federal Government (Note 11)
Long-term
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26. Related party transactions—Continued
These balances are included in the following balance sheet classifications:
Accounts receivable (Note 7)
Petroleum and Alcohol Account - receivable from Federal Government (Note 11)
Pension Fund
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The principal amounts of business and financial operations carried out with related parties are as follows:
BRASKEM S.A.
Centrais Elet. do Norte do Brasil S.A. - Eletronorte
COPESUL S.A.
Manaus Energia S.A.
Petroquímica União S.A.
Petroleum and Alcohol Account -
Receivable from Federal Government (Note 11)
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SUPPLEMENTARY INFORMATION ON OIL AND GAS EXPLORATION AND
PRODUCTION ACTIVITIES (UNAUDITED)
In accordance with SFAS 69 - Disclosures About Oil and Gas Producing Activities (“SFAS 69”), this section provides supplemental information on oil and gas exploration and producing activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations. The information included in items (iv) and (v) present information on PETROBRAS’ estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Beginning in 1995, the Federal Government of Brazil undertook a comprehensive reform of the country’s oil and gas regulatory system. On November 9, 1995, the Brazilian Constitution was amended to authorize the Federal Government to contract with any state or privately-owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. This amendment eliminated PETROBRAS’ effective monopoly. The amendment was implemented by the Petroleum Law, which liberated the fuel market in Brazil beginning January 1, 2002.
The Petroleum Law established a new regulatory framework ending PETROBRAS’ exclusive agency and enabling competition in all aspects of the oil and gas industry in Brazil. As provided in the Petroleum Law, PETROBRAS was granted the exclusive right for a period of 27 years to exploit the petroleum reserves in all fields where the Company had previously commenced production. However, the Petroleum Law established a procedural framework for PETROBRAS to claim exclusive exploratory (and, in case of success, development) rights for a period of up to three years with respect to areas where the Company could demonstrate that it had “established prospects.” To perfect its claim to explore and develop these areas, the Company had to demonstrate that it had the requisite financial capacity to carry out these activities, alone or through financing or partnering arrangements.
The “International” geographic includes activities in Angola, Argentina, Bolivia, Colombia, Ecuador, Mexico, Nigeria, Peru, The United States of America and Venezuela. The Company has immaterial non-consolidated companies involved in exploration and production activities; the amounts related to such are in the line item titled “Company’s share of unconsolidated affiliates”.
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The following table summarizes capitalized costs for oil and gas exploration and production activities with the related accumulated depreciation, depletion and amortization, and asset retirement obligation assets:
Unproved oil and gas properties
Proved oil and gas properties
Support equipment
Gross capitalized costs
Depreciation and depletion
Construction and installations in progress
Company’s share by unconsolidated affiliates
Net capitalized costs
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Costs incurred are summarized below and include both amounts expensed and capitalized:
Property acquisitions
Unproved
Exploration costs
Development costs
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The Company’s results of operations from oil and gas producing activities for the years ending December 31, 2003, 2002 and 2001 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the supply segment in Brazil. The prices calculated by the Company’s model may not be indicative of the price the Company would have realized had this production been sold in an unregulated spot market. Additionally, the prices calculated by the Company’s model may not be indicative of the future prices to be realized by the Company after January 1, 2002, when full price deregulation began. Gas prices used are contracted prices to third parties.
Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including such costs as operating labor, materials, supplies, fuel consumed in operations and the costs of operating natural liquid gas plants. Production costs also include administrative expenses and depreciation and amortization of equipment associated with production activities.
Exploration expenses include the costs of geological and geophysical activities and non-productive exploratory wells. Depreciation and amortization expenses relate to assets employed in exploration and development activities. In accordance with SFAS 69, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.
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Net operating revenues:
Sales to third parties
Intersegment
Production costs
Exploration expenses
Depreciation, depletion, amortization
Results before income taxes
Company’s share of unconsolidated affiliates
Results of operations
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The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2003, 2002 and 2001 are shown in the following table. Proved reserves are estimated by the Company’s reservoir engineers in accordance with the reserve definitions prescribed by the Securities and Exchange Commission.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves do not include additional quantities recoverable beyond the term of the concession or contract, or that may result from extensions of currently proved areas, or from application of secondary or tertiary recovery processes not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes which are expected to be recovered as a result of future investments in drilling, re-equipping existing wells and installing facilities necessary to deliver the production from these reserves.
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In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
A summary of the annual changes in the proved reserves of crude oil and natural gas follows:
Worldwide Net Proved Developed and Undeveloped Reserves
Reserves January 1, 2001
Reserves at December 31, 2001
Reserves at December 31, 2002
Purchase of reserves in place - PEPSA
Reserves at December 31, 2003
Net proved Developed Reserves
At January 1, 2001
At December 31, 2001
At December 31, 2002
At December 31, 2003
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The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of SFAS 69. Estimated future cash inflows from production in Brazil are computed by applying year-end prices based upon the Company’s internal pricing methodology for oil and gas to year-end quantities of estimated net proved reserves. Estimated future cash inflows from production related to the Company’s International segment are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indicators, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% midperiod discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.
The information provided does not represent management’s estimate of PETROBRAS’ expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations.
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The arbitrary valuation prescribed under SFAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of PETROBRAS’ future cash flows or the value of its oil and gas reserves.
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Undiscounted future net cash flows
10 percent midyear annual discount for timing of estimated cash flows
Standardized measure of discounted future net cash flows
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The following are the principal sources of change in the standardized measure of discounted net cash flows:
Sales and transfers of oil and gas, net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery, less related costs
Revisions of previous quantity estimates
Net changes in prices and production costs
Changes in future development costs
Accretion of discount
Net change in income taxes
* * *
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